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Alaska Gasline Determination Public Forum Sheraton Hotel 5-2008
GREETINGS FROM SARAH PALIN, GOVERNOR OF ALASKA GENERAL INFORMATION PRESENTER BIOGRAPHICAL INFORMATION SCHEDULE OF EVENTS (Chart & List Format) FINDINGS & DETERMINATION PLENARY SESSIONS (see tab sheet for list of sessions) BREAKOUT SESSIONS (see tab sheet for list of sessions) DEPARTMENT OF LABOR AND WORKFORCE DEVELOPMENT TRAINING PLAN CRACKING THE CODE SARAH PALIN aD iy P.O. Box 110001 2 ¥ JUNEAU, ALASKA 99811-0001 3 N GOVERNOR (907) 465-3500 Fax (907) 465-3532 GOVERNOR@GOV.STATE.AK.US WWW.GOV.STATE.AK.US STATE OF ALASKA OFFICE OF THE GOVERNOR JUNEAU May 28, 2008 Dear Alaskans: Welcome to the Alaska Gasline Determination Public Forum. Over the next three days, the recommendation of the commissioners of the Departments of Revenue and Natural Resources to award an AGIA license to TransCanada Alaska Company, LLC and Foothills Pipelines Ltd. (TC Alaska) will be outlined and explained. The materials and presentations made here will be made available on-line at the AGIA website (www.gov.state.ak.us/agia). In this binder, you will find the Findings and Determination of the commissioners. These findings explain why the TC Alaska project maximizes the benefits to Alaskans. Over the past four and one half months, the TC Alaska application has been rigorously examined. Over 350 public comments were submitted and carefully reviewed. Our state gasline team, assisted by dozens of world-class experts in engineering, law, commercial finance, and other disciplines, scrutinized and analyzed each page of TC Alaska’s application. The individual expert reports are included as appendices for review. Clearly, the commissioners have done their homework. Because it was so important to make sure this project was the best option for Alaska, the commissioners reviewed several liquefied natural gas (LNG) options. This analysis gives Alaskans more insight than ever on the options we have to commercialize our North Slope natural gas reserves. I congratulate the commissioners and the entire gasline team on completing this demanding task on behalf of the Alaskans we serve. I congratulate TC Alaska on their excellent proposal. I congratulate LNG proponents for their hard work and success in ensuring that LNG options received comprehensive review. And I congratulate Alaskans. We have continued our steady pace toward securing an Alaska gasline on our terms. Sincerely, Sarah Palin Governor General Information Daily Announcements Information on any adjustments in changes in session locations, times or subject will be available daily at the Registration/Information Desk. Food and Beverage Complimentary coffee and water service is available for attendees, but meals will not be provided. Breakfast and lunch service will be available in the hotel's restaurants, and a guide to nearby restaurants and map of Anchorage are included in this binder. Hotel Shuttle The hotel offers shuttle bus service to the downtown Anchorage area on a seven- passenger bus. The service is available on a first-come, first-served basis; some delays may be unavoidable. Request the bus at the front desk, or call 276-8700. Internet Access Wireless internet access is available in the hotel. Inquire at the front desk. Parking Parking is available in the Sheraton Anchorage Hotel's parking garage and in its various parking lots. All-day parking passes are available to all conference attendees for $5.00 per day. The passes may be obtained at the hotel’s front desk, and should be placed in the vehicle’s windshield. Registration/Information Desk The Registration/Information Desk will be staffed each day to help attendees pick up conference materials, register to receive any supplementary materials, get questions answered on schedules and changes, and more. The Registration/Information Desk is located in the foyer outside the Howard Rock Ballroom. Session Locations Plenary sessions will all be held in the Howard Rock Ballroom, located on the second floor. Breakout sessions will be held in the Yukon, Kuskokwim East, and Kuskokwim West rooms, on the second floor. Additional breakout sessions will be held in Rooms 305, 308 and 311 on the third floor, accessible by the elevators between the atrium and foyer. Website Conference materials and related materials will be posted as available on the Internet, at: www.gov.state.ak.us/agia Session Meeting Room Maps W ist Ave E 1st Ave Buttress E Grd Ave inare St Anchorage NM St Anchorage Memorial Park emetery E 7th Ave a a wh 9 a 0 W 7th Ave a E 7th Ave i WathAve =f = Ath Ave oe é C Juneau St SN Wh Ave : ’ E Sth Ave Delaney Park | ai = Fairbanks St W 10th Ave W 11th Ave 4 W 12th Ave W 12th Ave | ae W 1dth Ave aie WM a Q w W 4th Ave W tdth Ave — Hyder St = == 2=Ingra st== Kanuk St >t m 1S MeSunr Netchina E 12th Ave Oenali St Gambeill St 1S Neeunr Fairbanks St Medtra St ebeioyouy UMO}UMOG 40 dew 65uryiem Fine Dining (cont.) ORSO Seafood, grilled meats, fresh pasta. Lunch, dinner. 737 W. 5” Ave Sacks Café & Restaurant Consistently adventurous food. Lunch, dinner, brunch. 328 G St Sullivan’s Steakhouse Steak and seafood. Lunch, dinner. 320 W. 5" Ave (Anch 5" Ave Mall) The Marx Brothers Café Innovative dining. Dinner. 627 W. 3“ Ave Top of the World Fine dining. Lunch, dinner. 500 W. 3" Ave — Hilton Anchorage Hotel International Dining Dami Japanese restaurant. Lunch, dinner. 642 E. 3 Ave ; —S Café Savannah Qe Spanish cuisine, tapas bar. Lunch, dinner. 508 W. 6" Ave Ginger Asian influenced fusion food. Lunch, dinner. 425 W. 5" Ave Kumagoro Restaurant Japanese cuisine. Sushi Bar. Lunch, dinner. 533 W. 4" Ave La Cabana Restaurant Mexican food. Lunch, dinner. 312 E. 4" Ave Rice Bowl Chinese food, steaks. Lunch, dinner. 810 E. 6" Ave Solstice Café Bar & Grill Sushi bar, seafood, pasta, salads. Dinner. 720 W. 5" Ave *Listings include restaurants within the Downtown Improvement District OR are voluntary members of Anchorage Downtown Partnership, Ltd. ANCHORAGE ee AY SiS | *Downtown Restaurant information courtesy of : Downtown Anchorage @ Restaurants: Espresso and Pastries Dark Horse Coffee Espresso, quiche, oatmeal, pastries, SD sandwiches. Breakfast, lunch. * 7" Ave & F Street Wi Java Joan’s Espresso, coffee, pastries. Morning, afternoon. 605 W 4th Ave-inside old Federal Courthouse bldg Kaladi Brothers Coffee Company Espresso, pastries, sandwiches, soup. Breakfast, lunch. 6" Ave & G Street Kobuk Coffee Co. Espresso, homemade pastries & desserts, soup, cold sandwiches. Breakfast, lunch. 504 W. 5" Ave Midnight Sun Café Organic espresso, homemade pastries, soup, @ sandwiches, salads. Breakfast, lunch. 5" Ave & C St— street level 5" Ave parking garage Side Street Espresso Espresso, pastries, sandwiches, soup. Breakfast, lunch. 412 G Street — between 4" & 5" Avenues Starbucks Espresso, pastries. Morning, afternoon, evening. 601 W. 5" Ave Breakfast, Lunch, Casual Fare Alaska Gourmet Subs Gourmet Subs and pasta Lunch, dinner. 601 W. 7" Ave Alaska Salmon Chowder House Alaskan King Crab legs and seafood. Lunch, dinner. 443 W. 4" Ave Anchorage 5" Avenue Mall Food Court. Lunch, dinner. 320 W. 5” Ave Big Al’s Café & Craft Shop : Sandwiches, soup, coffee. Breakfast, lunch. 333 W. 4" Ave, Ship Creek Center Breakfast, Lunch or Casual Fare (cont. Café Nordstrom Sandwiches, soup, salads. Lunch. 603 D St — inside Nordstrom Country Kitchen Family dining . Breakfast, lunch, dinner. 346 E. 5" Ave Dianne’s Restaurant Soups, salads, sandwiches. S Breakfast, lunch. Mon-Fri. 550 W. 7" Ave - Inside Atwood Bldg — street level Downtown Deli & Café Casual dining — Breakfast, lunch, dinner. 525 W. 4" Ave Fletcher’s Hearty lunches, wine. Lunch, dinner. 939 W. 5" Ave — Hotel Captain Cook Hooper Bay Café AK seafood specialties. Breakfast, lunch, dinner. 500 W. 3" Ave — Hilton Anchorage Hotel Horizon Café Cafeteria style. Breakfast, lunch. 701 W. 8" Ave — inside ConocoPhillips bldg. Kodiak Café Breakfast, lunch, dinner. Seafood, beer, wine. 225 E. 5" Ave Midnight Sun Café Organic espresso, homemade pastries, breakfast sandwich, soup, sandwiches, salad. Breakfast, lunch. 245 W. 5" Ave Phyllis’s Café and Salmon Bake Fresh seafood daily, king crab. Lunch, dinner. 436 D St Ptarmigan Grill Cuisine with Alaska flare. Breakfast, lunch, dinner. 401 E. 6" Ave - Sheraton Anchorage Hotel Scottie’s Sub Shop Subs, sandwiches. Lunch, dinner. 331 W. 5" Ave Sizzlin’ Café Soups, sandwiches and panninis. Lunch, dinner - 523 W. 3" Ave Snow City Café Breakfast all day. Breakfast, lunch. 1034 W. 4" Ave The Pantry Breakfast, lunch, dinner. 939 W. 5" Ave — Hotel Captain Cook The White Spot Halibut sandwiches, hamburgers. Breakfast, lunch. 109 W. 4" Ave Uncle Joe’s Pizzeria Beer, wine, gourmet pizzas. Lunch, dinner. 428 G St Whale’s Tail Espresso - am, lunch, dinner, wine. 939 W. 5" Ave — Hotel Captain Cook Specializing in brews, ales, beers Glacier Brewhouse Alaska seafood, pizzas, specialty beers, ales. Lunch, dinner. 737 W. 5™ Ave Humpy’s Great Alaskan Alehouse 43 brews on tap, casual dining, live music. Lunch, dinner, brunch. 610 W. 6" Ave McGinley’s Pub Irish Pub fare. Lunch, dinner. 645 G Street Rumrunner’s Old Towne Bar & Grill Microbrews, cocktails, and music. Lunch, dinner. 501 W. 4" Ave Snow Goose Restaurant & Sleeping Lady Brewing Co. Specialty beer and ales. Lunch, dinner. 717 W. 3" Ave The Anchor Pub & Club Microbrews, cocktails, music. Lunch, dinner. 712 W. 4" Ave Fine Dining Club Paris Specialize - steaks, seafood. Lunch, dinner. 417 W. 5" Ave Crow’s Nest Steaks and seafood. Lunch, dinner. 939 W. 5™ Ave — Hotel Captain Cook Josephines Steaks and seafood. Lunch, dinner. 401 E. 6" Ave - Sheraton Anchorage Hotel (Continued) ANCHORAGE *Downtown Restaurant eek information courtesy of: [eal 38h 17 Presenter Biographical Information ARCADIS ARCADIS is a global network of business professionals that provides project management, consultancy and engineering. ARCADIS develops, designs, implements, maintains and operates projects for companies and governments. With 13,000 employees and $1.9 billion in gross revenue the company is multi-nationally present with a close-knit local network. Expertise and experience are of international significance. Conrad Mulligan Mr. Mulligan has more than 14 years experience as a strategic planner, technical communicator, meeting facilitator, rapporteur, and issues analyst. He has developed an expertise in communicating technical and scientific information. Mr. Mulligan is adept at working with scientists, engineers, and researchers to craft compelling, focused documents that are accessible, accurate, correct, and that meet their intended audiences’ needs. He is skilled at ‘translating’ complex information for non-technical readers, at discerning and packaging the key points and messages from large studies or bodies of knowledge, and at developing layouts and graphics that make complicated information approachable by a variety of audiences. Black & Veatch Black & Veatch Corporation is a leading global engineering, consulting and construction company. Founded in 1915, Black & Veatch specializes in infrastructure development in energy, water, telecommunications, federal management consulting, and environmental markets. Black & Veatch is an employee-owned company with more than 100 offices worldwide. Among other rankings and awards, Black & Veatch is ranked on the Forbes list of the "500 Largest Private Companies in the United States." Michael Elenbaas Mr. Elenbaas leads financial analysis, risk management, market analysis and asset management studies for energy and water utilities. He also specializes in strategic planning and risk management for the energy and water industries. Mr. Elenbaas has played a significant role in his career with Black & Veatch developing strategic planning and risk analysis solutions. His responsibilities have included creation of a capital project prioritization process and tool for both energy and water utilities, and several innovative and complex risk analysis models. He holds a B.S. degree in Mechanical Engineering from Dordt College. Hua Fang - Senior Economist Dr. Fang is a Senior Economist at Black & Veatch. She provides expertise in derivative asset pricing, econometrics modeling, stochastic processes and price modeling, fundamental market analysis, energy asset valuation, and forecasting. Dr. Fang applies the most recent developments in financial theory to the real world energy context and to provide better methods of asset evaluation and risk management for the energy industry. She holds a Ph.D. in Economics from the University of Virginia, an M.A. in Economics from University of Virginia, and an M.A. and B.A. in International Finance from the People’s University of China. Presenter Biographical Information 1 Greg Hopper - Vice President Mr. Hopper is vice president and a founding member of Lukens Energy Group (LEG) and brings nearly 20 years of energy industry experience to the company. At LEG he works with clients in the natural gas and electric generation industries, focusing on strategic and analytic services regarding capital asset investments and optimization. As part of this work he led due diligence valuations supporting three interstate pipeline acquisitions and a large LNG import terminal. Mr. Hopper leads the firm's market analysis practice and has consulted to numerous clients on regional needs for new pipeline capacity. He holds an M.B.A. in Finance from Rice University and a B.B.A. in Accounting from the University of Texas. Deepa Poduval Ms. Poduval is a Principal with Black & Veatch and is responsible for business strategy and project management. Ms. Poduval’s client engagements focus on strategic analytical services supporting portfolio optimization, asset acquisition, risk management, and business strategy development. Her expertise includes the valuation of energy industry assets, analysis of oil & gas marketing strategies and commercial agreements, performance and risk measurement, and analysis & utilization of natural gas industry structural models. She holds an M.S. degree in Engineering Management from Dartmouth College, an M.S. in Economics from B.|.T.S., and a B.E. in Mechanical Engineering. Scott R. Smith - Senior Vice President Mr. Smith leads Lukens Energy Group for B&V's Enterprise Management Solutions division, and has over 25 years of energy industry experience. His consulting focus and expertise includes energy market analysis, risk management, energy asset optimization, business strategy development, natural gas and power project development, trading and marketing strategy development, energy decision analysis and contract negotiations. He leads the Market Analysis practice within Enterprise Management Solutions. Mr. Smith holds an M.B.A. from Southern Methodist University and a B.S. in Chemical Engineering from the University of Texas. Brown, Williams, Moorhead & Quinn, Inc. Brown, Williams, Moorhead & Quinn, Inc. (BWMQ) is a leading energy consulting firm that has been providing advice and assistance to clients for more than 20 years. BWMQ provides comprehensive energy related services to hundreds of clients, including electric, natural gas and oil pipeline companies, local distribution companies, energy producers, trade associations, shippers and federal and state agencies. BWMQ provides advice on how to properly interpret and account for FERC precedents and current policies in the electric, natural gas and oil pipeline industries. BWMQ prepares complete regulatory filings for clients on a wide variety of regulatory matters and offers insights into the regulatory issues that arise in the evolving world of FERC regulation. Barry E. Sullivan - President Mr. Sullivan joined BWMQ in September 2005 after a long career in the Office of Litigation at FERC. He has filed expert witness testimony on a wide range of regulatory issues over the years, including all phases of natural gas pipeline regulation, market power, and oil pipeline ratemaking testimony. He filed testimony against the TAPS carriers in the TAPS proceeding in Docket No. ISO5-82. Mr. Sullivan has over 29 years of experience in litigated formal rate proceedings before FERC. Presenter Biographical Information 2 Bruce Warner - Vice-President Mr. Warner has over 34 years of experience as a consultant, CPA, Certified Depreciation Professional (CDP), accountant, strategic planner and regulatory executive. Mr. Warner served in regulatory, strategic planning and accounting management capacities for Williams Gas Pipelines-West and Kern River Gas Transmission Company for 25 years. His management experience and testimony experience includes: FERC regulation, rates and governmental affairs, property and inventory accounting, financial reporting, regulatory research, tariffs, nominations and strategic planning. Mr. Warner represented Williams in litigation against the TAPS carriers before the Regulatory Commission of Alaska. Energy Capital Advisers Energy Capital Advisers is an oil and gas asset acquisition and divestiture firm, which has facilitated the marketing, sales and purchase of production, royalties, overrides and prospects throughout the United States since 1982. The firm has successfully assisted clients in selling properties ranging from small Non-Operated Working Interests to the total assets of an entire company. Scott Hobbs Mr. Hobbs has been in the natural gas industry for over 30 years with experience in all facets of the business. Over the last six years, he has provided consulting services to state government, investment bankers, private equity firms, and other investors evaluating major projects, acquisitions, and divestitures principally involving oil and gas pipelines, processing plants, power plants, and gas distribution assets. During that period, he also served as Executive Chairman of Optigas, Inc., a private midstream (gathering and processing) natural gas company which was sold in March, 2006 to Energy Spectrum, a private equity firm in Dallas, Texas. Mr. Hobbs is presently on the Board of Directors of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., a publicly traded master limited partnership. Energy Project Consultants Energy Project Consultants is a Colorado-based consulting firm with more than 35 years of experience in natural gas pipeline project management, engineering and construction management. The firm’s experience spans onshore and offshore projects, as well as liquefied natural gas (LNG) projects. Bill Sparger Mr. Sparger has more than 35 years experience in project management, design and construction of natural gas pipelines, compressor stations, and gas processing facilities. Most recently, he worked for Entrega Gas Pipeline Company on a large diameter natural gas pipeline project. He also provided initial project management oversight for a proposed 1300 mile 42” pipeline from the Cheyenne Hub to eastern Ohio. That project is moving forward today with BP and ConocoPhillips participation. Presenter Biographical Information 3 Gaffney Cline Gaffney Cline & Associates (GCA), a wholly owned subsidiary of Baker Hughes, is a global petroleum consultancy of over 45 years specializing in the provision of independent technical, commercial and strategic advice and assistance to international oil and gas companies, national oil companies, governments and financial institutions. GCA’s involvement in the energy industry spans the entire spectrum from upstream to downstream, and includes energy strategy and portfolio management advice. Robert George - Area Manager and Senior Advisor Mr. George has over 35 years experience in the international oil and gas industry. With a degree in Earth Sciences from Leeds University, England and an M.B.A. from the Open University, Mr. George has spent most of his career in the commercial and financial area of the business. He has advised companies on strategy, acquisitions and divestments, and financing; advised governments and government agencies on petroleum policy and investment issues; and provided expert support and testimony in dispute proceedings. Mr. George’s clients have included National Oil Companies, governments, ministries or taxation authorities in Venezuela, Brazil, Kuwait, Saudi Arabia, Mexico, and Alaska on matters including license promotion, taxation, fiscal and regulatory reform and contract structuring. Richard Ruggerio - Area Manager and Senior Advisor Mr. Ruggerio is a graduate of the Colorado School of Mines and has over 30 years industry experience with a primary focus on natural gas, from upstream development to midstream infrastructure and downstream markets. Mr. Ruggerio worked for a major energy company for the first 20-plus years of his career, in which he was involved in multiple domestic and international gas projects, including development of pipeline and LNG projects. Since joining GCA he has advised governments on petroleum fiscal policy and design, participated on legislation and regulation drafting committees, participated in commercial negotiations (on behalf of governments) and provided expert support and testimony in gas dispute proceedings. Gas Strategies Gas Strategies Consulting was formed in 1989 as the consulting arm of its parent, Gas Strategies Group Limited. The practice advises on all commercial issues relating to the gas business. In 2003, Gas Strategies Group Limited was purchased by CRISIL, India’s leading ratings, financial news, risk and policy advisory company. Gas Strategies serves clients around the globe from their London base and also has a presence through consultants, associates and joint venture partners around the globe in Spain, France, Italy, Germany, Australia, Singapore, Brunei, Korea, South Africa and the United States. Gas Strategies operates across natural gas and LNG chains from markets to supply source, specializing in the following key areas: gas market supply, demand and pricing analysis; commercial due diligence for project sponsors and lenders; project structuring, evaluation and feasibility; business strategy development and implementation; competitor analysis and benchmarking; monetization strategy for gas exploration and production; contract advice, negotiation, valuation and arbitration; and regulation, restructuring and liberalization. Presenter Biographical Information 4 Rob Shepherd Mr. Shepherd is a Senior Consultant with Gas Strategies. His interests include the commercial and strategic aspects of LNG projects, industry and regulatory structures across the world, and the future of liberalized gas markets. Before joining Gas Strategies, Rob spent many years with BP, managing BP’s share of the North West Shelf LNG project in Australia and of Qatargas. He played a leading role in BP’s UK gas business, selling to British Gas and starting BP’s move into direct gas marketing. His experience includes advising on the development of Atlantic LNG in Trinidad and providing due diligence on many recent LNG export and receiving terminal projects from RasGas to Yemen LNG. In addition, Rob advises on development of commercial operational procedures for two LNG projects and assistance in developing institutional structures for South Africa and the West African Gas Pipeline with the World Bank. Goldman Sachs Goldman Sachs is a leading global investment banking, securities and investment management firm that provides a wide range of services worldwide. Goldman Sachs provides a broad range of investment banking services to a diverse group of corporations, financial institutions, investment funds, governments and individuals. Goldman Sachs engages in market-making and specialist activities on equities and options exchanges and clear client transactions on major stock, options and futures exchanges worldwide. They also provide investment advisory and financial planning services and offer investment products (primarily through separately managed accounts and commingled vehicles, such as mutual funds and private investment funds) across all major asset classes to a diverse group of institutions and individuals worldwide and provide prime brokerage services, financing services and securities lending services to institutional clients, including hedge funds, mutual funds, pension funds and foundations, and to high-net-worth individuals worldwide. Paul Bloom - Vice President, Public Sector and Infrastructure Banking Mr. Bloom grew up in Anchorage and began his career in 1986 working in government finance for the Portland Development Commission, the City of New York and the Port of Seattle, where he managed all aspects of the Port’s capital planning and financing program. Since his investment banking career began in 1994, Mr. Bloom has focused on the Northwest region and served as lead banker to a variety of Alaska clients, including the State of Alaska, the Municipality of Anchorage, Alaska Industrial Development and Export Authority and the Alaska Energy Authority. Mr. Bloom's financing experience with these clients includes a variety of structures and forms of debt including project financings in the energy, port and airport sectors. Bruce Schwartz - Vice President, Credit Risk Management and Advisory Mr. Schwartz is a Vice President in the Credit Risk Management & Advisory Group at Goldman, Sachs, based in New York. His primary focus is managing Goldman’s credit risk to the energy sector, including upstream, downstream, midstream, oilfield services, and utility companies across debt and derivative products. In addition, Mr. Schwartz advises companies on the credit aspects of merger and acquisition transactions and corporate finance strategies. Prior to joining Goldman Sachs in 2005, Mr. Schwartz worked at Standard & Poor’s Corporate Ratings, where he served as one of two global coordinators for their oil and gas ratings practice. Presenter Biographical Information 5 Timothy Romer - Managing Director and Co-Head of Public Sector Banking Mr. Romer is co-head of the Public Sector Banking at Goldman Sachs. He offers over 20 years of experience in infrastructure finance, having been Co-Head and Managing Director of Merrill Lynch’s western region public finance group until February 2000 and more recently, Managing Director in Bank of America Securities’ Real Estate Secured Finance Group. Mr. Romer provides a deep and diverse background in government, energy and project finance, completing large and small real estate, housing, infrastructure, general municipal and specialty credit financings throughout most of the western region of the United States. He has also been involved in a wide range of large infrastructure projects and public private ventures. Tim received a B.S. in Industrial Engineering from Stanford University and an M.B.A., with honors, from the Wharton School at the University of Pennsylvania. Ray Strong - Managing Director, Global Natural Resources Group Mr. Strong is a Managing Director in the Global Natural Resources Group at Goldman Sachs, based in New York. With over 17 years of investment banking experience, he has executed mergers and acquisitions transactions and equity and debt offerings for companies in the energy sector, including downstream, midstream, upstream, and oilfield services companies. Mr. Strong’s primary focus is on downstream, midstream and master limited partnership clients within the Natural Resources Group. Mr. Strong joined Goldman Sachs, Energy & Power Group from CSFB’s Natural Resources Group as a Vice President in 1999 and was promoted to Managing Director in 2001. He earned a B.A. in Economics from Middlebury College in 1991. Greenburg Traurig With 1,750 lawyers and 29 offices worldwide, Greenberg Traurig represents electric power generators, natural gas pipeline companies and other industry participants before the FERC, SEC and other federal agencies, as well as state agencies, in a wide range of regulatory matters, including: complex ratemaking proceedings; certificate and licensing proceedings; investigations by FERC and other agencies; and rulemaking proceedings. Greenberg Traurig represents clients from all corners of the oil and gas industry, from independent producers and pipeline companies to major integrated companies, as well as regulators and governments. Work in the oil and gas transportation and storage industries includes: natural gas and oil supply, transportation and storage contracts; pipeline transportation, rail/truck transport and trans-oceanic coal/oil shipping agreements; acquisition and divesture of gas processing and treating facilities, mid-stream transportation facilities, and pipeline and gathering systems; formation of strategic alliances, partnerships and joint ventures for the development of pipeline projects; negotiation and preparation of gas processing and treating, facility use, and gas purchase and sales agreements; preparation of transportation contracts for crude oil, natural gas and liquids; acquisition and divestiture of natural gas storage facilities; and development and/or acquisition of natural gas storage facilities. Presenter Biographical Information 6 Kenneth M. Minesinger Mr. Minesinger is co-chair of Greenberg Traurig’s Energy & Natural Resources practice group. He represents various clients in the energy industry, focusing his practice on energy regulatory proceedings before the Federal Energy Regulatory Commission and on related antitrust, litigation and transactional matters. He has represented energy clients in a wide range of regulatory matters, including complex ratemaking, restructuring, and licensing proceedings, and complaints and investigations into allegations of market manipulation and the exercise of market power. As the competitive issues in energy regulatory proceedings often intersect with the application of the antitrust laws, Mr. Minesinger has also represented energy and non-energy clients on numerous antitrust matters, including mergers and acquisitions, counseling, and litigation. He is also a former Chairman of the Antitrust Committee of the Energy Bar Association. Donald Shepler Mr. Shepler has more than 30 years of experience in the natural gas pipeline industry representing major interstate natural gas pipelines before the Federal Energy Regulatory Commission. His experience has included representing pipeline companies in complex rate and restructuring proceedings, numerous certificate proceedings with respect to new facilities and services, and transactional activities regarding sales of capacity on interstate gas pipelines. Mr. Shepler has briefed and argued cases before the United States Court of Appeals for the District of Columbia Circuit and the Tenth Circuit. Allan Van Fleet Mr. Van Fleet has 30 years of litigation, arbitration and antitrust victories, pro bono work, and service to the bar and community. He has represented large and small companies in a variety of industries, including computers and components, telecommunications, biotechnology, health care, foods and beverages, energy, oilfield services, pipelines, railroads, airlines, steel, glassmaking, concrete and cement, accounting, financial services, insurance, legal services, collegiate merchandise, and entertainment, and religious education. Mr. Van Fleet has tried cases for plaintiffs and defendants across the country and internationally. His antitrust practice includes, in addition to litigation, developing compliance programs; providing advice on transactions; structuring mergers and acquisitions; and representing clients before federal, state, and international agencies. Hosie, MacArthur LLP Hosie, MacArthur LLP is a San Francisco-based trail law firm that represents individuals, businesses and state government in complex commercial litigation in state and federal courts across the United States. In the past 20 years, the firm has won more than $2 billion in cases involving antitrust, intellectual property, energy and natural resources law and business tort claims. The firm and its partners have extensive experience in antitrust, intellectual property, energy and natural resources law, fraud, business torts, media law and class actions. In recent years, it has successfully pursued lawsuits for high-technology clients pressing both intellectual property and antitrust claims. Presenter Biographical Information 7 Spencer Hosie Mr. Hosie is a nationally recognized top-ranked trial lawyer for complex commercial cases. In his over 20 year career, he has won or settled cases worth almost $2 billion for his clients. In June 2005, the National Law Journal profiled Mr. Hosie as one of the 10 most successful trial lawyers in the country. His practice covers the spectrum of complex commercial cases, with particular focus on antitrust, energy, and intellectual property litigation. Mr. Hosie currently is an advisor to the Alaska, Louisiana, and Hawaii state governments. PetroTel, Inc. PetroTel is recognized worldwide as industry leaders in enhanced oil recovery, reservoir characterization and simulation, coalbed methane, production, and exploration technologies. We provide professional consulting and advisory services along with integrated project management support to domestic and international petroleum companies. We are an integrated team consisting of a number of highly qualified, versatile, and experienced experts and professionals that represent a diverse set of disciplines: reservoir engineering, reservoir simulation, reservoir characterization, enhanced oil recovery technologies, development geology and geophysics, exploration geology and geophysics, and petrophysics. We also have experts in economics and integrated project management and planning, including production, drilling, and facility engineering support. Together, we represent over 1100 years of combined experience and have broad experience in serving clients throughout the world. Our experience includes working with major oil companies in North and South America, South Asia, Russia, the Far East, Europe, and the Middle East. Dr. Anil Chopra Dr. Chopra obtained his B.S. degree from the Indian Institute of Technology (IIT) at Kanpur and a Ph.D. degree from University of Houston, both in Chemical Engineering. He is a Member of the Society of Petroleum Engineers, a past SPE Distinguished Lecturer, and recipient of a corporate highest technical achievement award. He is the Editor of the SPE book on Applied Geostatistics for Reservoir Characterization and has authored over 35 technical papers. He has over 25 years of experience in Reservoir Engineering, Enhanced Oil Recovery, Reservoir Characterization and Reservoir Management. He is founder of PetroTel Inc. Presenter Biographical Information 8 Pingo International Pingo International is an engineering consulting business with expertise in pipeline system design, construction and operation. The firm has extensive experience working in both North and South America, as well as in the Far East. Patrick Anderson Mr. Anderson has served in various Executive and Senior Technical positions with TransCanada Pipelines and its affiliates for 30 years in designing and building gas pipelines in Canada. Mr. Anderson was President of ARCAN Engineering & Construction (Argentina) from 1997 to 1999 and President of TransCanada Pipelines Services between 2000 and 2001. He has extensive experience conducting business in many countries ranging from the Far East to South America and is a leader in the design, construction and operation of pipeline systems. Currently Mr. Anderson is active in the pipeline engineering consulting business through his personally owned company, PINGO International Inc. Previously, Mr. Anderson was active on many Boards of Directors in Canada as well as in several foreign countries. State of Alaska Kevin Banks, Acting Director, Division of Oil & Gas, Department of Natural Resources Kevin Banks moved to Alaska in 1982 and worked for the Minerals Management Service as an economist in the Social and Economic Studies Program. In this position, he led the agency’s economic research program and directed several engineering assessments of the technologies required to develop the oil and gas resources of the Alaska Outer Continental Shelf. In 1991, Mr. Banks came to the Division of Oil and Gas as its sole petroleum economist. He presided over the establishment of the Commercial Section and was responsible for managing the State of Alaska’s royalty in-kind program, implementing the royalty modification statutes and other oil and gas incentives, and administering the many royalty settlement agreements between the state and its lessees. Mr. Banks has a B.S. in economics/philosophy from Loyola University Los Angeles, and an M.A. in economics from Washington State University. Presenter Biographical Information 9 Clark “Click” Bishop - Commissioner, Department of Labor and Workforce Development Mr. Bishop has been a leader for more than 17 years in training Alaskans for good jobs in the trades and craft industries. As commissioner of the Department of Labor and Workforce Development since 2007, he directs a statewide organization responsible for meeting the training needs of hundreds of employers and thousands of workers. Mr. Bishop served as the administrator and coordinator for the Alaska Operating Engineers Employers Training Trust, a statewide private industry organization training a new generation of workers for the civil and pipeline construction industries. His previous experience in the construction industry included 15 years working for private construction companies across Alaska. Mr. Bishop has more than 17 years of experience working on a regular basis with employers, elected officials, public agencies, private and public sector boards, labor unions and councils, Alaska Native organizations, industry employers and associations as an advocate for career and technical education in Alaska. He has held leadership positions in which he has developed innovative approaches for educating and training residents across Alaska for high-skill, high-pay jobs and careers. A life-long Alaskan, Mr. Bishop has also served on numerous on statewide/local public policy boards actively involved in developing workforce initiatives. Fred Esposito - Director, Alaska Vocational Technical Center, Department of Labor and Workforce Development Mr. Esposito has been the Director of the Alaska Vocational Technical Center (AVTEC) since 1997 and is presently working with the Commissioner of the Alaska Department of Labor and Workforce Development creating a statewide training plan for the AGIA. Mr. Esposito previously spent 16 years working in K-12 education in Alaska, first as a vocational education teacher in rural Alaska and then as vocational education administrator for the Kenai Peninsula Borough School District. He received an M.S. in Vocational Education from the University of Alaska in 1986. Patrick Galvin - Commissioner, Department of Revenue Mr. Galvin was appointed Commissioner of the Department of Revenue by Governor Sarah Palin effective December 4, 2006. Before his appointment he served as a Petroleum Land Manager for the Alaska Department of Natural Resources, Division of Oil & Gas. His responsibilities included managing the oil and gas leasing and licensing programs, lease administration, and oil and gas permitting for the division. His education background includes a Bachelor's degree in Visual Arts and Quantitative Economics from the University of California, San Diego, a law degree from the University of San Diego, and an M.B.A. from San Diego State. Jack Hartz - Petroleum Reservoir Engineer, Division of Oil & Gas, Department of Natural Resources Mr. Hartz is a Petroleum Reservoir Engineer working in the Resource Evaluation Section of the Division of Oil & Gas since 2005. Prior to this he worked as a Reservoir Engineer for the Alaska Oil & Gas Conservation Commission from 1991-2005. In addition, from 1970 to 1991 Mr. Hartz worked for Union Oil of California, Standard Oil of Ohio, British Petroleum and Alaska Petroleum Contractors in various petroleum engineering positions. Mr. Hartz has a Bachelor of Science degree in Petroleum Engineering from Montana Tech, is a lifetime member of the Society of Petroleum Engineers and is a Registered Professional Petroleum Engineer (No. 7923) in the State of Alaska. Presenter Biographical Information 10 Julie Houle - Petroleum Geologist Il, Division of Oil & Gas, Department of Natural Resources Ms. Houle is a Petroleum Geologist with the DNR Division of Oil & Gas and is the current Section Chief for the Resource Evaluation Group. She received a B.S. in Geology from Stanford University; an M.A. in Geology from the University of Texas at Austin; and an M.A.T. from the University of Alaska Anchorage. She worked with Atlantic Richfield Company and ARCO Alaska, Inc. from 1980-1994. During that time she was the field party chief for ARCO Alaska’s 1984 ANWR field program and was the geologist on the team that discovered the Pt. Mcintyre Field in 1988. Ms. Houle has been with the division since November 1996. Thomas Irwin - Commissioner, Department of Natural Resources Tom Irwin has been an important player in Alaska’s resource industry for many years. He earned a mining engineering degree from the Colorado School of Mines in 1968, and was managing a gold mine in Nevada before moving to Alaska in 1992 as Vice President of Operations for Fairbanks Gold Mining, Inc. to help design and begin the Fort Knox gold mine. Mr. Irwin held increasingly important management positions with Fort Knox and True North Mines; has a strong record of service to Alaska’s minerals industry; and is a strong advocate for responsible resource development in our state. Mr. Irwin became Commissioner of the Alaska Department of Natural Resources in 2003. In 2006, he became Vice President of Government and Public Affairs for Golden Valley Electric Association. He resumed his position as DNR Commissioner for Governor Sarah Palin in March of 2007. Steve Moothart - Petroleum Geologist I, Division of Oil & Gas, Department of Natural Resources Mr. Moothart is a Petroleum Geologist with the State Dept. of Natural Resources, Oil and Gas Division. He received both his bachelor’s (1986) and master’s (1992) degrees in Geology from Oregon State University. He joined the Division’s Resource Evaluation section in 2006. Prior to joining the Division, Mr. Moothart accrued over 15 years industry experience with ARCO/ConocoPhillips including field evaluation, development and reservoir modeling of fields on Alaska’s North Slope. Marty Rutherford - Deputy Commissioner, Department of Natural Resources Ms. Rutherford has served the citizens of Alaska for the last 24 years. Currently, she is the Deputy Commissioner of the Department of Natural Resources (DNR) for the State of Alaska and is the lead for the State’s gas line negotiation team. Ms. Rutherford has been involved with oil and gas leasing and royalty policy for the last 15 years. She has also served on the Exxon Valdez Oil Spill (EVOS) Restoration Team advising the EVOS Trustee Council on mitigation issues. Prior to her service with DNR, she was the Deputy Commissioner of the Alaska Department of Community and Regional Affairs and the Director of its Municipal & Regional Assistance Division. Presenter Biographical Information 11 Robert Swenson - Director, Division of Geologic & Geophysical Surveys, Department of Natural Resources Mr. Swenson received his Bachelor of Science degree from the University of Montana and a master’s degree in geology from the University of Wyoming, with emphasis in structural geology. He began his geologic pursuits in Alaska in 1991 analyzing the resource potential of sedimentary basins across all of Alaska for ARCO, ConocoPhillips, and later as exploration manager for Denali Oil & Gas. Mr. Swenson left the industry in 2004 when asked to return to Alaska and serve first as Deputy Director of Geologic Research for the Department of Natural Resources, and later as State Geologist for the Division of Geological & Geophysical Surveys. Mr. Swenson currently lives in Fairbanks, Alaska, and serves on numerous federal and state advisory boards including the Department of Energy gas hydrates research advisory board, the US Geological Survey FEDMAP advisory panel, and Alaska sub-cabinet on climate change. Always a field geologist, he continues to carve out time for summer field work and geologic research in the foothills of the Brooks Range. U.S. Geological Survey David W. Houseknecht Dave Houseknecht joined the U.S. Geological Survey (USGS) in 1992, serving as Energy Program Manager until 1998. He has worked on Alaska North Slope basin analysis and petroleum resource assessments since 1995. He frequently represents the USGS scientific perspective on petroleum resources in ANWR, NPRA, and other areas of Alaska and the Global Arctic to Congress and the Administration. Previously, Houseknecht was a professor of geology at the University of Missouri (1978-1992) and a consultant to the oil industry (1981-1992), working on domestic and international projects. He received geology degrees from Penn State University (B.S. 1973, Ph.D. 1978,) and Southern Illinois University (M.S. 1975). Westney Westney has over 30 years of experience in providing risk assessment advice related to major construction projects involving energy and other companies around the world. Westney’s representative clients on major projects in the past have included each of the major North Slope Producers. Since 1978, Westney Consulting Group has been providing owners and contractors with methodologies and services to reduce the cost and risk of capital projects. The company’s business focus is the energy industry, and its services are based on its differentiated approaches to strategic risk management, strategic project planning, as well as the evaluation and improvement of the effectiveness of project organizations. Westney’s services are based on its proprietary Risk Resolution™ concepts and processes that allow Strategic Project Risks to be framed very early in project development. Presenter Biographical Information 12 Eric Briel - Chief Operating Officer Mr. Briel routinely supports and leads large team facilitation events for Westney, including Project Execution Planning and Project Delivery System Assessment, as well other best practices including VE, Constructability, Risk Analysis and Lessons Learned. Mr. Briel has a total of 25 years of professional experience and expertise including six years as an officer in the U.S. Army Corps of Engineers, involved with all phases of operational planning and project execution, coupled with 18 years of progressive project management responsibilities on international projects for BP (formally Amoco). His knowledge and professional skills in project management span all project phases from initial development of a business opportunity through detailed design, fabrication, installation, start-up and initial facility operation. He holds a bachelor’s degree in Civil Engineering from the Virginia Military Institute and an M.B.A. from Regis University. Keith Dodson Mr. Dodson has extensive experience in the natural gas and LNG industries. Mr. Dodson’s focus is on Strategic Risk Management and Risk-Driven Contract Strategy. He is the developer of the Risk Resolution™ process. Mr. Dodson joined Westney in 2003, after holding executive positions with international engineering & construction contractors, such as Vice Chairman and CEO of MW Kellogg Ltd., President and CEO of Stone & Webster, and Executive VP of Brown & Root. He was also Senior VP with a major energy company. He holds a B.S. in Engineering from the University of Texas, and was Chairman of the Engineering Foundation. He was also Chairman of the Construction Industry Institute. Mr. Dodson is a graduate of the Advanced Management Program at Rice University. Presenter Biographical Information 13 Plenary Session No.1 Plenary Session No. 2 Alaska Gasline Determination Public Forum Schedule Opening Session: Howard Rock Ball Room Welcome by Governor Palin Commissioners Irwin and Galvin will explain their findings, outline the forum structure and introduce presenters. Howard Rock Ball Room TransCanada - Accomplished and Capable Page 1 of 3 Yukon Room Kuskokwim West Kuskokwim East Breakout Session Natural Gas Exploration Price Risk and Project | Analysis of Project Costs | Pipeline Negotiations and Commercial Keys to #3 seitinie and Tariffs the Role of FERC LNG Room Available Potential in the Alaskan 10:45AM [Break 11:00 AM Yukon Room Kuskokwim West Room 311 Room 308 Room 305 Breakout Session Evaluating #4 TransCanada's Analysis of Project Costs | Employment on the Gasline| R ‘Avuilable Price Risk and Project Prospects for an Alaska Commercial and Tariff and Tariffs Project Returns LNG Export Project Terms 12:00 PM Lunch Break 1:30 PM 3:00 PM 3:15 PM Management Pipeline Expansions Legal and Political Factors | Affecting Producer Participation in a TransCanada Project Room Available Point Thomson: Resources, Availability, and Effect on Project Economics Page 2 of 3 Friday, May 30th 10:00 AM oe Kuskokwim West Room 308 Room 305 Breakout Session # Legal and Political Factors ° Fiscal System Risk aide In-State Energy LNG Pricing in Asia | Financing LNG Projects | LNG Project Costs TransCanada Project 11:15 AM Break 11:30 AM Yukon Room Kuskokwim West Kuskokwim East Room 311 Room 308 Room 305 eens saa eae : : Resources; Availability; : < and Effect on Pi Commercial Keys to LNG Fiscal System Risk Financing LNG Projects LNG Project Costs Room Available Economics 12:30 PM Lunch Break 2:00 PM 3:15 PM Breakout Session Kuskokwim West Room Available Page 3 of 3 Alaska Gasline Determination Forum Schedule Wednesday, May 28, 2008 8:30 a.m. to 11:30 a.m. - Plenary Session No. 1: Welcome by Governor Palin; Commissioners Irwin and Galvin will explain their findings, outline the forum structure and introduce presenters e Location: Howard Rock Ballroom e Speakers: Governor Sarah Palin, DNR Commissioner Tom Irwin, DOR Commissioner Pat Galvin 11:30 a.m. to 1:00 p.m. - Lunch on your own 1:00 p.m. to 2:30 p.m. - Plenary Session No. 2: TransCanada — Accomplished and Capable e Location: Howard Rock Ballroom 2:30 p.m. to 2:45 p.m. - Break 2:45 p.m. to 3:45 p.m. - Breakout Session # 1 Pipeline Negotiations and the Role of FERC e Location: Yukon Room Is TransCanada Potentially Liable to its Former Partners? e Location: Kuskokwim West Natural Gas Exploration Potential in the Alaskan Arctic e Location: Kuskokwim East Pipeline Project Finance e Location: Room 311 Pipeline Expansions e Location: Room 308 LNG Pricing in Asia e Location: Room 305 3:45 to 4:00 p.m. - Break Program Schedule 1 Alaska Gasline Determination Forum Schedule Wednesday, May 28, 2008 - Continued 4:00 p.m. to 5:00 p.m. - Breakout Session # 2 Gas Pricing in North America e Location: Yukon Room Evaluating TransCanada’s Commercial and Tariff Terms e Location: Kuskokwim Room West Is TransCanada Potentially Liable to its Former Partners? e Location: Kuskokwim East Pipeline Project Finance e Location: Room 311 Cost Overrun Risk; Sources and Management e Location: Room 308 Employment on the Gasline Project @ e Location: Room 305 Program Schedule 2 @ Alaska Gasline Determination Forum Schedule Thursday, May 29, 2008 8:30 a.m. to 9:30 a.m. - Plenary Session No. 3: TC Alaska Project: From Costs and Schedule to Tariffs e Location: Howard Rock Ballroom 9:30 a.m. to 9:45 a.m. - Break 9:45 a.m. to 10:45 a.m. - Breakout Session # 3 Evaluating TransCanada’s Commercial and Tariff Terms e Location: Yukon Room Analysis of Project Costs, and Tariffs e Location: Kuskokwim West @ Employment on the Gasline Project e Location: Kuskokwim East Free Space e Location: Room 311 Price Risk and Project Returns e Location: Room 308 Prospects for an Alaska LNG Export Project e Location: Room 305 10:45 a.m. to 11:00 a.m. — Break Thursday’s schedule continues on the next page. @ Program Schedule 3 Alaska Gasline Determination Forum Schedule Thursday, May 29, 2008 - Continued 11:00 a.m. to 12:00 p.m. — Breakout Session # 4 Evaluating TransCanada’s Commercial and Tariff Terms e Location: Yukon Room Analysis of Project Costs, and Tariffs e Location: Kuskokwim West Employment on the Gasline Project e Location: Kuskokwim East Free Space e Location: Room 311 Price Risk and Project Returns e Location: Room 308 Prospects for an Alaska LNG Export Project @ e Location: Room 305 12:00 p.m. to 1:30 p.m. - Lunch on your own 1:30 p.m. to 3:00 p.m. - Plenary Session No. 4: Net Present Value (NPV) Analysis and Results e Location: Howard Rock Ballroom 3:00 p.m. to 3:15 p.m. - Break Thursday’s schedule continues on the next page. Program Schedule 4 @ Alaska Gasline Determination Forum Schedule Thursday, May 29, 2008 - Continued 3: 15 p.m. to 4:15 p.m. - Breakout Session # 5 Cost Overrun Risks; Sources and Management e Location: Yukon Room Pipeline Expansions e Location: Kuskokwim West Legal and Political Factors Affecting Producer Participation in a TransCanada Project e Location: Kuskokwim East Free Space e Location: Room 311 Point Thomson Resources, Availability, and Effect on Project Economics e Location: Room 308 @ Gas Pricing in North America e Location: Room 305 Program Schedule 5 Alaska Gasline Determination Forum Schedule Friday, May 30, 2008 8:30 a.m. to 10:00 a.m. — Plenary Session No. 5: Liquid Natural Gas (LNG) Analysis and Results (include NPV results compared to TC) e Location: Howard Rock Ballroom 10:00 a.m. to 10:15 a.m. — Break 10: 15 a.m. to 11:15 a.m. - Breakout Session # 6 Fiscal System Risk e Location: Yukon Room Legal and Political Factors Affecting Producer Participation in a TransCanada Project e Location: Kuskokwim West @ In State Energy e Location: Kuskokwim East LNG Pricing in Asia e Location: Room 311 Financing LNG Projects e Location: Room 308 LNG Project Costs e Location: Room 305 11:15 a.m. to 11:30 a.m. - Break Friday’s schedule continues on the next page. Program Schedule 6 @ Alaska Gasline Determination Forum Schedule @ 11:30 a.m. to 12:30 p.m. - Breakout Session #7 Point Thomson: Resources, Availability, and Effect on Project Economics e Location: Yukon Room Commercial Keys to LNG e Location: Kuskokwim West Fiscal System Risk e Location: Kuskokwim East Financing LNG Projects e Location: Room 311 LNG Project Costs e Location: Room 308 Free Space e Location: Room 305 12:30 p.m. to 2:00 p.m. - Lunch on your own @ 2:00 p.m. to 3:00 p.m. - Plenary Session No. 6: AGIA: Worth $500 Million? e Location: Howard Rock Ballroom 3:00 p.m. to 3:15 p.m. - Break 3:15 p.m. to 4:15 p.m. - Breakout Session # 8 Economics of Undiscovered Gas e Location: Yukon Room Prospects for an Alaska LNG Export Project e Location: Kuskokwim West In-State Energy e Location: Kuskokwim East Free Space e Location: Room 311 Free Space e Location: Room 308 Free Space @ e Location: Room 305 Program Schedule t Written Findings and Determination by the Commissioners of Natural Resources and Revenue for Issuance of a License under the Alaska Gasline Inducement Act (AGIA) Tom Irwin, Commissioner Alaska Department of Natural Resources Pat Galvin, Commissioner Alaska Department of Revenue May 27, 2008 Prepared by The Alaska Department of Natural Resources And The Alaska Department of Revenue Anchorage Alaska May 27, 2008 This publication was produced by the State of Alaska and printed at the cost of $59.77 per copy. The purpose of the publication is to meet the mandate of AS 43.90. Printed in Anchorage, Alaska AGIA Written Findings and Determination PREFACE This document contains the Findings and Determination of the Commissioners of Natural Resources and Revenue concerning whether to issue a license under the Alaska Gasline Inducement Act (“AGIA”) to TransCanada Alaska Company, LLC and Foothills Pipe Lines Ltd. Throughout this document, the AGIA applicant is referred to as “TC Alaska.” TC Alaska is a subsidiary of TransCanada Corporation (“TransCanada”). TransCanada, through its independent pipeline company affiliates, owns and operates one of the largest natural gas pipeline transportation networks in North America. TransCanada has pledged all support necessary, both financial and otherwise, to TC Alaska to achieve completion of the project. The basis for this Determination is explained in detail in the written Findings and supporting documentation that follows: e Executive Summary: The Executive Summary contains a short, simple discussion to provide the reader with a sketch of the more important aspects of the Findings document. The reader can obtain additional, more-detailed information from the actual text of the Findings and Determination. e¢ Chapter One — Introduction and AGIA: Chapter One serves as an introduction to the process used to develop this Findings document and presents information that guides the reader through the evaluation conducted by the Commissioners of the Departments of Natural Resources and Revenue under AGIA. Chapter One also presents information on how the commissioners examined and compared three natural gas projects in order to determine the type of project that most sufficiently maximizes benefits to Alaskans. e Chapter Two — Technical Background: Chapter Two provides a simplified explanation of the many components of a major natural gas pipeline project—what physical and engineering components comprise a natural gas pipeline, what regulatory processes govern the development and operation of a pipeline, what commercial factors drive the economics for the various pipeline stakeholders, and what methods are traditionally used to evaluate a pipeline project's technical and commercial viability. « Chapter Three — Analysis of TC Alaska’s Application. Chapter Three contains the commissioners’ evaluation of the TC Alaska Project as proposed in its AGIA Application. e Chapter Four — LNG: Chapter Four contains the commissioners’ comparison of the TC Alaska Project with liquefied natural gas (LNG) project options. e Chapter Five — Producer Project: Chapter Five consists of the commissioners’ comparison of the TC Alaska Project with the proposal ConocoPhillips and BP recently submitted, labeled “Denali™ - the Alaska Gas Pipeline” (“the Producer Project’). ° Chapter Six — Findings and Determination: Chapter Six contains the Findings and Determination of the commissioners. e Appendices: The appendices contain information that supplements or further explains the Findings document. The appendices include the summary of public comments and the responses to those comments, as well as expert reports. 22 May 2008 ES-1 AGIA Executive Summary Written Findings and Determination EXECUTIVE SUMMARY This Executive Summary contains a short, simple discussion of the more important aspects of the Findings document. The reader can obtain additional, more detailed information from the actual text of the Findings and Determination. As discussed in these Findings: e Issuance of the AGIA license to TC Alaska will maximize benefits to Alaskans because it will provide the best opportunity to achieve a gas pipeline that encourages full exploration of Alaska’s natural gas resources, generates long-term jobs for Alaskans, maximizes state revenues, provides affordable in-state gas opportunities, and realizes other important state goals. e Although liquefied natural gas (“LNG”) project options are likely economic, they would provide the state with less revenue than the TC Alaska Project. Exclusive LNG projects are significantly less likely to succeed compared to TC Alaska because they are more complex, more costly, more difficult to finance, and would face potential regulatory barriers in exporting LNG to Asia. The TC Alaska Project provides Alaska with its best opportunity for a successful LNG project, as a “Y-line” option. The TC Alaska Project proceeding first will reduce costs and lessen financial and contracting hurdles associated with an LNG project. Coming after gas is already bound for U.S. markets, a Y-line may be able to overcome political opposition to exporting gas. Accordingly, the commissioners believe that the best route to an Alaska LNG project runs through the TC Alaska proposal. e Although the TC Alaska Project would generate billions of dollars of profits for the Major North Slope Producers, BP and ConocoPhillips have opposed the TC Alaska Project and touted their own pipeline proposal (‘the Producer Project’). Unlike TC Alaska’s Project, the Producer Project contains no commitments to a project timeline, fails (similar to TAPS) to ensure tariff and expansion terms that will maximize North Slope exploration and development, suffers from potential antitrust problems, and in order to result in a pipeline will likely (similar to the failed Stranded Gas Development Act contract) require the state to provide the Producers with massive additional fiscal concessions. Purpose of this Finding and Determination AGIA, AS 43.90, requires the Commissioners of Natural Resources and Revenue to issue a determination with written findings if they decide that a proposed gasline project will sufficiently maximize the benefits to the people of Alaska and merits issuance of an AGIA license. This document constitutes the commissioners’ Finding and Determination. Following an extensive evaluation process and consideration of public comments, the commissioners have determined that the TC Alaska Project will sufficiently maximize the benefits to Alaskans and merits issuance of the AGIA license. 22 May 2008 ES-2 AGIA Executive Summary Written Findings and Determination Benefits for Alaska of a TC Alaska Gas Pipeline Project The pipeline project proposed by TC Alaska offers significant benefits to Alaska. Alaska’s economy will benefit from short-term construction jobs, but will benefit more significantly from long-term careers, as new natural gas fields are developed because the pipeline to market has been built. Alaska will benefit from a pipeline that can be expanded to accommodate additional natural gas supplies that can be dedicated to meet Alaska’s energy needs. Alaska will benefit from a Because of the commitments to pipeline tariff structure that maximizes state | ©Pansion and real open access that will open the North Slope basin to competition, the TC Alaska Project will revenues, provides true open access to all potential shippers, provides the lowest reasonable generate long-term jobs more transportation rates, and accommodates | effectively than either an LNG option expansions. Alaskans will benefit from the or the Producer Project. opportunity the TC Alaska Project creates for a “Y line” liquefied natural gas project and the “bullet line” to Southcentral Alaska. Alaska will benefit from the potential for lower energy costs as natural gas is made available to communities throughout Alaska via off-take points along the pipeline route and associated spur lines. The construction of a natural gas pipeline is an exciting start to a new era in the Alaska economy, one where more Alaskans have careers in natural gas exploration and development, where the state and its citizens enjoy a continuing stream of tax and royalty revenues, and where local energy costs are reduced. Constructing a natural gas pipeline will generate thousands of construction jobs that will last for three to four years. After the pipeline is operating, employees will be needed to operate compressor stations and other pipeline facilities. The demand for skilled workers trained to drill wells and build new production facilities will increase as the availability of a path to market enhances the economics of exploring for Alaska’s vast undiscovered gas resources. Because of its commitments to expansion and real open access that will open the North Slope basin to competition, the TC Alaska Project will generate long-term jobs more effectively than either an LNG option or the Producer Project. The TC Alaska Project will not interfere with a smaller “bullet line” from the North Slope to Southcentral Alaska. Rather, moving both projects forward simultaneously may produce unique synergies. There are adequate amounts of natural gas on the entire North Slope to fill both pipelines. Because of its smaller scale, the “bullet line” project may be designed and 22 May 2008 ES-3 AGIA Executive Summary Written Findings and Determination constructed more quickly than the TC Alaska Project. The two projects may provide benefits to each other: the construction work force may gain experience working on the “bullet line;” and the TC Alaska Project may attract experts to the state who would not otherwise be available to work on the “bullet line” project. The TC Alaska Project would not preclude an LNG project. Indeed, approving the TC Alaska Project will enhance the prospects for a successful “Y line” LNG project as it will reduce the costs, financing challenges, and commercial coordination challenges unique to LNG projects. TC Alaska offers to construct or transport gas to a “Y line” from Delta Junction to an LNG processing facility in Prince William Sound if shippers express sufficient demand for that project as the work on the overland project progresses. The TC Alaska Project provides several opportunities to address Alaska’s need for low-cost energy. TC Alaska’s proposed distance-sensitive transportation rates ensure that Alaskans will pay just the costs incurred to ship gas within Alaska. The TC Alaska Project also offers the potential for construction of spur lines that will make natural gas available to communities throughout the state. Most importantly, because the true open access and tariff provisions promote gas exploration and development, Alaskans will benefit from an environment in which companies compete to meet Alaskans’ energy needs. The cost of transportation on the TC Alaska pipeline (its “tariff’) will protect the state’s interests throughout the years of pipeline operation. Lowest reasonable tariffs are essential to ensure genuine open access and maximize opportunities for Low Tariffs Encourage exploration development of Alaska’s North Slope natural gas resources. TC Alaska commits to the requirements of AGIA that are Increase long-term designed to ensure the lowest possible tariffs. When tariffs employment are too high, explorers and developers are discouraged from opportunities investing in North Slope natural gas exploration and Produce higher ; . | revenues to the state development. Low tariffs improve the economics of finding Strengthen the and developing additional natural gas resources on the North Permanent Fund Slope, which encourages additional exploration and development work that will provide for long-term, stable employment for Alaskans. Low tariffs also mean that the state can earn a greater return on its natural gas resources. As the owner of the natural gas resources, the state gets a share of the natural gas production, its “royalty” share. As a sovereign, the state taxes the profit on natural gas production. Tariffs are 22 May 2008 ES-4 AGIA Executive Summary Written Findings and Determination deducted from the market price at the destination where the natural gas is delivered before the royalty amount and production taxes are calculated. This means the higher the tariff, the lower the return to Alaska for its natural gas resource. These returns are an important future revenue stream for the state that can be used to fund government services and capital projects, defray the cost of energy to Alaskans, and maintain the strength of and protect the Permanent Fund. TC Alaska has committed to regularly expand its pipeline to meet the need for transporting additional gas on reasonable commercial terms. This is essential to opening the North Slope to competitive natural gas exploration and development. New explorers and producers need confidence that if their efforts are successful, they will be able to get their natural gas into the pipeline and to market at a fair rate for transportation. Alaska’s experience with TAPS (which is owned by the Major North Slope Producers) demonstrates how the terms of ownership and operation of a pipeline can adversely affect the state’s economic interests and the exploration efforts of developers who do not own a share of the pipeline. When the Regulatory Commission of Alaska reviewed the tariffs on the TransAlaska oil pipeline twenty-six years after it began to operate, it found that the tariffs were excessive. The Superior Court, and eventually the Alaska Supreme Court, affirmed the Commission's finding that the TAPS owners had collected pipeline tariffs from shippers that were an average of 57 percent too high. Decades of excessive tariffs reduced the state’s royalties and production tax, and hindered competitive development of the state’s oil resources by non-owner companies. Alaska cannot afford to repeat the TAPS experience. The state must maximize development of the natural gas resources on the North Slope to realize economic growth through increased jobs, revenues and other benefits that will flow from increasing gas production. TC Alaska’s commitments to a lower tariff structure will ensure that the state does not repeat the problems experienced with TAPS. The commissioners recognize the Producer Project may be pursued to completion outside the AGIA process and without state fiscal concessions. The Producers have an obligation to market their gas when it is reasonably profitable to do so; they do not have an obligation to transport the gas through any particular project. If the Producer Project proceeds to an open season, the TC Alaska Project would compete with the Producer Project for gas commitments. However, the Producers have stated that they need concessions from the state to enable them to commit gas to any gas pipeline project. AGIA ties upstream incentives to gas committed at the initial 22 May 2008 ES-5 AGIA Executive Summary Written Findings and Determination open season of the AGIA project, to provide the state Awarding a license to TC Alaska will ensure that any additional opportunities throughout this process to evaluate the upstream incentives are need to increase the value of the AGIA upstream provided in exchange for the benefits inherent in an AGIA project. In addition, awarding a with the benefits Alaskans require. The state will have incentives, when justified. license to TC Alaska reduces the The TC Alaska Project offers significant benefits to the likelihood that the state will need to provide unwarranted concessions to the Major North increases its profits by expanding its system, TC Alaska Slope Producers. state and its citizens. As a pipeline company which has the incentive to foster timely development of the state’s natural gas resources to their maximum potential. This also serves the state interests. The TC Alaska Project sets the stage for an open and competitive North Slope natural gas basin during and after pipeline construction. TC Alaska is unique in its willingness to commit to actions that will realize this future. Background Development of Alaska’s natural resources is the cornerstone of Alaska’s economy. Alaska’s North Slope is a world-class natural gas basin. Recent studies estimate that there are 224 trillion cubic feet (“Tcf’) of undiscovered, technically recoverable natural gas resources throughout the Alaskan Arctic. Of this amount, 137 Tcf are categorized as undiscovered, economically recoverable resources. These resources are in addition to the approximately 24.5 Tcf of natural gas reserves within Prudhoe Bay plus 9 Tcf of natural gas reserves discovered in other existing fields on the North Slope, including Point Thomson. Although there has been considerable debate about who should build a pipeline and when it will be built, there is unanimous agreement that Alaska needs a pipeline to get its huge volumes of natural gas to market. When natural gas was discovered on the North Slope, the search began for a way to get Alaska’s substantial natural gas resources to market. State and federal laws were passed to encourage natural gas pipeline construction. Potential developers spent millions of dollars on plans and studies. However, the low prices in natural gas markets forestalled the commitments necessary to support the tremendous cost of what would be the largest construction project in North America. As dynamic changes occurred in the natural gas market within the last decade, the viability of, and interest in, an Alaska natural gas pipeline increased. 22 May 2008 ES-6 AGIA Executive Summary Written Findings and Determination In 1998, when the Stranded Gas Development Act (“SGDA”) was passed, the average price for natural gas in the Lower 48 was under $2 per million British thermal unit (mmbtu). The first half of this decade was marked by discussions of what type and amount of government subsidies and concessions were needed to make the project viable. Within Alaska, those discussions came in the context of contract negotiations conducted by the previous Governor and his administration with the three primary oil and gas leaseholders on the North Slope: BP, ConocoPhillips, and ExxonMobil (“Major North Slope Producers”). The debate surrounding the proposed contract centered on how much value the state would need to transfer to the Major North Slope Producers and how much risk the state would be required to accept. By 2006, the natural gas markets had changed dramatically. The average price of natural gas in the Lower 48 was more than $6 per mmbtu. Large government subsidies no longer appeared necessary to make the project economically viable. In addition, the state had become much better educated on natural gas pipeline economics. The State learned that if it was not careful to protect its interests, billions of dollars in value could be transferred unnecessarily from the state to the Major North Slope Producers. These changes shifted the public debate from what state concessions would be necessary to what the state government could do to most effectively advance the project and maximize the interests of Alaskans. The legislature did not accept the contract that had been negotiated with the Major North Slope Producers under the SGDA. The Major North Slope Producers continued to insist that large concessions from the state were needed, without demonstrating the need for those concessions. Alaska’s natural gas pipeline project was at an impasse. When the Palin Administration proposed AGIA in early 2007, it was based on the understanding that an Alaska natural gas pipeline project was economically viable and that the Major North Slope Producers would continue their efforts to AGIA uses free market competition to move the project through the current strategic position in Alaska and obtain maximum impasse. All interested companies negotiate commercial terms to maximize their were eligible to propose any type of project they determined to be protect the state’s interests, AGIA used free economically and technically viable. value from any natural gas pipeline project. To market competition to move the project through the current impasse. All interested companies were eligible to propose any type of project they determined to be economically and technically viable. The Major North Slope Producers would need to decide whether they were going to get the enormous reserves of Alaska natural gas in the fields they now operated to market in a pipeline they built and owned, or one constructed by 22 May 2008 ES-7 AGIA Executive Summary Written Findings and Determination a third party. AGIA presumed that the Major North Slope Producers would act as reasonable commercial players who would comply with their lease obligations and participate in a project with positive economics. Furthermore, AGIA established that if incentives are provided to a natural gas pipeline project they are given in exchange for genuine open access and other provisions necessary to protect the state’s interests. AGIA established a competitive process to allow companies to compete for a license. The companies submitting applications to construct and operate Alaska’s natural gas pipeline were required to commit to the tariff and expansion terms that were designed to protect the state’s interests and to develop the state’s economy by providing employment during the construction of the pipeline and (more importantly) providing long-term careers in a new natural gas exploration and development industry. AGIA was based on the understanding that competition could drive companies to make those commitments. All who recognized that the project economics were positive would compete for the commercial opportunity to build the natural gas pipeline and earn some of those profits. The competition was open to everyone willing to operate within the parameters established by the AGIA “must haves.” All competitors, including natural gas pipeline companies, natural gas producers, and LNG projects were eligible to compete. In exchange for the commitments required in AGIA, the Alaska legislature offered a package of inducements. These include: reimbursement of up to $500 million of the costs incurred to obtain a regulatory approval from the Federal Energy Regulatory Commission (“FERC”) to construct a pipeline; an AGIA project coordinator to facilitate the process; and a stable production tax rate for ten years and fixed royalty valuation methods to anyone who committed to purchase capacity to ship natural gas on the AGIA gasline during its first binding open season. The legislature recognized the state’s vital interests in encouraging exploration and development of Alaska’s natural gas resources by ensuring a genuine open access pipeline and the lowest reasonable transportation rates. AGIA license applicants were required to commit to a tariff structure that would assure the lowest possible transportation rates and expansion terms to encourage natural gas explorers and prospective developers to compete to explore for and develop Alaska’s North Slope natural gas resources and bring them to market. The legislature made the inducements available to an AGIA licensee if the licensee would agree to meet the requirements and make the commitments that the legislature deemed necessary to protect the state’s interests. 22 May 2008 ES-8 AGIA Executive Summary Written Findings and Determination A Request for Applications (“RFA”) was released on July 2, 2007. Applications were due November 30, 2007. The applications covered a variety of projects including both overland natural gas pipelines and LNG projects. After a thorough review, only the application from TC Alaska was found to have met all the threshold application “completeness” requirements of the AGIA statute and RFA. Although none of the applications proposing an LNG application was complete, the commissioners nevertheless compared several LNG options with the TC Alaska Project before making a decision due to the need to resolve the long-standing public debate over which route is preferable. A public review process was held on the TC Alaska application, and more than 350 public comments were received. The comments were considered in development of the Findings and are summarized in Appendix A along with responses. The commissioners assembled a team of experts to provide analysis to help the commissioners evaluate the TC Alaska application, examine LNG options, and review the Producer Project. The team included numerous experts whose names and contributions are presented in Chapter 2. Their reports, compiled and attached as Appendices, were evaluated in developing these Findings and Determination. How a Natural Gas Pipeline Project will Progress Construction of a natural gas pipeline to bring Alaska’s natural gas to market is a complex undertaking. There is no single event that will take the state from not having a pipeline to having a pipeline. Rather it is a series of steps, spanning a number of years, with each step affecting the next and requiring significant expenditures. Benchmarks define these steps, and at each one a pipeline developer must re-evaluate the project economics and decide whether to proceed. A successful Alaska natural gas pipeline requires much more than a proposal to build a pipeline; it requires a company that will move through each of the steps to completion. The state’s evaluation process considered how likely it is that the TC Alaska Project, various LNG options and the Producer Project will complete the progression from an exciting idea to an operating pipeline. The first step for the TC Alaska Project is issuance of an AGIA license. That license will make TC Alaska’s commitment to obtain a FERC certificate legally enforceable. TC Alaska will not earn any revenues until natural gas begins to flow through the pipeline; approximately ten years after an AGIA license is awarded. In exchange for the state’s commitment match of up to $500 million of the costs of taking the project through FERC certification, the state gets a commitment 22 May 2008 ES-9 AGIA Executive Summary Written Findings and Determination from TC Alaska to move the project forward to that benchmark. TC Alaska has committed to submit an application to the FERC by December 2011." After the AGIA license is issued, the next step for TC Alaska is holding an open season. Open season is the term used in the natural gas industry to describe the process a pipeline builder uses to solicit firm shipping commitments for natural gas. Producers that commit to ship natural gas get reserved capacity on the pipeline and fixed transportation rates. The pipeline company gets commitments to transport natural gas that will help it finance construction of the natural gas pipeline. A natural gas pipeline ultimately needs shipping The commissioners’ analysis shows that the Major North shipping commitments, a project must provide positive Slope Producers can expect The billions of dollars in profits if they commit gas to the TC commissioners’ analysis shows that the Major North Alaska Project. commitments to be successful. In order to attract economic opportunity for gas _ shippers. Slope Producers can expect billions of dollars in profits if they commit gas to the TC Alaska Project. After an open season, regardless of results, TC Alaska will apply for a FERC certificate. An interstate pipeline must have a certificate of public convenience and necessity from FERC before constructing new pipeline facilities. Among other things, FERC reviews the project, approves the proposed tariff terms, and sets recourse rates based on its review of the costs of construction and operation. Recourse rates are available to all shippers, but any company willing to commit to ship a defined volume for a specific period of time can negotiate better terms. FERC commonly approves negotiated rates. FERC has the authority to impose certificate conditions on the pipeline company that it believes are necessary to protect the public interest. The proposed transportation rates described in TC Alaska’s application are a reasonable first step in allocating the risks and rewards among the parties who will be involved in this project. However, nothing in the AGIA license prevents the state from protecting its interests in front of FERC by arguing for different terms. As the project moves forward and the project costs and * in its Application, TC Alaska premised this and other dates on receiving the AGIA License by April 1, 2008. According to TC Alaska, if the License is issued later this year, these dates may need to be adjusted. However, for ease of reference in these Findings we will continue to refer to the original dates used by TC Alaska in its Application. 22 May 2008 ES-10 AGIA Executive Summary Written Findings and Determination expected revenues are better defined, the negotiations between TC Alaska and potential shippers will continue. If, after they have negotiated their cost of transportation, the Major North Slope Producers can demonstrate that some change in the state's fiscal regime is necessary to enable them to earn a fair return, then the legislature can consider changes to the state's fiscal system. After a FERC certificate is awarded, the complex process of pipeline construction begins. Because of the remote location and large size of this pipeline, the process of ordering materials and bringing them to the site will require extensive logistical planning. Construction of the pipeline and the associated processing plant will take at least three years. Throughout the process, TC Alaska will continue to evaluate if there is demand for more capacity in the pipeline. Capacity can be added by including additional compressor stations (“compression”) or adding parallel pipe (“looping”). As additional natural gas fields are discovered and brought into production, the TC Alaska pipeline will add capacity and continue to create more jobs in Alaska’s natural gas industry. TC Alaska Project Proposal TC Alaska proposes to build a 48-inch diameter, high-pressure pipeline capable of carrying between 3.5 and 5.9 billion cubic feet per day (bcf/d). The project would run 1,715 miles from a natural gas treatment plant at Prudhoe Bay on the North Slope to interconnect with the Alberta Hub in Canada. This is the second largest natural gas trading center in North America, which interconnects with pipelines that carry more than 10 bcf/d of gas into U.S. markets. The Alaska section will be approximately 750 miles long with six compressor stations at startup and five natural gas delivery points in Alaska. The net present value (“NPV’ [culation P ( i Net Present Value - NPV is an methodology used to assess TC Alaska’s application allows the State to consistently and transparently assess its future value in common terms. Because TC Alaska’s application, the LNG options, and the Producer Project are based on a variety of assumptions and projections, it is essential to use common terms to assess the impacts of these assumptions and projections on economic calculation used to determine the value of long-term projects. It recognizes that a dollar today is worth more than a dollar in the future. Future income (or “net value”) is measured by its “present” value through discounting. The NPV calculation allows assessment of profits that will be spread over decades. ES-11 22 May 2008 AGIA Executive Summary Written Findings and Determination the value to the state. With the basic assumptions rendered into common terms, the state can evaluate whether the TC Alaska Project serves the best interests of the state and compare it to LNG options and the Producer Project. The path offered by TC Alaska’s plan is likely to succeed. TC Alaska provided a work plan that is technically reasonable, feasible and specific. It includes the use of technology that TransCanada is now using to operate pipelines in climates similar to Alaska’s. The schedule, including the timing of U.S. and Canadian regulatory approvals, is aggressive but reasonable and appropriate. TransCanada has the financial ability to contribute equity to the project and to obtain the financing necessary for construction. TransCanada has a strong record of performance in developing other large projects and a positive record of integrity and business ethics. The commissioners also considered whether sufficient natural gas exists on the North Slope to fill the capacity of TC Alaska’s proposed pipeline for 25 years. Alaska has enough natural gas resources to fill the TC Alaska pipeline for 25 years and for decades longer. This is true even though The state and the Major North Slope Producers stand to receive significantly positive cash flows and for any project during its initial years due to the NPVs from the Project even if the Prudhoe Bay gas is the only gas ever produced on the North Slope. If, in Point Thomson natural gas may not be available operator's failure to develop the Point Thomson Unit in a timely manner, and the significant addition to the Prudhoe Bay gas, potential that the Unit must first be developed for natural gas from Alaska’s other vast resources is also produced (including Point Thomson gas—which is very Point Thomson gas, however, is more than offset likely), then the Project will be even more profitable. liquid condensate and oil. The unavailability of by the unique profitability of the natural gas at Prudhoe Bay. In fact, despite the unavailability of Point Thomson gas, the state and the Major North Slope Producers stand to receive significantly positive cash flows and NPVs from the Project even if the Prudhoe Bay gas is the only gas ever produced on the North Slope. If, in addition to the Prudhoe Bay gas, natural gas from Alaska’s other vast resources is also produced (including Point Thomson gas—which is very likely), then the Project will be even more profitable. Additionally, the commissioners considered the claim by the Major North Slope Producers that TC Alaska cannot succeed because of the risk that, if it builds the Project, it would be sued by former partners that worked with other TransCanada affiliates to try to advance an Alaska 22 May 2008 ES-12 AGIA Executive Summary Written Findings and Determination gasline project more than two decades ago. As discussed in Chapter 3, the commissioners find that the potential claims against TC Alaska and its affiliates are extremely weak, and that the Producers have failed to support their speculative theory. As a result, the commissioners conclude that the risk of litigation over this issue does not present a significant barrier to the TC Alaska Project's likelihood of success, including its ability to obtain financing. The commercial terms proposed by TC Alaska are reasonable. TC Alaska’s plan for managing cost overruns will reduce the risk for shippers of tariff increases. The TC Alaska proposal provides the Major North Slope Producers with several significant commercial opportunities. They can construct and own the gas treatment plant on the North Slope. They can also own an equity share in the TC Alaska pipeline. Further, the terms may become even more attractive through negotiations with the Major North Slope Producers. Although there are project risks, none of them are significant enough to outweigh the TC Alaska Project's likelihood of success. Natural gas prices The commissioners anticipate that the state’s current fiscal structure will allow uneconomic. The risk that there are insufficient | companies that develop North Slope are not likely to decline enough to make the project gas and transport it on the TC Alaska pipeline to earn a significant profit. resources on the North Slope to fill the proposed pipeline is low. The commissioners anticipate that the state’s current fiscal structure will allow companies that develop North Slope gas and transport it on the TC Alaska pipeline to earn a significant profit. The TC Alaska Project is viable. TransCanada has successfully constructed many natural gas pipelines and now operates 36,000 miles of natural gas pipelines in North America. The TC Alaska Project will provide positive economics to the state and federal governments, the Major North Slope Producers and to TC Alaska. It is likely to succeed because all of the stakeholders will benefit from success and risk losing a lot if the project fails. Alternatives to the TC Alaska Proposal There were no applications found complete that proposed an instate pipeline and LNG project. In addition, although the Major North Slope Producers did not submit an AGIA application, BP and ConocoPhillips recently announced the Producer Project. To help determine whether TC Alaska’s pipeline proposal maximizes benefits and is in the best interest of the state, the commissioners evaluated LNG project options from the North Slope to an LNG plant in Valdez and the Producer Project. 22 May 2008 ES-13 AGIA Executive Summary Written Findings and Determination The LNG project options examined were guided by the LNG project proposals submitted under AGIA. Under the same assumptions used to analyze the TC Alaska Project, all LNG project options resulted in less value to the state and the Major North Slope Producers. Although an LNG project would be able to tap the higher prices, that we expect to be available in the Asian market, the LNG projects have significantly higher costs and thus result in lower NPV to the state or Major North Slope Producers. The commissioners’ analysis does not reveal comparative benefits in either timing or costs associated with an LNG project. Even if LNG had demonstrated comparable NPV to the TC Alaska Project, the LNG projects would still not be preferable to the TC Alaska Project. The commissioners’ analysis reveals that LNG projects have a much lower likelihood of success compared to the TC Alaska Project. An LNG project will face unique financing and The primary markets for Alaskan LNG are in Asia, thus an LNG project would include the need to negotiate multiple and not address North American energy commercial challenges for several reasons. These security and likely faces significant political opposition to exporting the transport, liquefaction, shipping, re-gasification, gas. concurrent agreements for the purchase, pipe and sale of natural gas. An LNG project also faces significant challenges because the Major North Slope Producers have made it clear that the Asian market is not their preferred market. In addition, an LNG project will face significant risk of not being permitted to export the gas to its primary market in Asia. The gas quality (specifically, requirements for higher heat content) required to fulfill long-term contracts to an Asian buyer is likely to preclude the development of a petrochemical industry in Alaska associated with an LNG project. Some propane can be removed from the natural gas stream to meet Alaskan energy needs. However, the other natural gas liquids would need to remain in the stream to satisfy the expected contract requirements of the Asian market. In addition, LNG projects create concerns about genuine open access at the liquefaction plant. FERC cannot impose open access requirements on a liquefaction plant. Just as pipeline tariff terms can create disincentives for exploration, so can the processing terms at the liquefaction plant. The lack of genuine open access at the liquefaction plant will increase risks for explorers and limit the incentive for new natural gas exploration and development on the North Slope. The career opportunities and revenues associated with future development and expansions offer great value to Alaska; the limitations on those factors associated with an LNG project make it less attractive. 22 May 2008 ES-14 AGIA Executive Summary Written Findings and Determination When compared to an exclusive LNG project, the Approving the TC Alaska Project will enhance the prospects for a successful provides an opportunity for a successful LNG “Y “Y line” LNG project as it will reduce overland gasline project proposed by TC Alaska costs, financing challenges, and commercial coordination challenges of an LNG project is greatest when it is constructed unique to LNG. line” project or “spur line.” The likelihood of success as a “Y line.” The dynamics of a producer-owned and operated pipeline are very different from those of a third-party owned pipeline. An entity that both produces natural gas and owns the pipeline, like the Producer Project, earns revenues through sales of natural gas and shipment of the natural gas. Such an entity is not necessarily as driven to keep costs low—a producer who owns a pipeline and the natural gas shipped through the pipeline, is essentially paying itself to ship the natural gas, and so is less sensitive to the transportation rate. And because they own or produce the natural gas, there is a reduced economic driver to explore for and develop additional resources until such time as it is necessary to maintain shipping volumes through the pipeline. As the state’s experience with TAPS has shown, combining pipeline and shipper responsibilities can harm the state’s interests. For many of these same reasons, the Producer Project suffers the risk of being stalled by anti-trust challenges. Any Alaska natural gas pipeline project can proceed without state assistance. AGIA is not the exclusive vehicle for construction of an Alaskan natural gas pipeline; rather it was created to ensure that a natural gas pipeline is constructed that meets Alaska’s needs. It was not designed to preclude the Major North Slope Producers from owning and operating the natural gas pipeline. Instead, its goal was to ensure that if they did, they would act like an independent pipeline company rather than an integrated gas producer and pipeline company. The state’s interests would be protected through commercial tariff terms that ensure the lowest possible tariffs, guarantee genuine open access and expansion of the pipeline to encourage continued development of Alaska’s vast natural gas resources. On the day before the AGIA applications were due, ConocoPhillips publicly announced their desire to pursue a natural gas pipeline outside the AGIA process. Negotiations of fiscal conditions were a pre-condition of moving forward with the project. The administration chose to continue the competitive AGIA process in favor of exclusive negotiations. Recently, BP and ConocoPhillips announced the pursuit of another natural gas pipeline project: “Denali™ - the Alaska Gas Pipeline” (“Producer Project”). Negotiations over fiscal conditions are no longer 22 May 2008 ES-15 AGIA Executive Summary Written Findings and Determination seen as a pre-condition of forward movement, but are now seen as a pre-requisite to a successful open season. None of the important commercial terms of the Producer Project are defined and, unlike TC Alaska, the Producer Project makes no enforceable commitments. There is no enforceable commitment to adhere to their stated timeline or to achieve additional milestones, such as applying for | None of the important commercial ; | | | terms of the Producer Project are a FERC certificate. There is no information on the defined and, unlike TC Alaska, the tariffs the Producer Project would offer, let alone | Producer Project makes no enforceable , a a commitments. an enforceable commitment to provide genuine open access. This makes the option currently presented by the Producer Project extremely risky for the state. The Producer Project was offered outside of the AGIA process, and may continue in parallel to TC Alaska’s efforts. Some have suggested that the state should “save” its $500 million, and exclusively pursue the Producer Project rather than the TC Alaska Project. However, no company would turn down $500 million unless it expected to extract even greater concessions later from the state. Indeed, during the SGDA process the Major North Slope In sum, the TC Alaska Project will enhance the likelihood of success Producers demanded the state provide billions of dollars in fiscal concessions—far more than the $500 of an LNG “Y line” project. million provided under AGIA. In addition, the Facilitating a “Y line” may protect : the state against future price Producers demanded numerous other concessions changes in North American and which would have required the state to relinquish a LNG markets. The Producer : J ; J Project, because of its undefined large portion of its sovereignty. There is no reason to coenrnerckal terms, iffars expect BP and ConocoPhillips would not demand enormous risks and uncertain similar concessions if the state rejects the TC Alaska rewards to Alaska. application. In addition, these objections to AGIA ignore the fact that the state will receive numerous benefits for the $500 million, including lower rates that more than offset the $500 million and enforceable commitments to move the project forward. In sum, the TC Alaska Project will enhance the likelihood of success of an LNG “Y line” project. Facilitating a “Y line” may protect the state against future price changes in North American and LNG markets. The Producer Project, because of its undefined commercial terms, offers enormous risks and uncertain rewards to Alaska. 22 May 2008 ES-16 AGIA Executive Summary Written Findings and Determination Summary of the Findings The TC Alaska Project is economically viable. At expected natural gas prices, the project will generate billions of dollars and substantial rewards for Alaskans, the Major North Slope Producers, the state and federal governments, and TC Alaska. TransCanada has a proven track record in pipeline design, construction, and operation and currently operates more than 36,000 miles of gas pipeline in North America. It has the financial resources to meet the challenge of financing this project. The TC Alaska Project plan is technically sound and feasible, and the project schedule is appropriately aggressive but reasonable. The extremely positive economics of TC Alaska’s Project, combined with the legal and political context, provide favorable conditions for attracting shipping commitments for the project. Overall, the TC Alaska Project is likely to succeed. Exclusive LNG project options would most likely result in lower NPV to the state than the TC Alaska Project, would not easily accommodate expansions and the open access terms that would cause more long-term jobs to be added to the state’s economy, and have a lower likelihood of success than the TC Alaska Project. A “Y-Line” addition to the TC Alaska Project is more likely to succeed than other LNG project options. The key for adding long-term jobs for Alaskans is a pipeline that encourages exploration and development of North Slope natural gas. The TC Alaska Project makes legally enforceable commitments that will result in such a pipeline. Alaskans need low-cost energy. This can be provided by an Alaskan gas pipeline project that has a low transportation cost (tariff), is committed to expansion to accommodate new found natural gas, provides access for natural gas off-take and spur lines in Alaska, ensures that natural gas delivered in Alaska only pays transportation costs for the mileage that the natural gas has traveled, and results in maximum revenue to the state and its citizens. The TC Alaska Project meets these objectives. 22 May 2008 ES-17 AGIA Executive Summary Written Findings and Determination e The TC Alaska Project will not preclude construction of a smaller pipeline from the North Slope to Southcentral Alaska. Issuing a license to TC Alaska may increase the likelihood that plans for a “bullet line” or “spur line” will become reality. e Similar to the failed SGDA contract, the Producer Project is not guaranteed to continue to advance the project to construction or even FERC certification and will likely require undefined concessions from the state. Similar to TAPS, the Producer Project will likely result in commercial terms that do not protect Alaska’s interests. e¢ The TC Alaska Project provides opportunities for significant Producer ownership. If the state determines that additional concessions are needed, they can be added to the TC Alaska Project to ensure that any concessions result in a pipeline that maximizes benefits for Alaskans. Determination The commissioners found TC Alaska’s application to be complete and in compliance with the AGIA statute and Request for Applications. Following an extensive evaluation process, the commissioners determine that the natural gas pipeline project from the North Slope to Canada proposed by TC Alaska is the project that will sufficiently maximize the benefits to the people of this state. The commissioners further determine that the TC Alaska Project merits the award of a license under AGIA. These Findings and Determination will be submitted to the presiding officers of each house of the Alaska Legislature for approval of the license. The license will be issued to TC Alaska as soon as practicable after the effective date of a bill approving the license proposed by the commissioners. If a bill is not passed within 60 days of the date that the legislative presiding officers receive this Determination, the commissioners may not issue the proposed license and may request new applications. This Executive Summary presents an overview of the Written Findings and Determination by the Commissioners of the Alaska Departments of Natural Resources and Revenue for issuance of a License under the Alaska Gasline Inducement Act (AGIA). It summarizes the commissioners’ process for evaluating TC Alaska’s proposed natural gas pipeline project and the commissioners’ determination as provided by AGIA. This Executive Summary is part of the commissioners Written Findings and Determination that is anticipated to be published on May 28, 2008. This document is a summary only, and is not the commissioners’ final determination under AGIA and is not a final agency action. 22 May 2008 ES-18 Written Findings and Determination by the Commissioners of Natural Resources and Revenue for Issuance of a License under the Alaska Gasline Inducement Act (AGIA) Executive Summary... Acronyms and Abbreviations Glossary CHAPTER ONE INTRODUCTION AND AGIA A. Introduction B. History of Alaska Natural Gas Pipeline Efforts. i: 1. The Stranded Gas Development: Act .................cccccccssecsssecerssescessssonssossaseansseascsacieascesesees 1-3 2. Alaska Gasline Inducement Act C. Summary of Projects The TC Alaska Application The LNG Project Options The Producer Project The Bullet Line LNG and an Overland Pipeline D. Maximizing Benefits for Alaskans .... Oe OLIN = 1. 2. 3. 4. F. CHAPTER TWO TECHNICAL BACKGROUND Pi, iipigerh aaee P acctecterertereinnenat nicotene eeEbeeRneeeeienees 1. Natural Gas Markets 2. LNG Basics....... 3. History of LNG.. a 4. Asian Gas Quality Demands. ; Bh — Fe PR erect 2-5 1. Natural Gas Pipeline Project Development.. 2. Project Analysis 3. Pipeline Regulation 4. The Alaska Natural Gas Pipeline Act and Impacts on the Regulation of an Alaska Natural Gas Pipeline .............c:ccceccescceeseeeeesseseeeseceeseeseeseesesesesseseaeeeeeaeeaeeas 2-9 5. Alaska’s Natural Gas Resources .... C. Analysis Team ID. _RRETOFONCES oisnoi linen nes case ell lassnennseslcsorrecranansennssuntaseenonss/dthanseauacenceetssssnseonssai/sunosensensaseue sien CHAPTER THREE ANALYSIS OF TC ALASKA’S APPLICATION A. Introduction and SUMMALY ............:csscsseesesesseeeesseessessesseseessensessesseeseeseeaeeseeseesesseseesseseeseass B._Whoiis TC:Alaska?. ico ccccccicossicsesesee 1. History and Company Description... a. TransCanada in Alaska C. Summary of Proposed Project 1. Gas Treatment Plant (GTP) a Potential Equity Partners b. | Management Challenges c. Regulatory Challenges 0, Ferrer CG nictincerentioincseeenemnnbntieomenidiiemeememnnin D. TC Alaska’s Project Would Produce a Significantly Positive Net Present Value for the State of Alaska .. 1. Summary of Methodology and Results of NPV Arialysie.. 2. NPV Methodology ... a. General Approach... 3-17 b. Natural Gas Prices. w.3°20 G BIA, Price Forecintlt secre ce rensessseennneenenunnnennnsmnreneennmannemenonstanes 3-23 d. Wood Mackenzie Price Projection..... sued ddl snassnasesesseerencuoserennbcduaseasenustiiea 3-25 e. Projection Based on Forward-Looking North Amesrtemn Supply and EUROS CIN ii iene cial ch senneemennnnetiel f. | Estimated Volumes of Natural Gas Sold g. Estimated Pipeline and GTP Costs, Schedule, and Tariffs... h. Pipeline Cost and Schedule Analysis, Including Cost and Schedule Ranges.......... 3-46 i. Nominal Dollar Cost Ranges and Tariffs: Escalation Risk ..........:.c:c:ccescsssesseseeeeeees 3-54 j. Upstream Costs. 3. Estimated NPV Produced by the Project—Results of the NPV Analysis .... a. Estimated NPV under the Proposal Base Case ............ceesceeceeeeeeeeeeeseneeneeeeneeneeennees b. Estimated NPV Under the Conservative Base Case and Low Volume Sensitivity Case Remain Favorable c. The Project Would Produce a Positive NPV Even If No Point Thorns or VIF ‘Gas Is) Ev6r' Produce]. s. ciccsssscascsseccecccacstacssaaceseeasseesceescesseusseststesvevanecevensa cast 3-75 4. Impact of $500 Million Match 5. Availability of Low Cost Expansion @: F. ‘L 2: 3. Analysis of the Likelihood of Success of TC Alaska’s Project. Introduction and Summary Methodology for Analyzing the Project's Likelihood of Success Analysis of Likelihood of Success Criteria Under AGIA Section 170 a. TC Alaska Has Submitted a Plan for its Project That is Technically Feasible, Reasonable, and Specific. ............ccccsesseseseecesesesseseecseeesseees 3-85 b. TC Alaska Has Demonstrated the Technical and Financial Ability Te Caneel fhe PRG iscccsiccmnorcncemmncnncmenmmmmmonicsinnneenmnasianinamenine 3-98 c. TC Alaska Has Submitted a Reasonable Commercial Plan Which, Coupled With Economic and Political Factors, Should Help To Encourage Firm Shipping) COMMIMENS ca ccecicsccsecssectsncsneeestecrovessusensnesssssconsenvevtssusssaesevessessss 3-106 d. TC Alaska’s Ability To Overcome Barriers To Obtaining Firm SHIPPING | COMMIMENMS sccscccssesevonssssecencesesessseneunssatosncoussvessonssneossesossonesssusesvesenaanvecss 3-119 e. Other Factors Which Indicate TC Alaska’s Project Has A Reasonable Prospect of Securing Firm Shipping Commitments... ...3-153 --3-160 G. References 3-161 CHAPTER FOUR LNG moagwW>D> OaARWN=- Introduction and Summary of Analysis of LNG Project Options............cccccscseseeeeeeeeeesees 4-1 Background The LNG Project Options The Y Line Option Analysis of the NPV of the LNG Project Options... Calculation of LNG Prices LNG Volumes Costs and Schedule Related to LNG Scenarios ... Comparison of LNG and TC Alaska Costs and Tariffs... Estimated State NPVs.... Comparison of Estimated NPVs Produced by the TC Alaska Project and a Ee NR ress on cna RNR URE RRN A LedaAi han 4-35 TC Alaska’s Project Has a Greater Likelihood of Success Than Any OTS LNG IE assis cccccccrssrerernrencennnemenn OER ENNE RECENT 4-43 An LNG Project Would Be Significantly More Complex, and Thus More Risky, Than an Overland Route An LNG Project Would Be More Difficult To Finance Than an Overland Route ... There Is a Significant Risk LNG Would Not Provide Open Access to Future Explorers, In Contrast With the TC Alaska Project .............c:ccccescssesseseesssseeeseeeeneeenees 4-47 The Major North Slope Producers Have Indicated Their Preference for An Overland Route Over the LNG Options. ...........cccccscessscseessessecneeeeeeeseeeeeeeeteeseneeeeaeeeee 4-48 An LNG Project Will Require Proven and Committed Reserves (Certified by Experts) to be Dedicated to the Project. ...........c:ccceseseeesesseeeseeeeseeeee 4-50 114-43 4-46 6. t G. H. Exporting LNG To Asia Presents Regulatory and Political Barriers That the TC Alaska Project Would Not Face..........cscscssseseesessscsessesessseneesesenseseesenesaeeeeseees 4-50 An Overland Route Has a Better Opportunity than an LNG Project To Spur a Petrochemical Industry CONGCIUSION (...250.c0sneesseressensse0n FRETOPENCES............scscscecesnnenonednescesduastnssiecsssacseensaarsrosesscasanssssssanesseees CHAPTER FIVE COMPARISON OF THE TC ALASKA PROPOSAL WITH THE PROPOSAL BY BP/CONOCOPHILLIPS A. introduction and Summary 6f Concho o. sisississcsinsscsssisicnccrcencasccnmanninannncasnievammanesans 5-1 B. The History of SGDA and TAPS Illustrates the Risks Posed by a Producer-Owned Pipeline 1. The State’s Experience Under SGDA 2: C. TC Alaska—Commitments; Producer Project—No Commitments... 1. Capital Structure 2. Expansion..... 3. Rolled-in Rates 4. Commitments To Hold an Open Season and File at FERC, and Other Issues That Could Result in a Delay of the Producer Project...........:c:csccsssesessseeseeseeeeeeeeeeee 5-17 D. A Producer-owned Pipeline Has an Incentive to Act in Ways That Are Contrary to the Best Interests of the State E. Both TC Alaska and the Producer Projects Lack Firm Shipping Commitments............... 5-24 F. Comparison of the Costs to the State Following the TC Alaska Project Path or the Producer Project Path G. TC Alaska’s Offer of Equity Partnership H. The Upstream Inducements Provided by AGIA are Valuable and Incentivize the Producers to Commit Gas to the TC Alaska Project |. It is in the State’s Interest to Pursue the TC Alaska Project J. Conclusion K. References. CHAPTER SIX FINDINGS AND DETERMINATION Commissioners’ Findings Commissioners’ Determination Figures Figure 2-1: Figure 2-2: Figure 2-3: Figure 3-1. Figure 3-2. Figure 3-3. Figure 3-4. Figure 3-5. Figure 3-6. Figure 3-7. Figure 3-8. Figure 3-9. Figure 3-10. Figure 3-11. Figure 3-12. Figure 3-13. Figure 3-14. Figure 3-15. Figure 3-16. Figure 3-17. Figure 3-18. Figure 3-19. Figure 3-20. Figure 3-21. Figure 3-22. Figure 3-23. Figure 3-24. Figure 3-25. Figure 3-26. Figure 3-27. Figure 3-28. Figue 3-29. PUDSUS NOW seccccceescecsiecsecsccacies axccecusspssecssavscevsvecesssnscessusssoninsssevevesviseusiseassaveeeres Natural Gas Production Potential LNG Trading Routes from Alaska.... Map of TransCanada Pipeline Operations 3-4 Present Value of $100 Cash Flow in Future...........cccccscesesseeeeeeeeeeeeeeeeeneeeeeeee Present Value of $100 Cash Flow in Future Years Sensitivity of State NPV to Discount Rates NPV Modeling Annual Henry Hub Price... EIA-Based Henry Hub and AECO Price Forecasts to 2045 (Nominal dollars) ..........c:cccccecssesessesseseeesssssscessseessseeseseaseseaseseeeseeeeseess Wood Mackenzie-Based Henry Hub Forecast to 2045 (Nominal dollars) .. Wood Mackenzie Basis Forecast ssssscisssccsscssssesccssscssscxsscasarsesseesseessxostasaversonssa Wood Mackenzie-Based Henry Hub and AECO Price Forecasts £0 2045i(Nomiliall COM ans) iutsscscess ces cuscoxenseoseconsesssssevussonssusvautensvevssevscsuesoussonesess 3-27 Black and Veatch Henry Hub and AECO Price Forecasts to 2045 (Nominal dollars) ..........::ccccccesscsscesseeeeeecseseceeseseeeecesseceeseceeseeseeseeseaees U.S. Gas-fired Power Generation Demand Distribution Range. WCSSB Finding and Development Cost Curve (Real 2008 $). U.S. Lower 48 Industrial Demand Distribution Range Relative Impact of Price Drivers on AECO HUB Price Formation, 2022 (Nominal $) Distribution Range of AECO Price Forecasts over Time (Nominal $).... AECO Price Forecasts (Nominal $) Production Profile for Proposal Base Case... Production Profile for Conservative Base Case Subproject Component Cost Ranges—Derivation Process Proposal Base Case Cost Distribution—Alaska Pipeline Proposal Base Case Cost Distribution—Yukon-BC Pipeline . Proposal Base Case Cost Distribution - GTP .........ceeeceeeeeeeeeeeeseseeneeeeeeneeeee - Proposal Base Case Cost Distribution—Integrated Project .............:cceceeees - Project Cost Risk: Comparing Project Escalation with Project Scope Risks Showing Cost Uncertainty and Risk Increasing With Escalation Rates isscccsccscccsscasscsssonvssncsocnsconanstassessescassstsassnsvactscassussvaascwecuncen 3-54 Tariff Distributions by Project Throughput:Smaller Projects Give FANUC FRG FU IT ssseecte ceca pccec ramet na exsist scov come one vae tasceooensaseasvanntvacinetenseereeteareateemn 3-57 State NPV5 Tornado Diagram: The Relative Importance of Different Project Risks State NPV5 Sensitivity to Price .. Comparing TC Alaska Pipeline Tarif (Nominal $) with Various AECO Price Forecasts ..........csccccsessesesseseeeeeeseeesseecseecassasecsesecessecaseasseeesseeateass 3-66 v1 3-64 -.3-65 Figure 3-30. Figure 3-31. Figure 3-32. Figure 3-33. Figure 3-34. Figure 3-35. Figure 3-36. Figure 3-37. Figure 3-38. Figure 3-39. Figure 3-40. Figure 3-41. Figure 3-42. Figure 3-43. Figure 3-44. Figure 3-45. Figue 3-46. Figure 3-47. Figure 3-48 Figure 3-49. Figure 3-50. Figure 3-51. Figure 4-1. Figure 4-2. Figure 4-3. Figure 4-4. Figure 4-5. Figure 4-6. Figure 4-7. Figure 4-8. Figure 4-9. Figure 4-10. Producer NPV, Tornado Diagram: The Relative Importance of Differont Project! RISKS saci ccssisscrssvensesscsnsnssoossessssaeeressnsenisusnenseassarsconstssocorsnenssnees 3-68 Pipeline Tariffs Under Proposal, Conservative, and Low Volume Cases State NPV5 Under Proposal, Conservative, and Low Volume Cases.............. 3-72 Aggregate Producer NPV Under Proposal, Conservative, and Lcrwy WIN OOD icons sceccainccccemns seen mimnamanemanenmammannnamennmamenannecettaRt Impact of Contract and Depreciation Periods on AECO Tariff Reserve Risk: Producer NPV Assuming No YTF Gas Reserve Risk: Yearly Net Back Cash Flow State of Alaska NPV5 with and without $500m match ... AGIA Roll-in-Rate Provision Schedule Risk of Proposal Base Case.... - Impact of Commercial Terms of Transportation Contracts to AECO Tariff ....3-109 Impact of Commercial Terms of Transportation Contracts to Producer NPV 36 ANG NPV ta\eciccsecseaceccecssszncassanazerancavessescvececssevesteserseseserssesesens 3-110 Tariff Consequences of Cost Overruns With and Without 100% DO bt FINGINCING can cescicerisvsesssscessnosnaesssceavacesnssasetanousononsensnteeveseressenseasnisnssssssniess 3-115 TransCanada NPV8.8 Sensitivity Consequences of Cost Overruns With and Without 100% Debt Financing ...ssssscesennsmsssensssennirenrnonemnccins TransCanada NPV8.8 For Different Project Configurations U.S. Government NPV; For Different Project Configurations State NPV; For Different Project Configurations ..............:ccccssessesseseeseeseeseeee Percentage Price Drop Necessary to Generate NPV of Zero For Producers’ Proved R@SEIVES ...........::ccccsseecsestseesseesessseeeeeeeessesesseeceeseesens 3-131 Aggregate Producers NPV; - 4.5 BCF/d Proposal Base Case With and Without Price Uncertainty ...........::.cceceeccesseseesseseneeeeeeeeeeseeseeseeseeseeseeeeeeees 3-132 Real AECO Price Forecasts vs. Tariff + Fuel ............ccesccscseseeeseeeseseseeeneeenees 3-133 Aggregate Producers NPV Uncertainty for the 3.5, 4.0, and 45 BCH CASES sicscscsevicscacesnsessaveisncscssossseseusscssessnssssenasonscesassesescsssvessoovcssseseuees 3-134 Impact of Different Periods of Fiscal Uncertainty for Producer NPVjp............ 3-139 Asian LNG Price Formula: The Historical Period 4-13 Japanese ‘S’ Curve for LNG Pricing: The Historical Period .............::scecsesees 4-14 More Recent Japanese, Korean, Tawainese, and Chinese LNG Prices Related to Crude Oil Price 1 Asian LNG and Henry Hub Prices in the Different Scenarios (Real 2007)....... Historical Oil to Gas Price Ratio ...........cccccescessseesseeecessseseeessseeeeeeeeneeenes -4-18 Cost-Risk Profile for the LNG Base Case GTP Plant Construction...............2++ 4-21 Cost-Risk Profile for the LNG Base Case Delta Junction to Valdez Pipeline Construction ............sceecsesccsecssccvssscossosssssnatsnscenssosscsenecssccsssesscescscseoens 4-22 Cost-Risk Profile for the LNG Base Case LNG Plant Construction................4. 4-24 Execution Cost Probability Distribution for a 4.5 Bcf/d Integrated LING IPROJ6CC................0.n05ecsssesesavaeseceesenonancssessvaaweaseesiarscnasenescessnreeneneustvessvesesteed 4-26 Tariff Comparison: 4.5 Bcf/d LNG vs. TC Alaska Proposal Base Case ........... 4-28 Figure 4-11. Fuel Loss Comparison: 4.5 Bcf/d LNG vs. TC Alaska Proposal Base Case....4-29 Figure 4-12. Tariff Comparison Including Estimated Incremental Fuel Costs: 4.5 Bcf/d LNG vs. TC Alaska Proposal Base Case Figure 4-13. Tariff with Incremental Fuel Costs and Shipping Costs Figure 4-14. Tariff Build Up Figure 4-15. State Net Present Value Under Different LNG Project Configurations............. 4-34 Figure 4-16. Margins of LNG Project versus a Pipeline Project..............scceessesseeseeseeeeeseeees 4-35 Figure 4-17. State NPV: Comparing TC Alaska Proposal Base Case and 4.5 Bcf/d LNG Scenario Under Different LNG Contract Price Assumptions.....4-36 Figure 4-18. Major North Slope Producers’ NPV: Comparing TC Alaska Proposal Base Case and 4.5 Bcf/d LNG Scenario Under Different LNG Contract POI PE cs ccencsoccsaniomnesnenrmcnecencneerenenaumnanennennanrerrwerevrerr——l 4-37 Figure 4-19. Price vs. Tariff for a 4.5 Bcf/d LNG Project and the 4.5 Bcf/d Proposal BaseiCase) Pipeline Prokectsrecccrsersqcevecrsscocoscaseaccesctraasaccceseacerssccecoseseesocesccessacee? 4-38 Figure 4-20. Comparative State NPV; Distributions Associated with Project Cost Risk....... 4-39 Figure 4-21. Comparative Producer NPV Distributions Associated with Project Cost Risk Figure 4-22. State NPV Under LNG and TC Alaska Pipeline Cases... Figure 5-1: —_ Impact of Capital Structures on Tariff Rates. Figure 5-2: — Impact of 50/50 debt to equity ratio Tables - ee _ Table 2-1: Contractor EXpertiSe:<<....ccs-scs:cccoconscacascccoceasccnsccnscacausdnastbasstcc=ceezsterastecseststsSattre 2-11 Table 3-1. NETL’s Estimate of Economically Recoverable Natural Gas Reserves........... 3-41 Table 4-1. Liquefaction Plant; Cost RANGES \scccccrcscrscccsrscnsccreserencsocesaracecetsscssccsesreacesonsencnes=t 4-25 Table 4-2. Stakeholder NPV for 4.5 LNG Project Under Alternative Scenarios-Base\Gase) ING ci snccccccccceccoccccccccscsconcasccacstenstsefestazset-csasaaevsueastietsTa 4-41 APPENDICES Appendix A: Appendix B: Appendix C: Appendix D: Appendix E: Appendix F: Appendix G1: Appendix G2: Appendix H: Appendix I: Appendix J: Appendix K: Appendix L: Appendix M: Appendix N: Appendix O: Appendix P: Appendix Q: Appendix R1: Appendix R2: Appendix R3: Appendix R4: Appendix R5: Appendix R6: Appendix R7: Appendix R8: Appendix S1: Appendix S2: Appendix S3: Appendix T: Appendix U: Public Comments and Responses AGIA Statute AGIA Overview and Completeness Review TransCanada Correspondence Post Completion Consultant Qualifications Technical Team Analysis of the TransCanada AGIA Application AGIA NVP Report Assessment of Commercial Likelihood of Success (LOS) pursuant to AGIA Section 49.90.170(c) Analysis and Findings Regarding TransCanada’s AGIA Application Potential LNG Production from North Slope Gas Regulatory Issues Report Expected Returns and Approval Economics The Prospect Exploration Economics Outlook for Yet-to-Find North Slope Natural Gas Resources Briefing Paper on Wood Mackenzie Long Term Outlook Summary of Findings for Resource Assessment and Field Development Study of the Thomson Sand, in the Point Thomson Alaska Natural Gas Pipeline - Employment Impacts Modeling AGIA Training Strategic Plan - A Call to Action Summary Analysis of TransCanada Contingent Liability Issues Export License Considerations for LNG Export Terminal Lack of Open Access for LNG Export Terminal Competitive Analysis of Producer - Owned Alaska Natural Gas Pipeline Review of TransCanada’s Corporate Integrity and Good Business Ethics as Required by AGIA Examples of Approved Capital Structure and Return on Equity (ROE) for Major New/Expansion Projects New Pipeline Projects that have used Negotiated Rates to Allocate the Risk of Potential Cost Overruns Producer-owned Pipeline Bennett Jones Report Comments on TransCanada’s Business Ethics Rolled-in vs. Incremental Tolls Applicable State and Federal Statutes AGIA License Acronyms and Abbreviations AEO Annual energy outlook AGIA Alaska Gasline Inducement Act, AS 43.90 et. seq. AMEC AMEC-Paragon Engineering Company _ ANCSA Alaska Native Claims Settlement Act, 43 U.S.C. § 1601 ANGPA Alaska Natural Gas Pipeline Act, 15 U.S.C. §§ 720 et. seq. ANGTA Alaska Natural Gas Transportation Act, 15 U.S.C. §§ 719 et. seq. ANGTS Alaska Natural Gas Transportation System ANNGTC Alaska Northwest Natural Gas Transportation Company AS Alaska Statute BC British Columbia Bef billion cubic feet Bcfid billion cubic feet per day BMP Best Management Practices Btu British thermal unit BV Black and Veatch cf cubic foot CO, carbon dioxide CPCN Certificate of Public Convenience and Necessity C.F.R. Code of Federal Regulations DNR Alaska Department of Natural Resources DO designated officer DOE U.S. Department of Energy DOG Alaska Division of Oil & Gas DOT Department of Transportation DOT-PHMSA | Department of Transportation, Pipeline and Hazardous Materials Safety Administration EIA Energy Information Administration EIS Environmental Impact Statement EOR enhanced oil recovery EPA Environmental Protection Agency EPC engineering, procurement and construction EPCM engineering, procurement and construction management ERR Economically recoverable reserves Se degrees Fahrenheit FEED front end engineering design FERC Federal Energy Regulatory Commission FID Final Investment Decision FPC Federal Power Commission GAAP. generally accepted accounting principles GHV gross heating value GTP gas treatment plant H2S hydrogen sulfide H20 Water HSE health, safety and environment IRR Internal Rate of Return 10S International Organization for Standardization LNG liquefied natural gas LOS Likelihood of Success LSCC Little Susitna Construction Company MAGTC MidAmerican Energy Holdings Company and MEHC Alaska Gas Transmission Company, LLC MAOP maximum allowable operating pressure m? cubic meters Mbpd Million barrels per day mef thousand cubic feet mmBtu million British thermal unit mmef million cubic feet MMS US Department of Interior Minerals Management Service NARG North America Regional Gas Model NBP Northern Border Pipeline NEB National Energy Board (Canada) NEB Act National Energy Board Act NEPA National Environmental Policy Act NETL National Energy Technology Laboratory NGA Natural Gas Act, 15 U.S.C. § 717 et. seq. NGL natural gas liquid NPA Northern Pipeline Act, 1977-78, c. 20, R.S., 1985, c. N-26 NPRA National Petroleum Reserve - Alaska NPV Net Present Value NYMEX New York Mercantile Exchange OCs Outer Continental Shelf OFI Office of the Federal Inspector OGIP Original gas in place O&M operations and maintenance OSHA Occupational Safety and Health Administration PA Precedent Agreement PDF Portable Document Format PFC Petroleum Finance Company | psi pounds per square inch | psig pounds per square inch gauge QP. Qatar Petroleum RCA Regulatory Commission of Alaska RFA Request for Applications RIK Royalty-in-Kind RIV Royalty-in-Value ROW right-of-way SCF standard cubic feet SGDA Stranded Gas Development Act AS 43.82 SME Subject matter expert TAGS Trans-Alaska Gas System TAPS Trans-Alaska Pipeline System TCAlaska TransCanada Alaska Company, LLC and Foothills Pipe Lines, Ltd. tcf trillion cubic feet TransCanada | TransCanada Corporation TRR Technically recoverable reserves TSM TAPS Settlement Methodology U.S.C. United States Code USGS United States Geological Survey WCSB Western Canada Sedimentary Basin YESEAA Yukon Environmental and Socio-Economic Assessment Act YPC Yukon-Pacific Corporation YTF Yet to Find YTG Yukon Territorial Government Glossary TERM DEFINITION Acceptable Credit Rating A Credit Rating not lower than any of the following: “BBB-” from Standard & Poor's, a division of the McGraw-Hill Companies, Inc. and its successors and assigns (S&P), “Baa3” from Moody’s Investors Service, Inc. and its successors and assigns (Moody’s), “BBB-” from Fitch Ratings Ltd. and its successors and assigns (Fitch), or “BBB (low)” from Dominion Bond Rating Service Limited and its successors and assigns (DBRS). In the event an entity is rated by two or more of S&P, Moody's, Fitch and DBRS, the lowest rating shall prevail. Actual Capital Cost The capital cost that is approved by FERC in the U.S. and the Northern Pipeline Agency and National Energy Board in Canada as the final capital cost of the Project following the In-Service Date and which TransCanada is authorized to include in the Project rate base for the recovery and return calculation pursuant to such approvals. AECO The Alberta Energy Company (AECO) hub was originally a storage facility in Alberta where natural gas was bought and sold. As suppliers and customers increasingly used this storage facility to buy and sell natural gas, the location was quickly established as the point at which the benchmark Alberta price was established in the marketplace. While this storage facility still exists, AECO today generally refers to the Alberta gas price and Alberta pricing point. When gas is said to be traded at the AECO hub, it is actually being traded on a notional (non-physical) point on the Nova Inventory Transfer pipeline system. AGIA Commissioners Commissioner of Revenue and Commissioner of Natural Resources Agreement on Principles Agreement Between the United States and Canada on Principles Applicable to a Northern Natural Gas Pipeline, September 20, 1977, U.S. — Can., 29 U.S.T. 3581. Alaska Open Season The process that complies with 18 C.F.R. Part 157, Subpart B (Open Seasons for Alaska Natural Gas Transportation Projects) pursuant to which TransCanada shall solicit initial binding commitments from potential Shippers for capacity on the Alaska Section, and the GTP in the event TransCanada is the sponsor for the GTP, which shall take place concurrently with the Yukon-BC Open Season and the Alberta Open Season. Alaska Section The section of the Pipeline System located in Alaska which runs from the outlet of the GTP near Prudhoe Bay, Alaska to the Alaska/Yukon border near Beaver Creek, and which would include related pipeline, compression, measurement and other permanent and temporary facilities located in Alaska. Alaska Shippers Those Shippers that commence service at a receipt point on the Pipeline System in Alaska. Alberta Hub The natural gas trading hub on TransCanada’s Alberta System, where natural gas and natural gas liquids are traded and which trading activities are facilitated by the NOVA Inventory Transfer (NIT). Alberta Open Season The process pursuant to which TransCanada shall solicit initial binding commitments from potential shippers for capacity on the TERM DEFINITION Alberta Section and TransCanada’s Alberta System from the British Columbia/Alberta border near Boundary Lake to the Alberta Hub and further downstream for deliveries to the Alberta border, which shall take place concurrently with the Alaska Open Season and the Yukon- BC Open Season. Alberta Section The existing Foothills Pre-Build System located in Alberta and any new pipeline required to be built and owned by Foothills in Alberta in order to provide access to the Alberta Hub from the Yukon-BC Section, including related pipeline, compression, measurement and other permanent and temporary facilities owned by Foothills and located in Alberta. Alberta System TransCanada Corporation’s wholly-owned, 15,000 mile natural gas transmission system in Alberta which gathers natural gas for delivery to end users and to liquids extraction facilities within the province and for delivery through provincial export locations to major natural gas market areas across North America. The Alberta System is a significant component of the Alberta Hub. Anchor Shipper A shipper who has reached an agreement with the pipeline sponsor, generally through one-on-one negotiation to support the project, by making a large early commitment to capacity on the proposed pipeline. Antitrust Opposing or intended to regulate business monopolies, such as trusts or cartels, especially in the interest of promoting competition. ANS The Alaska North Slope, which is the portion of Alaska north of sixty- eight degrees North latitude. ANS Explorers Those companies that have been or will be exploring for natural gas on the North Slope of Alaska. ANS Producers BP Exploration (Alaska) Inc., ConocoPhillips Alaska, Inc. and ExxonMobil Alaska Production Inc. Base Capital Cost The capital cost of the Pipeline System that is approved by FERC in the CPCN in Alaska and by the Northern Pipeline Agency and National Energy Board in the Leave to Construct in Canada. Basin Control The ability of the Major North Slope Producers to control the North Slope basin and discourage competitor producers from initiating and/or increasing their exploration and production activities in the area due to potentially high tariffs and uncertain access to essential pipeline capacity to move new production to markets. Basis Point One hundredth of a percentage point, or 0.01%. This term is usually used to discuss small fluctuations in equity indexes, interest rates, and yields on fixed annuities. Blow Down The rapid production of either oil or natural gas from a hydrocarbon reservoir. In terms of the Prudhoe Bay Unit and other mature reservoirs on the North Slope, blow down will signal a shift from a production approach that is designed to maximize the production of oil to an approach that is focused on the production of natural gas. Bridge Shipper An entity, usually governmental, that temporarily covers some of the unused capacity or commitments in the event that the new pipeline fails to attract enough paying customers to fill it. TERM DEFINITION Canada Open Season The combined Yukon-BC Open Season and the Alberta Open Season. Canada Section The Yukon-BC Section and the Alberta Section. Capital Cost Overrun That amount, if any, by which the Actual Capital Cost of the Pipeline System exceeds the Base Capital Cost or other agreed to amount. Capital Cost Overrun Loan The project loan which credit is proposed to be enhanced by the U.S. Loan Guarantee, and pursuant to which a Capital Cost Overrun would be financed. Capital Cost Overrun Surcharge The provisional toll which Surcharge Shippers are required to pay, when the market gas prices at the Alberta Hub are above a pre- determined threshold, for servicing the Capital Cost Overrun Loan. Central Gas Facility Existing facility at Prudhoe Bay that provides initial processing of the wet natural gas that has been separated from the ANS crude oil stream. Some natural gas liquids are extracted and the remaining gas stream is, for the most part, discharged for re-injection. Collateral (i) an irrevocable standby letter of credit from a financial institution acceptable to TransCanada with a Credit Rating of at least A by S&P and A2 by Moody’s; or (ii) unencumbered cash collateral in a form satisfactory to TransCanada; or (iii) other collateral which may be mutually acceptable to the shipper and TransCanada. Commission or FERC Federal Energy Regulatory Commission Contingent Liability Liabilities that may or may not be incurred by an entity depending on the outcome of a future event such as a court case. Credit Rating The respective rating assigned to the long-term senior unsecured debt (not supported by third party credit enhancement) of an entity by S&P, Moody’s, Fitch or Dominion Bond Rating Service and their respective successors and assigns. If an entity does not have a long- term senior unsecured debt rating, the corporate Credit Rating (or deemed equivalent) shall be used as a substitute. Cure Period A provision in a contract allowing a defaulting party to fix the cause of a default, for example a repayment grace period. Decision to Proceed The transition point between the Development Phase and the Execution Phase of the Project; the major Project milestone at which the final decision is made with respect to whether to proceed to execution of the Project or not. Definition Sub-Phase That portion of the Development Phase that begins with the conclusion of the Open Season and ends when all major Project approvals are in place and the final Decision to Proceed has been made. Delivery Point Any point on the Pipeline System where gas may be taken off the Pipeline System. Discount Rate AGIA specifies various discount rates to be analyzed in considering the NPV of future cash flows to the state. The discount rates specified are zero, five, six, and eight percent. Divisible Income The net cash flow from the proposed project. Dry Gas Natural gas that does not contain significant condensates or liquid hydrocarbons. End User The ultimate consumer of a product, especially the one for whom the TERM DEFINITION product has been designed. FERC Open Season | The FERC regulations as set forth in 18 C.F.R. § 157, Subpart B Regulations (Open Seasons for Alaska Natural Gas Transportation Projects). Firm Transportation The transportation service provided to a Shipper on a pipeline system Service pursuant to a Transportation Services Agreement (TSA) between the Shipper and a pipeline whereby the pipeline agrees to make available to the Shipper on a firm basis the capacity on the pipeline system subscribed for in the TSA and the Shipper agrees to pay for such capacity as per the TSA whether the Shipper uses such capacity or not. First Nations peoples The Indian peoples of Canada, both Status and non-Status, as defined in the Indian Act, R.S., 1985, c. I-5. Foothills System or Foothills Pre-Build or Pre-Build The existing natural gas pipeline system built under certificates issued pursuant to Canada’s Northern Pipeline Act that starts at Caroline, Alberta that branches into two legs, with one leg running south-east to Monchy, Saskatchewan and the other leg running south-west to Kingsgate, British Columbia, which is owned by Foothills Pipe Lines Ltd., a wholly-owned subsidiary of TransCanada Corporation. Gas Cap An oilfield term indicating the condition which occurs as oil is removed; the gas becomes mobilized and accumulates as a “gas cap” on the oil formation. Also, the portion of a reservoir occupied by free gas (gas not in solution). Gas Treatment Plant (GTP) In the TransCanada application, the GTP is necessary for treating some natural gas that is to be shipped via pipeline from the Alaska North Slope (ANS). The GTP will process over 5 billion cubic feet per day (bcf/d) of residue gas from the existing Central Gas Treatment Facility located at Prudhoe Bay. This residue gas would be treated by removing the undesirable constituents (e.g., CO2) by dehydration and filtration processes. The 4.5 bcf/d of sales gas would be chilled to 28°F and compressed to 2500 pounds per square inch gauge (psig) prior to shipping. The CO2 would be returned to the residue gas stream and re-injected into the Prudhoe Bay reservoir. Guarantee A financial guarantee in the form acceptable to TransCanada from a party with an Acceptable Credit Rating. Henry Hub The Henry Hub is a pipeline interchange located near Erath, Louisiana. The Henry Hub is the designated delivery point for the NYMEX Natural Gas futures contract. The Henry Hub is also a highly liquid trading point, with numerous buyers and sellers of both physical natural gas and financial derivatives. The Hub provides access to more than a dozen interstate and intrastate pipeline interconnects Hub A major natural gas receipt and delivery and/or trading point. Hurdle Rate The minimum rate of return producers must achieve to pursue a project. In-Service Date The date for Commencement of Commercial Operations of the Pipeline System. In-State Shippers Those Shippers that subscribe for transportation services with the Alaska Section for natural gas delivery to a delivery point within the TERM DEFINITION State of Alaska. Internal Rate of Return The internal rate of return (IRR) is a metric used to determine the efficiency of an investment, as opposed to the net present value (NPV), which indicates value or magnitude. The IRR is the annualized effective compounded retum rate which can be earned on the invested capital, i.e., the yield on the investment. Investment Grade Applies to an assessment of a shipper’s creditworthiness and means a long term senior unsecured debt rating of at least BBB- by Standard & Poor's (S&P); Baa3 by Moody’s Investor Services (Moody’s); BBB- by Fitch Ratings (Fitch); or BBB (Low) by Dominion Bond Rating Service (DBRS). Leave to Proceed Has the meaning ascribed to it in Section 2.2.4.2(2) “Canadian Regulatory Approvals”. Levelized cost The present value of the total cost of building a pipeline over its economic life, converted to equal annual payments. Costs are levelized in real dollars (i.e., adjusted to remove the impact of inflation). License The license to be granted under the Alaska Gasline Inducement Act, AS 43.90 et. seq. Line Pack A quantity of gas purchased for operational (non-commercial) use by the pipeline entity to fill and pressurize the pipeline prior to the commencement of commercial operations. The line pack quantity is generally considered a permanent part of the pipeline’s asset base (and its cost is included in the tariff), allowing the pipeline to deliver gas for a shipper at a pipeline delivery point at the same time the shipper delivers that quantity of gas to a pipeline receipt point. Lower 48 The contiguous states of the United States, i.e. not including Alaska or Hawaii. Mainline The large diameter pipeline that is routed generally along the TAPS pipeline and the Alaska Canada Highway, compressor stations and related facilities, including any additions, improvements, expansions, extensions or renewals or replacements to the pipeline, compressor stations, or related facilities, designed to transport gas from the ANS to off-take points and to connect with other pipelines. Major NS Producers Phrase used to describe major North Slope producers including Exxon, British Petroleum, and ConocoPhillips Management Committee A committee of senior representatives of TransCanada who direct the organization and who will provide executive guidance to senior management of the Project and will consider approvals for significant Project scope and budget changes. Midstream Capital Costs The capital costs of the pipeline, GTP, compressor stations, and (as applicable) LNG liquefaction facilities are a key input into the Midstream Model, and significantly affect Midstream tariffs. Midstream Divisible Income Consists of profits for the pipeline owner as well as property and corporate income taxes. Midstream Element Means a gas transmission pipeline, a gas treatment plant, the main pipeline (mainline), compressor stations, or a NGL plant. TERM DEFINITION Natural Gas Liquids Natural gas liquids include propane, butane, pentane, hexane and heptane, but not methane and ethane, since these hydrocarbons need refrigeration to be liquefied. Net Present Value (NPV) Net Present Value is an economic calculation used to appraise the financial value of long-term projects. An NPV calculation figures the present value of an investment that may generate returns for many years; in short, the AGIA NPV calculation allows us to understand, in terms of today’s money, the profits (or losses) that an Offeror's AGIA Application offers the State. Negotiated Rate Shippers Those Shippers that have elected to pay the transportation tariff/toll in accordance with the Negotiated Rate has the meaning ascribed to it in Section 2.2.3.7 “Negotiated Rates” Net Back value The net back value is defined as the unit price or value of a product such as natural gas at a particular point on the pipeline (or upstream of the pipeline such as at the point of production.) The net back value is calculated by subtracting from the downstream sales price of that product all the costs incurred to deliver the product to the point of sale. Net Cash Flow The net cash flow from gas, or “Upstream Divisible Income’, is: (1) the final destination price of the gas, times (2) the volume of gas transported, minus (3) total tariff payments and (4) out of pocket production costs. NOVA Inventory Transfer or NIT A notional point on TransCanada’s Alberta System that acts as a market hub, where the transfer of title to gas transported on such system occurs, and which transfer can only occur following payment by the shipper of the receipt toll. NIT functions as both a market and supply hub by providing direct access to over 300 bef of connected storage, a large (3 bef/d) intra-Alberta market and multiple pipelines which transport approximately 17 bcf/d to major markets across North America. Off-take Point A delivery connection location, consisting of necessary valves, flanges and fitting, where gas flows out of a mainstream pipeline to other pipelines for distribution. On Spec On speculation, or speculatively. Open Season An open season is the process during which a pipeline company seeks customers to make firm transportation commitments (usually long-term) to a project, e.g., the concurrent initial binding Alaska Open Season, Yukon-BC Open Season and Alberta Open Season. An open season is the process during which a pipeline company seeks customers to make long-term firm transportation commitments to a project. Px Indicates that an outcome or proposed action has a X% likelihood of occurring. For example and outcome of proposed action of Ps, has a 50% likelihood of occurring. Precedent An agreement between a Shipper and TransCanada entered into Agreement following the completion of the Alaska Open Season, the Yukon-BC Open Season or the Alberta Open Season, as applicable, pursuant to which such Shipper agrees to commit a certain amount of gas to the Alaska Section, the Yukon-BC Section or the Alberta Section and vi TERM DEFINITION TransCanada’s Alberta System, as applicable, which shall be superseded and replaced by the Transportation Services Agreement prior to the In-Service Date. Proposal Sub-Phase That portion of the Development Phase that begins with the award of the AGIA license and ends with the conclusion of the Open Season Proved Reserves Reserves of natural gas that are claimed with reasonable certainty (80% to 90% confidence) to be recoverable in future years by specified techniques. Ratemaking The practice of establishing rates of payment for services, as for public transportation or utilities. Rebuttable An assumption made by a court, one that is taken to be true unless Presumption someone comes forward to contest it and prove otherwise. Receipt Point Any point on the Pipeline System where gas may be put into the Pipeline System. Receipt Shippers Those Shippers that enter into a Transportation Services Agreement with TransCanada’s Alberta System pursuant to which the Shippers agree to deliver gas into the Alberta System and pay the receipt toll. Recourse Rate Recourse rates are cost-based rates set by FERC under conventional public utility rate-making methods. In Section 2.2.3.5(1) of TransCanada’s application Recourse Rate is used to describe that the 100% load factor for the Alaska section would be $1.06/mmBtu in constant 2007 dollars. Recourse Rate Those Shippers that have elected to pay the transportation tariff/toll Shippers for the Alaska Section in accordance with the Recourse Rate as described in Section 2.2.3.5 “Rate Structure and Supporting Information”. Regasification The practice of converting liquefied natural gas back into gaseous form to send to market, often after moving it into cold storage tanks. Rolled-in rates ls a term used by FERC to differentiate between rolling-in the construction costs of new pipeline expansion with the existing facilities or developing costs on an incremental basis (establishing separate cost-of-services and separate rates for the existing and expansion facilities). Royalty In-Kind Royalty is a share of production. When taken “in-kind” the State of Alaska physically takes custody of the oil or gas produced. Royalty In-Value When taken “in-value” the royalty share is left with the producer, who must sell 100 percent of the oil or gas, and pay the State of Alaska its royalty share of the net proceeds from the sale of 100 percent of the oil or gas, or the market value of the oil or gas, whichever is higher. Sealift The barging of large oil and gas field equipment from where it is built to where they are installed. Shippers Those entities that contract for gas processing and transportation services on the GTP and the Pipeline System. Sovereignty Supremacy of authority or rule as exercised by the State. Spend-Curve A component of calculating cost and schedule range data that shows when in the process the dollars will be spent to develop and construct the project. State State of Alaska Surcharge Shippers | Those Negotiated Rate Shippers that elect the Capital Cost Overrun vii TERM DEFINITION Surcharge option. Take or Pay Agreements between a buyer and a seller that obligate the buyer to Contracts pay a minimum amount of money for a product or service, even if the product or service is not utilized or purchased. Tangible Net Worth Total assets (exclusive of goodwill and other intangible assets) minus total liabilities, as reported in the provider's unqualified audited annual financial statements and unaudited quarterly financial statements in accordance with generally accepted accounting principles in the country in which the provider is organized, consistently applied. Tariff The rate and terms of service materials associated with operations of the pipeline. Frequently, this term only refers to the rates to be charged for particular services. Term-differentiated Rates Rates that that vary by the length of the contract term. These rates allow the pipeline to recover its capital costs from shippers over a longer period, thus lowering the rates paid by shippers that sign longer-term contracts. Transportation by Others or TBO Commercial arrangements whereby one pipeline system contracts for capacity on another pipeline system. The pipeline system taking the capacity uses it to provide integrated service to parties on its system. Transportation Services Agreement The agreement between a Shipper and TransCanada pursuant to which TransCanada agrees to provide natural gas transportation services on the Alaska Section, the Yukon-BC Section, the Alberta Section or TransCanada’s Alberta System, as applicable, to the Shipper and the Shipper agrees to abide by the terms and conditions of the agreement and pay the applicable tariff/toll for subscribing for capacity on the Alaska Section, the Yukon-BC Section, the Alberta Section or TransCanada’s Alberta System, as applicable. Twenty (20) Must Haves The twenty statutory requirements of the Alaska Gasline Inducement Act as specified in AS 43.90.130 Upstream Divisible Income The net cash flow from gas, or “Upstream Divisible Income’, is: (1) the final destination price of the gas, times (2) the volume of gas transported, minus (3) total tariff payments and (4) out of pocket production costs. Upstream Divisible Income is shared between the Producers, the State of Alaska, and the federal government through royalty, and state production taxes. Wet Gas Natural gas that contains methane and natural gas liquids such as butane, propane and ethane. Work Commitments A promise on the part of the participants to the fiscal contract to take the steps necessary to implement the gas pipeline project. With regard to the SGDA contract, work commitments refer to a promise on the part of the participants to the fiscal contract to take the steps necessary to implement the gas pipeline project Yet-to-find (YTF) area Production areas which, according to the NETL Alaska Gas Study and other sources, have a significant amount of economically recoverable reserves, but which have not yet been discovered. viii Units Bef/d billion cubic feet per day Btu British thermal unit (Btu). The term "Btu" is used to describe the heat value (energy content) of fuels. Calorific Content The heating value or calorific value of a fuel is the amount of heat released during combustion. Decatherms A decatherm is a measure of heat energy equal to 1,000,000 British thermal units (Btu). It is approximately the energy equivalent of burning 1000 cubic feet (often referred to as 10 Ccf) of natural gas Ft feet In Inches M Meter MMBTU MMBTU represents one million BTU, which can also be expressed as 1 decatherm (10 therms) MMTPA Million Metric Tons Per Annum. 1Bcf/d = 7.82 MMTPA | psig pounds per square inch gauge Tef trillion cubic feet Billion cubic feet per day (Bcf/d) — Million Metric Tons per Annum (MMTPA) Conversion Chart 50 zi a 5 4) = — 35 4 s = & 30+ Ss Oo 25 +4 a s 20 2 B 1s = f S10) 1 Befld = 7.82 MMTPA 0 — - - | 0 2 3 4 5 6 Billion cubic feet per day (Bcfld) A. B. 1. 25 C. Summary of Projects eee D. Maximizing Benefits for Alaskans ... Chapter One — Introduction and AGIA Table of Contents IntrodUCtiON ims nmeseeneeemt cc a ETT History of Alaska Natural Gas Pipeline Efforts The Stranded Gas Development Act Alaska Gasline Inducement Act The TC Alaska Application... The LNG Project Options The Producer Project The Bullet Line ..... LNG and an Overland Pipeline 1. Getting a Natural Gas Pipeline, Quickly... 2. Jobs and Long-term Careers for Alaskans 3. Affordable Energy for Alaskans................::c:ccceeee 4. Sufficiently Maximizing Revenues to the State and Its Citizens. 1-16 E. Summary 1-19 a -20 eo -¢ AGIA Introduction Written Findings and Determination A. Introduction Alaska’s North Slope is a world-class natural gas basin. Recent studies estimate that there are 224 trillion cubic feet (Tcf) of undiscovered, technically recoverable natural gas resources throughout the Alaskan Arctic. Of this amount, 137 Tcf are . ; . A natural gas pipeline from categorized as undiscovered, economically recoverable soo Re the North Slope could meet resources. These resources are in addition to the }| more than five percent of approximately 24.5 Tcf of natural gas reserves within | the United States’ current annual consumption of Prudhoe Bay plus 9 Tcf of natural gas reserves discovered in | natural gas for decades. other existing fields on the North Slope, including Point Thomson (USGS 2005; NETL 2007; Appendix O). Since the discovery of the Prudhoe Bay reserves, numerous entities have looked for ways to get gas to market. These efforts included state and federal laws designed to encourage gas pipeline construction, and millions spent on plans and studies by government sponsored authorities, North Slope oil and gas producers and various pipeline companies. The drafters of the Alaska State Constitution recognized both Alaska’s vast resource potential and the importance of resource exploitation. The State Constitution enshrined the principle that the state’s resources be managed for the benefit of Alaskans through the following two provisions: e It is the policy of the state to encourage the settlement of its land and the development of its resources by making them available for maximum use consistent with the public interest. (Constitution of the State of Alaska, Article VIII, Section 1) e The legislature shall provide for the utilization, development, and conservation of all natural resources belonging to the state, including land and waters, for the maximum benefit of its people. (Constitution of the State of Alaska, Art. VIII, Sec. 2) The Alaska State Constitution says it is essential for the The Alaska Gasline Inducement Act (AGIA) established an open resources be developed in a way that makes a lasting and competitive process for developing a natural gas future of Alaska that our state’s vast natural gas contribution to the state and its citizens and that a sent pipeline on terms that maximize maximizes benefits to Alaskans as envisioned by the benefits for the people of state’s founders. Alaska. 27 MAY 2008 1-1 AGIA Introduction Written Findings and Determination In 2007, the Alaska Gasline Inducement Act (AGIA) established an open and competitive process for developing a natural gas pipeline on terms that maximize benefits for the people of Alaska. Any pipeline will provide thousands of short-term construction jobs for Alaskans. But not just any pipeline will provide long-term jobs and careers, meet Alaska’s energy needs, and sufficiently maximize state revenues with minimal state concessions. Getting a gas pipeline constructed is one element necessary to meet these needs—another is maximizing gas resource development in order to provide for a secure future that benefits Alaskans now and for generations. 27 MAY 2008 AGIA History of Alaska Natural Gas Pipeline Efforts Written Findings and Determination. B. History of Alaska Natural Gas Pipeline Efforts For decades, Alaska has sought construction of a pipeline to develop and market the state’s natural gas resources. In the 1970s, three proposals were considered for federal authorization: an “over the top” pipeline; an in-state liquefied natural gas (LNG) pipeline; and an overland route from the North Slope to Canada. The overland route was selected and a consortium of U.S. and Canadian pipeline companies began acquiring financial backing. The economics of the time thwarted the pipeline effort and by 1982 the project was indefinitely stalled (FERC 2001). Starting in 1982, the state began taking a more active role in working toward a natural gas pipeline when then-Governor Hammond appointed a committee to guide the state efforts toward marketing North Slope gas. The committee examined an Alaska has sought construction of a pipeline to develop and Southcentral Alaska as the marketing point for the gas, market the state’s natural gas known as the Trans-Alaska Gas System (TAGS). The focuden, for more than three lecades. all-Alaska pipeline combined with an LNG terminal in Yukon Pacific Corporation acquired the pipeline right-of- way and other permits for the TAGS project but never moved forward with construction. Various other proposals for an Alaska-Canada overland pipeline and an all-Alaska LNG project have been put forward over the course of the past 20 plus years, but none resulted in construction of a gasline. 1. The Stranded Gas Development Act In 1998, the Stranded Gas Development Act (SGDA) was passed by the Alaska legislature, and amended in 2003. The Act provided the legal basis for developing a fiscal contract between the state and pipeline project sponsors. In 2004, five groups submitted pipeline proposals under the SGDA: BP, ConocoPhillips, and ExxonMobil (Major North Slope Producers or the Producers); TransCanada Corporation; Alaska Gasline Port Authority; Enbridge, Inc.; and MidAmerican Energy Holdings Company. The previous administration decided that the fastest way to getting a pipeline was through a contract on resource production terms that provided “fiscal certainty” to the Producers.’ (Alaska Department of Revenue 2006). The previous administration ultimately negotiated exclusively ' “Fiscal certainty” under the SGDA included “a commitment not to change the agreed upon rates for gas and oil severance or production taxes, corporate income tax, and property taxes, and to protect against imposition of other new taxes, such as a reserves tax, for the term of the contract.” (Alaska Department of Revenue 2006, p. ES-5) The tax freeze on oil and gas was from 35 to 45 years 27 MAY 2008 AGIA History of Alaska Natural Gas Pipeline Efforts Written Findings and Determination. with the Major North Slope Producers, resulting in public release of a draft fiscal contract with the Producers in May 2006. The proposed SGDA contract consisted of an unbalanced set of state concessions and so- called Producer “commitments.” The concessions made by the state under the contract were broad, material, long-term, and binding. They swept across fiscal and regulatory authorities and surrendered multiple aspects of the state’s sovereign rights and prerogatives. Furthermore, the terms harmed and frustrated the state’s interests in promoting the full exploration and development of natural gas resources in Alaska, limiting the potential for the creation of new exploration and In 1998, when the Stranded Gas Development Act (SGDA) was passed, the average price for natural gas in the Lower 48 was under $2 per million British thermal units (MMBtu). The first half of this decade was marked by discussions of what type and amount of government subsidies and concessions were needed to make the project viable. By 2006, the natural gas markets had changed dramatically. The average price of natural gas in the Lower 48 was more than $6 per MMBtu. Large government subsidies no longer appeared necessary to make the project economically viable. In addition, the state had become much better educated on natural gas pipeline economics. It learned that, if the state was not careful to protect its interests, billions of dollars in value could be transferred unnecessarily from the state to the Major North Slope Producers. development jobs on the North Slope. Nothing in the contract ensured development or construction of a gas pipeline. To accommodate the draft fiscal contract terms, the Alaska legislature would have needed to change the SGDA law as written. These changes were not passed by the legislature, and the negotiations between the state and the Major North Slope Producers ended in 2006, without approval of the proposed contract. 2. Alaska Gasline Inducement Act In 2007, the Alaska Gasline Inducement Act (AGIA) was passed by the Alaska Legislature with a nearly unanimous vote. The purpose of AGIA is to encourage, through an open and transparent process, expedited construction of a natural gas pipeline that: e Facilitates commercialization of North Slope gas resources in the state. e Promotes exploration and development of oil and gas resources on the North Slope. e Maximizes benefits to the people of the state from the development of oil and gas resources in the state. 27 MAY 2008 1-4 AGIA History of Alaska Natural Gas Pipeline Efforts Written Findings and Determination. e Encourages oil and gas lessees and other persons to commit to ship natural gas from the North Slope to a gas pipeline system for transportation to markets in this state or elsewhere. (AS 43.90.010) In July 2007, the state issued a Request for Applications The net present value of the anticipated cash flow to the for an AGIA license were received and submitted to a state, the project sponsor, and Major North Slope Producers for a license to be issued under AGIA. Five applications multi-step licensing process that included: werecaleulated (toc determine the overall economics of the e An evaluation of the completeness of each | project. application. e Solicitation and review of public comment on each complete application. e An evaluation of the net present value (NPV) of each complete application weighted by its likelinood of success (LOS). e An evaluation of whether any complete application maximizes benefits to Alaskans. e If an application maximizes benefits to Alaskans, provide public notice of and forward a Findings and Determination to the legislature of intent to award an AGIA license. A detailed explanation of each of these steps can be found in Appendix C. Only the TC Alaska Application was found complete. (A discussion of the process used to determine an application’s completeness can be found in Appendix C.) Following the completeness evaluation, TC Alaska’s proposed project was evaluated for the net present value of the anticipated cash flow to the state weighted by the likelihood of success for the proposed project.2 (See Chapter Three) The net present value of the anticipated cash flow to the state, Major North Slope Producers, and the project sponsor were all calculated to determine the overall economics of the project. Public comment on TC Alaska’s complete Application was solicited and considered. Following the evaluation of the complete Application and consideration of public comment on the ? If more than one application were found to be complete, the NPV and LOS evaluation would have been used to determine which application ranked the highest and whether that project sufficiently maximizes benefits to Alaskans. (AS 43.90.170) If, as in this case, only one application was found complete, the evaluation was used to determine whether the proposed project maximizes benefits to Alaskans sufficiently to merit issuance of an AGIA license. (AS 43.90.180) 27 MAY 2008 AGIA History of Alaska Natural Gas Pipeline Efforts Written Findings and Determination. Application, the Commissioners of the Departments of Natural Resources and Revenue @ compared the TC Alaska Application with the Producer Project and LNG options and evaluated whether the TC Alaska project sufficiently maximizes the benefits to the people of Alaska and merits issuance of an AGIA license. 27 MAY 2008 @ 146 AGIA Summary of Projects Written Findings and Determination. C. Summary of Projects Comments on the TC Alaska Application identified pipeline project alternatives including: e An export-oriented liquefied natural gas (LNG) project that would ship natural gas from the North Slope to a processing and shipping facility in Valdez. e A producer-owned overland pipeline from the North Slope to Canada. In order to fully evaluate whether TC Alaska’s proposed project would provide the maximum benefit to Alaskans, the commissioners compared the TC Alaska project with LNG options and the Producer Project. 1. The TC Alaska Application The TC Alaska Application proposes a 1,715-mile long, 48-inch diameter, mostly buried pipeline running from a gas treatment plant at Prudhoe Bay on the North Slope to the Alberta Hub in Canada. This is the second largest natural gas trading center in North America, which interconnects with pipelines that carry more than 10 Bcf/d of gas into U.S. markets. This overland pipeline’s base design is capable of carrying between 3.5 and 5.9 billion cubic feet per day (Bcf/d) of natural gas. The gas treatment plant will be constructed by a third-party or by TC Alaska. The Alaska section of the pipeline will be approximately 750 miles long with six compressor stations at startup and five gas delivery points in Alaska. The Application includes an initial expansion capability of up to 6.5 Bcf/d. Further expansions would include a combination of additional compression and pipeline looping. (See Chapter Three) 2. The LNG Project Options The commissioners evaluated the technical, commercial, and economic features of LNG options. These options were all based on a large-volume pipeline running from the North Slope to a new liquefaction facility located on Prince William Sound. The commissioners evaluated a number of pipeline configurations and throughput volumes to ensure that a comprehensive suite of LNG options were considered. (See Chapter Four) 3. The Producer Project On April 8, 2008, BP Alaska and ConocoPhillips announced “Denali™ - The Alaska Gas Pipeline” project (the Producer Project), an overland pipeline from the North Slope to Alberta, Canada. At this point, the only public information provided is contained in a 12-page PowerPoint 27 MAY 2008 1-7 AGIA Summary of Projects Written Findings and Determination. presentation and press release. The Producer Project recommends a 4 Bcf/d, large-diameter pipeline to the Alberta Hub, with extension of the pipeline to the Lower 48 if an extension is necessary. The project includes a gas treatment plant on the North Slope near the Prudhoe Bay facilities. The Denali™ PowerPoint presentation says that the project will support in-state gas distribution efforts and will provide at least five Alaskan natural gas delivery points, including one at Fairbanks (See Chapter Five). 4. The Bullet Line During the public comment period, many Alaskans raised concerns and asked questions about a small-diameter “bullet line” natural gas pipeline running from the North Slope to Fairbanks (and then presumably to a terminus in Southcentral Alaska). This bullet line would be designed and operated to meet the energy needs of Alaskans along the railbelt. The bullet line concept has been the subject of state review and evaluation in the recent past. In 2008, based on a request by the Governor, the Alaska legislature appropriated $4 million to the Alaska Natural Gas Development Authority to investigate in-state natural gas options. The AGIA legislation explicitly ensures that the state’s pursuit of a high-volume, large-diameter, pipeline from the North Slope to markets outside Alaska will not interfere with parallel efforts to build a smaller-volume (500 million cubic feet per day or less), small-diameter, in-state energy- oriented pipeline. Development of the two are separate, and AGIA ensures that neither will be negatively impacted by the other; thus, a bullet line was not evaluated for inclusion in these Findings. 5. LNG and an Overland Pipeline An overland pipeline to Alberta does not preclude an LNG project. TC Alaska has stated a willingness to offer gas treatment and pipeline transportation : An overland _ pipeline project may facilitate the project, if a shipper requests such services. An overland pipeline | development of an LNG Y services to Delta Junction or Valdez in support of an LNG Line project = within Alaska. and a pipeline delivering gas to an LNG facility are not mutually exclusive undertakings; there are economies of scale to be -— realized from a large-diameter overland pipeline that can make the economics of an LNG Y Line project more attractive. An overland pipeline project may facilitate the development of an LNG Y Line project within Alaska. (See Chapter Four) 27 MAY 2008 AGIA Maximizing Benefits for Alaskans Written Findings and Determination D. Maximizing Benefits for Alaskans The first goal for the state is getting a natural gas pipeline. The next goal is getting a pipeline that protects Alaska’s interests. Taken together, the state’s application requirements under AS 43.90.130, project development inducements under AS 43.90.110, .250-.260, 300-.330, and the project net present value and likelihood of success evaluation criteria under AS 43.90.170 effectively address protecting Alaskans’ interests by encouraging a pipeline project that maximizes the following benefits: e Getting a natural gas pipeline, quickly. e Jobs and long-term careers for Alaskans. e Affordable energy for Alaskans. e Sufficiently maximizes revenue to the state and its citizens from development of its natural gas resources. A pipeline that maximizes benefits to the state and Alaskans will: e Be predictably expandable. Predictable capacity expansions are key to encouraging new exploration and development of Alaska’s gas resources, which in turn will lead to new long-term jobs and careers for Alaskans, and opportunities for economic in-state use of North Slope gas. e Offer effective open access and reasonable transportation rates to all Alaska gas producers in order to encourage continued exploration and development of Alaska’s gas reserves and the generation of new long-term jobs and careers for Alaskans, and opportunities for economic in-state use of North Slope gas. e Make commitments, to the maximum extent permitted by law, to provide job opportunities for Alaskans, so that the benefits of pipeline construction and operation and new jobs in exploration and development stay in Alaska rather than being shipped Outside. ¢ Commit to provide in-state natural gas delivery points and distance-sensitive transportation rates to help meet Alaskans’ energy needs. ¢ Commit to take the necessary steps to develop a pipeline, including seeking the required approvals to construct the pipeline, so that the jobs and in-state energy benefits of the 27 MAY 2008 1-9 AGIA Maximizing Benefits for Alaskans Written Findings and Determination right pipeline can be realized sooner, and so that the state can begin to receive revenue from the commercialization of its natural gas resources. The commissioners, in their evaluation of the pipeline projects, have considered factors that assist in understanding whether and how each project will meet the needs of Alaskans and the state. These factors are explained below and examined in Chapters Three, Four, and Five. 1. Getting a Natural Gas Pipeline, Quickly With more than 85% of the state’s unrestricted revenue funded by oil production, continued oil production declines over the next decade may result in budget shortfalls that will have to be made up by (a) cutbacks in state services; (b) raising taxes or instituting new taxes; (c) use of Permanent Fund earnings or principle; or (d) a combination of the three. Given the robust economics of an Alaska gas pipeline project, the time to commercialize Alaska’s natural gas resources is now. An initial step to getting a pipeline project going is determining whether the project is economically viable and can obtain sufficient customer commitments and the necessary debt and equity financing for construction. Other early steps to be taken include an assessment of the technical viability of the project and consideration of the legal, regulatory, or other impediments to pipeline project development. Among other things, firm transportation commitments by producers or gas purchasers to ship gas on a pipeline are the basis for the financing of a pipeline project. Construction financing will also depend on the ability of a project proponent to finance the equity portion of the project. Factor: The Project’s Economic Viability from the Producers’ Perspective, and the Producers’ Likelihood to Make Firm Transportation Commitments to the Pipeline Firm transportation commitments are an important basis for financing pipeline construction and a significant factor in determining a project's economic viability. For a pipeline from the North Slope, the three Major North Slope Producers will be the likely initial gas shippers as they hold the majority of gas reserves on the North Slope. To evaluate if the Producers are likely to make firm commitments to a pipeline, several questions must be answered, including: e Does the pipeline project offer a significant enough return to the producers to encourage them to commit to ship gas on a pipeline? Answering this question requires an analysis of the likely cash flow and NPV that a project will generate for the Major North Slope Producers. There are a number of factors that can impact the return to the Producers, 27 MAY 2008 1-10 AGIA Maximizing Benefits for Alaskans Written Findings and Determination including the transportation rates offered by the pipeline. Chapter Three provides the result of this NPV calculation for the TC Alaska proposed project; Chapter Four provides the result for the LNG project options. e Does the pipeline allow the Producers to ship gas to their preferred markets? An overland project generally calls for construction of a pipeline from Alaska’s North Slope to the Alberta Hub; from Alberta, a project could use existing pipelines that transport gas to the Lower 48, or build a new one to markets farther south, such as Chicago. An LNG project would construct a pipeline from the North Slope to a processing and shipping facility, most likely in Valdez. From there, the product would be shipped via marine transport to Asian or West Coast markets. Chapter Three addresses the Alberta and North American markets, while Chapter Four addresses the markets in Asia. e Are the Producers reasonably insulated from pipeline construction cost overruns, which would increase the tariff they pay for shipping gas on the line? Firm transportation commitments will be more attractive to producers if a project proponent offers risk sharing tariff terms that can reasonably insulate shippers from some of the impacts of pipeline construction cost overruns, and if the project proponent has a track record of controlling cost overruns. Chapter Three discusses these factors. e Are there risks to the Producers if they decide not to make firm transportation commitments to an otherwise economic project? Among other things, these risks could include violations of oil and gas lease terms, or anti-trust and regulatory challenges. In addition, pressure from shareholders, Congress and the public to market the gas resource, particularly as oil and natural gas prices climb, may influence the Producers’ decision whether to commit gas for shipping on a pipeline. These issues are addressed in Chapter Three. Factor: The Technical Viability of the Project Evaluating the technical viability of a project is an important step in the consideration of a pipeline project. Technical viability rests on, among other things, sound development, engineering/design, and construction plans and sufficient natural gas reserves to justify pipeline construction. The technical evaluations of the projects and options are evaluated in Chapters Three, Four and Five. 27 MAY 2008 1-11 AGIA Maximizing Benefits for Alaskans Written Findings and Determination Factor: Holding a Binding Open Season An important benchmark on the path to getting a pipeline A binding open season is when gas shippers can commit to pay season. A binding open season is when gas shippers can | for space on the pipeline (that is, make firm transportation commitments). These firm built is preparing for and holding an initial binding open commit to pay for space on the pipeline (that is, make firm transportation commitments). These firm commitments commitments are used by the pipeline developer as the basis for obtaining credit support to obtaining credit support to fund construction activities. fund the pipeline project. are used by the pipeline developer as the basis for These issues are discussed in Chapters Three and Five. Factor: Applying for Regulatory Permits and Certifications Another important benchmark to keep the project moving forward is the application for necessary federal, state, local, and (if applicable) provincial or federal Canadian permits and certifications. Obtaining these permits and certificates is necessary for the construction and operation of the proposed project. These topics are covered in Chapters Three through Five. Factor: The Financial Strength of the Project Proponent The project proponents will be required to obtain financing for the project. This includes raising equity and securing debt. Financing issues are analyzed in Chapters Three through Five. Factor: Legal and Regulatory Challenges and Other Hurdles Legal and regulatory considerations will be faced by any project proponent. The complexity of these challenges depends on the type of pipeline and the pipeline route. An overland pipeline will face state and federal permitting hurdles in Alaska, as well as regulatory and First Nation hurdles in Canada. An LNG project will face similar state and federal permitting challenges and will encounter additional regulatory hurdles in the form of an export license should a project target Asian markets, and Jones Act limitations should a project target markets in the continental United States or Hawaii. These topics are discussed in Chapters Three through Five. 2. Jobs and Long-term Careers for Alaskans Alaska’s economic history has, to date, been one of boom and bust. Economic spikes centered around the fur trade, gold rushes, and then oil development have shaped the politics, society, 27 MAY 2008 1-12 AGIA Maximizing Benefits for Alaskans Written Findings and Determination and economy of Alaska. A natural gas pipeline construction project will represent the largest boom to Alaska’s economy since construction of the Trans-Alaska Pipeline System (TAPS) in the 1970s. Pipeline construction will generate thousands of jobs for a limited period of time. By working to ensure that an effective open access pipeline is built from the North Slope to market, the AGIA process will: create a more competitive gas basin on the North Slope, which will more quickly lead to the creation of the long-term, high-wage jobs that are important to the state’s economy; will sufficiently maximize revenues that when spent will generate additional long-term jobs in other sectors of the Alaska economy; and will ensure that local workers and businesses benefit from the construction and operation of a new natural gas pipeline. Factor: Create a More Competitive Gas Basin A competitive gas basin will create an environment where all explorers and developers, from the individual wildcatter A competitive 925 basin on, the North Slope will more quickly to the major international corporation, will be encouraged lead to the creation of the long- to explore and invest in the development of the state's | term, high-wage jobs that are important to the _ state's natural gas resources. A competitive basin also will more economy. quickly create the long-term jobs and careers that Alaskans want. A pipeline that can be expanded to ship new natural gas as it is found and developed, and that offers reasonable transportation rates for all shippers so that the economics of transporting newly-found gas to market are attractive, will create this more competitive natural gas basin. Factor: Maximize Revenue to the State and Create Long-term Jobs Throughout the Economy An open, competitive natural gas basin will generate significant new revenue streams for the state that can lead to the creation of further long-term employment opportunities. The expenditure of state tax revenues and royalty revenue earned from the production of the state’s natural gas resources will generate additional, non-natural gas related long-term jobs in the state. Direct, indirect, and induced jobs will be generated as state revenue from gas sales and gas production is spent to fund government services and capital projects around the state. 27 MAY 2008 1-13 AGIA Maximizing Benefits for Alaskans Written Findings and Determination Further, by obtaining sufficient revenues from oil and gas development, the state can shield other sectors from a tax burden to further foster economic expansion. The revenue that the state will receive from natural gas production will be directly influenced by the wellhead price (or net back price) of natural gas and the volume of natural gas produced. The higher the net back price, the higher the state’s income, which in turn equates to greater numbers of long-term direct, indirect, and induced jobs created throughout the Alaska economy. These revenues will also bolster Alaska’s Permanent Fund, which creates employment throughout the economy as a result of The revenue that the state will receive from natural gas production will be directly influenced by the wellhead price (or net back price) of natural gas and the volume of natural gas produced. paying dividends to Alaskans. Factor: Maximizing the Employment Opportunities for Alaskans A commitment by a pipeline proponent to establish an Alaska headquarters, hire Alaskans, and utilize Alaska businesses to the maximum extent permitted by law, will ensure that Alaskans have the opportunity to obtain local pipeline development and construction jobs. In addition, training Alaskans for pipeline-related jobs should begin as early as possible so that Alaskans have the job skills that will be required during construction.* 3. Affordable Energy for Alaskans Ever-rising fuel prices are increasing hardships for Alaska communities and families, and there is no single solution to ease this energy crunch. However, in-state supply of North Slope natural gas could help reduce energy costs in some regions of the state and allow for the development of value-added petrochemical industries within Alaska. Natural gas is currently used in only limited locations within the state. The majority of current non-oil field consumption of natural gas occurs in Southcentral Alaska, where natural gas from the Cook Inlet Basin is used for heat and cooking, to generate electricity, and in industrial facilities. Very little To meet the energy needs of Alaskans, a pipeline project must be designed to include in-state delivery points and to offer economic distance- sensitive tariffs for delivery of gas within Alaska. ° The State of Alaska has already begun efforts to prepare an Alaska workforce for pipeline jobs. The Department of Labor and Workforce Development's AGIA Strategic — Training Plan is available — at http://www. labor.state.ak.us/AGIA_teams/docs-combined/agiaweb.pdf 27 MAY 2008 1-14 AGIA Maximizing Benefits for Alaskans Written Findings and Determination natural gas is used elsewhere in Alaska due to a lack of transportation infrastructure and a lack of local supply. A National Energy Technology Laboratory report released in 2006 indicates that natural gas demand from both residential and business consumers will be strong after North Slope gas becomes available (NETL 2006). In rural areas, the high cost of energy hampers economic development. While the low population density of rural Alaska and the long distances between populated areas make construction of an in-state natural gas distribution system economically infeasible, there are technologically feasible means of supplying rural Alaska with natural gas or gas products. One such concept is the stripping of propane from North Slope natural gas, containerizing it, and then trucking or barging it to communities located off the pipeline route. A natural gas pipeline from the North Slope will be designed to primarily export natural gas from Alaska. Consequently, in order to implement one of the fundamental tenets of AGIA (providing North Slope gas directly to Alaskans), a pipeline project must be designed to include in-state delivery points and to offer economic distance-sensitive tariffs for delivery of gas within Alaska. Factor: In-state Delivery Points In-state delivery points are akin to freeway off-ramps—they are a collection of valves and piping that allow natural gas to be removed from one pipeline and transferred into another pipeline for transport and delivery. An ideal natural gas pipeline project would provide delivery points in locations that can best serve the energy needs of Alaskans, including rural Alaska. AGIA requires this. Factor: Economic In-state, Distance-sensitive Tariffs Providing in-state delivery points and sufficient quantities of natural gas to meet in-state needs are but two | Alaskans would pay a distance- sensitive tariff, meaning natural gas shipped within Alaska will be components of meeting the in-state energy needs of Alaskans. The other factor to consider is whether a | cheaper than natural gas shipped project will transport natural gas to those delivery points | *° the Lower 48. at a transportation rate that is reasonable and affordable. Establishing an in-state, distance-sensitive tariff is one means that a pipeline operator may employ to ensure that natural gas is available to Alaskans at affordable and reasonable rates. A 27 MAY 2008 1-15 AGIA Maximizing Benefits for Alaskans Written Findings and Determination distance-sensitive tariff is a transportation rate under which local consumers (Alaskans) would pay only for the cost of shipping natural gas from the North Slope to the in-state delivery point. If a distance-sensitive tariff was not used, local consumers could pay the same amount for shipping as consumers at the end of the pipeline in Alberta. AGIA requires distance-sensitive tariffs. Factor: Expansion Provisions Expansion of the pipeline provides additional opportunities for in-state consumers to access affordable North Slope gas. Because effective open access and low tariff provisions promote gas exploration and development, Alaskans will benefit from an environment in which companies compete to meet Alaskans’ energy needs. 4. Sufficiently Maximizing Revenues to the State and Its Citizens Alaska owns its oil and gas natural resources. Through leases, the state gives companies the tight to produce, and profit from, the state’s oil and gas. As an owner, the state is entitled to a percentage of the oil and gas produced on the leases—its “royalty” share. As a sovereign, the state also taxes the profit on production. Maximizing these revenues over the long term will ensure that future generations of Alaskans benefit from the state’s finite natural gas resources. The proposed project's net present value of the anticipated cash flow to the state is a factor in determining whether a natural gas pipeline project maximizes revenues to the state. Under AGIA, the net present value evaluation considers: e How quickly the applicant proposes to begin construction of the proposed project and how quickly the project will commence commercial operations. e The net back value of the gas and estimated transportation costs (tariffs) and treatment costs. e The applicant's ability to prevent or reduce project cost overruns that would increase the tariff. e The initial design capacity of the project and the extent to which it can accommodate low-cost expansion. e The amount of the reimbursement by the state that the applicant has proposed. 27 MAY 2008 1-16 AGIA Maximizing Benefits for Alaskans Written Findings and Determination e Other factors found by the commissioners to be relevant to the evaluation of the net present value of the anticipated cash flow to the state (AS 43.90.170(b)). While the state does not control how much revenue it will receive from commercialization of its natural gas resources, it can influence when and how natural gas is produced by ensuring a pipeline is open and expandable, and can influence cost factors such as tariffs. Factor: Minimizing Tariffs Pipeline tariffs are the amount that a pipeline owner charges A high tariff will lower the state’s royalty and tax shippers to transport gas through a pipeline. Tariffs are deducted from the market price of natural gas before the state’s | revenue. royalty amount and production tax is calculated. Thus, a high tariff will serve to lower the state’s royalty and tax revenue. Transportation rates can be reduced through specific measures including using a higher debt/equity ratio for ratemaking purposes, preventing and managing cost overruns, and utilizing specific tariff types to minimize the charges to shippers. | tariffs = ¢ net back value = ¢ state revenues Factor: Decreasing the Equity in the Debt/Equity Ratio A capital structure with a higher debt/equity ratio can drastically reduce pipeline tariffs because the lesser the amount of equity in the capital structure, the lower will be the pipeline’s transportation rate. This is because equity is a much more expensive means of financing a pipeline than debt. The Federal Energy Regulatory Commission (FERC) allows a return on equity for a new pipeline of approximately 13% to 14%, whereas debt can be financed at current rates of interest at approximately 7% to 8%. Consequently, the higher the amount of debt financing, the lower the tariff. Low tariffs lead to higher net back values for natural gas at the wellhead—the higher the net back, the greater the value of the state’s royalty natural gas. 1 debt/equity ratio = | tariff = t net back value = f state revenues 27 MAY 2008 1-17 AGIA Maximizing Benefits for Alaskans Written Findings and Determination Factor: Minimizing Cost Overruns © Preventing and managing project cost overruns will maximize the value of a pipeline project to Alaskans. Cost overruns raise the capital cost of the project, which in turn raise the tariff, and lower the net back value of the natural gas shipped through the pipeline system. | cost overruns = | tariff = t net back value = + state revenues 27 MAY 2008 @ 1-18 AGIA Summary Written Findings and Determination E. Summary Alaskans have high and reasonable expectations from a natural gas pipeline. They want long- term jobs and careers; they want access to economic natural gas from the North Slope to alleviate high energy prices; they want to see the state maximize the revenue from the production of its natural gas resources; they want to avoid giving unnecessary concessions to get a pipeline built or to get producers to commit to ship the state’s natural gas; and they want to avoid the delays and false starts that have plagued natural gas pipeline projects for more than 30 years. These expectations guided the commissioners’ evaluation; the factors described above in Sections D.1 through D.4 are among those that the commissioners used to develop their Findings and Determination. 27 MAY 2008 1-19 AGIA References Written Findings and Determination F. References Alaska Department of Revenue. 2006. Interim Findings and Determination Related to the Stranded Gas Development Act for a Contract between the State of Alaska and BP Alaska (Exploration), Inc., ConocoPhillips Alaska, Inc. and ExxonMobil Alaska Production, Inc. Contract Version dated May 24, 2006 with Proposed Amendments. November 16, 2006. [Web Page] Located at: http://www.revenue.state.ak.us/gasline/IFIF%201 1-16-06. pdf The Constitution of the State of Alaska. 1959. [Web Page] Located at: http://Itgov.state.ak.us/constitution.php Federal Energy Regulatory Commission (FERC). 2001. Alaska Natural Gas Transportation Act: Staff Report of the Federal Energy Regulatory Commission. January 18, 2001. [Web Page] Located at: http:/Avww.ferc.gov/legal/maj-ord-reg/land-docs/angta.pdf. Accessed March 2008. National Energy Technology Laboratory (NETL). 2006. Alaska Natural Gas Needs and Market Assessment. June 2006. National Energy Technology Laboratory (NETL). 2007. Alaska North Slope Oil and Gas: A Promising Future or an Area in Decline? DOE/NETL-2007/1280. August 2007. [Web Page] Located at: http:/Awww.netl.doe.gov/technologies/oil- gas/publications/EPreports/ANSFullReportFinalAugust2007.pdf. United States Geological Survey (USGS). 2005. Economics of Undiscovered Oil and Gas in the Central North Slope, Alaska. U.S. Geological Survey Open-File Report 2005-1276. 27 MAY 2008 1-20 A. Natural Gas Primer 1. 2. 3. 4. B. 1. 2. 3. 4. 5. Cc. Analysis Team D. References Pipeline Primer Chapter Two — Technical Background Table of Contents Natural Gas Markets LNG Basics History of LNG Asian Gas Quality Demands Natural Gas Pipeline Project Development Project Analysis Pipeline Regulation The Alaska Natural Gas Pipeline Act and Impacts on the Regulation of an Alaska Natural Gas Pipeline Alaska’s Natural Gas Resources .... @ Figures Figure 2-1: Pipeline Flow Figure 2-2: | Natural Gas Production Figure 2-3: Potential LNG Trading Routes from Alaska.... Tables Table 2-1: AQ 2-11 27 May 2008 AGIA Natural Gas Primer Written Findings and Determination A. Natural Gas Primer Natural gas is a general term applied to a mixture of combustible hydrocarbon gases that are produced from both natural gas wells and from oil wells. When natural gas flows out of a reservoir, it may contain a combination of methane, butane, propane, ethane, carbon dioxide (CO,), hydrogen sulfide (H2S), water vapor (H2O), and other compounds. Natural gas that contains significant portions of heavier hydrocarbons like butane, propane, and ethane is referred to as “wet gas;” natural gas that is mostly methane is called “dry gas.” Much of the natural gas in the Prudhoe Bay reservoir is wet gas, but there are significant accumulations of dry gas on the North Slope as well. To prepare natural gas for delivery to market in a high pressure pipeline, natural gas must often be processed or treated. In this process, such as would occur in a gas treatment plant (GTP), water is removed from the natural gas stream to prevent pipeline corrosion, and the non- commercial gases, carbon dioxide, and hydrogen sulfide are removed and sometimes reinjected back into the geologic formation to maintain reservoir pressures. The ethane, propane and butanes in wet gas are known as natural gas liquids (NGLs). These may be removed from the gas stream in a process sometimes known as “stripping” or “extraction” at a Processing or Straddle Plant. Natural gas liquids may be used as a feedstock for petrochemical manufacture, and can also be liquefied and used by consumers. One of the liquefied components—propane—is used in many rural villages for heating. After removing NGLs, the remaining natural gas will now be “dry gas,” containing mostly methane. This is the natural gas that is piped into homes and businesses. Figures 2-1 and 2-2 are schematics of the components and processes found in a generic natural gas production system. 1. Natural Gas Markets In North America, a common pricing point for natural gas prices is the Henry Hub near Erath, Louisiana. This is also the physical location employed by the New York Mercantile Exchange or NYMEX for | The Alaska Gasline Inducement Act (AGIA) established an open and competitive process for in physical delivery rather than simply clearing on the | developing a _ natural gas settling futures contracts when those transactions result pipeline on terms that maximize benefits for the people of natural gas is in Alberta at the AECO Hub. Most of the Alaska. exchange. In Canada, a common pricing point for demand for natural gas in the North American (United 27 May 2008 24 AGIA Natural Gas Primer Written Findings and Determination States and Canada) market is met by domestic production. More than 80% of the natural gas @ imported by the United States has come from Canada (EIA 2008a). Longstanding treaties between the United States and Canada prohibit discriminatory treatment and allow for a transparent trade of gas between the two countries." Figure 2-1: Pipeline Flow *Sales Quality Gas = Wet Gas (methane, butane, propane, ethane, pentanes) @ Figure 2-2: Natural Gas Production aiid Butane Water Vapor Propane AA Methane Hydrogen Sulfide Emane /- { Carbon Dioxide Iso-butane Helium Natural Gasoline Ne =) Ni ee Natural gas Impurities in the Wet gas is ee fon dry natural flows to the => raw natural gas E> transported to ES ocr gas wellhead on are removed; some straddle plant via ies the surface are injected back high-pressure ee into the formation pipeline a ' United States Secretary of State and the Government of Canada. 1977. Agreement on Principles Applicable to a Northern Natural Gas Pipeline (with annexes). @ 27 May 2008 2-2 AGIA Natural Gas Primer Written Findings and Determination 2. LNG Basics In areas of the world that must import their energy and that cannot be reached by an overland pipeline from oil and gas producing areas, marine transportation supplies their energy. Natural gas moved in this way is shipped via tankers as Liquefied Natural Gas (LNG). For LNG to be transported economically in tankers, compressed gas from the pipeline system must be purified and super-cooled until it condenses into a liquid at roughly -260°F. This energy-intensive process, called liquefaction, takes place in processing equipment called "trains." A LNG train is a complete processing unit that turns natural gas into a liquid. The “train” consists of a collection of sub-units and equipment that cleans, compresses and cools natural gas into a liquid. A LNG plant consists of one or more “trains” plus support facilities such as utilities, storage tanks and jetties. LNG tankers keep the gas in this super-cooled state during transport using built-in refrigeration systems. When the ships arrive at the receiving terminal, a “re- gasification” facility must be available to heat the LNG back to natural gas so that it can be transported via pipeline. LNG plants are large, complex processing facilities. Because of the demands that constructing such a facility in Alaska would put on the global construction infrastructure, it would be installed in sections, with each section beginning to produce LNG for export after it is installed and commissioned for service. Thus, LNG production would ‘ramp up’ to its full capacity over a period of time depending on the configuration of the facility and the number of “trains.” 3. History of LNG The first regular LNG bulk trade started in 1964 between Algeria and the United Kingdom, and the first Pacific trade was started in 1969 between Kenai and Tokyo (Tussing 2005). The LNG trade has grown considerably over recent decades due in large part to demand in Asian energy markets. Because countries like Japan, Taiwan and South Korea produce very little domestic gas, they are heavily dependent on steady supplies of foreign gas imports. These countries are thus often more concerned about security of supply than price. In Asia, prices have traditionally been set using formulas that link the price paid for natural gas to the price paid for crude oil. These price formulas are set at the time of the initial long-term sale in response to market conditions at the time, and are reviewed periodically. As a result, there is no single market price for LNG in Asia. When the market moves quickly from surplus to shortage, as it has done in recent years, large price differentials between different contracts occur (Appendix |, Section 4.5). 27 May 2008 2-3 AGIA Natural Gas Primer Written Findings and Determination 4. Asian Gas Quality Demands The specifications for LNG sold to Asian markets differ from LNG sold to the USA and Europe, primarily because of the Asian market need for richer (higher Btu) gas. The reason for this stems from differences in design between gas-distribution systems. Gas burners—particularly those in home appliances—can only handle a limited range of gas quality safely. Gas burners in one region will be designed for different types of gas than gas burners in another region, depending on the predominant gas type in that region. Asian markets were developed around the use of relatively wet (energy-rich) LNG and cannot easily use the drier gas sold to U.S. and European markets (Appendix |, Section 4.4). Therefore, LNG from Alaska being sold to the Asian market would need to meet their higher gas quality (higher Btu) requirements. Figure 2-3: Potential LNG Trading Routes from Alaska 27 May 2008 2-4 AGIA Pipeline Primer Written Findings and Determination B. Pipeline Primer 1. Natural Gas Pipeline Project Development Any supply-driven gas pipeline project begins with the natural gas resource - how much natural gas is available, where do the producers want to market the natural gas, and what is the best way to get the gas to market? Any supply-driven project—be it an overland pipeline or an LNG project—will progress through similar groundwork and permitting activities, including: ¢ Starting preliminary work with regulatory bodies. « Communicating with potential customers to assess interest. e Determining project destination and scope. ¢ Conducting preliminary design, engineering and field work. e Designing commercial terms and tariff structure(s) in preparation for a binding “open season.” Early pipeline development efforts focus on generating a detailed and comprehensive plan for the project in preparation for holding an open season. An open season is an event during which a pipeline project sponsor offers terms to potential shippers who seek to reserve capacity in a pipeline. Shippers can include gas producers, utilities, and end users. In North American markets, open seasons help determine the need for new pipeline capacity. Open seasons can be either binding or non-binding. Non-binding open seasons are held early in a project's development to gauge potential interest. In contrast, in a binding open season, bids are contractually binding once they are accepted by the project sponsor. A binding bid will generally specify a date by which the parties must enter into a “precedent agreement” and, ultimately, a contract reserving capacity on the pipeline. These contracts are called “Firm Transportation Commitments,” “FTs” or “Ship or Pay Contracts.” The precedent agreement contains the terms and provisions describing the price of the capacity, volume of capacity reserved, and length of the contract. A “successful” open season is one in which enough potential shippers commit to enter into firm transportation contracts to enable the project to obtain financing. By contrast, an “unsuccessful” 27 May 2008 2-5 AGIA Pipeline Primer Written Findings and Determination open season is one in which the sponsors fail to obtain sufficient commitments for capacity for the project to move forward to detailed design, engineering, and construction. An unsuccessful open season does not necessarily equate to a failed project. Rather it demonstrates the market is unable or unwilling at that time to accept the proposed terms. In this case, negotiations will likely continue in the future to seek a common, mutually beneficial agreement. There are no restrictions on the number of open seasons that can be conducted for any particular project. In the Lower 48, it is not uncommon for sponsors proposing new pipeline capacity to hold two or more open seasons before the proposed project's design and shipping terms are fully coordinated with the interests of potential shippers. LNG projects and overland pipeline projects are developed and financed differently. Because the largest markets for LNG cannot meet their natural gas demands with domestic supplies, LNG buyers are often very concerned about the volume and security of supply. Virtually all LNG projects are vertically integrated and contain structured, long-term commercial commitments between the producers (sellers) and consumers (buyers) of LNG (see Appendix | for greater detail on the workings of the LNG market and the structure of LNG projects). In contrast, overland pipelines in North America are typically part of a network that can easily move gas from one market to another, allowing project stakeholders to take additional risks. Financing for overland pipeline projects generally depends on the credit-worthiness of the gas shippers or those making the firm transportation commitments, rather than a review of the complex financial and commercial relationships included in a LNG project. 2. Project Analysis The analysis of a proposed project leading up to and following an open season is varied and complex. The pipeline project sponsor must establish reasonable confidence in a project's technical, commercial, and financial viability to encourage gas shippers to make long-term binding shipping commitments. A technical viability analysis determines if the project can be permitted, engineered and constructed, and estimates the capital costs and schedule for completion. The commercial evaluation determines if there is a downstream market into which gas can be sold, and the economics of transporting and selling gas to the market over the life of the pipeline and its contracts. The financial review evaluates the economics of the project to determine if the project proponent has sufficient financial resources and bonding capacity to finance the project. 27 May 2008 2-6 AGIA Pipeline Primer Written Findings and Determination Because each type of analysis depends on information from the others, they must be advanced in parallel. The technical development of a pipeline project includes conducting the necessary engineering and environmental studies, obtaining all regulatory permits, and estimating the costs and schedule. There are a multitude of components involved in the evaluation, such as pipe size, pipe specification, compressor stations, availability and price of steel, and labor costs. Each of these factors affect cost estimates for the project, which in turn impact the project’s various commercial components. Thorough commercial analysis is complex in that it attempts to quantify a project’s total value after considering any potential risk factors. Two common methods of quantifying a project's value are the calculation of Net Present Value (NPV) and Internal Rate of Return (IRR). Net Present Value is an economic calculation used to appraise and compare the financial value of long-term projects. An NPV calculation figures the present value of an investment that may generate returns for many years. It measures the profits (or losses) that a project will produce over time in today’s money. Because NPV is expressed in the common term of today’s money, it can be used to compare the relative benefits of several competing projects. IRR is a capital budgeting metric used by firms to decide whether they should make a given investment. IRR is an indicator of the efficiency of an investment; it is a calculation of the earnings or “cash flow yield” a firm could expect to realize on an investment. 3. Pipeline Regulation Gas pipelines are regulated by different agencies depending on where they begin and end. Transportation of gas within the State of Alaska (intrastate) is regulated by the Regulatory Commission of Alaska, while transport between states (interstate) is regulated by the Federal Energy Regulatory Commission (FERC). The FERC’s counterpart in Canada is the National Energy Board (FERC 2001). Under both Regulatory Commission of Alaska and FERC jurisdiction, any gas pipeline project sponsor must first obtain a Certificate of Public Convenience and Necessity (CPCN). A CPCN is the primary certification issued by the regulatory agency which verifies that the project sponsor is able to construct and operate a gas pipeline, and that the project is in the best interest of the public. 27 May 2008 AGIA Pipeline Primer Written Findings and Determination In filing for a CPCN, the pipeline project sponsor provides the required details of the proposed gas pipeline and sets forth its proposed rates and all of the other terms and conditions of service. The rate and terms of service materials are contained in a document known as the pipeline company’s “tariff.” (Frequently, though, the term “tariff” refers to the rates to be charged for particular services.) FERC review of the sponsor's application for a CPCN includes a review of the environmental aspects of the project. This is one of the most time consuming aspects of the regulatory process. To expedite the certification process, FERC has established a “pre-filing” process to allow the environmental work to start even before the certificate application is filed (FERC 2008). During the “pre-filing” process the FERC staff works with the project sponsor and interested parties to establish the scope of the necessary environmental review and may select an independent contractor to perform the environmental review. FERC also reviews the design of the project, the route, the proposed rates and any other aspects that interested parties identify in their filings with the agency. In a project that involves a new pipeline such as an Alaska natural gas pipeline project, the FERC will review and set the initial tariff for the project during the CPCN proceeding. Under the Natural Gas Act and FERC regulations, rates have to be “just and reasonable.” This generally means that the rates are based on the actual or projected costs of the project and earn a reasonable return on the company’s investment. Rates set in this manner are referred to as “recourse rates” and any shipper (or potential shipper) has the right to obtain capacity and service on the pipeline at those recourse rates if there is available capacity on the pipeline. Because pipelines receive a regulated rate of return, how much of the pipeline construction is financed with debt and how much with equity is significant to potential shippers. A rate of return between 11% and 14% plus an allowance for applicable income taxes is typically allowed on portions of the project that are equity-financed, while the borrowed interest rate (which is typically lower that the rate of return on equity) is allowed on portions of the project that are debt-financed. As a result, the ratio of debt to equity financing for a project has a large impact on the final tariff: more debt lowers the tariff, while more equity raises it. FERC rules also allow for “negotiated rates.” Negotiated rates on new pipeline projects are often lower than the recourse rates for several reasons. First, the recourse rates that are set in the CPCN are based on initial projected costs, not actual costs, so the sponsor will typically 27 May 2008 2-8 AGIA Pipeline Primer Written Findings and Determination estimate costs on the high rather than the low side. Second, negotiated rates frequently involve innovative concepts such as “levelized” rates or “term-differentiated” rates. Levelized rates are established for long periods of time and are lower in the early years and higher in the later years than would be achieved through conventional rate making. Levelization is accomplished by deferring recovery of depreciation expenses by the pipeline company from the early years to the later years. Term-differentiated rates fluctuate according to the duration of the transportation contract: rates are generally higher for shorter term contracts and lower for longer term contracts. This reflects the fact that the sponsor has more time to recover its initial investment (and associated returns) and has less risk of not being able to sell capacity when it has long term contracts than when it is under short term contracts. This translates into a somewhat lower rate for longer term contracts. Most recent pipeline projects in the Lower 48 are fully or mostly subscribed under negotiated rather than recourse rates. (For more information on rates, see Appendix G1, Section 3.7.) 4. The Alaska Natural Gas Pipeline Act and Impacts on the Regulation of an Alaska Natural Gas Pipeline Failed construction efforts over the past decades have inspired a number of laws and regulations which will apply to an Alaska natural gas pipeline project. Congress enacted the Alaska Natural Gas Pipeline Act (ANGPA) in 2004. ANGPA created a clear and expedited process for acting upon a pipeline certificate application, provided FERC with limited authority to require expansions, created a central coordinator for the issuance by other federal agencies of permits necessary for a pipeline, prohibited an “Over-the-Top” route from Prudhoe Bay through the Beaufort Sea to Canada’s Mackenzie River delta, confirmed the jurisdiction of the Regulatory Commission of Alaska over an in-state lateral pipeline, gave the state specific rights with respect to the shipment of royalty gas for in-state needs, and authorized a Federal Loan Guarantee of up to $18 billion (escalating with inflation) for an Alaska gas pipeline project that serves the North American market. To help expedite the review process, ANGPA included a provision requiring the FERC to presume a need for the project and to presume that there will be adequate downstream capacity to move Alaskan gas to markets (ANGPA 2004). Inclusion of the Federal Loan Guarantee stemmed from widespread concerns over the estimated project cost and difficulties that previous project sponsors had encountered with 27 May 2008 AGIA Pipeline Primer Written Findings and Determination financing. The additional assurance that the loan guarantees provide to potential lenders should allow the project sponsor to borrow at a lower interest rate, thus improving the project's economics and lowering the transportation rate. Decisions from the FERC are always subject to review by the Federal courts. However, ANGPA also dictates that any appeal from FERC orders relating to the Alaskan project can only be appealed to the U.S. Court of Appeals for the District of Columbia Circuit and also mandates that the court must expedite its actions on appeals related to the Alaskan gas pipeline (ANGPA 2004). 5. Alaska’s Natural Gas Resources Alaskan natural gas is a largely untapped U.S. energy resource. Until recently, no exploration expressly targeting natural gas had taken place on the North Slope. Existing gas resources have been discovered as a byproduct of the search for oil. Natural gas produced with oil is used either as fuel in oil production facilities or is compressed and injected back into the reservoirs to enhance oil recovery. Recent studies estimate that there are 224 trillion cubic feet (Tcf) of undiscovered, technically recoverable resources throughout the Alaskan Arctic. These are natural gas resources that may be technically and physically recovered independent of price. Of this amount, 137 Tcf are categorized as undiscovered, “economically recoverable” resources (USGS 2005; NETL 2007). Economically recoverable resources are sensitive to both price and technology; an increase in price or an improvement in technology would be expected to increase these estimates. In addition to these resource estimates are roughly 24.5 Tcf of natural gas reserves known to exist within Prudhoe Bay, plus 9 Tcf of natural gas reserves discovered in other existing fields on the North Slope, including Point Thomson.” ? To understand the magnitude of these resources, the volumes can be compared to the annual total consumption by commercial and residential users in the United States of 23 Tcf. (EIA 2008b) 27 May 2008 2-10 AGIA Written Findings and Determination C. Analysis Team Analysis Team A 1,715 mile natural gas pipeline as proposed by TC Alaska from the North Slope to the border between the Canadian Provinces of British Columbia and Alberta, would be one of the largest and costliest projects ever constructed in the world. AGIA Statute AS 43.90.170 requires the commissioners to analyze technical, commercial, and financial and hydrocarbon reserves supporting or related to the Project. The commissioners assembled a team of experts to help analyze the NPV and likelihood of success (LOS) in support of the commissioners’ determination of whether the TC Alaska Application sufficiently maximizes benefits for the state and its people and is the right project for Alaska. Key contractors and their expertise are provided in Table 2-1 below; a list of all contractors and their respective resumes are provided in Appendix E. Table 2-1: Contractor Expertise FIRM EXPERTISE AMEC-Paragon, Inc. (AMEC) Leading provider of services and engineering solutions to the world’s infrastructure, manufacturing and process industries. AMEC assisted in cost estimating for the pipeline portions of the project in both Alaska and Canada, hydraulic flow modeling of the proposed facilities, and historical analysis of capital cost escalation for pipeline projects. Bennett Jones Internationally recognized Canadian law firm with long-standing practice in oil and gas industry, mergers and acquisitions, foreign exploration and international investment coupled with evolving regulatory legislation, stakeholder community, commercial matters, and strategic advice on export and commodity tax compliance matters. Bennett Jones has extensive experience negotiating joint ventures and resource development agreements for native reserve and treaty lands, counseling governments and proponents on engineering, procurement and construction contracts, and representing industry participants on surface rights acquisition matters for wells, facilities and pipelines. Bennett Jones provided legal expertise including Canadian regulatory, First Nations and environmental considerations for natural gas pipeline critical path analysis. Black & Veatch, Lukens Energy Group Enterprise Management Solutions With more than 80 years of experience in oil and gas engineering design and commercial analysis, Black and Veatch led the commercial analysis that included development of the NPV model and commercial analysis of the likelihood of success. 27 May 2008 2-11 AGIA Written Findings and Determination Analysis Team FIRM EXPERTISE Brown, Williams, Moorhead & Quinn, Inc. (BWMQ) Leading energy consulting firm that provides comprehensive energy related services to hundreds of clients, including natural gas and oil pipeline companies, local distribution companies, energy producers, shippers and federal and state agencies. BWMQ provided advice on how to properly interpret and account for FERC precedents and current policies in the natural gas pipeline industry. Energy Capital Advisors Has provided clients with a wide array of financial services throughout the international energy spectrum, with an emphasis on petroleum ventures. Energy Capital Advisors supplied commercial oversight and assisted in coordinating efforts between commercial and technical groups. Energy Project Consultants LLC More than 40 years of experience in pipeline design and construction. EPC directed the Technical Team and provided expertise in engineering, costs and scheduling of pipeline systems for the U.S. pipeline segment analysis. Gaffney, Cline and Associates International energy consulting firm that has been providing clients with value added, commercially viable results for over 40 years. Provided cost information for the Black and Veatch model of the GTP and other economic aspects of the proposed TC Alaska Project. Provided economic and fiscal system expertise for the analysis. Gas Strategies Experts that provide advice and data on strategic energy matters for commercial and governmental clients around the globe. These leaders in the industry analyzed the path of natural gas and LNG from supply source to market and specialize in: evaluation and feasibility, demand and pricing analysis, commercial due diligence, and market regulation, restructuring, liberalization and competition. Goldman Sachs Leading global investment management, banking and securities firm that provided the financial analysis of the TransCanada co- applicants, TransCanada Alaska Company, LLC and Foothills Pipe Lines Ltd., in terms of their financial capabilities to obtain financing for the Project as well as evaluating the firms’ likelihood of financial success. Greenberg Traurig One of the largest law firms in the U.S. that has expertise representing electric power generators, natural gas pipeline companies and other industry participants before the FERC, SEC and other federal agencies in a wide range of regulatory matters. Greenberg Traurig’s Energy and Natural Resources practice group provided advice on legal aspects of the proposed Project. 27 May 2008 2-12 AGIA Written Findings and Determination Analysis Team @ FIRM EXPERTISE Heenan Blaikie, LLC |__ Merlin Associates Internationally recognized Canadian law firm provides a full range of legal services to some of Canada’s largest oil and gas producers and emerging companies. Its regulatory lawyers have acted for both government and industry in numerous applications before the National Energy Board and provincial regulatory bodies and the courts. Heenan Blaikie has extensive experience in major inter-provincial and international pipeline and power line facilities, tolls and tariff applications, and representing power producers, marketers and consumer groups on jurisdictional, commercial, environmental and First Nations issues. Heenan Blaikie provided consultation on Canadian federal, provincial and First-Nation issues. Merlin Associates is a leading technical and engineering consulting organization offering specialized expertise in oil and gas production and development to energy companies worldwide. Merlin Associates’ publication “LNG: Cost and Competition” (co-authored with Poten and Partners, Inc.) is the standard reference used by many of the leading LNG project participants, consulting and engineering firms, and financial institutions of the world. Provided cost validation. Mustang Management, Ltd. @ (Mustang) Canadian company that specializes in pipeline construction and installation. Provided cost validation for costs related to pipeline construction in Canada. PetroTel PetroTel is a recognized worldwide industry leader in enhanced oil recovery, reservoir characterization and simulation, coalbed methane, production, and exploration technologies. PetroTel provided professional consulting and advisory services. Pingo International, Inc. More than 30 years of experience in pipeline design and construction. Pingo provided expertise in engineering, costs and scheduling of pipeline systems for the Canadian pipeline segment analysis. Westney Consulting Group Houston-based consulting group with 30 years experience in global gas projects including: pipelines, NGL, GTP, and LNG projects. Westney’s contribution included the use of a proprietary model to provide cost analysis and Monte Carlo simulations into the NPV evaluations, world-wide LNG expertise, and risk analysis systems. Wood Mackenzie Wood Mackenzie developed proprietary commodity pricing forecasts for the State of Alaska. This confidential and proprietary information was used to support evaluations of other potential oil and gas developments that could also potentially utilize capacity in the proposed Project. 27 May 2008 2-13 AGIA References Written Findings and Determination D. References Alaska Natural Gas Pipeline Act. 2004. Energy Information Administration (EIA). 2008a. U.S. Natural Gas Imports by Country. [Web Page] Located at: http://tonto.eia.doe.gov/dnav/ng/ng_move impc_s1_a.htm. Accessed May 2008. Energy Information Administration (EIA). 2008 b. Natural Gas Consumption by End User. [Web Page] Located at http://tonto.eia.doe.gov/dnav/ng/ng_cons_sum _dcu_nus_a.htm. Accessed May 2008. Federal Energy Regulatory Commission (FERC). 2001. Alaska Natural Gas Transportation Act: Staff Report of the Federal Energy Regulatory Commission. January 18, 2001 Federal Energy Regulatory Commission (FERC). 2008. Pre-Filing Review Process. [Web Page] Located at http:/Awww.ferc.gov/help/processes/flow/Ing-1-text.asp. Accessed May 2008. National Energy Technology Laboratory (NETL). 2007. Alaska North Slope Oil and Gas: A Promising Future or an Area in Decline? DOE/NETL-2007/1280. August 2007 Tussing, Arlon R. 2005. The Past and Future of LNG in Alaska. [Web Page] Located at: http://www.alaskaneconomy.uaa.alaska.edu/tussingfinallng.pdf. Accessed May 2008. U.S. Geological Society (USGS). 2005. Economic Analysis of Undiscovered Oil and Gas of the Central North Slope of Alaska. [Web Page] Located at: http://pubs.usgs.gov/fs/2005/3120/. Accessed May 2008. 27 May 2008 2-14 o> Cc. Summary of Proposed Project .. Chapter Three — Analysis of TC Alaska’s Application Table of Contents WPOGUCHON BAG SUMIBIY cca yeevcsrverenesevereercennrcnscnnennanne anihits DIAL INIA TSEENEtinannals Who is TC Alaska?................. 1. History and Company Description a. TransCanada in Alaska........ 1. Gas Treatment Plant (GTP) .. a. Potential Equity Partners... b. Management Challenges .................:::escseeeeeeeee C Regulatory Challenges sscisissiissssasisvcnscnnesaronseccvenann d. Transportation Challenges D. TC Alaska’s Project Would Produce a Significantly Positive Net Present Value for the State of Alaska Summary of Methodology and Results of NPV Analysis. 2. NPV Methodology = a. General Approach b. Natural Gas Prices... c. EIA Price Forecast.. _— G:; Wood Mackenzie! Price! Projection csscss.cc..sescssesussvssonssesssvonsnestsseresecescransersosevesseseevsses e. Projection Based on Forward-Looking North American Supply and Demand Model f. Estimated Volumes of Natural Gas Sold g. Estimated Pipeline and GTP Costs, Schedule, and Tariffs ............0....cccceeeeeeeeeee 3-44 h. Pipeline Cost and Schedule Analysis, Including Cost and Schedule Ranges.......... 3-46 Nominal Dollar Cost Ranges and Tariffs: Escalation Risk . Upstream Costs tess 3. Estimated NPV Produced by the Project—Results of the NPV Analysis .... a. Estimated NPV under the Proposal Base Case b. Estimated NPV Under the Conservative Base Case and Low Volume Sensliviy Case Remain Favor. sccicicisiscnvcnenncmnnasannnnamanmmmmnascavenaney 3-69 c. The Project Would Produce a Positive NPV Even If No Point Thomson or YTF Gas Is Ever Produced — 4. Impact of $500 Million Match 5. Availability of Low Cost Expansion E. Analysis of the Likelihood of Success of TC Alaska’s Project 1. Introduction and Summary 2. Methodology for Analyzing the Project's Likelihood of Success .... - 3. Analysis of Likelihood of Success Criteria Under AGIA Section 170 ..............:cceeeeee 3-85 sie 27 MAY 2008 Table of Contents (continued) Ee G. References Figures a. TC Alaska Has Submitted a Plan for its Project That is Technically Feasible, Reasonable, and Specific. ..............eecececesesceceeeseeeseeeseeeeeeees 3-85 b. TC Alaska Has Demonstrated the Technical and Financial Ability MOIGONSULICE tHe | PROVO CU reo ecccvcnnennxwvmcccoconcoscscoveseressansosoncss sronswdecasoes os secsessvsrsesccasectsuts 3-98 c. TC Alaska Has Submitted a Reasonable Commercial Plan Which, Coupled With Economic and Political Factors, Should Help To Encourage Firm’ Shipping! Commitments iresacesccsexeceececeosercusncees ncecensas swescsonswacarecessusessucnasersnses 3-106 d. TC Alaska’s Ability To Overcome Barriers To Obtaining Firm SHIPPING COM MMUMO MS Fs cersecscececscnevaccsacss sovnccvavscensneaqsaccsecasdeesurenssensivernees=e-e¥=0es 3-119 e. Other Factors Which Indicate TC Alaska’s Project Has A Reasonable Prospect of Securing Firm Shipping Commitments Summary.... Figure 3-1. | Map of TransCanada Pipeline Operations .................ccccseseseeseseseseseseseteneeeeeees Figure 3-2. | Present Value of $100 Cash Flow in Future Figure 3-3. | Present Value of $100 Cash Flow in Future Years .... Figure 3-4. Sensitivity of State NPV to Discount Rates Figure 3-5. NPV Modeling Figures SE. vara eri i UN ss sss stecmcnsncn nen satn sectomneennnennnenenocenesesmsencerwnscionne Figure 3-7. EIA-Based Henry Hub and AECO Price Forecasts to 2045 (Nominal dollars) Figure 3-8. | Wood Mackenzie-Based Henry Hub Forecast to 2045 (Nominal dollars) ........ 3-25 Figure 3-9. | Wood Mackenzie Basis Forecast Figure 3-10. Wood Mackenzie-Based Henry Hub and AECO Price Forecasts HORZO4 51 (INOMINGIICONANS) pececeretesscessesectereceseecnnceeeeseststense snes setrecucsceeestcerseccnttes 3-27 Figure 3-11. Black and Veatch Henry Hub and AECO Price Forecasts Figure 3-12. U.S. Gas-fired Power Generation Demand Distribution Range Figure 3-13. WCSB Finding and Development Cost Curve (Real 2008 $).. Figure 3-14. U.S. Lower 48 Industrial Demand Distribution Range....... to 2045 (Nominal dollars) Figure 3-15. Relative Impact of Price Drivers on AECO HUB Price Formation, Figure 3-16. Distribution Range of AECO Price Forecasts over Time (Nominal $) ... Figure 3-17. AECO Price Forecasts (Nominal $) Figure 3-18. Production Profile for Proposal Base Case Figure 3-19. Production Profile for Conservative Base Case 2022 (Nominal $) i scarsccocsssenesczcucessacscaravevensursesearecsssvns tevaccssatot st ossnsvsvtvestarsesrnvaves Figure 3-20. Subproject Component Cost Ranges—Derivation Process ................::::c00+ 27 MAY 2008 ii Figure 3-21. Figure 3-22. Figure 3-23. Figure 3-24. Figure 3-25. Figure 3-26. Figure 3-27. Figure 3-28. Figue 3-29. Figure 3-30. Figure 3-31. Figure 3-32. Figure 3-33. Figure 3-34. Figure 3-35. Figure 3-36. Figure 3-37. Figure 3-38. Figure 3-39. Figure 3-40. Figure 3-41. Figure 3-42. Figure 3-43. Figure 3-44. Figure 3-45. Figue 3-46. Figure 3-47. Figure 3-48 Figure 3-49. Figure 3-50. Figure 3-51. Table of Contents (continued) Proposal Base Case Cost Distribution—Alaska Pipeline ...............0..c eee 3-49 Proposal Base Case Cost Distribution—Yukon-BC Pipeline..................c cee 3-50 Proposal Base Case Cost Distribution - GTP............ccsssssesesseseseesessesesesseeeseees 3-51 Proposal Base Case Cost Distribution—Integrated Project ...............cceee 3-52 Project Cost Risk: Comparing Project Escalation with Project Scope Risks Showing Cost Uncertainty and Risk Increasing With (Escalation; Rates) ..1--..01-..0-.eccecssestsserzossescesrstonsnsoncesscccescceroscsetartesnenas 3-54 Tariff Distributions by Project Throughput:Smaller Projects Give FIO TiariffS oi. rere enecverree so screscessnsesecnnsenaresneescevesesasssteoesteosssepsnsseensesesses 3-57 State NPV5 Tornado Diagram: The Relative Importance of RTT FU, CI ate crit bees monger nha AN IRRETrnaeeremenrce wenn 3-64 SR PG Tr Ta NG cristina repens mrs 3-65 Comparing TC Alaska Pipeline Tariff (Nominal $) with Various AECO) Price) FOreCasts):..2..--t.cscscsccvsencescansecsstarencosseostuncscsurstosausesceeassshssersscaseed 3-66 Producer NPV1o Tornado Diagram: The Relative Importance of EET, FI FEIT anne creecnerermr eee seen cae eeh eT ERNEENEiniaaemes 3-68 Pipeline Tariffs Under Proposal, Conservative, and Low Volume Cases......... 3-70 State NPV5 Under Proposal, Conservative, and Low Volume Cases.............. 3-72 Aggregate Producer NPV Under Proposal, Conservative, and Low Volume CaSO oil) te cscecsaresestes-con-csecsoonsesosseesssesussres¥set bevennorscsacessvensessced 3-73 Impact of Contract and Depreciation Periods on AECO Tariff .................::000 3-74 Reserve Risk: Producer NPV Assuming No YTF Ga ...............:cc:ccseeseeeeeseeeees 3-76 Reserve Risk: Yearly Net Back Cash Flow State of Alaska NPV5 with and without $500m match AGIA Roll-in-Rate Provision Schedule Risk of Proposal Base Case... 1 Impact of Commercial Terms of Transportation Contracts to AECO Tariff ....3-109 Impact of Commercial Terms of Transportation Contracts to Producer NPVi9 and NPVi5 Tariff Consequences of Cost Overruns With and Without 100% SI FI an seerrenecne necesita =< rere ARENT RIT ane mannreeopnenniel 3-115 TransCanada NPV8.8 Sensitivity Consequences of Cost Overruns With and Without! 100% Debt Financing soon on.. ccsesscresessnssvavessecaseoesseoeseone TransCanada NPV8.8 For Different Project Configurations U.S. Government NPV; For Different Project Configurations. State NPVs For Different Project Configurations Percentage Price Drop Necessary to Generate NPV of Zero For Produners’ PrOved Framer ii cereresrennennssctiernnaneneeeereunenns 3-131 Aggregate Producers NPV; - 4.5 BCF/d Proposal Base Case With and Without Price Uncertainty Real AECO Price Forecasts vs. Tariff + Fuel.... Aggregate Producers NPV1o Uncertainty for the 3.5, 4.0, and AIG BOtld (Cases cicciits sesso csvesesescasessusssectviasustus catnesssecersseabecsevenpapet reese taarenoct sess 3-134 Impact of Different Periods of Fiscal Uncertainty for Producer NPVjpo...........- 3-139 27 MAY 2008 iii Table of Contents (continued) Tables @ Table 3-1. NETL’s Estimate of Economically Recoverable Natural Gas Reserves............ 3-41 27 MAY 2008 iv AGIA Introduction and Summary Written Findings and Determination @ A.|Introduction and Summary After providing background information about TC Alaska and a brief summary of its application, this chapter of the Findings discusses the analysis of the net present value and likelihood of success of TC Alaska’s Application. In summary: e TC Alaska is a subsidiary of TransCanada Corporation (TransCanada). TransCanada, through its independent pipeline company affiliates, owns and operates one of the largest natural gas pipeline transportation networks in North America. TransCanada has pledged all support necessary, both financial and otherwise, to TC Alaska to achieve completion of the project. e Inits Application, TC Alaska proposes to construct a 4.5 Bcf/day pipeline from the North Slope to interconnect with the AECO Hub. TC Alaska commits to all of the AGIA requirements, which are integral to achieving a number of state benefits. These legally enforceable commitments include: o Commitments to expand the project's capacity when warranted, and to use rolled-in rate treatment for expansions, which will encourage maximum exploration and © development of Alaska’s natural gas resources, which in turn will lead to more long- term employment opportunities for Alaskans. o The commitment to use a minimum 70/30 debt/equity ratio for ratemaking purposes, which will keep rates low and thereby enhance state revenues, while also encouraging exploration and development of Alaska’s natural gas resources, which again will lead to more long-term employment opportunities for Alaskans. o The commitments to hold an open season by September 30, 2009, to initiate the FERC pre-filing process by June 2010 and to file for a FERC certificate by December 2011, which will help get a gasline more quickly.’ o The commitment to provide firm natural gas transportation service to a minimum of five delivery points in this state using distance-sensitive rates, which helps to ensure natural gas for Alaskans. o The commitments, to the maximum extent permitted by law, to hire Alaska residents and to negotiate a project labor agreement, which help ensure jobs for Alaskans. ' In its Application, TC Alaska premised these dates on receiving the AGIA License by April 1, 2008. According to TC Alaska, if the License is issued later this year, these dates may need to be adjusted. However, for ease of reference in these Findings we will continue to refer to the original dates used by TC Alaska in its Application. 27 MAY 2008 3-1 AGIA Introduction and Summary Written Findings and Determination e TC Alaska’s Project is likely to produce a very significant cash flow and positive NPV for the State of Alaska and for the other major stakeholders in the Project, including the Major North Slope Producers. Specifically: e TC , TC Alaska’s Project is likely to o The State of Alaska would realize an | produce a very significant cash estimated cash flow of $261.5 billion, and | flow and positive NPV for the an estimated NPV of approximately $66.1 | State of Alaska and for the billion at a discount rate of 5%. other major stakeholders in the Project, including the Major o The Major North Slope Producers would North Slope Producers. realize an estimated cash flow of $147.4 billion, and an estimated NPV of approximately $13.5 billion at a discount rate of 10%.” Alaska’s Project also has a significant likelihood of success, for several reasons including the following: fo} First, TransCanada is a highly experienced, independent natural gas pipeline company, with the necessary experience (operating within U.S., Mexico, Canada, arctic and near-arctic conditions) and financial resources to complete its Project. It has also proposed commercial terms that contain several attractive features, including the offer to share the risk of cost overruns, which are likely to improve significantly after TC Alaska negotiates commercial terms with the Major North Slope Producers. Second, there is a reasonable likelihood that TC Alaska will be able to successfully overcome the key barriers to the Project, including the need for firm shipping agreements with the Major North Slope Producers. For the reasons explained later in this chapter, the commissioners conclude TC Alaska has a significant prospect of obtaining firm shipping commitments even in light of the Producer Project recently proposed by BP and ConocoPhillips. The potential benefits to be gained from the TC Alaska Project, and the risks to all of the parties of not taking reasonable actions to make the Project a success, are simply too large for the parties to allow the Project to fail. 2 As explained more fully herein, the Producer NPV would be significantly higher at the same 5% discount rate used for the state. 27 MAY 2008 3-2 AGIA Who is TC Alaska? Written Findings and Determination B.Who is TC Alaska? 1. History and Company Description TransCanada is one of North America’s largest energy infrastructure companies. TransCanada’s operations include natural gas pipelines, power (electric) generation, LNG and natural gas storage. First and foremost, TransCanada is an independent natural gas pipeline company that owns one of the largest natural gas pipeline systems in North America.? In 2007, TransCanada reported assets of $30.3 billion resulting in a net income of $1.22 billion.* The natural gas pipeline portion of TransCanada’s operating portfolio is principally comprised of the company's pipelines in Canada, the United States and Mexico. TransCanada operates over 36,000 miles of wholly-owned natural gas pipelines. The majority of TransCanada’s pipelines transport natural gas from Alberta to major markets in the United States and Canada (Application 2007, Section 2.1.1). Beyond its experience owning and operating pipeline systems, TransCanada also has extensive experience in constructing and operating natural gas pipelines in harsh, cold weather conditions (Application 2007, Executive Summary, page 3). A map of TransCanada’s network is provided in Figure 3-1 below. a. TransCanada in Alaska In 2005 TransCanada discussed the Alaskan portion of a proposed Alaska natural gas pipeline project with Alaska North Slope producers and the State of Alaska. The prior Administration eventually decided not to pursue a contract with TransCanada, and instead negotiated a contract under the SGDA process with the Major North Slope Producers. That contract ultimately failed to secure legislative approval. Continuing to pursue its interest in developing a natural gas pipeline in Alaska, on November 30, 2007, TransCanada, through TC Alaska submitted an application in response to the AGIA Request for Applications (RFA). On January 4, 2008, the commissioners determined that TC Alaska’s Application satisfied all of the mandatory requirements set forth in AS 43.90.130 and complied with the requirements set forth in the RFA. Accordingly, TC Alaska’s Application is reviewed and analyzed in the subsequent sections of these Findings. > See: http://www.transcanada.com/gas_transmission/index.htm| - http://www. transcanada.com/investor/annual_reports/2007/2007_TCC_AR_Financial_Highlights. pdf 27 MAY 2008 3-3 AGIA Who is TC Alaska? Written Findings and Determination Figure 3-1. Map of TransCanada Pipeline Operations @ PIPELINES Natural Gas Pipelines El Canadian Mainline EB Alberta System El Gas Transmission Northwest Systern Wi foothills BC Systerr Gi North Baja Ventures LP 8 Tamazunchale Bh AnR BD Tuscarora fl Northern Border Great Lakes BB troquois tom Portland Alaska Highway Pipeline Project (proposed by TransCanada) El Mackenzie Gas Pipeline Project (proposed by producers) Oil Pipeline BB Keystone Pipeline Project (proposed by TransCanada) Natural Gas Storage ® ANR Natural Gas Storage —— Wholly owned Partially owned comme Proposed Source: TransCanada 2007 27 MAY 2008 3-4 AGIA Summary of Proposed Project Written Findings and Determination C.Summary of Proposed Project TransCanada Alaska and Foothills Pipe Lines Ltd. (TC Alaska) jointly responded to the RFA on November 30, 2007. TransCanada and Foothills Pipe Lines Ltd. are wholly-owned subsidiaries of TransCanada Corporation. The TC Alaska Application proposes to construct a 4.5 Bcf/day natural gas pipeline from Prudhoe Bay to existing pipeline infrastructure near Boundary Lake in Alberta, Canada. A summary of the information and data provided in the November 30, 2007 Application is provided in the following sections.° TC Alaska proposes to build a natural gas pipeline from a gas treatment plant (GTP) on the North Slope, across the Canadian border and interconnecting with existing facilities near Boundary Lake near the Alberta-British Columbia border.® From there, TC Alaska proposes to add new pipeline infrastructure to existing infrastructure from Boundary Lake, Alberta to connect with the AECO Hub (Application 2007, Section 2.1.1). At Boundary Lake the pipeline will connect with the existing Canadian pipeline grid system that has 15,000 miles of pipe, 1,000 receipt points and 200 delivery points (Application 2007, Executive Summary, page 4). This existing pipeline network feeds all major gas consuming markets in North America. The gas from the North Slope will flow through and be traded at the AECO Hub, which is one of the largest natural gas trading hubs in North America (Application 2007, Executive Summary. p. 4). TC Alaska proposes to construct the Alaska section of the pipeline using 48-inch diameter Grade X80 steel pipe with a wall thickness of slightly over one inch in diameter. The Alaska portion of the pipeline will be approximately 750 miles in length (Application 2007, Section 2.1.1). The pipeline will generally follow the Trans Alaska Pipeline System (TAPS) route from Prudhoe Bay to Delta Junction. From Delta Junction the pipeline will follow the Alaska Highway to the border of Alaska and Canada (Yukon Territory) (Application 2007, Section 2.1.1). TC Alaska proposes to bury the pipeline except at metering stations, compressor stations, certain major river crossings and selected seismic fault lines. Initially a total of six compressor stations will be located in Alaska to operate the pipeline at a capacity of 4.5 Bcf/d. TC Alaska proposes to retain these basic design parameters so long as it receives firm shipping commitments of at . The complete Tc Alaska Application is online at http://www.dog.dnr.state.ak.us/agia/PublicApplications/trans%20canada/ application/ transcanada%20application%20(non-confidential). pdf. ® The Application contains numerous commitments and TC Alaska’s project plan. Those commitments and project plan can only be changed in accordance with AGIA, notwithstanding how they may be described in these Findings. 27 MAY 2008 3-5 AGIA Summary of Proposed Project Written Findings and Determination least 3.5 Bef/d.’ According to the Application, through the addition of seven compression stations in Alaska, the capacity of the proposed system could be expanded to 5.9 Bef/d.® Pursuant to AGIA, TC Alaska’s Application commits to providing a minimum of five delivery points within Alaska. These in-state delivery points will include connections at Fairbanks and Delta Junction (Application 2007, Section 2.2). The Canadian section of the pipeline will also be constructed of 48-inch diameter Grade X80 steel pipe. The pipeline in Canada will be approximately 965 miles long with 517 miles in the Yukon Territory and 448 miles in British Columbia (Application 2007, Section 2.1.1). The Canadian section of the pipeline would originate near Beaver Creek, Yukon. Generally, the pipeline would parallel the Alaska Highway through the Yukon Territory and then cross into British Columbia. The Yukon section will follow an established easement right held in Foothills’ name (Application 2007, Section 2.2.4.2). The pipeline will be buried except at compressor stations, metering stations and certain major river crossings. Ten compressor stations will be constructed at the same time as the pipeline to operate at a capacity of 4.5 Bcf/d (Application 2007, Section 2.1.1.3). According to the Application, ultimately there could be up to nineteen stations built allowing the pipeline to operate at a capacity of 5.9 Bcf/d (Application 2007, Section 2.2.1.4). After the Alaska natural gas reaches the AECO Hub, TC Alaska’s Application assumes that the gas will be processed through existing third-party natural gas liquids (NGL) facilities (“straddle plants”) in Alberta (Application 2007, Section 2.1.4). The NGL processing facilities remove gas components such as propane, butane and ethane. There are a number of large existing NGL processing facilities in Alberta that TC Alaska expects will have the sufficient capacity to accommodate the Alaska gas. TC Alaska’s Application also accommodates the development of new NGL processing facilities in Alaska (Application 2007, Executive Summary, p. 4). 1. Gas Treatment Plant (GTP) The GTP is necessary for treating natural gas that is to be shipped via pipeline from the Alaska North Slope. The GTP will process approximately 5 Bcf/d of residue gas from the existing Central Gas Treatment Facility located at Prudhoe Bay. This residue gas would be treated by ’ The state has confirmed that, technically, TransCanada’s project is indeed technically feasible at this reduced throughput. See Appendix F, Exhibit J, at page 8. 8 id. 27 MAY 2008 3-6 AGIA Summary of Proposed Project Written Findings and Determination removing the carbon dioxide and other objectionable components. The 4.5 Bcf/d of sales gas would then be chilled to 28°F and compressed to 2,500 pounds per square inch gauge prior to shipping. The carbon dioxide would be returned to the residue gas stream and re-injected into the Prudhoe Bay reservoir (Application 2007, Section 2.1.2). TC Alaska states in its Application that it does not intend to ( y¢ Alaska, however, has develop, own, or operate the GTP. However, in the event no | stated in its Application that aa _ T it is open to offering equity third-party expresses a willingness to undertake the GTP, TC waka bi Ha prolect and Alaska would include the GTP as part of its open season and | would welcome _ project stands prepared to develop, own, and operate the facility | Partners. (Application 2007, Section 2.1.2). a. Potential Equity Partners TC Alaska’s Application is not dependent on partnerships with non-affiliated pipeline companies nor is it subject to any ownership interests by current or potential natural gas producers in Alaska. TC Alaska, however, has stated in its Application that it is open to offering equity stakes in the project and would welcome project partners (Application 2007, Section 2.2.3.7). TC Alaska has proposed ownership interests to potential anchor shippers on the pipeline. b. Management Challenges TC Alaska’s project has three main phases: the project development phase; the project execution phase; and the project operations phase (Application 2007, Executive Summary, p. 5)! The project development phase would begin with the issuance of the AGIA license in 2008 and go through August 2013. This phase begins by performing the Front End Engineering Design (FEED) that refines the project scope and attendant cost estimates, project schedules, engineering and environmental work that support the open season. After open season, the FEED work includes the routing, engineering and design work. The project development phase concludes with the “Decision to Proceed” milestone. TC Alaska estimates that 3,750,000 labor hours, at a cost of $625 million, will be required to complete the development phase of the project in Alaska and Canada (Application 2007, Executive Summary, page 7). The project execution phase would commence immediately after a favorable Decision to Proceed, which, under TC Alaska’s current estimated timetable, is expected in September 2013 27 MAY 2008 3-7 AGIA Summary of Proposed Project Written Findings and Determination (Application 2007, Section 2.6). The execution phase includes the construction of the pipeline and all associated facilities. This phase continues until the actual construction of the pipeline and associated facilities is completed, the pipeline is commissioned, and all major components are functioning and commercial operations begin. TC Alaska estimates that this phase will be completed by November 2017 (Application 2007, Section 2.6). The pipeline operations phase would begin with the commencement of commercial operations. This phase continues for the life of the pipeline, until the pipeline is removed from service. TC Alaska proposes in its Application to be the operator of the pipeline and would be responsible for all operations and maintenance activities. TC Alaska commits in its Application to assess market demand for additional pipeline capacity at least every two years after the initial open season. TC Alaska would also be responsible for the development, management and execution of future expansion projects (Application 2007, Executive Summary, page 6). c. Regulatory Challenges The AGIA licensee will be required to obtain a variety of permits and approvals from both United States and Canadian regulatory agencies. The ability to successfully manage the regulatory process is critical to meeting project schedules and the ultimate success of the project. In seeking FERC certification of the proposed project, TC Alaska has made enforceable commitments in its Application to: e Conclude an initial binding Open Season within 18 months after issuance of the AGIA license (estimated by TC Alaska in its Application to be September 30, 2009); e Apply for FERC approval to use NEPA pre-filing procedures by June 2010 (see 18 CFR § 157.21); and e Apply for a FERC certificate of public convenience and necessity authorizing the construction and operation of the Alaska section by December 2011 (Application 2007, Executive Summary, page 7). In addition to these commitments, and other enforceable commitments made in its Application, in the December 14, 2007 response to Request for Clarification from the commissioners, TransCanada Corporation emphasized its commitment to providing all support necessary, both financial and otherwise, to the Applicants to achieve completion of the project. 27 MAY 2008 3-8 AGIA Summary of Proposed Project Written Findings and Determination © With regard to Canadian regulatory issues, the Northern Pipeline Act (NPA) is the Canadian legislation that provides an expedited regulatory approval process for the development of the Alaska Pipeline Project through Canada. TC Alaska asserts that Co-Applicant Foothills holds certificates of public convenience and necessity pursuant to the NPA for the Canadian portion of the project. Foothills currently own and operate a portion of the Canada Section known as the Foothills Pre-Build. These pipelines were constructed in the early 1980s and serve to move western Canadian gas to market (Application 2007, Executive Summary,. page 11). The Pre- Build accounts for 30% of the Canadian section (Application 2007, Section 2.8). In addition to the NPA approvals, TC Alaska states it will need to obtain the following permits for the construction of the Alaska Pipeline Project through Canada: e Leave to Proceed order from the Designated Officer (DO) for the Alaska Pipeline Project. e¢ DO approval and certification of various plans, profiles and book of reference. e NEB Approval of the tolling methodology and tariffs. @ e NEB Leave to Open. e Authorizations under the Fisheries Act and the Species at Risk Act. e Provincial and Territorial approvals. TC Alaska has identified up-front planning, proper coordination, early identification of relevant issues and executing an effective stakeholders plan as some key issues to address in order to avoid unnecessary regulatory delays. d. Transportation Challenges In its Application, TC Alaska recognizes that the agreement of natural gas producers to commit gas to ship through the pipeline is an essential component in the success of the Alaska Pipeline Project. An open season is the process by which the producers or other potential shippers can commit to ship natural gas, and the pipeline owner can commit to provide transportation serviced to the producers or other potential shippers. To attract shippers to participate in the initial open season, TC Alaska is willing to offer anchor shippers a potential ownership option in the pipeline in exchange for committing a threshold amount of gas during the initial open season (Application 2007, Executive Summary, page 14). 27 MAY 2008 3-9 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination D.TC Alaska’s Project Would Produce a Significantly Positive Net Present Value for the State of Alaska AGIA requires the commissioners to use a two-part analysis in evaluating applications for the AGIA license. First, the commissioners must “rank each application according to the NPV of the anticipated cash flow to the state from the applicant's project proposal.” As discussed in Chapters 1 and 6 of these Findings, the NPV to the state is important for all Alaskans because it represents money the state could receive from royalties and taxes as a result of the Project. That money can be used for essential state services such as roads and schools, and to continue Alaska’s economic security. Second, the commissioners must weigh the NPV of the project's anticipated cash flow to the state “by the project's likelihood of success” (AS 43.90.170(a)). The likelihood a project will succeed is important to the state because, even if a project would produce a high NPV in theory, if the project is not successfully completed it may not provide any benefits to the state. After completing this process and considering the public comments, AGIA directs the commissioners to determine whether an application proposes a project that will sufficiently maximize the benefits to the people of Alaska and merits issuance of an AGIA license (AS 43.90.180). Five parties responded to the AGIA RFA by submitting applications. Of these, only one application met the threshold “completeness” requirements of the statute. Accordingly, the AGIA statute’s instructions for “ranking” are not fully applicable: there is only one AGIA- compliant applicant, so it clearly ranks first. An assessment of the TC Alaska Project's NPV and likelihood of success was nevertheless undertaken to determine whether awarding TC Alaska a license would sufficiently maximize the benefits to the state. This subsection of the Findings will discuss the analysis undertaken to evaluate the NPV of the Project, including the methodology used, and the results of the analysis. When evaluating the NPV of anticipated cash flow to the The net back value of the gas is the destination value (price sold the commissioners to consider a number of criteria that at market) minus the cost of affect the NPV. They must use an undiscounted value | t'ansportation from the inlet of ; the GTP to the destination and, at a minimum, discount rates of two, five, six, and market. state from an applicant's project proposal, AGIA directs eight percent. They must also consider how quickly the 27 MAY 2008 3-10 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination applicant proposes to begin construction of the proposed project and how quickly the project will commence commercial operation; the net back value of the gas and estimated transportation (tariff) and treatment costs; the applicant’s ability to prevent or reduce project cost overruns that would increase the tariff; the initial design capacity of the project and the extent to which it can accommodate low-cost expansion; the amount of the reimbursement by the state that the applicant has proposed; the economic value resulting from payments required to be made to the state under the proposal;® and other factors found by the commissioners to be relevant to the evaluation of the NPV of the anticipated cash flow to the state (AS 43.90.170). 1. Summary of Methodology and Results of NPV Analysis Having considered numerous factors, potential uncertainties, and various scenarios, the commissioners’ general conclusion is clear: based on the many The economics of the TC Alaska Project are escalation rates, capacity subscription (project throughput), robust and generate variables considered—including gas prices, project costs, cost available gas reserves including the timing of when Point | significant cash flows and NPVs to all the major stakeholders, discoveries, project schedule (including the risk of delay), tariff | including the state. Thomson gas will be available, the extent of future gas terms, discount rates, and other factors—the economics of the TC Alaska Project are robust and generate significant cash flows and NPVs to all the major stakeholders, including the state. The eventual gasline project that emerges will almost certainly differ in some respects from the project proposed in an AGIA application. The applicant, as a pipeline company, cannot control the amount of capacity that is eventually subscribed for in an open season. Future gas prices are notoriously difficult to predict. Meanwhile, because actual orders for long-lead items for pipeline construction are unlikely to occur for many years, the eventual cost of the project cannot be known with certainty. And finally, future commercial negotiations between the pipeline company and potential shippers, along with the regulatory process at FERC and the NEB, will likely modify (and, from the shippers’ perspective, generally improve) the applicants’ proposed tariff rates and terms of service. Each of these factors can significantly affect the NPV that flows to the state from a proposed project. ° This provision of the statute directs the commissioners to consider extra payments if any, made by the project sponsors to the State (e.g. payments in lieu of tax, dividends from the state's AGIA-inducement contribution should 27 MAY 2008 3-11 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination To assess the Project's economics and to organize its investigation of factors that create uncertainty which could impact the estimated NPV, the state adopted two “base” cases. These base cases were defined by fixed assumptions concerning project size (throughput), the gas volumes coming from different fields, and tariff terms. The “Proposal Base Case” largely mirrors TC Alaska’s Project size and tariff terms. It contemplates a pipeline that transports 4.5 Bcf/d, initially made up of 3.0 Bcf/d from Prudhoe Bay, 0.9 Becf/d from Point Thomson, and 0.6 Bef/day from other existing proved reserves. It assumes TC Alaska’s negotiated rate offer of a 75/25 debt to equity capital structure, a 14% return on equity, levelized transportation rates, and 25-year shipping contracts that fully amortize the initial pipeline investment (Application 2007, Section 2.2.3.7). The “Conservative Base Case” was developed to analyze the scenario in which, at the time of pipeline financing, Point Thomson gas is not available to be committed to the project. It contemplates a pipeline that transports 4.0 Bcf/d, initially made up of 3.5 Bcf/d from Prudhoe Bay, and 0.5 Bcf/day from other existing proved reserves. It assumes TC Alaska’s negotiated rate offer of a 75/25 debt to equity capital structure, a 14% return on equity"’, levelized transportation rates, but assumes 20-year shipping contracts that fully amortize the initial pipeline investment. Although the 20-year depreciation schedule was not explicitly offered in its Application, TC Alaska made clear that it is amenable to term-differentiated rates of 30 and 35 years, the only requirement being that the shipping contracts fully amortize the investment. (Application 2007, Section 2.2). The commissioners see no logical nor commercial reason why TC Alaska would not find a similar 20-year arrangement perfectly acceptable so long as it fully amortizes TC Alaska’s investment. The “Conservative Base Case” was generated because the availability of Point Thomson gas is uncertain. The Point Thomson reservoir is classified, for regulatory purposes, as an oil field that must be managed to prevent “waste” of the oil resource.'’ Therefore, it is possible that Alaska the project be completed). TC Alaska proposed no such extra payments and the issue is not further considered. TC Alaska proposed that return on equity be set using a 965 basis point premium above the 10-year US Treasury bond rate. See Application at 2.2-67. For purposes of the analysis we assume that return on equity is a constant 14%, which is the figure TC Alaska used in its application for tariff calculations (Application at 2.2-68). Although this rate of return could change depending upon changes in underlying interest rates, we have not attempted to model this. We think it quite unlikely that this term would survive commercial negotiations with shippers (see Appendix J; Appendix G2). Finally, potential shippers and the State would have the ability to oppose the proposed 965 basis point premium at FERC " See statement of AOGCC November 3, 2006, in the matter of an Appeal from the October 27, 2005 Amended 27 MAY 2008 3-12 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Oil and Gas Conservation Commission (AOGCC) will require that the oil must be produced before natural gas is produced (the gas is needed to maintain pressure in the field so the oil can be produced). The timing and quantity of Point Thomson gas availability will only be known after significant geologic uncertainties are resolved (Appendix O). Because Point Thomson development has not yet occurred, the production method and date of Point Thomson gas development would not be known by the time of TC Alaska’s initial open season. It is unclear at this time whether the initial development method will primarily target liquids (oil and gas condensates’’) or gas. An immediate gas production project (“blow-down”) may not be consistent with the requirements of the AOGCC. Instead, a project that targets liquid production, a process known as cycling, where gas is removed and reinjected to enhance oil recovery, may first occur. The Point Thomson unit has been terminated by the Commissioner of Natural Resources, and his decision is the subject of a legal challenge. However, even if the unit’s status were clear, the geologic uncertainty makes it questionable whether Point Thomson gas could be committed to the project during the development phase of the Project. Although analyzed through complex economic and statistical procedures, the basic framework for considering the economics of TC Alaska’s proposed Project is straight-forward. For an Alaska natural gas pipeline project to be economic, the price of natural gas must be high enough to cover the project's costs. On a per unit basis the project's costs consist of the cost of gas transportation, or tariff, and the costs of gas production. The net cash flow from gas, or “Upstream Divisible Income,” is thus: (1) the final destination price of the gas, times (2) the volume of gas transported, minus (3) total tariff payments and (4) out of pocket production costs. (Each of these major components is discussed in subsections, below). Upstream Divisible Income is shared between the producers, the State of Alaska'* and the Federal Decision on Proposed Plan of Development for the Point Thomson unit. "2 The existing geological uncertainty at Point Thomson, which limits its availability for underpinning the project's financing, most likely would have been sufficiently resolved had the former Unit operator fulfilled its obligations under the Plans of Development over the past thirty years. '3 Condensates are liquid hydrocarbons that are produced from high pressured gas reservoirs. Condensates in the reservoir remain in the gaseous phase and, as long as sufficient pressure is maintained through gas cycling, will remain gaseous and can be brought to the surface. Once at the surface, pressure can be reduced and the condensates collected for transportation to market as a liquid product. “* For purposes of this finding, property tax payments to municipalities are considered payments to the State of Alaska. 27 MAY 2008 3-13 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Government. The government share is composed of royalty, state production taxes (AS 42.55), state corporate income taxes (AS 43.20), Federal income taxes, and state and local property taxes (AS 43.56). Royalty and production taxes make up the bulk of the state’s income. The pipeline tariff also generates a “Midstream Divisible Income,” consisting of profits for the pipeline owner as well as property and corporate income taxes for the state, and corporate income taxes for the Federal government. By itself, the concept of Divisible Income, or the net cash flow from the project, does not recognize that a dollar received 20 years from now has less value than a dollar received today. In recognition that there is a time value of money, and in accordance with the statutory requirement (AS 43.90.170(b)), the calculated present value of the entire future stream of the state’s share of project net cash flows, or the state’s NPV. The farther into the future that a given net cash flow occurs the smaller its size will be in today’s dollars and the smaller its contribution to total NPV. Accordingly, all things being equal, project delays reduce the NPV. Figure 3-2, below, provides an illustrative example of this concept. Figure 3-2. Present Value of $100 Cash Flow in Future Present Value of $100 Cash Flow in Future Discount Rate = 5% 120.00 100.00 80.00 60.00 40.00 20.00 | Value of $100 in the future 0.00 1234567 8 9 101112131415 1617 181920 In addition, the contribution of a given future net cash flow to total NPV shrinks as the discount rate increases. At a 5% discount rate $100 is worth $39.57 in twenty years’ time; at a 10% discount rate $100 is worth less than half this ($16.35) and at a 15% discount rate it is worth only $7.03 (Figure 3-3). The Producers’ greater discount rate, compared with the state, helps 27 MAY 2008 3-14 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination explain why in the results that follow discounted state benefits from a project exceed producer benefits (Newell 2004). Figure 3-3. Present Value of $100 Cash Flow in Future Years Present Value of $100 Cash Flow in Future Years Sensitivity to Discount Rate 120.00 , £ 5 | = 100.00 2 | © 80.00 Ss * 60.00 ° $ | ‘g 40.00 —— 5% Discount Rate 2 8% Discount Rate & 20.00 | ; 3 _—— 10% Discount Rate - 0.00 | 15% Discount Rate 123 45 6 7 8 9 1011 12 13 14 15 16 17 18 19 20 As will be seen, this principle would make an equivalent cash flow to the Major North Slope Producers at a 15% rate look less than it would look at the 5% discount rate used for the state."® If it could be built today an Alaska natural gas project as proposed by TC Alaska would be economic. Natural gas prices at the AECO Hub, the planned end point of the Project, are currently in the $9.30-9.67/MMBtu range,"® well above the total estimated costs and tariff rate for the pipeline and gas treatment facilities, which in current 2008 dollars are estimated to be $3.19/MMBtu for the Proposal Base Case, and $3.59 for the Conservative Base Case 8 Using a lower discount rate for the State than the Producers is appropriate because it is generally assumed that government has a different role than a private company. A private company is focused on shorter-term revenues for its shareholders. By contrast, a government is more concerned about future generations and (unlike a private company) does not pay federal income tax and thus has a lower cost of capital. For these reasons, it is generally accepted that a government's discount rate is lower than that of a private company. "8 According to the May 19, 2008 issue of Gas Daily, prices for the AECO Hub are in the $C9.30-9.67/MMBtu range. Platts, Gas Daily Price Guide. Midpoint Average at the AECO-C Hub, April 2008. 27 MAY 2008 3-15 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination (Appendix G1, Section 5.7.2). For the “base case” in-service date of 2020,'’ Wood Mackenzie foresees natural gas prices at about $9.65/MMBtu, with the tariff at $4.73 MMBtu for the Proposal Base Case and $5.33 for the Conservative Base Case (Appendix G1; Section 6.4). After deducting the cost of producing natural gas the Project produces significant positive cash flow and NPV. As discussed below, the analysis shows that TC Alaska’s Project, as modeled under its proposed commercial terms, would generate very The Project would also produce a positive NPV to the cash flow to the state under the Proposal Base Case would | State under any of the exceed $260 billion over a 25 year period which, at a 5% | ‘iscount rates of two, five, six, and eight percent specified in discount rate, is worth over $66 billion in today’s dollars | aga. (Appendix G1; Section 5.7.9). For the Conservative Base Case, the state’s NPVs is $60.7 billion (Appendix G1; Section 6.4). The Project would also produce a positive NPV to the state under any of the discount rates of two, five, six, and eight significant profits for all parties under both Base Cases. Net percent specified in AGIA. In addition, under both base cases the Project would produce a significant NPV for the Major North Slope Producers, the U.S. Government, and TC Alaska (Appendix G1; Sections 5 and 6). Moreover, the analysis shows that if TC Alaska were to construct the Project, the Major North Slope Producers would stand to achieve an internal rate of return of over 50% under both Base Cases (Appendix G1, Sections 5 and 6). The state NPV for the Proposal Base Case is shown under discount rates of two, five, six, and eight percent on an undiscounted basis. As one would expect, the state’s NPV declines regularly and substantially as the discount rate rises. 1” See discussion in Chapter 3 (D)(a) of the analysis of schedule risk, which explains why 2020 is the “base case” for the project's in-service date. 27 MAY 2008 3-16 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-4. Sensitivity of State NPV to Discount Rates $300 $ Billions (2008) “fn g $100 $50 $0 Discount Rate: Cash 2% 5% 6% 8% Flow Source: Black and Veatch, Appendix G.1, Section 5.7.9 2. NPV Methodology a. General Approach The commissioners employed a large team, from multiple disciplines, to collaboratively develop a model to calculate the state’s NPV, as well as the returns to various stakeholders. The overall model itself—the state NPV Model—was built and operated by Black and Veatch with the state’s active collaboration and direction. The NPV model in it simplest expression contains outputs, algorithms, and inputs, as summarized in Figure 3-5. 27 MAY 2008 317 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-5. NPV Modeling —---- As INPUTS Monte Carlo Production Scenarios Upstream Model Midstream Rate Model etree ee ee ee ee ee ee eee ' ! 1 1 ‘ ’ Nee ew ew ew ed Source: Black and Veatch, Appendix G1, Section 3.1 The NPV Model generates informational outputs on each stakeholder’s share of project Divisible Income, including the state’s NPV. It links two key submodels (algorithms), the Midstream and Upstream models, which themselves are composed of further submodels. The Midstream Model calculates tariffs for the pipeline and GTP, which include property and corporate income tax payments. The Upstream Model calculates Upstream Divisible Income, and addresses gas and oil production volumes, sales values, production costs, and taxes and royalty. Upstream Model calculations, including calculations of production taxes and royalty, receive as input the Midstream Model's tariff outputs. The easily categorized inputs are shown in the diagram and were supplied as follows: e Gas and Oil Production Volume Scenarios Gas volumes both directly (through sales volumes) and indirectly (through tariff impacts) affect project revenues. Oil volumes, and the impact of gas sales on oil production, affect the calculation of project revenue because project revenue is measured as the difference between revenue with and without a major gas sale. Production scenarios were provided by the State of Alaska, which relied significantly on work by PetroTel for Point Thomson" and Prudhoe Bay, and the National Energy Technology Laboratory (NETL)? for undiscovered resources. '8 Appendix O, by the Division of Oil and Gas, summarizes in public form PetroTel’s report on Point Thomson which, because it contains confidential data, cannot be made public. 8 See http://www.netl.doe.gov/publications/press/2008/08002-DOE_Releases_Alaska_Report.html for the NETL 27 MAY 2008 3-18 TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Prices Prices directly affect revenue from the sale of gas. Separate price forecasts were obtained from the US DOE's Energy Information Administration, Wood Mackenzie,” Gas Strategies Consulting,”’ and Black and Veatch.” Midstream Capital Costs The capital costs of the pipeline, GTP, and (as applicable) LNG liquefaction facilities are a key input into the Midstream Model, and significantly affect Midstream tariffs. Cost ranges were developed and reviewed by a large engineering team (the state's “Technical Team’), including Westney Consulting, Energy Project Consultants, Pingo International, AMEC Paragon, Colt Engineering, Mustang Management, Energy Operations Consulting, Black and Veatch, and Merlin Associates (See Appendix F). Project Schedules and Timing Project schedules affect the timing of when gas sales begin, and because of discounting and both gas price and project cost escalation, can significantly affect project NPV. Project schedule ranges were developed and reviewed by the state’s Technical Team (See Appendix F). Interest Rates The project is highly capital intensive. Much of the funds to finance construction will be borrowed. The interest rates attached to such borrowings will significantly affect the Midstream tariffs. Goldman Sachs used its own models to generate interest rate inputs assumptions (see Appendix H). Operation and Maintenance (O&M) Costs O&M costs affect the tariff rate. For the Midstream Model input, O&M costs were reviewed and developed by the state’s Technical Team (Appendix F). O&M costs also affect the cost of production (Appendix G1). Escalation Rates Escalation rates refer to the rate at which future costs and prices change. Escalation rates for midstream costs have a particularly large impact on tariffs. The Technical Team provided guidance as to appropriate cost escalation rate assumptions (Appendix F, Section 2.1.5). report. See Appendix L by the Division of Oil and Gas, for a summary of the NETL study and an explanation for how that study was extended for use in the Upstream Model. 2 See Appendix N which provides a summary of the key parameters and expectations that underlie Wood Mackenzie's views of future gas prices in North America (both at Henry Hub and AECO Hub), as well as world oil prices. Wood Mackenzie's full report is available for subscription and, accordingly, cannot be provided here in full. 2" Appendix | contains Gas Strategies’ full report, including a discussion of LNG pricing and a forecast of Asian LNG prices based on Wood Mackenzie's views of future oil prices. 2 The Black and Veatch approach to North American gas price forecasting is detailed in Appendix G1. As explained there, Black and Veatch created an entire price model that was integrated into the NPV model to facilitate systematic exploration of price uncertainty. 27 MAY 2008 3-19 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination The NPV Model enabled the state to assess the Project's net cash flow and NPV under a range @ of different assumptions. These included the Proposal Base Case set of assumptions, and alternative assumptions and scenarios. This allowed the commissioners to evaluate and answer a number of key questions, including: What are the key factors that affect the Project's overall economics, and what are their relative magnitudes? How are the Project's risks and rewards distributed? What is the value of various aspects of TC Alaska’s commercial offer? The following discussion summarizes the major assumptions and sensitivities used by the commissioners in their NPV analysis, including additional aspects of the methodology used to derive those assumptions. Finally, with respect to the basic model structure, there are important interdependencies of oil and gas development—both in physical production and production tax treatment thereof. The NPV model measures and tracks these. Accordingly, the NPV consequences of a major natural gas sale are measured as the difference between a scenario in which there is no gas project and a scenario in which a project is developed. b. Natural Gas Prices The starting point for the estimate of the Project's cash flow and NPV was the projected price of @ natural gas during the life of the Project. As noted above, for the Project to be economic, the price of natural gas must be high enough to cover the Project’s costs, including a sufficient profit for the pipeline and for the producers of natural gas after the deduction of state revenues, including royalty and tax payments. In the late 1970s and 1980s, the price of natural gas, one of the key variables (along with costs and other factors) in determining whether a project would be economic, was generally not considered by some to be high enough to cover the cost of constructing an Alaska gas pipeline project and provide a reasonable profit to the pipeline and the producers. In the mid-1980s, for example, gas prices ranged generally between from $1.73 and $2.71.7° Since 2000 the price of natural gas has steadily increased. 3Brice published by the U.S. Department of Energy, Energy Information Administration; http://tonto.eia.doe.gov/dnav/ng/hist/n9190us3M.htm. 27 MAY 2008 3-20 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-6. Annual Henry Hub Price Annual Henry Hub Price ($/MMbtu) Nominal Dollars $10.00 $9.00 $8.00 $7.00 $6.00 | $5.00 - $4.00 | $3.00 - $2.00 | $1.00 | $0.00 + aD Tr NO TW y- OD Tr AN OT WH LY BSSSISSSssssssssess errr er eee Ke KE KE NAAN AAA AN Source: US DOE, Energy Information Administration Natural gas prices at the AECO Hub, the planned end point of the Project, are currently in the $9.30-9.67/MMBtu range.” If the pipeline could be built today, such prices would be sufficient to easily cover the tariff rate and provide substantially positive net backs, profits to the Major North Slope Producers and significant cash flow to the state.”° Of course, the Project cannot be built “today.” Under TC Alaska’s proposed timeline it will not commence for at least ten years. Thus, estimating the cash flow and NPV of the Project requires projecting the price of natural gas well into the future, beginning on the projected in- service date of the Project (i.e., an estimate of the date on which the Project would initially transport natural gas for its shippers), and continuing throughout the projected life of the Project. Projecting the future price of natural gas is challenging. However, as discussed in later sections, the price of natural gas has the single largest effect on the Project's economics. To cope with the difficulties of projecting future gas prices, given their particular importance, the state used several different approaches: (1) the forecast contained in the Annual Energy Outlook published by the U.S. Energy Information Administration (EIA); (2) a forecast provided by the Wood ?4according to the May 19, 2008 issue of Gas Daily, prices for the AECO Hub are in the $C9.30-9.67/MMBtu range. Platts, Gas Daily Price Guide. Midpoint Average at the AECO-C Hub, April 2008. 25 Recall that, if built today, the tariff would be $3.19 for the Proposal Base Case and $3.59 for the Conservative Base Case. 27 MAY 2008 3-21 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination MacKenzie consulting group; (3) a probability distribution of forecast prices produced by Black and Veatch; and (4) an entirely agnostic approach that simply considers project economics assuming that prices, in real terms, were to remain unchanged at a number of different levels. EIA’s forecast has several strong features. The AEO is a free, public, and common reference point in the energy industry. It reflects a fundamental supply and demand model, which is integrated into a broad overall assessment of demand, supply and prices for oil, natural gas and electric power. For these reasons the AGIA RFA directed applicants to base their analyses on EIA’s projections.2° However, the AEO only provides a forecast of natural gas prices at Henry Hub, a major trading point in Louisiana. Accordingly, AECO Hub prices—which determine the Project's economics, because this is where the TC Alaska project would deliver the gas—have to be inferred. Some have also questioned whether EIA’s projections are overly conservative, as during the last ten years they have tended to systematically underestimate natural gas prices (Appendix G1, Section 4.3). Although it is available only a subscription basis, Wood Mackenzie’s price forecast is also widely used in the natural gas industry. Wood Mackenzie’s clients include each of the Major North Slope Producers and a large number of other major energy companies.”” Like EIA, Wood Mackenzie's price forecast reflects an integrated view of the energy sector. Unlike EIA, Wood Mackenzie offers a direct price projection for the AECO Hub itself, in addition to projections for Henry Hub. The Wood Mackenzie forecast was the reference forecast used to generate “base case” results, for several reasons. First, it offers a widely respected, public (if proprietary) natural gas price forecast. Second, Wood Mackenzie directly forecasts prices into the AECO Hub—the relevant market. Finally, this price forecast is modeled on a consistent basis with Wood Mackenzie’s forecast of world oil prices, upon which LNG prices are based. This permits an “apples to apples” modeling comparison of Asian LNG prices and AECO Hub prices (which will be discussed later in the analysis of LNG options in Chapter 4). 26 To facilitate an “apples to apples” comparison between competing applications, Section 3 of the RFA directed all Applicants to benchmark their estimate of natural gas prices off the U.S. EIA’s most recent Annual Energy Outlook forecast of Henry Hub spot market prices. The RFA also permitted the use of other gas price forecasts in addition to the EIA forecast. RFA at Section 3.2.1. ?7http:/Amww.woodmacresearch.com/cgi-bin/corp/portal/corp/overview.jsp?overview_title=corpCredentials. According to Wood Mackenzie, 24 out of the 25 largest energy companies are clients. 27 MAY 2008 3-22 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination At the state’s direction Black and Veatch used the North American Gas Model to develop projections of AECO Hub prices. It did so in recognition that the main drivers of gas supply (e.g. production costs) and demand (e.g. electricity demand, industrial demand, LNG imports) and thus gas price, are themselves highly uncertain. Both the EIA and Wood Mackenzie price forecasts each embody only a single view of these main drivers of supply and demand. Accordingly, they do not recognize these uncertainties. They do not permit an explicit and quantitative consideration of price uncertainty as driven by supply and demand uncertainty. There is no way using the EIA and Wood Mackenzie forecasts to address questions like: “what would happen to prices if LNG imports were 40% higher than EIA is assuming?,” or “how would a decrease of 60% in electricity demand for gas affect prices?” The Black and Veatch approach permits just this kind of direct consideration of price uncertainty. It culminates in the development of probability distributions of the AECO Hub price over time. The Black and Veatch model structure and its assumptions are discussed in detail in Appendix G1, Section 4. Each of the foregoing gas price forecasts derive from different fundamental models of supply and demand, and use different sets of assumptions regarding the determinants of supply and demand. They each provide different insights into what prices may be. However, precisely because they are sophisticated—embodying numerous inputs and assumptions—they can be difficult to understand. Accordingly, project economics and state NPV were also modeled on the basis of a series flat real prices. Although natural gas prices are highly volatile and are anything but flat, the advantage to looking at project economics “as if’ prices were flat is that the assumption is directly and easily understood. As discussed below, the conclusion that the The conclusion that the Project would produce significant NPVs to the state and state and other key stakeholders is robust other key stakeholders is robust across the different price projections. Further, under the Project would produce significant NPVs to the across the different price projections. Further, relatively unlikely low price scenarios, the under relatively unlikely low price scenarios, the project’s economics appear favorable even if project's economics appear favorable even if the | the Project experiences significant cost increases. Project experiences significant cost increases. c. EIA Price Forecast In its 2008 annual energy outlook, EIA projected the price of natural gas at Henry Hub to be approximately $8.40/MMBtu in 2020 (in nominal dollars), increasing to approximately $13.06/MMBtu in 2030 (again, in nominal dollars). 27 MAY 2008 3-23 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination EIA does not project a price at the AECO Hub, the projected destination point for the Project. To help account for this fact, TC Alaska reduced the EIA projection for Henry Hub by 75 cents per MMBtu based on a measure of the historical difference between the price of gas at Henry Hub and the AECO Hub.”° In effect, it subtracted 75 cents from each of the prices in the previous graph. When we use EIA price forecasts we follow TC Alaska’s suggested approach. (Appendix G1, Section 4.3.5.4, reproduced in Figure 3-7). However, using a historically-based price differential is not consistent with the fundamental supply-demand model EIA used to forecast prices. Further, at least in Wood Mackenzie’s view, the assumption of a constant 75 cent price differential between Henry Hub and the AECO Hub is conservative and in the future AECO Hub prices may be closer to Henry Hub. Figure 3-7. EIA-Based Henry Hub and AECO Price Forecasts to 2045 (Nominal dollars) $30.00 EIA Henry Hub Forecast $25.00 . —— EIA AECO Forecast i ° c ° 7 ° . $20.00 . : 2 -5¢ $15.00 - ase Nominal $/MMBtu . . 1% = 8 . . $10.00 $5.00 $- 7 = 2008 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 Source: Black and Veatch, Appendix G1, Section 4.3.5.4. 28 Application at 2.10-5; see Appendix G.1 at Section 4.3.5.3 (establishing that $0.75) generally reflects the historical differential between Henry Hub spot prices and Alberta Hub spot prices. 27 MAY 2008 3-24 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination As Figure 3-7 demonstrates, the 2008 EIA forecast projects that in the year 2020 the price of natural gas at AECO will be approximately $7.40/MMBtu, and approximately $11.77/MMBtu by 2030.”° There are reasons to think that EIA’s pricing outlook is conservative. Over roughly the last eight years the EIA has consistently underestimated prices (Appendix G1, Section 4.3.4.5). d. Wood Mackenzie Price Projection In addition to the EIA projection, a projection of natural gas prices supplied by the Wood Mackenzie consulting group was considered. The details underlying Wood Mackenzie’s “view of the world"—its projections of fundamental supply and demand drivers—are reviewed in Appendix N. The Wood Mackenzie forecast extends only to 2027. Because the NPV model requires price inputs for the first twenty-five years of gas flow, Black and Veatch extrapolated the Wood Mackenzie forecast using the real price growth rate exhibited during 2020-2027. (Appendix G1, Section 4.3.6.3) This is reflected in Figure 3-8. Figure 3-8. Wood Mackenzie-Based Henry Hub Forecast to 2045 (Nominal dollars) $35.00 — $30.00 . ~~ Wood Mackenzie Henry Hub Forecast . $25.00 i $20.00 5 $15.00 . v4 $10.00 1 eel $5.00 a 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 Sources: Wood Mackenzie's Long Term View—January 2008 Update: Gas and Power Service; Black and Veatch; Appendix G1, Section 4.3.6.3 9 The EIA publishes its price forecast in “real” dollars. These have been converted to “nominal” dollars by assuming a 2.5% rate of inflation. ElA’s real-dollar estimates are $5.60/MMBtu and $6.85/MMBtu for 2020 and 2030, respectively. 27 MAY 2008 3-25 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination As noted earlier, the EIA forecast is used to derive an AECO Hub price assuming AECO Hub prices continue to reflect the historical average reduction of approximately 75 cents per MMBtu from Henry Hub prices. (Appendix G1, Section 4.3.6.3). However, this method of deriving AECO Hub prices does not fully account for future supply and demand conditions that will determine actual prices at the AECO Hub. By contrast, Wood Mackenzie projects that the price of natural gas at AECO Hub will actually increase relative to the Henry Hub price. Figure 3-9 reflects this expected convergence of AECO and Henry Hub prices. Figure 3-9. Wood Mackenzie Basis Forecast (Henry Hub) - (AECO Hub Nominal) price differences 0.70 | 0.60 | 0.50 0.40 0.30 0.20 0.10 0.00 Us$/Mmbtu -0.10 -0.20 -0.30 Source: Wood Mackenzie’s Long Term View—January 2008 Update: Gas and Power Service; Black and Veatch; Appendix G1, Section 4.3.6.3 Wood Mackenzie forecasts future changes in Canadian natural gas supply and demand that differ from the historical data supplied in the Application using ElA-adjusted data. Specifically, Wood Mackenzie projects demand for natural gas in Canada to continue to increase. At the same time, Wood Mackenzie projects that the available supply of natural gas in Canada, which is already flat and in some cases declining, will decrease. According to Wood Mackenzie, both of these factors—increasing Canadian demand and decreasing Canadian supply—will tend to increase the price of gas at AECO Hub relative to the Henry Hub price.*° Wood Mackenzie thus % As will be discussed in Section E, the decrease in Canadian supply will also result in lower throughput and more unutilized capacity on TransCanada’s pipelines located in Canada, absent the construction of the Project. This 27 MAY 2008 3-26 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination projects a price of natural gas at AECO Hub of approximately $9.65/MMBtu in 2020, with gradual increases thereafter. Beginning in about the year 2016 and continuing through at least the year 2030, the Wood Mackenzie natural gas price forecast exceeds EIA’s 2008 forecast by a full $2/ MMBtu. The Wood Mackenzie forecast for AECO is shown in Figure 3-10. Figure 3-10. | Wood Mackenzie-Based Henry Hub and AECO Price Forecasts to 2045 (Nominal dollars) $35.00 $30.00 Wood Mackenzie AECO Forecast ea ~—— Wood Mackenzie Henry Hub Forecast . $25.00 ar $20.00 . 3 $15.00 e* Nominal $/MMBtu . . . $10.00 $5.00 $- + + 2008 2012 «= 2016 «= 2020S «2024 «=: 2028 «= 2032-2036. «= 2040) 2044 Source: Wood Mackenzie’s Long Term View—January 2008 Update: Gas and Power Service; Black and Veatch; Appendix G1, Section 4.14 Because the Wood Mackenzie price forecast generally exceeds the EIA forecast, it results in a higher cash flow and NPV to the state. e. Projection Based on Forward-Looking North American Supply and Demand Model The NPV model also used price forecasts generated by Black and Veatch that use the North America Regional Gas model (NARG) as a platform. The state commissioned Black and provides TransCanada with an increased incentive take the necessary steps to make the Project become a reality. 27 MAY 2008 3-27 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Veatch to generate these forecasts so that gas price uncertainty, as caused by uncertainty in the fundamental drivers of supply and demand, could be systematically addressed. The NARG model analyzes the entire North American market, including all demand centers at the state and provincial level (including major demand centers like New York City, Chicago and Los Angeles) all North American natural gas producing basins, and the entire North American natural gas pipeline grid (Appendix G1, Section 4.3.7). The NARG model generates price forecasts for all demand centers and major supply hubs (including the AECO Hub), and corresponding pipeline flows across the entire grid. The model balances supply and demand by matching natural gas production from each basin with pipeline flows and natural gas consumption across the entire North American market. The NARG modeling effort began with establishing a “base case” price forecast—a direct analogue of the forecasts provided by EIA and Wood Mackenzie. Major assumptions that underlie this base case are discussed in Appendix G1, Section 4.3.7.2. In general, base case assumptions that Black and Veatch adopted for various drivers can be considered “conservative.” That is, they tend to err on the side of driving gas prices down.*' They assume, for example, that: e U.S. natural gas demand, in aggregate, will remain virtually flat for the next 35 years, despite a reasonable expectation of significant economic growth in North America, and despite the possibly increased need to use natural gas (rather than coal) given efforts to reduce greenhouse gas emissions. e Even though gas exploration and development costs have increased approximately 100% since 2003,** costs are assumed to remain essentially flat for the discovery of approximately the next 190 Tcf in the Western Canada Sedimentary Basin, the Rockies, and the Gulf of Mexico (offshore). The assumption of relative stability of E&D costs in these areas tends to result in lower projected gas prices inasmuch as higher finding costs put upward pressure on the price of marginal supplies and thus on gas prices generally. *' The state has twice previously hired Black and Veatch to create long-term price projections. There, too, an effort was made to err on the side of caution, and assume price-driver values that depress gas prices. As discussed in Appendix G1, Section 4.3.7.3.4, a review of past Black and Veatch forecasts suggests that assumptions have indeed been conservative; realized gas prices have exceeded forecasted prices. % IHS/CERA upstream capital cost index, "Costs...have doubled since 2005,” CERA May 14, 2008 27 MAY 2008 3-28 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination e A large increase in LNG imports into the U.S. from approximately 2.5 Bcf/day in 2008 to almost 11 Bef/day in 2020, and over 15 Becf/day in 2040. This assumption can be considered to provide a conservative projection of AECO Hub prices in two respects: the import volumes are higher compared with industry estimates and the import price is expected to be at levels below market-clearing price (LNG is an inframarginal source of supply) (Appendix G1, Section 4.3.6.2.3). Lower LNG import volumes or higher import costs will result in upward pressure on North American natural gas prices where the import volumes arrive regardless of the LNG premium that may be enjoyed in other markets during the period (See Appendix |). Based on these assumptions, Black and Veatch’s NARG Model generates an AECO Hub base case price forecast of approximately $9.10/MMBtu in 2020, as shown in Figure 3-11: Figure 3-11. Black and Veatch Henry Hub and AECO Price Forecasts to 2045 (Nominal dollars) $35.00 _- - eee peas — $30.00 —— BV AECO Forecast ~~ BV Henry Hub Forecast $25.00 $20.00 $15.00 Price (Nominal $/MMBtu) $10.00 $5.00 2009 2013 2017 2021 2025 2029 2033 2037 2041 2045 Source: Black and Veatch; Appendix G1, Section 4.3.7.3.2. In general, the Black and Veatch base case forecast initially closely tracks Wood Mackenzie's before occupying a mid-point between EIA’s and Wood Mackenzie's. 27 MAY 2008 3-29 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Black and Veatch’s approach to long-term price forecasting not only focuses on providing baseline projections under specific assumptions, but also emphasizes the range of uncertainties around the forecasts. This permits a much fuller assessment of price risks and highlights the market factors that could influence natural gas prices. Wide ranges of important supply and demand drivers of natural gas prices were modeled. For each given variable, both a “high” case and a “low” case were considered. In the “high” case there is a 90% chance that the variable will have a value at or below; in the “low” case there is only a 10% chance that the variable will take a value at or below the case. For example, the P90 case for LNG imports assumes that LNG will supply fully one-third of U.S. demand (LNG currently makes up about 3%)°** (Appendix |, Section 4.2). Some sample drivers, and the range of their considered values, are shown in Figure 3-12 (see Appendix G1, Section 4.3.8 for more assumptions and discussion): Figure 3-12. _ U.S. Gas-fired Power Generation Demand Distribution Range 30.0 25.0 20.0 15.0 + 10.0 5.0 0.0 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 Source: Black and Veatch; Appendix G1, Section. 4.3.8.2.4 33 See EIA, 2008: “Natural Gas Consumption by End Use”; http://tonto.eia.doe.gov/dnav/ng/ng_cons_ sum _dcu_nus_a.htm, and EIA, 2008: “U.S. Natural Gas Imports by Country’ http://tonto.eia.doe.gov/dnav/ng/ng_move_impc_s1_a.htm 27 MAY 2008 3-30 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination The foregoing imagines the need for gas generation being both much larger and significantly smaller than under the “base case.” Figure 3-13. | WCSB Finding and Development Cost Curve (Real 2008 $) $10.00 $8.00 $6.00 $4.00 $2.00 —— Base Case P10 ——P90 | Finding and Development Cost (Nominal $/MMBtu) $0.00 r r r r 4 0 50 100 150 200 250 Accumulative Reserve Additions (Tcf) Source: Black and Veatch; Appendix G1, Section 4.3.8.2.1 The cost of finding and developing new gas resources in a given supply basin has a significant effect on future prices. Here we assume a high-to-low multiple of about two. 27 MAY 2008 3-31 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-14. U.S. Lower 48 Industrial Demand Distribution Range @ 30.0 25.0 20.0 15.0 10.0 5.0 + on =s<-es - - | 0.0 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 Source: Black and Veatch; Appendix G1, Section 4.3.8.2.5 The relative impact of each fundamental driver on the AECO Hub price is shown, below (Figure @ 3-15). 27 MAY 2008 3-32 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-15. Relative Impact of Price Drivers on AECO HUB Price Formation, 2022 (Nominal $) Tech Improvement & Cost Escalation Power Generation WCSB F&D Costs GOM and Rockies F&D -$4.00 -$3.00 -$2.00 -$1.00 $0.00 $1.00 $2.00 $3.00 $4.00 Price Delta ($) | @P10 @ P90 Source: Black and Veatch; Appendix G1, Section 4.3.8.3 The impact of each driver is shown by assuming all other drivers are held constant at their “base case” levels, and then varying the driver in question. By a significant margin, the largest effect on AECO Hub prices in 2022 is the cost of finding and developing new gas resources, which is itself most affected by the rate of technological innovation and cost escalation. The level of gas demand from power generation also particularly matters in this time frame. Although the previous chart considers them separately, the uncertainties in each of these drivers can be jointly considered. That is, one might want to know, for example, both what the price would be if LNG imports are high, and electricity demand is low, but also the likelihood of both events simultaneously occurring. Using statistical techniques, Black and Veatch integrated the NARG analysis into a Monte Carlo framework* (Appendix G1, Section 4.3.8.1). This result is not a single price forecast, but many thousands of price forecasts. The collection of these on Although the details differ somewhat, the general Monte Carlo simulation approach taken for price is similar to that used in the cost modeling work, which is discussed ,below. 27 MAY 2008 3-33 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination forecasts forms a probability distribution of future prices. The results are shown, below (Figure 3-16). Figure 3-16. Distribution Range of AECO Price Forecasts over Time (Nominal $) $45.00 $40.00 — BV Base BVP10 -—~—BVP90 $35.00 $30.00 $25.00 $20.00 Price (Nominal $/MMBtu) $15.00 $10.00 $5.00 $0.00 T —— 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 Source: Black and Veatch; Appendix G1, Section 4.3.8.4 The relevant question, when considering future gas prices, remains simple: will they generally be greater than the costs of gas transportation, treatment, and production, so that the project generates positive net backs and can provide a positive NPV? The answer cannot be known with certainty. However, on balance it appears highly likely that they will be. The following chart (Figure 3-17) shows the EIA, Wood Mackenzie, and Black and Veatch forecast. 27 MAY 2008 3-34 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-17. AECO Price Forecasts (Nominal $) $45.00 + — Wood Mackenzie AECO Forecast $40.00 | ___e\ AECO Forecast — BV Base Case Forecast $35.00 BV P10 ssn | a eveeO aia | t ’ 2 -o— Historical 2007 AECO Price with inflation 52 - i $25.00 j $20.00 Ss 2 $15.00 $10.00 $5.00 $- 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 Source: Black and Veatch; Appendix G1, Section 4.3.8, f. Estimated Volumes of Natural Gas Sold The second component of the net cash flow formula (price multiplied by volume minus cost equals net cash flow) is the volume of natural gas. In its application TC Alaska contemplates an initial annual average daily project capacity of 4.5 Bcf/day (Application 2007, Section 2.1.1). The pipeline base design—pipeline diameter, yield strength, compressor size—will accommodate volumes as small as 3.5 Bcf/d and provide for expansion through infill compression up to at least 5.9 Bcf/d (Application 2007, Section 2.2.3.2(1); 2.2.1). Because TC Alaska does not control gas reserves it cannot determine how much gas the pipeline will transport. Accordingly, throughput must be modeled according to various plausible scenarios. There are two issues of importance that must be considered in constructing any plausible throughput scenario: a) how much gas, in total, will flow; b) the relative proportions from various gas fields of this total flow. Total flow is an important determinant of total project revenue. The relative proportions matter because the costs of production differ considerably across fields and, because of the net profit tax structure of the state’s production tax, production costs have a significant effect on state NPV. 27 MAY 2008 3-35 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination The NPV model tracks four major “pools” of gas. Prudhoe Bay will be the project's main anchor. It contains over 24 Tcf of gas (ADNR 2007).*° Point Thomson also contains very significant gas reserves; based on work by PetroTel, it may contain up to 10.4 Tcf of gas (Appendix O). Total recoverable reserves from Point Thomson could range from 5 to 7 Tcf.*° Other “State Existing” proved reserves, scattered between the Colville River, Duck Island, Kuparuk, and Northstar Units, and the Greater Point McIntyre Area of Prudhoe Bay, together total roughly 3.7 Tcf of known gas reserves. These are modeled as a single “pool.” Finally, gas for the project may come from significant yet to be found (YTF) resources. Prudhoe Ba’ Prudhoe Bay currently produces over 7.4 Bcf/d,°” most of which is currently reinjected into the reservoir to maintain reservoir energy and enhance oil production. The unit is clearly capable of producing natural gas at a very considerable rate. The issue for this analysis is simply what rate might be approved by the Alaska Oil and Gas Conservation Commission (AOGCC), and what the consequences of different off-take rates for oil production might be. We have modeled gas off-take rates for Prudhoe Bay and into the Project at 3.0 Bcf/d (for the “Proposal Base Case”) and 3.5 Bcf/d (for the “Conservative Base Case”). These off-take rates, although in excess of those currently approved by AOGCC, are nevertheless reasonable because they are highly likely to pass regulatory muster. The remainder of this subsection explains why. The AOGCC is responsible for implementing the Alaska Oil and Gas Conservation Act (AS 31). It is charged with regulating oil and gas practices in order to prevent “waste” of oil and gas and promote greater ultimate recovery of oil and gas. “Waste,” in addition to its ordinary meaning, includes: %° Alaska Department of Natural Resources (ADNR). Alaska Oil and Gas Report. July 2007. Available at http:/Awww.dog.dnr.state.ak.us/oil/products/publications/annual/report.htm % The low end of this range reflects low-end results generated by PetroTel in its Point Thomson reservoir simulation work for a gas cycling development, while the upper end reflects possible recovery under gas blow-down development; see Appendix O for discussion. 37 See BP’s submitted “2008 Plan of Development and Annual Progress Report for the Initial Participating Areas of the Prudhoe Bay Unit,” March 31, 2008; p. 4. 27 MAY 2008 3-36 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination “the inefficient, excessive, or improper use of, or unnecessary dissipation of, reservoir energy; and the locating, spacing, drilling, equipping, operating or producing, of any oil or gas well in a manner which results or tends to result in reducing the quantity of oil or gas to be recovered from a pool in this state under operations conducted in accordance with good oil field engineering practices.” (AS 31.05.170(15)(A)) In most cases “the specified wastes represent physical losses of oil and gas that tend to occur under competitive exploitation of petroleum deposits by individual operators using primary means of recovery.” (McDonald 1971). McDonald goes on to explain that the “prevention of operations tending to cause loss of ultimate recovery does not in practice extend to a positive requirement that all feasible means be employed to maximize recovery” (McDonald, p. 122) and goes on to define waste as “a preventable loss the value of which exceeds the cost of avoidance” (McDonald, p. 129, emphasis added) AOGCC carries out its responsibility by regulating the quantity and rate of the production of oil and gas. (AS 31.05.030(e)(1)(F)). The AOGCC does not determine and direct the rate or method of production. Rather it responds to operators specific requests for approval of off-take rates and volumes. Operators file requests with the AOGCC for allowable off-take rates and volumes with technical justification for their requests. In 1977, the Prudhoe Bay Unit (PBU) owners requested and received approval from the AOGCC of a maximum allowable PBU annual gas off-take rate of 2.7 billion standard cubic feet per day (BSCF/D), which contemplated an annual average gas pipeline delivery sales rate of 2.0 BSCF/D. Between 2002 and 2007, there was much public discussion by the Major North Slope Producers and others about a 4.3 BSCF/D gas pipeline with capacity to expand to 5.6 BSCF/D.* The AOGCC expressed concern that delay in their decision-making could disrupt a timetable for a potential gas line project. The AOGCC adopted a proactive approach to ensure there would be an adequate factual basis for its eventual decision on allowable gas off-take. The PBU working interest owners (WIOs) provided the AOGCC access to their reservoir simulation and other relevant engineering studies for the purpose of analyzing gas off-take rates and gas sales startup timing for the PBU. The AOGCC conducted a confidential study and recommended that a change to the current off- %8 These prior discussions provide indirect support for the feasibility of TC Alaska’s proposed 4.5 Bef/day Project. 27 MAY 2008 3-37 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination take rule was not necessary at that time because the producers had not yet requested a different gas off-take rate and did not have a sales startup date.*® The AOGCC determined that the ultimate impact of gas sales on hydrocarbon recovery could not be appraised in the absence of a proposed development plan that identifies the start date, sales rate and liquid loss mitigation efforts. The AOGCC noted that the longer gas sales are delayed, the greater the risk that well and facilities failures will result in premature field shutdown. While the results of its study are confidential, the AOGCC has signaled that it is not concerned about a greater off-take rate to accommodate a major gas sale as long as the PBU continues to increase the capture of oil prior to gas sales and ensures that facility and well downtime is minimized. For example, in testimony before the Senate Resources Committee of the Alaska Legislature, Commissioner Cathy Foerster stated that “whenever we get a gas line and whatever gas sales volume, within reason, is called upon from Prudhoe Bay, it will be the right answer . . . the ‘right answer is that we will want to sell whatever volume is needed from Prudhoe Bay and we'll want to sell it whenever it is needed to ensure that the gas line is a go (Foerster, 2008).” The Division of Oil and Gas (DOG) professionally evaluated all reservoir information provided by the PBU operator as part of its responsibility to evaluate and approve annual Plans of Development for the PBU. Based on all the information available, DOG believes that there is little risk that the AOGCC will not approve a change to the off-take rate for a major gas sale (assuming that PBU oil continues to be aggressively produced and mitigation alternatives are adopted). The PBU owners have an ongoing responsibility to provide the DOG with an annual reservoir surveillance report, an annual field overview presentation and annual plan of development that must be approved by the DOG. As recently as March 2008, the PBU owners have shared with the DOG information about their gas sales evaluation framework. Potential major gas sales are at least ten years away. During the pre-commitment stage PBU working interest owners (WIOs) will look at gas off-take studies and will use a new full-field model for major gas sales forecasting. The PBU WIOs also plan to engage in depletion strategies to optimize total economic hydrocarbon recovery with gas sales. They continue to evaluate enhanced oil recovery options including potential use of carbon dioxide concurrent with major gas sales. Oil recovery from the PBU has far exceeded initial expectations. In 1977 the PBU owners *° See Prudhoe Gas Sales Reservoir Study, Feb. 28, 2007, Public Report Summary and Slides. 27 MAY 2008 3-38 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination projected they would recover approximately 9 billion barrels of oil, begin major gas sales in the 1980s and reach end of field life by 2003. Gas sales didn’t materialize in the 1980s and more than 11 billion barrels of oil have been recovered to date. PBU oil recovery is currently projected to reach 13 billion barrels, providing another almost 2 billion barrels of oil. PBU’s 24 TCF of gas in the gas cap is equivalent to 4 billion barrels of oil. Gas is currently reinjected to produce oil. As time goes on, there is ever increasing water and gas in every barrel of oil that is produced. The increasing costs to produce a marginal barrel of oil will tip towards producing the gas for sale rather than consuming it to produce marginal barrels of oil. The success in recovering oil will make it easier for the AOGCC to approve whatever amount of gas the producers eventually seek permission to take. PBU oil production will continue even after major gas sales begin. In sum, for the reasons discussed above, we believe that at the appropriate time in the future AOGCC will take the actions necessary to facilitate sales of natural gas needed to fill the Project capacity consistent with the volume forecast relied on in our NPV analysis. Point Thomson As discussed earlier, the nature and pace of development at Point Thomson is subject to considerable uncertainty. The primary driver of this is actually geological uncertainty. Different geological interpretations of the available data suggest: e The volumes of original gas in place (OGIP) range from 8.5-10.4 trillion cubic feet (TCF). e The volumes of associated condensate range from 490-600 million barrels (MMB) of condensate in place. e A range of volumes of original oil in place (OOIP) in the oil-rim from 580-950 MMB (Appendix O). Resolution of what is actually in place and what can be recovered, and how, will not occur until more wells are drilled and production begins. It is exceedingly unlikely, even absent the extant litigation over Point Thomson development that the necessary actions—development, commercial, and regulatory—could be taken in time. With financing decisions needing to be made within roughly 6 years, it is highly unlikely that geological uncertainty could be resolved sufficiently, and in a timely manner, for Point Thomson gas to be available to help underpin the initial financing of any gas pipeline project. 27 MAY 2008 3-39 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Nevertheless, for NPV modeling purposes we consider two cases. In the first, the “Proposal Base Case,” Point Thomson is indeed available to help underpin project financing. It gets developed using a primary depletion strategy (“gas blowdown”) and initially produces at 1 Bcf/d. In the second case, the “Conservative Base Case,” Point Thomson is developed as a cycling project and is not available until much later. State Existing Other proved gas reserves are brought into the project, in aggregate, in both Base Cases at an initial rate of 0.5 Bcf/d. Additional details concerning the assumptions made regarding other proved gas reserves are included in Appendix G1, Section 4. Yet To Find Gas Studies estimate that there are 224 trillion cubic feet of undiscovered, technically recoverable natural gas resources throughout the Alaskan Arctic (USGS, 2005. NETL, 2007. Appendix O). Of this amount, 137 trillion cubic feet are categorized as undiscovered, economically recoverable resources. (NETL 2007). In terms of overall hydrocarbon potential there would appear to be an | Although gas exploration and development is an_ inherently uncertain business, it appears that gas exploration and development is an_ inherently future gas discoveries will be more uncertain business, it appears that future gas discoveries | than sufficient to fill the pipeline’s capacity during the life of the will be more than sufficient to fill the pipeline’s capacity | project. abundant supply of natural gas for the project. Although during the life of the Project. The conclusion is reinforced by a comparison with the reserve base supporting other greenfield projects. (Appendix J; Section Ill) In both Proposal and Conservative Base Cases, the NPV model assumes that sufficient gas will be found to keep the Project operating at full capacity. The modeling assumptions around “yet to find” (YTF) gas volumes, timing, and cost of development are based squarely on a recent study by the U.S. Department of Energy’s National Energy Technology Laboratory (NETL; Alaska North Slope Oil and Gas: A Promising Future or an Area in Decline?; hereafter “Alaska Gas Study”). “° NETL concludes there are approximately oo Appendix L provides a detailed discussion of the NETL study, and explains the minor extensions of the study upon which the timing, volume, and cost assumptions concerning YTF gas were based. The assumptions about costs for developing YTF resources were then used in the Upstream Model. For details see Appendix G1, Section 3.8. 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination 137 Tcf of economically recoverable natural gas reserves on the North Slope, about four times greater than estimates of known reserves. Table 3-1 summarizes NETL’s conclusions, showing NETL’s estimates within various individual North Slope producing areas. Table 3-1. NETL’s Estimate of Economically Recoverable Natural Gas Reserves Near Term Long Term Total Exploration Province 2005 to 2015 2015 to 2050 2005 to 2050 Colville-Canning and State Beaufort Sea 10.0 TCF 23.3 TCF 33.3 TCF Beaufort Sea OCS 1.0 TCF 20.0 TCF 21.0 TCF Chukchi Sea OCS 0 TCF 50.0 TCF 50.0 TCF NPRA 1.0 TCF 30.0 TCF 31.0 TCF ANWR 1002 Area 0 TCF 2.0 TCF 2.0 TCF TOTAL ARCTIC ALASKA 12.0 TCF 125.3 TCF 137.3 TCF Source: National Energy Technology Laboratory 2007 Under NETL’s estimate there should be more than enough natural gas to fill the Project's capacity for the entire 25-year Project life, and for a significant time beyond. At a capacity of 4.5 Bcf/day, it would take 41 Tcf of gas to keep the Project at capacity for 25 years—roughly 6 Tcf beyond the existing proved reserve base, or only about 5% of the total economically recoverable reserves that NETL estimates exist. On the other hand, if NETL’s estimates are correct, then reserves should be sufficient to keep the pipeline full for more than 100 years. Even under a conservative assumption, it appears that there is more than enough economically recoverable natural gas reserves exist to fill the Project's capacity during the Project’s proposed 25-year life and beyond. In general the NPV model assumes that YTF gas is available to fill the pipeline capacity when it is needed. This involves making simplifying assumptions that depart from the “real world”: rather than gas developments being “lumpy” and potentially requiring expansions, for the Base Cases the model assumes that YTF gas flows into the Project as needed. The alternative approach— trying to make “realistic” assumptions about the timing and degree of “lumpiness” of discoveries, with possible attendant expansion—would have been worse. For modeling details for YTF gas see Appendix G1, Section 3.8. It is worth stressing that the economic returns provided by YTF gas, discussed subsequently in this Chapter, appear sufficiently attractive to attract the necessary investment. The profile of gas production from different “pools” for the Proposal Base Case and Conservative Base Cases are shown below (Figure 3-18 and Figure 3-19, respectively).”" * Note that, to maintain the data confidentiality, Prudhoe Bay and State Existing gas are shown as an aggregate 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-18. | Production Profile for Proposal Base Case @ G PBU/State Existing Point Thompsom as State - Yetto-Find © Fed-Onshore : 45 3.5 3.0 3 IS 8 25 NS S 2 w Le 2.0 VOU ee B58; Oy) 1.5 1.0 0.5 0.0 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 Source: Black and Veatch; Appendix G1, Section 4.2.2.1 @ pool, even though the model tracks each separately. 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination @ Figure 3-19. Production Profile for Conservative Base Case 5.0 @ PBU/State Existing State - Yet-to-Find @ Fed-Onshore 46 es Se ee ee ese - c — ote 4.0 3.5 3.0 2.5 Befid 2.0 15 1.0 0.5 0.0 - 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 © Source: Black and Veatch; Appendix G1, Section 4.2.3.1 Production scenario sensitivities were run off the Base Cases. For both cases, project economics were considered for the extreme case where no YTF resources were developed. The Proposal Base Case was also run under the assumption that PTU was not available, but that PBU production was increased to make up the difference. Details and results are available in Appendix G1 Sections 5 and 6, and are treated later in this Chapter. Market factors, including competition among producers and the production economics of particular fields, are likely to determine exactly which scenario becomes reality. Producers will incur only minimal incremental costs to produce natural gas from Prudhoe Bay, due to the fact that natural gas can be produced using the extensive infrastructure already in place which is used to produce oil (Appendix G1, Section 3.8). The production costs for Point Thomson, and YTF gas will be materially greater, because those areas do not have extensive production infrastructure already in place (Appendix G1, Section 3.8). From an NPV perspective, the lower production costs at Prudhoe Bay mean that the NPV to the state and the Major North Slope Producers is significantly higher under the scenarios that 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination assume no Point Thomson production, and more rapid production of Prudhoe Bay. The low The low incremental cost of natural gas from Prudhoe Bay should mean that production and sale of these volumes should mean that production and sale of these would be very profitable to the Major volumes would be very profitable to the Major | North Slope Producers and would incremental cost of natural gas from Prudhoe Bay justify construction of a pipeline to deliver North Slope gas to market even construction of a pipeline to deliver North Slope | in the absence of the other volumes expected to be available. North Slope Producers and would justify gas to market even in the absence of the other volumes expected to be available. This is detailed fully in later sections summarizing the NPV to each of the major stakeholders (Appendix G1, Section 5.6). g. Estimated Pipeline and GTP Costs, Schedule, and Tariffs Overview Pipeline and GTP tariffs are a key determinant of the state’s overall NPV from the project. As the tariff or transportation rate rises (which is based on the cost of the Project), the value upon which royalty and production taxes are based falls. Accordingly, the state focused extensively on developing an independent understanding of the future costs of the pipeline and GTP. The state did not rely on TC Alaska’s assessment, as presented in its Application, of the Project's cost and schedule (Application 2007, Section 2.5). Doing so would have failed to address the risk that TC Alaska’s assessment might be incorrect. Just as with future prices, future costs cannot be known with certainty. Accordingly, the state particularly focused on developing a detailed understanding of the probable range and relatively likelihood of future cost outcomes. There are two key types of uncertainty that affect future costs of the Project. The first is Project “scope uncertainty.” That is, there is currently an imperfect understanding of all of the details of exactly what will be constructed and how it will be constructed. Until those details are resolved it is impossible to develop a fully refined understanding of what the project may cost. In general, as more field work, detailed engineering, and procurement planning are performed, scope uncertainty diminishes. The second type of uncertainty is cost “escalation uncertainty.” That is, even if project scope could be perfectly understood today, there remains considerable uncertainty as to what it will 27 MAY 2008 3-44 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination cost to build the project being contemplated. Actual procurement—whereupon actual costs of various portions of the project get established—will not begin for at least five and a half years and is more likely to start six and a half years from now. (Application 2007, Section 2.6) Predicting the cost of steel, labor, and other critical inputs into the cost of Project construction that far into the future is exceedingly difficult. To separate the effects and importance of “scope” from “escalation” uncertainty, the AGIA RFA asked applicants to submit costs in 2007 dollars. In essence, TC Alaska’s Project cost estimate reflects its current understanding of project scope. By stripping out uncertainty as to future costs of steel, labor, and the like, TC Alaska’s cost estimate could be critically reviewed and assessed for scope uncertainty. As discussed in detail in the next section, TC Alaska’s cost estimate was subject to a thorough due diligence review by the state. Recognizing that all cost estimates used for planning purposes should be both realistic and aggressive—if they are not aggressive, then there is no hope of achieving a favorable outcome in practice—the state endeavored to develop a detailed understanding of the risks of costs differing from those used in planning. Accordingly, the state directed its Technical Team to develop probability distributions of project costs, as expressed in current dollars. The eventual GTP and pipeline cost estimates, which determine eventual GTP and pipeline tariff estimates, were established by escalating the current dollar (scope) cost estimates by an escalation rate. In NPV model runs the base case escalation rate is 4% per year. Additional sensitivities of 2% and 6% were also considered. Although cost increases in the industry have climbed much faster than 4% for the last few years, on balance we believe that this trend is unlikely to continue. Over the last twenty five years, the pipeline escalation rate has averaged about 3.6% per year (Appendix F, Section 2.1.5). Pipeline capital costs are currently above the historical trend line, which suggests that a continuing acceleration of costs is unlikely to be sustained. (Appendix F, Section 2.1.5). In current dollars, reflecting the base-case escalation rate of 4% per year, the mid-range cost estimate for the Proposal Base Case is a little more than $31 billion; the mid-range cost estimate for the Conservative Base Case is about $29 billion (Appendix F, Exhibit D). If the project could be built today the tariffs would be $3.19 and $3.59 for the two respective Base Cases. After accounting for annual cost escalation of 4%, the final project costs for money as 2 Appendix F (Tech Team), Section 2.1.5, provides support for why these escalation rates are reasonable. 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination spent will be $45 billion for the Proposal Base Case, and $42 billion for the Conservative Base Case. As noted earlier, these figures translate to tariffs if $4.73 and $5.33 for the Proposal Base and Conservative Base Cases, respectively (Appendix G1, Section 6.4.1). Under each of the price projections discussed earlier, including conservative Black and Veatch pricing scenarios, the Project provides significantly positive net backs. The following discussion summarizes our assessment—both the method of investigation and the study results—of Project cost and schedule risk, as expressed in probability distributions.** h. Pipeline Cost and Schedule Analysis, Including Cost and Schedule Ranges Current-dollar Cost Ranges: Scope Risk. To assess Project Cost risk the state did not rely on TC Alaska’s cost estimate, but rather developed an independent assessment of Project Scope risk. TC Alaska’s cost estimate can be located as one possible outcome along the range of possible project cost outcomes.“* Separate probability distributions for each major subproject— GTP, Alaska pipeline segment, Canadian pipeline segment—were developed for both the development phase and the execution phase. A complex, multi-step process was used to develop the probability distributions. This process is depicted on the following chart (Figure 3- 20): ‘8 More detailed treatment of the topic is provided in Appendix F. “ TransCanada's total estimated cost for the Project is approximately $25.8 billion, including $20 billion for the pipeline facilities and $5.8 billion for the GTP. See Application at 2.5-2. TransCanada also included total cost estimates for its proposed project at the “sub-project” level (i.e., Gas Treatment Plant, Alaska Pipeline Segment and Canadian Pipeline Segment). In response to information requests, TransCanada provided a more detailed breakout of pipeline development phase costs and pipeline execution phase costs by subproject, and more detail to distinguish between pipeline and compression costs during the Development Phase and the Execution Phase of the Project. (See TransCanada’s responses to data requests dated December 11, 2007, January 15 and January 24, 2008). The more detailed cost estimates became the starting point for the cost analysis. 27 MAY 2008 3-46 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-20. Subproject Component Cost Ranges—Derivation Process Biche lar ler] CA emt S ela) Base Cost $ elie ey Adjustments Ranging Los Tera |R1 R1 | R1 . R2 Final | R3 ¥ Source: Westney 2008, Appendix F, Section 3.2.2 The Technical Team first divided each subproject into a number of major cost components. Major components of the Alaska pipeline subproject, for example, include Major Equipment and Materials, Installation, and Owners Costs (Appendix F, Table 1). For each subproject component a “base case” cost estimate was developed. The “base case” was determined with reference both to TC Alaska’s estimate for the subproject component cost and to an independent cost estimate developed by the state’s Technical Team (Appendix F, Section DA) ee In some cases, the TC Alaska estimates were used to set the “base case” for the simple reason that TC Alaska’s estimates, if generally validated by the independent estimate, reflected TransCanada’s years of experience studying this project and dealing with large diameter, high- pressure gas pipelines in near-arctic conditions (Appendix F, Section 2.1). The “base cases” became anchors for estimating “best” and “worst” case outcomes for each subproject cost component. (Appendix F, Section 2.1). The “best” case is the lowest value that + In its application TC Alaska stated it preferred not to develop, own, or operate the GTP (an option permitted under RFA Section 2.1.2), but that it would do so if necessary. Application at 3.2.1-12. The Application nonetheless contained a conceptual design and description of the GTP plant and an overall cost estimate of $5 billion. Application at 2.1-12. Because TC Alaska provided relatively limited cost and schedule details concerning the GTP the “base” cases for GTP costs were primarily developed by Westney Consulting and Black and Veatch Engineering; (Appendix F, Section 2.1.1 and Appendix F, Exhibits B and J). The cost estimates were not based on a complete simulated GTP design, but were sufficient to provide a basis to make informed judgments as to cost and timing. Appendix F, Section 3.2.1 contains a detailed discussion surrounding the basis for GTP design adopted here. 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination each subproject component could reasonably be expected to attain. In essence, the “best” case reflects the lowest cost assuming “everything generally would go right”; there is about a 5% probability that the actual cost would be even lower than the “best” case. The “worst” case is similarly defined in terms of virtually nothing “going right”; there is about a 5% probability that the actual cost would be even higher than the “worst” case. Each subproject component “base,” “best,” and “worst” case determination was made by subject matter experts (SMEs) using a facilitated consensus process (Appendix F, Section 2.1.4). The determinations, along with the rationales underlying these determinations, are discussed in Appendix F, Exhibit B. These cost ranges represent the reasonable bounds of outcomes associated with each subproject cost component. Once the foregoing cost ranges were established, appropriate probability distributions to characterize the relative likelihood of different outcomes within each range were selected.*° Each of these probability distributions over each cost range for each subproject component was then used in a Monte Carlo simulation to develop a probability distribution for cost outcomes for the full subproject.*” Monte Carlo simulation is a well- established method for probabilistic analysis, and a widely-used technique for predicting the likely range of outcomes for the cost and schedule of a construction project. Westney has developed and used variations of this technique for the past 30 years. A number of federal agencies and offices rely on the Monte Carlo simulation method as an analytical tool in a variety of circumstances, and view it as a valid methodological tool.** The results of the Monte Carlo ‘6 A Minimum Extreme Distribution (right skewed) was used for the GTP because the GTP will be the largest gas treatment plant ever built and there are larger than normal risks associated with installation on the North Slope. A Maximum Extreme Distribution (left skewed) was used for the pipelines because it better matches historical estimates when a project is well defined by significant study and years of preliminary design. The normal “bell shaped” curve was used for the LNG Plant study because the costs used in the LNG study were based on historic projects with very wide cost ranges that were built over the past several years and were geographically spread around the world. (Appendix F, Section 2.1.4) 47 In Monte Carlo simulation a computer selects at random one of the cost estimates contained in each of the subproject component ranges. The software then calculates the total cost that would result from that particular combination of subproject component costs. The process is then repeated thousands of times (10,000 iterations being standard practice) to produce an entire probability distribution, composed of the thousands of run results, for the total subproject cost. 4 For example, the federal government's Government Accountability Office (the audit arm of Congress) and the executive branch Office of Management and Budget each view the Monte Carlo method as a valid methodology and employ it as an analytical tool in a broad array of circumstances. See GAO-06-823 (Washington, D.C., July 27, 2006) and OMB Circular Q-4. Other agencies which rely on the Monte Carlo method include: (1) the National Aeronautics and Space Administration (NASA), which has a Cost Estimating Handbook that calls for Monte Carlo simulation in cost estimating; and (2) the Federal Aviation Administration, which has a “Standard Benefits Analysis Methodology Final Guideline” (approved November 22, 2002) that recommends Monte Carlo simulation as an analytical tool as part of a complete cost estimate analysis—specifically to develop a statistical distribution of costs for various project elements and to compute the statistically-derived risk-adjusted constant dollars based on randomized parameters according to a range specified by an analyst as is done in the Westney model. In addition, the Department of 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination simulations, reflecting project scope pipeline cost risk, are presented in Figure 3-21. In current dollars, the Alaska pipeline subproject cost estimates ranged from roughly $8 billion to $12 billion for a 4.5 Bcf/day project, with a midpoint probability of $10.5 billion (Appendix F, Exhibit D; note that this and subsequent cost distributions, shown below, are Execution Phase costs only and do not include costs from the Development Phase). This compares with TC Alaska’s estimate of $9.8 billion for the Alaska pipeline segment (Application 2007, Section 2.5.2). Figure 3-21. Proposal Base Case Cost Distribution—Alaska Pipeline AGIA TransCanada Application - Base Case Cost-Risk Profile for Base Case: 4.50 bcfd Alaska Pipeline = 7 Source: Westney 2008; Appendix F, Exhibit D Energy's Los Alamos National Laboratory cites applications of Monte Carlo methods to: cancer therapy; traffic flow; Dow-Jones forecasting; oil well exploration; stellar evolution reactor design; quantum chromo-dynamics; modeling of materials and chemicals; grain growth modeling in metallic alloys; behavior of nanostructures and polymers; and protein structure predictions. See Kindinger, “Use of Probabilistic Cost and Schedule Analysis Results for Project Budgeting and Contingency Analysis at Los Alamos National Laboratory” Los Alamos National Laboratory, 1999. In addition to the examples listed above, numerous Federal Register notices cite to the Monte Carlo method used by many Federal agencies, including the Environmental Protection Agency, the Department of Homeland Security, and the Board of Governors of the Federal Reserve. See, e.g. ,65 FR 7550 (Environmental Protection Agency), 73 FR 18384 (Department of Homeland Security), and 71 FR 55,958 (Board of Governors of the Federal Reserve). . 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-22. Proposal Base Case Cost Distribution—Yukon-BC Pipeline @ AGIA TransCanada Application - Base Case Cost-Risk Profile for Base Case: 4.50 bcfd Yukon-BC Pipeline i @ The Yukon-BC pipeline subproject cost estimate ranges from roughly $9.5 to $14 billion, with a midpoint probability of $12.4 billion (Appendix F, Exhibit D). This compares with TC Alaska’s estimate of $9.1 billion for the Yukon-BC pipeline segment (Application 2007, Section 2.5.2). Source: Westney 2008; Appendix F, Exhibit D The GTP subproject cost estimate ranges from roughly $3 to $10.5 billion, with a midpoint probability of $8.2 billion. This compares with TC Alaska’s estimate of $5.7 billion for the GTP (Application 2007, Section 2.5.2). While the cost range for the GTP is broad, estimating the cost of the GTP is particularly difficult in light of the numerous factors involved in designing, fabricating, transporting and installing the plant on the North Slope (Appendix F). Accordingly, the Technical Team's cost range prudently recognizes the possibility that costs for the GTP could increase significantly. 27 MAY 2008 3-50 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-23. Proposal Base Case Cost Distribution - GTP AGIA TransCanada Application - Base Case ior Base Case Cost-Risk Profile 11,000 12,000 Source: Westney 2008; Appendix F, Exhibit D Although the cost ranging for the GTP substantially relied on the state’s own assessment of costs, the range appears reasonably supported by two recent, independent estimates. First, ConocoPhillips has recently indicated that it has done significant work on the design of the GTP, and has indicated a cost range of $4 to $6 billion (2007 dollars) for an outlet capacity of 4 Bcf/day and an inlet capacity of 4.5 Bcf/day.*° Second, in a 2006 study done for the Alaska Department of Revenue, Petroleum Finance Corporation (PFC Energy) analyzed work done by Bechtel Corporation concerning the 3.8 Bcf/day outlet (4.3 Bcfiday inlet) plant proposed by the Port Authority to supply an LNG project. Bechtel estimated the cost of the GTP to be $5.1 billion (PFC Energy 2006). Converting these values into 2007 dollars for the present analysis and bee ConocoPhillips Company, Proposal to the State of Alaska, at Section III, pages 1-4 (November 30, 2007) 27 MAY 2008 3-51 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination adjusting them for published upstream capital cost escalation factors results in a $6.5 billion cost, which is less than the midpoint assumed by the Technical Team. Overall, for the reasons summarized above and detailed in the Technical Team report (Appendix F), the GTP cost range provides a reasonable estimate for purposes of analyzing the TC Alaska proposal and assessing the NPV, and its uncertainty, to the state. When considering the sum of all project subcomponents, and including the uncertainty associated with the development stage of the project, in current-day collars the project scope risk for the project's execution phase is summarized by the Figure 3-24, below. Figure 3-24. Proposal Base Case Cost Distribution—integrated Project AGIA TransCanada Application - Base Case Cost-Risk Profile for Base Case: 4.50 befd integrated Project Source: Westney 2008, Appendix F, Exhibit D The integrated project cost ranges from roughly $23 to $35 billion, with a midpoint probability of roughly $31.5 billion (Appendix F, Exhibit D). This is roughly 25% greater than TC Alaska’s integrated project cost estimate of $25.1 billion (Application 2007, Section 2.5.1). This reflects 27 MAY 2008 3-52 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination the fact that the Technical Team, rather than accepting TC Alaska’s cost estimates, independently analyzed those cost estimates and increased them where appropriate based on the Technical Team’s experience and the objective evidence available to the Team.°° Given the foregoing, the likelihood seems small that TC Alaska will achieve its Application project cost estimate. However, this conclusion should be tempered in that these probability distributions were developed assuming a pipeline operator of neutral competence. To the extent that the operator does a good job anticipating, planning for, and working to mitigate project risks, the probability distributions will tend to skew to the left (there will be more likelihood of achieving lower-cost outcomes than illustrated here). As discussed below, TransCanada is an excellent pipeline operator. Accordingly, we expect that, on balance, the probability distributions that best describe likely outcomes are somewhat more favorable than what is presented here. However, no attempt was made in any of the NPV analysis to quantitatively adjust the probability distributions to reflect this. As well, it should be stressed that we believe Cost estimates used for planning purposes should be both realistic and aggressive. If one for this stage of project planning, if unlikely | they are not aggressive, then there is no to be realized. Cost estimates used for planning | ope of achieving a favorable outcome in isi practice. The commissioners believe that purposes should be both realistic and | tc alaska’s estimate is realistically that TC Alaska’s cost estimate is an appropriate aggressive. If they are not aggressive, then aggressive. there is no hope of achieving a favorable outcome in practice. As described in the Technical Team’s report, we believe that TC Alaska’s estimate is realistically aggressive (Appendix F, Section 3.5). 5° The P95 cost estimate is approximately 40% more than TC Alaska’s estimated Project cost, similar to the cost overrun scenario outlined in Exxon’s comments. Compare Appendix F, Exhibit D with Exxon’s Comments at 3.11. 27 MAY 2008 3-53 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination i. Nominal Dollar Cost Ranges and Tariffs: Escalation Risk The cost probability distributions discussed in the previous section indicate the risks associated with project scope. There is also cost risk associated with cost escalation. Assuming a 4% annual escalation rate, the integrated project cost ranges from roughly $35 to $55 billion, with a midpoint probability of roughly $45 billion (Appendix F). Put differently, this cost range reflects the actual money that may be spent on the project by the time it goes into service, over ten years from now. If the escalation rate is 6%, such that pipeline construction costs in the next ten years exceed the annual rate of the last ten years (Appendix F, Section 2.1.5), then the project costs will be greater and the cost range will be wider. The integrated project cost ranges from roughly $45 to $65 billion, with a midpoint probability of roughly $54 billion (Figure 3-25). Figure 3-25. Project Cost Risk: Comparing Project Escalation with Project Scope Risks Showing Cost Uncertainty and Risk Increasing With Escalation Rates 100% a — : ——4% CapEx Inflation / 90% == ‘0% CapEx Inflation : = = 2%CapExinflation / 80% == '6% CapEx Inflation | mse | = Soon ee B 50% os s | ° a 40% + -- , j 30% wens - { \ 4% CapEx 0% CapEx 2% CapEx 6% CapEx | 20% Inflation Inflation Inflation Inflation 4.5 AECO $45.2 $30.8 $37.4 $54.4 10% - : a ant aa # ¢ ° 0% a ae en _ = $10 $20 $30 $40 $50 $60 $70 $2008 Billions Source: Black and Veatch, Appendix G1, Appendix C 27 MAY 2008 3-54 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Schedule Risk In addition to the cost ranges, the Technical Team also established an estimate of ranges for when the Project would be built, because the time at which the Project is completed is a significant factor in determining the NPV for the project. In an NPV analysis, a dollar in hand now is worth more than a dollar ten years from now. Thus, to determine the Project’s NPV, it is important to determine not only how much the Project will cost, but when the Project will commence service and begin to generate revenues.*" In order to estimate schedule ranges the Technical Team reviewed TC Alaska’s proposed timeline and, as in the case of the cost ranges discussed above, worked with AMEC and Mustang to develop an estimate of probable ranges for completion of various aspects of the Project. As with the development of the cost estimate, the Technical Team independently estimated the schedule range for the “Best Duration” and “Worst Duration” (P95 best case and P5 worst case) that each activity might involve. These activities included construction, procurement, permitting, engineering and design activities. A duration range for each activity was developed (Appendix F, Exhibit C) and used in Monte Carlo simulations. The process used to derive these schedule ranges, and the results of that process, are discussed in detail in the Technical Team’s Report (Appendix F, Sections 2.1.2 and Section 3.3). As it turns out, the GTP schedule plays a key role in the overall project timing. GTP construction is a function of the time from order placement to North Slope delivery of the large gas treating modules. As discussed in the Technical Team report (Appendix F), fabrication, delivery to the North Slope and assembly of the GTP on the North Slope is a complex process that will require at least two summer seasons to accommodate two sea-lifts. TC Alaska has stated in its application that it would not make final procurement commitments for materials until the FERC permit and a Decision to Proceed was final (Application 2007, Section 2.1.2). This would set the ordering of the vessels no earlier than the end of November 2013 with the first sealift for North Slope delivery occurring no earlier than September 2016 51 The NPV of a project is the difference between the sum of the discounted cash flows which are expected from the investment and the amount which is initially invested. If the NPV results in a positive amount, the company should pursue the project. Net Present Value is an economic calculation used to appraise the financial value of long-term projects. An NPV calculation figures the present value of an investment that may generate returns for many years; in short, the AGIA NPV calculation allows us to understand, in terms of today’s money, the profits (or losses) that an AGIA Application offers the state. 27 MAY 2008 3-55 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination (Appendix F, Exhibit C). The second sealift would be landed in September the following year, or 2017 (Appendix F, Exhibit C). This would allow for earliest delivery of first gas, at one-half capacity (2.25 Bcf/d), to the pipeline inlet in November 2017 and the earliest final full volume (4.5 Becf/d) to the pipeline inlet in June 2018 (Appendix F, Exhibit C). The Technical Team estimates TC Alaska’s project will likely commence service between the middle of 2018 and the beginning of 2022, with 2020 as the midpoint estimate (Appendix F, Exhibit D). Spend Curve Estimates for Project Costs The Project's pipeline and GTP tariffs will reflect the returns to capital that investors require. Accordingly, to develop pipeline and GTP tariffs, it is necessary to know when in the process the dollars will be spent to develop and construct each subproject so that these returns can be appropriately calculated. The Technical Team used TC Alaska’s estimate of the likely timing of its expenditures on a year-to-year basis as a basis for developing reasonable schedules for yearly capital expenditures. (Appendix F, Section 3.2.3). These schedules were then converted from a “dollar per year’ basis to a “percentage of cost per duration” basis, so that spend schedules could be developed for the joint ranges of cost and duration schedules discussed previously (Appendix F, Section 3.2.3). Tariff Rates, Based on Estimated Project Costs and Schedules Estimating a net back price is a prerequisite to estimating the royalties and production taxes the state would receive as a result of the Project; that is, the price of the gas at the AECO Hub less the transportation cost or tariff. The net back price serves as the basis for calculating the state’s royalties and production taxes. In broad terms, a distribution of net back prices was determined by translating the full range of project cost estimates into a similar range of unit rate “costs of service,” or tariffs. These were then subtracted from the projected AECO Hub natural gas price. Combined with the distribution of prices, then, the distribution of tariffs is key. Under the Proposal Base Case, which has significantly greater throughput for a relatively minor increase in corresponding costs, the distribution of project tariffs is presented below. Under the Conservative Base Case project costs are slightly lower but this is overcome by the significantly smaller throughput, leading to a generally greater per unit cost (or tariff). 27 MAY 2008 3-56 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination © Figure 3-26. Tariff Distributions by Project Throughput: Smaller Projects Give Higher Tariffs 100% 7— ~ 1 ov — 3.5 Befld Low Volume Sensitivity Case ~~~ 4.0 Bcfid Conservative Base Case 7 80% 1 = = 4.5 Bcfid Proposal Base Case ' : 70% . ' a ‘ SZ comt ee - e223 2 . ; I B 50% + ees a = La doe. 8 ; ' : 2 ee ' a 40% oo 1 t 1 ' 30% + - wee ee cine eee 2 a L-- “+ loa = ~--4---------- ; : 20% . : 4.5 Case 4.0Case 3.5 Case ' Tariff Expected Value ‘ (Based on WM Prices): $473 aos #571 10% - =o = See = a 7 - - p= = j ¢ / i im ' ° — \ \ $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 @ $/MMBtu Source: Black and Veatch, Appendix F, Appendix C The conversion of these project cost estimates into a tariff rate is discussed in detail at Appendix G1. To summarize briefly, however, a pipeline’s tariff rate is the sum of four basic components: (1) operating expenses; (2) return on rate base (i.e., a return on the pipeline’s capital expenses as approved by FERC); (3) income and other taxes; and (4) depreciation expense.*? Components (2), (3), and (4), above, are directly affected by the project’s capital costs, discussed above (Appendix G1, Section 3.7). The NPV model incorporated the Technical Team’s estimate of Project operating expenses. The Technical Team's estimate was derived from TC Alaska’s estimated operating expenses, independent estimates of those expenses, and by reference to actual operating expenses on several major interstate natural gas pipelines (Appendix F, Section 2.1.5 and Appendix J). 2 See, e.g., Schneider, Steven, Natural Gas Pipeline Regulation and its Impact on Value (1997) at: http://law.honigman.com/db30/cgi-bin/pubs/Schneidera67602.pdf. 27 MAY 2008 3-57 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination The second component, return on rate base, reflects a return on capital expenses (both equity and debt). The NPV analysis took the previously-discussed ranges of capital costs and calculated the return on rate base by applying a 14% return on equity to the 25% equity portion of the Project rate base, and a 7.06% debt cost to the 75% debt portion of the Project rate base, to determine the total return on rate base (Appendix G1, Section 5.7.2). The NPV model applied appropriate federal and state tax rates for income and other taxes to derive an estimate of the taxes FERC (and the NEB) would allow to be recovered by the Project in tariff rates. Because income taxes are affected by pipeline income (or return, see above), the Project's capital cost indirectly affects income tax costs (Appendix G1, Section 3.7). Finally, the NPV model calculates the annual depreciation expense, or an allowance for the return of capital to investors, by multiplying the rate base by the depreciation rate derived from the proposed 25-year Project life. The Commercial Team thus used a 4% depreciation rate, which would be necessary to fully depreciate the Project rate base over 25 years under the Proposal Base Case. For the calculation of state and federal income taxes the NPV model uses tax depreciation rates based on a tax life of 7 years for the Alaska pipeline sections and a tax life of 15 years for the GTP plant or a rate of 14.3% and 6.6% respectively (Appendix G1, Section 3.7.2).°° In simplified terms, the sum of these four rate components was then divided by the projected billing determinants of 4.5 Bcf/day to determine the projected tariff rate, which was calculated on a levelized basis (i.e., the rate does not change over the 25 years of the project). For the Proposal Base Case, in 2008 dollars, the projected tariff rate (assuming a 25-year project life and firm contracts with a term of 25 years) is approximately $3.19. After accounting for escalation in construction costs, the midpoint likely tariff in 2020 would be approximately $4.73 (Appendix G1, Section 5). This estimated rate is well below each of the natural gas price projections used in the analysis. The Project appears likely to produce positive net backs for the Major North Slope Producers and other producers, as well as significant cash flow and a positive NPV for the state. In addition, it should be recognized that while FERC requires all pipelines to have a tariff rate (also known as the recourse rate), most major new projects enter into negotiated rate contracts 88 Although the BandV report states that Federal Tax Life was set at 7 years, the NPV model does use a 15 year Tax Life for the GTP. 27 MAY 2008 3-58 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination with their major shippers.°* These negotiated rate contracts typically are lower than the recourse rate (Appendix J, Section 1). Thus, it is to be expected that TC Alaska and the Major North Slope Producers would enter into negotiated rate contracts. Due to the bargaining power of the Major North Slope Producers, the negotiated rates would probably be lower than the FERC-approved tariff rate. To the extent TC Alaska and the Major North Slope Producers negotiate rates which are less than the tariff rates modeled here, the net back, cash flow and NPV produced by the Project would be even higher than if Major North Slope Producers were to pay the recourse tariff rate. That is because, in conjunction with the earlier explanation of net back pricing, lower tariff rates produce a higher net back, which means higher state tax and royalty revenues. In addition, the estimated rates may be conservative because two elements of the tariff rate may be overstated. First, TC Alaska’s return on equity may be reduced below 14% once the Project has been constructed and in the event TC Alaska files a rate case with FERC.®° FERC policy generally allows a new pipeline a higher return on equity than an existing pipeline, in view of the higher risks faced by a new pipeline.®© For purposes of this analysis, the Commercial Team conservatively assumed TC Alaska will receive a 14% return on equity throughout the 25-year Project life. A reduction in this return on equity would reduce the tariff rate and increase the net back, cash flow and NPV produced by the Project (assuming shippers pay the tariff rate instead of negotiated rates).°” The second rate component which may be overstated, also resulting in an understatement of the net backs, cash flow and NPV that the Project would likely produce to the state, is depreciation expense. A key factor in determining a pipeline’s rates is the depreciable life of the project. If a longer depreciable life is used to calculate rates, then the costs of the project can be recovered and spread over a longer time period, resulting in lower rates than if a shorter time * See, e.g., Rockies Express Pipeline, LLC Application at 26; Appendix A of sample precedent agreement between Rockies Express Pipeline, LLC and shipper at: http://www. kindermorgan.com/business/gas_pipelines/rockies_express/rex_docs.cfm (December 17, 2005). 55 In this regard, TransCanada proposed (but did not require as a condition of its Application) to charge a return on equity of 965 basis points above the U.S. 10-year Treasury Note, to be reset annually. As discussed in Appendix G1, this proposal may not be accepted by FERC. See Application at Section 2.2.3.7(1). 58 Alliance Pipeline, L.P., Preliminary Determination of Non-Environmental Issues, 80 FERC ¥] 61,149 (1997). 57 In addition, a 14% equity return is significantly higher than the equity returns typically approved by the NEB, according to the state’s Canadian legal counsel. Thus, this assumption may understate the NPV of the Project to the state (because it reduces the net back price used to determine state royalty and production tax revenues). 27 MAY 2008 3-59 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination period is used, all other factors being equal. Conversely, the use of a shorter depreciable life for ratemaking purposes results in higher rates, but reduces the pipeline’s risk of cost recovery somewhat because the pipeline will not bear the risk of finding firm shippers for its capacity over a longer time period. TC Alaska has proposed to use a 25-year depreciable life for ratemaking purposes. Application at 13, 2.2-65. While TC Alaska’s proposed 25-year Project life can be questioned, it is not unreasonable by industry and FERC standards. For example, when Kern River Gas Transmission Company constructed a major new pipeline from the Rockies to California in the early 1990s, Kern River proposed and FERC approved the use of a 25-year depreciable life for use in calculating Kern River's initial rates. Other pipelines have also proposed, and received FERC approval of, 25-year depreciable lives for ratemaking purposes.°? A number of other pipelines, however, have proposed longer depreciable lives, which also have been approved by FERC. For example, FERC recently approved the 35-year depreciable life proposed by Rockies Express. Numerous other similar examples also exist.©° Moreover, in pipeline rate proceedings at FERC (which traditionally have not occurred until several years after the pipeline’s in-service date), FERC typically requires pipelines to use a depreciable life of longer than 25 years, based on an assessment of the natural gas reserves available to be transported by the pipeline and other factors®’. For example, in Kern River's recent rate case, FERC required Kern River to use a 35-year depreciable life, instead of the 25-year depreciable life on which Kern River based its initial project rates. Recent estimates have indicated that the recoverable natural gas reserves on Alaska’s North Slope significantly exceed prior estimates. Indeed, the Alaska Gas Study discussed above indicates that there are economically recoverable reserves available to fill the capacity of the Project for decades. (NETL 2007, pp. vii-ix, 22-23) Accordingly, in a future rate proceeding 58 See Kern River Gas Transmission Co., 50 FERC 7 61,069 (1990). 58 See, e.g., AES Ocean Express, LLC, 103 FERC {| 61,030 (2003); Mojave Pipeline Co., 58 FERC {| 61,074 (1992); Wyoming-California Pipeline Co., 50 FERC {| 61,070 (1990). ® See, e.g., Colorado Interstate Gas Co., 122 FERC J 61,256 (2008); Entrega Gas Pipeline, Inc., 112 FERC J] 61,177 (2005); Kinder Morgan North Texas Pipeline, L.P., 111 FERC {| 61,439 (2005). e See, e.g., Williston Basin Interstate Pipeline Co., 104 FERC {| 61,036 (2003), order on reh’g, 107 FERC {] 61,164, at PP 21-52 (2004); Iroquois Gas Transmission System, L.P., 86 FERC {| 61,261 (1999). ® Kern River Gas Transmission Co., 117 FERC {| 61,077 (2006). 27 MAY 2008 3-60 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination FERC may require TC Alaska to use a depreciable life of more than 25 years for ratemaking purposes. If that occurs, then (all other factors being equal) TC Alaska’s tariff rates would decrease, the net back price would increase, and the royalty and tax revenue which the state will derive as a result of the Project would increase, thus increasing the NPV to the state. Accordingly, from an NPV perspective, because FERC may require the use of a longer depreciable life in the future, the use of TC Alaska’s proposed 25-year depreciable life to calculate the Project's rates results in a conservative assessment of the likely NPV the Project would produce for the state. j. Upstream Costs The costs of production have three effects on state NPV. First, capital expenditures end up being subject to state and local property tax. Second, capital expenditures affect producer property balances, which in turn affect state corporate income tax. Finally, upstream capital and operating costs are deductible from production taxes, and capital costs can be eligible for investment tax credits. A detailed explanation of how upstream costs are modeled can be found at Appendix G1, Section 3.8. 3. Estimated NPV Produced by the Project—Results of the NPV Analysis In the prior sections of this Chapter, we have explained the fundamental elements of our NPV analysis, including projected natural gas prices, Project costs and tariffs, and volumes to be produced and transported through the Project. This section summarizes the results of the NPV analysis for the 4.5 Bcf/d-capacity Proposal and 4.0 Bcf/d-capacity Conservative Base Cases, as well as results of various sensitivities (e.g. prices, volumes, tariff terms) off those cases. The evidence, as discussed in more detail in the Commercial Team report, demonstrates that the state, the Major North Slope Producers, and TC Alaska would each realize a very significant NPV from the Project under both the Proposal and Conservative Base Cases. Indeed, the Project presents an economically attractive opportunity for the state, for the Major North Slope Producers, and for TC Alaska under a range of volume scenarios, and under a variety of different, sometimes very conservative assumptions regarding natural gas prices, costs and other factors. ®3 An increase in the depreciable life from 25 years to 35 years would reduce the tariff rate by approximately 27 MAY 2008 3-61 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination a. Estimated NPV under the Proposal Base Case Under the Proposal Base Case set of assumptions (which will be summarized shortly), the Project would produce the following results: e The State of Alaska would realize an estimated NPV of approximately $66 billion at a discount rate of 5%. ¢ The Major North Slope Producers would realize an estimated NPV of $13.5 billion at a discount rate of 10%, and an NPV of approximately $5.2 billion at a discount rate of 15%. Like TC Alaska, Producer NPV would be significantly higher if the same 5% discount rate were used to calculate their NPV. Higher discount rates are appropriate for the Producers, however, to reflect the higher rate of return they generally demand before proceeding with a project. The Producers would also realize extremely high internal rates of return from the production and sale of gas from Prudhoe Bay and other state existing fields,“ and economic returns from the production and sale of Point Thomson and Yet-to-find (YTF) gas.® e TC Alaska would realize an NPV of $4.5 billion at a discount rate of 8.8%. TC Alaska’s discount rate was set at its assumed weighted average cost of capital for the Project. For a given equivalent net cash flow TC Alaska’s NPV will be lower than the state’s, because its discount rate is greater. For discussion see Section C.1 of this Chapter. These results are derived from the Proposal Base Case set of assumptions, which include the following: $0.20/MMBtu and increase the net back price by a corresponding amount. ® Not too much should be made of exceedingly high rates internal rates of return (IRR) for gas produced from these fields. IRRs much above 30% cease to be very meaningful. The math embedded in the IRR calculation implicitly assumes that revenue from an investment can be reinvested at that rate; however, there simply are not many opportunities to earn returns at this level. Moreover, once a project's internal rate of return meets a company’s hurdle rate it is unlikely to be used as an important determinant of investment choices. (Finizza, 2006). Note that IRRs drop dramatically if one were to treat firm transportation commitments as a capitalized investment. We do not believe that this is the proper way to consider or calculate IRRs. However, we acknowledge that there is controversy on the subject. Accordingly, we do not focus particularly, nor base our findings, upon the IRR results. The controversy surrounding how IRR “should” be calculated with regard to shipping commitments is largely a sideshow. The main emphasis properly belongs on project NPV, which is the primary measure for whether the project will add value to the company (Finizza, 2006). As it happens, Producer NPV is fairly insensitive to whether shipping commitments are capitalized. (See Appendix F.1, Section 6.8 for discussion and results; capitalizing the shipping commitment yields investment measures similar to those that are obtained when the Producers are assumed to own the pipeline.) ®5 See Appendix K for discussion of the relative acceptability of project economics of YTF gas. 27 MAY 2008 3-62 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination e Natural gas prices: We relied on a gas price forecast supplied by the well-respected Wood Mackenzie consulting firm, a firm that has done work for numerous companies in the natural gas industry, including the Major North Slope Producers. We also considered price forecasts prepared by the EIA and Black and Veatch. e Production scenarios: As a variation to the Proposal Base Case, we assessed Project returns assuming that initial volumes from Prudhoe Bay were 3.5 Bcf/day, state existing reserves came in initially at about 0.7 Bcf/day, and the remainder of the volumes is made up of YTF gas. Point Thomson gas does not enter the project in this sensitivity. Assessment of the extreme case in which Point Thomson gas does not enter the project at all is evaluated more fully under the Conservative Base Case. e Schedule: The midpoint probability schedule estimate, in which the Project would begin transporting gas in the year 2020. e Capital Cost: The midpoint probability cost estimate for the Project of approximately $31.3 billion in current or “real” dollars. e Costescalation: Capital costs for the Project escalate at an annual rate of 4%, and operating costs escalate at an annual rate of 3%. e Pipeline Interest Rate: The Project would rely on the Federal Loan Guarantee provided by the Alaska Natural Gas Pipeline Act, which results in a lower interest rate than would otherwise be the case. e Contract length and depreciation period: the Project would be depreciated over a 25- year period, shippers would sign 25-year firm shipping commitments, and pipeline tariffs would be levelized. In evaluating the NPV of the Project, sensitivity analysis was performed to analyze the effect of different factors on Project economics for the stakeholders, including the state, the Major North Slope Producers and TC Alaska. In a sensitivity analysis the relative importance of risk factors that can affect the NPV results for each stakeholder are assessed. A “Tornado Diagram” provides a tool to visually compare the results of different sensitivity cases at the same time. A tornado diagram essentially shows which factors have the largest estimated impact on NPV. A tornado diagram reflecting the main factors that can affect the NPV to the state is shown below (Figure 3-27). ® The assumption that is being varied in each bar of the tornado diagram chart is listed on the left-hand side under the ‘Sensitivity heading, while the list to the right of the chart describes what the base case assumption is for each sensitivity case. The x-axis gives the State of Alaska NPV value (in billions of dollars). The vertical line shown near the center of the chart is the base case NPV and is labeled ‘Base Case’ at the top of the chart. The bars to the right 27 MAY 2008 3-63 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-27. State NPV5 Tornado Diagram: The Relative Importance of Different Project Risks Base Case ae Sensitivity 1 Assumption 1 ' Wood Commodity Prices P10 P90 Mackenzie : : Prices ' ' Cost Escalation 6% Capex; 5% Opex ' ' ou , ' 1 1 1 ' ' ' Upstream Capital Costs | 100% Increase 50! : Base Case ‘ 1 ' 1 ' 1 i i i i Mean Capital TransCanada Capital Cost ; ; : ' ' 1 ' ' 1 1 ' ' ' ' ' Pipeline Interest Rate i i i 7.06% 1 1 1 1 1 ' ‘ ' ' TransCanada Schedule 1 ' ' 1 Base Case ' 1 ' ' ' ‘ \ 1 ' 1 ' 1 : \ ' ' PBU 3.0 Production Scenarios ' 1 ' PBU 3.5 BCF/d; No PT 1 BCF/d; PT ' ' ' Blowdown ' 1 ' 1 i t $- $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 $140.0 State NPVs ($Billion 2008) The left-hand side of each bar on the chart plots the low NPV result while the right-hand side of each bar plots the high NPV result. The factor shown at the top of the chart (natural gas prices) has the greatest impact on the Proposal Base Case results, while the factor at the bottom of the chart (pipeline interest rate) has the smallest impact. The results show the range of uncertainty evaluated for the State of Alaska NPV for a TC Alaska 4.5 Bcf/d pipeline to AECO Hub. The main points reflected in this Proposal Base Case tornado diagram are as follows: Qverall: The results show that for all sensitivity cases, the State of Alaska’s NPV remains substantial. In other words, even if a worst case scenario occurs for a single factor (such as gas prices), the Project would still generate a positive NPV assuming the other Proposal Base Case assumptions are correct. It would take a “perfect storm” of worst case scenarios from multiple and left of this base case NPV line show how much the base case NPV changes depending on the assumptions used. The labels found at the end of each bar describe what assumption is used to generate the results shown on the far left and right side of the bar chart. 27 MAY 2008 3-64 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination factors for the Project to be uneconomic. Indeed, as It would take a “perfect storm” discussed below, a “perfect storm” of low gas prices and of worst case scenarios for multiple factors for the Project to be uneconomic. Indeed, as generate negative state NPV. discussed below, a “perfect high construction costs, together, are not enough to storm” of low gas prices and Natural gas prices: The factor with by far the biggest | high construction costs, together, are not enough to generate negative state NPV. potential impact on the state’s NPV (and the Producers’ NPV) is the price of natural gas. However, as reflected in the diagram above, even in an extreme low price scenario (depicted above as the “P10” scenario, in which there is only 10% likelihood that prices will be at, or below, the very low price), the state NPV would still be approximately $20 billion over the life of the Project.®” Conversely, in an extreme high price scenario (P90), in which there is a 90% likelihood that prices will be at or below a very high level), the state NPV would swell to approximately $100 billion. As discussed earlier, the commissioners and the Commercial Team assessed Project economics under several different price scenarios. Under each pricing scenario, the Project has a positive estimated NPV in the aggregate over its 25-year life (Appendix G1, Figure 5-8). Figure 3-28. State NPV5 Sensitivity to Price State NPVs $140.0 ee eee $118.2 $120.0 $100.0 $80.0 $60.0 $ Billions (2008) $40.0 $20.0 Wood EIA 2008 BV Mean BVP10 BVP90 Mackenzie Source: Black and Veatch, Appendix G1, Section 6.6.1 §7 Note that while the Wood Mackenzie pricing projection is used to generate the Base Case result (represented by the blue line in the chart above), the P10 and P90 cases reflect the Black and Veatch assessment of price probabilities. The Wood Mackenzie and Black and Veatch approaches to price are explained in more detail earlier this Chapter, and in Appendix BandV, Section 4. 27 MAY 2008 3-65 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination In addition, while in the aggregate the state NPV is significant, even for very low prices, Project net backs appear to be quite robust even under low gas price scenarios that are quite unlikely. The following chart (Figure 3-29) shows the full range of Project forecast prices discussed above, including the average 2007 AECO Hub gas price, as compared with Proposal Base Case tariffs. Figue 3-29. | Comparing TC Alaska Pipeline Tariff (Nominal $) with Various AECO Price Forecasts $45.00 7— an a on | Nominal AECO Tariff $40.00 ; ——WoodMac AECO Price Forecast 5 —— EIA AECO Price Forecast 35.00 —— BV Base - ° $30.00 BY Pid ? ——~ BV P90 $25.00 $20.00 Nominal $/MMBtu $15.00 $10.00 $5.00 2020 2024 2028 2032 2036 2040 2044 Source: Black and Veatch; Appendix G1, Section 5.7.1.. Chart assumes Proposal Base Case tariffs As shown in this chart, net backs are positive for the EIA forecast, the Wood Mackenzie forecast, the Black and Veatch base forecast, and if the average AECO Hub price during 2007 were achieved. Indeed, under the Black and Veatch probability distribution of prices there is a 90% chance® that prices will be sufficient, in every single year of the project, to generate positive net backs. Thus, under Proposal Base Case assumptions net back risks appear modest. % The “PV P10” line shows that there is at most a 10% chance, for each and every year, that prices will be at or below that level. Put differently, the chance is 90% that prices will exceed that level. 27 MAY 2008 3-66 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Escalation in project costs: After natural gas prices, the factor with the next largest impact on the State’s NPV is the rate of Project cost escalation. As reflected in Figure 3-29, even if the costs of the inputs required to construct the Project (steel, labor, major construction equipment) were to increase at an annual rate of 6%—a rate that would in nominal dollars more than double project costs from today’s level by the in-service date—the state would still realize a very positive NPV. Interest Rate Risk: The Project is extremely capital intensive and will require several tens of billions of dollars in debt financing. The interest rate that must be paid on such debt has a large effect on the Project tariff. Indeed, the risk of rising interest rates may have a bigger effect on overall project returns than project scope or schedule risk (discussed below). Interest rates affect the Project much the same way as does capital cost escalation risk Capital Cost (or Project Scope) Risk: What the diagram refers to as “capital cost” risk has earlier been referred to as “Project scope risk.” Earlier sections of this Chapter explain that the Monte Carlo range of project costs, expressed in current-day dollars, reflects the cost uncertainty that is caused by less than complete project definition. The Tornado Diagram (Figure 3-25) shows that the NPV risk caused by Project scope uncertainty is relatively small. Indeed, the NPV risks associated with Project cost escalation dwarf the risks associated with Project scope.® Project scope risk also takes a back seat to interest rate risk. Production Scenarios: State NPV climbs if Point Thomson gas is displaced by Prudhoe Bay, other state existing, and YTF gas. Because Prudhoe Bay gas is especially profitable, flowing more of it, earlier, increases state NPVs. Schedule: Although they are large (potentially billions of dollars) in absolute terms, the risks associated with Project delay are comparatively small compared with the risks associated with price, cost escalation, and the level of upstream capital costs associated with YTF gas. The same risk factors that affect the NPV to the state also affect Producer NPV. The following tornado diagram shows the sensitivity of Producer NPV, as measured against the Proposal Base Case, to various risk factors. ® Recall that Project Scope risk — or “Capital Cost” risk in the diagram — is calculated assuming a 4% annual rate of cost escalation; the Project Escalation risk assumes the P50 cost estimate. 27 MAY 2008 3-67 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-30. | Producer NPV; Tornado Diagram: The Relative Importance of Different Project Risks Base Sensitivity pase Case Assumption 1 , ft Wood Commodity Prices | P10 P90 Mackenzie Prices 1 ' ' 1 ' ' Cost Escalati ' 6% Capex; 5% Opex 2% Capex: 2% Opex 4% Capex; S . ' \ " " \ 3% Opex ' 1 1 ' ' ' 1 1 ' ' ' ' 1 ' ' Upstream Capital Costs : } 100% Increase ' 50% Decrease ¢ Base Case ' 1 ' 1 1 1 ' \ ' 1 ' ' 1 ' TransCanada Schedule ' 1 P90 1» P10 1 Base Case ' ‘ 1 1 1 1 ' ' 1 1 1 1 \ : : ' : ; Mean Capital TransCanada Capital Cost ' 1 , P80 P10 1 \ 1 1 ' ' ' ' ' ' ' i ( ! i i 7.06% Pipeline Interest Rate H ' 8.81% 1 : \ \ ' 1 ‘ ' 1 1 ' ' ' PBU 3.0 Production Scenarios ‘ ! ' PBU 3.5 BCF/d; No PT BCF/d; PT ' ' 1 ' Blowdown $(5.0) $- $5.0 $10.0 $15.0 $20.0 Producer NPV%io ($Billion 2008) Source: Black and Veatch, Appendix G1, Section 5.6.2 In general, the various risk factors affect Producer NPV in a manner very similar to the state NPV. This is because the state derives the bulk of its revenues from royalty and production taxes, which are directly dependent on the degree to which Producers realize profits as a result of shipping their gas through the pipeline and selling that gas at the AECO Hub. Two issues deserve particular attention. First, the majority of these risk factors involve things over which a producer or pipeline can exercise relatively limited control. The most significant exception is probably the ability of a pipeline company to control project costs through careful management of project scope risk. Still, the impact of this factor is relatively small compared with others. Second, capital cost (scope) risk appears to have a relatively modest impact on Producer NPV. Given the substantial rewards that the Project offers anchor shippers, it is not apparent that capital cost risk would prohibit them from participating as shippers in TC Alaska’s project. 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination We have reviewed the Project economics from numerous perspectives and have run numerous scenarios to assess the impact of many variables. We acknowledge the inherent difficulty in projecting future events. However, over a wide range of future events the Project’s economics are robust. b. Estimated NPV Under the Conservative Base Case and Low Volume Sensitivity Case Remain Favorable. A Point Thomson resource study performed for the commissioners by Petrotel, a summary of which is attached at Appendix O, discusses the uncertainties associated with the development of natural gas reserves at Point Thomson. Given the potential condensate and black oil resource at Point Thomson, and the need for maintaining reservoir energy to maximize recovery of these hydrocarbons, gas may not be available from Point Thomson for the Project for many years. Accordingly, Project economics were assessed assuming, in the extreme, that Point Thomson gas might not be available during the first 25 years of Project operations. Under this Conservative Base Case, the capacity of the Project was reduced from 4.5 Bcf/day to 4.0 Bcf/day, and the initial term of firm shipping contracts was reduced from 25 to 20 years. The P50 current-dollar cost estimate for the Conservative Base Case is $29.4 billion,”” about $2 billion less than the P50 estimate for the Proposal Base Case.”’ In addition, to assess whether the Project economics remain attractive with an even smaller pipeline project, the commissioners and the Commercial Team also considered a pipeline configuration of 3.5 Bcf/day, which is referred to as the Low Volume Sensitivity case. The Conservative Base Case offers several lessons, including: e Tariff rates increase by about 13%. This increase results from the smaller pipeline capacity and shorter contract/depreciation period. Essentially, even though the Conservative Base Case costs about $2 billion less than the Proposal Base Case, the tariff rate of the Conservative Base Case increases due to the need to recover that $29.4 million over a shorter period of time (20 years instead of 25 years) and over a smaller 7 Recall that a “P50” cost estimate represents the level of costs that generate an equal likelihood of greater or smaller costs. 7 In current-day dollars, the midpoint probability estimate Conservative Base Case project cost is $29.4 billion. The reduction, compared with the Proposal Base Case, is due primarily to reduced needs for pipeline compressor stations, as well as reduced GTP costs. (See Appendix F, Exhibit D, for details.). 27 MAY 2008 3-69 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination volume of firm shipping contracts (4.0 Bcf/day instead of 4.5 Bcf/day). Similarly, the 3.5 @ Bcf/day case indicates an increase in the tariff rate of approximately 21% above the Proposal Base Case (Figure 3-31). Figure 3-31. Pipeline Tariffs Under Proposal, Conservative, and Low Volume Cases AECO Tariff $10.0 m 4.5 Befld 4.0Bcfid [93.5 Befld $8.0 4 B 1 = $6.0 | 2 $5.33 = a $4.73 £ E $4.0 +- --- 2 $2.0 | @ $- . 4.5 Befid 4.0 Befid 3.5 Befld Source: Black and Veatch; Appendix G1, Section 6.4.1 e The Conservative Base Case Creates Less Reserve Risk. Initial shippers on the pipeline face reserve risk. In the later years of their firm transportation contracts, the lessees at Prudhoe Bay and the other fields with known gas reserves will face production declines such that they will have more capacity than throughput. To fully use such capacity, YTF gas will be needed. Accordingly, a commitment to ship on the pipeline places the initial shippers at risk for not finding sufficient reserves to fill their capacity in later years. The Conservative Base Case, which contemplates 20-year shipping contracts, reduces the reserve risk for the initial shippers compared with the 25- year contract period assumed in the Proposal Base Case. In the 4.0 Bcf/day Conservative Base Case, with a 20-year contract period, producers must find enough @ 27 MAY 2008 3-70 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination YTF gas to fill only 15% of the contracted volumes during the life of the contract (the majority of which is required in the last few years). In contrast, the Proposal Base Case, even with Point Thomson gas, requires producers to find enough YTF gas to fill 26% of their initially contracted capacity. The smaller 3.5 Bcf/day configuration under the Low Volume Sensitivity Case has the lowest reserve risk, requiring the production of only 10% YTF volumes (assuming 20-year shipping contracts). In essence, by reducing the pipeline capacity from 4.5 to 4.0 (or 3.5) Bcf/day and reducing the contract period from 25 to 20 years, the shippers have to find significantly less YTF volumes to fill the pipeline and fully utilize their firm capacity. Mitigating Reserve Risk Involves Tradeoffs with Net back Risk. As discussed earlier, tariffs rise as initial throughput and contract lengths decline. This increases exposure to price risk—at least during earlier years of pipeline operation. But, as initial throughput and contract lengths decline, the need to find new gas to fill existing capacity falls. Conversely, one can increase early-year net backs by increasing the transportation contract length and pipeline size, but this may reduce cash flow in future years (such that, in the limit, gas revenues from diminished production fail to cover the costs of the total transportation commitment). Despite Increased Tariffs, Estimated NPVs Remain Positive. As discussed earlier, the 4.0 Bcf/day Conservative Base Case offers substantial net revenues to the state, the Producers and TransCanada. State NPV would decrease by only 8% under the Conservative Base Case due to greater gas production at Prudhoe Bay. The NPV to the state under the 3.5 Bcf/day Low Volume Sensitivity Case is about 15% less than under the Conservative Base Case, but is still approximately $51.6 billion. 27 MAY 2008 3-71 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-32. State NPV5 Under Proposal, Conservative, and Low Volume Cases @ State NPV; $80.0 $70.0 4 $66.1 ee $60.7 $60.0 4 o Ss $50.0 } x 5 $40.0 4 m $30.0 | - a $20.0 4 - $10.0 + $- 4 + r 4.5 Befid 4.0 Bef/d 3.5 Befid Source: Black and Veatch; Appendix G.1, Section 6.4.2 @ The NPV results for the Major North Slope Producers are directionally similar to the state results under the Conservative Base Case and the Low Volume Sensitivity Case. The Producer NPV1o under the Conservative Base Case is 9% less than the Proposal Base Case (approximately $12.3 billion), and is about 23% less under the Low Volume Sensitivity Case (approximately $10.5 billion) than under the Proposal Base Case. Fundamentally, the smaller 4.0 Bcf/day and 3.5 Bcf/day cases are profitable projects for the state and the Major North Slope Producers, despite their smaller size.’? 7 For more details on these results, see Appendix G1, Section 6 27 MAY 2008 3-72 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination ©} Figure 3-33. | Aggregate Producer NPV Under Proposal, Conservative, and Low Volume Cases Aggregate Producer NPV1io $20.0 $18.0 + $16.0 +4 $14.0 4 $12.0 4 $10.0 +4 $8.0 4 $6.0 + $4.0 4 $2.0 4 $ Billions (2008) 4.5 Bcfid 4.0 Befid ©} Aggregate Producer NPV;5 $20.0 - -— $18.0 | $16.0 4 $14.0 4 $12.0 4 $10.0 4 $8.0 | $6.0 4 $5.2 $4.7 $4.0 $2.0 4 $ Billions (2008) 4.5 Bcfid 4.0 Bcfid Source: Black and Veatch, Appendix G1, Section 6.4.2 27 MAY 2008 3-73 AGIA Written Findings and Determination TC Alaska’s Project Would Produce Significant NPV The NPV May Improve After TransCanada Negotiates with the Producers. Under the Conservative Base Case, we assumed a 20-year firm contract term, which matches the assumed 20-year depreciation life of the pipeline. The firm transportation commitment contract term has been assumed to match the 20-year assumed depreciation life of the 4.0 Bcf/day project, consistent with the spirit of the Application. Thus, TC Alaska has initially proposed for shippers (the Major North Slope Producers) to sign 25-year, 30- year, or 35-year contracts using corresponding 25-year, 30-year, or 35-year depreciation periods. However, it is possible that, after negotiations between TC Alaska and the Producers, TC Alaska will offer a contract period that is shorter than the depreciation period. For example, it could offer contracts for 20, or even 15 years but depreciate the pipeline over 25 years. Such an offering would fit squarely within the mainstream of commercial transactions on Lower 48 projects, and appears feasible from a financing perspective.”* Initial shippers could substantially benefit from this approach. In the first instance they would be able to “shed” the majority of their reserve risk. Secondarily, tariffs determined on a levelized basis would drop. Figure 3-34 shows tariffs for the Conservative Base Case, and variations of that case where the Project is depreciated over 25 years but initial shipping contracts are 20 and 15 years in duration. Figure 3-34. Impact of Contract and Depreciation Periods on AECO Tariff Nominal $ / MMBtu AECO Tariff $10.0 $8.0 $6.0 $5.33 $5.41 $5.31 $4.0 $2.0 $- 20/20 20/25 15/25 Source: Black and Veatch, Appendix G1, Section 6.7.1 "3 See Appendix H, Section VI.B (for results) and Section VI.D (for discussion). 27 MAY 2008 3-74 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination @ Given shorter contracts and a longer depreciation period Producer net backs would improve, as would the NPVs for the Producers and the state. In such a scenario, TC Alaska would essentially be offering to take some of the reserve risk by agreeing to bear the risk of finding shippers to contract for capacity on the pipeline over the remaining depreciable life of the Project. If TC Alaska takes that risk, and continues to use a 25-year depreciation period, NPVs to the state and the Producers would improve, all other things being equal (Appendix G1, Sections 6.5 and 6.7 for discussion). c. The Project Would Produce a Positive NPV Even If No Point Thomson or YTF Gas Is Ever Produced. When considering the potential impact of 9 Po . When considering the potential impact of Point Thomson and YTF gas on Project | point Thomson and YTF gas on Project NPVs, NPVs, it is critical to understand that the | it is critical to understand that the Project would produce profitable NPVs even if no Point Thomson or YTF gas is ever produced. Project would very likely produce profitable NPVs even if no Point Thomson or YTF gas is ever produced. This is true for the Proposal Base Case, the Conservative Base Case, and the Low Volume Sensitivity Case, as demonstrated in the chart below (Figure 3-32): @ As the previous chart demonstrates, even if the only gas that is ever shipped through the Project is the Prudhoe Bay and state existing gas, the Project would very likely produce a significant NPV to the state and significant profits to the Major North Slope Producers. 27 MAY 2008 3-75 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-35. | Reserve Risk: Producer NPV Assuming No YTF Gas @ Proven Reserves NPV) with No YTF Gas $15.0 wi4.5 Befid 4.0 Bcfld 3.5 Befid $12.0 + $113 gig, -- $141 = $9.6 é : S $90 }-- & fa " $3.0 4 $- r 25/25 20/20 15/15 Contract Period/Depreciation Life (years) Proven Reserves NPV,; with No YTF Gas @ $15.0 4.5 Bcfid 4.0 Bcfld (3.5 Bcfid $12.0 +- , : doe a geterciss soe o S $90 }- : ; aRAntaoe s a $4.8 $4.5 $4.6 $4.4 7 . $4.3 $4.1 - $4.0 $3.8 $3.5 $3.0 +-- | --- - - $- - - 25/25 20/20 15/15 Contract Period/Depreciation Life (years) Source: Black and Veatch, Appendix G1, Section 6.5.2 27 MAY 2008 3-76 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Of course, producers may care about more than NPV in the aggregate. If they cannot keep their capacity full, then the risk increases that they will have periods of negative cash flow. To assess this risk we compare annual revenues and costs for the Major North Slope Producers, assuming that no additional gas was discovered and developed over the next 30 years. The results are shown in the following three charts (Figure 3-36). Even with declining production and pipeline throughput, revenues under the Wood Mackenzie price forecast are more than sufficient in every year to fully cover all transportation and upstream production costs. Cash flow for the Producers remains positive for the Proposal Base Case, Conservative Base Case, and 3.5 Bcf/d throughput case. Figure 3-36. Reserve Risk: Yearly Net Back Cash Flow Revenue vs. Transportation Costs 4.5 Befid (3.0 PBU, PT Blowdown) $70.0 (zzz. Transportation Costs $60.0 4 Revenues $50.0 { — — Revenues with No YTF Gas 5 $40.0 |- 5 $30.0 4 a ww" $20.0 4 ete ~ ~ $10.0 4 : J 2020 2023 2026 2029 2032 2035 2038 2041 2044 27 MAY 2008 3-77 AGIA $70.0 $60.0 $50.0 $40.0 $30.0 $ Billions (2008) $20.0 $10.0 $70.0 $60.0 $50.0 $40.0 $30.0 $ Billions (2008) $20.0 TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Revenue vs. Transportation Costs 4.0 Befid (3.5 PBU, No PT) Transportation Costs 7 Revenues — — Revenues with No YTF Gas ta tat 2020 2023 2026 2029 2032 2035 2038 2041 2044 Revenue vs. Transportation Costs 3.5 Befid (3.0 PBU, No PT) Transportation Costs Revenues — — Revenues with No YTF Gas — AAA AAARERAAA AAR RR RRA... 2020 2023 2026 2029 2032 2035 2038 2041 2044 Source: Black and Veatch, Appendix G1, Section 6.5.2 27 MAY 2008 3-78 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination @ Of course, this seems an extremely conservative set of cases. It assumes that no additional gas will be found and developed, despite the NETL study conclusions that there is at least a 50% chance that over 137 Tcf of gas on the North Slope can be economically developed. It also assumes that Point Thomson gas never comes into the project. This confirms again that the Project presents an attractive economic opportunity to the state and the Major North Slope Producers. 4. Impact of $500 Million Match AS 43.90.170(b)(5) requires the commissioners to consider, in analyzing the estimated NPV of the Project, the impact of the $500 million in state matching funds that would be available to TC Alaska. Assuming the project goes forward, the state would actually receive a higher NPV as a result of paying the $500 million (Appendix The state is paid back for its $500 million investment G1, Section 5.7). This is because the matching funds will not be included in the rates TC Alaska would charge for the Project | in getting the ea A ci | Project going, and (Application 2007, Section 2.2.3.7). This in turn reduces the tariff by keeping it going. about 6 cents/MMBtu. The state receives the value of tariff reduction st through increased royalty and production taxes. Accordingly, the state is more than paid back @ for its $500 million investment in getting the project going, and keeping it going. Figure 3-37. State of Alaska NPV5 with and without $500m match State NPV, Base Case No $500 Million Match Source: Black and Veatch, Appendix G1, Section 5.7.8.2 27 MAY 2008 3-79 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination The Producer Project by BP and ConocoPhillips would not require any state matching funds. Some have suggested that the state would be better off abandoning AGIA and thus avoiding what they consider the unnecessary expenditure of $500 million of state funds on the TC Alaska Project. This analysis, however, demonstrates that the state would actually receive a net benefit if the Project is constructed, even without consideration of the numerous other benefits provided by TC Alaska’s Application (including enforceable commitments to expansion, rolled-in rates treatment for those expansions, rates based on no more than a 70/30 debt to equity ratio, progressing the project by making regulatory filings on a fixed timeline, hiring state workers to the extent permitted by law, providing in-state deliveries of natural gas at economic rates, etc.). In any event, even if the $500 million would not result in lower transportation rates and would therefore represent a real cost to the state, that cost would be much less than the billions in tax concessions which the Major North Slope Producers demanded,” and that the previous administration was willing to provide, under the SGDA contract negotiations as a precondition to even considering a pipeline project. According to the comments they filed in the AGIA public comment process (discussed more fully later in this Chapter), BP and ConocoPhillips have not abandoned their demands for fiscal concessions by the state. Thus, it is reasonable to conclude that the $500 million of state matching funds required by AGIA would be less than the amount the state would be required to spend or forego to induce construction of a gasline in the absence of AGIA. 5. Availability of Low Cost Expansion AGIA requires the commissioners to consider the applicant's initial design capacity and the extent to which the design can accommodate low-cost expansion. AS 43.90.170(b)(4) Under the direction of the commissioners, the Technical and Commercial Teams analyzed this issue. The NPV of the Project under the proposed initial design capacity of 4.5 Bcf/day has been discussed above. This section will briefly discuss the extent to which that design can accommodate low-cost expansion. The $10 billion figure is measured in 2005 dollars, based on analysis by the Legislature’s consultants EconOne, assuming a $4 gas price. The figure climbs to over $20 billion assuming an $8 gas price. For details, see slides 15-18 of: Pulliam, Barry. 2006. Comments to Legislature on Gas Contract and Fiscal Interest Findings: Returns to the state and Producers. June 14, 2006. Available at http://Iba.legis.state.ak.us/sga/doc_loa/2 06-14 pulliam4 pdf. 27 MAY 2008 3-80 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination The state has confirmed that, on an engineering basis, TC Alaska’s initial design capacity of 4.5 Bcf/day can be expanded with infill compression—which is cheaper than pipeline looping—to 5.9 Bcfiday.”© Such expansions can be accommodated using TC Alaska’s design parameters for compressor stations. Accordingly, up to 1.4 Bcf/d of additional capacity can be accommodated in “engineering increments,” as AGIA defines that term. In other words, potential shippers can be assured that TC Alaska’s design accommodates an additional 1.4 Bcf/d of capacity under AGIA-mandated expansions. TC Alaska’s system can be expanded even further, to 6.5 Bcf/d, through added compression at existing compressor stations. However, this would require adding compressor units of a different size than that proposed by TC Alaska. (Appendix F, Exhibit J) To assess the degree to which the Project can be expanded on a low-cost basis, a series of compression-only expansions were analyzed. Rolling the cost of those expansions into the Project rates would cause relatively small rate increases in, and in some cases would actually decrease, the Project rates (including the cost of fuel) (Appendix G1, Section 5.7.8.6). The projected rate for the compression expansions analyzed by the Commercial Team is shown in Figure 3-38 (Appendix G.1, Section 5.7.8.6). In this example, the AGIA rolled-in rate provisions provide shippers who would use expansion capacity above 5.1 Bcf/d assurance that they can get their gas into the project on reasonable terms. Rather than facing incremental rates, they enjoy rolled-in rates. Meanwhile, the “burden” associated with rolled-in rates on initial shippers is small. The expansions beyond 5.1 Bcf/d do not increase rates above the level that they initially paid. 78 See Appendix F, Exhibit J at p. 8. 27 MAY 2008 AGIA TC Alaska’s Project Would Produce Significant NPV Written Findings and Determination Figure 3-38. AGIA Roll-in-Rate Provision mms Last Expansion Pipeline and Fuel Rates Combined - 100% (<< Base Pipeline and Fuel Rates Combined Multiplied 1.15 (AGIA Provision) —*— Actual Base Pipeline and Fuel Rates Combined $7.00 -—— —— $6.50 + $6.00 + $5.50 + $5.00 + $4.50 + $4.00 + $3.50 + $3.00 Tariff Nominal $/MMBtu 45AECO-Yr 4.8AECO-Yr 5.1AECO-Yr 5.9AECO-Yr 6.5 AECO- Yr 2020 2022 2023 2025 2027 1) Initial Rate * 1.15 + Fuel based on Initial Fuel % and next expansions In-Service Year's Netback Price 2) Incremental increase based on Initial Fuel % and next expansions In-Service Year's Netback Price 3) Initial Rate + Fuel Based on Initial Fuel % and next expansions In-Service Year's Netback Price 4) Previous Exp Rate + Fuel Based on Previous Exp Fuel% and next expansions In-Service Year's Netback Price Source: Black and Veatch, Appendix G1, Section 5.7.8.6 As can be seen (Figure 3-35), the Project can be expanded up to 6.5 Bcf/day on a low-cost basis, actually resulting in reduced rates (compared with initial rates) in 2027 for the full 6.5 Bcf/day of capacity. Even though AGIA requires the roll-in of expansion costs up to 115% of the original Project rate (as reflected in the striped bars in the chart), the AGIA rolled-in rate provisions would only be implicated when the pipeline expanded from 5.1 to 5.9 Bcf/day. Thus, the 4.5 Bcf/day capacity of the Project appears to provide at least 2.0 Bcf/day of low cost expansion capacity. 27 MAY 2008 3-82 AGIA Analysis of the Likelihood of Success Written Findings and Determination E.Analysis of the Likelihood of Success of TC Alaska’s Project 1. Introduction and Summary Because the commissioners have found that the TC Alaska Project would produce a positive estimated NPV for the state and the other stakeholders in the Project, the analysis now turns to the Project's likelinood of success (AS 43.90.170(c)). After reviewing the evidence, we believe TC Alaska’s Project has a significant prospect of succeeding, for three principal reasons. First, TC Alaska has submitted a plan for its Project that is technically feasible, reasonable, and specific. Under the supervision of the commissioners, the Technical Team rigorously analyzed TC Alaska’s proposed plan. TC Alaska’s Application describes a detailed plan for its Project that provides more specificity than AGIA and the RFA required. TC Alaska's plan for a pipeline through Alaska to interconnect with the AECO Hub in Alberta is also technically sound and reasonably addresses the challenges of constructing a large diameter natural pipeline in arctic conditions. Second, TC Alaska has the technical expertise and financial ability to construct the Project. TC Alaska has demonstrated, both through the specifics of its application and its track record, that it is willing and financially and technically capable (Appendix F, Section 3.5) of implementing the proposed project work plan. TC Alaska is one of the TC Alaska has the technical largest natural gas pipeline companies in North America expertise and financial ability to and is an experienced, independent natural gas pipeline | construct the Project. TC Alaska has demonstrated, both through builder and operator (Application 2007, Attachment 1-1). the specifics of its application and Its experience in constructing and operating pipelines | its track record, that it is willing throughout the United States and Canada includes and financially and technically capable. experience constructing and operating pipelines in harsh near-arctic conditions similar to Alaska's. TC Alaska has also submitted a reasonable plan to manage and minimize cost overruns, although to a large degree increases in the price of steel and other inputs are out of its control. In addition, TC Alaska has demonstrated it has the financial resources to construct the Project, assuming it receives firm shipping commitments that would enable it to obtain financing.”® 7° For detailed analysis, see Appendix H, Section II.D. 27 MAY 2008 3-83 AGIA Analysis of the Likelihood of Success Written Findings and Determination Third, TC Alaska has submitted a reasonable commercial plan which, coupled with the economic, political and legal environment, appears to generate the favorable conditions needed to encourage shippers to sign the firm shipping commitments necessary for the Project to succeed (Appendix G2, Section 4). TC Alaska has proposed reasonable commercial terms for potential shippers that will allow them to participate by committing in an open season to ship their gas on the future pipeline. In addition, TC Alaska’s proposed commercial terms are likely to be further improved and refined during negotiations between TC Alaska and the Major North Slope Producers and the regulatory processes at FERC and the NEB.”” Finally, the likelihood that TC Alaska’s proposed Project will succeed is enhanced by the Project's strong potential profitability as shown in the results of the NPV analysis discussed in the preceding section of these Findings. Indeed, the Project’s robust economics are reasonably likely to help generate the necessary commercial, political and regulatory environment that will encourage potential shippers to sign firm shipping agreements, thus enabling the Project to obtain financing and move forward. Accordingly, the commissioners conclude that the Project is likely to succeed. The following discussion of the Project's likelihood of success first summarizes the methodology that was used, followed by discussion of the three sets of issues discussed above. 2. Methodology for Analyzing the Project’s Likelihood of Success AS 43.90.170 directs the commissioners to consider several specific criteria that affect the likelihood that the proposed Project will succeed: (1) the reasonableness, specificity, and feasibility of the applicant's work plan, timeline, and budget required to be submitted under AS 43.90.130, including the applicant's plan to manage cost overruns, insulate shippers from the effect of cost overruns, and encourage shippers to participate in the first binding open season; (2) the financial resources of the applicant; ae Appendix J, Section 1; Appendix G2, Section 4. These Findings do not constitute an endorsement of any of the proposed terms. The state retains its right to oppose any commercial or other terms proposed by TransCanada or TC Alaska at FERC and the NEB. 27 MAY 2008 AGIA Analysis of the Likelihood of Success Written Findings and Determination (3) the ability of the applicant to comply with the proposed performance schedule; (4) the applicant's organization, experience, accounting and operational controls, technical skills or the ability to obtain them, and necessary equipment or the ability to obtain the necessary equipment; (5) the applicant’s record of (A) performance on projects not licensed under this chapter; (B) integrity and good business ethics; and (6) other evidence and factors found by the commissioners to be relevant to the evaluation of the project's likelihood of success. (AS 43.90.170(c)). A project's likelihood of success under these factors cannot be as easily quantified numerically as the NPV analysis. It is possible, however, to assess whether a particular factor has a positive, negative or neutral impact on the Project's likelihood of success. The method for evaluating TC Alaska’s proposal used a three-tiered approach to assess the impact of various factors relevant to the Project's likelihood of success. A finding of “Positive Impact” indicates that the Project would have an increased likelihood of success based on the particular factor under analysis. A finding of “Negative Impact” indicates that the Project would have a decreased likelihood of success as a result of the factor. A finding of “No Impact” indicates that the factor under review would have no impact on the Project's likelihood of success. These LOS impacts simply indicate that the area that the project will probably land on cost and duration probability curves. A negative impact will tend to move the outcome up the curves, to the right, a positive impact down the curves to the left, and a neutral impact will tend to stay around the midpoint of the curves. 3. Analysis of Likelihood of Success Criteria Under AGIA Section 170 a. TC Alaska Has Submitted a Plan for its Project That is Technically Feasible, Reasonable, and Specific. E Specificity AS 43.90.170(c)(1) requires the commissioners to consider “[t}he reasonableness, specificity, and feasibility of the applicant's work plan, timeline, and budget required to be submitted under 27 MAY 2008 3-85 AGIA Analysis of the Likelihood of Success Written Findings and Determination AS 43.90.130.” A certain degree of specificity was required in an AGIA application to assess whether a project plan is reasonable and feasible. The RFA issued in July 2007 required applicants to provide a substantial amount of specific information about their proposed project. In addition to the required information, the RFA also requested, but did not require, applicants to provide additional information that would aid the commissioners in evaluating the applications. RFA Section 3.1 - 3.1.4. Overall, TC Alaska’s Application provides an excellent level of detail and specificity, which greatly facilitated the commissioners’ ability to evaluate the reasonableness and feasibility of the proposed Project. TC Alaska provided all the information required by the RFA, (TransCanada Completeness Determination Letter (January 4, 2008)), plus a significant amount of additional information. The overall Project contains a pipeline component and a GTP component. TC Alaska provided an excellent level of specificity in its Application about the pipeline component of the Project.” For example, TC Alaska’s Application contains a detailed project description, front-end engineering design plan, project cost and schedule estimates, and numerous appendices specifying additional technical details about its proposal (Application 2007, Sections 2.1, 2.2, 2.5, 2.6 and Application Appendices A, B3, B4, B6, N, O, and R). As the Technical Team’s report makes clear, the details provided by TC Alaska aided the Technical Team in its analysis of the Project. According to the Technical Team report (Appendix F), TC Alaska provided a complete project design with well-defined key components and assumptions, which positively affects the subproject’s likelihood of success (Appendix F, Exhibit A.) TC Alaska provided a lesser but sufficient level of specificity about the proposed GTP component of its Project. A gas treatment plant, which removes carbon dioxide and other impurities from the gas stream to render the natural gas fit for transportation in an interstate natural gas pipeline, is an essential part of the facilities needed on the North Slope for any Alaska pipeline to transport North Slope natural gas to market. As permitted by AGIA and the RFA, TC Alaska does not propose to own the GTP. ” (Application 2007, Section 2.1-12) 78 The state's Technical Team determined that the applicant had done a favorable job of defining the pipeline subproject scope and capabilities in sufficient detail to allow analysis, and that the pipeline’s key components and assumptions were well defined. See Appendix F, Exhibit F. 78 The RFA does not require an applicant to submit a GTP design if they do not intend to build the GTP. (RFA Section 2.1.2). Since TransCanada does not intend (at least initially) to design, build or operate the GTP, it is not required to 27 MAY 2008 3-86 AGIA Analysis of the Likelihood of Success Written Findings and Determination Rather, TC Alaska suggests that the current owners of the Central Gas Facility at Prudhoe Bay (the Major North Slope Producers) should own and operate the GTP.®© (Application 2007, Section 2.2.3.12) TC Alaska’s proposal does state, however, that it would “be prepared to build, own and operate” the new GTP facility if the Major North Slope Producers do not agree to own and operate the GTP (Application 2007, Section 2.2). The Major North Slope Producers may ultimately own the GTP as an adjunct to their production operations. It is reasonable that TC Alaska provides less detail about the GTP than about the pipeline component of the Project because TC Alaska does not propose to own the GTP. In addition, the Major North Slope Producers have much of the specific information about gas quality that will dictate the specifications of the GTP that will need to be constructed. They also control and have the final say on how much of the existing North Slope infrastructure can be utilized by the GTP. The Technical Team studied the significant current uncertainties surrounding the GTP element of the Project. They concluded that with sufficient engineering and design work the Major North Slope Producers, TC Alaska, or a third-party should be able to construct a GTP with sufficient capacity on a schedule consistent with the pipeline element of TC Alaska’s Project.®’ This could allow gas to flow on a schedule and within the cost range reflected in the Technical Team’s report (Appendix F). Thus, notwithstanding the complexities of designing, building and transporting such a facility to the North Slope, the commissioners believe the GTP should not negatively impact the overall likelihood of the success of the Project. ii. Technical Feasibility and Reasonableness of the Project Plan, Including the Project Cost and Schedule From a technical standpoint, TC Alaska’s project plan is highly reasonable and feasible for two reasons. First, TC Alaska is generally relying upon proven technology and methods. Although it says that it will consider using pipe with yield strengths greater than X80, (Application 2007, Section 2.21), TC Alaska bases their application on existing, proven technology. (Appendix F, provide design information. Nevertheless, TransCanada presented a “conceptual design” for the GTP (Application 2007, Section 2.1). ® The Central Gas Facility is a gas treatment facility on the North Slope that removes water and some liquid hydrocarbons that are then shipped down the TAPS line. The remaining gas stream is then re-injected into the reservoir for pressure maintenance in the reservoir. 5 Without specific design plans, in order to review the likelihood of success aspects of the GTP, Black and Veatch (with Amec-Paragon Engineering) performed a limited engineering study to determine the requirements for the GTP and to estimate a feasible construction schedule and cost range. (Appendix G1 at Exhibit J.) While the study shows that designing and constructing a North Slope GTP is a major and complex undertaking, it appears to be feasible if the project is properly managed. 27 MAY 2008 3-87 AGIA Analysis of the Likelihood of Success Written Findings and Determination Exhibit A) For both GTP and pipeline subprojects, TC Alaska’s technical design is based on existing technology that has been used on major United States and Canadian natural gas pipelines (Appendix F, Exhibit A). Such technology includes the proposed 48-inch diameter pipeline, which is adequate to transport 4.5 Bcf/day at a pressure of 2500 pounds per square inch gauge (psig), expandable to approximately 6.5 Bcf/day using compression without pipeline looping. (Appendix F, Exhibit J) Second, to the extent TC Alaska proposes to use an aggressive approach or newer, less tested technology, it is aware of the risks and has appropriate mechanisms in place to monitor the technology (Appendix F, Exhibit F), or will likely be able to address any issues that arise due to its experience and expertise as a pipeline operator (see next section for discussion). Of all the details contained in TC Alaska’s Application, none were determined to have a negative impact on the project's likelihood of success (Appendix F, Section 3.5). Further, only a few issues concerning the realism and feasibility of TC Alaska’s design resulted in a “no impact” rating with regard to the likelihood of the pipeline subproject’s success as specified in their Application. e Strain-based_ design. TC Alaska proposes to use strain-based design to address stresses on the project associated with frost heave and thaw settlement. (Application 2007, Sections 2.2.1, 2.4.8, 2.9.5)°* Although strain-based designs have been approved ® Frost-heave can occur when a pipeline is transporting gas that has a temperature below freezing and the pipeline crosses unfrozen, wet terrain. The cold pipe will tend to freeze the unfrozen saturated soil that surrounds the pipe resulting in the formation of an ice ball (frost bulb) around the pipe. This frost bulb can grow to the extent that it forces the pipe upwards (frost heave). Appendix F, Exhibit A. Thaw settlement occurs when the pipeline is transporting gas that has a temperature above the melting point of ice and the pipeline crosses terrain that is frozen at pipeline depth in soils with high ice content. The warm gas inside the pipe will tend to melt the ice in the soil, and the pipe could settle as it loses support from the underlying frozen soil. Appendix F, Exhibit A. Both of these unique arctic events, discussed in TransCanada’s Application (Section 2.2, pages 17-30), can induce stresses and strains on the pipe that must be accommodated in the pipeline design and during operation. Among other things, frost heave and thaw settlement require limits on the flaw size in the pipe and welding requirements that ensure welds are actually stronger than the surrounding pipe. Pipelines can be subjected to a variety of forces (loads). These forces cause stresses and strains in the pipeline. Stress is a measure of the amount of pulling or pushing the pipe steel is being subjected to. If you pull too much the steel will break apart. Strain is a measure of how much the steel is stretching as a result of this force. If you stretch the steel too much it will break apart. The two basic types of pipeline loads are Primary loads (example is force on the pipeline steel due to the pressure of the gas in the pipeline) and Secondary loads (example the force on the pipeline steel due to it being bent because of the movement of the soil around the pipeline due to frost heave). The Conventional Design approach for pipelines is for the stress in the pipeline steel caused by both Primary and Secondary loads to be limited to a fraction of the capability of the pipeline steel. 27 MAY 2008 AGIA Analysis of the Likelihood of Success Written Findings and Determination @ for onshore applications in Canada, and offshore applications in the U.S., and although the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration is working with the Canada’s National Energy Board on a trans-border study of pipeline safety (PHMSA 2008), the Technical Team noted that it is not currently permitted under US regulations.(Appendix F, Exhibit F). The Technical Team believes there is a high probability that this design approach will be approved by U.S regulators. If it is not permitted to use strain based design, TransCanada’s expertise as an operator and its track record of completing projects on time lead us to agree with the Technical Team that this is not a factor that is likely to cause a negative impact to the project's likelihood of success. e Pipeline Gas Temperature. In Alaska and into the first initial compressor station in Yukon, TC Alaska is planning to limit discharge temperature of the gas coming out of the compressor stations to just below freezing; further “downstream” than this the gas temperature would be allowed to rise (see Application at 2.10). Gas temperature matters in the presence of high ice-content soils: if soils melt then this could cause strain on the pipeline (Appendix F, Exhibit F). The extent to which this design plan is appropriate, therefore, depends upon actual soil conditions. TC Alaska plans to review these design © assumptions for the Yukon-BC section to ensure the appropriateness of their design assumptions. It is expected that this issue will be resolved by TC Alaska as more site- specific soil data becomes available (Appendix F, Exhibit F). In addition to the foregoing, the project's massive size will create labor and equipment availability challenges. These challenges are not unique to TC Alaska’s plan, but rather are inherent to the scale of the project. (Appendix F, Exhibit F) However, the Technical Team concluded that TC Alaska would be able to overcome the design, construction, and operating challenges inherent to the project (Appendix F, Exhibit F). Except for these issues, the pipeline subproject project plan specified in the Application earned positive impact ratings on the vast majority of technical issues. For example, TC An alternative design approach is to use Strain Based design. The stress in the pipeline steel due to the Primary loads is still limited to a fraction of the capability of the pipeline steel, same as the Conventional Design approach. The unique element of the Strain Based Design is the Secondary loads are limited by the strain (not the stress) in the pipeline steel (example is the amount of bending caused by frost heave would be limited by the amount of strain in the pipeline steel) The amount of strain allowed in the pipeline steel is a fraction of the strain capability of the pipeline steels. 27 MAY 2008 3-89 AGIA Analysis of the Likelihood of Success Written Findings and Determination Alaska earned positive impact ratings regarding the following factors for the pipeline subproject. e Whether the subproject development plan reflects a complete and realistic FEED (two- stage Front End Engineering and Design) plan with a scope of work, resource plan, governance model, and schedule necessary to support project execution, (Appendix F, Exhibit F).°° « Whether the stakeholder management plan addresses the key stakeholders, key issues to be addressed and a viable plan to address their needs within the context of the subproject, (Appendix F, Exhibit F).°* e Whether TC Alaska’s project execution plan is realistic and achievable in light of the subproject challenges, (Appendix F, Exhibit F). e« Whether the construction management plan address the challenges associated with the project location as well as the potential project resources environment (Appendix F, Exhibit F). TC Alaska’s cost estimate methodology is appropriate for each subproject such that the estimated cost is realistic and achievable; for the pipeline subproject it positively contributes to the project’s likelihood of success. (Appendix F, Exhibit F). Because of this, it was possible to carefully and rigorously assess TC Alaska’s actual cost estimates. As noted earlier, it is somewhat unlikely that TC Alaska’s cost, expressed in 2007 dollars, will be achieved. (See Section D.2, above, for an assessment of the likely distribution of Project costs), That, however, does not impugn the appropriateness of TC Alaska’s estimate, or reduce the Project’s likelihood of success, given the current state of Project planning. TC Alaska’s cost estimate was determined to be “aggressive but realistic.” That is, if things were to go well it would be achieved as it is realistic, but it is on the optimistic end of the achievable range—it is aggressive. Such an estimate is appropriate for planning purposes: if one does not “aim high” at this stage, there is little hope of achieving a favorable cost outcome. TC Alaska’s scheduling methodology is 83 The FEED plan that TransCanada proposes has one phase designed to define the pipeline plan in sufficient detail for the open season and another phase involving work necessary to support the regulatory process and to implement the execution plan for the project (Application 2007, Section 2.1). The Technical Team report concluded that this is reasonable and should support the project's ultimate execution (Appendix F, Exhibit A). 54 We note that TC Alaska has provided a 13-page list of the stakeholders it has identified for this project (Appendix G to the Application). 27 MAY 2008 3-90 AGIA Analysis of the Likelihood of Success Written Findings and Determination appropriate for the subproject such that the estimated schedule is realistic and achievable, and its methodology for the pipeline subproject contributes positively to the Application’s likelihood of success (Appendix F, Exhibit F). As with TC Alaska’s proposed cost estimate, the proposed schedule itself was carefully scrutinized by the commissioners and their Technical Team. See Appendix F, Sections 2.1.2, 3.2, and Exhibit D. Overall TC Alaska adopted a relatively conservative scheduling approach (Appendix F, Exhibit F). It does not currently plan to unconditionally award contracts to material suppliers or construction contractors until after a Certificate of Public Convenience and Necessity has been awarded by the FERC and NEB (Appendix F, Exhibit F) and the Decision of Notice to Proceed has been made. By staging their activities in this way they reduce their risk exposure; if additional risk were taken on—such as awarding these and other contracts earlier in the development phase—the overall schedule could potentially be accelerated (Appendix F, Exhibit F). The commissioners scrutinized the development phase of proposed schedule, especially in regards to obtaining necessary regulatory permits. TC Alaska’s proposal to complete the project's development phase and obtain the necessary permits within five and a half years is aggressive but not unreasonable. The commissioners believe TC Alaska’s proposed schedule is technically feasible and reasonable under the circumstances. As discussed in the Technical Team report (Appendix F), the Technical Team’s most likely outcome (the “P50” estimate) is that TC Alaska will not be able to begin the execution phase for approximately six and a half years after license award (Appendix F, Exhibit D). 27 MAY 2008 3-91 AGIA Analysis of the Likelihood of Success Written Findings and Determination Figure 3-39. | Schedule Risk of Proposal Base Case AGIA TransCanada Application - Base Case Time-Risk Model Profile for Base Case: 4.50 bcfd (Base Case) Integrated Project af Pome ey ee cLoy ieee Sept ate fp VII2 UVB GET D ADAL W223 pest Pere | Source: Westney 2008, Appendix F, Exhibit D TC Alaska’s estimate of the conclusion of the development phase, which comes in a full year earlier than the Technical Team’s midpoint probability estimate, is assessed as having a likelihood of about 5%. However, that does not mean that TC Alaska has proposed an unreasonable schedule. Given the adage that “a project expands to fill the time made available to it,” a reasonable but aggressive schedule is necessary; there is little hope of making a shorter development schedule if a longer one is planned. Meanwhile, TC Alaska has a good understanding of the critical activities that must be scheduled (Appendix F). The Technical Team Report (Appendix F) concludes that TC Alaska may be able to achieve its aggressive schedule if many things “go right” for TC Alaska—especially with regard to the Canadian regulatory and First Nations issues. The fact that TC Alaska is pushing to construct the pipeline as soon as possible positively contributes to the Project’s likelihood of success, given the state’s interest in getting a gasline as soon as possible. 27 MAY 2008 3-92 AGIA Analysis of the Likelihood of Success Written Findings and Determination One particular issue that could impact the Project schedule which the commissioners analyzed carefully is the question of how long it will take TC Alaska to obtain Canadian regulatory 85 authorizations.*° AGIA requires that any applicant proposing a pipeline through Canada must provide, “a thorough description of the applicant's plan to obtain necessary rights-of-way and authorizations in Canada...” (AS 43.90.130(2)(D)i)). TC Alaska has indicated that it already holds certain rights-of-way through Canada (Application 2007, Section 2.2.4.2) and also holds certificates of public convenience and necessity to construct and operate the first gas pipeline from Alaska into Canada pursuant to the Northern Pipeline Act (NPA) (Application 2007, Section 2.2.3.13).°° However, in public comments (Appendix A, Alliance Comments, March 6 2008) and in earlier testimony before the Legislature, parties have asserted that TC Alaska’s (through Foothills) Norther Pipeline Act certificates are dated, fail to reflect current environmental standards and are no longer valid. To better understand these Canadian issues, the commissioners retained the Canadian law firm of Bennett Jones LLP (“Bennett Jones”), which has significant experience in Canadian energy regulatory issues, to review TC Alaska’s application with respect to its authorizations and plans to obtain regulatory authorization and access (i.e., rights-of-way) through Canada and the probable time line for obtaining such necessary approvals. The Bennett Jones report is attached as Appendix S1. According to Bennett Jones, the five and one-half years that TC Alaska’s schedule includes for obtaining Canadian regulatory authorizations is probably optimistic. Bennett Jones suggests that a seven-year time frame is more likely due to the likelihood that at least certain of the risks identified with associated delays, will actually be encountered by the project, regardless of who builds it. This is similar to (although somewhat shorter than) the time the Mackenzie Valley Gas pipeline project has taken to obtain the necessary authorizations to build its pipeline in Canada. However, it is reasonable to expect that TC Alaska, as an experienced Canadian pipeline 85 Pursuant to the Energy Policy Act of 2005, Congress required FERC to provide the U.S. regulatory authorizations within specified time periods which generally are significantly shorter than the estimated time it will take to obtain regulatory authorizations for the Canadian portion of the Project. Further, ANGPA requires that the FERC complete its review of an application for an Alaskan pipeline within 20 months of receiving a complete application. Accordingly, the focus of the discussion here is on the Canadian issues. ®© Because of TransCanada's unique position in Canada with regard to regulatory certificate and right of way matters, it is impossible to separate TC Alaska’s project plan from TC Alaska’s capabilities for implementing the plan. The following discussion reflects this fact. 27 MAY 2008 3-93 AGIA Analysis of the Likelihood of Success Written Findings and Determination operator, will pursue an approach to obtaining Canadian regulatory authorizations that does not repeat some of the mistakes made by Mackenzie (Appendix S1). With respect to timing we note that recently Canadian officials have announced a new policy designed to expedite energy projects.®” While it remains unclear what effect this might have on TC Alaska’s proposal (or whether it would apply inasmuch as TC Alaska will be advancing its project under the authority of the NPA), it suggests a step in the right direction. Further, we note the public comments of Mr. Gary Lunn, Minister of Natural Resources of the Canadian government. He notes that the Canadian authorities are preparing for an Alaska project, “and are cognizant of the need for an efficient and effective review process that can match the time lines of a parallel process by the [FERC]...” This again, suggests that Canadian authorizations can be obtained in a timely manner. In analyzing the feasibility and reasonableness of TC Alaska’s proposed schedule for obtaining regulatory permits and its likelihood of success, the commissioners considered a variety of factors, including the seven-year estimate provided by Bennett Jones and the six-and-one-half year estimate by the technical team. The commissioners have confidence in the reliability of the schedule for obtaining Canadian regulatory permits because Bennett Jones and the Technical Team reached their schedule estimates independently of one another, and yet were only six months apart in their estimate of the most likely outcome. Several of the conclusions in the Bennett Jones report are significant. Bennett Jones (Appendix $1, Section A) notes that the NPA created a “single window” agency (the Northern Pipeline Agency (NPAgency)) for obtaining all Canadian authorizations required to build the ANGTS t 88 projec! It notes also that the NPA was enacted to ensure the “prompt issuance of all necessary permits, licenses, certificates, rights-of-way, leases and other authorizations required for the expeditious construction and commencement of operation of the Pipeline” as had been °7 Petroleum News, Canada to Fast Track Alaska, Vol. 13, No. 19, at 1 (May 11, 2008). 8 As required by the RFA, TC Alaska provided details of its plans to secure regulatory authorizations and rights-of- way in Alaska and Canada. Application 2007, Sections 2.2.4.1 and 2.2.4.2. TC Alaska asserts that it presently holds certificate authority to build the first gas pipeline from Alaska pursuant to the Northern Pipeline Act (NPA’). Application 2007, Section 2.2.3.13. The State received public comments asserting that TC Alaska’s reliance on the thirty-year old NPA is misplaced (BP Comments at 2) These comments claim that the NPA is outdated and does not reflect modern environmental and other standards. However, TC Alaska claims that the NPA is still in effect and has no sunset or expiry date. TC Alaska also claims that it already holds easements for such a pipeline through the Yukon and has certain other rights to access lands over which its proposed pipeline will run. Application 2007, Section 2.2.4.2. TC Alaska also explains that it has identified approximate forty First Nations with whom it has either contacted to consult on its project or with whom it anticipates such consultation. Application 2007, Section 2.9.5(1). 27 MAY 2008 3-94 AGIA Analysis of the Likelihood of Success Written Findings and Determination agreed to by the U.S. and Canada in the September 20, 1977 Agreement between Canada and the United States of American on Principles Applicable to a Northern Natural Gas Pipeline. After analyzing the argument that the NPA is not applicable to the APP, Bennett Jones concludes that the NPA is still valid and the certificates issued there under continue to be effective. Bennett Jones concludes that “the legislation by its terms continues to apply; stating that the Certificates do not have an expiration date (Appendix S1, Section D.2). They note that the NPA was utilized as recently as 1998 when certain of the Foothills Pre-Build® facilities were expanded. (Appendix S1, Section D.2). According to Bennett Jones, however, the NPA is silent on process. While the idea underlying the NPA was to create a “single window’ for all required regulatory approvals related to the project, the Act is silent on exactly how this is to be accomplished. The NPAgency is empowered to develop procedures and processes to implement the Act. The NPAgency can have critical regulatory functions carried out under the NPAgency’s authority and to transfer issues to the NPAgency staff from other Federal agencies to evaluate and analyze the project. The NPAgency may adopt review standards used by other agencies. For example, the NPAgency could require that the standards and requirements of Canadian Environmental Assessment Agency (CEAA) be applied to environmental review under the NPA. If the NPAgency applies other agencies’ review standards Bennett Jones suggests that objections to TC Alaska’s reliance on the NPA can be minimized and the risks of litigation about this issue reduced. Bennett Jones also notes that TC Alaska has the opportunity to propose to the NPAgency the use of a joint Yukon/Federal panel to review the impacts of the project in Yukon just as would likely occur if the Yukon Environmental and Socio-Economic Assessment Act (YESAA) were directly triggered by the project. Bennett Jones believes that YESAA would apply. Here again, by adopting the substance if not the actual form of YESAA review, TC Alaska and the NPAgency could reduce the risk of litigation that could delay the project. Public comments questioned whether the current TC Alaska application describes the project that was approved and certificated in the 1970s. The early project plan was for a 2.4 Bcf/day 8 The “Pre-Build” refers to the existing natural gas pipeline system built under certificates issued pursuant to Canada's Northern Pipeline Act that starts at Caroline, Alberta and branches into two legs, 1) south-east to Monchy, SK and 2) southwest to Kingsgate, BC, which is owned by Foothills Pipe Lines, LTD. A wholly-owned subsidiary of TransCanada Corporation (TC Alaska Glossary). 27 MAY 2008 3-95 AGIA Analysis of the Likelihood of Success Written Findings and Determination line. Now, however, a much higher pressure, larger diameter and more expensive line is contemplated. Commenters argue that this difference triggers the requirement in the NPA for National Energy Board (NEB) approval of an “expansion.” Bennett Jones concludes that an expansion approval process would in turn trigger CEAA’s public hearing process and major environmental review. Bennett Jones suggests that there may be merit to the expansion claim (Appendix S) but advises that it could be resolved within the seven year time frame that they have identified. However, this issue, like other Canadian legal and regulatory issues discussed in the Bennett Jones report, should not adversely impact the Project's likelihood of success because the time line developed by the Technical Team presumes that the final regulatory approval of the project in Canada will extend beyond the five and one-half years suggested by TC Alaska. The longer time line was also used in the NPV analysis.” Another Canadian regulatory issue arises from TC Alaska’s proposal to make use of only the Alberta pipeline system owned by Foothills once the pipeline reaches Alberta. Potential shippers (i.e., ExxonMobil) and competitors of TC Alaska (i.e., Alliance) have commented on this matter, calling it a “tying” arrangement. The State of Alaska cannot resolve this issue. It will be resolved by Canadian regulators when TC Alaska puts forth its open season or re-engages the NPA permitting process. Bennett Jones commented on this issue in their report, however, noting that it could result in litigation and thereby delay the project. However, they also note that if TC Alaska adopts a flexible and expansive approach to the issue of moving Alaskan gas on the most economic and efficient route to markets, making use of all available infrastructure, it will be able to mitigate the risks on this issue. Nonetheless, the risk of delay associated with resolution of this matter is incorporated in the time line used in the NPV analysis of the project. Another issue the project faces in Canada is the duty to consult with First Nations. The consultations that occurred in the 1970s may not be adequate today given Constitutional changes that occurred during the intervening years. Bennett Jones notes that the current duty to consult is quite rigorous and likely to be quite time consuming (Appendix S1, Section D.5). While TC Alaska does appear to hold easements through the Yukon as detailed in the application (Application 2007, Section 2.2.4.2), the right-of-way through British Columbia is 27 MAY 2008 3-96 AGIA Analysis of the Likelihood of Success Written Findings and Determination unresolved. Furthermore, given the vagueness of the project's configuration in Alberta, that right-of-way may also be unresolved. TC Alaska acknowledges that it has a duty to consult with First Nations (Application 2007, Section 2.2.3.13) and indicates it has a long-standing relationship with affected First Nations. While the nature of these long-standing relationships may be questioned (Government of Liard First Nation Comments, at 2-5) it is clear that TC Alaska acknowledges the necessity for such consultations (Appendix F, Exhibit F) and has a long history of working with First Nations on this project and others. (Application 2007, Section 2.9.5.) Accordingly, the current duty to consult with First Nations may cause some delay, but does not appear to negatively affect the overall likelihood of project success. We note that the duty to consult will apply to any project crossing lands claimed by First Nations’ or lands traditionally used by First Nations. Given Given _ TransCanada’s years of presence in detailed in the application, TC Alaska appears to have a First Nation as detailed significantly higher likelihood of success than a newcomer or | in the application, TC Alaska appears to have a significantly higher TransCanada’s years of presence in these communities as newcomers to the project who may have no prior experience in such consultations. likelihood of success than a newcomer or Before concluding, we focus again on TC Alaska’s plan for the | "ewcomers to the project who may have no prior experience in propose to deal with the GTP, regardless of whether that plant is \ such consultations. part of the applicant's proposal. (AS 43.90.130(8). As noted earlier, TC Alaska does not propose to construct or own the GTP. Rather, they suggest that the Major North Slope Producers should build, own and operate the GTP. However, in the event GTP subproject. AGIA requires an applicant to explain how they that the Major North Slope Producers do not wish to, TC Alaska stands prepared to do so. Accordingly, TC Alaska provided a basic work plan, timeline, and budget for a GTP to address this contingency. That they did so contributes to the overall Project’s likelihood of success, as it demonstrates a willingness to taking relatively unusual actions to see the project through. However, because their work plan concerning the GTP subproject was conducted at a relatively high level, the Technical Team generally concluded that the plan neutrally affected the Project's °° We note that the Technical Team utilized a 6 % year time line whereas Bennett Jones suggests that a 7-year time line is the most probable. The minor six-month difference is not material to the NPV analysis on a project of this 27 MAY 2008 3-97 AGIA Analysis of the Likelihood of Success Written Findings and Determination overall likelihood of success.°' (See, generally, Appendix F, Exhibit F). We concur with their assessment. In sum, from a technical standpoint, TC Alaska’s plan and schedule for constructing the Project are challenging yet technically reasonable and feasible, are appropriate for planning purposes, and contribute positively to the likelihood of success of the Project. b. TC Alaska Has Demonstrated the Technical and Financial Ability To Construct the Project. Having concluded that TC Alaska’s plan has the requisite specificity, and is reasonable and feasible, we next analyze several of the specific factors set forth AS 43.90.170(c) to determine whether TC Alaska has demonstrated the technical and financial ability to successfully complete its plan. For the reasons discussed below, we conclude that TC Alaska has demonstrated that ability. i. TC Alaska’s experience, skills and capabilities To determine the likelihood that an applicant can successfully execute its plan, AGIA requires the commissioners to consider the “applicant's organization, experience, accounting and operational controls, technical skills or the ability to obtain them, and necessary equipment or the ability to obtain the necessary equipment.” AS 43.90.170(c)(4) Similarly, AGIA requires the commissioners to assess the “ability of the applicant to comply with the proposed performance schedule” (AS 43.90.170(c)(3)). To analyze how TC Alaska does in regard to these criteria, the Technical Team employed its Positive Impact/No Impact/Negative Impact analysis framework. They awarded a Positive Impact rating on TC Alaska’s overall likelihood of success. The commissioners concur with and adopt the Technical Team’s assessment. In response to a state data request, TransCanada clarified that, as the parent company of TC Alaska, it was committing to: Make available the necessary human resources, technical know-how and expertise, management information systems, and procedures and policies to ensure that the Co- Applicants can meet their AGIA undertakings. (Palmer, 12/14/2007; Letter to Marty scale. ® TC Alaska’s conceptual design for the GTP is based on existing and well proven technology. (Appendix F, Exhibit F). This contributes favorably to the project's likelihood of success, as problems that can occur with using cutting edge approaches are unlikely to materialize. 27 MAY 2008 3-98 AGIA Analysis of the Likelihood of Success Written Findings and Determination Rutherford, Deputy Commissioner, Alaska Department of Natural Resources, December 14, 2007). Accordingly, when analyzing TC Alaska’s experience, skills, equipment and capabilities we look through them to their parent, TransCanada. TC Alaska appears to have the work processes and project governance standards in place to effectively manage the project (Appendix F, Exhibit F). The Technical Team assessed that TC Alaska demonstrated the appropriate work processes, governance, and staff competencies with ability to manage major pipeline projects on cost and on schedule (Appendix F, Exhibit A). TC Alaska’s demonstrated ability to manage major pipeline projects on cost and on schedule (Appendix F, Exhibit F) is an important factor which contributes positively to the Project’s overall likelihood of success. Although it appears that no company has experience dealing with the unique attributes of this Project, the commissioners concur with the Technical Team’s assessment that: “the areas where TransCanada lacks experience are generally areas where TransCanada’s technical and management capabilities can be adapted to these challenges and the TransCanada staff can be supplemented with contract staff with the necessary experience” (Appendix F, Exhibit F). TransCanada’s solid track record as a pipeline operator also indicates it will be able to successfully mitigate the risks associated with its technical plan (Appendix D, Palmer Letter February 8, 2008). It has a good understanding of the critical activities that must be scheduled for a large international Arctic pipeline (Appendix F, Exhibit F). Meanwhile, TransCanada presents a documented record of constructing projects at or near the projected costs (Application 2007, Section 2.9.3). This suggests that TC Alaska’s likelihood of completing the Alaska project at or near the estimated cost—at least with respect to controllable costs—is good (Appendix F, Exhibit F). The Technical Team expressed some concern that TC Alaska’s role in the Keystone project and a possible lead role in the Mackenzie Gas project could reduce the involvement of key management personnel and could result in a lack of experienced staff to meet all the staffing requirements that the company will face. (Appendix F, Exhibit F). On the other hand, as TC Alaska notes, TC Alaska’s ability to manage the Project may actually benefit from the increased staffing on those two projects, provided TC Alaska can rely on those staffing resources for the Alaskan pipeline project as the Keystone and Mackenzie 27 MAY 2008 3-99 AGIA Analysis of the Likelihood of Success Written Findings and Determination projects are completed (Appendix D, Palmer Letter February 8, 2008). Due to the uncertainty with this issue, the Technical Team gave it a neutral impact rating. The Technical Team noted that TC Alaska has significant experience in dealing with multitudes of stakeholders based on its experience in other major projects, including the Keystone project, Gas Pacifico (Argentina and Chile) and Tamazunchale (in Mexico) (Appendix F Exhibit F). Further TC Alaska has extensive experience in dealing with the Aboriginal communities in Canada (Appendix F). A positive contributing factor to the Project's likelihood of success is TransCanada’s experience in operating and managing large complex projects (Appendix F, Exhibit A). TransCanada is one of the leading pipeline operating companies in North America, if not the world (Appendix F, Exhibit F). Moreover, TransCanada has experience in large natural gas pipelines through its other natural TC Alaska’s organization, experience, gas and oil pipeline projects—including the Keystone | Skills, and equipment, and the ability to obtain each of these, favorably contributes to the pipeline subproject’s oil pipeline project involving over 1600 miles of 30” and 36” pipe running from Canada to the U.S. likelihood of success. The fact that TC ; ain Alaska is an experienced natural gas (Appendix F, Exhibit F). TC Alaska has constructed pipeline operator contributes to the hundreds of miles of high pressure, large diameter likelihood of success of the Project. gas pipelines in near arctic operating conditions (Appendix D, Palmer, 2/8/2008; letter to Rutz; Additional Clarifying information). Based on TC Alaska’s experience, and for the other reasons discussed in the Appendix F, the commissioners conclude TC Alaska has the ability to comply with the schedule it proposed for the Project, and with the more conservative schedule estimated by the Technical Team and used by the commissioners to estimate the NPV of the Project. In addition, as the Technical Team concludes, TC Alaska’s organization, experience, skills, and equipment, and the ability to obtain each of these, favorably contributes the pipeline subproject’s likelihood of success. The fact that TC Alaska is an experienced natural gas pipeline operator contributes to the likelihood of success of the Project. ii. TransCanada’s Record of Performance on Other Projects Another factor the commissioners must consider in assessing the likelihood that an applicant can successfully execute its plan is an applicant's record of performance on other projects. Section 170(c)(5)(A). This provides evidence of the applicant's capabilities (which are considered in the preceding subsection). As summarized below, TC Alaska’s record of 27 MAY 2008 3-100 AGIA Analysis of the Likelihood of Success Written Findings and Determination performance on projects not licensed under AGIA should contribute positively to the Project’s likelihood of success. Given that it is one of the largest natural gas pipeline companies in North America, it is not surprising that TransCanada has built or participated in other large pipeline projects in the past. These include a series of mainline expansions to its natural gas pipeline facilities in North America (Appendix G2, Section 5.2). Other examples of pipelines TransCanada helped build are the Energia Mayakan Natural Gas Pipeline Project in Ciudada Pemex, Tabasco and the Tamazunchale Pipeline Project in Naranjos, Veracruz (Appendix G2, Figure 20). TC Alaska also appears to be an active participant in environmental management within the industry (Application 2007, Section 2.9.1). TC Alaska’s application indicates that it annually compares its safety performance to the average of peer companies in various industry groups and organizations, including the Canadian Energy Pipeline Association, the American Gas Association’s transmission group, the Canadian Gas Association and the U.S. Occupational Safety and Health Administration (Application 2007, Section 2.9). From 1996-2006, TC Alaska has equaled or exceeded the safety performance of each of those organizations (Appendix F). Another indicator of TC Alaska’s expertise in planning and executing projects is its record in completing projects on schedule and within the cost estimates (Application 2007, Section 2.9.3).°2 During the period from 1990 to 2000, TC Alaska asserts it added 6,683 miles of pipe and over 3 million more compression horsepower to its existing natural gas pipeline network (Application 2007, Section 2.9.3). According to TC Alaska, it completed these additions within 0.6% of the budgeted amounts Application 2007, Section 2.9.3). TC Alaska also reported that it generally completed these additions on or before the originally scheduled dates and it never experienced substantial schedule setbacks Application 2007, Section 2.9.3). These pipeline projects included pipelines of the same diameter (48”) and compression units of the same horsepower that TC Alaska has proposed to install on the Project (Application 2007, Section 2.9.5). TC Alaska also states that it installed several of the pipelines within this group of facilities in the winter in areas with sporadic permafrost (Application 2007, Section 2.9.3). 8 See TC Alaska’s 2007 Annual Report at 8; see also TC Alaska’s website, available at: http://www. transcanada.com/ gas transmission/index.html, for a listing of the pipelines it owns and operates; also see Figure 3-1. 27 MAY 2008 3-101 AGIA Analysis of the Likelihood of Success Written Findings and Determination Notably, none of the public comments regarding TC Alaska’s TransCanada’s history application disputed these assertions by TC Alaska. demonstrates a positive Accordingly, TC Alaska’s assertions stand and they provide | ikelihood of success with respect to its ability to plan and execute large natural evidence supporting its ability to construct and operate long- distance, natural gas transportation facilities similar to those gas pipeline projects in near-arctic as well as other conditions likely to exist in demonstrates a positive likelihood of success with respect to its developing the Project. included in the Project. In sum, TransCanada’s history ability to plan and execute large natural gas pipeline projects in near-arctic as well as other conditions likely to exist in developing the Project. iii. TransCanada’s Record of Integrity and Business Ethics To determine the likelihood that an applicant can successfully execute its plan, AGIA also requires the commissioners to consider the applicant's “record of integrity and good business ethics.” (AS 43.90.170(c)(5)(B)). As summarized below, TransCanada’s record of integrity and good business ethics should contribute positively to the Project's likelihood of success. First, TransCanada operates over 36,000 miles of wholly-owned natural gas pipelines and maintains a sound record of pipeline safety with agencies responsible for pipeline safety in the U.S. and Canada (Appendix R5 and Appendix S2). Second, a review of FERC and NEB proceedings indicates no issues of concern at the FERC or the NEB which implicate integrity or business ethics (Appendix S2). As a regulated pipeline company TransCanada has a variety of ongoing regulatory proceedings at FERC, NEB and other agencies. On balance, those proceedings appear to involve routine regulatory matters such as rates, services, and new projects, not issues that might, depending on the nature of the proceeding, raise issues of concern regarding integrity and business ethics. Although Congress gave FERC new civil penalty authority in 2005, which FERC has exercised repeatedly against other companies, a review of FERC orders shows TransCanada and its affiliates do not appear to have been the subject of any civil penalty. (See, e.g. www.ferc.gov media releases on FERC investigations and penalties (which do not include TransCanada or its affiliates.)) Similarly, an assessment of TransCanada’s SEC filings revealed no maior litigation which implicates integrity or business ethics. Third, TransCanada has been commended for its record on the environment and corporate governance. For example, TransCanada was named to the Global 100 sustainable 27 MAY 2008 3-102 AGIA Analysis of the Likelihood of Success Written Findings and Determination corporations during the World Economic Forum in 2007 and 2008 (Appendix R5).. It also was named as a member of the Dow Jones Sustainability Index in 2006 in recognition of its practices in the areas of climate change, corporate governance, and labor practices, among others. See ld. Similarly, TransCanada has been recognized by the Canadian Coalition for Good Governance (Appendix R5). Fourth, TransCanada receives solid customer satisfaction ratings in surveys of customers of natural gas pipelines in North America (Appendix S2). Perhaps more significantly, TransCanada also received high marks from a major potential shipper, ConocoPhillips, in public comments filed by ConocoPhillips. According to ConocoPhillips, “we think highly of TransCanada and they are a valued associate in other large projects in North America.”* ConocoPhillips’s comments appear representative of how the natural gas industry as a whole perceives TransCanada, based on the publicly available information reviewed (Appendix S2). No public comments were received that expressed any concern about TransCanada’s record of integrity and business ethics. In Canada the NEB’s Pipelines Services Survey provides an assessment of shippers’ satisfaction with the quality of services of major NEB-regulated pipeline companies. In the latest survey (conducted in the first quarter of 2007) TransCanada Pipe Line Company outperformed the industry average for Canadian transmission pipelines (Appendix S2). Further, TransCanada Pipe Lines Ltd. received a Pollution Prevention Award from the Canadian Council of Ministers of the Environment for its “disciplined and cost effective approach to reducing fugitive emissions releases of methane gas from pipeline systems by finding a means of measuring and understanding the scope of the problem, followed by developing the Fugitive Emissions Management Program.” In 2005, implementation of this program avoided the release of roughly the equivalent of 201,000 tons of CO2 into the environment (Appendix S2). Accordingly, based on the information reviewed above, the commissioners conclude that TransCanada’s record of integrity and business ethics is a factor which should positively impact the likelihood of success of the Project, including the likelihood of successfully attracting firm shippers to the Project, successfully constructing the Project, and successfully operating the Project after it commences service. 3 See Public Comments filed by ConocoPhillips, Jan. 24, 2008 letter at page 5. 27 MAY 2008 3-103 AGIA Analysis of the Likelihood of Success Written Findings and Determination iv. TransCanada’s Financial Resources Another factor the commissioners must consider in assessing the likelihood that an applicant can successfully execute its plan is “the financial resources of the applicant.” (AS 43.90.170(c)(2)). The commissioners engaged Goldman, Sachs and Co. (Goldman Sachs) to review TransCanada’s financial resources, assess TransCanada’s ability to obtain project financing”, and to prepare a report summarizing its conclusions (Appendix H). Just as we did when assessing its technical capabilities, we look to TC Alaska’s parent company when assessing financial resources. We do so because of TransCanada’s clarification of the application. “TransCanada Corporation will provide irrevocable commitments to the Co-Applicants and Project lenders with respect to the total equity commitment, consistent with the Negotiated Rate capitalization structure, for the Project to secure financing” Goldman Sachs analyzed TransCanada’s funding needs for the project under both the Base Cases and across a broad range of potential outcomes. They addressed not only the P50, or midpoint cost estimate, but also the P95 cost estimate. They considered the higher interest rate scenarios. And they also considered combinations of the two (Appendix H, Sections V and VI). In its report, Goldman Sachs explains that TransCanada is a large, diversified energy company with substantial physical and financial resources, as well as a number of growth initiatives (Appendix H, Section I.E). Importantly, TransCanada has / TransCanada, through strategic and financial incentive to fulfill its obligations under its | its AGIA bidding entities, , : Foothills Pipe Lines Ltd. AGIA proposal (Appendix H, Section IX) and Goldman Sachs and TraneCanada Alaska concludes that “TransCanada, through its AGIA _ bidding Company, LLC, has the entities, Foothills Pipe Lines Ltd. and TransCanada Alaska financial wherewithal to meet the financial obligations implied in the Proposal. % TransCanada’s ability to obtain financing for the Project is addressed in later in this chapter. % Letter from Tony Palmer to Marty Rutherford, Deputy Commissioner, Alaska Department of Natural Resources, December 14, 2007 27 MAY 2008 3-104 AGIA Analysis of the Likelihood of Success Written Findings and Determination Company, LLC, has the financial wherewithal to meet the financial obligations implied in the Proposal.” It also states as follows: TransCanada has the ability to fund all of the predevelopment costs and early construction costs from company equity. As construction and procurement spending increases during the execution phase (2014-2019), we believe TransCanada would be able to raise 100% of the substantial equity funded portion of the project through internally generated cash and/or corporate debt. However, funding 100% of the project equity requirements with no equity partners or by raising additional primary equity at the TransCanada level could put financial strain and downward credit ratings pressure on TransCanada during construction. Nevertheless, we expect that TransCanada’s credit ratings would remain investment-grade and the company will be able to attract external capital to fund its commitment to the project because the strain is a temporary effect of the major financial requirements during development and project execution and the potential strategic and financial benefits of the Project to the Company are compelling. TransCanada has previously demonstrated the ability and willingness to take actions to fortify its financial profile materially if it needs to do so to maintain its credit rating. For example, in conjunction with acquiring ANR Pipeline Company in 2007, TransCanada issued additional equity. (TransCanada, 2006). Given the long lead time on the project, TransCanada could take similar, or other, actions to reinforce its credit ratings during the project development phase of the Project (Appendix H Section IV). If this occurs, or if the credit rating agencies view the Project as having a high probability of success, Goldman Sachs believes TransCanada may be able to maintain its currently strong credit ratings, even though the Project will obviously constitute a very large financial undertaking (Appendix H, Section IV). % The Goldman Sachs analysis is based on a wide range of assumptions, including but not limited to the following: The Project is a 4.5 Bef/day system to transport natural gas from Prudhoe Bay to the Alberta market hub; 25-year firm shipping contracts with market standard shipper credit requirements; Debt is non-recourse to TransCanada (i.e., the debt is ‘project debt’); Capitalization of 70% debt and 30% equity during construction; Capital cost overruns to be financed through federally guaranteed cost overrun loans; Federally guaranteed capital cost overrun loans to be repaid through shipper surcharge; and No project completion guarantee or pre-completion debt guarantee from equity sponsors is assumed. 27 MAY 2008 3-105 AGIA Analysis of the Likelihood of Success Written Findings and Determination A number of major factors support financial viability. Some of these are driven by project fundamentals that are independent of TransCanada e The Project is strategically important for the key principals: TransCanada, the Federal Government, the State of Alaska and prospective shippers; e TransCanada and the principal Alaska North Slope shippers are financially strong; e The project shows strong financial results. (Appendix H, Section II.E). In short, Goldman Sachs believes the Project has strong fundamentals, including the fact that TransCanada is financially strong and possesses the necessary financial wherewithal. It finds that the pro forma financial results are robust, even in the face of stress tests (Appendix H, Section V. D). The commissioners concur with and adopt these conclusions. Accordingly, and as more fully explained in the Goldman Sachs report, the commissioners conclude that TransCanada has the financial resources to fund the equity requirements of the Project and obtain necessary debt financing (Appendix H). c. TC Alaska Has Submitted a Reasonable Commercial Plan Which, Coupled With Economic and Political Factors, Should Help To Encourage Firm Shipping Commitments Having concluded that TC Alaska has submitted a plan that is reasonable from a technical standpoint, and that TC Alaska is technically and financially capable of executing that plan, we now turn to the commercial aspects of TC Alaska’s plan. As discussed below, we find that TC Alaska has submitted a reasonable commercial plan which, coupled with the economic, political and legal environment, appears to generate the favorable conditions needed to encourage shippers to sign firm shipping commitments. i. TC Alaska’s Commercial Plan During an open season a pipeline invites potential customers to commit to sign contracts to ship gas on the pipeline. As discussed earlier, and treated further below, the Project’s economics are robust. Moreover, as discussed below, there are a number of aspects of TC Alaska’s proposal that should be attractive to potential shippers. Accordingly, by themselves these are good reasons to believe that the Major North Slope It is highly likely that TC Alaska producers will seek to monetize their gas reserves and | will engage in commercial participate in an open season. negotiations with potential shippers to enhance the : . prospects for success. Nevertheless, TC Alaska recognizes that it may be a 27 MAY 2008 3-106 AGIA Analysis of the Likelihood of Success Written Findings and Determination challenge to convince the Major North Slope Producers to participate in the Project's open season (Application 2007, Section 2.2.3). It is highly likely that TC Alaska will engage in commercial negotiations with potential shippers to enhance the prospects for success (Application 2007, Section 2.2.3), after all, this is typical industry practice. During or before the open season process, a pipeline and its shippers often negotiate rates based on market factors and the pipeline’s estimate of project costs (Appendix G2, Section 4.1). Sometimes the pipeline and its shippers agree to negotiated rates that are lower than the rate initially offered by the pipeline (Appendix J, Section 1). Negotiations address rates, factors such as the term (length) of any firm service contract, the volume to be contracted, and various other mechanisms for sharing risk (Appendix J, Section 1; Appendix G2, Section 4). This aspect of the negotiation process for natural gas transportation service is similar in a way to the process of selling and buying a house. The seller makes an initial offer to sell its home at, say, $225,000. After a series of counteroffers by the buyer and seller, they agree on a sales price of $200,000. The fact that the parties ultimately agreed to a price of $200,000 does not mean the initial offer of $225,000 was unreasonable. In fact, in this example, the initial offer established a reasonable framework for an ultimately successful negotiation between the seller and the buyer. Similar to the initial offer to sell the house discussed in this example, the commercial terms, principally the rates, that TC Alaska has proposed to offer shippers in its Application also establish a reasonable framework for a successful negotiation, and should increase the likelihood of success of the Project by encouraging shippers to participate in the first binding open season (Appendix G2, Section 4). Exxon’s comments (see Appendix A) correctly recognize that TC Alaska’s proposed commercial terms constitute an "opening offer,” similar to the opening offer in the home sale example. The commissioners analyzed TC Alaska’s proposal from that same perspective. Thus, while it is important to understand TC Alaska’s current commercial terms, it is also important to recognize that those terms are likely to change and improve during the regulatory process, the open season process, and the process of negotiation with the Major North Slope Producers, and will likely end up at a point that is even more favorable from a shipper perspective than the reasonable terms which TC Alaska is proposing today (Appendix G2, Section 4; Appendix J, Section 1).Therefore, from an economic standpoint, the NPV that the Project would produce for the state and the Major North Slope Producers will likely only improve beyond the results discussed earlier in this Chapter. 27 MAY 2008 3-107 AGIA Analysis of the Likelihood of Success Written Findings and Determination Even under TC Alaska’s current proposal to its shippers, the Project would produce significant cash flow and a positive NPV for Major North Slope Producers and the state. As discussed in the prior Section regarding the Project's estimated NPV, the Proposal Base Case would provide the Major North Slope Producers an NPVjo of than $13.5 billion. If, as is currently typical for a major gas pipeline project, TC Alaska and the Major North Slope Producers ultimately negotiate rates in the open season process that are lower than those initially proposed by TC Alaska in its Application (what Exxon correctly terms TC Alaska’s “opening offer” to potential shippers),°” the NPV for the Major North Slope Producers and the state will be even higher. We also note that while some of TC Alaska’s initial transportation offerings favor TC Alaska as opposed to shippers, many of the proposed terms have been accepted by regulators and shippers on other large pipelines. This can be seen in Figure 18 of the Commercial Team report (Appendix G2, Section 4.2). As shown there, the key components of TC Alaska’s proposal, including the credit requirements, equity return,®° overall rate of return, capital structure, depreciable life, and rate structure, are within the range of what has been proposed and accepted for other large pipeline projects (Appendix G1). That is not to say that the commissioners endorse each of TC Alaska’s proposed commercial terms. In fact, the state retains the right to oppose any of TC Alaska’s proposed terms at FERC or the NEB. However, and without endorsing any specific term, the commissioners believe TC Alaska’s package as a whole sets forth a reasonable starting point, which is only likely to improve as TC Alaska negotiates with shippers and seeks regulatory approvals and the reviewing agencies are asked $7 As noted in Appendix G2, Section 4, it is not uncommon for potential shippers to submit binding offers in pipeline open seasons that do not fully conform to the terms offered by the pipeline or contain contingencies on the occurrence of specific events It is not unreasonable to expect that potential bidders in the open season on the Alaskan project will do the same. As further discussed in the Commercial Team report, there is little risk that a Major North Slope Producer would be unable to obtain capacity on the pipeline if it submitted a non-conforming “low bid” in the open season, because it is unlikely that a third-party lacking in North Slope gas reserves will bid for capacity Even if a low bid is rejected by TC Alaska, it is not likely that capacity will not be available if the shipper were later to offer to acquire capacity at a higher rate given that one of the challenges of the project is fully contracting the system at the beginning % The fact that TC Alaska is asking to have its return on equity set based on a 965 basis point premium to 10-year U.S. Treasuries is discussed in some detail in Appendix J where it is noted that this formula currently produces an equity return of slightly above 13.3%. That report also notes that the current TC Alaska proposal is probably less generous to TC Alaska than the “Incentive Rate of Return” approach adopted for the ANGTS project thirty years ago. The report concludes that while TC Alaska’s proposal is not consistent with the FERC’s preferred discounted cash flow (DCF”) method for setting equity returns, there is reason to believe that it will be accepted by FERC. We note, however, that the equity return that flows from that formula is still above equity returns that the NEB normally allows under a more formulaic approach than the FERC uses (Appendix S2).. 27 MAY 2008 3-108 AGIA Analysis of the Likelihood of Success Written Findings and Determination @ to require more favorable terms. Some examples of commercial negotiation outcomes, that would enhance the risk reward balance for shippers, might include: Shorter Contract Lengths. After negotiations between TC Alaska and the Producers, TC Alaska may offer a contract period that is shorter than the depreciation period. For example, they could offer contracts for 20, or even 15 years but depreciate the pipeline over 25 years. Such an offering would fit squarely within the mainstream of commercial transactions on Lower 48 projects (Appendix J, Section 1) and appear feasible from a financing perspective (Appendix H, Section VI.B (for results) and Section VI.D (for discussion)). Initial shippers could substantially benefit. In the first instance they would be able to “shed” the majority of their reserve risk. Secondarily, tariffs determined on a levelized basis would drop. Figure 3-40 shows tariffs for the Conservative Base Case, and variations of that case where the Project is depreciated over 25 years but initial shipping contracts are 20 and 15 years in duration. @ Figure 3-40. Impact of Commercial Terms of Transportation Contracts to AECO Tariff AECO Tariff $10.0. —-———— ] | $8.0 2 a = $60 $5.33 $644 $5.31 2 | £ $4.0 | = . | 3 | 2 $2.0 $- + - 20/20 20/25 15/25 Source: Black and Veatch, Appendix, G1, Section 6.7.1 Given shorter contracts and a longer depreciation period Producer net backs would improve, @ as would their NPVs, as shown in Figure 3-41. 27 MAY 2008 3-109 AGIA Analysis of the Likelihood of Success Written Findings and Determination Figure 3-41. Impact of Commercial Terms of Transportation Contracts to Producer @ NPV1o and NPV45 Producer NPV49 $15.0 $12.5 42:3 20/20 20/25 15/25 ole $12.3 $12. $11.0 TI $10.8 $10.8 o g $9.0 | § | Ks $6.0 4 " $3.0 $1.55, 815 $- 7 7 1 Aggregate Proven Reserves YTF Producers Producer NPV,5 $15.0 5 ; | 20/20 20/25 15/25 | $12.0 4 | o S $9.0 xs 2 | 2 | = $60 | $4.8 $4.6 | ia $47 $48 $45. $45 $3.0 $0.2 $0.3 $0.3 $- - ; 1 Aggregate Producers Proven Reserves YTF Source: Black and Veatch, Appendix, G1, Section 6.7.1 In such a scenario, TC Alaska would essentially be offering to take some of the reserve risk, by agreeing to bear the risk of finding shippers to contract for capacity on the pipeline over 27 MAY 2008 3-110 AGIA Analysis of the Likelihood of Success Written Findings and Determination the remaining depreciable life. If TC Alaska takes that risk, and continues to use a 25-year depreciation period, NPVs to the state and the Producers would improve, all other things being equal (Appendix G1, Section 6.7.1). Reduced ROE. The Proposal and Conservative Base Cases are modeled assuming that rates are based on a 14% return on equity (ROE). It is possible that, after negotiations, the return on equity that TC Alaska receives would be reduced from its initial offer. (Appendix J, Section 1; Appendix G2, Section 4). If the ROE were reduced from 14 to 12%, under the Proposal Base Case the “all in” tariff to the AECO Hub would decrease by $0.28/MMBtu, and the Producers’ aggregate NPV19 would increase by about $400 million (Appendix G1, Section 5.7). Increased Cost Overrun Risk Sharing. TC Alaska proposes to share some of the risk of cost overruns by taking, for five years, a reduction in its return on equity should an overrun occur. Application at 2.2-66. Given a 20% cost overrun (measured against the cost estimate at the time the FERC certificate is issued), the ROE reduction mechanism would decrease tariffs by $0.04/MMBtu from where they would otherwise be; a 40% cost overrun would decrease tariffs by about $0.09/MMBtu. The respective Producer NPV; benefits would be between $70 and $200 million, and TC Alaska NPVzge losses would be between $200 and $300 million (Appendix G1, Section 5.7). In light of common practice on other pipelines, increased cost overrun risk sharing on TC Alaska’s part would seem a reasonable possible outcome of negotiations (Appendix G2, Section 4.4). In addition to offering to negotiate rates, TC Alaska has also offered potential shippers several other commercial terms that should further increase the potential that shippers will sign firm transportation commitments. For example, a favorable aspect of TC Alaska’s proposal is its statement that it will be receptive to term-differentiated rates In addition to offering to negotiate rates, TC Alaska are rates that vary by the length of the contract term. Thus, has also offered potential shippers several other (Application 2007, Section 2.2). Term-differentiated rates shippers that sign up for a longer-term contract can obtain PP gn up 9 commercial terms that lower rates than shippers that sign shorter-term contracts. should further increase the This recognizes the increased risk that a pipeline with | Potential that shippers will sign firm transportation shorter-term contracts will, in the future after shipper commitments. contracts expire, lack sufficient shippers to allow the a : : pipeline to recover its costs. Term-differentiated rates allow the pipeline to recover its capital costs from shippers over a longer-term period, thus lowering the rates paid by shippers that sign 27 MAY 2008 3-111 AGIA Analysis of the Likelihood of Success Written Findings and Determination longer-term contracts. TC Alaska’s willingness to consider term-differentiated rates would allow @ shippers to lower their rates and transportation costs by extending the duration of their contracts. A similar approach has been successfully employed on other major natural gas pipeline systems, including the Kern River system.°° In addition, the precedent agreements TC Alaska will negotiate with shippers in the context of the open season provide another vehicle for shippers to negotiate favorable terms. A precedent agreement is a contractual agreement by the shipper to sign a firm transportation contract with the pipeline at the rates, volumes, contract duration and other terms set forth in the precedent agreement. As explained in the Commercial Team report, a precedent agreement typically will give shippers (and the pipeline) the option of terminating the agreement if certain conditions do not occur (Appendix G2, Section 4.1). Currently, TC Alaska has proposed to require shippers that terminate their precedent agreement to pay a pro rata share of all of TC Alaska’s unreimbursed development costs (Application 2007, Section 2.2). However, this term may be substantially modified during the process of negotiation that will occur between TC Alaska and potential shippers. As an example, in the Rockies Express project the precedent agreements provided shippers with the right to back out of the commitment to sign a firm shipping contract if certain milestone dates were not met (such @ as obtaining certificate authorization by specified dates, and putting segments into service by specified dates).'° Based on the experience of Rockies Express and other pipelines in the natural gas industry, it can reasonably be expected that shippers will be able to negotiate similar protections with TC Alaska (Appendix G1, Section 4.1). Further, TC Alaska is providing prospective shippers with TC Alaska’ is providing prospective shippers with an an equity ownership interest in the project (Application important negotiated term by 2007, Section 2.2.3.8). An anchor shipper is a shipper that | Offering anchor shippers an equity ownership interest in the project. an important negotiated term by offering anchor shippers makes a firm commitment to contract for a large volume of a new pipeline’s capacity, typically in exchange for a more favorable (lower) rate than the pipeline offers to non-anchor shippers. Here, TC Alaska has °° See, Kern River Gas Transmission Company, 94 FERC {| 61,115 at p 61,439 (2001). 100 Rockies Express Generic Precedent Agreement at 3, located at: http://www. kindermorgan.com/business/gas_pipelines/rockies_express/PA_Rockies_Express_12-17-05.pdf 27 MAY 2008 3-112 AGIA Analysis of the Likelihood of Success Written Findings and Determination extended the anchor shipper concept beyond the concept of lower rates by offering anchor shippers the ability to own a portion of the Project. As a part-owner of the Project, shippers will be able to influence the terms and conditions that are offered by TC Alaska and also reduce their overall costs of shipping gas by sharing in the profits of the project as part owners. Partial ownership may also give an anchor shipper the ability to control cost overruns through the owner/shipper’s influence over project development (Appendix G2, Section 4.3). A notable example of this anchor shipper concept is the Rockies Express pipeline. There, ConocoPhillips agreed to become an anchor shipper in exchange for a partial ownership interest in the pipeline, which is majority-owned by an independent pipeline company (Kinder Morgan). TC Alaska’s willingness to offer the Major North Slope Producers a similar equity ownership interest will enhance its ability to attract them to the Project as anchor shippers, either during or after the first open season process. In sum, these elements of TC Alaska’s initial proposal to potential shippers, including the ability of shippers to enter into even more favorable negotiated rates than the rates currently proposed by TC Alaska, enhance the Project’s likelihood of success. ii. TC Alaska’s Plan To Manage and Insulate Shippers From Cost Overruns AGIA directs the commissioners to consider how TC Alaska’s proposes to manage cost overruns and to insulate shippers from the effect of cost overruns. (AS 43.90.170(c)(1)). There are two aspects to this evaluation. The first can be broadly viewed as “technical.” “Managing cost overruns” is done, in part, through an engineering and management plan for doing so. An overall technical work plan that is specific, reasonable, and feasible stands a better chance of producing good outcomes, with regard to cost overrun risk, than one that is not. Specific aspects of the work plan that directly go to the question of managing cost overruns were also addressed in the commissioners’ assessment of TC Alaska’s proposal. These include: e Is the cost estimate methodology appropriate? ¢ Does the cost estimating process have means to establish the risk of cost overruns? e Are reasonable contingency levels applied to the overall cost estimate? ¢ Does the risk management plan list major risks and an assessment of their impact on the subproject, as well as an appropriate mitigation plan? 27 MAY 2008 3-113 AGIA Analysis of the Likelihood of Success Written Findings and Determination The commissioners’ assessment of these factors has been discussed previously in this chapter. The Technical Team addressed these and other questions that are directly relevant to the Applicant's plan for managing cost overruns. They determined that TC Alaska’s plan contributed positively to the project's likelihood of success, meaning that the plan was a good one (Appendix F, Exhibit F). The commissioners agree with their analysis and find that TC Alaska has a good technical plan for managing cost overruns. The second aspect of addressing cost overrun risk is commercial. In the end, shippers should be encouraged to participate in an open season. Given the fact that shippers have incentive to reduce their exposure to cost overrun risk, they are more likely to participate in an open season if this risk is smaller. Accordingly, the statute directs the commissioners to assess the extent to which TC Alaska will take actions that insulate shippers from this risk. For reasons discussed below, the commissioners find that TC Alaska’s proposals for addressing cost overrun risks help encourage shippers to participate in an open season. First, TC Alaska’s proposals remove any incentive that TC Alaska might have to permit cost overruns. Second, TC Alaska’s proposals create The commissioners _ find that TC Alaska’s proposals for addressing cost overrun incentives for TC Alaska to avoid cost overruns. And third, in indicating a willingness to negotiate commercial terms with | risks help —_ encourage shippers (Appendix G2, Section 4), we expect that TC Alaska lei lla idea may take further actions in this regard. to insulate shippers from cost overruns. In addition, the allocation of responsibility for cost overruns, and the risks associated with cost overruns, are likely to be the subject of intense negotiations between TC Alaska and its potential shippers. Thus, like the negotiated rates issue just discussed, it seems likely that TC Alaska ultimately will agree to address cost overruns in a way that is even more favorable to shippers as compared with its initial proposal and offer to shippers (Appendix G2, Section 4.4). TC Alaska has proposed several measures which help to insulate TC Alaska Hee shippers from the risk of cost overruns. First, TC Alaska has proposed several proposed to use Federal Loan Guarantee funds in a way that would | Measures which help to insulate shippers from the risk of cost overruns and encourages TC Alaska to control cost overruns. overruns. help hold down tariff rate increases due to the costs of financing cost Specifically, TC Alaska proposes to use Federal Loan Guarantee 27 MAY 2008 3-114 AGIA Analysis of the Likelihood of Success Written Findings and Determination funds to finance cost overruns using 100% debt (Application 2007, Section 2.2.3.1). This has the effect of making the financing cost for such facilities as low as possible since the cost of debt guaranteed by the U.S. government is anticipated to be the lowest cost source of capital available to TC Alaska. And, in particular, it is considerably less costly than equity. The lower financing rate would be reflected in proportionately lower increases in the tariff rates from cost overruns than would otherwise occur. As shown in Figure 3-42, compared with maintaining the 75/25 debt-equity ratio of the base project, TC Alaska’s cost overrun financing proposal would reduce tariffs by nearly $.18/MMBtu for a 20% cost overrun, and $.35/MMBtu for a 40% cost overrun. Figure 3-42. Tariff Consequences of Cost Overruns With and Without 100% Debt Financing Tariff $10.0 -——— — @GTP GQAKPipeline @ Yukon-BC @ Alberta $8.0 ---- Z ssa 8597 pest L $5.35 ae 5 0 $4.73 = f $4.0 5 z $2.0 $0.0 Base 20% Cost 20% Cost 40% Cost 40% Cost Case Overunw Overrun Overunw Overrun Loan w/o Loan Loan w/o Loan Source: Black and Veatch, Appendix G1, Section 5.7.8.1 In addition, TC Alaska’s proposal to fund cost overruns with 100% debt would help to align the interests of TC Alaska and its shippers in controlling cost overruns, because TC Alaska would not earn any additional return should an overrun occur. Having no additional equity in the project means that TC Alaska could earn no additional profits. In other words, TC Alaska will 27 MAY 2008 3-115 AGIA Analysis of the Likelihood of Success Written Findings and Determination not profit from cost overruns, and thus would have no incentive to permit Project costs to increase.’ This is shown in Figure 3-43 (EconOne 2008). Figure 3-43. TransCanada NPV8.8 Sensitivity Consequences of Cost Overruns102 With and Without 100% Debt Financing TransCanada NPV3.3 $15.0 $12.0 “n © oO $6.0 $ Billions (2008) $3.0 $0.0 Base Case 20% Cost 20%Cost 40% Cost 40% Cost Overrun w/ Overrun) Overrunw/ = Overrun Loan w/o Loan Loan w/o Loan Source: Black and Veatch, Appendix G1, Section 5.7.8.1 Second, TC Alaska has proposed to insulate shippers from at least some of the effects of cost overruns by offering to absorb, to the extent cost overruns occur, up to a 200 basis point reduction in its equity return (i.e., a reduction from a return on equity of 14 to 12%) for up to five years (Application 2007, Section 2.2.3.6). This proposal does not have a large impact on the rates paid by shippers due in substantial part to the fact that TC Alaska has proposed a shipper-friendly capital structure with an equity ratio of only 25% upon FERC approval of the Project's capital costs. Nevertheless, TC Alaska’s agreement to reduce its return on equity by up to 200 basis points is more than just a symbolic ba Appendix A, Exxon Comments. 102 A discount rate of 8.8% is equal to the TransCanada weighted average cost of capital for the Proposal Base Case. 27 MAY 2008 3-116 AGIA Analysis of the Likelihood of Success Written Findings and Determination gesture on its part. Rather, it represents a material portion of its potential benefits from the project. Accordingly, the ROE penalty that TC Alaska offers should give it an additional incentive to control costs and prevent cost overruns. This is especially the case because, as discussed above, TC Alaska’s proposal would remove any incentive to allow a cost overrun. In addition, it should be noted that FERC and NEB also will review costs to determine whether they were prudently incurred. Thus, there are regulatory protections available to shippers if TC Alaska attempts to include imprudently incurred costs, including cost overruns, in its tariff recourse rates. In addition, the state would have the right to join shippers in opposing the recovery of imprudently incurred costs at FERC or the NEB. Third, TC Alaska is proposing to allow negotiated rate shippers an option to defer payment of costs associated with cost overruns whenever market conditions do not allow such costs to be recovered (Application 2007, Section 2.2). This would help to ensure that shippers are not put into a negative cash flow condition to pay for cost overruns. At the same time, TC Alaska would only recover costs associated with cost overruns when that can be accomplished while still providing a positive net back to the upstream producers. This element of TC Alaska’s proposal would help reduce the potential impact of cost overruns on its shippers. This proposal—if accepted by the US DOE as part of an acceptable loan guarantee package under ANGPA— would have involve the Federal Government share in the risk of poor net backs If approved it would provide shipper something of a price floor. Such a mechanism would appear to have been contemplated in the loan guarantee’s authorizing legislation: LOAN TERMS AND FEES: The Secretary may issue Federal guarantee instruments under this section that take into account repayment profiles and grace periods justified by project cash flows and project-specific considerations. [Sec. 116 (d)(1)] Fourth, and as discussed earlier, TC Alaska has proposed that shippers who participate in the first binding open season will have the opportunity to obtain an equity ownership interest in the Project (Application 2007, Section 2.2). At this early stage of the process, TC Alaska has not fully Another means of helping to insulate shippers from cost overruns is the defined how an interested party can obtain an negotiated rate concept that TC Alaska has indicated a willingness to offer its shippers. equity ownership interest. However, that process will likely be fully fleshed out in the notice of the open season. Through equity participation shippers can have a “seat at the table” regarding activities that might give rise to cost increases, giving them an enhanced ability to prevent cost 27 MAY 2008 3-117 AGIA Analysis of the Likelihood of Success Written Findings and Determination overruns. The concept of shipper ownership of an equity interest in a pipeline project is familiar to the Major North Slope Producers; ConocoPhillips has a minority ownership interest in the Rockies Express project as well as a substantial shipping commitment Finally and as also discussed above, another means of helping to insulate shippers from cost overruns is the negotiated rate concept that TC Alaska has indicated a willingness to offer its shippers (Application 2007, Section 2.2). Negotiated rates are common on new pipelines in the Lower 48 (Appendix J, Attachment 1A). Through negotiated rates shippers and TC Alaska can agree to risk sharing arrangements that satisfy both parties. As an example, the Rockies Express pipeline (commonly referred to as “REX”), which is presently under construction, allowed potential shippers that elected negotiated rates to base their rates on the actual cost of steel—upward or downward from a stated dollar amount per ton.’ Given the substantial bargaining power of the Major North Slope Producers, it is reasonable to expect that TC Alaska and its shippers may agree to negotiated rates with similar provisions that insulate shippers from a major portion of any cost overruns (Appendix G1). In fact, in some cases parties agree to negotiated fixed rates for the life of the contract— regardless of the level of cost (Appendix J)."“ The use of negotiated fixed rates provides shippers with the ability to protect themselves against some or all cost overruns. In this regard, it is notable that negotiated rates are often lower than the FERC’s cost-based recourse rates (Appendix J). By negotiating rates that are less than the recourse rates, shippers can mitigate or eliminate their exposure to cost overruns that would increase recourse rates above the rate the shippers negotiated (Appendix J). Notably, the Major North Slope Producers have numerous firm shipping contracts on other pipelines where they have negotiated a fixed rate and eliminated their exposure to cost overruns (Appendix R and Appendix J) Similar negotiated rates, which at a minimum shift a significant part of the risk of cost overruns to the pipeline, are also likely on this Project. While TC Alaska has indicated a willingness to offer negotiated rates to its shippers, and has proposed an initial 103 The Precedent Agreement can be found at the following webpage: http:/Awww.kindermorgan.com/business/gas_pipelines/rockies_express/PA_Rockies_Express_12-17-05.pdf. 104 Although this is important to recognize for illustrative purposes, it is an outcome that is highly unlikely on this project. TransCanada’s total NPVg.s is about $4.5 billion under the Proposal Base Case — a third of the Producers’ NPVio benefits (see Appendix F.1, Section 5.5. A significant cost overrun could essentially wipe out TransCanada’s return under a fixed-tariff arrangement. Accordingly, it is more likely that this project will be marked by some middle ground risk sharing. 27 MAY 2008 3-118 AGIA Analysis of the Likelihood of Success Written Findings and Determination set of negotiated rate terms, the bargaining power of the Major North Slope Producers would likely dictate that result in any event. | i 0 TC Alaska h d uilcunyselninyviannd ail) Because TC Alaska has proposed several several means of controlling and mitigating the means of controlling and mitigating the impact of cost overruns, shippers will have | impact of cost overruns, shippers will have i : options to help insulate themselves from options to help insulate themselves from or or substantially mitigate the potential substantially mitigate the potential impact of impact of cost overruns. Overall, these proposals contribute positively to the Project's likelihood of success. cost overruns. Overall, these proposals contribute positively to the Project’s likelihood of success. d. TC Alaska’s Ability To Overcome Barriers To Obtaining Firm Shipping Commitments As discussed earlier, TC Alaska’s proposed commercial terms provide a framework that should encourage shippers to sign firm shipping commitments. Despite that fact, however, significant barriers still exist which TC Alaska will need to overcome to obtain firm shipping commitments. This Section of the Findings concludes that TC Alaska has a reasonable opportunity to overcome those barriers, assuming it receives the AGIA License. As discussed below, due to the Project's strong economics, it is reasonable to conclude that the Major North Slope Producers, TC Alaska, the U.S. government, and the state will take actions that are necessary and appropriate to make the Project a success. The risks to the parties of not progressing the Project , including the loss of profits, are too great. Whether TC Alaska can obtain long-term firm shipping commitments from the Major North Slope Producers (and potential other shippers) for the initial capacity of the Project will have a critical impact on whether the Project succeeds or fails.‘ Natural gas pipeline companies rarely if ever construct a major project “on spec,” i.e., on the speculative hope that shippers will sign firm contracts and a market will materialize after the construction of the project. Before ordering pipe and commencing construction, a company typically must secure long-term firm contracts. Long- 15 In its Application, TC Alaska raises the possibility of seeking additional Federal government assistance for the project (Application 2.2.3.2). Conceptually, even absent firm shipping contracts. the US Government could act as a “bridge shipper” while the project continued to be developed, If this were to occur long-term firm shipping contracts might not be required to advance the project to completion. The “bridge shipper” concept, while innovative, was not a condition of the Application (Appendix D, Palmer Letter March 12, 2008). “Additional Clarifying Information”) It has not been assumed in any of the analysis of this finding. 27 MAY 2008 3-119 AGIA Analysis of the Likelihood of Success Written Findings and Determination term firm contracts, which enable the project to secure financing and, if necessary or desirable, additional equity investors, constitute the economic foundation of a major natural gas pipeline construction project. In ordinary circumstances, the prospects that the Project could secure firm shipping commitments would be excellent, even after Even using a conservative price projection for natural gas, the Project would likely result in recognizing the unique size and scope of an Alaskan gasline project (Appendix G2, Section 4.1). As significant cash flows, a positive explained previously in this Finding, even using a NPV, and a large internal rate of return for the Major North Slope Producers. conservative price projection for natural gas, the Project would likely result in significant cash flows, a positive NPV, and a large internal rate of return for the Major North Slope Producers. There are reasonable prospects for some further improvement in shipper economics after negotiations with TC Alaska over contract terms (Appendix G2, Section 4). In addition, the economics of the Project for the Major North Slope Producers (and the state) are likely to improve even further because TC Alaska has offered to enter into firm shipping commitments on commercial terms that are likely to become more attractive after TC Alaska negotiates those terms with the Producers, who possess considerable bargaining power. In addition to the strong economics which the Project would provide, TC Alaska is an experienced pipeline company, with a proven track record as a In a normal, competitive situation in which the production basin has numerous producers seeking to dependable pipeline owner and operator. According to ConocoPhillips, TC Alaska is a “fine company,” and a “valued business associate throughout North America.”" In a normal, competitive situation, in which the production basin has numerous producers seeking to commercialize their reserves, these factors—a project with strong economics and a strong pipeline Operator that has initial made ___ reasonable transportation offers to potential shippers to enter commercialize their reserves, these factors—a_ project with strong economics and a strong pipeline operator that has made reasonable transportation offers to potential shippers to enter into firm shipping agreements—would make it likely that a pipeline project to bring Alaska’s gas to market would obtain the necessary firm shipping commitments. initial 108 See Jan. 24, 2008 Letter from Mr. J. L. (Jim) Bowles, President of ConocoPhillips Alaska, Inc. to The Honorable Sarah Palin, at page 5. We also noted that ConocoPhillips is a joint venture partner with TransCanada in the Keystone oil pipeline project. 27 MAY 2008 3-120 AGIA Analysis of the Likelihood of Success Written Findings and Determination into firm shipping agreements—would make it likely that a pipeline project to bring Alaska’s gas to market would obtain the necessary firm shipping commitments. Actual experience in the United States in the past 15 years shows that natural gas producers have supported the construction of new, independent pipelines to ship gas from emerging production basins to various markets when similar conditions have existed. For example, the Kern River Gas Transmission pipeline—an independent gas pipeline not affiliated with major natural gas producers—was constructed in the early 1990s to transport gas from the Rockies to southern California, with the key support of a number of natural gas producers that committed to sign firm shipping contracts with the pipeline.” More recently, the Rockies Express pipeline has been developed to transport gas from the Rockies to markets in the eastern and central U.S. Like Kern River, Rockies Express obtained the support of natural gas producers, including ConocoPhillips and BP that supported the pipeline by signing firm transportation contracts.'°® Although Rockies Express has been developed by a majority owner which is an independent pipeline (Kinder Morgan), the original impetus for the project came from a major producer of natural gas (Encana) seeking to find a market for supplies which previously had lacked sufficient pipeline access to consuming markets. ‘°° As these examples demonstrate, when a production basin has less pipeline capacity than the amount of gas production, and when prices support construction of new pipeline capacity, a significant number of natural gas producers typically will facilitate new pipeline construction out of a production basin by signing firm shipping commitments after a process of negotiation with the pipeline sponsor over key commercial and tariff terms. For producers like these, signing firm contracts makes economic sense because the new pipeline capacity enables them to sell more gas, obtain higher prices for their gas, and make more profits. ‘07 Kern River Gas Transmission Co., 50 FERC {] 61,069 (1990). 18 Rockies Express Certificate Application at 32 (Docket No. CP06-354-000, filed May 31, 2006), as amended by the reivsed “shipper table” in the supplement to application filing at Appendix A (filed July 28, 2006). ConocoPhillips is also a minority owner of Rockies Express, while BP is a shipper only. ConocoPhillips Press Release, ConocoPhillips Completes Acquisition of Interest in Rockies Express Pipeline, located at: http://www.conocophillips.com/newsroom/news_releases/2006news/06-30-2006.htm 109 Rockies Express Pipeline, 116 FERC {| 62.151. at p. 64,447. ConocoPhillips is also a minority owner of Rockies Express. See /d. at n. 107. 27 MAY 2008 3-121 AGIA Analysis of the Likelihood of Success Written Findings and Determination In contrast with these examples of producer-supported, basin-opening pipelines, the Project has not yet received non-binding indications of support from the Major North Slope Producers, although at least one explorer has filed comments in support of the project (Appendix / All of the major stakeholders—including A)."70 Instead, the Major North Slope TC Alaska, the State of Alaska, the U.S. government, and the Major North Slope Producers—have a significant interest in not support the Project, at least in its current ensuring that the Project succeeds. Each stakeholder has a great deal at stake. Producers have filed comments stating they do ee Thus, it is reasonable to assume that each have proposed their own project. This Section of those stakeholders will take the actions will examine the Major North Slope Producers’ necessary to ensure that, at the end of the day, the project eventually receives the firm shipping contracts that it needs to which constitutes the biggest potential barrier \ proceed without undue delay. opposition to the TC Alaska Project in detail, to the Project's success. As discussed below, despite the current refusal or reluctance of the Major North Slope Producers to support the Project, TC Alaska nonetheless has a reasonable likelihood of succeeding if it receives the AGIA License. i. The Stakeholders in the Project Have a Strong Interest in Seeing the Project Succeed. All of the major stakeholders—including TC Alaska, the State of Alaska, the U.S. government, and the Major North Slope Producers—have a significant interest in ensuring that the Project succeeds. Each stakeholder has a great deal at stake. Thus, it is reasonable to assume that each of those stakeholders will take the actions necessary to ensure that, at the end of the day, the Project eventually receives the firm shipping contracts that it needs to proceed without undue delay. Indeed, as recognized by Goldman Sachs, “the Project is strategically important for all key principals: TC Alaska, the Federal Government, the State of Alaska and prospective shippers” (Appendix H, Section II.E). A brief review of these stakeholders’ interests follows: TC Alaska as Stakeholder. TC Alaska has strong incentives to make its proposed Alaska natural gas line to Alberta become a reality. TC Alaska stands to realize a significant amount of "1° See Comments filed by Anadarko on March 6, 2007. 27 MAY 2008 3-122 AGIA Analysis of the Likelihood of Success Written Findings and Determination direct revenue from the Project under the Proposal Base Case, the Conservative Base Case, and the Low Volume Sensitivity Case. (Appendix G1, Section 6.4.2) Figure 3-44. TransCanada NPV8.8 For Different Project Configurations""’ TransCanada NPV¢5.3 $10.0 45 Befid 4.0 Befld 93.5 Befid $8.0 - =a: ae o S $6.04 ee a x g $4.5 = $3.8 a $4.0 4 nA $2.0 4 $0.0 4 4.5 Befid 4.0 Befid 3.5 Befld Source: Black and Veatch, Appendix G1, Section 6 However, TC Alaska’s motivation to see this Project succeed goes far beyond the direct revenue from the Project. It is important to TransCanada to maintain its profile in the financial community as a company with strong growth potential. The TC Alaska Project would enhance this profile, and is therefore important to TransCanada. According to Goldman Sachs: TransCanada’s growth beyond 2010 at a level consistent what it has achieved to date is less certain, and TransCanada has emphasized the Alaska gas and Mackenzie pipelines as sources of long-term growth. Further, TransCanada currently has the largest natural gas transportation footprint in Canada, with the Foothills Pipeline forming the pre-build for the Alaska natural gas pipeline project. ‘'t A discount rate of 8.8% is equal to the TransCanada weighted average cost of capital for the Proposal Base Case. 27 MAY 2008 3-123 AGIA Analysis of the Likelihood of Success Written Findings and Determination TransCanada is clearly heavily incentivized to utilize, and should benefit from its ability to leverage, its existing asset footprint in Western Canada to bring Northern gas to market (Appendix H, Section IX). In addition, TransCanada will use Alaskan gas to offset a substantial decline in Canadian production which threatens to result in significant underutilization of its existing pipeline system in Canada. TransCanada is the largest natural gas pipeline company in Canada, with approximately 29.5 Bcf/day of capacity on various pipelines that deliver gas to markets across Canada and to U.S. pipelines for further transportation to U.S. markets.” It is widely projected that natural gas production in Canada has leveled off and will decline in the near future, causing a reduction in throughput on TransCanada’s pipelines (Appendix H; G1; F and J). Thus, in its public comments Anadarko observes that “due to the expected decline in indigenous gas production in the Western Canadian Sedimentary Basin and the growth of Albertan natural gas demand, this project is of critical strategic importance to TC Alaska in terms of offsetting declining throughput on its existing transcontinental pipeline system” (Appendix A, Anadarko Comments). TC Alaska also needs Alaskan gas because increased Canadian consumption is projected to decrease the gas available to flow through TC Alaska’s pipelines to U.S. markets. According to TC Alaska itself, growth in natural gas consumption in Alberta will reduce the amount of natural gas available for transportation on pipelines to the U.S. by approximately 1.9 Bcf/day. This will create further underutilization of TC Alaska’s existing pipeline system.'’? Even assuming that construction of the MacKenzie Valley Pipeline occurs, TC Alaska’s existing natural gas pipeline system in Canada would have significant excess capacity (Appendix G2, Section 3.3). Based on these market developments, TC Alaska will face the daunting prospect of a severely underutilized pipeline system unless it can connect its system to new sources of supply. By constructing the Project, TC Alaska stands to increase the competitive position of its existing downstream pipelines, which would receive gas from the Project and transport it to markets and pipelines located beyond the AECO Hub.'* TC Alaska thus has an incentive to offer a set of commercial terms and take other necessary and appropriate actions that will induce the Major ‘2 TransCanada Corporation web-site, available at http:/Awww.transcanada.com/gas_transmission/index.html. "3 See Appendix H, Section IX., Appendix G2, Section 3.3, and Appendix J, Section IV; and Appendix A, Anadarko Comments. "4 As throughput on these downstream pipelines rises their tariffs will fall, thus making more economic continued gas exports from Canada into the U.S. market. 27 MAY 2008 3-124 AGIA Analysis of the Likelihood of Success Written Findings and Determination North Slope Producers to sign firm transportation agreements. TC Alaska should be highly motivated to have the Project succeed, whether or not the first binding open season attracts firm commitments. TC Alaska’ strong interest in moving the Project forward represents a positive contributing factor to the Project's likelihood of success. United States as Stakeholder. A sometimes overlooked fact, which also contributes positively to the Project's likelihood of success, is that the United States government also has a strong incentive to see the Project succeed, for at least four reasons. First, and as confirmed by a recent EIA study, Energy Information Administration, Analysis of Restricted Natural Gas Supply Cases, at 8 (2004), the Project would reduce the price of natural gas in the U.S. below the price it would otherwise be if the Project were not built. Natural gas prices in the U.S. are at high historical levels. Higher natural gas prices have a significant impact on U.S. consumers, which rely on natural gas as a source of heat for their homes and schools, to generate electricity which provides air conditioning during the summer, and as a source of fuel or a feedstock for factories and other businesses. Higher energy prices, including prices for natural gas and oil, have a dramatic negative impact on the U.S. economy and U.S. consumers. While no one would contend the Project will solve the Nation’s energy problems by itself, it is an important step in the right direction. The Project would supply 6-7% of the total U.S. natural gas demand projected for the year (see EIA AEO), providing an important source of supply to help moderate or reduce the price of natural gas and electricity. Second, the Project will help enhance the Nation’s energy security. Production of natural gas from many domestic production areas is flat or declining’ (Appendix G1, Section 3). The U.S. must find new sources of supply. LNG is widely expected to play an increasing role (EIA AEO, Wood Mackenzie study). Even assuming Alaskan gas is brought to market in 2020, EIA projects that LNG imports from other countries are projected to increase by 1.4 Bcf/day in 2008 to 7.7 Bef/day in 2030. (EIA 2008) Without Alaskan gas U.S. dependence on LNG imports from the Middle East and elsewhere will grow. Alaska’s natural gas offers an important part of the solution to this problem. A third reason which should provide the U.S. government with a strong incentive to support the Project is the significant environmental benefit associated with the Project. Natural gas constitutes the cleanest burning fossil fuel, with significantly fewer emissions of carbon and "8 The Rockies are a notable exception. 27 MAY 2008 3-125 AGIA Analysis of the Likelihood of Success Written Findings and Determination other pollutants than oil and coal. For example, if fifty percent of the natural gas from the Project were used to displace coal-fired electric generation, the Project would provide enough energy to displace between 120-190 coal-fired electric generation plants.'*® With climate change initiatives gaining momentum at the state and federal levels, Alaska’s natural gas can play a significant role in efforts to reduce greenhouse gas emissions in the U.S. Finally, the U.S. Government will gain billions of dollars in revenue once the Project is completed. The U.S. government would receive over $24 billion in royalty and corporate income taxes regardless of the Project’s configuration (Figure 3-45). With pipeline expansions, facilitated by AGIA’s rolled-in rate provisions, this figure could go considerably higher. Based on the NETL study, it is reasonable to assume that roughly half of YTF gas, including project / if fifty percent of the natural gas from the expansions, will originate from Federal lands | Project were used to displace coal-fired electric generation, the Project would provide enough energy to displace percentage of U.S. Government income could between 120-190 coal-fired electric (Appendix L). Accordingly, the royalty generation plants. With climate change initiatives gaining momentum at the state alone should provide the U.S. government with | and federal levels, Alaska’s natural gas can a major economic incentive to take action if | Play @ significant role in efforts to reduce areenhouse aas emissions in the U.S. be expected to significantly climb. This fact necessary to facilitate the construction of an Alaskan natural gas pipeline. "© The displacement number depends on the size and efficiency of the plants in question. For the illustrative purposes here, we assume here that the plants have a capacity of 66.74 megawatts — the average sized plant that EIA described as being planned for 2007-2011; see http:/Avww.eia.doe.gov/cneaf/electricity/epa/epat2p5.html. The amount of electricity generated from natural gas depends on the conversion efficiency (or heat rate) of the plant. The average heat rate for natural gas power varies from 7,502 Btu/kWh to 11,664 Btu/kWh; see htto://www.eia.doe.gov/cneaf/electricity/epa/epata6.html 27 MAY 2008 3-126 AGIA Analysis of the Likelihood of Success Written Findings and Determination Figure 3-45. U.S. Government NPV; For Different Project Configurations U.S. Government NPVs $80.0 eee ca $70.0 $60.0 - $50.0 - - ---- $40.0 snd $30.5 : $28.5 $ Billions (2008) $20.0 $10.0 4 4.5 Bcfid 4.0 Befid 3.5 Befid Source: Black and Veatch, Appendix G1, Section 6.4.2 The additional revenues to be realized by the U.S. treasury and the Project's ability to reduce energy prices for U.S. consumers, enhance energy security, and provide environmental benefits, all provide strong incentive for the U.S. government to help an Alaskan gas pipeline succeed. Additional Federal support, such as the “bridge shipper” concept suggested by TC Alaska in its Application (Application 2007, Section 2.2.3.1(4)), may make sense given the benefits that the U.S. Government and its citizens would receive.'"” The State of Alaska as Stakeholder. The State of Alaska has clear incentives to facilitate the construction of a natural gas pipeline which commercializes North Slope natural gas reserves. The state would receive substantial revenue from royalty and taxes. State NPV; ranges from over $51.6 billion to $66.1 billion depending upon the project's throughput (from 3.5 Bcf/day to 4.5 Bef/day). "'7ANGPA contemplates that the U.S. Government could play an augmented role if private sector progress is not sufficient (ANGPA 15 USC 7209(b)(1)) if the parties do not act to advance a project soon. Indeed, the Federal Gas Pipeline Coordinator Drue Pierce has suggested that an Alaska gasline is so important that it could merit a federal takeover of the project if the parties do not act to advance a project soon. Associated Press, Congress Questions Gas Line progress, located at: http:/www.adn.com/money/indistries/oil/pipeline/story/297218.html (January 29, 2008). 27 MAY 2008 3-127 AGIA Analysis of the Likelihood of Success Written Findings and Determination Figue 3-46. State NPV; For Different Project Configurations State NPV; $70.0 $66.1 = $60.7 4.5 Bcfid 4.0 Bcfid Source: Black and Veatch, Appendix G1, Section 6.4.2 This would help offset the declining revenues associated with declining North Slope oil production increased revenues would also help augment the continued health of the Permanent Fund. In addition to the revenue that the Project would generate, the state has a strong incentive to see that the Project proposed by TC Alaska succeeds because of the unique benefits the Project would provide. As discussed in detail in Chapter 5 of these Findings, TC Alaska’s TC Alaska’s unconditional commitments, including enforceable commitments to Project has committed unequivocally to AGIA’s move the Project forward by holding an true open access and tariff requirements that | pen season and filing for a FERC certificate by specific dates, provide the are essential to meeting the state’s needs. best opportunity to achieve critical state These benefits would not have been secured goals, including long-term jobs for Alaskans and natural gas supplies for in- by the proposed SGDA contract, nor were Sato Use commitments to them offered by ConocoPhillips’ proposal from the fall of 2007 or by the most recent Producers Proposal. TC Alaska’s unconditional commitments, including enforceable commitments to move the Project forward by holding an open season and filing for a FERC certificate by specific dates (Application 2007, Section 2.2.4.3), provide the best opportunity to achieve critical state goals, 27 MAY 2008 3-128 AGIA Analysis of the Likelihood of Success Written Findings and Determination including long-term jobs for Alaskans and natural gas supplies for in-state use. In short, because the Project makes real commitments, it stands to provide Alaskans with real benefits too. To ensure that Alaskans finally achieve these and other benefits that an Alaska natural gas pipeline would bring, the state has a strong incentive to use its sovereign authority to ensure that the Project succeeds. The state has already exercised that authority by providing the incentives set forth in AGIA. Given the extraordinarily profitable economics that the Project would produce, there is no demonstrated need for further state incentives at this time. Nevertheless, should a need be demonstrated in the future, the state has several options to encourage construction of the Project. As discussed below, these include: (1) providing additional upstream incentives to encourage the Major North Slope Producers to sign firm contracts on the Project; and (2) enacting a reserves tax that would apply to any producer which fails to sign a firm contract, (3) investigating whether the Major North Slope Producers have violated their leases or other applicable laws (such as antitrust laws) by failing to produce Alaska’s gas, (4) initiating litigation over any such violations, either at the state or federal level (as applicable). The Major North Slope Producers as Stakeholders. As discussed earlier, the Major North Slope Producers stand to make huge profits from the sale of Alaskan gas if the Project is built (Appendix G1, Section 5.2). They have a duty to their shareholders to seek profits and should be expected to behave as rational commercial players. The fact that BP and ConocoPhillips have proposed the Producer Project strongly suggests that those two producers agree that the economics of a major gas pipeline project to the AECO Hub are favorable.""® It tends to support the commissioners’ conclusion that TC Alaska’s Project, which would follow the same general route as the Producer Project, would provide a significantly positive NPV for the Major North Slope Producers. Despite this, they have refused thus far to support the TC Alaska Project. In the discussion that follows, we will analyze their objections to the Project, and the impact of those objections and the Denali proposal on the Project's likelihood of success. "18 Adams, Mikaila, BP, ConocoPhillips Put Up $600M for First Leg of Alaska Gas Pipeline, Oil and Gas Financial Journal, at 12, 14 (May 2008), available at: http://www.qmags.com/download/default.aspx? pub=OGF Jandupid=13189andfl=others/OGF J/OGF_20080501_May_ 2008.pdf 27 MAY 2008 3-129 AGIA Analysis of the Likelihood of Success Written Findings and Determination ii. Risks to the Project Economics Although it would be somewhat inconsistent with the recent launch of the Producer Project, the Major North Slope Producers may contend that risks to the Project economics prevent them from supporting the Project (or moving forward with their own project). Despite huge profits that the Major North Slope Producers stand to earn by supporting the Project, the commissioners recognize that the Project economics are not free from risk. Accordingly, a detailed analysis of project risks—e.g. including gas prices, project costs, cost escalation rates, capacity subscription (project throughput), the timing of when Point Thomson gas will be available, the extent of future gas discoveries, project schedule (including the risk of delay), tariff terms, discount rates, and other factors—was undertaken (Appendix G1). However, despite those risks, on balance the Project appears to present the Major North Slope Producers with a robust profit opportunity. Net Back Risks There is always a risk natural gas prices could To generate an NPV,, of zero - meaning decline or that costs could increase. However, ; the Major North Slope Producers would the Project would be economic for the Major North Slope Producers even if prices are considerably lower than those projected by Wood Mackenzie. Indeed, to generate NPV15 of zero—meaning the Major North Slope Producers would earn a return of 15% on their gasline related investments—natural gas prices would have to drop by at least 62% in the Conservative Base Case, and 62% in the Proposal Base Case, from those forecast by Wood Mackenzie (and assuming no change in Project costs).'"? earn a return of 15 percent on their gasline related investments — natural gas prices would have to drop by at least 62 percent in the Conservative Base Case, and 62 percent in the Proposal Base Case, from those forecast by Wood Mackenzie (and assuming no change in Project costs). To put this in perspective, a price drop in excess of 60 percent in the price of gasoline would take pump prices from roughly $4 per gallon to under $1.60 per gallon. "8 In this chart, the Conservative Base Case is represented by the middle grey bar: 4.0 Bcf/d throughput, assuming 20-year contracts and a 20-year depreciation life. The Proposal Base Case is represented by the left blue bar: 4.5 Bcf/d of throughput, with 25 year contracts with a 25 year depreciation life. The results assume that project costs are held at their mid-point probability (P50) levels. 27 MAY 2008 3-130 Analysis of the Likelihood of Success AGIA Written Findings and Determination Percentage Price Drop Necessary to Generate NPV of Zero For Producers’ Proved Reserves Figure 3-47. Proven Reserves - % Price Drop for 0 NPVio © 3.5 Befid 4.0 Befid 0% -10% 4 -20% + -30% + -70% + -80% + 15/15 Contract Period/Depreciation Life (years) serves - % Price Drop for 0 NPV, Proven Re 15/15 G 3.5 Befid 4.0 Bef/d 20/20 Contract Period/Depreciation Life (years) @ 4.5 Befid 0% -10% -20% -30% 3 40% -50% 60% -70% -80% 25/25 Source: Black and Veatch, Appendix G1, Section 6.5 27 MAY 2008 3-131 AGIA Analysis of the Likelihood of Success Written Findings and Determination To put this in perspective, a price drop in excess of 60% in the price of gasoline would take pump prices from roughly $4 per gallon to approximately $1.60 per gallon. How unlikely is it that prices would drop this low? If one assumes that the Black and Veatch probability distribution over prices is correct, the chance is about 5%. The following chart shows the effect of price and cost uncertainty, considered separately, for the Proposal Base Case. The light blue-solid line shows the effects of price uncertainty while holding costs at their mid-point probability level.'2° Figure 3-48 | Aggregate Producers NPV;) - 4.5 BCF/d Proposal Base Case With and Without Price Uncertainty 100% + 7 - ~~ 4.5 AECO wi Price and TC 90% + Schedule-Cost Uncertainty : ; — -4.5 AECO wi only TC Schedule- : ' 1 | 80% + Cost Uncertainty \ t ! ! ! | 70% + i i 1 ‘ x ' ' ~— 60% +- we oe -4--e 4 a 2 4.5 AECO 3 50% + - . ! Agg. Producer NPVi9 $13.5 2 | Expected Value (WM Prices): E 40% + | ; i 1. = a 30% + - i 4 . at 20% + | : 2 | t i \ ' 10% + bo--- t t + U ; = ' 0% — + dé. | : : : + 1 -$10 -$5 $0 $5 $10 $15 $20 $25 $30 $35 $40 $2008 Billions NPV1o Source: Black and Veatch, Appendix G1, Section 5.7 Over the life of the project, there appears to be essentially no chance that overall Producer profits will be negative. "20 The dark blue-dashed line shows the effects of cost uncertainty while holding prices at their mid-point (P50) levels. 27 MAY 2008 3-132 AGIA Analysis of the Likelihood of Success Written Findings and Determination Out of concern that these results were being potentially driven by our assumptions on inflation (for gas prices) and cost escalation (for pipeline construction costs), the risk that net backs would be insufficient to cover the tariffs was further scrutinized. We considered the case of zero cost escalation and zero price escalation. The analysis was performed for the Proposal Base Case, the Conservative Base Case, and the Low Throughput cases. The results are shown in Figure 3-49. Figure 3-49. Real AECO Price Forecasts vs. Tariff + Fuel Cy re eee (Gummma 4.5 Case Tariff (Approximate Real) 4.0 Case Tariff (Approximate Real) CCT 3.5 Case Tariff (Approximate Real) ————- WoodMMackenzie AECO (Real) BV AECO Base (Real) —s— BV AECO P90 (Real) $15.0 —*— BV AECO P10 (Real) Current AECO Forw ard Price $20.0 Gas Price ($/MMBtu) $0.0 ' LEO BOBS 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 Source: Black and Veatch, Appendix G1, Section 6.7 The results indicate there is a better than 90% chance that prices will be sufficient to cover transportation costs in each and every year for both Proposal and Conservative Base Cases. If one puts price, capital cost, and schedule risks together, the overall likelihood of the Project returning negative values is still only around 5%. Figure 3-50, shows the probability that the Major North Slope Producers, in aggregate, would receive different NPV1o at different project sizes. It indicates that, across the Proposal Case, the Base Case, and Low-volume scenarios, for NPV; to be zero would require a “perfect storm.” 27 MAY 2008 3-133 AGIA Analysis of the Likelihood of Success Written Findings and Determination Figure 3-50. Aggregate Producers NPV Uncertainty for the 3.5, 4.0, and 4.5 Bcfid Cases 100% — ——— oe —~ = 3.5 Bcfid Low Volume Sensitivity Case , 4 ~~ 4.0 Befid Conservative Base Case ft 80% + = = +4.5 Bcfid Proposal Base Case 70% + -- ---- L = 2 60% + 7 = 2 50% 4 ¢ ' ' 3 | E wnt-- : Povot so pecsece 1 0% aT a eee re 4.5Case 4.0Case 3.5 Case ie Aggregate Producer NPVio $13.5 $123 $10.5 | 20% “77 Expected Value (WM Prices): 10% 4 0% $5 $0 $5 $10 $15 $20 $25 $30 $35 $2008 Billions NPVio Source: Black and Veatch, Appendix G1, Section 6.7'7' The foregoing probability charts embody only Project cost risks associated with uncertainty in Project scope. As indicated earlier (Figure 3-23), uncertainty associated with Project cost escalation is more important. We did not attempt to capture escalation cost risk in Monte Carlo probability analyses, such as the one shown above, because of the inability to provide good estimates of the probability distributions over future project cost escalation rates. The risk of Project cost escalation is real. It is always conceivable, though quite unlikely, that Project costs would significantly escalate and yet prices would be soft. However, we also believe that the risk of Project cost escalation—at least in terms of its ability to generate catastrophic results—is one that can be significantly managed. At the conclusion of the Project's Development Phase, TC Alaska will be in a position to sign many of the supply contracts required to begin construction (Application 2007, Section 2.2.1(2)(a)). The bounds of how costs may change will have significantly narrowed. Under the terms of the precedent agreement negotiated between TC Alaska and its shippers, shippers will at that time have the 121 The chart assumes Black and Veatch price probability distribution (see Appendix G1, Section 6.7.3), and the project cost scope and schedule risks developed by the Technical Team (See Appendix F, Exhibit D). 27 MAY 2008 3-134 AGIA Analysis of the Likelihood of Success Written Findings and Determination ability to withdraw from their shipping commitments (Application 2007, Section 2.2.3.3).'7 A shipper would only be expected to exercise such rights in the event that a major Project cost escalation had occurred, or a major decline in prices were expected, such that the Project was determined to be uneconomic. Reserve Risk To have a successful pipeline project, there must be sufficient gas to fill the pipeline. There are more than enough economically recoverable natural gas resources on the North Slope to fill TC Alaska’s proposed 4.5 Bcf/day pipeline for twenty-five years (or much longer), as discussed above in Chapter 2(B)(5). However, the amount of gas reserves at Prudhoe Bay and from other existing state production fields, while substantial, is not sufficient to fill the pipeline under either the Proposal or Conservative Base Cases. That means additional gas must be found and produced in order to fill the pipeline for the twenty-five year term of the firm shipping commitments proposed by TC Alaska. After carefully analyzing this issue, the commissioners conclude that the risk of insufficient reserves is not a risk that should negatively impact the likelihood of success of the Project. First, it is important to understand how profitable the opportunity to produce the Prudhoe Bay gas alone truly is to the Major North Slope Producers. Project economics, while affected by The Major North Slope Producers would receive a significantly positive NPV and make a very profitable rate upon them. As noted earlier, even if no YTF gas is of return even if the only gas they developed, at expected prices Project revenue | ver produce on the North Slope is the Prudhoe Bay and state existing gas. Thus, the Project could proceed commitments. The Major North Slope Producers | even without the exploration and production of additional gas. the YTF gas finds, does not appear dependent appears to be sufficient to cover the transportation would receive a significantly positive NPV and make a very profitable rate of return even if the only gas they ever produce on the North Slope is the Prudhoe Bay and state existing gas (Appendix G1, Section 5). Thus, the Project could proceed even without the exploration and production of additional gas. 122 In its initial offer, TC Alaska has proposed that shippers would have to bear their pro rata share of Development costs if they withdraw. The proportionate sharing of such development costs is an area that could well be subject to future negotiations; see Application 2007, 2.2.3.3, Appendix G2, Section 4. 27 MAY 2008 3-135 AGIA Analysis of the Likelihood of Success Written Findings and Determination However, it appears highly likely that additional gas will be found and produced from state YTF areas. The NETL study and other sources indicate that the quantity of economically recoverable gas is more than enough to fill the Project for decades after the Prudhoe Bay gas is fully produced. Compared with other projects, the reserve picture is favorable (Appendix J, Section 3). Meanwhile, over a significant range of prices the economics associated with producing YTF gas and shipping it on the TC Alaska Project appear to be profitable (Appendix G1, Section 5). YTF economics, as modeled, appear to be internationally competitive (Appendix K). Thus, the risk of not finding and producing sufficient gas to fill the 4.5 Bcf/day capacity of the Proposal Base Case or of the Conservative Base Case, does not appear sufficient to deter the Project from moving forward. If shippers are concerned about reserve risk, and they wish to manage that risk by accepting higher tariffs, they could opt to make shipping commitments that support a smaller throughput project. Accordingly, a project of only 3.5 Bcf/d was considered. Even under this smaller capacity scenario, however, the Commercial Team report demonstrates the Project would produce significantly positive NPVs, although somewhat less than for a larger project (Appendix G1, Section 6). For these reasons, the commissioners believe the risk of insufficient gas reserves should not ultimately be a barrier to the Project's likelihood of success. Fiscal Risks The Major North Slope Producers have consistently asserted that they cannot construct an Alaska gasline themselves, or sign firm shipping contracts with an independent gas pipeline, unless the state provides them with “fiscal certainty.” For example, in its public comments, BP argues that AGIA “does not sufficiently address the resource framework, the key enabler for a project to be successfully financed” (Appendix A, BP Comments). Similarly, Exxon argues that “[a]ln appropriate fiscal regime must be negotiated between the state and the [Major North Slope] Producers” (Appendix A, Exxon Comments) In addition, referring to the risk of signing firm shipping contracts and other risks, ConocoPhillips maintains that “[n]Jo commercially reasonable party will take these unprecedented investment risks until a number of conditions 27 MAY 2008 3-136 AGIA Analysis of the Likelihood of Success Written Findings and Determination have been met, including the establishment of a predictable gas fiscal framework.”'7° The Major North Slope Producers’ continued demand for “fiscal certainty” echoes their position during the prior Administration. In 2004, the Producers negotiated a contract which provided them with billions of dollars in tax concessions,'** and would have effectively required the state to surrender a significant portion of its sovereignty for decades, in exchange for a pledge by the Major North Slope Producers to merely study the feasibility of a gas pipeline. The commissioners acknowledge the possibility that future state governments will change the fiscal structure in a way adverse to the Major North Slope Producers’ interests. However, the first thing to note here is that, in regard to royalty, fiscal certainty already exists. The royalty rate is established by contract, and cannot be changed. While some risk exists associated with the state’s ability to switch between taking its royalty in value or in kind, AGIA mitigates this risk for shippers that obtain capacity in an AGIA project's first binding open season. (AS 43.90.310.).'”° With regard to production taxes, we note that it was precisely in response to producer concerns about this risk that AGIA provides ten years of fiscal certainty to any shipper that participates in the first open season of the AGIA project. For the first ten years of pipeline operations, any shipper that commits gas during the first open season will pay whatever production tax rate was in effect at the time of the first open season. (AS 43.90.320(a)) 123 123 See Jan. 24, 2008 Letter from Mr. J. L. (Jim) Bowles, President of ConocoPhillips Alaska, Inc. to The Honorable Sarah Palin, at page 5. We also noted that ConocoPhillips is a joint venture partner with TransCanada in the Keystone oil pipeline project. 124 See Pulliam 2006. 128 Minor producer risk exists concerning how royalty value should be calculated due to the state leases’ “higher of” provisions.. However, AGIA provides an avenue to resolve this uncertainty for those that commit gas to the first open season. AS 43.90.310 27 MAY 2008 3-137 AGIA Analysis of the Likelihood of Success Written Findings and Determination In Alaska the Major North Slope Producers do not face the risk, as they do in some countries, that the state will nationalize their production facilities. But in any case, the risks associated with state government action appear to be significantly overstated, especially when considered in the broader international context. As a democratic republic, Alaska’s political system provides an inherent protection from the threat of a tax system that is unresponsive to producers’ profit needs. In fact, from 1975 through 2006 the state’s general history involved a gradual decline in production tax rates. As demonstrated throughout this Finding, the current fiscal regime provides for robust profits for modeled new gas development. In addition, it does not appear that fiscal risk is the crucial one facing the project. The chart below shows the effect to Producer NPV of potential tax increases of 15, 30, and 50% that are modeled to occur at different periods after first gas flows under the Proposal Base Case. Further, for gas that is committed at the initial open season of the TC Alaska project, the legislature has committed to not change the tax rate for the first ten years of operations. From the chart we see that a tax increase as large as fifty percent imposed at year ten reduces Producer NPV by ten percent. Although these changes are material, in context of other risks they do not appear to be the project’s main risk factors. Other factors—such as price and project escalation risks—have a much greater effect on overall project economics. Moreover, the tax rate increases—especially large ones—do not seem likely, for several reasons. 27 MAY 2008 3-138 AGIA Analysis of the Likelihood of Success Written Findings and Determination @ Figure 3-51. Impact of Different Periods of Fiscal Uncertainty for Producer NPV; Decrease in Producer NPVio $0.0 - ($0.5) : ($0.3) i ($0.6) se) ($0.5) 5 ($1.0) | ($0.8) ($0.8) eos 508) ($1.4 * ($1.5) aa a 5 : A$1.3) ___- z ($1.5) % ($2.0) : ($1.8) & ($2.5) - - é ($2.5) ($3.0) _ — _ — Oys 5 yrs 10 yrs 15 yrs Fiscal Certainty Period Before Tax Increase TaxIncrease 15% Taxincrease 30% © Tax Increase 50% % Decrease in Producer NPVio 0.0% +. - -2 A OM 3% * ; -5% -4% = ay some 7% = -10.0% 9% ‘ _ : $ -10% 12% & -15.0% ae Bere 15% | # -20.0% + - - - ce ia : ea Fotos -20% -25.0% — aa ee cata 0 yrs | 5 yrs i 10 yrs 15 yrs Fiscal Certainty Period Before Tax Increase TaxIncrease 15% Taxincrease 30% Tax increase 50% Source: Black and Veatch, Appendix G1, Section 6.7 First, project returns have been modeled under the current production tax law (ACES). However, ACES has a supplemental tax, or “progressivity” feature, that is triggered off a fixed marker of $30 per barrel oil equivalent. This marker is not indexed for inflation. Over time, general inflation will cause ACES’ progressivity feature to bite harder and harder. It seems highly probable that in coming decades the trigger level will be revised upwards, thereby reducing taxes. 27 MAY 2008 3-139 AGIA Analysis of the Likelihood of Success Written Findings and Determination This conclusion is reinforced when one Given that the state’s future is dependent upon a_ vibrant exploration and to enter the project roughly coincides with the development environment, it would be directly contrary to the state’s interests to raise taxes prohibitively just when YTF considers that the timing of the need for YTF gas expiration of AGIA’s fiscal stability period. Given that the state’s future is dependent upon a | gas economics are most relevant. Indeed, vibrant exploration and development much of AGIA’s rationale has been based on ensuring that the economics of YTF gas, including that for expansions, will be state’s interests to raise taxes prohibitively just favorable. environment, it would be directly contrary to the when YTF gas economics are most relevant. Indeed, much of AGIA’s rationale has been based on ensuring that the economics of YTF gas, including that for expansions, will be favorable. The NPV analysis discussed earlier in these Findings demonstrates that fiscal changes should not be necessary for the Major North Slope Producers to support a pipeline to the AECO Hub. The significant estimated NPV of the Project makes the Major North Slope Producers’ request for fiscal certainty unnecessary. As demonstrated above in Figure 3-33 the Project would enable the Major North Slope Producers to earn $12.3 billion (NPV1o) under the Conservative Base Case and $13.5 billion (NPV19) under the Proposal Base Case (Appendix G1, Section 6.4), with a very large internal rate of return, without any changes to the state’s existing production tax and royalty structure. iii. Risks to TC Alaska’s Project Due to the Producer Project The Project's economics are robust. Risks to the If the Project economics are favorable (even spectacular for explanation for why the Major North Slope Producers Prudhoe Bay gas), and the Project have filed comments opposing the TC Alaska Project. | iS supported by other factors including TransCanada’s fine Project economics do not provide a reasonable However, if the Project economics are favorable (even record as a gas pipeline operator, spectacular for Prudhoe Bay gas), and the Project is then it is logical to ask why the : : 7 Producers would continue to supported by other factors including TransCanada’s fine oppose the Project. record as a gas pipeline operator, then it is logical to ask why the Producers would continue to oppose the Project. At least a partial answer may lie in the fact that BP and ConocoPhillips, after TC Alaska submitted its AGIA proposal, proposed their own Producer Project. In Chapter 5 of these Findings, the commissioners explain why the state needs TC Alaska’s Project despite the recent 27 MAY 2008 3-140 AGIA Analysis of the Likelihood of Success Written Findings and Determination BP/ConocoPhillips proposal.'*® Assuming BP and ConocoPhillips truly pursue their Producer Project to completion, it would have a significant negative impact on TC Alaska’s likelihood of success, simply because TC Alaska would probably be unable to attract the necessary firm shipping commitments without the reserves leased by BP and Conoco. Of course, under that scenario, the state would finally get a gasline, although it would be one built outside the AGIA process and without the benefits that an AGIA pipeline would provide to the state and its citizens, including genuine open access and increased jobs due to expansion and rate commitments that will maximize exploration and development of the North Slope. Neither BP nor ConocoPhillips have abandoned their previous insistence that the state provide them with major fiscal changes and fiscal certainty before any pipeline project can proceed. In announcing their own pipeline concept, BP and ConocoPhillips carefully avoided saying anything about fiscal terms. However, their public comments ; Assuming for the sake of filed on March 6, 2008 regarding TC Alaska’s Project make analysis that the Major North clear that significant fiscal changes by the state are the “key | Slope Producers truly need fiscal changes and_ fiscal certainty, the means for the A, BP Comments), and that the producers believe “[n]o Producers to achieve their fiscal objectives is to support enabler for a project to be successfully financed” (Appendix commercially reasonable party will take these unprecedented TC Alaska’s Project as firm investment risks until a number of conditions have been met, shippers and, if equity including the establishment of a predictable gas fiscal | ownership is an attractive option to them, negotiate with TC Alaska to become a partial equity owner in the It thus is reasonable to expect that, even if BP and pipeline. framework..”'2” ConocoPhillips “commit” to sign firm contracts on their own pipeline project, they will condition those commitments, and their commitment to pursue their project, on the state’s agreement to massive changes in fiscal terms. Until they have supported 26 As discussed later in Chapter 5, rejecting the Project due to the promises made by BP and ConocoPhillips to pursue a producer-owned pipeline would leave the state in the same leveraged position it was in the prior Administration: with an unenforceable pledge by BP and ConocoPhillips to pursue a pipeline, but with no enforceable milestones and only on the condition that the state relinquish a large portion of its sovereignty by agreeing to “fiscal certainty”. There is a strong possibility that, absent the existence of TC Alaska’s Project, the BP/ConocoPhillips pipeline would not have been proposed, and would not be pursued. As a result, it is important to continue the competitive AGIA process with TC Alaska regardless of the new producer-owned pipeline concept that has been floated by BP and Conoco. "27 In the alternative pipeline proposal that it publicized just prior to the AGIA application deadline on November 29, 2007, ConocoPhillips expressly stated that it could not construct its proposed pipeline without receiving fiscal concessions from the state. Letter from ConocoPhillips CEO J. Mulva to Governor Palin at 2. See also ConocoPhillips Proposal at Section IV., at 4-5 (November 30, 2007). 27 MAY 2008 3-141 AGIA Analysis of the Likelihood of Success Written Findings and Determination their need for fiscal certainty with economic facts demonstrating that they will be unable to realize a reasonable profit without changes in state tax laws, those conditions should be viewed as attempts to gain leverage in a negotiation with the state. In light of the fact that the analysis above shows that the Project would enable the Major North Slope Producers to realize billions in profits and an extremely large rate of return from the Prudhoe Bay field, they are unlikely to be able to support the need for fiscal changes at this time. Assuming for the sake of analysis that the Major North Slope Producers truly need fiscal changes and fiscal certainty, the means for the Producers to achieve their fiscal objectives is to support TC Alaska’s Project as firm shippers and, if equity ownership is an attractive option to them, negotiate with TC Alaska to become a partial equity owner in the pipeline. We will explain in the following sections why various Producer objections to becoming equity partners with TC Alaska (or shippers) on the TC Alaska Project lack merit. TC Alaska has opened the door to the possibility that the Producers can become equity partners in the Project, a constructive offer which enhances the likelihood of success of its Project. In addition, assuming TC Alaska becomes the AGIA Licensee, it will be the state’s partner in achieving an Alaska gasline. The state would surely take any such partnership seriously, and indeed could not support another pipeline project, including offering fiscal changes to BP/ConocoPhillips and their Producer Pipeline concept, without subjecting itself to the penalty exposure provided under AGIA.'”® Thus, it is important to understand that the path to fiscal changes, should any be necessary in the future as market conditions unfold, is through the TC Alaska Project, not through the Producer Project. iv. Producer Objections to the TC Alaska Project Lack Merit The foregoing discussion presumes that BP and ConocoPhillips are serious about developing the Producer Project. However, it is also possible that the Producer Project is merely a vehicle intended to either provide “cover” for the Producers while they object to the issuance of an AGIA license to TC Alaska, or to enable the Producers to increase their negotiating leverage with TC Alaska should they decide to become shippers on the Project (Appendix G2, Section 5). In fact, the Major North Slope Producers, in their AGIA comments, legislative testimony, and other public statements, have advanced several reasons which attempt to explain why they cannot "28 AS 43.90.230 27 MAY 2008 3-142 AGIA Analysis of the Likelihood of Success Written Findings and Determination support an independent pipeline in general, and TC Alaska’s Project in particular. This section analyzes the principal remaining producer objections to the Project. (1) Producers Suggest Only They Can Build an Alaska Gas Pipeline Project During the AGIA process, the Major North Slope Producers have argued that only they have the ability to construct an Alaska gasline, implying that producer-owned pipelines are the norm in the U.S. However, while they could probably construct (or, more likely, hire a third-party to construct) an Alaska gasline if they wanted to, the Major North Slope Producers lack experience in constructing long-distance, regulated natural gas transportation facilities in the U.S. In fact, even though the U.S. natural gas pipeline grid is many times larger than the proposed Project, none of the major interstate natural gas pipelines in the U.S. are majority-owned by the Major North Slope Producers. This is probably explained, in part, by the fact that interstate natural gas pipelines provide a much lower regulated rate of return than the return earned by the Major North Slope Producers for producing oil and gas (Appendix N). As a result, owning an interstate pipeline would dilute their earnings and growth profile. Because their focus is on oil and gas production instead of natural gas pipeline ownership, the Major North Slope Producers do not have a great deal of experience in constructing, owning or operating interstate gas pipelines.'° Independent pipeline companies like TC Alaska, not the Major North Slope Producers or their counterparts, have constructed and operate most of the natural gas pipeline facilities in the U.S (Appendix R7). As demonstrated in the earlier discussion of background information about TransCanada and TC Alaska, TransCanada alone owns and operates gas pipelines that collectively have several times more capacity than the capacity of the proposed Project. It thus is a better position to successfully construct and operate an Alaska gasline than the Producers. The Major North Slope Producers have also suggested in the past that as a result of their financial strength, only they can construct a “mega-project” like the Alaska gasline project. The profitability and resources of Major North Slope Producers cannot be disputed. However, it would be a mistake to conclude that only they have the ability to construct an Alaska gasline. As discussed earlier, the commissioners retained Goldman Sachs to assess the critical issue of "28 The Major North Slope Producers own pipelines that gather gas they have produced and deliver it into major interstate natural gas transmission lines. However, the pipelines owned by the Major North Slope Producers are largely an adjunct to their production business, and by and large are not major interstate natural gas pipelines. 27 MAY 2008 3-143 AGIA Analysis of the Likelihood of Success Written Findings and Determination whether TC Alaska has the ability to obtain financing for the Project. At the commissioners’ direction, Goldman Sachs carefully assessed this issue, including a review of the financial elements of the proposed Project, an assessment of TC Alaska’s ability to fund the Project, and an evaluation of TC Alaska’s plan to use the Federal Loan Guarantee. After conducting its review, Goldman Sachs concluded that the Project is financeable on the basis outlined in the TC Alaska proposal, as follows: e TransCanada is a well-capitalized, highly expert sponsor with strong incentives to complete the Project. e Although the scope and complexity of the Project are significant, the shipping contracts are key to the credit strength of the financing, and the most likely shippers (the Major North Slope Producers) have very strong financial profiles. e Based on a review of other major projects (such as the Alliance and Maritimes pipelines), and recognizing that exactly comparable projects or precedents do not exist, Goldman’s view is that the proposed Project can be funded in the project finance market, even though the size and length of construction will test the market's capacity for project financing e The elements of the proposed Project that relate to financing—including the plan to obtain shipping contracts, the proposed debt/equity ratio, the general financing plan, and the plan to use the Federal Loan Guarantee—all create the basis for a financially viable project and project financing. Goldman Sachs’ report is based on the assumption that TC Alaska will obtain firm shipping contracts for the full capacity of the Project, again underlining the critical importance of that issue. e Goldman Sachs also assumes TC Alaska will obtain the Federal Loan Guarantee that Congress authorized when it passed ANGPA in 2004, and Federal Loan Guarantee are used as outlined in the TC Alaska Proposal. This would enhance the financial position of the Project (Appendix H). e The proposed debt/equity ratios—70/30 during construction, and 75/25 upon FERC approval of the final capital costs—will be acceptable to the capital and banking markets. e TC Alaska has the financial resources to fund the equity requirements of the Project, including 100% of those requirements if necessary. According to Goldman Sachs, the 27 MAY 2008 3-144 AGIA Analysis of the Likelihood of Success Written Findings and Determination Project’s financeability also is enhanced because TC Alaska is a strong pipeline operator. Based on these factors, and as discussed more fully at Appendix H, Goldman Sachs concludes the Project proposed by TC Alaska can be funded in the project finance market, assuming key credit features like firm shipping contracts, and the Federal Loan Guarantee, are in place and that obstacles to the Project can be surmounted. Accordingly, the commissioners disagree with any suggestion that only the Major North Slope Producers can construct a project of this scope and size. (2) Producers Suggest They Are Insufficiently Protected from Cost Overruns In their public comments, the Major North Slope Producers argue that TC Alaska’s proposal inadequately protects them from the risk of cost overruns (Appendix A, BP Comments). The issue of cost overruns has been extensively discussed earlier in this Chapter. The discussion here will provide a brief additional response to the Producers’ argument. As a threshold matter, it is important to understand the impact of potential cost overruns on the profitability of the Project to the Producers. Based on the Commercial Team's analysis, the commissioners agree that cost overruns could have a material impact on Project economics. However, even assuming a significant cost . ah Even assuming a significant cost overrun overrun scenario, the Project would still permit | scenario, the Project would still permit the the Major North Slope Producers to eam | Major North Slope Producers to earn substantial profits on the sale of natural gas. substantial profits on the sale of natural gas. Specifically, if the Project experiences a 40% cost overrun ($12.5 billion, capital cost $2008), and assuming for the sake of argument that the Major North Slope Producers did not have the protection of the U.S. loan guarantee, the Commercial Team’s analysis demonstrates the Major North Slope Producers would still earn an attractive rate of return and realize an NPV of approximately $11 billion if the other assumptions in the Proposal Base Case scenario, including gas price projections, remain unchanged (Appendix G1, Section 5.7.8). In reality, the Major North Slope Producers’ risk of cost overruns will likely be materially lower, because even under TC Alaska’s proposal, TC Alaska has offered to bear part of the cost overrun risk by adjusting its return on equity downward by up to 200 basis points for the first five years of the Project (Application 2007, Section 2.2.3.6). In addition, its public comments, ExxonMobil has correctly characterized TC Alaska’s proposed commercial terms as a mere 27 MAY 2008 3-145 AGIA Analysis of the Likelihood of Success Written Findings and Determination “opening offer” to the Producers (Appendix A, ExxonMobil Comments). As a result of the @ significant bargaining power possessed by the Major North Slope Producers, it is reasonable to | Based on the bargaining power of the Major North Slope Producers and their experience on other pipelines, there is counteroffer and engage in rigorous negotiations every reason to conclude that the Major assume that after they make an appropriate North Slope Producers would not be required to bear an inordinate share of proposed by TC Alaska, they will require TC the cost overrun risk. with TC Alaska over the initial rates and terms Alaska to bear a materially larger portion of the risk of Project cost overruns. In addition, and as discussed above in the analysis of TC Alaska’s proposed commercial terms in this chapter of these Findings, pipelines often offer to bear a material part or in some cases the entire risk of cost overruns themselves, by agreeing to negotiated rate agreements that shift all or part of the risk of cost overruns to the pipeline. In fact, the Major North Slope Producers themselves have entered into numerous negotiated fixed rate contracts on pipelines in the u.s.° Accordingly, based on the bargaining power of the Major North Slope Producers and their experience on other pipelines, there is every reason to conclude that the Major North Slope © Producers would not be required to bear an inordinate share of the cost overrun risk. Although the risk of cost overruns is without question a significant issue facing any Alaska gasline project due to the sheer scope and extended timeline of the project, it does not appear to constitute an insurmountable barrier to the success of the Project, including the initial open season. (3) Producer Concerns That TC Alaska Has Done Insufficient Design Work Leading to Cost Uncertainty In its public comments, Exxon expresses concern that TC Alaska has not planned to spend the funds necessary to develop a reliable estimate of what the Project ultimately will cost. The commissioners agree that obtaining a reliable cost estimate is very important. However, as indicated earlier, the biggest cost risk is the risk that the price of steel and other project cost components will increase for reasons that are beyond TC Alaska’s control or ability to predict. iy evaluating the Major North Slope Producers’ comments on the cost overrun issue, it is important to recall their prior arguments on this same topic. In opposing the passage of AGIA in 2007, the Major North Slope Producers argued that it is imperative that they own the Alaska gas pipeline because, if the gasline were constructed by an independent pipeline company, the producers would bear the entire risk of cost overruns. As discussed above, that is inconsistent with the Producers’ experience on other pipelines. Appendix R6. @ 27 MAY 2008 3-146 AGIA Analysis of the Likelihood of Success Written Findings and Determination In other words, even if TC Alaska spent a considerably higher amount to generate its project cost estimate prior to the open season, it would not materially increase the reliability of these areas of the cost estimate. Large increases in steel prices and related costs are a significant factor in pipeline economics in the current market environment. As shown earlier, cost escalation risk dwarfs the risk of increased costs due to inadequately defined or managed project scope. But the risk factor of cost escalation, or increases, is not hugely diminished merely through the conduct of extensive engineering work. That is because, after open season, a multi-year regulatory process must still be conducted (Appendix F Exhibit D). The risks of substantial year-over-year cost escalation— such as what the industry has suffered in the last few years—will remain.'*" There are two obvious ways to mitigate such escalation risk. First, if detailed design work is indeed performed, and if the Project proponents are willing to commit to purchase long-lead items after the open season so that their prices can be secured, then a significant portion of cost escalation risk can be avoided. Doing this, however, entails its own risks as the project scope may be forced to change as a result of the regulatory process. The Major North Slope Producers have not, to date, indicated a willingness to take this risk."** Second, precedent agreements signed at open season between the shippers and the pipeline owners can permit shippers with “off ramps’ or “outs” if costs appear to have increased above some threshold. The commercial question facing such contract provisions is the sharing of development costs should the project not go forward. Having TC Alaska as an additional commercial party—not to mention the state, through its $500 million matching contribution under AGIA — at least creates the prospect for sharing this cost escalation risk. Accordingly, the commissioners do not agree with the contention that TC Alaska’s proposed level of design costs should impede the Project's likelihood of success. 131 See Erman, Michael; 2008. Oil industry costs continue steep rise: CERA. Reuters. http:/www. reuters.com/article/sphereNews/idUSHO44071 7200805 14?sp=trueandview=sphere 132 For evidence of this concerning projects in which they are pipeline sponsors, see, e.g., BP/ConocoPhillips. 2008. Denali gas pipeline PowerPoint announcement. http://www.denali- thealaskagaspipeline.com/images/pdf/Denali_Presentation%20FINAL.pdf. at Slide 10; see also Department of Revenue, 2006 at 59. [Interim Findings and Determination. November 16, 2006.] 27 MAY 2008 3-147 AGIA Analysis of the Likelihood of Success Written Findings and Determination (4) Producer Objections to Rolled-in Rates and AGIA’s Expansion Provisions As discussed earlier in this chapter in the analysis of the Project’s NPV, the Major North Slope Producers would be exposed to relatively little of a reduced NPV due to the AGIA rolled-in rate provisions. The fact is that expansions due to the addition of compression — which would be the initial vehicle for expanding the Project by nearly 50% above initial Proposal Base Case thoughput — has very little potential to materially increase the Project rates and would generally reduce the Project rates to the benefit of the Major North Slope Producers (Appendix G1, Section 4.7.8.6). For this reason, the commissioners do not believe the AGIA rolled-in rate provisions would have a material impact on producer profitability and thus do not constitute a valid reason for the Producers to oppose TC Alaska’s Project.'* (5) Producers Arguments Concerning The Withdrawn Partner Issue Another reason given by the Major North Slope Producers for not supporting the Project involves TransCanada’s alleged obligations to a partnership formed by TransCanada affiliates under New York law in the late 1970s to construct an Alaska natural gas pipeline pursuant to the Alaska Natural Gas Transportation Act (ANGTA). To understand the Producers’ arguments, some brief background facts about the situation are necessary, which are summarized below and discussed in more detail in Appendix R1. In 1978, TransCanada affiliates and several other companies formed a partnership called the Alaskan Northwest Natural Gas Transportation Company (ANNGTC). Each partner was required to make an initial contribution of capital of up to $24 million to ANNGTC, and additional annual contributions as necessary (Appendix D, TransCanada letter dated January 24, 2008). Over the intervening decades, all of the ANNGTC partners have withdrawn from the partnership except for two TransCanada affiliates. The total investment by the TransCanada partners and the now-withdrawn partners in ANNGTC was approximately $200 million (Appendix H, Section VIII B) with the TC Alaska partners accounting for approximately 30% of the total (Appendix D, TransCanada letter dated January 24, 2008 Data Response, and Alaskan Northwest Natural Gas Transportation Company, General Partnership Agreement). *33 In theory, if the Project costs are much less than what has been projected, rolled-in rates could have an impact. But in that unlikely event, the Project would be even more profitable to the Major North Slope Producers, as a result of the lower costs. Appendix G1, Section 3.7.5.1. 27 MAY 2008 3-148 AGIA Analysis of the Likelihood of Success Written Findings and Determination As discussed in more detail at Appendix R1 of these Findings, the ANNGTC partnership agreement provides that if ANNGTC ever builds the 1970s project, then it must repay any withdrawn partners their original contributions plus interest at the rate approved by FERC (14% annually), provided that certain conditions are met, including the condition that such payments can be made without “undue hardship” to the partnership (Appendix D, TransCanada letter dated January 24, 2008; ANNGTC Partnership Agreement at Section 4.4.4(i)). Due to the compounding of interest at 14% for about 30 years, ANNGTC’s contingent “obligations” to withdrawn partners have grown rapidly and currently total approximately $10 billion, with the number expected to grow to over $35 billion in the next ten years. In their public comments, the Major North Slope Producers have asserted that if TC Alaska builds the Project, there is a significant risk the withdrawn partners could sue ANNGTC, TC Alaska and any party that becomes an equity partner in the Project or signs a firm transportation contract with the Project. According to ConocoPhillips, for example, this obligation “will constitute an insurmountable risk for potential shippers on a TransCanada project, for potential new associates advancing a project with TransCanada, for potential financiers of a TransCanada project, and for the State of Alaska.” BP filed similar comments, asserting that “TransCanada potentially faces a multi-billion dollar liability to withdrawn partners associated with an earlier attempt to advance an Alaska pipeline project.” Neither BP nor ConocoPhillips included in their public comments any discussion of the legal theories behind such claims. Although ConocoPhillips stated in a letter to Governor Palin that it had asked its law firm “to prepare a memorandum to your Administration that identifies many of the withdrawn partner liability risks,” id., ConocoPhillips failed to provide the commissioners or the state with that memorandum, and refused the state’s request for a copy of the memorandum.’ Of the prospective shippers on the Project, only the Major North Slope Producers raised this issue. Other prospective shippers on the Project, such as Anadarko or BG, did not raise the issue. ' Although ConocoPhillips refused to provide the memo, they did allow the state’s outside counsel to discuss the issue with ConocoPhillips’ outside counsel (See Bowes, Jim Jan. 24, 2008 ConocoPhillips Letter to the Honorable Sarah Palin). 27 MAY 2008 3-149 AGIA Analysis of the Likelihood of Success Written Findings and Determination In addition, in March 2008, the LB&A Committee asked each of the withdrawn partners not affiliated with TC Alaska whether they would waive their rights as withdrawn partners and whether the Project proposed by TC Alaska violated those rights. On April 1, one of the withdrawn partners, Sempra, filed a response. In its response, Sempra stated that while it would not waive any rights it has as a withdrawn partner, it was not aware of anything that TC Alaska has proposed in its AGIA Project that would violate Sempra’s rights as a withdrawn partner. To our knowledge, none of the other withdrawn partners has responded to LB&A’s request. However, Sempra’s statement appears to contradict the claims by ConocoPhillips and the other Major North Slope Producers that the withdrawn partner issue constitutes “an insurmountable risk for potential shippers on a TransCanada project, for potential new associates advancing a project with TransCanada, for potential financiers of a TransCanada project, and for the State of Alaska.” Notwithstanding the fact that the Major North Slope Producers failed to include in their public comments any legal analysis in support of their claims regarding ANNGTC, the commissioners asked their legal counsel (Greenberg Traurig) to analyze this issue and provide a public analysis of the issues raised by ConocoPhillips and other commenters, including an assessment of the risk of lawsuits by withdrawn partners against TC Alaska and any entity that helps advance the Project either by signing a firm contract, partnering with TC Alaska, or financing the Project. That analysis is set forth at Appendix R1 of these findings, and is summarized below. For the reasons discussed above and in that analysis, the commissioners believe that concerns about the risk of litigation are significantly overstated, and that the potential legal claims by withdrawn partners are, at best, weak and unlikely to succeed. For example: e FERC would probably refuse to allow most of the $10 billion to be recovered in rates, assuming ANNGTC were ever actually built. The Major North Slope Producers failed to address this issue in their comments. FERC rules only permit a pipeline to recover from customers the interest accrued on funds used “during construction.” Here, it is 138 See February 29, 2008 letters from LB&A Committee to the Loews Corporation, MidAmerican Energy Holding Company, NiSource, Inc., Pacific Gas and Electric Corporation, Sempra Energy, and The Williams Companies. ‘88 See Definition (17) of Gas Plant Instruction 3. of the FERC’s Uniform System of Accounts, 18 C.F.R. Part 201 at 611 (2007) (‘Allowance for funds used during construction’ includes the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used, . . . .” (Emphasis added.)). E.g., Metropolitan Edison Co., 11 FERC {| 61,027 at 61,042 (Classifying plant as construction work in progress and accruing an allowance for funds used during 27 MAY 2008 3-150 AGIA Analysis of the Likelihood of Success Written Findings and Determination @ undisputed that ANNGTC has not constructed anything, and that any work on the project ended more than twenty years ago. Consequently, because the interest on the contingent liability, which comprises most of the $10 billion, has not been accruing during construction, it would likely not be recoverable in rates under FERC rules and precedent. Accordingly, as explained in Appendix R1, payment of the vast majority of the contingent liability would not be required under the Partnership Agreement. At most, FERC would probably only permit recovery of the book value of any assets that could truly be used to build the ANNGTC project. The value of those assets for withdrawn partners not affiliated with TransCanada is approximately $200 million or less. No party—not even the Major North Slope Producers—contends that a liability of that much lower amount would pose an insurmountable barrier to the Project. e In addition to the fact FERC rules likely would drastically reduce the real amount at issue in any potential dispute, there are other major weaknesses in any potential claims against TC Alaska. For example, the ANNGTC partnership agreement does not require TC Alaska to make payments to the withdrawn partners unless it constructs the project contemplated in the partnership agreement (Appendix R1). In fact, TC Alaska is building a project under a different set of FERC authorizations than applied to the ANNGTC @ project. /d.. The ANNGTC partnership agreement also does not contain any language that expressly prohibits TC Alaska from pursuing a new project. e Taken to its ultimate conclusion, the Major North Slope Producers’ argument goes too far because it would ultimately, and probably unlawfully, preclude TC Alaska from ever constructing an Alaska gasline. Assuming for the sake of argument that the $10 billion contingent liability actually exists, the ANNGTC project probably could never be built because the Project would be uneconomic if the cost of the alleged liability (which will be more than $33 billion in the year 2016) (Appendix A, ExxonMobil) had to be recovered in the project's rates. At the same time, under the theory of ConocoPhillips and the other Producers, TC Alaska cannot pursue its new Project without violating an alleged duty to the ANNGTC withdrawn partners to construct the old project. By effectively precluding TC Alaska from building either the new Project or the old ANNGTC project, the Major construction when such plant is in fact not under construction obviouly [sic] deviates from the descriptive definition and function of those accounts.”), modified on other grounds, 13 FERC {| 61,142 (1980). 27 MAY 2008 3-151 AGIA Analysis of the Likelihood of Success Written Findings and Determination North Slope Producers’ theory overreaches. Courts strongly disfavor contract interpretations which unreasonably restrict a party from competing in the marketplace."*” e TC Alaska’s potential liability is even more remote because a strong argument can be made that withdrawn partners have waived any claims they may have against TC Alaska, either by pursuing new Alaska gasline projects themselves, or by failing to file public comments during the AGIA process opposing the Project due to the alleged existence of the ANNGTC “contingent liabilities.”. Even though they had notice of the issue, none of the withdrawn partners filed comments.’ For these reasons, and as more fully explained in the analysis in Appendix R1, the risk of litigation concerning the ANNGTC contingent liability issue is not a reasonable basis for the Major North Slope Producers to refrain from partnering with TC Alaska or contracting with the Project. Nor would it necessarily present an impediment to financing the Project. In addition, the commissioners further conclude that, should litigation be necessary to gain additional clarity regarding this issue, such litigation could be resolved in a time frame that would not have a materially adverse impact on either the NPV or likelihood of success of the Project. For example, the state or some other party could ask FERC to issue a declaratory order ruling that it would disallow most of the ANNGTC costs, particularly the interest that has accrued during a period when no construction has occurred. Assuming FERC acts on the petition, a FERC ruling could be issued within several months from the time of the filing, and help to eliminate most of the alleged liability, reducing it to a much smaller and more manageable level that would not have a material adverse impact on the marketing or financing of the Project.'*° Similarly, TC Alaska or another party could ask a court in Alaska (or potentially '3” See Restatement (Second) Contracts § 186 (1979) (“A promise is unenforceable on grounds of public policy if it is unreasonably in restraint of trade. A promise is in restraint of trade if its performance would limit competition in any business or restrict the promisor in the exercise of a gainful occupation.”). See also In re American Preferred Prescription, Inc., 186 B.R. 350, 354 (E.D.N.Y. 1995) (“Courts generally look with disfavor on restrictive covenants not to compete.”); Technical Aid Corp. v. Allen, 134 N.H. 1, 8, 591 A.2d 262, 265 (1991) (“This court has stated that the law does not look with favor upon contracts in restraint of trade or competition.” (Internal quotation omitted.)). 138 Given that they failed to file public comments or otherwise raise this issue with TransCanada prior to the public comment deadline, any effort by the withdrawn partners to assert claims against TransCanada, or against its future partners and shippers in the Project, could subject the former partners to a claim by the state that they have tortuously interfered with the state’s license relationship with TransCanada, assuming TransCanada receives the AGIA License. 27 MAY 2008 3-152 AGIA Analysis of the Likelihood of Success Written Findings and Determination in New York), to issue a declaratory judgment regarding whether the construction of the Project would breach a fiduciary duty to the ANNGTC withdrawn partners. In sum, the potential claims against TC Alaska regarding the ANNGTC issues are extremely weak. Accordingly, the ANNGTC withdrawn partner issue would not pose a significant threat to the success of the Project (Appendix H, Section VIII). e. Other Factors Which Indicate TC Alaska’s Project Has A Reasonable Prospect of Securing Firm Shipping Commitments Despite the pendency of the BP/ConocoPhillips Despite the pendency of the BP/Conoco Phillips Producer Project Producers’ stated objections to the TC Alaska and the Major North Slope Producers’ stated objections to the TC Alaska Project, several factors support the conclusion that there is a reasonable Producer Project and the Major North Slope Project, several factors support the conclusion that there is a reasonable chance the Producers will not withhold their gas indefinitely, and will | chance the Producers will not withhold their gas indefinitely, and will eventually decide to negotiate firm agreements with TC Alaska which will enable the shipping agreements with TC Alaska which will enable the TC Alaska Project to obtain financing. eventually decide to negotiate firm shipping TC Alaska Project to obtain financing. This analysis is supported by the various Appendices to these Findings. Simply put, the commercial, legal and political risks of a failed open season are simply too great for the stakeholders to permit the TC Alaska Project to fail. As a threshold matter, if the TC Alaska Project fails due to a lack of shipper support and despite the robust profits the Project would produce, the Major North Slope Producers would risk the loss of their leases which give them the right—and the obligation—to produce and market natural gas located on land owned by the State of Alaska. A hydrocarbon leaseholder has a duty to produce and market oil and gas when it would be reasonably profitable to do so.'” Under the terms of their leases with the state, the Major North Slope Producers do not have the option of delaying the production and sale of natural gas, if committing to the Project now would provide them with the opportunity to make a reasonable profit on gas shipped over the pipeline. According to our NPV analysis, even using conservative price and cost projections and under 138 FERC’s ruling would be subject to rehearing at FERC and a court appeal. 1 See, e.g., Williams and Myers, Oil and Gas Law § 853 (2006). “[L]essee is ordinarily under an implied duty to use due diligence to market the product.” 27 MAY 2008 3-153 AGIA Analysis of the Likelihood of Success Written Findings and Determination the current state tax and royalty structure, the Major North Slope Producers would reap billions of dollars of profits if the Project were constructed, a huge internal rate of return at Prudhoe Bay, and a significant rate of return in other North Slope production areas. Because the infrastructure to produce gas at Prudhoe Bay is already in place, incremental production costs would be extremely low at that important location. TC Alaska’s Project gives the Major North Slope Producers the ability to sell their gas produced from state lands at an extraordinary profit. As a result, absent a valid excuse, they would have a duty to produce and sell the state’s gas, which would require them to sign firm shipping contracts with the Project. In the past, the Major North Slope Producers have proffered a variety of explanations for why they cannot support an independent pipeline. The foregoing discussion addresses a number of those explanations. For example, the Producer Project proposed by BP and ConocoPhillips is likely contingent upon a demand for fiscal certainty that is unnecessary, and thus would not constitute a valid reason not to support TC Alaska’s Project.'*' Three additional possible explanations for why the Major North Slope Producers currently oppose the Project also merit brief discussion. First, the Major North Slope Producers may maintain that the rate of return that participation in or shipping over the Project would generate is insufficient to clear their internal “hurdle” rates— the minimum rate of return the Producers must achieve to pursue a project. A lessee’s internal hurdle rate, however, is irrelevant to the duty to produce and sell gas from leased state lands. So long as participation in the Project would provide the Major North Slope Producers the ability to earn a reasonable profit, they must provide assurances to support the Project—or unequivocally commit to some other means of commercializing the gas—regardless whether those profits would surpass their internally set hurdle rates. ‘4? ‘4 The state, as lessor, should consider demanding assurances that the NS Producers will fulfill their obligations to produce either by firmly committing to ship over the TC Alaska Project or by committing unconditionally to build the Denali project. ‘#2 Because the Project is so solidly “in the money,” the Major North Slope Producers also face the risk that, in any open season for the Project, an independent marketer will sign a firm contract (subject to the condition that the Producers agree to sell their gas to the marketer). That would further expose them to the risk of a claim that they breached their duty to produce the state's natural gas. 27 MAY 2008 3-154 AGIA Analysis of the Likelihood of Success Written Findings and Determination Second, the Major North Slope Producers’ opposition to the Project reflects their evident desire to control any Alaska gasline. The recent Producer Project by BP and ConocoPhillips provides a concrete indication of this intent. Chapter 5 of these Findings fully discusses the competitive dangers inherent in producer ownership of any Alaska gasline, similar to the state’s experience with TAPS. Apart from those dangers, however, the mere desire to control the pipeline (and thereby achieve “basin control” over the North Slope production basin itself), is not a valid reason for refusing to support the Project, not when the Project would produce extraordinary profits for the Producers. A third possible explanation for the Major North Slope Producers’ opposition to the Project involves prices and profits on other natural gas resources they control. The Major North Slope Producers may be concerned that, by signing firm shipping contracts with the Project, they would increase the actual and projected supply of natural gas in the U.S. market, moderating the price of natural gas and possibly reducing their rate of return on other sales of natural gas they make in the U.S., including sales of liquefied natural gas (LNG) imported from other countries. The Major North Slope Producers control approximately 40% of the natural gas sold in the U.S. (Gas Daily, 2008). The Major North Slope Producers have also made huge investments in overseas LNG projects, including major projects in unstable areas of the world such as the Middle East. Exxon, for example, has reportedly spent $3.2 billion developing a massive LNG project in Qatar, which when completed will produce 61.6 million gross tons per year of LNG for export to markets in the U.S. and other world markets.'* Thus, one of the key benefits of the Project—the ability to moderate the price of natural gas in the U.S.—may not be in the interests of the Major North Slope Producers. The EIA has projected that the construction of an Alaska gasline would reduce the price of natural gas by approximately 20 cents (See Chapter 5, supra). Even though the Producers stand to earn huge profits from the sale of Alaska gas if the Project were constructed, a reduction in the natural gas price of 20 cents could also impact the profitability of their other gas production. It is reasonable to assume the Major North Slope Producers are well aware of this fact. Indeed, the commissioners are aware that ICF, a major international consulting firm, performed a study for "43 ExxonMobil Corporation 2006 Annual Report at 41 (2007); ExxonMobil Corporation, 2007 Financial and Operating Review at 56 (2008). Similarly, BP’s Bontang, Indonesia LNG plant, one of the largest in the world, produced 18.4 million gross tons per year in 2007 and Conoco’s QatarGas3 Joint Venture, scheduled to be completed in 2009, is projected to produce 7.8 million gross tons per year. 27 MAY 2008 3-155 AGIA Analysis of the Likelihood of Success Written Findings and Determination the Major North Slope Producers assessing the impact that an Alaska natural gas pipeline @ would have on the prices of natural gas and LNG in the U.S (ICF 2008). Thus, it is reasonable to conclude that, even though the It is reasonable to conclude that, even though the Project would the Major North Slope Producers, they may wish to delay increase the amount of natural the Project for fear it would reduce the margins on their | 9@s sold by the Major North Slope Producers, they may wish Project would increase the amount of natural gas sold by other existing sales of natural gas. That, however, is not to delay the Project for fear it a valid excuse under Alaskan law. The Producers have would reduce the margins on their other existing sales of a duty to produce Alaska’s natural gas if they would earn natural gas. a reasonable profit on the sale of that gas, regardless whether such sales might moderate the prices they receive for sales of other gas supplies. In light of their obligations under Alaskan law, there is a reasonable prospect that the Major North Slope Producers, as rational commercial actors, will ultimately choose to support the TC Alaska Project rather than risk being found in violation of their duty to produce. Supporting TC Alaska’s Project would also enable the Major North Slope Producers to avoid exposure to other risks. In addition to the lost revenue opportunity associated with loss of their leases, the Major North Slope Producers would also lose the opportunity to book a sizeable @ amount of proved reserves. This is a growing problem in the oil industry, which could affect the market's perception of how profitable these companies will be in the future. For example, Exxon has been struggling to replace the oil and gas it produces with new reserves it can produce in the future.'“* The loss of Alaska’s reserves due to revocation of the existing leases would exacerbate this growing problem. Again, it is reasonable to assume that, as rational commercial actors, the Major North Slope Producers ultimately will choose to support the Project and thereby achieve the ability to book a significant amount of new reserves. A decision by the Major North Slope Producers to withhold their reserves from shipment over the Project could also have adverse political ramifications for the Producers. For example, a refusal by the Producers to participate in the open season for the Project could result in an effort in the Alaska Legislature to pass a “reserves tax.” Under a reserves tax, the Major North Slope Producers would pay a tax on their natural gas reserves, even if they do not actually produce "44 See, e.g., Business Wire, Exxon Mobil Corporation Announces 2007 Reserves Replacement (Feb. 15, 2008), available at http://news.morningstar.com/newsnet/ViewNews.aspx?article=/BW/20080215005650_univ.xml. @ 27 MAY 2008 3-156 AGIA Analysis of the Likelihood of Success Written Findings and Determination and sell those reserves. The potential for a reserves tax should provide the Major North Slope Producers with additional incentive to participate meaningfully in an open season, and to negotiate firm shipping agreements Alaska on reasonable terms. Moreover, if the Major North Slope Producers collectively decide not to participate in the Project open season, that collusive conduct could subject them to scrutiny under federal and state antitrust laws. Given their domination of leased natural gas reserves on Alaska’s North Slope and sales of gas { If the Major North Slope Producers collectively decide not to participate in the Project open North Slope Producers must expect that the state would | season, that collusive conduct request the Alaska Attorney General, as well as the U.S. | Could subject them to scrutiny . under federal and state antitrust Department of Justice and Federal Trade Commission | jaws. and LNG in the remaining United States, the Major to investigate any apparent agreement among the Producers to refuse to participate in the AGIA effort to bring competitive gas to the market, or other joint or unilateral anticompetitive activity that impedes or delays the construction of a gasline.'*° A statement by the Major North Slope Producers that they refuse to support the TC Alaska Project, because they prefer their own pipeline project, would be problematic, given the anticompetitive issues inherent in a producer-owned pipeline, which we discuss in Chapter 5 in comparing the two proposals. Similarly, the actions or inactions of the Major North Slope Producers could, depending on the specific facts and circumstances, implicate the statutes and regulations enforced by FERC. In general, FERC has been charged with ensuring that interstate natural gas and electricity prices are “just and reasonable.” In the wake of recent highly publicized manipulation of electricity markets, FERC has been charged with for preventing and punishing manipulation of natural gas as well as electricity prices, including any collusion for the purpose of market manipulation. '*® The state could either request an investigation by FERC, or file a complaint at FERC. Again, it would be premature at this time to speculate on specific claims that could be brought or theories that could be investigated. However, there is no reason that a FERC action should need to be "48 For example, a joint agreement to withhold goods or services in order to coerce more money from a government entity would violate Section One of the federal Sherman Act, 15 U.S.C. § 1 and its counterpart in the Alaska Restraint of Trade and Monopolies Act, AS §§ 45.50.562-596. See, e.g., FTC v. Superior Court Trial Lawyers Ass'n, 493 U.S. 411 (1990) (per se illegal for bar association to agree not to represent indigent defendants unless the government increased lawyers’ compensation). "46 Prohibition of Energy Market Manipulation, 114 FERC {| 61,047 (2006). 27 MAY 2008 3-157 AGIA Analysis of the Likelihood of Success Written Findings and Determination pursued, when the rational alternative for the Major North Slope Producers is to pave the way to reap billions in profits by negotiating firm shipping agreements with TC Alaska. Finally, a refusal by the Major North Slope Producers to take advantage of the unique opportunity presented by the Project would almost surely subject them to intense political scrutiny, at both the state and federal level. Skyrocketing energy costs, coupled with record profits by oil and gas producers, have already prompted calls by some in Congress to take legislative action, including proposals for windfall profits taxes and other initiatives. The profits for ExxonMobil alone in 2007 eclipsed the $40 billion mark (ExxonMobil 2007). If, at a time of record energy prices and record profits, the Major North Slope Producers are perceived to be preventing or stalling the development of perhaps the greatest untapped natural gas resource in the United States, which could help moderate natural gas and electricity prices, satisfy growing demand, and provide energy independence and other benefits to U.S. consumers and taxpayers, the prospect of intense congressional scrutiny seems likely. Indeed, some members of Congress have been highly critical of the FTC for what they consider the “rubberstamping’” of major oil and gas mergers, and for failing to uncover collusion in the setting of gasoline prices. Similarly, the FERC received heavy congressional criticism for allegedly failing to do enough to prevent the California market manipulation and resulting energy crisis in 2000-2001.'*” Calls for FTC and FERC investigations can be expected if the Major North Slope Producers refuse to support the Project and cause its open season to fail. The purpose of analyzing the risks of a failure to negotiate firm shipping agreements with TC Alaska is not to demonize the Major North Slope Producers. The Major North Slope Producers and other oil and gas producers have brought significant benefits to Alaska and the Nation. These companies perform incredible feats of engineering on a daily basis to produce and bring Alaska’s oil supplies to market, in some of the most extreme conditions on Earth. For that, they deserve great credit, not only from Alaskans but from the Nation as a whole. Too often, the contributions of energy companies such as these to our state and our Nation are overlooked, including their hard work to keep the lights on at night, provide heating for homes in the winter, and supply the fuel that runs the U.S. economy. The state and the Major North Slope ‘47 Pelosi, N. 2008. Letter to the Honorable William G Kovacic, April 25, 2008. Available at http://speaker.gov/newsroom/pressreleases?id=0628. See also Study Faults U.S. Regulators In Aftermath of Power Crisis, New York Times, Section C, Page 1 (June 18, 2002); See also Government Developments, Oil and Gas Journal, August 20, 2001 (stating that “the [Federal Energy Regulatory] Commission came under intense criticism and congressional scrutiny for its handling of California's electricity crisis”). 27 MAY 2008 3-158 AGIA Analysis of the Likelihood of Success Written Findings and Determination Producers have been partners for several decades, and there is every reason to be hopeful that this partnership will continue and grow. Notwithstanding the important role the Major North Slope Producers have played in developing Alaska’s oil reserves, the analysis discussed in this chapter demonstrates that the time for an Alaska natural gas pipeline project is long overdue. Record or near-record natural gas prices, both now and projected into the future, combined with an economic tariff rate for the Project, provide compelling project economics for the Major North Slope Producers and the state, as well as other stakeholders including the federal government and TC Alaska. Under these circumstances, it is reasonable to conclude that the Major North Slope Producers ultimately will decide not to withhold their supplies by refusing to negotiate firm shipping commitments, and that the other major stakeholders will take reasonable actions to do what is necessary to help achieve that goal. In sum, the commissioners fully recognize the Major North Slope Producers do not support the Project at the present time, and that there will be many challenges to overcome before success is achieved. In the final analysis, however, the commissioners believe it is reasonable to conclude that the Major North Slope Producers, as rational commercial actors, will ultimately decide to commercialize Alaska’s gas by supporting the Project instead of taking the tremendous risks associated with refusing to participate. Accordingly, the commissioners believe it is reasonable to conclude that the Project has a significant likelihood of success because the major stakeholders are likely to find a path that resolves these issues. 27 MAY 2008 3-159 AGIA Summary Written Findings and Determination F. Summary TC Alaska’s Project is likely to produce a very significant cash flow and positive NPV for the State of Alaska and for the other major stakeholders in the Project, including the Major North Slope Producers. Specifically, The State of Alaska would realize an estimated cash flow of $261.5 billion, and an estimated NPV of approximately $66 billion at a discount rate of 5%. The Major North Slope Producers would realize an estimated cash flow of $147.4 billion, and an estimated NPV of approximately $13.5 billion at a discount rate of 10%.'* TC Alaska’s Project also has a significant likelihood of success, for several reasons. TransCanada is a highly experienced, independent natural gas pipeline company, with the necessary experience (operating within the U.S., Mexico, Canada, and in arctic conditions) and financial resources to complete its Project. It has also proposed commercial terms that contain several attractive features, including the offer to share the risk of cost overruns, which are likely to improve significantly after TC Alaska negotiates commercial terms with the Major North Slope Producers. In addition, TC Alaska will likely be able to successfully overcome the key barriers to the Project, including the need for firm shipping agreements with the Major North Slope Producers. The commissioners conclude TC Alaska has a significant prospect of obtaining firm shipping commitments even in light of the Producer Pipeline project recently proposed by BP and ConocoPhillips. The potential benefits to be gained from the TC Alaska Project, and the risks to all of the parties of not taking reasonable actions to make the Project a success, are simply too large for the parties to allow the Project to fail. "48 As explained more fully herein, the Producer NPV would be significantly higher at the same 5% discount rate used for the State. 27 MAY 2008 3-160 AGIA References Written Findings and Determination G.References Alaska Department of Revenue. 2006. Interim Findings and Determination Related to the Stranded Gas Development Act. November 16, 2006. Alaska Department of Natural Resources (ADNR). Alaska Oil & Gas Report. July 2007. Available at http:/Awww.dog.dnr.state.ak.us/oil/products/publications/annual/report.htm Alliance Pipeline. 2005. Alliance Pipeline L.P. Letter to Honorable John Efford, P.C., M.P. January 26, 2005. TransCanada Alaska Company, LLC and Foothills Pipe Lines Ltd. 2007. AGIA Applicastion. November 30, 2007. Erman, Michael 2008. Oil industry costs continue steep rise CERA. Reuters. http://www.reuters.com/article/sphereNews/idUSHO44071720080514?sp=true&view=sp here ExxonMobil. 2007. Annual Report. Available at http://www.exxonmobil.com/corporate/files/news_pub_sar_2007.pdf Finizza, A. 2006. Investment Performance Metrics and Decision-Making: How Do Oil and Gas Companies Make Investment Decisions? Econ One Research. Comments to Legislature on Gas Contract and Fiscal Interest Findings, Presented to Alaska Legislature June 14, 2006. Foerster, Cathy. 2008. Alaska Oil and Gas Conservation Commission. Testimony to the Alaska Senate Resources Committee, as Reported in the Anchorage Daily News. Published January 30, 2008. Gas Daily. 2008. Top North American Gas Marketers. March 14, 2008. ICF Interntional. 2008. Fuels Markets. [Web Page] Located at: http://www. icf.com/markets/energy/fuels-markets.asp Massey, Marty. 2007. Recorded Testimony to the Alaska Legislature, House Finance Committee. May 2, 2007. McDonald, Stephan. 1971. Petroleum Conservation in the United States: An Economic Analysis. 294 pages. National Energy Technology Laboratory (NETL). 2007. Alaska North Slope Oil and Gas a Promising Future or an Area in Decline? Available at: http://www.netl.doe.gov/technologies/oilgas/publications/EPreports/ANSSummaryReport FinalAugust2007.pdf Newell, Richard. 2004. Discount Rate for State Participation in the Alaska Natural Gas Pipeline Project. Memo prepared for the State of Alaska. November 3, 2004. Pelosi, N. 2008. Letter to the Honorable William G Kovacic, April 25, 2008. Available at http://speaker.gov/newsroom/pressreleases?id=0628. 27 MAY 2008 3-161 AGIA References Written Findings and Determination PFC Energy, March 17, 2006, Assessment of the Alaska Gasline Port Authority LNG Project, Available at http://www. revenue.state.ak.us/Publications/Assessment%200f% 20AGPA%20Project.pdf Pulliam, B. 2006. Returns to State and Producers. Econ One Research. Comments to Legislature on Gas Contract and Fiscal Interest Findings, Presented to Alaska Legislature June 14, 2006 Schneider, Steven. 1977. Natural Gas Pipeline Regulation and its Impact on Value. Available at http://law.honigman.com/db30/cgi-bin/pubs/Schneidera67602.pdf. TransCanada. 2006. “TransCanada to acquire premium U.S. natural gas pipeline and storage assets” Available at http:/www.transcanada.com/news/2006_news/2006_12_22.html United States Department of Transportation, Pipeline and Hazardous Material Safety Administration (PHMSA). 2008. Comparison of US and Canadian Transmission Pipeline Consensus Standards. Draft Report. March, 2008. United States Geological Survey (USGS). 2005. Economics of Undiscovered Oil and Gas in the Central North Slope, Alaska. US Geological Survey Open-File Report 2005-1276 27 MAY 2008 3-162 Chapter Four — LNG Table of Contents A. Introduction and Summary of Analysis of LNG Project Options. ............:c:ceseseseeeseeeeeeee 4-1 B. Background C. The LNG Project Options... D. The Y Line Option E. Analysis of the NPV of the LNG Project Options. Calculation of LNG Prices LNG Volumes Costs and Schedule Related to LNG Scenarios Comparison of LNG and TC Alaska Costs and Tariffs Estimated: State: NPV 6 sesscceccsecsnscsesecsucccsscesesccsusenssocscssvscenerececannssdncessutcevsyatsveneustescacsseasn Comparison of Estimated NPVs Produced by the TC Alaska Project and thre LING) Options: crcciatevscccecectecetesevtecescssccsssscscsaonsocecoonssonsecdesdeaasonatsuss susavanvuueesscatceustses 4-35 F. TC Alaska’s Project Has a Greater Likelihood of Success Than Any CEL FES CIO. senscssnesrrtnse cneanenereerseseenareeesaennniniZietacsnn GENRES RENEE ERE EEENEEEeSeed 4-43 1. AnLNG Project Would Be Significantly More Complex, and Thus More Risky, Tamar are er ear tl I regen nme nnn iksickctscnerian RRR RRTReeroneimaned 4-43 2. AnLNG Project Would Be More Difficult To Finance Than an Overland Route .......... 4-46 3. There Is a Significant Risk LNG Would Not Provide Open Access to Future Explorers, In Contrast With the TC Alaska Project .........c.cccscsesesseeeeeeseseesesseeereees 4-47 4. The Major North Slope Producers Have Indicated Their Preference for An Chemriensd Fecal Chamue than LING CR eens ananassae ERNE 4-48 5. AnLNG Project Will Require Proven and Committed Reserves (Certified by Experts) to be Dedicated to the Project. ............:ccccescesescsseseeseeeeeseeeees 4-50 6. Exporting LNG To Asia Presents Regulatory and Political Barriers That the TC Alaska Project Would Not Face 7. An Overland Route Has a Better Opportunity than an LNG Project To Spur a Pair rican aR coset cer es crteteenenennonsmeeererereeenseeseseenernie cde 4-52 G. Conclusion H. References oS ON = ---4-50 +-4-56 Figures Figure 4-1. Asian LNG Price Formula: The Historical Period Figure 4-2. Japanese ‘S’ Curve for LNG Pricing: The Historical Period Figure 4-3. | More Recent Japanese, Korean, Tawainese, and Chinese LNG Pricey Freebies Bh orcad C0 PN eer eterrrere even senvenseneenwneasesermnnnsnnnnstistccenennnnel 4-15 Figure 4-4. Asian LNG and Henry Hub Prices in the Different Scenarios (Real 2007)... Figure 4-5. —_ Historical Oil to Gas Price Ratio 27 May 2008 Table of Contents (continued) Figure 4-6. Cost-Risk Profile for the LNG Base Case GTP Plant Construction.................. 4-21 Figure 4-7. Cost-Risk Profile for the LNG Base Case Delta Junction to Valdez Pip@line CONBIUCHON siccsscssscnncncanenecssecenemnanenonemaieucacennmncenvemenneinnsd 4-22 Figure 4-8. Cost-Risk Profile for the LNG Base Case LNG Plant Construction................. 4-24 Figure 4-9. | Execution Cost Probability Distribution for a 4.5 Bcf/d Integrated LNG Project Figure 4-10. Tariff Comparison: 4.5 Bcf/d LNG vs. TC Alaska Proposal Base Case ........... Figure 4-11. Fuel Loss Comparison: 4.5 Bcf/d LNG vs. TC Alaska Proposal Base Case....4-29 Figure 4-12. Tariff Comparison Including Estimated Incremental Fuel Costs: 4.5 Bcf/d LNG vs. TC Alaska Proposal Base Case ...........eeeeeeeeeeeseeeeeeeeeeee 4-30 Figure 4-13. Tariff with Incremental Fuel Costs and Shipping Costs.. 4-31 Figure 4-14. Tariff Build Up... cece ceeeeseeseeesseeeeseeeeseseeeesseeeseeeeeeeeeees 4-33 Figure 4-15. State Net Present Value Under Different LNG Project Configurations 4-34 Figure 4-16. Margins of LNG Project versus a Pipeline Project..............:::ccee 4-35 Figure 4-17. State NPV: Comparing TC Alaska Proposal Base Case and 4.5 Bcf/d LNG Scenario Under Different LNG Contract Price Assumptions.....4-36 Figure 4-18. Major North Slope Producers’ NPV: Comparing TC Alaska Proposal Base Case and 4.5 Bcf/d LNG Scenario Under Different LNG Contract Price Assumptions. .....2..:::s:s0.sscsconsssesssnssscesencsesssenssensssavensvenns tose 4-37 Figure 4-19. Price vs. Tariff for a 4.5 Bcf/d LNG Project and the 4.5 Bcf/d Proposal Ben aes Pipes Pl ecsennecceemnmmammnmsmmmemnanannne) Figure 4-20. Comparative State NPV; Distributions Associated with Project Cost Risk Figure 4-21. Comparative Producer NPV%o Distributions Associated with Project GOSEIRISK oiled lo sals tidal sat acoasa cadeasversseusnacscessasessessssessacesetabacaatessasaveceusssasnevassss 4-40 Figure 4-22. State NPV Under LNG and TC Alaska Pipeline Cases ..............c:csecceeeeeeeeeees 4-42 Tables Table 4-1. Liquefaction Plant Cost Ranges... Table 4-2. Stakeholder NPV for 4.5 LNG Project Under Alternative Scenarios-Base Case LNG ...0......cceceeecesceseeeeeeeeeeeeeeeeeeeeeaesseeseteaseaeeaeeaeeseteeeaeees 4-41 27 May 2008 ii AGIA Introduction and Summary of Analysis of LNG Project Options Written Findings and Determination A. Introduction and Summary of Analysis of LNG Project Options To assess whether TC Alaska’s proposed pipeline from the North Slope to Alberta will sufficiently maximize the benefits to the people of Alaska and merits issuance of the AGIA License, the commissioners have evaluated several LNG project options. For many years, proponents of Alaskan LNG projects have highlighted specific benefits that may accrue to the people of the State of Alaska from an LNG project. LNG supporters have argued in comments that LNG offers superior benefits when compared to an overland project like the one offered by TC Alaska in its AGIA Application. Alaskans must have confidence that the right path is chosen for working to commercialize North Slope gas. Therefore, a close look at possible LNG options and comparison of those options with the TC Alaska Project is necessary before determining whether awarding a license to TC Alaska will sufficiently maximize the benefits to the people of Alaska. LNG proponents assert that an LNG project offers superior economics and job opportunities. In particular, they identify an earlier in-service date and access to premium markets in Asia that combine to generate a higher NPV for Alaska. LNG supporters expect additional opportunities for jobs, compared with an overland pipeline into Canada, due to the operation of a liquefaction plant and the development of an in-state petrochemical industry that utilizes natural gas liquids. This Chapter of the Findings discusses the analysis of possible LNG options and the benefits such options could offer to the state under AGIA—including the estimated NPV to the state and the likelihood of success of the LNG options. It also compares the benefits offered by the LNG options to the benefits offered by the TC Alaska Project. The analysis of the LNG options shows the following: e Positive NPV. Several LNG project configurations would likely provide the state with a positive NPV. Putting aside any likelihood of success issues or any comparison with TC Alaska’s project, a properly configured and managed LNG project would be economic. e Likelihood of Success Challenges. Several factors negatively impact the likelihood of success of the LNG project options. For example, an LNG project would be a much larger undertaking, involving not just a pipeline and gas treatment plant (GTP) but also a costly liquefaction plant, tankers to ship the LNG overseas, and the need to secure long- 27 May 2008 41 AGIA Introduction and Summary of Analysis of LNG Project Options Written Findings and Determination term gas sales contracts with creditworthy customers. Each of these factors complicates the ability to finance and arrange an LNG project. Besides the technological difficulties, the commercial complications are substantial.’ There are simply many more links in the chain including acquisition of a firm, long-term gas supply, securing long-term firm purchase agreements, and negotiating for pipeline as well as tanker capacity (Appendix |, Section 9). In addition, the myriad commercial provisions must come together essentially simultaneously. LNG options also face an additional hurdle because the Major North Slope Producers appear to continue to view an overland route to Canada as economically preferable. Finally, LNG options face several other significant barriers, including the lack of an obvious route to open access for explorers, and political/regulatory issues which could prevent an LNG project from obtaining the necessary export authorizations. After reviewing several LNG alternatives, the Y Line concept is clearly the best LNG option. It provides the most likely way to solve The Y Line concept is clearly the best LNG option. It provides the providing substantial deliveries of gas to North most likely way to solve the problems of obtaining export the problems of obtaining export authority by American markets in conjunction with the export authority by providing substantial project. It provides for the maximum market deliveries of gas to North diversification options and allows for substantial | American markets in conjunction with the export project. sharing of essential pipeline and gas treatment costs, and also results in fewer technical elements (e.g., essential pipeline and treatment facilities) having to be designed/constructed/installed together at the same time as the liquefaction plant. ‘ As discussed in Appendix F, Section 2.1.4 and Section 2.4 of the Addendum, an LNG liquefaction terminal is more technically complex than just a pipeline project and subject to significant and material additional risks. 27 May 2008 4-2 AGIA Background Written Findings and Determination B. Background For almost as long as Alaskans have discussed a natural gas pipeline, they have talked about transporting North Slope gas south along the existing Trans-Alaska Pipeline System corridor to a tidewater facility where it would be chilled into a liquefied natural gas (LNG) form, and then transported by ship to market. As far back as the 1970s, when an Alaskan LNG project sought necessary FERC (then Federal Power Commission) authorizations, to the mid-1980s, when the Yukon Pacific Corporation was first formed with the help of former Governors William Egan and Walter Hickel, the prospect of an LNG project has intrigued resource developers and Alaskans alike. Indeed, in 1975, Senator Ted Stevens sent out a questionnaire which received 45,000 responses. The question posed: “Do you support a trans-Alaska gas pipeline as opposed to a trans-Canadian line?” The results were: Yes—85%; No—8%; and Undecided—9% (TC Alaska Application 2007, page 4). Recent surveys appear to confirm this conclusion, showing that the concept of an “all-Alaskan” LNG line has enjoyed broad support among Alaskans for many years. By the mid-1990s, two of the major North Slope producers, BP Exploration (Alaska) Inc. and ARCO Alaska Inc., began publicly discussing plans to begin an LNG project with the expectation that gas could be landed in East Asian markets by roughly 2007. Like other North Slope gas commercialization options, including various sizes of overland pipelines routed through Canada and into North American markets, the economics of an LNG option have historically been stressed. The combination of abundant sources of affordable natural gas supply closer to consuming regions and the costs of steel and labor challenged every project's economic viability. In 1999, the Alaska Gasline Port Authority (Port Authority) was created as a municipal entity. It is comprised of the Fairbanks North Star Borough, the North Slope Borough and the City of Valdez, and was formed “to develop, build or cause to be built, ...a project to monetize Alaska’s North Slope natural gas which would include a trans- Alaska gas pipeline, liquefaction and gas processing facilities and related infrastructure for the transportation of North Slope natural gas to market...” (AGPA 2007) In 2002 the Alaska State Legislature re-introduced and extended the Stranded Gas Development Act (SGDA). The Port Authority was among the interested parties that submitted an SGDA application for an LNG project as a prelude to negotiations with the state. Like other independent pipeline project proponents, the proposed Port Authority project was not supported by the administration of the time. Though rejected by then-Governor Murkowski in favor of 27 May 2008 4-3 AGIA Background Written Findings and Determination exclusive negotiations with the Major North Slope Producer consortium, the Port Authority continued to make the case publicly that it, along with all interested project sponsors, should be allowed a seat at the table. The Port Authority's argument, one embraced by many in the State of Alaska including then-gubernatorial candidate Sarah Palin, was that Alaskans stand to benefit considerably when developers and investors compete for the opportunity to monetize the state’s resources. Alaskans, both inside and outside the Alaska Legislature, recognized that preserving the state’s options was essential to striking a fair deal with whomever would ultimately begin the project. The Port Authority and those supportive of its efforts were instrumental in trying to protect the state from becoming highly leveraged in gas pipeline negotiations conducted exclusively with Alaska’s three largest producers. After the failure of the SGDA negotiation process, the legislature passed AGIA to create an open and competitive process that secured state needs and thereby ensured that state “gives” were made in exchange for essential state “gets.” The story of resource development in Alaska is one that has been told using words like “partnership” and “cooperation.” { !" many ways the tireless . . efforts of Alaskans like the Equally important, however, are the principles of competition Port Authority and _ its and fairness. Without a comparative analysis between the | supporters laid ~—_—tthe groundwork for the competitive Process North Slope Producers and the independent pipeline projects, developed through AGIA. economics of an integrated pipeline like that proposed by the whether overland to Canada or liquefied at Alaskan tidewater, Alaskans could not be expected to make an informed decision about how to cast their lot for the next several generations. In many ways the tireless efforts of Alaskans like the Port Authority and its supporters laid the groundwork for the competitive process developed through AGIA. 1. Selection of LNG Options for Analysis Both the Port Authority and Little Susitna Construction Company submitted LNG-based proposals under the AGIA process. Neither the Port Authority’s LNG project, nor that submitted by Little Susitna, are eligible for formal consideration under AGIA for the reasons documented in Appendix C. Nevertheless, the commissioners determined that the LNG option was so important to so many Alaskans that it merited consideration as a possible alternative. Therefore, while not required under the terms of AGIA, a number of conceptual LNG project options were reviewed. The project configurations considered were based upon the only market 27 May 2008 4-4 AGIA Background Written Findings and Determination signal available: the project configurations for LNG submitted by AGIA applicants, including the Port Authority, Little Susitna, and TC Alaska. In the LNG analysis, the GTP and pipeline cost data developed from the analysis of the TC Alaska application (see Chapter 3 for discussion) were used to ensure an apples-to-apples comparison of costs and cost risk with the TC Alaska Project. Costs and cost risks for the liquefaction plant were developed by LNG project experts contracted by the commissioners. These were compared, for reference purposes only, with the cost figures developed by the Port Authority and Little Susitna. Thus, in their January 30, 2008 letter to the Port Authority, the commissioners stated that they “recognize the importance to the state of undertaking a thorough evaluation of [LNG] project options, and are committed to undertaking such an evaluation before determining whether a pipeline that goes through Canada will sufficiently maximize the benefits to the people of Alaska and merits issuance of a license.” (Appendix C) The analysis greatly informed the overall Findings and Determination. 2. Analysis of LNG Options AGIA requires a determination of whether a project being considered for award of the AGIA License sufficiently maximizes the benefits to the people of the State of Alaska (AS 43.90.180). Accordingly, under the supervision of the commissioners, the Technical, Commercial, Financial and Legal Teams—including London-based Gas Strategies Consulting, an experienced LNG consulting firm—conducted a thorough analysis of LNG project options. The analysis included a comparison between LNG project options and TC Alaska’s Project. Two basic factors are critical to understanding that analysis: (1) the integrated nature of an LNG project, and (2) the fact that the primary market for Alaskan LNG supplies would likely be in Asia, not in North America. LNG comprises a series of elements forming a delivery chain, all of which must be in place in order to have a viable project (Appendix |, Sections 2 and 7.2). These elements include one or more sources of supply (fields), feed pipelines, liquefaction plant, ships and access to regasification plants. The commercial arrangements linking each of these elements are interdependent and must all be agreed to simultaneously before any firm commitments to financing or construction are made. In practice all the agreements must be signed simultaneously. For Alaska that would mean long term North Slope gas supplies, a pipeline across the state to transport that gas supply, a liquefaction terminal located at tidewater and tankers to ship the gas to Asian markets. Unlike an overland pipeline in which shippers can simply sell gas into a very liquid market on a long or short term basis as suits their needs, the 27 May 2008 4-5 AGIA Background Written Findings and Determination LNG project sponsor(s) must negotiate long-term contracts for the sale of the LNG to customers, typically large utilities. Each of the elements in this chain must be completed successfully for an LNG project to proceed. The likely market for an Alaskan LNG project is Asia.? (Appendix |, Sections 4.1 and 4.6) Japan (the world’s leading LNG importer), Korea and Taiwan lack domestic gas supplies and currently import significant quantities of LNG. Because of the lack of domestic gas supplies, future growth in the energy needs of these markets is projected to result in a growing demand for LNG. China, India and other countries in Asia also are emerging as significant potential markets. By contrast, no LNG import terminals exist on the U.S. West Coast due primarily to local opposition; other legal barriers or economic challenges also exist to shipping LNG from Alaska to U.S. West Coast markets.> One LNG import terminal exists in Baja California in Mexico, although that is relatively small and has relatively limited uncontracted capacity, and as currently configured, could not fully accommodate the volumes of gas contemplated here. Moreover, the price that can be obtained for LNG in Asian markets, both currently and in the future, is likely to be generally higher than at the Mexican terminal or other North American terminals that might be constructed. (Appendix |, Section 4.3) Thus, the focus of the analysis here is on the Asian market, which provides higher prices and a higher NPV for sales of LNG than potential markets in North America. ? The fact that both LNG applications under AGIA proposed the Asian Pacific as the market of choice further confirms this; see the ANGPA and LSCC Applications under AGIA at: http:/www.dog.dnr.state.ak.us/agia/ 3 An additional consideration for any Alaska LNG project is the applicability of the “Jones Act” (coastwise merchandise statute, 46 U.S.C. App. § 883) to any shipments of LNG to an LNG terminal located on the west coast of the United States. The Jones Act may also be a factor in the instance of LNG shipments from Alaska to Canada or Mexico that may re-enter the U.S. market. The Jones Act requires that any freight being transported between points in the United States, “either directly or via a foreign port,” be transported on a ship built in and documented under U.S. laws and owned by persons who are citizens of the United States (Id.). Thus, any transportation of LNG from Alaska to regasification terminals along the United States’ west coast would be required to meet these requirements for vessels and their ownership. The only exceptions to the statute are scenarios in which an entity transports its own freight between two terminals that it also owns (which would be unlikely in an LNG scenario), or in the instance of freight being transported to a foreign port, where the cargo is then manufactured or processed into another identifiably new and different product, and then is transported back to the U.S. Natural gas that results from the regasification of LNG would most likely not be considered such a “new and different” product to qualify as an exception to the Jones Act requirements. Additionally, the statutory language (“no merchandise...shall be transported...between points in the United States...either directly or via a foreign port...”) may be interpreted as also requiring any LNG shipped to a terminal in either British Columbia or the coast of Mexico, to comply with the Jones Act if such LNG were to be regasified and transported via pipeline back to the United States. 27 May 2008 46 AGIA The LNG Project Options Written Findings and Determination C.The LNG Project Options There are an infinite number of potential LNG project configurations that could be considered. To analyze in-state LNG options, the state decided to base its analyses upon the LNG project configurations submitted by AGIA applicants, including the Port Authority, Little Susitna, and TC Alaska. It did so for two reasons. First, the AGIA process provided an important market signal. The resulting LNG applications reflected the judgment of project proponents who had taken the time and expense to submit applications around project configurations that they believed were best. Second, the AGIA process provided a reasonable source of reference data for the state’s analysis. The AGIA-submitted project configurations provided the basis for considering a number of different project sizes and in-service dates (including project expansions). The following LNG project alternatives, which will be referred to in these Findings as the “LNG project options,” were analyzed: e 4.5 Bcfiday Option: This option assumes a 4.5 Bcf/day LNG project using a 48-inch diameter pipeline from the North Slope to Valdez.* e 2.7 Bcfiday Option: This option assumes a 2.7 Bcf/day LNG project using a 48-inch diameter pipeline from the North Slope to Delta Junction, and a 42-inch diameter pipeline from Delta Junction to Valdez.® e 2.7 Bef/day Expansion Option: One would not build a 42-48 inch diameter pipeline if the total volume of LNG that one contemplated selling was restricted to 2.7 Bcf/d. This base pipeline design makes sense only if one expects future expansions. Accordingly, the state considered a variation of the 2.7 Bcf/day project in which a capacity expansion to 4.5 Bcf/day occurs three years after the initial in-service date. This provides an optimistic ramp-up scenario, but one that is more realistic than the initial 4.5 Bcf/d case. (Appendix |, Section 2) * This scenario is similar to the volume and pipeline facilities proposed in Little Susitna’s incomplete application. In addition, the cost and schedule uncertainty associated with a 4.5 Bef/d project, configured (as was the Port Authority's) with a 48” pipeline to Delta Junction and a 42” pipeline from Delta Junction to Valdez, was also assessed; see “Case 1b” as discussed in Appendix F, Addendum A and Exhibit D, LNG Options Analysis. However, we did not run project economics on this case, as its costs were marginally greater than the other 4.5 Bcf/d, 48” pipeline case that we did model. 5 This scenario is similar to the volume and pipeline facilities proposed in the Port Authority's incomplete application. 27 May 2008 47 AGIA The LNG Project Options Written Findings and Determination e Y_Line Option: The state also analyzed a 4.5 Bcf/day project to Alberta (like the TC Alaska project), expanded to 6.5 Bcf/day capacity through the addition of a 2.0 Bcf/day expansion from the North Slope to Delta Junction and addition of a pipeline to Valdez after the initial in-service date of the project.® Direct comparison of the TC Alaska 4.5 Bcf/day project and an LNG project is in some ways best facilitated by considering the 4.5 Bcf/day LNG project. Volumes are the same, and project timing is similar. This brings the comparative net backs into focus. Accordingly, we consider the 4.5 Bcfiday LNG project configuration as the LNG Base Case. However, the LNG Base Case overstates the NPV that the state might achieve through an LNG project, because such large initial volumes cannot be practicably brought to the Asian Pacific market (Appendix G1, Section 7.12.4). The LNG Base Case, as modeled, is highly unlikely to occur. It is very unlikely that such large volumes of LNG could be brought to the Asian Pacific market all at once; LNG volumes would very likely have to be phased in over eight to ten years (Appendix |, Sections 2 and 6.2). This is due to the Asian market's inability to absorb an incremental 4.5 Bcf/day as quickly as the very liquid AECO (North American) market.’ This ramp up was not directly modeled in the NPV analysis, but it is a reality. Further, the 4.5 Bcf/day scenario is also made unlikely because Asian Pacific buyers typically require certification of twenty years’ worth of reserves (Appendix |, Section 4.6). In addition, if Point Thomson gas were not available to be committed to the LNG project, then twenty-year contracts at even 3.5 Bcf/d would still require new gas reserves to be brought on-line, raising questions about the viability of a project this size (Appendix G1, Section 6). Before discussing the 4.5 Bcf/day LNG Base Case, we will address in the following section the unique issues raised by the Y Line LNG option. ® The cost and schedule uncertainty associated with an initial 6.5 Bcf/d Y Line project was assessed, along with a later Y Line expansion; see “Case 2” and “Case 2a” as discussed in Appendix F, Addendum A and Exhibit D LNG Options Analysis. Such a project configuration is consistent with TC Alaska’s Application (see Application at 2.2.3.14). However, economics were run only on the Y Line expansion, rather than an initial 6.5 Bcf/d Y Line project. On balance, proved gas resources do not appear sufficient to support 6.5 Bcf/d at initial operations. ” For discussion of AECO Hub market liquidity, see Appendix G2. 27 May 2008 48 AGIA The Y Line Option Written Findings and Determination D. The Y Line Option In its application, TC Alaska has stated a willingness to consider constructing, in addition to its mainline to AECO, a lateral to the Valdez area if market demand for a Y Line option is expressed by potential shippers during an open season. Specifically, TC Alaska states that “[while its proposal does not include an LNG option, [it] is willing to consider offering gas treatment and gas transportation services from Prudhoe Bay to an LNG terminal should Shippers commit sufficient volumes to support such services in the initial binding open season.” As discussed by TC Alaska in their application, the Y Line option assumes a 48-inch diameter pipeline through Delta Junction to Alberta where it could be connected to the AECO Hub with an initial capacity of 4.5 Bcf/day, and a 30-inch diameter pipeline from Delta Junction to a liquefaction plant in Valdez with a capacity of 2.0 Bcf/day (TC Alaska Application 2007, Appendix D). TC Alaska offered to construct the 2.0 Bcf/day pipeline to Valdez as part of the initial Project if sufficient volumes were committed in an initial open season (TC Alaska Application 2007, page 13). A Y Line option could be viable even if volumes for the LNG portion were not committed at the time of an initial open season. TC Alaska would have the commercial motivation to expand their Project facilities if, at some later date, a producer or group of producers wished to market their gas as LNG. But even if TC Alaska did not wish to facilitate an LNG Y Line, TC Alaska would be required to expand the project as far as Delta Junction under AGIA’s expansion provisions (AS 43.90.130). From there, given FERC interconnection policy (FERC 2000), a different sponsor could construct the Y Line lateral and necessary liquefaction facilities. 1. Benefits of the Y Line Option This Y Line alternative would give Alaskans several distinct benefits. A Y Line could piggyback on, and enjoy the superior likelihood of success of, TC Alaska’s proposed project to the AECO Hub. It could also, from a portfolio approach, provide superior economics for Alaskans. The optionality created by having a lateral which supplies an LNG project at Valdez could act as a “hedge” against the risk that pricing projections do not turn out as expected. Much in the way ® See TC Alaska Application, Executive Summary, p.5 and pp. 16-17. TC Alaska also provided, as part of its Application, a discussion of a study it performed of the Y Line option, and of related tariffs for the GTP and pipeline associated with that option. See TC Alaska Application. 27 May 2008 4-9 AGIA The Y Line Option Written Findings and Determination that a diversified portfolio of several stocks is less risky than holding only a single stock, a Y Line would leave the state less exposed to the risk that the price in any one particular market would fall below expectations. A Y Line may also be attractive to gas producers who would prefer access to Asian markets. The factors that go into a producer's identification of a preferred market go beyond NPV. There may be significant strategic advantages to pursuing LNG that a particular producer may decide outweigh NPV considerations. By working with TC Alaska, LNG proponents would also secure the benefits provided by AGIA for the pipeline and GTP components of the LNG project. These include open access and expansion provisions that would help encourage the maximum development of the state’s abundant natural gas reserves on the North Slope. As explained later in this Chapter, absent an overland route to North American markets, an LNG project pursued outside of the AGIA process would probably not provide all the open access and expansion benefits mandated by AGIA. The Y Line option would have another, related benefit: more jobs. A Y Line would create additional jobs needed to construct and operate the liquefaction plant at Valdez. In addition, the larger 6.5 Bcf/day project would require more exploration and development on the North Slope and would generate significant new employment. A Y Line would need producers and explorers to develop, in addition to the gas resources at Prudhoe Bay, other substantial resources located on the North Slope. The access and expansion provisions mandated by AGIA are essential to ensuring that such development does in fact occur. A Y Line would also provide the state and its citizens with additional revenue. As discussed in the Commercial Team Report, a 6.5 Bcf/day Y Line would provide the state with a significant additional NPV on top of the NPV provided by TC Alaska’s 4.5 Bcf/day project into the AECO Hub. While the NPV of the Y Line would not be as high as the NPV of a 6.5 Bcf/day expanded pipeline to AECO, a Y Line could, as explained above, be a more attractive option for some producers and would provide the state with a more diversified “portfolio” with less exposure to the risks of fluctuations in gas prices (Appendix G1, Section 7). Ultimately, whether an overland project to AECO is expanded to transport additional gas through the AECO Hub or through a Y Line that supplies an LNG terminal in Alaska will be determined by a variety of economic, technical, regulatory, and political factors. This analysis takes no position regarding which of these two expansion options should be favored by the 27 May 2008 4-10 AGIA The Y Line Option Written Findings and Determination State of Alaska. Indeed, the state’s essential position is that the decision will likely best be made by the relevant commercial parties. TC Alaska’s statement of its willingness to listen to competitive market forces in determining whether the Y Line option should be pursued provides the state with an intriguing option. Given the additional obstacles facing an LNG project at this time in comparison with an overland route, in the commissioners’ view the best way to increase the possibility of a future Alaskan LNG project is to encourage the initial construction of an overland route. Once an overland route is under development, the momentum created by that project may create the environment needed to overcome the additional barriers facing an LNG project. Once an overland pipeline project is under way or in place, the LNG project will be able to share The best way to get an LNG project is to first get the TC the cost of the gas treatment facilities and pipeline from the North Slope to Delta Junction, and will not bear all of those | Alaska overland project. costs alone. This fact alone also reduces the financing requirements related to the LNG project. Further, once Alaskan gas is flowing (or about to flow) into North American markets, the chances are higher that U.S. agencies will allow export of domestic energy supplies to foreign markets. Putting this as simply as possible, the best way to get an LNG project is to first get the TC Alaska overland project. 27 May 2008 4-11 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination E. Analysis of the NPV of the LNG Project Options The calculation of the estimated NPV of the various LNG projects involves the same basic factors discussed in Chapter 3 with respect to the TC Alaska Project.® For ease of comparison with the TC Alaska 4.5 Bcf/day Base Case, and because it produces a higher estimated NPV than the other LNG options, the following discussion summarizes the NPV analysis with specific regard to the 4.5 Bcf/day Base Case LNG Project scenario, described in Section C above. Details concerning the economics of the 2.7 Bcf/day LNG cases (with and without expansion) are provided in Appendix G1. 1. Calculation of LNG Prices One cannot simply look up “the price” of LNG in the Asia Pacific market. Instead, the vast majority of gas is sold under long-term (e.g., 20-year), take-or-pay, bilateral negotiated contracts. The terms of these contracts are, in the main, confidential (Appendix |, Section 4). This is very different from the natural gas market in North America, where there are public and transparent prices at numerous natural gas trading “hubs.” Accordingly, to better understand LNG prices, the state retained Gas Strategies, an international consulting firm, to analyze the 10 question of the potential price that Alaskan LNG could command in Asia. Because it has been and continues to be directly involved in a number of actual LNG deals, Gas Strategies has the market intelligence to gauge not only the terms under which past contracts have been struck, but also to reasonably assess where they are going, and why." The need for bilateral contracts is driven, in part, by the structure of Asian markets’ demand. The North American market is both significantly larger and interconnected; the Asian LNG market is really a collection of segmented markets which in aggregate are about half the size. 8 Price is the first factor in the NPV calculation: price times volume less cost equals net cash flow, which after adjustments for the project's schedule and discount rates equals NPV. '° In addition to analyzing LNG prices, Gas Strategies also provided details on other relevant issues, including the structure of LNG markets, particularly in Asia, (see Section 4 and Exhibit A of Appendix |), as well as the structure of LNG business arrangements (see Section 7 of Appendix |) and financing (see Section 8 of Appendix |). In addition, the state relied upon Gas Strategies’ market intelligence and industry expertise for estimates of LNG shipping costs between Alaska and Asia (see Appendix |, Section 5.8). The analysis of LNG options also considered input from Goldman Sachs on the structure of LNG arrangements and financing LNG projects. (See Section VI.C of Appendix H). "' Gas Strategies’ general conclusions about historical contract terms were generally verified by Wood Mackenzie's subscription-accessed database of inferred LNG contract terms. 27 May 2008 4-12 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination Total North American demand in 2007 was roughly 30 Tcf; total Asian demand for LNG (which spans disconnected markets in Taiwan, South Korea, Japan, and China) is in the neighborhood of 14 Tcf. (EIA 2008a; NEB 2007; Appendix |, Section 5.3). The particular pricing terms established in a given contract will be a function of the demand and LNG supply conditions that exist at the time that the bilateral contract is being negotiated. Once those terms are struck, the buyer and seller are largely stuck with them, subject to periodic (and potentially limited) reopeners. This places certain risks on both buyers and sellers of LNG. If, as a seller, you are negotiating your contract during a period of tight supply, then you may be able to lock in favorable terms. However, the converse can also occur. For illustration we briefly review the Asian LNG pricing history provided by Gas Strategies (Appendix |, Section 4.5.2). In Asian markets, as a general rule, prices are set by a formula that links gas price to crude oil price (normally Japanese import prices, known as JCC). For many Asian contracts struck from 1986 until 2001, LNG was priced off crude oil in a formula that provided a premium (on an energy basis) to crude oil for oil prices below about $29, and a value decrement for prices over $29. Figure 4-1. Asian LNG Price Formula: The Historical Period Pins 311 ‘$20 Pcrude Applicable Range 7 LNG Price PLN = 0.1485 x PCrude + Constant Crude Parity PLNG=0.172 x PCrude Source: Gas Strategies Consulting; (Gas Strategies, Section 4.5.2.1) Some contracts during this period were priced off crude oil that generated “S-curve” LNG price movements as crude oil prices change. In such contracts the LNG price premium (on an energy basis) was greater at lower oil prices, but was reversed at about $25 oil. 27 May 2008 413 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination Figure 4-2. Japanese ‘S’ Curve for LNG Pricing: The Historical Period eas Pine $11 $16 rye) Pctude ~—— Applicable Range ~~ Source: Gas Strategies Consulting; (Gas Strategies, Section 4.5.2.1) However, from 2001 to 2004, there was a shortage of buyers of LNG in the Asian market. LNG buyers were able to negotiate contracts with hard ceilings, such that gas prices (though by formula linked to oil) would top out when oil hit $25. At current oil prices the ceilings mean that these contracts are enormously more favorable to the buyers than the contracts negotiated in the earlier period. Since 2005, LNG sellers have enjoyed significantly better terms, and are currently obtaining values very close to crude oil parity (on an energy basis). LNG pricing terms need to be understood as being “sticky.” Once the deal has been done, the supply becomes essentially locked into the market for the full duration of the contract; prices can only be readjusted toward the prevailing market level at roughly five-year intervals (Appendix |, Section 4.6). Accordingly, much hinges on market conditions at the time that the contracts are negotiated. 27 May 2008 4-14 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination @ Figure 4-3. More Recent Japanese, Korean, Tawainese, and Chinese LNG Prices Related to Crude Oil Price 14 End-2006 2 a 3 12 £ 10 Mid-2006 ® = < 8 Early 2006 o Pre-2000 = 6 Late 2005 4 Early 2005 2002-2004 2 T ey T T T T T T i i T T™11 10 20 30 40 50 60 70 80! Price in $/bbl —— Legacy Japanese — China —® Kogas 2005 —*&- New Japanese —— Early NWS Renewals —Later Renewals ~~ RasGas - Kogas end 2006 -® Crude Oil Parity @ Source: Gas Strategies Consulting; (Gas Strategies, Section 4.5.2.1) a. Forecasting LNG Price Scenarios To develop a projected LNG price for purposes of evaluating the NPV of the LNG project options, Gas Strategies developed three price scenarios—a Base Case, a High Case, and a Low Case. These phrases—‘Base,” “High,” and “Low’—do not refer to the LNG prices that will be realized. Rather, they refer to the general LNG contract terms in relation to crude oil prices. Within a given contract's pricing terms (be it “Base,” “High,” or “Low’), if crude oil prices are high then, all else equal, LNG prices will also rise. If crude oil prices are low then, all else equal, LNG prices will fall.'? Accordingly, as a general matter a “High” contract regime will result in a higher LNG price for a given oil price than does a “Low” contract regime. The Base Case price scenario expects that there will be a balance between LNG supply and demand in Asia, such that sufficient LNG projects will be developed to satisfy the market. This scenario has generally existed for most of the last 40 years (with instances of market ” All else is not equal in the Low Price contract scenario. Under such contract LNG prices become tied, not to crude oil, but to Henry Hub prices. @ 27 May 2008 4-15 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination imbalances reflected in the wide disparity of contracts compared to the price of oil). This is a reasonable scenario considering that the structure of the LNG business in Asia is grounded on long-term contracts, meaning that new LNG projects typically cannot proceed until they have secured long-term LNG sales contracts. As a result, it is difficult for supply and demand to be out of balance for a sustained period of time (Appendix |, Section 5.2). Gas Strategies recommended that, for our Base Case evaluation, the contract terms used to derive a delivered price should be: LNG Price = 0.1485 x (Brent price of crude oil) + $0.90 (Appendix |, Section 5.4)."° The High Case price scenario projects that the current LNG supply tightness in Asia will continue, even though it represents a divergence from the market conditions that have tended to exist for several decades. This recent tight supply situation is due, in part, to problems with Japanese nuclear reactors, decline of Indonesian supplies, high liquefaction plant costs, environmental opposition to new projects, social and political challenges in producing countries, and strong economic growth driving energy consumption in the market area (Appendix |, Section 5.5). Gas Strategies recommended that for our High Case evaluation, the contract terms used to derive a delivered price should be: LNG Price = 0.162 x (Brent price of crude oil) + $1.00 (Appendix |, Section 5.5). The Low Case price scenario requires a sustained recession that slows energy and other demand for LNG in Asia with reduced development costs, leading to an oversupply of LNG. This scenario could lead to an extremely low LNG price, and would require a “profound period of stagnation in the US and/or Europe similar at least to the problems of Japan post 1990...” (Appendix |, Section 5.6). Gas Strategies recommended that, for our Low Case evaluation, the contract terms used to derive a delivered price should: LNG Price = 0.9 x (Henry Hub price of gas) - 0.5 (Appendix |, Section 5.6). To turn Gas Strategies’ pricing formuals into a forecast of actual LNG prices, a forecast of Brent crude oil and Henry Hub prices is necessary.“ For these the state relied on Wood Mackenzie’s forecasts. As discussed in Chapter 3, Wood Mackenzie’s views of these particular commodity '3 The ‘Brent price of crude oil’ is an internationally-used benchmark for oil produced in Europe, Asia, and the Middle East. The Brent price is similar to the West Texas Intermediate price, which is the benchmark price often quoted for oil produced in the Americas. "4 These prices are the variables on the right hand side of the contract-formula equations. If values for these variables are entered, then an LNG price results. 27 May 2008 4-16 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination prices is logically and internally consistent with their views of AECO Hub commodity prices. This permits an “apples to apples” comparison of prices between the AECO Hub (for the TC Alaska Project) and Asian Pacific LNG prices (for an LNG option). Assuming Wood Mackenzie’s forecasts of oil and Henry Hub prices are valid, the resulting Base Case price for LNG in the Asian Pacific market in 2020 (in constant 2007 dollars) shows a premium of approximately $3.00 over Henry Hub prices. The High Case price for LNG in 2020 (in constant 2007 dollars) shows a premium that is approximately $4.00 over Henry Hub prices in 2008. The Low Case price for LNG reflects a discount of approximately $2.50 from Henry Hub prices (Appendix |, Section 5.7). This is depicted in the following chart: Figure 4-4. Asian LNG and Henry Hub Prices in the Different Scenarios (Real 2007) Scenario LNG Prices 18.00 16.00 14.00 12.00 —High 10.00 — Base $/MMBtu 8.00 Low —HH 6.00 4.00 2.00 0.00 + HP gr grag ge ge Poh PP PPO KP SK Me Year Source: Gas Strategies Consulting/Wood Mackenzie Recent spot prices and recently negotiated contract prices in the Asian Pacific markets are trading at a greater premium (sometimes as high as $10) than the $3.00 premium generated by our Base Case. At today’s oil prices and gas prices, the premium provided by the Base Case is 27 May 2008 417 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination closer to $7/MMBtu.'° That is, if an LNG contract for Alaska gas could be struck today at the Base Case contract price, then the premium over Henry Hub prices would be around $7. In trying to think about LNG prices more than ten years into the future, the relevant question becomes two-fold: what contract terms might one receive, and what would be the price premium in the Asian market relative to Henry Hub? The extent to which Base Case or High Case contract terms yield an Asian LNG price premium depends significantly on the relationship of the price of oil, on an energy equivalent basis, to the price of gas in North America. In historical terms, oil is currently trading at a significant premium to North American natural gas. The oil price to gas price ratio fluctuates over time. For the period of January 1995 to March 2008, the ratio was as high as 14 to 1 and as low as 3 to 1, with an average 8 to 1 (Appendix G1; Section 7.15.4.3). Figure 4-5. Historical Oil to Gas Price Ratio 16 —— a a yn o Oil (Nominal $/Barrel) to Gas Price (Nominal $/MMBtu) Ratio © 0 r r r T Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 JanO01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Source: Black and Veatch 2008, Appendix G1, Section 7.15.4.3 'S Based on Oil Daily’s reported spot prices for Brent ($120.82) and Henry Hub ($11.52) on 5/14/2008. Oil Daily, 58 (94):2. May 15, 2008. 27 May 2008 4-18 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination There are good reasons to think that the current price relationship—in which oil is priced significantly higher than North American gas—is unlikely to persist over the relevant time frame. Gas Strategies predicts the current higher premium is not likely to continue, and that during the relevant time frame of any Alaskan LNG project, LNG and North American natural gas prices will likely converge somewhat, trading at prices closer to Henry Hub (and AECO) prices. According to Gas Strategies, “it is unlikely that supply would be as tight as it is at present for a full 20 year period. In practice we would expect the high prices to pull forward enough supply to bring the market back into balance within 5 to 10 years.” (Appendix |, Section 5.6) There is more than enough new LNG supply coming on stream over the next four or five years to eliminate the projected shortfall in Asia. These quantities are targeted to supply the U.S. or U.K. markets, but because these markets are liquid and flexible some or all of the LNG could be diverted to Asia. These diversions would clearly weaken prices in Asia and strengthen them in the U.S. (the rigid Asian contracts would strongly inhibit the reverse happening). In other words, as the United States becomes more dependent on LNG supplies in the next decade, LNG customers in the U.S. will have to pay a (higher) competitive price to attract LNG away from other world markets."® (Appendix |, Section 4.7.) Growing global competition for reliable gas supplies, including an increased North American reliance on LNG, will create upward price pressure on LNG. Higher LNG prices will also tend to increase AECO and Henry Hub prices, because sellers will only introduce LNG cargoes to those locations if they can demand a price similar to the price received in competing LNG markets. For example, an LNG supplier is unlikely to dispatch a tanker to North America unless either (a) all of the alternative markets were fully supplied and the only remaining demand was in North America or (b) the market in North America was price competitive with other markets. Accordingly, LNG will act as a force to re-link oil and North American gas prices. (Kelly, 2008) While Gas Strategies predicts that the current premium is not likely to continue, it believes that the Asian Pacific markets will continue to pay some premium over the Henry Hub price for LNG to ensure the security of its supplies because it does not enjoy the flexibility provided by the diversity of supplies and the significant gas storage facilities that exist in the United States. As a *® In actual fact prices will not rise to attract imports on a transactions basis. Rather, the widely-forecasted supply gap in North America will cause prices to rise, which in turn will create incentives for LNG suppliers to sell LNG into the North American market. Still, the effects are the same: it is “as if North American consumers were paying a higher price to attract LNG cargoes. 27 May 2008 4-19 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination result of these factors, Gas Strategies believes its projected Base Case price, which represents a moderate easing of the currently very tight market situation, is appropriate (Appendix |, Section 5.4). Another driver behind that eventual convergence, independent of the fundamental commodity supply-demand relationship between LNG and natural gas, is the relative price of oil and North American natural gas. As the price of oil diverges from North American natural gas, resources—drilling rigs, geological and engineering expertise—are diverted from North American natural gas exploration and development to pursue more profitable oil opportunities. Given scarce expertise and equipment in the oil and gas sector, divergently high oil prices will tend to reduce resources devoted to developing North American gas. The result of the migration in exploration and development resources will be a reduction in North American natural gas reserves replacement. Depletion without replacement, again considering the relative inelasticity of North American natural gas demand, should begin to tilt the scales such that the value of domestic natural gas rises (Appendix G1, Section 7.15.4). A detailed discussion of pricing relationships between North American gas and oil prices is contained in Black and Veatch’s expert report (Appendix G1, Section 7.15.4). It concludes that, while the price relationship is uncertain, it is more likely that North American natural gas prices will tend to return to their historical average relationship with oil. If Black and Veatch, Gas Strategies, and Wood Mackenzie’s views are correct, then the substantial current-day premium received for Asian LNG is likely to narrow significantly. 2. LNG Volumes The second factor in the NPV calculation is volume. The primary LNG scenario addressed here has the same production volume used to analyze the TC Alaska Project Base Case. Gas volumes for the other LNG project options discussed above are summarized in Appendix G1, Sections 7.4, 7.5 and 7.6. 3. Costs and Schedule Related to LNG Scenarios The third factor in the NPV calculation is cost. There are three main cost components for an Alaskan LNG project: (1) the cost of the pipeline and GTP; (2) the cost of the liquefaction plant 27 May 2008 4-20 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination in Alaska; and (3) the cost of tankers to transport the LNG to on the market.'” Those three cost components are summarized below. Pipeline and GTP Costs. The commissioners’ Technical Team estimated a cost and schedule for the GTP and pipeline system (Appendix F, Exhibits B and C). For purposes of estimating the GTP and pipeline costs, the Technical Team used much of the data and analysis that it had already developed while analyzing the TC Alaska Project. This ensured that the GTP and pipeline components of LNG project options were, to the extent possible, based on the same cost assumptions used to analyze the TC Alaska Project (Appendix F, Sections 2.2, 2.3, and Exhibit B). Those data were used in the Technical Team’s Monte Carlo simulation; the results of that process were provided to the Commercial Team for its NPV analysis of each scenario. For the 4.5 LNG Base Case, the current-dollar GTP costs are essentially the same as for the TC Alaska Application (Appendix F, Addendum A Sections 2.2 & 2.3; LNG Options Analysis Exhibit D). Figure 4-6. Cost-Risk Profile for the LNG Base Case GTP Plant Construction AGIA LNG Options Cost-Risk Profile for LNG 3: 4.50 befd (48") Gas Treatment Plant 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% —— 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 Potential Outcome $Millions 0% Source: Westney 2008. Appendix F, Addendum A. ‘’ The state’s NPV analysis of LNG project options modeled LNG prices into the regasification terminal; accordingly, there is no need to consider regasification costs in the “net back” calculation. 27 May 2008 4-21 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination For NPV modeling purposes, cost ranges for the pipeline subprojects for the LNG project options are, on a per mile basis, essentially the same as that of the Alaska portion of TC Alaska’s pipeline subproject. The Monte Carlo based probability distributions of pipeline costs for the Delta Junction to Valdez pipeline subproject are shown below. Figure 4-7. Cost-Risk Profile for the LNG Base Case Delta Junction to Valdez Pipeline Construction AGIA LNG Options Cost-Risk Profile for LNG 3: 4.50 befd (48") Delta Junction to Valdez Pipeline LNG3 Cost 4 DJ-V PL 080313.x1s Total Chart Printed: 3/24/2008 Source: Westney 2008. Appendix F, Addendum A. Liquefaction Plant_Costs. The process of establishing a probability distribution for the liquefaction plant differed somewhat from that used for the GTP and pipeline subprojects. The Technical Team did not have an AGIA-compliant application to directly evaluate regarding the cost of the liquefaction. Accordingly, they could not follow the process used to generate Monte 27 May 2008 4-22 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination Carlo probability distributions for the pipeline and GTP (Appendix F, Addendum A, Section 2:4).° Therefore, rather than trying to generate a probability distribution of costs from the “bottom up,” based on subproject cost components, their ranges, and their probability distributions, the Technical Team chose to generate a cost estimate from the “top down.” That is, the approach relied on existing data on liquefaction costs from actual projects around the world to generate a representative distribution of liquefaction costs per ton for an Alaskan LNG project. As a first step, the Technical Team mined data contained in the Westney proprietary data base that shows the costs per ton of LNG output for several recently constructed and operating LNG plants. These liquefaction plants vary in size from about 3.25 million tons per annum (mtpa) to 8.9 mtpa (0.42 Bcf/d to 1.16 Bcf/d), and went into service between 2003 and 2007 (or are currently under construction).'? The cost per ton of LNG for these plants ranges from a low of less than $350 to over $1,300 for the Snohvit project in Norway (Appendix F, Addendum A, Section 2.4). Because the projects were constructed at different times, cost components for each LNG plant (e.g., compressors, vessels, pipe, electrical, etc.) were reviewed on a commodity basis and then escalated to 2007 dollars. Because the projects in the data set are generally located in developing countries and in tropical climates, each project cost was adjusted to an Alaska basis for the costs of construction (i.e., using projected labor rates and productivity factors for Alaska). Finally, the highest and lowest costs of liquefaction were excluded from the Westney data set as being unrepresentative. The remaining data were then reviewed and confirmed against the global LNG data base of Merlin Associates (Appendix F, Addendum A, Section 2.4). Based on an adjusted data set of liquefaction costs, the best cost case and the worst cost case were used, together with an assumed normal (or “bell shaped”) probability distribution, to generate a full probability distribution of Alaskan per ton liquefaction costs. The train sizes for the relevant LNG case under consideration then determined the entire Monte Carlo-based ‘8 For the TC Alaska subproject cost estimates, the Technical Team started with “base case” cost estimates of the major components. These were used to establish an overall Monte Carlo based probability distribution based on separate “best” and “worst” case ranges of each of the major cost components and distributions. This process could not be followed for the liquefaction estimate in part because, absent an AGIA-compliant applicant, there was no ability to engage in the necessary clarification process of estimates and assumptions. '® One mmtpa of LNG is approximately equivalent to 140 MMcf per day of gas. 27 May 2008 4-23 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination probability distribution for the liquefaction plant costs. The result for the 4.5 Bcf/day LNG project is shown below. Figure 4-8. Cost-Risk Profile for the LNG Base Case LNG Plant Construction AGIA LNG Options Cost-Risk Profile for LNG 3: 4.50 befd (48") LNG Plant 15,000 Source: Westney 2008. Appendix F, Addendum A. Figure 4-8 indicates that the midpoint (or “P50”) probability cost of the LNG liquefaction plant is approximately $22.5 billion. The entire range of possible costs is very wide. This is due both to the location and unusual market conditions that have affected liquefaction plant costs for the data set used to assess plant cost risks. But it is also due to the fact that liquefaction plants are quite complex (See discussion in Appendix F, Section 2.4). Because the cost range is wide, the Technical Team recommends that the middle 50% of the probability range—excluding the top 25% and bottom 25% of costs—provides a more useful lens for considering project cost risk. This generates a range of $17.5 billion to $27.5 billion. 27 May 2008 4-24 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination Liquefaction cost ranges for other LNG project configurations are summarized in the following 20 table. Table 4-1. Liquefaction Plant Cost Ranges LNG P25 Value (75% probability | P75 Value (75% probability of Cases Volume of exceeding value) not exceeding value) 19 mmtpa $10.8B $17.6B ire ern (2.45 Befd) 568 $/T 926 $/T 2.7 Befiday 315 $17.4B $27.9B | Expansion Option _| (4.06 Befd) 552 $/T 885 $/T ' ; 13.9 $8.1B $13.7B Y Line Opti a (1.79 Befd) 582 $/T 985 $/T 31.5 $17.4B $27.9B foe 4.06 Befd 552 $/T 885 $/T Source: Westney Consulting. Appendix F, Addendum A, Section 2.4. At “P25” there is a 25% likelihood that the actual costs could be lower than stated; at “P75” there is 75% likelihood that the costs would be lower than stated." Putting all of the pieces together, the risk distribution of the integrated capital costs of a 4.5 Bcf/day project are shown below. 20 The volumes of each of these cases assume no natural gas liquids (“NGL”) extraction, in order to meet the minimum quality requirements of the Asian Pacific markets which is consistent with the market analysis of Gas Strategies (Appendix |, Section 2). However, the Technical Team determined that propane in the quantity required to supply the current and near-term future market in Alaska can be extracted without significant reduction of either the volumes or heating value of LNG. (Appendix F, Addendum A, Section 2.4) 21 As an additional point of reference, the Port Authority and Little Susitna applications estimated the cost per ton of liquefaction capacity at approximately $550 and $520 respectively, which put them very close to the P25 estimates above. These estimates included a reasonable allocation of their estimated overhead and related costs to facilitate a fair comparison. 27 May 2008 4-25 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination Figure 4-9. Execution Cost Probability Distribution for a 4.5 Bcf/d Integrated LNG Project AGIA LNG Options Cost-Risk Profile for LNG 3: 4.50 befd (48") Integrated Project § 90% 80% 70% 60% 2 5m a 2 a 0% 30% 20% 40,000 50,000 Potential Outcome $Millions Source: Westney 2008. Appendix F, Addendum A. Not including the development schedule, the figure indicates that the mid-point (P50) cost estimate is approximately $43 billion in current dollars. There is less than a 10% probability that costs will be below $32.5 billion. Schedule The process for assessing project schedule risk for the pipeline and GTP subproject components was the same as used for the analysis for the TC Alaska project except for the risks associated with the Canadian regulatory process. To assess schedule risk for the liquefaction plant, the Technical Team analyzed the number of LNG trains that would be needed for the entire project at the largest size commercially available (so as to obtain the greatest economic efficiency and minimize the overall installation time and expense).”” This analysis 22 An “LNG train” is a complete process unit that turns natural gas into a liquid. The “train” consists of a collection of sub-units and equipment that cleans, compresses and cools natural gas into a liquid. The exact mix of sub-units and 27 May 2008 4-26 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination was predicated on the fact that there is a necessary lag between the completion of one train and the time that a follow-up train can be completed. This is because of the necessity to ensure that all of the systems for the first train are fully operational on an integrated basis before adding another train. For purposes of the analysis it was also assumed that three months was the shortest period that could reasonably be expected between completion and a train being fully operational (even though it is likely that a longer period would be necessary; see Appendix F, Addendum A, Section 2.4). The schedule range based on the number of trains was used in the Technical Team’s Monte Carlo simulation and the results provided to the Commercial Team for conducting the NPV analysis of the various cases (See Appendix F, Addendum A, Section 1.1). A comparison of the “P50” schedule for the 4.5 Bcf/d LNG case and the 4.5 Bcf/d TC Alaska Project Base Case shows that the LNG project will require approximately two additional years before the in-service date or before first gas flows. There are two primary factors behind this delay. First, it was assumed that a new state process—including, possibly, a new round of applications under AGIA—would be required for an LNG project, because it was assumed that an LNG project sponsor would require some type of state support to advance the project. This was assumed to push the start date for an LNG project back by one year to provide time for (1) an LNG project sponsor to prepare and submit a new application or proposal to the state and (2) the administration and legislature to review, analyze and approve the granting of an AGIA license. The second factor affecting the timing of an LNG project is the additional time needed to complete and place the multiple LNG trains required for a 4.5 Bcf/d project into service. Tanker Costs. Tanker costs are a significant component of an LNG project. Gas Strategies estimated that, based upon extrapolations from existing shipping rates, total shipping would come to 99 cents/MMBtu (expressed in real dollars) (See Appendix |, Section 5.8 for discussion).”* This component is included in the comparison of the estimated cash flow and NPV that would be produced by the TC Alaska Project and the LNG project options (Appendix G1, Sections 1.1 and 7.1). equipment varies depending on which proprietary technology is used. An LNG plant consists of one or more “trains” plus support facilities such as utilities, storage tanks and jetties. 3 Gas Strategies assumed somewhat larger sized tankers than did the AGIA applicants proposing LNG projects. (See, e.g. LSCC AGIA Application at p. 58). Accordingly, the tanker costs assumed here are on the conservative side. 27 May 2008 4-27 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination 4. Comparison of LNG and TC Alaska Costs and Tariffs Based on the Technical Team’s cost and schedule projections, a hypothetical levelized rate (or tariff) was constructed for each LNG option.”4 The costs to move gas from the North Slope to Valdez, including the cost of liquefaction at Valdez, would be significantly higher than the costs to transport gas from the North Slope to Alberta, even without considering the costs of shipping the LNG in tankers from Valdez to the Asian market. This is because the LNG options require a capital-intensive liquefaction facility. As shown in the chart below, there is a $3.66 per MMBtu cost difference between the LNG pipeline, GTP and liquefaction costs for a 4.5 Bcfiday LNG scenario and a 4.5 Bcf/day pipeline to Alberta (The TC Alaska Proposal Base Case). Figure 4-10. Tariff Comparison: 4.5 Bcfid LNG vs. TC Alaska Proposal Base Case $14.00 $12.00 @GTP Plant ZAK Pipeline GLNG Plant @MYukon-BC Alberta $10.00 $8.39 $8.00 $6.00 Nominal $/MMBtu $4.73 4.5 Befid LNG Project 4.5 Befid Proposal Base Case $4.00 $2.00 $0.00 + Source: Black and Veatch. Appendix G.1, Figure C-2. In addition, these costs do not include the substantial amount of shrinkage associated with LNG liquefaction. Making LNG consumes substantial volumes of natural gas, which reduces the amount of gas (or LNG) that is available for sale. As shown in the chart below (Figure 4-11), the *4 In fact, the costs would be recovered in potentially different charges reflecting the GTP, Alaska pipeline, and liquefaction segments. They are presented here as a single hypothetical cost-based tariff charge to simplify the presentation. 27 May 2008 4-28 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination difference in shrinkage between a 4.5 Bcf/day pipeline to Alberta and a 4.5 Bcf/day LNG project is material: 8.9% for the TC Project pipeline to Alberta line versus 16.5% for an LNG project. Figure 4-11. Fuel Loss Comparison: 4.5 Bcfid LNG vs. TC Alaska Proposal Base Case 18% —--—— rs - 16.5% 16% : @GTP GAK Pipeline GLNG Plant @ Yukon-BC 14% ONova 12% 10% 8% OO 4% 2% 0% 4.5 Befld LNG Project 4.5 Bef/d Proposal Base Case Source: Black and Veatch. Appendix G.1, Figure C-3. In essence, an additional 7.6% of the original gas volume is lost in the transportation and manufacture of LNG versus the TC Alaska pipeline. The value of this incremental 7.6% depends, of course, on how the gas is valued. If it is valued against the AECO price, then the lost gas is calculated as the AECO net back multiplied by 7.6%. Figure 4-12 compares the TC Alaska Project’s per unit transportation cost with the LNG project cost to Valdez, including the cost of incremental fuel “lost” to manufacturing the LNG. 27 May 2008 4-29 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination Figure 4-12. Nominal $/MMBtu $14.00 $12.00 + $10.00 $8.00 $6.00 $4.00 + $2.00 Tariff Comparison Including Estimated Incremental Fuel Costs: 4.5 Bcfid LNG vs. TC Alaska Proposal Base Case G Estimated Incremental Fue! Costs | @ Tariff with no Shipping Cost Incremental Fuel Cost Assumption: Assumes the market price of AECO in 2022 on a netback $8.77 basis before fuel times the difference in fuel between the projects. This assumption underestimates the actual cost of the fuel cost difference due, in part, to the assumption that ignores nominal price growth. $0.00 + 4.5 Bef/d LNG Project 4.5 Bcfid Proposal Base Case Source: Black and Veatch. Appendix G.1, Figure C-4. This increases the cost of the LNG project by $.37/MMBtu. Additional costs associated with shipping LNG to market through LNG tankers must be included. Gas Strategies estimates that LNG tanker and receiving port charges add up to an additional cost of approximately $0.99 per MMBtu (in real, 2008 dollars) of LNG shipped (Appendix |, Section 5.8). As shown on the chart below (Figure 4-13), this increases the cost advantage that the TC Alaska Project has over the LNG project options. 27 May 2008 4-30 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination Figure 4-13. Tariff with Incremental Fuel Costs and Shipping Costs $12.00 -<_—__________—_———- aan _— S$ @Estimated Incremental Fuel Cost $10.00 LNG Shipping @ Tariff with no Shipping Cost $8.00 $6.00 Nominal $/MMBtu $4.00 $2.00 $0.00 + 4.5 Bcfid LNG Project 4.5 Befid Proposal Base Case Source: Black and Veatch. Appendix G.1, Figure C-5. Based on the information presented above, the commissioners conclude that a cost-of-service based tariff for the 4.5 Bcf/d LNG project would be significantly higher than a 4.5 Bcf/d pipeline project to the AECO Hub (Appendix G1, Section 7).”° Indeed, under Base Case assumptions, the transportation cost for a 4.5 Bcf/d project into AECO is less than half the cost (48%) that of the LNG project (Appendix G1, Sections 1.1 and 7.3).”° This is perhaps surprising, given that difference in the integrated project construction cost, in current dollars, between the TC Alaska project and the LNG project is 38%. Factors that lead to a disproportionately higher LNG tariff include the following: ?5 Of course, there may be no tariff for a liquefaction plant. Moreover, open access tolling for liquefaction is not the model, worldwide, for LNG projects (Appendix |, Section 7.8). However, for royalty and tax calculations a liquefaction deduction would be required. The numbers used here reasonably approximate what those deductions might be. If anything, these figures are conservative as they presume a capital structure for tariff calculation purposes. °8 Critical assumptions, such as cost escalation and inflation, were held constant across the two cases to permit an “apples to apples” comparison. 27 May 2008 4-31 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination ) 2) 3) 4) 5) 6) Project capital costs. The capital costs of a 4.5 Bcf/d LNG project are $12.0 billion greater than the costs of constructing a similarly-sized pipeline project to the AECO Hub. Holding everything else between the LNG option and the TC Alaska Project fixed, the greater cost increases the LNG project tariff by $1.97/MMBtu relative to the pipeline project. Volumes delivered to market (fuel losses). The fuel usage/retention of a 4.5 Bcfid AECO pipeline project is 8.91%, compared with the similarly sized LNG project of 16.5%. Based on the Base Case price assumption from Wood Mackenzie and the Base Case Gas Strategies LNG price, this results in an approximately $0.38/MMBtu increase in the LNG tariff (assuming a 2020 start date). Operations and Maintenance costs. Operations and Maintenance costs for an LNG project will be significantly greater than a pipeline project, owing to the significantly greater complexity of the liquefaction plant. The expected impact to the LNG tariff rates from these higher expenses is $0.36/MMBtu.”” Property taxes. Property taxes for an LNG project are higher due predominantly to the higher installed capital value of the liquefaction plant.”® This further raises the LNG tariff by about $0.30/MMBtu. Later in-service date. The Technical Team estimates that an additional two years (for a P50 case) is expected for completion of an LNG project. The rising cost of manufacture coupled with the delay has a negative impact on all sections of the project. The LNG tariff is expected to be $0.11/MMBtu higher due to the GTP delay, $0.16/MMBtu higher due to the pipeline project delay, and $0.36/MMBtu higher due to the liquefaction/terminal facility delay. Interest rate for debt. An LNG project serving Asian markets will probably not qualify for the Federal Loan Guarantee provided under the ANGPA statute.”° Accordingly, the LNG project will have a higher cost of debt. A higher cost of debt on the project, as assessed 27 See Appendix F, Addendum A LNG Options Analysis, p. 64 for base line costs, derived from study at pp. 109-113; see Appendix G1 for explanation of how total O&M costs were converted to per unit terms. 28 In addition, property taxes on the LNG project are greater because a greater percentage of the project is in Alaska and Alaska has a greater tax rate than do Canadian provinces. 28 The Port Authority's AGIA application recognized that this would likely be the case: “because the project is an export project the Port Authority has not counted on qualifying for federal loan guarantees under the Alaska Natural Gas Pipeline Act of 2004” (AGPA, 2007) 27 May 2008 4-32 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination @ by Goldman Sachs, is estimated to have an adverse impact on the LNG tariff relative to the TC Alaska Project (Appendix H, Section VI.C). The size of this impact depends on which cases are being compared. 7) Shipping costs. The cost of shipping would be approximately $0.99 per MMbtu (Appendix |, section 5.8). Figure 4-14 shows how these factors build to ultimately make up the full tariff. The first bar shows the different tariffs for different components of the transportation chain that results from the 4.5 Bcf/d LNG project costs, not accounting for any of the other factors. The second bar adds in the effects of the increased LNG shrinkage at the liquefaction plant. The third through seventh bars progressively add in the effects of higher LNG O&M costs, higher property taxes, delayed in-service date, higher borrowing costs, and the requirement to ship the LNG from Valdez to Asian Pacific markets. Figure 4-14. Tariff Build Up $12.0 —— . - = | =GTP @ Pipeline From Delta to Valdez G Pipeline From NS to Delta (LNG Plant in Valdez $10.0 [LNG Shipping $9.18 $8.33 > | a $8.0 | E 70 2 2 $4.86 3 $6.0 | $4.81 ; | It 3 | { 3 | [ii q $4.0 | $0.78 $2.0 | $- eng LNG 45a LNG 4.54 LNG 45a LNG 45a LNG 45a LNG 45a LNG 4.5a Scen1 Scen2 Scen3 Scen 4 Scen5 Scen6 "Base Case" Scenario Settings [Capital Costs in 08 Dollars Case Volume ‘Same as AECO loam Same as AECO | Same as AECO Property Tax Same as AECO | Same as AECO | Same as AECO In-Service Year 2020 2020 2020 7.06% 7.06% 7.06% NIA NIA N/A Source: Black and Veatch. Appendix G1, Section 7.8.3. rT 27 May 2008 4-33 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination 5. Estimated State NPV; Despite the increased costs associated with transporting, liquefying, and shipping LNG, each of the LNG options reviewed could produce a positive NPV; for the state and for the Major North Slope Producers.” For example, under the Base Case set of assumptions, a 4.5 Bcf/day, 48- inch diameter pipeline LNG project would produce an NPV to the state of approximately $48 billion, and a NPV to the Major North Slope Producers of approximately $8.6 billion (Appendix G1, Section 7.11). The NPV results to the state for each of the LNG project options, using Base Case assumptions for contract terms, costs, escalation rates, and the like, are summarized in Figure 4-15. Figure 4-15. State Net Present Value Under Different LNG Project Configurations State NPV; $90 = $85.5 y $80 Yy $70 Yy $60 $ 3 $50 $47.1 $48.0 Y j ao ” = $20.1 Yj $20 $10 Y + 2.7 Befid LNG 2.7 Befid LNG Expanded to 4.5 4.5 Befid LNG 6.5 Bef/d Y-Line Befid LNG Source: Black and Veatch. Appendix G1, Figure C-6. % “NPV;" refers to the NPV calculated using a 5% discount rate. 4-34 27 May 2008 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination In sum, although the LNG project options have higher costs than the overland project options, they would still produce a positive NPV under the pricing and cost assumptions discussed above.*" Because of the likely need to ramp up volumes over an eight to ten year period, rather than the 3 year period assumed in the 2.7 to 4.5 Bcf/d expansion case, the actual configuration of a stand-alone LNG project is likely to provide an NPVs; of somewhere between the two left- most cases in Figure 4-15. 6. Comparison of Estimated NPVs Produced by the TC Alaska Project and the LNG Options Under Base Case assumptions for the TC Alaska Project and the LNG options, the TC Alaska Project Base Case has a higher estimated NPV than the LNG options (Appendix G1, Section 7.12.2). In general, this is because the price premium that LNG is likely to enjoy in Asian Pacific markets, relative to prices at the AECO Hub, is generally insufficient to overcome the greater total costs of transporting the LNG to market. This dynamic is graphically shown in Figure 4-16. The black line shows the LNG price level necessary for the LNG project to deliver superior net backs compared to the TC Alaska Proposal Base Case. Figure 4-16. | Margins of LNG Project versus a Pipeline Project $10.0 wa0 4.5 Bcfid LNG Netback is HIGHER than a 4.5 Bct/d Pipeline ca pT ees ananassae | | ion 4.5 Bef/d LNG Netback is LOWER than a 4.5 Bcf/d Pipeline | | | $0.0 | | } ($2.0) 7 we emia — ($4.0) ; _— | LNG High Case: Price Delta (LNG Price — = ee —— A«Co) me | (36.0) a ae isen) Transnortation Delta (LNG Tariff + Fuel Less Pineline ($8.0) 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 Source: Black and Veatch. Appendix G1, Section 7.12.2. 3" As with the TC Alaska Project, the estimated NPVs would improve or decline if more optimistic or pessimistic assumptions are used. 27 May 2008 4-35 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination Under the high contract price scenario (see Figure 4-16, for the price formula), there are a few years in which the Asian Pacific LNG market is sufficient to overcome the higher transportation costs. However, even in this unlikely High contract price case (Appendix |, Section 5.5), net backs are generally lower than under the TC Alaska Proposal Base Case. Under the Base and Low contract cases net backs never exceed those provided by the TC Alaska Proposal Base Case. As a result, the TC Alaska Proposal Base Case generates a higher NPV; than the comparable Base Case LNG project option under each contract price assumption. This conclusion is depicted in the chart below (Figure 4-17): Figure 4-17. State NPV: Comparing TC Alaska Proposal Base Case and 4.5 Bcfid LNG Scenario Under Different LNG Contract Price Assumptions State NPV; 4.5 Bciid LNG Scenario 70 $ Billions (2008) o - Oo o 353 96 Ny o 4.5 Befid 45BcfidLNG 45BcfdLNG 4.5 Bcfid LNG Proposal Base (Low Price) (High Price) Case Source: Black and Veatch. Appendix G1, Section 7.12.3. Figure 4-17 demonstrates that the TC Alaska Project would produce a significantly higher NPV for the State of Alaska than the LNG project across a range of long-term LNG contract arrangements. Under the Base Case set of assumptions, the LNG project would generate for the state an NPVs; of approximately $48 billion, while the TC Alaska Project would produce a NPV; of approximately $66 billion. The results are directionally similar for the Major North Slope Producers. Under Base Case assumptions, the NPV to the Producers, at both 10 and 15% discount rates, are greater under 27 May 2008 4-36 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination the TC Alaska Project than under the 4.5 Bcf/d LNG option. Indeed, for the Low Contract price case, the LNG option fails to deliver positive returns to the producers.** Figure 4-18. | Major North Slope Producers’ NPV: Comparing TC Alaska Proposal Base Case and 4.5 Bcfld LNG Scenario Under Different LNG Contract Price Assumptions Producer NPV 4.5 LNG Scenario $15.0 $13.5 $13.0 + $11.0 4 $9.0 $7.0 4 $5.0 $3.0 $1.0 ($1.0) + --- . Ni 1.3), : ($3.0) L = ii) se $8.6 4.5 Befid 4.5 BcfldLNG 4.5 BcfidLNG 4.5 Bcfld LNG Proposal Base Base Case Low Case Price High Case Case Price Price Producer NPV,5 4.5 LNG Scenario $3.8 $ Billions (2008) REE ($0.8) 4.5 Becfid 4.5 Bcfld LNG 4.5 Bcfid LNG 4.5 Bcfld LNG Proposal Base Base Case Low Case Price High Case Price Case Price Source: Black and Veatch. Appendix G1, Section 7.12.3. * This result differs directionally from the state’s results for several reasons. For one, the state receives property taxes and corporate income taxes from the pipeline and liquefaction projects, while these are net costs for the Producers. In addition, both 4.5 Bcf/d cases significantly rely upon YTF resources. As modeled, under base case assumptions, YTF gas is found, developed and produced to enter the projects to keep them full, regardless of their economics. Because margins under the Low Price contract assumption are poor, the damage to YTF economics serves as a drag on Producer NPVs. 27 May 2008 4-37 AGIA Written Findings and Determination Analysis of the NPV of the LNG Project Options In addition, because LNG transportation costs are higher, the LNG project options considered are more susceptible than TC Alaska’s Proposal Base Case to price risk. For a given net back margin, it takes a smaller percentage decrease in Asian Pacific LNG prices to stress an LNG project than it does to stress an overland pipeline project. This result can be visually inferred from Figure 4-19. A 50% drop in the price of LNG prices (the green line) “bites into” the LNG transportation cost (green bars) and thus leads to greater negative net backs than a 50% price drop in AECO Hub prices (the black line) “bites into” overland transportation costs (blue bars). Figure 4-19. _ Price vs. Tariff for a 4.5 Bcfid LNG Project and the 4.5 Bcfid Proposal Base Case Pipeline Project $40.00 EZ LNG Tariff with Incremental Fuel $35.00 5 Pipeline Tariff == LNG Base Case LNG Price $30.00 =" WoodMac AECO Gas Price 2008 2012 2016 2020 AN] aR) Pea eESSSESS) AAAS bee 2024 2028 2032 2036 2040 2044 Source: Black and Veatch. Appendix G1, Section 7.12.1. The analyses presented here are premised on both the TC Alaska and LNG cases coming in at mid-point probability (P50) cost levels. If costs for an LNG project come in lower than expected, then it would be better able to benefit from the expected higher Asian Pacific LNG prices. Figure 4-20 shows the state NPV; probability distribution that is generated from Base Case prices (for 27 May 2008 4-38 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination both LNG and the TC Alaska Project) and uncertain project costs. It shows the NPV uncertainty that derives from cost uncertainty associated with project scope. Figure 4-20. Comparative State NPV; Distributions Associated with Project Cost Risk 100% f T —— 4.5 Bcfid LNG with Base Case LNG prices 90% ; ' —4.5 Bcfid Proposal Base Case with Wood ' 1 80% Mackenzie AECO prices i ; 70% 1 1 t | s ' \ ' | 2a | 2 4.5AECO 4.5LNG 3 50% State NPV; Expected $66.1 $48.0 -! \ 2 Value (WM Prices): ' ' £ 40% t ‘ ' a t . | 20% : > t | 10% ; : | 0% + -$20 -$10 $0 $10 $20 $30 $40 $50 $60 $70 $80 $2008 Billions NPVs Source: Black and Veatch. Appendix G1, Section 7.12.2. Figure 4-20 shows that under the Base Case price assumption, there is less than a 10% likelihood that LNG project costs would be low enough for the LNG Base Case NPV; to exceed the NPVs of a TC Alaska 4.5 Bcf/d project. Similar results hold for comparative returns to the Major North Slope Producers from the 4.5 Bcf/d LNG project and a 4.5 Bcf/d pipeline project into Alberta. There is essentially no chance that construction costs, as measured in current-day dollars and before figuring escalation risk, could be low enough to make an LNG project more profitable for S Uncertainty of the cost escalation in inputs to construction, such as labor, steel, and the like, is addressed subsequently. 27 May 2008 4-39 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination the Major North Slope Producers under the Base Case Contract price assumptions. This may help explain why, since at least 2001, the Major North Slope Producers have demonstrated so little interest in pursuing an LNG project for Alaska gas. Figure 4-21. Comparative Producer NPV, Distributions Associated with Project Cost Risk 100% 7 moe ae ~— pee 5 —— 4.5 Bcfld LNG with Base Case LNG prices : 90% ' — 4.5 Bcfid Proposal Base Case with Wood ! 80% Mackenzie AECO prices ' 70% ' Soom 45Case 4.5LNG_ 2 Aggregate Producer NPVio $13.5 $8.6 = Expected Value (WM Prices): . . 2 50% 2 ae @ 2 Ew 30% 20% 10% . 0% -$2 $0 $16 $2008 Billions NPVi9 Source: Black and Veatch. Appendix G1, Section 7.12.2. There is another way, besides beating the odds on construction costs, that the 4.5 Bcf/d LNG project could provide better returns to the state than the TC Alaska Project’s Base Case. As noted earlier, the extent to which Base Case or High Case contract terms yield an Asian LNG price premium depends significantly on the relationship of the price of oil, on an energy equivalent basis, to the price of gas in North America. As the oil to gas price ratio rises, the price premium generated by the Asian Pacific Base and High Case LNG contracts also rises. Accordingly, a high oil to gas price ratio could improve the relative economics of an LNG project. (See Appendix G1, Section 7.15.4, for a discussion of these points.) Table 4-2 calculates the NPV difference to the state that would be provided by a 4.5 Bcf/d LNG project compared with the TC Alaska Project Base Case. It shows these differences under 27 May 2008 4-40 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination different assumptions about the oil to gas price ratio during the projected period of project operations. It indicates that, if the oil to gas ratio was sustained at ten or above, an LNG project of this magnitude could generate superior returns to the state as compared with an overland project.* Table 4-2. Stakeholder NPV for 4.5 LNG Project Under Alternative Scenarios-Base Case LNG Scenario U.S. Government Producer 4.5 Befid LN 8 to 1 Oil to Gas Ratio ($18.4) ($5.1) 9 to 1 Oil to Gas Ratio ($4.4) ($0.5) 10 to 1 Oil to Gas Ratio $11.4 $3.5 11 to 1 Oil to Gas Ratio $28.6 $7.0 Source: Black and Veatch. Appendix G1, Section 7.15.6. However, a price ratio of at least 11 would be Compared with the state, the Producers have a greater sensitivity to Producers. Compared with the state, the Major the price ratio because an LNG project's costs only detract from their ; | revenues. Here again, these results to the price ratio because an LNG project's costs may help explain why the Major North only detract from their revenues.*> Here again, | Slope Producers have — shown comparatively little interest — in pursuing an LNG project. required to generate a superior NPV for the North Slope Producers have a greater sensitivity these results may help explain why the Major North Slope Producers have shown comparatively little interest in pursuing an LNG project. It is possible that, going forward, the oil to gas price ratio could be sustained at an average of ten to one. However, as noted earlier, the oil to gas price ratio fluctuates over time (See Figure 4-5, page 4-18). For the period of January 1995 to March 2008, the ratio was as high as 14 to 1 and as low as 3 to 1, with an average 8 to 1 (Appendix G1; Section 7.15.4.3). Recently the oil to gas price ratio has been nearly 12 (Oil Daily 2008b). * We note again that the 4.5 Bcf/d Base LNG project contemplates initial volumes that are unrealistic. Actual volumes would need to be ramped up over an eight to ten year period. This would significantly decrease the revenue that the state would receive. *® The greater sensitivity derives from the fact that, for the producers, higher project costs only reduce their profits. In contrast, increased property tax receipts associated with greater in-state property balances mean that the state enjoys some degree of off-setting benefit from an LNG project's higher costs. 27 May 2008 AGIA Analysis of the NPV of the LNG Project Options Written Findings and Determination However, the commissioners see no reason to believe that this ratio will continue to depart, ona sustained basis, from historical averages. The current high oil to gas ratio is indicative of the natural volatility experienced for more than a decade. Meanwhile, as discussed previously, there are fundamental market forces that give good reason to believe that, over the relevant time frame, the oil to gas price ratio will more closely approximate its historical norm (Appendix G1, Section 7.15; Appendix |, Section 4.7; Kelly 2008). Finally, the commissioners note that the volume uncertainty affects the TC Alaska Project just as it does an LNG project into the Asian Pacific. The volume of gas is sensitive to the commitments that gas shippers make. Accordingly, we can also compare returns to the state generated by lower volume TC Alaska projects with a range of LNG projects. The results are shown in Figure 4-22. Figure 4-22. State NPV Under LNG and TC Alaska Pipeline Cases $70.0 7 $66.1 oasis i $60.7 $60.0 - i a $50.0 $47.1 - $48.0 Tpal= =< 2 $40.0 ' 2 \ 2 s300 | $731 - | a ” $20.0 - | |. -- $10.0 - $- . - 4 2.7BcfidLNG 2.7BcfldLNG 4.5 BcflidLNG 4.5 Befld 4.0 Bcfid 3.5 Befld Low Expanded to 4.5 Proposal Base Conservative Volume Bcfld LNG Case BaseCase _ Sensitivity Case Source: Black and Veatch. Appendix G1, Section 7.12.3. The TC Alaska project generates superior returns compared to any of the LNG projects under Base Case assumptions. Even the 3.5 Bcf/d Low Volume TC Alaska scenario generates a greater state NPV than does the 4.5 Bcf/d LNG project. 27 May 2008 4-42 AGIA TC Alaska’s Project LOS Written Findings and Determination F. TC Alaska’s Project Has a Greater Likelihood of Success than Any of the LNG Options In addition to producing a materially higher estimated NPV to the state than the LNG options, the commissioners conclude that the TC Alaska Project has a greater likelihood of success than the LNG options. The stand-alone LNG options face unique, significant challenges to their likelihood of success. Those issues, along with a comparison of the LNG options with the TC Alaska Project, are summarized below. 1. An LNG Project Would Be Significantly More Complex, and Thus More Risky, Than an Overland Route There are a number of unique challenges that negatively affect the likelihood of success of any LNG project. First and foremost, an LNG project constitutes a significantly more complex undertaking than an overland project such as TC Alaska’s, on several levels. As Goldman, Sachs and Co. states in its report, “LNG projects are inherently more complex than gas pipelines. Simply put there are more steps in the ‘value chain’ which translates into more parties involved, more contractual arrangements, and more technology and construction complexity.” (Appendix H, page 43) For example, to obtain financing, an LNG project, or its shippers, must secure long-term sales contracts for the LNG, in the form of a long-term take-or-pay market contract (Appendix H, Section VI.C). An LNG project cannot go forward without these long-term gas sales contracts. By contrast, the shippers on an overland pipeline project do not need to secure long-term gas sales contracts; instead, they can simply sell their gas into the market at the AECO Hub due to the liquidity of that market. For this reason alone, it would be considerably more difficult for an LNG project sponsor to obtain financing without firm long-term take-or-pay contracts than it would be for an overland pipeline project such as the TC Alaska Project (Appendix |, Sections 8.2 and 9.1). The long-term sales contracts required for an LNG project will likely require a minimum of 20 years of proven and committed gas reserves dedicated to the project (with the reserves being certified by experts) to support the contracts (Appendix |, Section 4.6). Again, this type of long- term demonstration of sufficient gas reserves would not be required by the parties that are purchasing Alaskan gas at the AECO Hub. To be sure, an overland project, like an LNG project, will have to demonstrate a certain level of available reserves in order to obtain 27 May 2008 4-43 AGIA TC Alaska’s Project LOS Written Findings and Determination financing. But, aside from the showing required to obtain financing, an LNG project would have @ to demonstrate adequate, long-term gas reserves to its customers as a result of the enhanced need of customers in Asia for security of supply, given that they have few if any available alternative supplies. Thus, TC Alaska’s Project to the AECO Hub would have a somewhat lower hurdle to clear regarding demonstration of gas reserves than an LNG project. Several other factors contribute to the enhanced risks and complexity facing an LNG project as compared to the TC Alaska Project. For example, in contrast with the TC Alaska Project to the AECO Hub, the LNG project options will require the design, construction and financing of very costly liquefaction facilities, in addition to establishment of the associated ownership structure and commercial terms and contracts to support the liquefaction facility (Appendix |, Section 7.2). Unlike the TC Alaska Project, an LNG project also requires costly marine transportation arrangements through ownership of or contracting for a significant number of LNG tankers. (Appendix |, Section 5.8). In addition, an LNG project will require that arrangements be made (typically by the buyer) for compatible regasification facilities or services at the market end of the transaction (Appendix |, Section 7.3). Each of these project elements presents additional complexity and material risks in comparison to the TC Alaska Project, including, as the case may be, cost, technology, completion, currency, © country and jurisdictional/choice of law risks. As Goldman Sachs states: “From a comparative standpoint (i.e., [over]land gas line project versus an LNG alterative), injecting this broad range of incremental credit issues and risk factors substantially raises the bar in terms of obtaining investment grade ratings, favorable financing rates and ultimately developing a viable financing plan.” (Appendix H, p. 45) There are simply more links in the chain that must be completed for an LNG project than for an overland pipeline project. And, even more Th ‘links’ in th ject challenging is that fact that all the links in the Sone eager ten Pe we eid one development chain that must be chain must be assured simultaneously. Indeed, completed for an LNG project than for Gas Strategies states that “[t]he need for | 2” overland pipeline project. proponents of LNG projects, usually the owners of | Even more challenging is that fact that all the links in the chain must be upstream gas reserves, to be assured of all assured simultaneously. elements in the LNG chain at the time of the investment decision is a key driver in the structuring of LNG projects” (Appendix |). 27 May 2008 @ 4-44 AGIA TC Alaska’s Project LOS Written Findings and Determination As a result, an LNG option would inevitably involve a longer schedule than the TC Alaska Project to negotiate all the project arrangements into place prior to the commencement of construction and potentially throughout the project. These challenges are not faced by an overland route. The typical structure of an LNG project involves several different ownership entities that must first agree to the elements of the project and then coordinate their activities to assure the earliest possible start date (Appendix |, Sections 2, 6.1, and 7.2). In many cases, for example, while the consortium of producers often is responsible for construction of the facilities through the liquefaction stage and loading terminal, if the tankers are chartered, another company may be responsible for delivery of the required tankers and still a third entity, the buyer of the LNG, would be responsible for arranging for the receiving terminal and regasification services. Thus, the project manager has a significant challenge to coordinate the various elements of the project and a very heavy negotiating burden. Moreover, each entity (including each joint venture partner developing the project) would be subject to its own risks and have its own priorities. Such complications, while not guaranteeing that unexpected delays would arise, substantially increase the risks of delays occurring. If they do, the economic basis for the choice of an LNG project would be further eroded (Appendix |, Section 9.1). By contrast, the TC Alaska Project essentially faces none of these risks, but does have right-of-way and regulatory challenges of its own as discussed more fully in Chapter 3. This is not to suggest that an LNG project could not overcome these barriers. LNG liquefaction projects have been constructed in other challenging areas of the world, and an Alaska project could be successful under the right set of conditions.°° However, an LNG project involves several, interrelated elements—pipeline/GTP, liquefaction plant, long-term gas sales contracts, demonstration of long-term gas reserves, LNG tanker arrangements—which collectively are more complicated than the challenges facing the TC Alaska Project, and which must be achieved before a project can obtain financing (Appendix H, Section VI. C). The complexity of these multiple factors contributes to the lower likelihood of success for the LNG project options relative to the TC Alaska Project. % That said, unlike most other LNG projects where the gas reserves are located at or near the liquefaction terminal, an Alaskan LNG project would have to construct a lengthy and costly pipeline from the producing area to the LNG liquefaction terminal. This makes the challenges facing an Alaskan LNG project even more complex than for most competing LNG projects located elsewhere in the world. 27 May 2008 AGIA TC Alaska’s Project LOS Written Findings and Determination 2. An LNG Project Would Be More Difficult To Finance Than an Overland Route According to Goldman Sachs’ analysis, an LNG project may be able to obtain financing, and could in rare circumstances potentially have a higher NPV than the TC Alaska Project depending on the price of LNG. However, as a result of the complexity and other factors discussed above, it will be quite challenging, and more difficult to finance an LNG project than the TC Alaska Project (Appendix H, Section VI. D). Thus, Goldman Sachs states that “it is difficult to reach a definitive conclusion at this stage about viability of the LNG-based cases,” citing the “[a]bsence of key project elements upon which to base analysis.” An in-depth analysis of the financeability of an LNG project would require, at a minimum, information about the project’s: e Defined business structure/finance plan. e Equity sponsor/developer. e Gas purchaser. e Ship builder/operator. e Committed gas volumes to supply the project. (Appendix H) None of this information is available at this time. In addition to the relative complexity of an LNG project, the Goldman Sachs report also identifies other issues that we believe would constitute barriers to financing an LNG project. First, the sheer size of an LNG project makes it more difficult to finance than an overland route. According to the Goldman Sachs report: “Comparing the 4.5 Bcf Proposal Base Case to the 4.5 Bcf LNG case provides a clear cost/per capacity measure. The [TC Alaska] Base Case has an all-in financing requirement of $56 billion, which in and of itself will be a challenge in terms of financing market capacity. The LNG project with comparable capacity requires $85 billion in funding. The second key comparison is between fully loaded transportation costs. In the case of the [TC Alaska] Base Case, the transportation cost is $4.73. For both the 4.5 Bcf and the 2.7 Bcf all LNG projects, the transportation cost is estimated to be between $9.51 and $9.74. In the case of the 4.5 Bcf project, this is driven by larger capital costs; in the case of the 2.7 Bcf project, capital costs are roughly the same as the TC Alaska Base 27 May 2008 AGIA TC Alaska’s Project LOS Written Findings and Determination Case but are spread over fewer units of throughput resulting in a higher transportation cost.” (Appendix H, p. 47) Second, Goldman Sachs assumes that the Federal Loan Guarantee would not be available to an LNG project (Appendix H, Section VI. D). The TC Alaska Project can take advantage of an $18 billion Federal Loan Guarantee that Congress made available to qualified project through its passage of ANGPA in 2004, and that due to indexing will escalate to approximately $32.9 billion in the year 2020 (Appendix H, p. 50). An LNG project, however, would not have the ability to use the Federal Loan Guarantee if the LNG would be shipped to Asia instead of the U.S. (ANGPA 2004, Section 116). While this does not mean an LNG project could not obtain financing under the right set of circumstances, it makes it more difficult to obtain financing, and again places an LNG project at a disadvantage relative to the TC Alaska Project.>” Finally, LNG projects are most typically financed primarily with equity (Appendix |, Section 8.1). This is due largely to the complicated, interrelated nature of the many commercial and financial elements of a project that have to be tied together with contracts in a project financing (Appendix H, Section VI. C). Only the original two trains of the RasGas project in Qatar have raised significant quantities of bond finance (Appendix |, Section 8.3). Given the very high costs of an LNG project, it is unclear from where the equity for the project would come. 3. There Is a Significant Risk LNG Would Not Provide Open Access to Future Explorers, In Contrast With the TC Alaska Project There is a significant risk LNG would not fulfill the state’s interest in achieving a gasline project that can be reasonably expanded on an open access basis for explorers and producers. As explained in detail in Appendix R3, FERC does not require LNG terminals to operate on an open access basis. Thus, FERC does not require LNG terminal owners to allow other parties that may wish to bring additional gas supplies to market to use an LNG terminal. In fact, in the Energy Policy Act of 2005, Congress codified FERC’s policy and went a step further by establishing that FERC cannot impose open access requirements on an LNG facility, which the 37 The lack of loan guarantees would also increase the cost of any LNG project due to the fact that the interest rate on any financing will be higher to reflect the greater project risk that exists because the U.S. government is not guaranteeing the project debt in the event of a project failure (Appendix H, Section VI.D.). This increased cost is reflected in the NPV analysis discussed earlier in this Section. 27 May 2008 4-47 AGIA TC Alaska’s Project LOS Written Findings and Determination Act defined to include an LNG export facility.** Thus the state could not impose its own open Assuming private ownership of the liquefaction facilities, it is unclear how the state could ensure open access. If LNG export facility currently operating in the U.S. the Major North Slope Producers, or : if al iah Ld, I FERC any other producer, owned the resides in Alaska (Nikiski) and it is neither liquefaction plant (as is typical in access terms on the LNG facility. Indeed, the only jurisdictional nor is it operated on an open access many LNG projects), they would be : under no obligation as a matter of basis (GUA 20065}, FERC regulation to provide access to the plant for other explorers and Assuming private ownership of the liquefaction producers, or to expand the plant to facilities, it is unclear how the state could ensure allow third-party access. open access. If the Major North Slope Producers, If the lack of open access prevents an LNG project from being expanded, then any hypothetical jobs advantage plant (as is typical in many LNG projects), they for an LNG project would be would be under no obligation as a matter of FERC substantially diminished relative to the TC Alaska project, because of the reduced potential for exploration and explorers and producers, or to expand the plant to production. or any other producer, owned the liquefaction regulation to provide access to the plant for other allow third-party access (See Appendix | at pen Section 9.2.1). Accordingly, even though the state or FERC could impose open access conditions on the GTP and pipeline facilities upstream of the LNG plant, the liquefaction plant could operate as a “pinch-point” for third parties. Without access to liquefaction, access to the pipeline and GTP plants is irrelevant. If the lack of open access prevents an LNG project from being expanded, then any hypothetical jobs advantage for an LNG project would be substantially diminished, relative to the TC Alaska project, because of the reduced potential for exploration and production. This problem would be even greater for a smaller LNG project. 4. The Major North Slope Producers Have Indicated Their Preference for An Overland Route Over the LNG Options Another factor in comparing an overland project to the LNG options is an understanding of which approach the Major North Slope Producers would prefer. In the Major North Slope 38 See Section 311(c)(2) of the Energy Policy Act of 2005 (codified at 15 U.S.C. § 717b(e)(3)(B)(ii)(!)). Section 311 of The Energy Policy Act of 2005 also gives FERC the exclusive authority over the siting, construction, expansion or operation of an LNG terminal. (Appendix R3, p. 6) 27 May 2008 4-48 AGIA TC Alaska’s Project LOS Written Findings and Determination Producers’ proposal under the SGDA process, in ConocoPhillips November 30, 2007 proposal, and most recently in the Producer Project unveiled by BP and ConocoPhillips, the Major North Slope Producers have consistently favored an overland route over an LNG project. It is reasonable to assume that economics play a large role in their decision. Indeed, as shown above, the TC Alaska Project would produce a materially higher estimated NPV for the Major North Slope Producers than would an LNG project, and would engender significantly lower risks (See Appendix G1, Section 7 for further details). Thus, while both TC Alaska and an LNG project face the challenge of convincing the Major North Slope Producers to commit to transport gas on them, any LNG project would face the additional challenge of convincing the Major North Slope Producers to pursue something they have clearly rejected since their major 2001 study of Alaskan gas options. On top of what appear to be inferior economics for the LNG projects, as discussed previously, securing gas commitments from the Major North Slope Producers for an LNG project may be especially difficult because each has gas reserves in the Pacific and Middle East regions which the companies may also wish to develop as part of their worldwide supply strategy (Appendix |, Section 9.1). Each company will have a different perspective on the priority it puts on developing Alaskan LNG. As a result, there is a risk that at least one of the Major North Slope Producers may not want to push ahead the development of an Alaskan LNG project. As Gas Strategies explains: “In the absence of a strong economic incentive companies will prefer a pipeline project over LNG. This is driven by concerns over project delays and costs arising from their divergent strategic objectives in the Asia Pacific region and the need to secure long term sales contracts. This contrasts with their ability independently to transport gas to the North American market where volume risk is minimal and sales contracts are not required before investing in pipeline capacity.” (Appendix |, p. 4) In addition, Gas Strategies concludes that the Major North Slope Producers “will be aware of the Federal desire to have Alaskan gas contribute to the energy security of the USA. Protecting their wider US interests may drive a reluctance to be seen to be promoting gas export from Alaska.” (Appendix |, p. 54.) These reasons, coupled with the NPV advantage that an overland route would have over the LNG options, help to explain why the Major North Slope Producers have expressed, and likely will express in the future, a preference for an overland route instead of an LNG project. 27 May 2008 4-49 AGIA TC Alaska’s Project LOS Written Findings and Determination 5. An LNG Project Will Require Proven and Committed Reserves (Certified by Experts) to be Dedicated to the Project As earlier noted, promoters of an LNG project will have to commit, in advance, to long-term (generally 20-25 year) sales contracts. Buyers will expect these to be backed by sufficient proven and committed reserves to fulfill the contract obligations; they will require a reserves certificate to demonstrate it (Appendix |, p.27). Banks providing funding will, as well, require evidence that sufficient reserves of proven gas are dedicated to the project to fulfill the sales contracts and a gas supply contract that is back-to-back with the LNG sales commitments (Appendix |, p.54-55). This is quite unlike an overland project, where gas shipping commitments from individual parties are sufficient to support financing. As noted earlier, it does not appear that proved reserves are sufficient to support such certificates for a 4.5 Bcf/d project; without Point Thomson gas there would even be challenges for a 3.5 Bcf/d project. The magnitude of the reserves that will be required to be both proven and dedicated to support any LNG option are significant. More than 5 Tcf of natural gas are required for a 0.65 Bcf/d (5 mtpa) train to operate for 25 years (Appendix |, p. 46). The sponsor will be required to own or have binding contracts to acquire all of the gas to support the project (as well as firm pipeline access to move it to tidewater) at the time the project is structured and financed. This creates a further burden for an LNG project compared to an overland project. 6. Exporting LNG To Asia Presents Regulatory and Political Barriers That the TC Alaska Project Would Not Face As discussed earlier, the most likely market for an Alaskan LNG project is in Asia. This is due to several factors, including the lack of any LNG receiving terminals on the West Coast of the U.S. or Canada, the fact that there is only one Mexican LNG receiving terminal, and, perhaps most importantly, the fact that LNG prices in Asia are (and are projected to be) higher than natural gas prices in U.S. West Coast markets due to the relative lack of other supply alternatives in Asia. Because Asia would be the primary destination market for Alaskan LNG, it is important to understand the special barriers that an Alaskan LNG project would face in attempting to export LNG to Asia. The fact that a Federal Loan Guarantee is available for an overland route but is not available for an LNG export project is indicative of the political and regulatory obstacles facing any project which seeks to export LNG outside of North America. There are significant regulatory and 27 May 2008 4-50 AGIA TC Alaska’s Project LOS Written Findings and Determination political barriers to exporting LNG to Asian markets, The fact that a Federal Loan Guarantee is available for an overland barriers. route but is not available for an LNG export project is indicative of the whereas the TC Alaska Project does not face similar For example, Section 3 of the Natural Gas Act political and regulatory obstacles facing any project which seeks to effectively provides that an export to a NAFTA export LNG outside of North America. country (Canada or Mexico) shall be approved (Appendix R2). Based on this provision, and past practice by the U.S. Department of Energy (DOE), it would appear to be relatively routine for the shippers on TC Alaska’s Project to receive the necessary export authorization.** In addition, although TC Alaska will not control any of the sales of natural gas that its shippers make, TC Alaska assumes that a large quantity of the gas initially exported to Canada will eventually be re-imported back into the U.S. after being transported through pipelines that receive gas at the AECO Hub (TC Alaska Application 2007, pp. 2.1-11). Canada is currently a net exporter of natural gas to the United States. As such, the introduction of a substantial incremental volume of natural gas from a pipeline transporting Alaskan gas to Canada would simply reinforce or enhance that exporter status. By contrast, LNG projects would face several problems in obtaining the necessary authorizations to enable them to export LNG to Asian markets. The authorizations include DOE export authority, which is required to send Alaskan natural gas to a non-NAFTA country such as Japan, Korea, Taiwan or China.*° As discussed in Appendix R2, although DOE authorized an export of LNG from Prudhoe Bay to Asia approximately 20 years ago that authorization occurred during a period when the supply and demand balance in the U.S. natural gas market was much different than it is today and is projected to be in the future.*’ Supply in the U.S. has struggled to keep pace with demand. Due to these fundamental supply and demand changes, there is a significant risk that DOE would not permit the export of significant quantities of Alaskan LNG to Asia (Appendix R2). °° See Maritimes & Northeast Pipeline, L.L.C., Order Granting Blanket Authorization to Import and Export Natural Gas from and to Canada, DOE/FE Order No. 1212 (1996) © See Appendix R2 and 15 U.S.C. 717b (2006) “" See Yukon Pacific Corporation, DOE Opinion and Order No. 350, 1 FE {J 70,259 (1989) 27 May 2008 4-51 AGIA TC Alaska’s Project LOS Written Findings and Determination Other export regulations also suggest that any effort to export LNG to Asia could face additional regulatory hurdles.*? In addition, as a practical matter, any effort to export gas to Asia would face political opposition in both the U.S. and Canada.” Because of the political sensitivity of sending domestically-produced energy supplies to markets outside North America, particularly during a period of rising energy prices and declining domestic supplies, a material risk exists that any effort to export LNG to Asian markets would not receive the necessary regulatory approvals (Appendix R2).4 Although these export barriers would exist for any project seeking to export North Slope LNG outside of North America, a project seeking to export LNG to China might face additional political and regulatory hurdles. U.S. Congressional opposition to a Chinese company’s effort to acquire Unocal was significant. (Lohr 2005). Meanwhile, Sinopec’s involvement in the Little Susitna Construction Company’s AGIA application caused some in Congress to suggest that an export ban could ensue. (Bolstad 2007) As discussed in Appendix R2, those hurdles create serious doubt that a project could obtain the authority to export North Slope LNG to China. But in any case, China would probably not be the most attractive buyer for LNG supplies (Appendix |). China is more price sensitive than the other major Asian markets and there are creditworthiness questions around some of the smaller gas buyers. As an emerging gas market, China would need to develop not only the infrastructure to receive and market LNG but also the pipeline and distribution systems to move it from the terminal to the end users (Appendix |). The implications as to the preferred destination market—China or Canada/US— are clear: Canada via an overland pipeline provides sponsors and the state with much more certainty and likelihood of realizing the best value for Alaskan natural gas. 7. An Overland Route Has a Better Opportunity than an LNG Project To Spur a Petrochemical Industry The specifications for LNG sold to Japan, Korea and Taiwan differ from LNG sold to the U.S. (and European) markets in terms of Gross Heating Value (GHV). The gas distribution systems “2 Among these are the Naval Reserves Petroleum Act, 10 U.S.C. § 7420; section 28 of the Mineral Leasing Act, 30 U.S.C. § 185; and Foreign Investment and National Security Act of 2007 (“FINSA’) at 50 App. USCA 2170. 3 See Appendix R2, page 8. “ See also Appendix |, page 57 (noting that the Major North Slope Producers “will be aware of the Federal desire to have Alaskan gas contribute to the energy security of the USA. Protecting their wider US interests may drive a reluctance to be seen to be promoting gas export from Alaska.”). 27 May 2008 4-52 AGIA TC Alaska’s Project LOS Written Findings and Determination in these Asian markets require a higher GHV than do U.S. systems (Appendix |, Section 4.4). The Btu per cubic foot of gas required in these three principal Asian markets range from 1050 to 1170*° (Appendix |, Section 4.4). This is higher than in most U.S. markets where the required GHV ranges from 980 to 1070 Btu. As a consequence, it is unlikely that such a project will spur the development of a major petrochemical industry in Alaska. A petrochemical industry would require that the gas liquids (propane, butane, ethane, and other liquids or liquefiables that increase the heating value of the natural gas stream) be stripped out of the gas stream for separate sales. However, this could not be accomplished while at the same time meeting the Asian market's GHV requirements.*° That being said, however, the analysis of LNG liquefaction processes reveals that an LNG project would be compatible with meeting in-state demand for propane. The cost and schedule impact of removing propane from the gas stream, for sale to Alaskans, is minimal. Meanwhile, total Alaskan needs for propane are modest. Accordingly, propane could be stripped from the LNG bound for Asia and diverted to the Alaskan market without falling afoul of Asian Pacific GHV requirements. The impact of propane extraction from both “lean gas” and “rich gas” cases described in the AGIA RFA is shown in Section 2.4 of the LNG analysis. While an LNG project would not support a major petrochemical industry in the state, an NGL processing plant could be installed on TC Alaska’s overland project to strip out the gas liquids. (TC Alaska There is more potential for creation of a petrochemical Application 2007, pp. 2.2-2.77). Thus, there is more industry in Alaska via the TC potential for creation of a petrochemical industry in } Alaska project than via an LNG ject. Alaska via the TC Alaska Project than via an LNG a project designed to move gas to Asian markets. Although as currently proposed, the TC Alaska project contemplates processing of NGLs in Alberta, the location of liquids processing will be determined by market forces. 45 Prudhoe Bay gas has a Btu content that generally ranges between 1067 and 1118 Btu. ‘6 The difference in GHV also reduces the interchangeability of destination markets for an Alaskan LNG project since gas with the heating value to meet Asian requirements will exceed US requirements. 27 May 2008 4-53 AGIA Conclusion Written Findings and Determination G.Conclusion As discussed above, the analysis shows that although LNG project options could produce positive benefits to Alaska, TC Alaska’s Project would provide the state and its citizens with greater benefits than the LNG options, including the following: Higher NPV. Under the Base Case set of assumptions for each alternative, the NPV to the state would be greater from TC Alaska’s Project than from any stand-alone LNG project options. The stand-alone LNG options would only have a higher NPV to the state if future LNG prices significantly exceed the level that are likely to occur in the future on a sustained basis. Higher Likelihood of Success. The TC Alaska Project has a greater likelihood of success than a stand-alone LNG project, and accordingly offers a better chance at providing the state with benefits important to Alaskans—including jobs, in-state gas, an open access project, a source of state revenues, and getting a gasline as quickly as possible. For example: o The TC Alaska Project is less complex and involves fewer hurdles than an LNG project. In contrast with the TC Alaska Project, which must develop the pipeline/GTP, LNG projects require the development of the entire supply chain— including gas supply, pipeline/GTP, liquefaction plant, and access to LNG tankers and regasification facilities—before a project can obtain financing. Unlike an overland route to Canada, an LNG project must have long-term gas sales contracts with creditworthy customers before it can be financed. By contrast, the shippers on an overland pipeline to Canada can simply make short-term gas sales in the spot market at the AECO Hub. LNG options may also be disadvantaged because the Major North Slope Producers, based on their prior actions and recent indications, view an overland route as economically preferable to an LNG project. While TC Alaska must obtain regulatory authorizations in both the U.S. and Canada, a stand-alone LNG project would have greater difficulty obtaining authorization to export gas from the U.S. to Asian countries, the most likely destination market for Alaskan LNG. 27 May 2008 4-54 AGIA Conclusion Written Findings and Determination Analysis shows that stand-alone LNG project options are less desirable for the state than the TC Alaska Project. Even if one presumes the simultaneous occurrence of a number of unlikely economic events which could generate a greater NPV for a stand-alone LNG project option, the TC Alaska Project continues to enjoy a significantly higher likelihood of success. Accordingly, TC Alaska has a better chance than the stand-alone LNG options of providing benefits to Alaskans, including jobs, in-state gas deliveries, open access for explorers, and greater revenues for the state and its citizens. The TC Alaska proposal does improve significantly the prospects of an Alaskan LNG project— the Y Line option. The TC Alaska Project provides Alaska with its best opportunity for a successful LNG project, as a Y Line option. The TC Alaska Project proceeding first will reduce costs and lessen financial and contracting hurdles associated with an LNG project. Coming after gas is already bound for U.S. markets, a Y Line may be able to overcome political opposition to exporting gas. Accordingly, the commissioners believe that the best route to an Alaska LNG project runs through the TC Alaska proposal. 27 May 2008 4-55 AGIA References Written Findings and Determination H. References ANGPA. 2004. Alaska Natural Gas Pipeline Act of 2004. Section 116. Alaska Gasline Port Authority (AGPA). 2007. Alaska Gasline Inducement Act License Application, November 30, 2007. Section 1. Bolstad, Erika. 2007. Alaska delegation plans to block gas export. Petroleum News. December 16, 2007. Energy Information Administration (EIA). 2008a. U.S. Natural Gas Monthly Supply and Disposition Balance. [Web Page] Located at: http://tonto.eia.doe.gov/dnav/ng/ng_sum_sndm_s1_m.htm. Energy Information Administration (EIA). 2008b. Location of U.S. Natural Gas Import and Export Points. [Web Page] Located at: http:/Awww.eia.doe.gov/pub/oil_gas/natural_gas/ analysis_publications/ngpipeline/impex_list.html Accessed May 22, 2008. Federal Energy Regulatory Commission (FERC). 2000. Panhandle Eastern Pipe Line Company, Order on Remand, 91 FERC {| 61,037. FERC Interconnection Policy. pp 61,141- 61,143. Kelly, Edward. 2008. North American Natural Gas Markets: Historic Highs, Relative Lows—How Long? Presentation by Edward Kelly, VP North American Gas and Power, Wood Mackenzie, delivered at a meeting of the American Association of Petroleum Geologists. April 21,2008. Lohr, Steve. 2005. Unocal Bid Denounced at Hearing. [Web Page] Located at: http:/Awww.nytimes.com/2005/07/14/business/worldbusiness/14unocal.html. National Energy Board (NEB). 2007. Canada’s Energy Future—Reference Case and Scenarios to 2030. Her Majesty the Queen in Right of Canada as represented by the National Energy Board 2007. 155 pages. Oil Daily. 2008a. Oil Daily Vol. 58, No. 94, May 15, 2008. Oil Daily. 2008b. Oil Daily Vol. 58, No. 98, May 21, 2008. TC Alaska (Application). 2007. Alaska Gasline Inducement Act License Application, November 30, 2007. U.S. Department of Energy (DOE). 1989. DOE Opinion and Order No., 350, 1 FE {| 70, 259, 1989. U.S. Department of Energy (DOE). 2005. U.S. Energy Policy Act of 2005 (codified at 15 U.S.C. § 717b(e)(3)(B)(ii)(1)). U.S. Department of Energy/Fossil Energy (DOE/FE). 2006. DOE/FE Order No. 1212 1996, Maritimes & Northeast Pipeline, LLC, Order Granting Blanket Authorization to Import and Export Natural Gas from and to Canada. 27 May 2008 4-56 C. TC Alaska—Commitments; Producer Project—No Commitments fl, 2. 3. Rolled-in Rates 4. Chapter Five — Comparison of the TC Alaska Project with the Producer Project Table of Contents Introduction and Summary of Conclusions B. The History of SGDA and TAPS Illustrates the Risks Posed by a Producer-Owned Pipeline ......... 1. The State’s Experience Under SGDA... D. T PB a stcicccncminmn aRmRRERRENRERRCRRTEE Capital Structure Expansion Commitments To Hold an Open Season and File at FERC, and Other Issues That Could Result in a Delay of the Producer Project............:csccsssseseseeeeteeseeteeeeees 5-17 A Producer-owned Pipeline Has an Incentive to Act in Ways That Are Contrary to the Best Interests of the State 0.0.00... cccececeeseseeseeeeeeeseneeeeeeeeeeees Both TC Alaska and the Producer Projects Lack Firm Shipping Commitments.. Comparison of the Costs to the State Following the TC Alaska Project Path or the Producer Project Path TC Alaska’s Offer of Equity Partnership The Upstream Inducements Provided by AGIA are Valuable and Incentivize the Producers to Commit Gas to the TC Alaska Project ..........::cccccccessesscssssesseseseeeseeeeeeee 5-30 It is in the State’s Interest to Pursue the TC Alaska Project Conclusion References 5-33 10°34 Figures Figure 5-1: Impact of Capital Structures on Tariff Rates.... Figure 5-2: —_ Impact of 50/50 debt to equity ratio... ott +8912 27 May 2008 AGIA Introduction and Summary of Conclusions Written Findings and Determination A. Introduction and Summary of Conclusions This section of the Findings compares the Producer Project with TC Alaska’s proposed project. The purpose of this comparison is to analyze whether the state’s interests would be better served by awarding an AGIA license to TC Alaska or by relying on the Producer Project as the state’s vehicle to obtain a gas line. On April 8, 2008, BP and ConocoPhillips announced they have combined efforts to pursue a project they call “Denali - The Alaska Gas Pipeline™’ (BP/ConocoPhillips 2008). According to a BP/ConocoPhillips press release and a 12-page PowerPoint presentation describing the project (which provides the only information formally available from the sponsors regarding the project), the Producer { This section of the findings analyzes whether the State's interests would be _ better Bcf/iday. According to BP and ConocoPhillips, the pipeline served by awarding an AGIA would extend from the North Slope to Alberta, Canada, | license to TC Alaska or by relying on the Producer Project as the state’s vehicle to obtain if doing so would improve project success or reduce agas line. Project would have a capacity of approximately 4.0 and from there to a destination point in the Lower 48 states transportation costs. BP and ConocoPhillips assert that they plan to spend $600 million to reach the first major project milestone, an open season commencing before December 31, 2010. If the open season is “successful” (a term which is not defined or explained by either the BP/ConocoPhillips press release or the PowerPoint presentation), BP and ConocoPhillips state they intend to obtain FERC and NEB certifications. BP and ConocoPhillips have proposed the Producer Project outside the AGIA process. As explained below, rejecting TC Alaska’s Project in order to pursue the path offered by BP and ConocoPhillips would not be in the state’s interests. TC Alaska has made binding, enforceable commitments to take various actions that will provide real benefits and value to the state. The commitments made by TC Alaska include commitments to (1) hold an open season and file for regulatory permits by specific dates, which will enable the state to get a gasline as quickly as possible; (2) provide transportation at reasonable rates, which will encourage exploration and development and also maximize revenues to the state and its citizens; (3) expand its system on reasonable terms, which will promote the full exploration and development of Alaska’s natural gas resources, thereby maximizing jobs for Alaskans; and (4) accept the critically important FERC certificate once it becomes final and no longer subject to judicial review. 27 May 2008 AGIA Introduction and Summary of Conclusions Written Findings and Determination By contrast, the sponsors of the Producer Project have made no binding, enforceable commitments to advance a project on terms that are in the best interests of Alaska. In addition, as demonstrated by the history of the failed SGDA negotiations and SGDA contract, the sponsors have economic incentives that conflict with advancing a project that is in the best interests of the state. They are motivated to maximize the commercial value of the project for themselves, and can be expected to demand large concessions from the state. Further, as demonstrated by the history of the TAPS oil pipeline, the Producer Project sponsors have incentives to engage in behavior that will frustrate the state’s goal of obtaining a competitive exploration and production industry on the North Slope. Reliance on any project that does not include legally enforceable commitments made by the project sponsor similar to those made by TC Alaska would deprive the state of a real opportunity to achieve its objectives. Rejecting the TC Alaska Project would leave the state no other option but to negotiate with BP and ConocoPhillips to obtain pipeline terms similar to those contained in AGIA that benefit the state and its citizens. However, such negotiations would be conducted from a position of ever-increasing weakness as time goes by, as oil production and related revenues decline, and as the state becomes more and more desperate for whatever new revenue it can obtain from a gas pipeline. There is no need to imagine what might happen in that circumstance. One needs merely to look back at the terms of the draft SGDA contract presented to the Alaska Legislature in 2006 for evidence of what will be required of the state if the producers have that kind of commercial negotiation | Reliance on any project that does not obligate the sponsors to provide the legally enforceable Producers extracted billions of dollars in concessions commitments made by TC Alaska leverage over the state. The Major North Slope would deprive the state of a real opportunity to achieve _ its Producers. This is far more than the $500 million objectives. from the state with no binding commitments from the investment under AGIA that secures the valuable commitments from TC Alaska to build a natural gas pipeline that serves the state’s interests in exploration, jobs, revenues and other issues of importance to the state. The commissioners also recognize that the Producer Project may be pursued to completion outside the AGIA process and without state fiscal concessions. The Producers have an obligation to market their gas when it is reasonably profitable to do so; they do not have an obligation to transport the gas through any particular project. If the Producer Project proceeds 27 May 2008 5-2 AGIA Introduction and Summary of Conclusions Written Findings and Determination to an open season, the TC Alaska project would compete with the Producer Project for gas commitments. However, the Producers have stated that they need concessions from the state to enable them to commit gas to any gas pipeline project. AGIA ties upstream incentives to gas committed at the initial open season of the AGIA project, to provide the state with the benefits Alaskans require. The state will have the opportunity throughout this process to evaluate the need to increase the value of the AGIA upstream incentives, when justified. The state’s primary interest is ensuring that any concessions be provided in exchange for real value. In sum, the commissioners strongly believe that if the state forgets the history of the SGDA process, the state will be risking a repeat of the SGDA results. If it pursues the Producer Project alternative instead of the TC Alaska Project, the state will be forced into negotiations that will resemble those that produced the SGDA Contract. The sponsors of the Producer Project have economic interests that are fundamentally at odds with adopting the types of commitments made by TC Alaska, including effective open access provisions. Because those commitments are so important to the long-term economic interests of the state it would be a terrible mistake to abandon the results of the AGIA process and turn back to reliance on the Producers who are not, and cannot ever be, totally aligned with the state on very fundamental policies affecting the natural gas pipeline. The Producer Project does not reach the level of protecting the state’s interest nor does it warrant further consideration because it lacks commitments necessary for the state to adequately compare or evaluate. 27 May 2008 5-3 AGIA Risks Posed by a Producer-owned Pipeline Written Findings and Determination B. The History of SGDA and TAPS Illustrates the Risks Posed © by a Producer-owned Pipeline Before comparing the TC Alaska Project and the Producer The history of the failed SGDA process and the TAPS oil state’s history of dealings with producer-owned pipelines. pipeline provides a strong The history of the failed SGDA process and the TAPS oil | indication of what the state's experience will be if the state Project, it is useful to briefly recall and summarize the pipeline provides a strong indication of what the state’s elects to follow the path of (and the Nation’s) experience will be if the state elects to | reliance on a producer-owned pipeline instead of relying on follow the path of reliance on a producer-owned pipeline the TC Alaska proposal. instead of the TC Alaska Project. That history certainly does not support the prudence of such a decision, as shown below. 1. The State’s Experience Under SGDA In 1998, the state enacted the SGDA to support the development of an LNG project in Alaska through an application and negotiation process. The law was amended in 2003 to allow the state to provide natural gas and property tax incentives to parties who would move Alaska’s gas @ to market via a pipeline through Canada. In 2004, MidAmerican Energy Holdings Company, a subsidiary of Berkshire Hathaway, filed an application under the SGDA to negotiate incentives with the state for developing a gas pipeline from the North Slope to markets in the Lower 48. Shortly after the state accepted MidAmerican’s application, the The proposed SGDA contract consisted of an unbalanced set Major North Slope Producers filed a competing SGDA of state concessions that were broad, material, long-term, and binding. They surrendered Authority, and affiliates of TransCanada Corporation also multiple aspects of the state’s submitted applications. sovereign rights and prerogatives and harmed and frustrated the state’s interests in promoting the full exploration administration undertook negotiations with (1) and development of natural gas MidAmerican, (2) the Major North Slope Producers, and | sources in Alaska, limiting the potential for the creation of new exploration and development jobs on the North Slope. 27 May 2008 @ application. Enbridge, The Alaska Gasline Port During the ensuing process, the Murkowski (3) TransCanada Corporation. Ultimately, the Murkowski administration chose to negotiate a contract exclusively with the Major North Slope Producers. Those 5-4 AGIA Risks Posed by a Producer-owned Pipeline Written Findings and Determination negotiations resulted in a proposed SGDA contract in the spring of 2006 regarding the possible development of a natural gas pipeline from the North Slope to the Lower 48. The proposed SGDA contract consisted of an unbalanced set of state concessions and so- called producer “commitments.” The concessions made by the state under the contract were broad, material, long-term, and binding. They swept across fiscal and regulatory authorities and surrendered multiple aspects of the state’s sovereign rights and prerogatives. Furthermore, the terms harmed and frustrated the state’s interests in promoting the full exploration and development of natural gas resources in Alaska, limiting the potential for the creation of new exploration and development jobs on the North Slope. The state was required to give up (for up to 45 years) its sovereign rights to change oil and gas taxes and to determine the royalties it would be paid for its oil and gas. The state was required to take its royalty gas in-kind. The state was also required to take its production tax payment in gas, was required to contract for capacity in the pipeline (and upstream gathering pipelines), and to market its own gas, all of which exposed the state to new and substantial costs and risks. The state was also required to waive numerous taxes to which the Major North Slope Producers would normally be subject. Regulatory concessions crossed multiple agencies within state government. The Department of Natural Resources was deprived of its authority to regulate lease activities and Plans of Development. The SGDA contract also drastically reduced the authority of the Alaska Oil and Gas Conservation Commission, particularly related to Point Thomson. In addition, the orders of the Regulatory Commission of Alaska affecting the proposed line were made virtually meaningless by an indemnification provision guaranteed by the state. In monetary terms, the state’s quantifiable concessions to the Major North Slope Producers under the SGDA contract were estimated to be more than $10 billion.'. Additional non- quantifiable concessions were granted, exposing the state to tremendous economic risk. The Producers claimed all these concessions were essential for them to proceed with a pipeline project. i Following the recent enactment of the ACES production tax changes, the $10 billion estimate of quantifiable concessions would likely be much higher. 27 May 2008 5-5 AGIA Risks Posed by a Producer-owned Pipeline Written Findings and Determination Even more troubling, the state’s numerous concessions did not secure any binding, enforceable commitments by the Major North Slope Producers to actually build a gas pipeline project, or to apply for the necessary regulatory permits on a fixed timeline. The Major North Slope Producers merely committed to commence planning of a natural gas pipeline project, with no requirement to ever hold an open season or obtain the necessary FERC certification to go forward with developing a natural gas pipeline.” The SGDA contract did not include any enforceable commitments by the Major North Slope Producers on issues that were critical to protect the state’s interests in promoting the maximum development of the state’s North Slope natural gas resources and ensuring maximum revenues from our royalties and production taxes. The SGDA contract did not contain any commitments regarding tariff and rate issues such as capital structure. The contract also was silent on when, if ever, the sponsors would consider an expansion of the project. In addition, unless expansion reduced rates for existing shippers, the expansion would have to be priced on an incremental basis or it could not be undertaken. Additionally, an expansion could be precluded by the sponsors if the expansion would “adversely affect” the financial or economic viability or overall operations of the project—with no material limitations on these impacts. Other significant omissions were the lack of any binding commitments of the Major North Slope Producers’ leased gas to the project or to the size, route, or destination of the project. In sum, the provisions of the proposed SGDA contract bound the state to unacceptable contract obligations for decades, including the surrender of state sovereignty and billions of dollars in fiscal concessions, but without commitments by the Major North Slope Producers to any: e Timelines or benchmarks to advance the project. e Expansion terms that provide effective open access to foster exploration and development of Alaska’s natural gas resources. e Tariff terms that protect the state’s interests. ? Section 5.2 of the SGDA Contract which addressed Project Implementation merely committed the parties to “begin project planning” and to “advance the project planning activities by Diligence” and to conclude such activities “with a decision on whether to begin preparation of regulatory applications and planning for an Open Season.” 27 May 2008 AGIA Risks Posed by a Producer-owned Pipeline Written Findings and Determination The proposed SGDA contract between the Major North Slope Producers and the state was never approved by the Alaska Legislature. From the demise of the proposed SGDA contract in 2006 until late 2007 there were no proposals by any of the Major North Slope Producers for any pipeline project. During the 2007 legislative session the legislature enacted AGIA. All three of the SGDA sponsors actively opposed AGIA. Only after TC Alaska proposed its project did BP and ConocoPhillips come forward with their proposal to move a project forward outside the AGIA process.* 2. TAPS The state’s experience with the FERC-regulated, producer-owned TAPS oil pipeline also sheds light on the path offered by the Producer Project. Although the state has a long history with the TAPS line, two brief points about that history merit particular mention here. First, producers that merely ship oil on the TAPS line and that do not hold an ownership interest in the line have long complained that the TAPS transportation rate structure established by the producer-owners of TAPS impedes non-owner producers’ ability to explore for and produce oil in Alaska (Anadarko 2004). Some third-party (non-TAPS owner) producers and explorers have even left the state. Indeed, in 1985, ConocoPhillips (then an independent producer on the North Slope with no ownership stake in TAPS) began producing oil from the Milne Point field. In late 1989, ConocoPhillips suspended production at Milne Point citing low oil prices, technical difficulties with producing oil from the field, and the high tariffs charged for shipping oil through TAPS. In 1993, ConocoPhillips traded Milne Point to BP and left the state. Conoco's president and CEO at the time, Archie Dunham, was quoted as saying that "[a]ll the value of that property was taken away from us in the pipeline tariffs.” (Haines 1996) In effect, ConocoPhillips argued that an independent company (i.e., a non-TAPS owner/producer) could not profitably produce and market oil from its North Slope leases largely because the TAPS tariffs made it uneconomic for ConocoPhillips to get its oil to market. Second, the producer-owned TAPS pipeline has charged excessive rates, which may have impeded the full exploration and development of the state’s North Slope oil resources. In 2002, 3 The commissioners note that on the eve of the AGIA application deadline, ConocoPhillips did release a plan to study a natural gas pipeline. The plan included a condition requiring the state to negotiate a new “fiscal framework” before any advancement of the project. The administration declined the request, and the plan was withdrawn. 27 May 2008 5-7 AGIA Risks Posed by a Producer-owned Pipeline Written Findings and Determination the Regulatory Commission of Alaska determined that the TAPS owners had overcharged shippers receiving intrastate service by almost $10 billion between 1977 and 1997 (Appendix R4).4 That decision has been affirmed by the Alaska Supreme Court. Further, an Administrative Law Judge at FERC has held that the rates for interstate service as well as the intrastate service on the line are also substantially overstated.® This ruling is pending; a decision by the full FERC is expected soon. In sum, the conclusion that shippers have been overcharged has been reached by the Regulatory Commission of Alaska, an Alaska Superior Court judge, the Alaska Supreme Court, FERC staff, and a FERC Administrative Law Judge (ADN 2004). * See, P-97-4 Order No. 151, In the Matter of the Correct Calculation and Use of Acceptable Input Data to Calculate the 1997, 1998, 1999, 2000, 2002 and 2002 Tariff Rates for the Intrastate Transportation of Petroleum over the Trans Alaska Pipeline System, Order Rejecting 1997, 1998, 1999 and 2000 Filed TAPS Rates. (November, 2002). ° BP Pipelines (Alaska), Inc., 119 FERC 763,007 (2007) 27 May 2008 5-8 AGIA Written Findings and Determination TC Alaska-Commitments/Producer Proposal-No Commitments C.TC Alaska—Commitments; Producer Project—No Commitments In contrast with the excessive transportation rates charged by TAPS and the SGDA contract which failed to contain effective commitments by the Major North Slope Producers to advance a gas pipeline project, TC Alaska has made binding, enforceable commitments to pursue a natural gas pipeline project with reasonable transportation rates and on other terms that are important to the state. TC Alaska’s Project includes commitments to base its rates on a reasonable TC Alaska has made _ binding, enforceable commitments to pursue a gasline project with reasonable transportation rates and on other terms that are important to the state. structure that will promote full exploration of North TC Alaska’s proposal _ includes commitments to base its rates on a reasonable structure that — will promote full exploration of North Slope resources. Slope resources, which should maximize the opportunities for long-term exploration and development jobs for Alaskans. Although TC Alaska has made numerous, binding commitments in its application, each of which provides substantial value to the state, this section briefly examines four of those commitments. By contrast, the sponsors of the Producer Project have not made any binding commitment, on these or any other issues. 1. Capital Structure Section 130(10) of AGIA requires that a potential Licensee commit to use a capital structure with at least 70% debt and no more than 30% equity to determine the project's rates. The reason a capital structure with less equity is critically important to the state — and why a low ratio of equity to debt is required by AGIA - is that it helps to ensure lower transportation rates on the pipeline. As explained below, lower transportation rates help to maximize the state’s revenues and encourage full exploration and development of the North Slope, thereby increasing the number of long-term job opportunities for Alaskans. All other things being equal, the greater the amount of equity in the capital structure used to determine the pipeline’s transportation rates, the higher the rates will be. This stems from the fact that equity is a much more expensive means of financing a pipeline than debt. The return on equity for a new gas pipeline allowed by FERC is approximately 13% to 14%. By contrast, debt can be financed at current interest rates of approximately 7% to 8%. (Appendix J; Appendix G1) As a result, even if two pipelines have identical construction and operating costs, 27 May 2008 5-9 AGIA Written Findings and Determination TC Alaska-Commitments/Producer Proposal-No Commitments a pipeline which uses a lower equity ratio for ratemaking purposes will have a lower transportation rate than a pipeline which uses a higher equity ratio. TC Alaska has committed to use the 70/30 debt/equity capital structure required by AGIA through the initial construction phase of the project. Even better, TC Alaska enhanced its proposal, from the state’s perspective, by committing to use an even lower 75/25 debt/equity capital structure in its negotiated rates upon approval by FERC and the NEB of the Project's final capital costs. A capital structure with less equity is critically important to the state. TC Alaska committed to use the 70/30 debt/equity capital structure required by AGIA. The sponsors of the Producer Project have not made any commitment to a capital structure for ratemaking purposes. By contrast, the sponsors of the Producer Project have not made any commitment to a capital structure for ratemaking purposes.® Further, even if BP and ConocoPhillips assert in the future that they plan to use a particular capital structure, their assertion would not be enforceable or binding. BP and ConocoPhillips ultimately could adopt whatever capital structure suits their needs, not one that suits the state’s needs or the needs of shippers for the lowest possible transportation rates. Thus, one possible outcome of abandoning the TC One possible outcome of. abandoning the TC Alaska Project in favor of the Producer Proposal is that the rates on the pipeline will be much higher than they could or should be. Alaska Project in favor of the Producer Project is that the rates on the pipeline will be much higher than they could or should be. This risk would appear to be significant based on the state’s experience with other pipelines in which BP and/or ConocoPhillips This will result in lower revenue and royalties to the state, and could have ownership interests. For example, on the negatively impact the timely development of the state’s natural gas resource. TAPS oil pipeline, the producer-owners (including BP and ConocoPhillips) have recently advocated at FERC a capital structure of 70% equity and 30% debt—the polar opposite of what AGIA requires and ® We note that the November 30, 2007 ConocoPhillips proposal (which appears to have been withdrawn) stated that the company intended “to target a minimum overall debt/equity ratio of 70/30 to the extent such leverage is achievable at commercially reasonable terms in the market at the time of issuance.” Proposal at § VII p. 1, emphasis added. A “target” of course, is not enforceable, nor is an undefined concept such as “achievable at commercially reasonable terms at the time of issuance.” 27 May 2008 5-10 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination what TC Alaska has committed to do.’ Similarly, for the Rockies Express project in which ConocoPhillips owns a minority ownership interest, the pipeline has a capital structure of 55% equity and only 45% debt.® The impact of the debt to equity ratio on the tariff for an Alaska gasline can be seen in the following chart (taken from Appendix G1) that shows the significant impact of four different capital structures on rates for an Alaskan gasline. Figure 5-1: Impact of Capital Structures on Tariff Rates $10.0 s $6.0 $4.0 Nominal $/mmBtu $2.0 $0.0 Base Case - 75/25 DIE - 70/30 DIE - 60/40 DIE - 50/50 Source: Black and Veatch. Appendix G1, Section 5.7.8.5. ” See BP Pipelines (Alaska), Inc., 119 FERC {| 63,007 at P 183 (2007) 5 There is precedent at the FERC for relatively high equity ratios to be used to set rates for gas pipelines: Williams Natural Gas Co., 77 FERC {| 61,277 (1996) (64.26 % equity); Panhandle Eastern Pipe Line Co., Opinion No. 404, 74 FERC {61,109 (1996) (59.97 % equity); Panhandle Eastern Pipe Line Co., Opinion No. 395, 71 FERC {| 61,228 (1995) (61.79 % equity); Northwest Pipeline Corp., 71 FERC J 61,253 atp. 61,989 (1995) (55 % equity); Transok Inc., 70 FERC J] 61,177(1995) (58.49 %equity); Pacific Gas Transmission Co., 62 FERC J] 61,109 (1993) (68.86 % equity); and Midwestern GasTransmission Co., 31 FERC {| 61,317 (1985) (77.94 % equity) and Transcontinental Gas Pipeline Company, 90 FERC {| 61,279 (60.2% equity) This indicates generally that historically the bounds for the upper end of the range encompass common eauity ratios for gas pipelines regulated by the FERC is between 55% and 77.94%. 27 May 2008 5-11 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination As can be seen in the figure above, capital structure has a major impact on the transportation rate. Perhaps more importantly, it also has a major impact on state revenues and the state’s NPV. The impact on state revenue and state NPV is shown in the following figure: Figure 5-2: Impact of 50/50 debt to equity ratio $70.0 3 $ Billions (2008) g Base Case- 75/25 DIE - 70/30 DIE - 60/40 DIE - 50/50 Source: Black and Veatch. Appendix G1, Section 5.7.8.5. As Figure 5-2 shows, a change from the base case to a 50/50 debt/equity ratio reduces the state’s NPV by more than $8 billion. Stated differently, by committing to a 75/25 debt/equity ratio instead of a 50/50 ratio, TC Alaska has improved the value of its application to the state by the same $8 billion amount. The Major North Slope Producers’ consistent opposition to the AGIA requirements and their advocacy of higher equity ratios for their own oil pipelines at FERC directly conflicts with their past argument that they have a greater incentive to keep the tariff rate low than an independent pipeline. As demonstrated by the history of TAPS, the Producer-owners of a pipeline have an incentive to establish a high tariff rate. By keeping the tariff rate high, BP and ConocoPhillips can reduce the net back price, which would reduce the state’s revenues because of the reduction in state royalties and taxes that are based on the lower net back price. The reduction in royalties and taxes would result in a corresponding revenue increase to BP and ConocoPhillips and higher profits because they (through ownership of the project) would also 27 May 2008 5-12 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination collect the higher tariff rate resulting from the higher equity ratio used for ratemaking purposes. Essentially, by moving money from their producer pocket into their pipeline pocket, BP and ConocoPhillips would increase their profits significantly at the state’s expense by avoiding state royalty and production tax obligations. Finally, an added benefit of a high tariff rate for BP and A high tariff rate on the gas pipeline would be a benefit for is that it would tend to deter entry into Alaska’s gas BP and ConocoPhillips, and a detriment to the state. ConocoPhillips—and an added detriment to the state— basins by competing producer companies. This has A high tariff rate would tend to deter entry by competing “basin control,” which is the ability of the Major North producers, leading to “basin previously been referred to in the SGDA hearings as Slope Producers to control the North Slope producing control.” basin and discourage competitor producers from initiating and/or increasing their exploration and production activities in the basin due to potentially high tariffs and uncertain access to essential pipeline capacity to move their new production to markets. The problem is similar to the problem the state has already experienced on TAPS, and would discourage explorers from developing North Slope natural gas resources to their fullest potential. Basin control would also discourage diversity in the companies that are exploring for and developing gas on the North Slope. The addition of new companies to the exploration and development business there creates competition—competition for leases and competition for capacity in the pipeline.® This competition can result in increased long-term employment opportunities for Alaskans on the North Slope through more exploration and development activity. 2. Expansion Expansion terms are also critical elements of AGIA and any AGIA-licensed project that guard against the risk of basin control. A vibrant exploration and development industry cannot develop unless producer companies explore for more gas. Despite the abundant gas resources on the North Slope—which some estimates put at more than 224 Tcf, enough gas to fill TC Alaska’s Project for more than 100 years—such exploration is unlikely to occur if explorers do not have ° As discussed more fully later in this chapter, antitrust enforcers are concerned about the ability of one competitor to increase the costs of doing business of competing firms. In this case the ability of a producer-owned pipeline to increase the transportation costs of competing gas producers would raise concerns of anticompetitive behavior. 27 May 2008 5-13 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination confidence that expansion capacity to move gas they find will be added when needed. (See Chapter 3, Section 3 in this document.) AGIA requires binding commitments by the Licensee that it will pursue expansions by conducting non-binding open seasons at least every two years after the license is issued (AS 43.90.130 (5), Appendix B). If demand for new capacity exists, AGIA requires that the Licensee expand the project in reasonable engineering increments under commercially reasonable terms. These provisions ensure that explorers have (1) the opportunity to communicate their capacity needs to the pipeline, and (2) the assurance that expansion capacity will be available when needed, thus enabling explorers to make drilling commitments. This increased development of the North Slope translates directly into more jobs for Alaskans, more royalty and tax revenue for the state, and a secure economic future for years to come. TC Alaska has made binding, enforceable commitments to the expansion requirements of AGIA. TC Alaska has made binding, Thus, the state would obtain real value and the real | enforceable commitments to the expansion requirements of AGIA. Thus, the state would obtain real pursuing the path offered by TC Alaska. value and the real prospect for new jobs and increased revenue prospect for new jobs and increased revenue by by pursuing the path offered by TC Alaska. In contrast, BP and ConocoPhillips have not made any commitment to expansion policies. Furthermore, no pe In contrast, BP and ConocoPhillips assertion that they might make in the future regarding have not made any commitment expansion policies would be enforceable by the state \_ to expansion policies. because their project has been proposed outside the AGIA process. 3. Rolled-in Rates AGIA also requires that a licensed project utilize rolled-in rate treatment for the costs of expansions provided that such treatment does not raise the rates of incumbent shippers by more than 15% above the project's initial rates (AS 43.90.130 (7))'°. Like the expansion provisions discussed above, AGIA’s rolled-in rate provisions encourage expansion. The rolled- in pricing required by AGIA produces lower rates for expansion shippers (new gas shippers) '© See Appendix S3 for a detailed discussion of rolled-in rates, including the importance of the AGIA rolled-in rate provisions to the state. 27 May 2008 5-14 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination than incremental pricing would for expansions when substantial new pipe must be laid (referred to as “looping”) or when major new components are required for the Gas Treatment Plant (GTP) as a result of new demand. By reducing the transportation rates which would have to be paid by explorers that find and develop new natural gas reserves on Alaska’s North Slope, AGIA’s rolled-in rate provisions provide the greatest opportunity for new producers and explorers to utilize the system, and gives an increased incentive for producers and explorers to invest in exploration and development of new natural gas fields. One need not look further than FERC’s Order No. 2005 for evidence that rolled-in pricing is good for explorers and the state. There, the FERC adopted a rebuttable presumption that voluntary expansions of the Alaska line must reflect rolled-in pricing.’ This means that the FERC will expect that owners of the Alaskan gasline will propose rolled-in treatment for expansions and will likely accept such proposals (or order rolled-in treatment on its own motion if it is not { TC Alaska, unlike the sponsors of the Producer Project, has committed to using rolled-in rolled-in pricing is not appropriate on this pipeline. This | Pricing for expansions as required by AGIA. Because of this, TC Alaska’s proposed) unless parties can show good reason why is a complete departure from FERC’s policies in the Lower 48 and signals how important FERC views the proposal is more likely than the pricing policies of the Alaskan pipeline sponsors to be. Producer Project to encourage In adopting this presumption favoring rolled-in pricing, | &Pansions that will the North Slope basin, which will benefit the state through more drilling, more Congress which had required that FERC’s rules | jobs, more royalties and more revenues. the FERC was in fact following the dictates of regarding access to the Alaskan gas pipeline that must “promote competition in the exploration, development and production of Alaskan natural gas.'* Clearly, rolled-in pricing for expansions—especially expansions that would otherwise result in higher rates for new shippers than for incumbent shippers—is fully consistent with the desire to encourage exploration and development of North Slope natural gas reserves. AGIA's rolled-in rate provisions protect against the risk that FERC would require incremental rate treatment instead of rolled-in rate treatment for voluntary or involuntary expansions of an Alaska natural gas pipeline. "' Regulations Governing the Conduct of Open Seasons for Alaska Natural Gas Transportation Projects, 110 FERC {| 61,095, Order No. 2005 at P 123. '2 ANGPA 2004, § 103(e)(2)(c) 27 May 2008 5-15 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination Rolled-in rates are required in Canada. As discussed in Appendix S2, the National Energy Board has required rolled-in pricing even where expansions have resulted in a doubling of the pipeline’s rate base which produced a dramatic increase in rates for incumbent shippers. Rolled-in rate treatment, however, has encouraged pipeline expansions in Canada and the creation of a competitive gas exploration and development industry in Alberta. TC Alaska has committed to the rolled-in pricing for expansions as required by AGIA. However, the sponsors of the Producer Project have not made any commitment, enforceable or not, regarding the pricing of expansion capacity.'? Therefore, TC Alaska’s Project is more likely than the Producer Project to encourage pipeline expansions that will facilitate full development of the North Slope basin, which will benefit the state through more drilling, more jobs, more royalties and more tax revenues. Indeed, the prospect that rolled-in pricing could raise the shipping rates of the BP and ConocoPhillips entities that might hold shipping contracts on the pipeline would clearly discourage the Producer-owners of the proposed project from proposing rolled-in rates.'* "3 Further, the Major North Slope Producers not only refused to commit to rolled-in rates in the 2006 SGDA Contract but actively opposed the inclusion of any rolled-in rate requirement in AGIA before it was enacted. In addition, it should be noted that while the apparently withdrawn ConocoPhillips November 30, 2007 proposal did indicate it would use rolled-in rates up to 105% of the pre-existing rate, that proposal fell significantly short of AGIA’s requirement that rolled-in rates be used up to 115% of the initial rate. In addition, the mere statement that ConocoPhillips would use rolled-in rates was completely unenforceable by the state or expansion shippers if ConocoPhillips for whatever reason had decided later not to use rolled-in rates. "4 As shown in Appendix G1, Figure 5-55, the Commercial team projects that expansions of the TC Alaska line up to a capacity of about 6.5 Bcf/day will result in rate reductions to incumbent shippers compared to the rates projected for the 4.5 Bcf/day original project. At a point, however, looping will be required if the capacity is to be increased, and that will be very expensive (compared to merely adding compression). At that point the use of rolled-in pricing for expansions will become critical to whether or not the gasline will continue to be expanded. Without rolled-in rate treatment new shippers will be responsible for the entire cost of the expansion and it will be uneconomic for those shippers to contract for expansion capacity. This will mean that as the pipeline is expanded through the addition of compression up to 6.5 Bcf/day and perhaps somewhat beyond that level, explorers will become less willing to invest new capital exploring for or developing reserves unless it is clear, up front, that looping expansions will be priced on a rolled-in basis rather than incrementally. However, rolled-in pricing of looping expansions comes at a cost to the shippers already using the system—their rates will go up somewhat in order for new shippers’ rates to be more reasonable. Inasmuch as a producer-owned pipeline is largely motivated to generate the greatest bottom-line profit from the sale of its own (or its affiliates’) production the prospect of raising the rates of incumbent shippers will be adverse to the owners’ bottom line interest. Given that a producer-owned pipeline does not have a strong interest in expanding the line to serve others (as discussed above) and has a clear economic disincentive to pursuing expansions that require looping, the commissioners are necessarily concerned about whether the sponsors of the Producer Project will ever support the rolled-in pricing that will become necessary for the full development of the pipeline. It is simply not in their economic interest to do so. 27 May 2008 5-16 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination 4. Commitments To Hold an Open Season and File at FERC, and Other Issues That Could Result in a Delay of the Producer Project In part to avoid a repeat of the SGDA experience, in which the Major North Slope Producers refused to make concrete commitments to pursue a pipeline project, AGIA required an applicant to make enforceable commitments to advance a project. Specifically, AGIA required applicants to make enforceable commitments to commence an open season, initiate the FERC pre-filing process, and file for a FERC certificate regardless whether the initial open season is successful, by specific dates. Further, AGIA required that the Licensee must agree to accept the certificate issued by the FERC once it becomes final and is not subject to further judicial review. If TC Alaska fails to adhere to these commitments, TC Alaska will be subject to sanctions with adjudication in Alaska courts. In accordance with those requirements, TC Alaska has committed to hold an open season by September 30, 2009, and to file for a FERC certificate by December 2011, regardless whether its open season is successful, as required by AGIA."® By contrast, BP and ConocoPhillips have made an unenforceable claim that they plan to hold an open season by 2010 (BP/ConocoPhillips 2008). They claim they will file for a FERC certificate if the open season is “successful,” but this implies that they will not file for a certificate if the open season is “unsuccessful.” (ConocoPhillips/BP 2008) Significantly, there is nothing in the BP/ConocoPhillips press release or PowerPoint presentation that even defines what a “successful” open season might actually entail (i.e. there is no indication as to the minimum amount or proportion of capacity that will have to be subscribed in the open season in order for the sponsors to pursue FERC/NEB certification). Thus there is nothing that would bind BP or ConocoPhillips to any concrete action as a result of any open season they would conduct. By contrast, TC Alaska, through its AGIA application, has made enforceable commitments to move its project forward through a binding open season, filing for the critical FERC certificate and acceptance of that certificate. The commissioners recognize that BP and ConocoPhillips have stated their intention to spend $600 million over a three-year period as part of an initial development and planning phase of the '> in its Application, TC Alaska premised these dates on receiving the AGIA License by April 1, 2008. Assuming the License is issued to TC Alaska later this year, these dates may need to be adjusted. However, for ease of reference in these Findings we will continue to refer to the original dates used by TC Alaska in its Application. 27 May 2008 5-17 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination Producer Project. However, they announced their plans only after TC Alaska proposed its project. The commissioners believe that if the state rejects TC Alaska’s Project, there is a significant risk that BP and ConocoPhillips will delay further work on the Producer Project until the state agrees to provide financial concessions. In addition, the fact that BP and ConocoPhillips have not made any binding commitments to advance the project on a fixed timeline is problematic due to the large volume of natural gas sales they make in the North American market. As two of the largest producers of natural gas in the U.S. and the world, BP and ConocoPhillips have a clear interest in controlling the schedule of any Alaska gas pipeline construction project and having power over the timing of shipping natural gas to North American consumers. The commissioners must assume that these sophisticated companies take into account the impact that bringing 4 or 4.5 Bcf/day of additional natural gas to market will have on the price of other natural gas these companies sell.'° The commissioners know that the Energy Information Administration (EIA) has predicted and forecasts that gas prices in North America will somewhat decrease (at least initially) once Alaskan gas comes on line.'’ An Alaska gasline thus would somewhat reduce the value of the other North American gas production and reserves these Producers own. It would be naive to think that BP and ConocoPhillips (or any other producer companies that might become investors in the Producer Project) will not manage their overall gas portfolio in the best interests of their shareholders even if it means delaying an Alaska gasline. The commissioners also know that both BP and ConocoPhillips have significant investments in projects to bring LNG to the U.S. For example, ConocoPhillips has a 30% ownership interest in Qatargas 3—a $5.8 billion LNG project bringing 1.4 Bcf/day equivalent of LNG to the U.S. starting in 2009. ConocoPhillips also has an interest in the Golden Pass LNG regasification '® Indeed, the commissioners are aware that ICF International, a major international consulting firm, “evaluated [for Alaskan gas producers] the effect of Alaska and Mackenzie Delta gas on US and Canadian gas markets prices and pipeline flows [and evaluated] various scenarios to assist the [Alaskan] North Slope producers in understanding the implications of different assumptions and configurations for bringing frontiers (sic.) supplies to market.” (http:/Avww. icfi.com/Markets/Energy/fuels-markets.asp#1) The commissioners would fully expect that many other similar studies have been undertaken by or on behalf of BP and ConocoPhillips (and other North Slope producers) in order for them to manage their overall gas portfolios, of which Alaskan gas is only one piece. '” In February 2004 EIA was specifically requested to evaluate the impact on U.S. gas prices if Alaskan gas does not flow. The conclusion was that Lower 48 gas prices would be approximately 20 cents higher than if Alaskan gas was available. Energy Information Administration, Analysis of Restricted Natural Gas Supply Cases at 8 (2004). While not specifically discussed, the 2007 Annual Energy Outlook implies a similar result. 27 May 2008 5-18 AGIA TC Alaska-Commitments/Producer Proposal-No Commitments Written Findings and Determination facility near Sabine, Texas that will be supplied by Qatargas 3 according to the company’s “Fact Book.” (ConocoPhillips, undated) BP’s website states that it imports LNG shipments into existing LNG terminals in the Lower 48 and will supply Indonesian gas to the Energia Costa Azul project that will supply markets in the U.S. and Mexico. (BP 2008) The economics of these and other LNG projects may also be affected by whether the price of gas in North America is decreased by the addition of the Alaskan gas to the overall supply. As a result of the potential adverse impact an Alaska gasline could have on the LNG investments of BP and ConocoPhillips, there is a significant risk the producers would delay the Alaska gasline until such time as it would have the optimal impact for their shareholders, which is not necessarily as soon as the State of Alaska would prefer. This fact suggests the state should not rely on BP and ConocoPhillips to move forward a gasline project. Another significant schedule issue facing the Producer Project is the Canadian regulatory process. First, TransCanada Corporation has the largest natural gas pipeline network in Canada, having obtained NEB approval for the construction of virtually its entire system. Neither BP nor ConocoPhillips have anything approaching the same level of experience as the TransCanada in obtaining Canadian regulatory approvals to construct natural gas pipelines. Second, any effort by the Producer Project to obtain Canadian regulatory approvals would probably become ensnared in litigation based on TransCanada’s claims to have the first right to construct an Alaska gas pipeline project under Canadian law. If TransCanada’s claim has merit (an issue on which the commissioners take no position) and if TransCanada prevails in its arguments, the Producer Project might never advance. This would be true even if BP and ConocoPhillips decide to include a different Canadian pipeline company, such as Enbridge, in their project. Third, TransCanada has already obtained a right-of-way in the Yukon, whereas the Producer Project has not. Thus, the Producer Project may not be able to obtain the necessary regulatory approvals to construct an Alaska gas pipeline through Canada as quickly as TransCanada. 27 May 2008 5-19 AGIA Producer-owned Pipeline is Contrary to the State’s Best Interests Written Findings and Determination D.A Producer-owned Pipeline Has an Incentive to Act in @ Ways That Are Contrary to the Best Interests of the State The failure of BP and ConocoPhillips to make any enforceable commitments to advance the project is compounded by the fact that a producer-owned pipeline has an inherent incentive to act in a way that is contrary to the interests of the State A producer-owned pipeline has an inherent incentive to act in a way gasline. There is a significant risk that the sponsors of that is contrary to the interests of the State of Alaska with respect to facilitating the full expansion of an consistent with the state’s interests with respect to low Alaska natural gas pipeline, of Alaska in facilitating the full expansion of an Alaska the Producer Project would not act in a way that is transportation rates, an explorer-friendly expansion | ¢tablishing low transportation rates, implementing an explorer- friendly expansion policy, and ing Indeed, there is a significant risk that the producer- | Alaska’s North Slope natural gas resource. policy, and full development of North Slope reserves. owners of the project could become entangled in litigation as a result of the serious competitive issues that would be raised by producer-ownership of an Alaska gas pipeline. A producer-owned pipeline has an inherent ability and incentive to discriminate against third- party producer-shippers that do not own the pipeline.'® By raising the pipeline’s rates or @ engaging in acts of discrimination against third-party producer-shippers, the gasline could be used to discourage entry by other producers and explorers. As discussed earlier, the state’s experience with the TAPS oil pipeline illustrates this point. Third-party producers have long complained that the TAPS rate structure impedes their ability to explore for and produce oil in Alaska.'® The owners of the gasline could attempt to achieve a similarly anticompetitive situation.”° Access to an oil pipeline such as TAPS is not an issue because oil pipelines are “common carriers” and not “contract carriers” as are gas pipelines (Appendix R4). Because of this, the basin control risk that competing producers face is greater in the context of a FERC- '® The competitive problems associated with a producer-owned pipeline are fully discussed in the memorandum prepared by Greenberg Traurig dated December 21, 2006, entitled “Updated Competitive Analysis of Producer- Owned Alaska Natural Gas Pipeline”, http://Iba.legis.state.ak.us/sqa/doc_log/2006-12-21_alaska_antitrust_memo.pdf. A copy of the Greenberg Traurig memorandum is attached to these Findings as Appendix R4 '8 See, e.g., Protest and Complaint of Anadarko Petroleum Corp., filed in FERC Docket No. ORO5-3, Dec. 16, 2004. 2 Interestingly, referring to the pipeline proposal by ConocoPhillips on November 30, 2007 (which ConocoPhillips withdrew when it and BP announced Denali), Anadarko asserts that “the rate estimate provided by TransCanada is considerably lower than the rate proposed by the ConocoPhillips proposal for comparable service.” See Appendix A. 27 May 2008 @ 5-20 AGIA Producer-owned Pipeline is Contrary to the State’s Best Interests Written Findings and Determination regulated gasline than in the context of a FERC-regulated oil line, such as TAPS.”" In TAPS, they face the potential of high rates. In the gasline they face that risk as well, but also the risk that they will be denied meaningful access to pipeline expansions in order to ship the production from their exploration and development activities to market. One of the goals of AGIA is to ensure these types of competitive problems do not occur in the development of North Slope natural gas reserves. AGIA provided an opportunity for any company, including a producer, to obtain the incentives associated with the AGIA License. However, to help avoid the problems experienced with TAPS and the inherent competitive problems associated with a producer-owned gas pipeline, AGIA essentially requires the Licensee to act like an independent pipeline. For example, an independent pipeline has an incentive to expand its system and increase its profits.?* By contrast, a producer-owned pipeline may be incented to control the production basin and to delay or thwart expansion as a way to limit competition by competing producers (Appendix R4). AGIA’s expansion and rate provisions seek to prevent this problem from occurring. By virtue of the producer-owners'’ interests that are at odds with the state’s interest (as set out in AGIA), and by failing to commit to follow those provisions, the Producer Project is less likely than TC Alaska to result in the full development of the state’s North Slope natural gas reserves.”° 2" The rates for interstate service on the TAPS line are regulated by FERC. As an oil pipeline subject to regulation under the Interstate Commerce Act TAPS is a “common carrier’ pipeline. That means that it must provide service to every party seeking to move oil through the line, even if doing so means that other shippers’ capacities must be reduced. Under FERC regulations of natural gas pipelines under the Natural Gas Act, however, the Alaskan project will become a “contract carrier.” Regulation of Natural Gas Pipelines After Partial Wellhead Deregulation, Order No. 436-A, 50 Fed. Reg. 52,217 (1985). This means that new shippers do not have any right to firm capacity once the capacity is fully contracted to others. The significance here is that the TAPS owners cannot deny access to potential shippers whereas owners of the gasline can deny access by refusing to expand to accommodate new shippers (unless they can successfully petition FERC to require an expansion). Thus, a party seeking service on the Alaskan gasline may be denied access to the line in the event that capacity to move its gas is not available because other parties have contracted for the capacity but such a circumstance could never arise on TAPS because capacity must be made available. However, on both the TAPS line and an Alaskan gas pipeline producer-owners can seek to increase rates in the line in order to make production of Alaskan gas uneconomic as a way to exercise basin control. 2 This is because regulated gas pipelines make their profit (their return on equity) based on the amount of investment they have in the pipeline (referred to as “rate base”). As a result of depreciation, rate base is continually being eroded which means the pipeline’s earnings base is being continually eroded. The way that gas pipeline companies overcome such erosion of their earnings potential is through adding new facilities (i.e., expanding the pipeline). 3 it is possible that BP and ConocoPhillips will eventually expand their Denali partnership to include a third-party pipeline (such as Enbridge). Whether that step would cure the competitive problems inherent in a producer-owned pipeline would depend on how the partnership is structured, although a complete cure is unlikely. For example, if one or more of the producers could veto a commercially reasonable expansion, the inclusion of a third-party pipeline company in the Denali partnership would not fix the problems. Moreover, Denali still would have failed to commit to the requirements of AGIA. 27 May 2008 5-21 AGIA Producer-owned Pipeline is Contrary to the State’s Best Interests Written Findings and Determination There is also a risk that a pipeline owned by BP and ConocoPhillips would be exposed to © litigation or investigations either by FERC, the Department of Justice, the Federal Trade Commission, or potential private plaintiffs. For example, the Department of Justice, headed by the U.S. Attorney General, warned in the 1970s that producer ownership of an Alaska natural gas pipeline would raise serious competitive concerns. This warning relates to basin control - the ability of a producer-owner of an Alaskan gas pipeline to discriminate against rival producers, including delaying or limiting pipeline expansions needed to serve rival producers. That issue resulted in the Department of Justice’s recommendation in 1977 that producers be completely barred from owning any equity interest in an Alaskan pipeline.” That eventually gave rise to a requirement that, for any project built under the ANGTA legislation, “any agreement on producer participation [in the Alaskan pipeline] may be approved by the [FERC] only after consideration of advice from the Attorney General and upon a finding by the [FERC] that the agreement will not (a) create or maintain a situation inconsistent with the antitrust laws or (b) in and of itself create restrictions on access to the Alaska segment of the [proposed pipeline].”*° (Minesinger 2007) Based on these same concerns, there is a significant likelihood that FERC-imposed conditions on any certificate (assuming BP and ConocoPhillips file for a certificate) may be necessary to @ ensure that the project ultimately serves the public interest, not just the interests of BP and ConocoPhillips. FERC has the power to place conditions on any certificate it issues when it finds that such a condition is necessary to ensure or protect the “public convenience and necessity.” However, while AGIA requires that the Licensee actually accept the certificate that is issued by the FERC once it becomes final and is no longer subject to judicial review, BP and ConocoPhillips have no such obligation. Thus if the FERC imposes conditions on the certificate it might issue to the Producer Project in order to protect the public interest, BP/ConocoPhillips could reject the certificate because of the conditions. In that case, Alaska would find itself with no gas pipeline at all. 24 Public Papers of the Presidents of the United States, Reagan, Ronald, 1981 Pub. Papers at 935 (1981). 27 May 2008 S ?5 Bub. L. No. 97-93, 95 Stat. 1204, 1981 5-22 AGIA Producer-owned Pipeline is Contrary to the State’s Best Interests Written Findings and Determination The prospect of FERC conditions designed to minimize or eliminate competitive concerns was addressed in a January 28, 2005, letter from the then-FERC Chairman to Representative Ethan Berkowitz of the Alaska Legislature: In authorizing an Alaskan gas pipeline under the NGA, the Commission will seek to promote investment in and the development of Alaskan gas reserves to expedite the delivery of these reserves to markets in and out of Alaska, in conformity with antitrust laws. In doing so, the commissioners will be mindful of the congressional and presidential pronouncements you referenced in your letter. Continuing, the FERC Chairman stated: Currently, the Commission does not have before it any application for authority to construct an Alaskan natural gas transportation pipeline. Thus, it is not possible to respond specifically to issues, including antitrust matters, which may arise once such an application is filed. However, all such issues will be carefully assessed by the Commission when an application is submitted for a pipeline project, and the Commission will do everything it can to preclude antitrust abuses and promote competition in the authorization, construction, and operation of a future Alaskan natural gas pipeline .. . [I]t would be prudent to conclude that the antitrust issues which concerned Congress and the President over twenty years ago are still valid and will be addressed by our Commission in our proceedings.”® This statement highlights the potential that FERC would impose a certificate condition unacceptable to BP and ConocoPhillips, which could cause them to delay or even abandon the project. It also indicates BP and ConocoPhillips, as owners of the project, could face additional scrutiny from federal antitrust agencies, and possibly from the State Attorney General, who is charged with enforcing Alaska’s antitrust laws. BP and ConocoPhillips would also face the risk of antitrust litigation by private plaintiffs seeking to prevent the development of an anticompetitive market structure or anticompetitive activity that could impede or distort the development of North Slope natural gas reserves. 26 FERC Docket No. RM05-2, January 28, 2005 Letter at 2 (emphasis added)). 27 May 2008 5-23 AGIA TC Alaska and Producer Proposal Lack Firm Shipping Commitments Written Findings and Determination E. Both TC Alaska and the Producer Projects Lack Firm Shipping Commitments Neither TC Alaska Project nor the Producer Project has firm shipping commitments to support their respective projects at this time. It might be assumed that the Producer Project (owned by BP and ConocoPhillips) would have the ability to obtain firm shipping commitments from its owners. The commissioners acknowledge that, at first glance, the Producer Project would appear to have an advantage over TC Alaska in convincing BP and ConocoPhillips to sign firm shipping commitments on their own project.”” A significant problem, however, is that BP and ConocoPhillips have consistently insisted, including in their AGIA comments, that the state must provide them with major fiscal concessions before an Alaska gasline project can proceed. ConocoPhillips stated in a January 24, 2008 letter that, with regard to firm shipping commitments and other issues, “[nJo commercially reasonable party will take these unprecedented investment risks until a number of conditions have been met, including the establishment of a predictable gas fiscal framework,...” (ConocoPhillips 2008). As a result of these demands for fiscal certainty, the Producer Project is unlikely to obtain unconditional firm shipping commitments that are not conditioned on or dependent upon such concessions from the state. Chapter 3 of these Findings demonstrated that, even under the state’s current fiscal structure, the Major North Slope Producers would earn billions of dollars in profits and an extraordinary rate of return by signing firm contracts on the TC Alaska project (which presumably will have similar costs to those that would be incurred by the Producer Project), even if the only North Slope gas they ever produce is from the Prudhoe Bay Unit. 27 We also acknowledge that BP and ConocoPhillips unquestionably have the financial resources to construct the Denali project. In the presentation which accompanied the Denali announcement, BP and ConocoPhillips emphasized their financial strength, pointing to their combined $300 billion market capitalization. See BP/ConocoPhillips Denali PowerPoint presentation, at slide 11, April 8, 2008. These companies’ financial strength and their ability to finance a large-scale project cannot be doubted. On the other hand, while TransCanada is also a major energy company, its market capitalization is not as large as the combined market capitalization of BP and ConocoPhillips. See Appendix H at Section 4. Nevertheless, Goldman Sachs concludes that TransCanada has the financial resources to obtain financing of the Project. See Appendix H at Section 4. Accordingly, while BP and ConocoPhillips may have more financial resources than TransCanada, both projects have the necessary financial wherewithal to succeed, assuming other barriers to financing (such as the need to obtain firm shipping commitments) can be overcome. 27 May 2008 5-24 AGIA TC Alaska and Producer Proposal Lack Firm Shipping Commitments Written Findings and Determination In comparison, the TC Alaska project will include upstream fiscal inducements provided through AGIA for any gas committed at the initial binding open season for the project. These inducements increase the likelihood that TC Alaska’s project will attract commitments from the Producers even with the existence of the Producer Project. In addition, prior to the TC Alaska Open season, the state may choose to increase the value of those inducements, if proven necessary. 27 May 2008 5-25 AGIA Costs Comparison to State Following TC Alaska Project Written Findings and Determination F. Comparison of the Costs to the State Following the TC Alaska Project Path or the Producer Project Path Some have suggested the state would be better off pursuing the Producer Project instead of the TC Alaska Project because the Producer Project would allegedly “save” the state up to $500 million. In other words, the argument is that the Producer Project is offering the state a better deal because it would build a natural gas pipeline without any state matching funds, whereas TC Alaska would be entitled under AGIA to receive $500 million for qualified expenses incurred to develop its Project. This argument is flawed, for several reasons. First, as discussed in Chapter 3, the state would The State of Alaska will receive a net benefit from its $500 million actually realize a higher NPV as a result of paying the $500 million to TC Alaska. In other words, the state | inducement if the TC Alaska project will not only get the $500 million back, but will make | 's constructed. more than a 5% return on the investment. This is because the matching funds will not be included in the transportation rates TC Alaska would charge for the Project. As a result, TC Alaska will charge lower transportation rates, which in turn will increase net backs and producer profits, and in turn increase state royalty and tax revenues which depend heavily on the level of Producer profits. Thus, contrary to the argument that the state would be better off abandoning AGIA and avoiding what some consider the unnecessary expenditure of $500 million of state funds on the TC Alaska project, this analysis demonstrates that the state would actually receive a net benefit if the TC Alaska project is constructed compared to the Producer Project. In addition, the state will receive significant benefits and commitments from TC Alaska in exchange for the matching funds. For example, as demonstrated above, TC Alaska’s commitment to a 75/25 debt to equity structure would increase the value of the project to the state by more than $8 billion over a possible Producer Project structure. These benefits also include values that cannot be as easily quantified. Examples of these benefits include enforceable commitments by TC Alaska to expand its pipeline when commercially reasonable, to hold an open season by a date certain, to file for a FERC certificate on a fixed timeline and regardless whether the initial open season is successful, to hire state workers to the extent permitted by law, and to provide in-state deliveries of natural gas at reasonable rates. The Producer Project has not made any enforceable commitments. Critics of the $500 million fail to recognize the “quid” the state will receive for the $500 million “quo.” 27 May 2008 5-26 AGIA Costs Comparison to State Following TC Alaska Project Written Findings and Determination Even if one ignores the benefits the state stands to receive for the $500 million, the cost of those funds pales in comparison to the billions of a . AGIA’s $500 million inducement pales in comparison to the billions Producers demanded the state provide them during the | of dollars in concessions which the dollars in concessions that the Major North Slope Major North Slope Producers demanded during the SGDA considering a_ pipeline project. In their AGIA negotiations. SGDA negotiations as a precondition to even comments, BP and ConocoPhillips have renewed their insistence that the state make significant fiscal concessions as a precondition to moving a natural gas pipeline forward. Thus, it is reasonable to conclude that the expenditure of up to $500 million of state matching funds on the TC Alaska project would be significantly less than the amount the state would be required to spend or forego to induce construction of the Producer Project. Those concessions are likely to be even more substantial if the legislature rejects the TC Alaska Project. As discussed earlier, the state found itself in an untenable negotiating position with the Major North Slope Producers in the SGDA negotiations. The prior administration terminated negotiations with the other applicants under SGDA and elected to negotiate exclusively with the Producers. By eliminating its options or alternatives to a negotiated agreement with the Producers, the previous administration gave up any leverage that it had, and thus was unable to negotiate an agreement that protected the state’s interests. AGIA provides a clear path to move the natural gas pipeline project forward. TC Alaska has committed to take this project through the acceptance of certificates from the FERC and Northern Pipeline Agency/National Energy , complying with all of the requirements of AGIA. Due to the favorable economics of the TC Alaska project, including the extraordinary profits it would generate for Producers, it should be unnecessary for the state to have to take action regarding any failure by the Producers to support TC Alaska’s project. However, the state has a strong fallback position if the Producers, TC Alaska, and the state cannot agree to terms in the interim. TC Alaska's commitments to obtain permits and authorities to construct and operate a pipeline will position the state to require Finally, if in the future the Major North Slope Producers can make a convincing case, based on market that the Major North Slope Producers fulfill their obligations to produce and market the state’s state in addition to those already attached to the TC natural gas resources. conditions at that time, that fiscal concessions by the Alaska project are needed to move the project forward, 27 May 2008 5-27 AGIA Costs Comparison to State Following TC Alaska Project Written Findings and Determination then AGIA provides the vehicle for that to occur. Having elected to issue a License to TC Alaska, the state would have a strong interest in taking all actions necessary to see the TC Alaska project succeed, so long as such actions are reasonable and consistent with the state’s interests. Those actions could include fiscal changes, although as stated above no need for any fiscal changes has been demonstrated at this time. 27 May 2008 5-28 AGIA TC Alaska’s Offer of Equity Partnership Written Findings and Determination G.TC Alaska’s Offer of Equity Partnership In its Application, TC Alaska has indicated a willingness to offer equity participation opportunities to any shipper that participates in the initial open season. According to TC Alaska, offering shippers an equity ownership opportunity will enhance the chances its project will have a successful open season and will align the interests of TC Alaska and its shippers. It is thus quite possible that one or more of the Major North Slope Producers may eventually participate in the TC Alaska Project as an owner. Indeed, in its comments ExxonMobil states that it “agrees with [TC Alaska’s] suggestion that it would be useful for the [Major North Slope Producers] to be involved as co-owners in the project” (Appendix A, comment #269). An example of a joint pipeline/producer ownership structure involving a major new natural gas pipeline project is the recent Rockies Express pipeline, in which the majority owner is an independent pipeline company (Kinder Morgan), while ConocoPhillips is a minority owner (along with Sempra). AGIA supports the possibility of offering equity participation opportunities to shippers. Depending on the facts and circumstances, including the structure of and specific rights associated with any equity ownership position, equity ownership in the TC Alaska project by shippers that make firm shipping commitments on the Project could be consistent with AGIA. The commissioners believe TC Alaska’s willingness to include firm shippers as equity partners in its AGIA project is a positive step, as is ExxonMobil’s favorable reaction. The commissioners strongly encourage the parties to discuss ways of collaborating on an AGIA-compliant project. 27 May 2008 5-29 AGIA Upstream Inducements Provided by AGIA Written Findings and Determination H. The Upstream Inducements Provided by AGIA are Valuable and Incentivize the Producers to Commit Gas to the TC Alaska Project The question can fairly be asked, “What will cause the North Slope Producers to commit natural gas production to TC Alaska’s project and why should the state even consider investing up to $500 million in that project?” This is especially relevant in light of the Producer Project. The answer lies in the provisions of AGIA that provide meaningful and valuable benefits to parties that commit their gas to the AGIA licensed project in the first binding open season (AS 43.90.310 and .320). Those provisions give to holders | AGIA inducements represent real of state leases that commit gas to the AGIA-licensed | value to the producers that is “here and now,” not speculative. project the assurance that, for ten years after the commencement of commercial operations by the licensed pipeline, their production tax rates will not change from those in effect at the close of the first binding open season. The Producers can also obtain the benefit of future royalty regulations that the state will establish prior to the close of the first binding open season for the licensed project. These royalty regulations will establish a method for determining fair market value; minimize the retroactive adjustments to the monthly determination of value for the state’s royalty share; and define the state’s rights to switch between taking royalty gas in-kind versus in-value. These provisions of AGIA are available only to producers who commit gas to the first binding open season of the AGIA licensed project. They are not available to producers who commit their gas to any other project—in this case, to the Producer Project. Historically, the Producers have insisted on much more sweeping (frequently unspecified) concessions by the state with respect to taxes and royalties (and, under SGDA, many other major concessions). As discussed in Chapter 3 of the Findings, there is no reason for the commissioners to believe at this time that any concessions on the state’s part are needed over and above those already available to producers who commit gas to the AGIA project during its first open season. The upstream inducement provisions of AGIA, however, are available now - and those inducements will be locked in if all of the producers commit their production to the AGIA project. 27 May 2008 5-30 AGIA Upstream Inducements Provided by AGIA Written Findings and Determination Given the fact that no basis currently exists to support the state’s providing any additional concessions to induce parties to commit their gas to a gas pipeline, the availability of the upstream inducements of AGIA represent real value to the Producers. The value is “here and now” and not speculative. Given the NPV that the commissioners believe will flow to the major North Slope Producers under the TC Alaska Project, it is reasonable to believe that the Producers will act as rational commercial players and commit gas to the TC Alaska Project in order to secure the benefit of the upstream inducements of AGIA. 27 May 2008 5-31 AGIA State’s Interest to Pursue TC Alaska Project Written Findings and Determination I. It is in the State’s Interest to Pursue the TC Alaska Project @ It should be clear that Alaska is better served by obtaining a natural gas pipeline that will provide the many benefits that will flow from an AGIA-licensed project. However, nothing in AGIA prevents or limits the rights of BP/ConocoPhillips to pursue their own project; in fact, the competition between the TC Alaska project and the Producer Project probably moves the state closer to a natural gas pipeline. However, if, at the end of the day, for whatever reason the Producer Project wins out and obtains shipper support, regulatory approvals and financing, and builds the project, the state is better Competition is good—The presence of off than if no line is constructed. Based on prior | the TC Alaska project will constantly force the Producers to move forward with the Producer Project, join the TC experience (TAPS and SGDA) it is not likely that this circumstance will occur without having the TC Alaska project, or face the risks outlined in Chapter 3 associated with failure to commercialize Alaska’s North presence of the TC Alaska Project will constantly Slope gas. Alaska Project supported by the state. The force the Producers to move forward with the Producer Project, join the TC Alaska project, or face the risks outlined in Chapter 3 associated with failure to commercialize Alaska’s North Slope gas. 27 May 2008 @ 5-32 AGIA Conclusion Written Findings and Determination J. Conclusion The commissioners’ objective is to find a project that maximizes benefits to Alaskans. On balance, the commissioners believe it is in the state’s interests to rely on the binding commitments made by TC Alaska rather than on the Producer Project. The sponsors of the Producer Project, by contrast, have not made any comparable commitments and, as evidenced by the history of the failed SGDA contract and TAPS, are unlikely to pursue their project on a basis that fully achieves the state’s interests. 27 May 2008 5-33 AGIA References Written Findings and Determination K. References Alaska Department of Revenue. 2006. Draft Alaska Stranded Gas Fiscal Contract between The State of Alaska and BP Exploration (Alaska)., Inc. and ExxonMobil Alaska production Inc. State of Alaska Department of Revenue. May 24, 2006 Anadarko Petroleum Corporation. 2004. Protest and Complaint filed in FERC Docket No. ORO5- 3, Dec. 16, 2004. Anadarko Petroleum Corporation. 2008. Comment of Anadarko Petroleum Corporation on Joint Application of TransCanada Alaska and Foothills Pipe Lines LTD for License Under the Alaska Gasline Inducement Act. Viewed May 16, 2008 at http:/Awww.dog.dnr.state.ak.us/agiacomments/Comments.aspx Anchorage Daily News. 2004. “Oil Firms Overcharge, Agency Says.” July 3, 2004. p. A-1 BP and ConocoPhillips. 2008. Denali Project PowerPoint Presentation. www.denali- thealaskagaspipeline.com/ BP. 2007. BP Annual Report and Accounts. Viewed May 18, 2008 at: http://www.bp.com/liveassets/bp_internet/globalbp/globalbp_uk_english/set_branch/STA GING/common_assets/downloads/pdf/ara_2007_annual_review.pdf. BP. 2008. BP and ConocoPhillips Join on the Alaska Gas Pipeline. Press release dated April 8, 2008. Viewed May 16, 2008 at http://www.bp.com/genericarticle.do?categoryld=2012968&contentld=7043306 BP. 2008. Crown Landing Bringing Clean Energy to the Region, 2008 https:/www. piersystem.com/external/index.cfm?cid=569&fuseaction=EXTERNAL.docvie w&documentID=48103. ConocoPhillips. 2007. ConocoPhillips Financial Review 2007. Viewed May 18 at: http:/www.bp.com/liveassets/bp_internet/globalbp/globalbp uk english/set_branch/STA GING/common_assets/downloads/pdf/ara_2007_annual_review.pdf. ConocoPhillips. Undated. Fact Book. Viewed May 16, 2008 at http://www.conocophillips.com/about/company _reports/fact_book/index.htm Energy Information Administration, Analysis of Restricted Natural Gas Supply Cases. SR- OIAF/2004-03. February 2004. Viewed May 16, 2008 at http://www.eia.doe.gov/oiaf/servicerpt/ngsupply/ ExxonMobil Corporation. 2008. Exxon Mobil Corporation Comments on TransCanada AGIA License Application. March 6, 2008. Viewed May 16, 2008 at http:/Awww.dog.dnr.state.ak.us/agiacomments/Uploads/030608153830.pdf Federal Energy Regulatory Commission. 2005. Letter from FERC Chairman to Representative Ethan Berkowitz of the Alaska Legislature. FERC Docket No. RM05-2. January 28, 2005. Viewed May 16, 2008 at http://elibrary.ferc.gov/IDMWS/common/opennat.asp?filelD=10402571 27 May 2008 5-34 AGIA References Written Findings and Determination Federal Energy Regulatory Commission (FERC). 2005. Regulations Governing the Conduct of Open Seasons for Alaska Natural Gas Transportation Projects, 110 FERC {] 61,095, Order No. 2005. Federal Energy Regulatory Commission (FERC). 2007. 119 FERC {] 63,007 Greenberg Traurig. 2006. “Updated Competitive Analysis of Producer-Owned Alaska Natural Gas Pipeline.” Included as Appendix R.1 to the AGIA Findings and Determination. Viewed May 16, 2008 at http://Iba.legis.state.ak.us/sga/doc_log/2006-12- 21 _alaska_antitrust_memo. Greenberg Traurig. 2007. “Producer-owned Pipelines.” Included as Appendix R.4 to the AGIA Findings and Determination. Viewed May 16, 2006 at http://Iba.legis.state.ak.us/sqa/doc log/2006-12-21 alaska _antitrust_memo.pdf Haines, Leslie. 1996. Getting to the future first.” Hart’s Oil & Gas Investor. August 1996. ICF International. 2008. Fuels Markets Webpage. Viewed May 19, 2008 at http://www. icfi.com/Markets/Energy/fuels-markets.asp Minesinger, Kenneth M. 2007. How AGIA Addresses Competitive Issues Of A Producer-Owner Pipeline. Presentation to the Alaska Legislature Senate Judiciary Committee. May 11, 2007 27 May 2008 5-35 @ Chapter Six — Findings and Determination Table of Contents Commissioners’ FindingS ............cccccccessessseeseeseescseeseeeeeecseceseecsceesseeeessesececeenenesieesenesieeeseeaeneeneetey 6-1 Commissioners’ Determination ............:cc:ccccceceesseeeseeeeseesceseeseesessssseassecseceesseseesaecaeeseeesseeeeeeneeees 6-2 27 May 2008 AGIA Commissioners’ Findings Written Findings and Determination Commissioners’ Findings Based on the analysis provided in the previous chapters, the Appendices, and in the supporting documentation, the commissioners find that the TC Alaska Project: e Is Alaska’s best opportunity for expediting construction of a natural gas pipeline that commercializes North Slope gas resources. * Maximizes jobs and long-term careers for Alaskans by promoting exploration and development of oil and gas resources on the North Slope. e Maximizes access to affordable energy for Alaskans. e Sufficiently maximizes revenues to the State of Alaska. e Encourages oil and gas lessees and other persons to commit to ship natural gas from the North Slope to a gas pipeline system for transportation to markets in this state or elsewhere. 27 MAY 2008 6-1 AGIA Commissioners’ Determination Written Findings and Determination Commissioners’ Determination Development of the North Slope natural gas basin is key to Alaska’s long-term economic security and to the state’s and the nation’s energy security. The Alaska Gasline Inducement Act (AGIA) offers an opportunity to maximize Alaska’s prospects for getting a natural gas pipeline and to maximize benefits for Alaskans when it comes to developing and marketing Alaska’s gas resources. One of the primary purposes of AGIA is to move the pipeline project forward through defined benchmarks so as to eliminate the project's uncertainties. At each step of the process more information will be gathered and, with that additional knowledge, appropriate decisions can be made to keep the project moving through to construction. With the uncertainties eliminated, and the project’s economic potential even better defined, there will be increased predictability and incentives for the Major North Slope Producers to participate as gas shippers — without concomitant concessions by the state on the fiscal terms associated with natural gas production (such as royalty values and the state production tax). The commitments required of an AGIA Licensee are geared toward achieving a vibrant oil and gas industry on the North Slope now and in the future. The AGIA requirements are based on what is commercially reasonable as well as what is in Alaskans’ interests: getting a natural gas pipeline, maximizing jobs and long-term careers, maximizing affordable energy for Alaskans, and sufficiently maximizing state revenues. In the course of the evaluation process, the commissioners found that the pipeline project proposed by TC Alaska is the project that has the greatest likelihood of moving forward in a timely manner with terms that most sufficiently maximize benefits to Alaskans. In comparison, the commissioners found that an LNG project will provide less revenue to the state and is less likely to move forward to construction because, among other issues, an LNG project (1) is extremely complex and requires that all elements, from production to the market destination, be in place prior to financing; (2) would likely cost more to construct than the TC Alaska project; (3) is less likely to get firm transportation commitments from North Slope producers; and (4) would face significant hurdles in obtaining federal approval to ship LNG to foreign ports. 27 MAY 2008 6-2 AGIA Commissioners’ Determination Written Findings and Determination The commissioners also found that the Producer Project would not protect the state’s interests or maximize benefits to Alaskans to the same extent as the TC Alaska Project. The Producer Project provides no legally enforceable commitments that the project will continue to move forward or provide the reasonable tariff and expansion terms needed to maximize North Slope exploration and development. Furthermore, it is highly likely that, at some point, the Producer Project proponents will seek significant concessions from the state prior to moving the project forward to construction. Through the evaluation process, and consideration of public comment, the commissioners have found that the TC Alaska Project is economically and technically viable; that it will generate significant value for the state, the producers, the federal government, and the pipeline company; that the Project is likely to succeed; and that TC Alaska has made the necessary commitments to maximize benefits to Alaskans. Commissioners’ Determination: Based on the analysis and discussion set forth in the Executive Summary, Chapters 1 through 5, the Appendices including Public Comment and Responses, and other supporting documents to these Findings, the Commissioners of the Departments of Natural Resources and Revenue determine that TC Alaska’s application proposes a project that will sufficiently maximize the benefits to the people of this state and merits issuance of a License under AGIA (AS 43.90). Because of the sheer volume of material incorporated into the Findings and Determination, the commissioners reserve the right to provide errata to correct errors or omissions that do not have a material effect on the Determination itself. This Findings and Determination, Appendices, and associated License will be submitted to the presiding officers of each house of the Alaska Legislature on June 3, 2008. In addition, the Findings and Determination and Appendices will be publicly noticed and made available on the state’s website at http://www.gov.state.ak.us/agia/. Hard copies of the Findings and Determination and Appendices on CD will be available for review at Department of Natural Resources Public Information Centers and Legislative Information Offices. Upon legislative approval of issuing the License proposed by the commissioners, the License will be issued to TC Alaska as soon practicable after the effective date of the legislation. 27 MAY 2008 6-3 AGIA Commissioners’ Determination Written Findings and Determination On the effective date of a bill approving issuance of the AGIA License, this determination becomes a final agency decision for purposes of an appeal to Superior Court. (AS 43.90.180(a)(1)) A person affected by this final order and decision may appeal to Superior Court within 30 days of the effective date of the bill approving issuance of the AGIA License in accordance with Appellate Rule 602(a)(2) of the Alaska Rules of Appellate Procedure. Pursuant to AS 43.90.420, “[a] person may not bring a judicial action challenging the constitutionality of this chapter or the constitutionality of a License issued under this chapter unless the action is commenced in a court of the state of competent jurisdiction within 90 days after the date that a License is issued.” BEC 27 May 2008 Commissioner Thomas E. Irwin Date Alaska Department of Natural Resources LL— 27 May 2008 Commissioner Patrick Galvin Date Alaska Department of Revenue 27 MAY 2008 6-4 P-1 P-2 P-3 P-4 P-5 P-6 PLENARY SESSIONS Opening Session - Welcome by Governor Palin; Introduction and Presentation by Commissioners Irwin and Galvin TransCanada - Accomplished and Capable TransCanada Alaska Project: From Costs and Schedule to Tariffs Net Present Value (NPV) Analysis and Results Liquid Natural Gas (LNG) Analysis and Results Is AGIA worth $500 Million? Opening Session Welcome by Governor Palin; Introduction and Presentation by Commissioners Irwin and Galvin b-d AGIA Gasline Determinatio Public Forum May 28-30, 2008 Prov )pportunity for Legis Public to Understand the Recent AGIA Decision e Explain the Basis and Rationale for the Commissioners’ Findings and Determination ¢ Present the Analysis and Results Prepared by Expert Consultants _ © Allow Interaction between Legislators, the Schedule Broadcast Legislator Binders All presentation materials will be on AGIA website: www.gov.state.ak.us/agia/ CDs including all presentations and appendices available Friday application — will sufficiently maximize the benefits to the people of Alaska, and — merits issuance of an AGIA license. ¢ Issuing an AGIA License to TC Alaska maximizes benefits to Alaskans more than pursuing an LNG project or the Producers Based on the Commissioners’ evaluatior Alaska’s application, examination of LNG © ¢ Assembled a team of experts to provide analysis and foundational information for the Commissioners © Many of those experts are here to present their alysis e Jobs and long-term careers © Opportunity of affordable energy for Alaska ¢ Maximize state revenue and create opportunity for future growth of state economy — A feasible project plan, sponsored by a capable pipeline company — An economic project likely to attract firm transportation commitments and secure financing ¢ Jobs and long-term careers © Opportunity of affordable energy for Alaskans _¢ Maximize state revenue and create dortunity for future g e Jobs and long-term careers — True “open access” for explorers © Opportunity of affordable energy for Alaskans ¢ Maximize state revenue and create opportunity for future growth of state economy e Explorers have Confidence that — Pipeline capacity will be expanded if new gas is found — New gas will pay a fair transportation rate e “Expansion Provisions” lled-in Rates” * Jobs and long-term careers © Opportunity of affordable energy for Alaska — Off-Take Points, and Distance-Sensitive Rates — Expansion Provisions — Does not interfere with “Bullet Line” project | © Maximize state revenue and create opportunity for future growth ofstate = © Jobs and long-term careers © Opportunity of affordable energy for Alaskans ¢ Maximize state revenue and create opportunity for future growth of state economy — Lowest Reasonable Transportation Rates (tariff) _ — Expansion Provisions * A feasible project plan, sponsored by ; capable pipeline company ¢ An economic project likely to attract firm transportation commitments and secure financing 1,715 miles of pipe, 750 in Alaska Capacity as low as 3.5 BCF/day Expandable to 5.9 BCF/day with compression Connect to AECO hub in Alberta with access to North American markets PIPELINES Natural Gas Pipelines El Canadian Mainline BB Aberta system HA Bl Gas Transmission Northwest Systerr ANA Natural Gas Storage —— Wholly owned —— Pattiaty owned —— Proposed anada is a highly experience: independent natural gas pipeline | company, with the necessary experien (operating within U.S., Mexico, Canada, arctic and near-arctic conditions) and financial resources to complete its _ Project ° Net Present Value (NPV) ¢ Likelihood of Success ) Ana — Measures the profits (or losses) that a project produce over time in today’s money. — Because NPV is expressed in the common term of today’s money, it can be used to compare the relative benefits of several competing projects. — Discount rate greatly affects present value of a future cash flow Present Value of $100 Cash Flow in Future Discount Rate = 5% Present Value of $100 Cash Flow in Future Years Sensitivity to Discount Rate ——5% Discount Rate ——8% DiscountRate —— 10% DiscountRate —— 15% DiscountRate ‘oday’'s value of $100 in the future = Gas Prices — Transportation Costs © Pipeline Project Capital Costs * Cost Escalation Rates © Pipeline Capacity ° Tariff Terms (e.g. debt to equity ratio) — Pipeline Construction Schedule Production Costs — “Proposal Base Case” * 4.5 Bcf/d (including 0.9 Bcf/d from Pt. Thomson) © 75/25 debt to equity * 14% return on equity © 25 year shipping contracts — “Conservative Base Case” * 4.0 Bcf/d (No gas from Pt. Thomson) © 75/25 debt to equity * 14% return on equity 20 year shipping contracts — Separate price forecasts were obtained © US DOE’s Energy Information Administration (EIA) © Wood Mackenzie * Gas Strategies Consulting © Black and Veatch -— “Technical Team”, included © Westney Consulting ¢ Energy Project Consultants © Pingo International ¢ AMEC Paragon * Colt Engineering ¢ Mustang Management © Energy Operations Consulting __ © Black and Veatch — Proposal Base Case © $31 Billion in today’s dollars — $3.19 tariff © $45 Billion in dollars spent — $4.73 tariff — Conservative Base Case * $29 Billion in today’s dollars — $3.59 tariff ___-¢ $42 Billion in dollars spent Alaska’s? — — Difference Between Assumptions Mandated in — the RFA and the final analysis assumptions © Exchange rate, cost escalation rate — Assumed “Neutral Competence” of Operator — Cost of the GTP * One vs. Two seasons of sea-lift — TC Alaska’s Cost Estimates are “realistically 5! = Mid-range probability put first gas 20 — State’s Canadian Counsel advised on expected regulatory timeline in Canada, including First Nation issues — TC Alaska’s schedule (first gas in 2017) is “realistically aggressive” mmary — — Gas Prices (WoodMac) — Transportation Costs * Pipeline Project Capital Costs ($31.5 billion) * Cost Escalation Rates (4%) * Pipeline Capacity (4.5 Bcf/d) * Tariff Terms (e.g. debt to equity ratio[75/25]) — Pipeline Construction Schedule (2020) _— Gas Production Costs ¢ The State of Alaska would realize a estimated cash flow of $261.5 billion, ane an estimated NPV of approximately $66.1 billion 7 at a discount rate of 5%. ¢ The Major North Slope Producers would realize an estimated cash flow of $147.4 billion, and an estimated NPV of oproximately $13.5 billion at a discour ¢ The State’s NPV decreases by 8% from the Proposal Base Case to $60.7 billion. ¢ The Major North Slope Producers NPV decreases by 9% to $12.3 billion. @ State NPV e The Project Economics are Ext — It would take a “perfect storm” of worst case scenarios for multiple factors for the Project to be uneconomic. — Indeed, a “perfect storm” of low gas prices and high construction costs, together, are not enough to generate negative state NPV. @ State NPV ° Tariff is reduced by 6 cents ¢ State’s NPV increases by $200 Million and reasonable ¢ Extremely capable pipeline company. © State’s Upstream Inducements — 10-year tax certainty — Royalty valuation certainty ¢ Avoid Problems of Not Committing Gas — Duty to develop _ — Anti-trust that is technically feasible, reas specific. * TC Alaska has demonstrated the technical and financial ability to construct the project. e TC Alaska has submitted a reasonable commercial plan which, coupled with economic and political factors, should bee to ¢ Risk of litigation is significantly overstated. ¢ Potential legal claims by withdrawn partners are, at best, weak and unlikely to succeed. ¢ Not a reasonable basis for the Major North Slope Producers to refrain from partnering with TC Alaska or contracting with the Project. — will produce positive rett stakeholders ¢ Producers likely to commit gas ¢ TC Alaska can finance and build the project e “Contingent Liability” not likely to impede progress Cost risks are not unique to TC Alaska and TC laska has reasonable plan to manage the n * Producer Project (Denali) ¢ LNG Options ° No certainty on project schedule ¢ Undefined tariff terms — Example, 50/50 debt to equity increases the tariff by $1 compared to 75/25, costing the state over $8 billion in NPV ¢ Undefined state fiscal concessions needed for Denali — SGDA concessions worth over $10 billion No Certainty on Expansion Provisions -Stifles North Slope basin development ou ¢ Higher return expectation than pip e Experience constructing and operating gas pip ¢ TAPS record demonstrates incentives not consistent’ with state’s interests Producer pipeline can proceed concurrently with TC Alaska’s Project it, and build it without any additio: concessions ¢ State has significant interest in attracting Produce to commit gas to TC Alaska’s project — Expansion Provisions — Lowest reasonable tariff - Highest Netback tate Needs to Use Power of Competition to likelihood of success — Asian market price — LNG project costs and schedule — How LNG projects are developed — Potential hurdles for LNG projects Confirmed Asian market premium price Liquefaction plant costs create economic drag LNG does not provide time or cost savings Asian LNG does not provide “value added” — Entire project stream, from gas supply, to pipeline, to liquefaction, to tankers, to re- gasification, to gas sales must be negotiated and executed nearly simultaneously — Requires reserves certification — Expansions are more difficult because of size — Liquefaction plant is additional “open access” inch-point transport gas from Delta Junctio William Sound © LNG project will benefit from TC Alaska’s financial and technical abilities ¢ State will benefit from supplying gas to both LNG and North American markets Alaskans — Best Chance to Get a Pipeline — Expansion Provisions Provide best chance for Jo’ and long-term careers for Alaskans — Increases Alaskans opportunity of affordable energy — Maximizes state revenue - Alaska’s Project is Better for the State tha * Chapter 1-Introduction ¢ Chapter 2-Technical Background ¢ Chapter 3-TC Alaska Application © Chapter 4-LNG © Chapter 5-Producer Proposal 'e from delive © Clock will start June 3 when Findings al Determination submitted to presiding officer TransCanada Accomplished and Capable Plenary Session 2 TransCanada- Accomplished and Capable Likelihood of Success Alaska Gasline Determination Public Forum Wednesday May 28, 2008 Overview ¢ NPV’s are very attractive and will be addressed in detail tomorrow ¢ Likelihood of Success (LOS) Criteria defined by Section 170 of AGIA ¢ Is TransCanada the right party to get the job done and can they do it? * Discussion today follows our analysis — Technical — Commercial — Financial — Legal Plenary Session 2 TransCanada- Accomplished and Capable Technical LOS Assessment William H. Sparger Alaska Gasline Determination Public Forum Wednesday May 28, 2008 Likelihood of Success “The assessment of the Technical Team is that TransCanada has a “reasonable” to “high” likelihood of success in the execution of the Alaska Pipeline Project in accordance with their application” Pipeline — Strongly Positive GTP — No Impact/Neutral No negative LOS ratings Reasonableness, Specificity & Feasibility Detailed, well thought out project scope and execution plan Proven conventional design, technology and materials Route generally follows “corridors” Reasonable cost and schedule estimates Excellent project management and control systems Organization, Experience & Ability One of the largest natural gas pipeline companies in North America — over 36,000 miles of pipeline Have installed over 7000 miles of pipeline and 3 million compression horsepower since 1990 Staff and systems in place for large pipeline projects Currently in execution phase of the Keystone Project — 2100 mi oil pipeline in US and Canada Excellent pipeline industry reputation Leader in technical innovation Record of Performance ¢ 1990-2000 was TransCanada’s largest growth decade — Total actual capital costs less than 1% of budget — Generally ready for service on or before the scheduled dates — no substantial schedule setbacks ¢ No identified major cost or schedule overruns Likelihood of Success “The assessment of the Technical Team is that TransCanada has a “reasonable” to “high” likelihood of success in the execution of the Alaska Pipeline Project in accordance with their application” They are “Fit, Willing and Able” Plenary Session 2 TransCanada- Accomplished and Capable Commercial LOS Assessment Greg W. Hopper Alaska Gasline Determination Public Forum Wednesday May 28, 2008 Summary Comments ¢ The market is supportive of the project. * TransCanada’s proposal is a reasonable opening offer. ¢ TransCanada is a credible developer. The Market Is Supportive of the Project * Market projections clearly reflect a need for the gas supplies, starting in 2019. * Long-run price forecast are sufficient to support commitments to the pipeline project. ¢ Alaskan gas line shipper-merchants will have access to markets across North America. Alaskan Supplies are an Integral Part of North America’s Future Supply 70 ddd ” VIL: YW ‘Supply / Demand gap assumed to be filled by Alaskan Gas 2005 2007 2009 2011 2013 «2015 «= 2017—- 2019) 2021 2023 «2025 «492027 #82029 (= Lower 48 Production @——US NetPipeline imports @ZaUS NetLNG Import — Lower 48 Consumption TransCanada’s proposal is a reasonable opening offer ¢ Shippers will enjoy a low cost / low risk option to participate in TransCanada’s planned open season. * The proposal provides an informative framework and the flexibility for shippers to negotiate most aspects of the project. ¢ Risk allocation between shippers and the pipeline is consistent with or better than industry norms. Shippers Have the Ability to Negotiate Reasonable Profit Margins = Nominal AECO Tanff ——WoodMac AECO Price Forecast ——~ EIA AECO Price Forecast —— BV Base BY P10 ——BV P90 $25.00 }o------- eee $45.00 $40.00 $35.00 $30.00 $20.00 4---------e-reseeseeeeceecereeteneeneetenttss $15.00) f-22s2sss $10.00 $5.00 +, 2020 2024 2028 2032 2036 2040 2044 EIA: AEO 2008, WoodMac, and B&V Analysis TransCanada is a Credible Developer * TransCanada has the scope and scale of expertise as demonstrated in its other operations. * The potential for merging with the Denali project is typical of the pipeline industry’s development process. — Denali sponsors may distribute more tangible information about their project in the future. ¢ The proposal preserves future flexibility to support LNG exports, if warranted. TransCanada’s Alaska Gas Line will Complement Their Vast Network Existing Pipeline System ¢ TransCanada’s network of more than 36,500 miles of wholly owned pipeline — 11.1 bcf/d current deliveries * Recent expansions include 6500 miles of large diameter pipe, almost 3.2 million hp of compression, and 376 custody transfer meter facilities Plenary Session 2 TransCanada- Accomplished and Capable Financial LOS Assessment Bruce Schwartz and Ray Strong Alaska Gasline Determination Public Forum Wednesday May 28, 2008 How Will the Markets Assess TransCanada’s Financial Strength? — Lenders, ratings analysts, and fixed-income investors will review: . What can go wrong with the Project and within TransCanada’s core businesses? How will TransCanada finance their equity contribution? Will TransCanada be required to make additional capital contributions if the pipeline project experiences delays or cost overruns? Should analysis consolidate or not consolidate the project debt onto TransCanada’s books? Would TransCanada ever really “walk away” either during construction or after operations commence? Overall Credit Assessment: Rate to the trough (i.e., the point in time during construction when financial pressure is highest), likely post-construction profile, or somewhere in between? Current Moody’s and S&P Ratings for TransCanada Comparables? MidAmerican Kinder Morgan TransCanada Enbridge Energy Holdings SpectraEnergy Energy Partners Corporate Ratings _ ABIA- Baat/A- Baa t/A- Baa 1/BBB+ Baa2/BBB Outlook Negative/Stable Stable/Stable Stable/Stable Stable/Stable Stable/Stable Assets ($ millions) $30,717 $20,161 $39,216 $22,970 $15,178 Revenues 8,941 12,072 12,376 4,742 9,218 EBITDA 3,888 1,768 3,838 1,965 1,732 Net Income 1,239 716 1,189 957 590 DebvEBITDA? 4.0x 6.0x 5.2 48x 4x Debt/Cap* 59% 64% 67% 55% 61% EB!T/interest® 2.7x 2.1x 21x 2.3x 3.0x RCF/Debt 14% 9% 12% 12% 4% ' Credit statistics as of 12/31/07 from Capital 10 2 Lower is better 2 Higher is better Goldman Sachs Analyzed Four Alternative Approaches for TransCanada to Absorb Project Costs * Case 1 - “Base Case”: Assumes that the costs related to TransCanada are equal to its equity investment only and are being financed 100% with debt. The equity method of consolidation accounting is used (i.e., revenues, costs, assets, debt, and cash flows at the Alaska pipeline level are not consolidated; only net income available to TransCanada is consolidated) and cash payments to TransCanada are equal to the amount distributed to equity holders and is recorded as other income. * Case 2- “Fully Loaded”: Assumes that TransCanada fully consolidates the project and all costs are on its balance sheet, financed 100% with debt. All income and expenses of the project are recorded on TransCanada’s financial statements. * Case 3 — “50% JV Sell Down”: Assumes TransCanada splits 50% of the project with a third party and proportional accounting is used. As such, 50% of the project’s income and expenses are recorded on TransCanada’s financial statements. * Case 4- “Base with 25% Stock Financing”: Uses the same methodology as Case 1, only instead of funding the costs with 100% debt, 25% of its capital commitment to the pipeline during years 2014-2017 are being financed through common equity issuance. Goldman Sachs’ Review of TransCanada Key Findings * TransCanada has very stable, durable, and free cash flow generative businesses; * TransCanada’s business and financial risk profiles substantially improve if the Project is completed; * Rating agency concerns about additional capital calls on TransCanada during construction likely would be alleviated by the cost overrun facility; * If capital calls are required because costs escalate, TransCanada should have the ability to contribute additional capital (if needed); * TransCanada generates substantial free cash flow at the corporate level that should enable the Company to potentially debt-finance the majority of its equity contribution; * If TransCanada finances its capital contribution to the pipeline entirely with debt, ratings downgrades are possible (all else being equal) but maintenance of investment-grade ratings is expected; and * Maintenance of current ratings is possible if TransCanada takes actions to fortify its financial strength in anticipation of the project and ensures the agencies view the pipeline as having a high probability of success. 5/27/2008 1:39 PM Disclaimers * The analysis and conclusions set forth herein are based on economic, financial, political, market and other conditions as they exist and can be evaluated on the date hereof, and we have not undertaken to reaffirm or revise our findings or otherwise comment upon any conditions or events occurring after the date hereof. Our analysis and conclusions also involve numerous assumptions and uncertainties, many of which cannot be verified or ascertained presently. Goldman Sachs does not provide accounting, tax or legal advice, and we make no representation as to the appropriateness or adequacy of the information contained herein or our procedures for, and express no view as to, the tax, accounting or legal treatment of any matter. * Goldman Sachs and its affiliates, officers, directors, and employees, including persons involved in the preparation or issuance of this material, may from time to time have “long" or "short" positions in, and buy or sell, the securities, derivatives (including options) or other financial products thereof, of entities mentioned herein. In addition, Goldman Sachs and/or its affiliates may have served as an advisor, manager or co-manager of a public offering of securities by any such entity and/or for any other securities- or asset-related transaction. Further information regarding this material may be obtained upon request. * This material provided by Goldman Sachs is exclusively for the information of the Commissioners of the State of Alaska Departments of Natural Resources and Revenue and senior management of the State. In addition, unless indicated otherwise, further use by the State of information and data contained herein sourced to third parties would require approval from such third parties given directly to the State. 5/27/2008 1:39 PM Plenary Session 2 TransCanada- Accomplished and Capable Legal LOS Assessment Don Shepler and Ken Minesinger Alaska Gasline Determination Public Forum Wednesday May 28, 2008 Withdrawn Partners Issue * Some parties claim that TransCanada faces a potential liability to former partners of Alaska Northwest Natural Gas Transmission Co. (“ANNGTC”) Claims are Very Weak FERC would not let ANNGTC attempt to recover in rates $10 Billion related to withdrawn partners’ claims. Partnership agreement does not require any payment that would cause “undue hardship” to remaining partnership owners. No “non-compete” clause in partnership agreement $10 Billion claim would make project uneconomic for any TransCanada entity— precluding competition to build the line — Courts look with disfavor on interpretations of contracts that restrict competition. Former partners may have waived claims by participating in other Alaskan pipeline projects and not raising the issue in public comments Issue can be resolved on TC Alaska’s timeline The issue (if any) can be resolved through potentially many avenues. — FERC declaratory order on rate inclusion; — Court declaratory order on interpretation of partnership agreement; — Other Resolution can be achieved on timeline consistent with TC Alaska proposal Canadian Issues * State Retained Canadian Legal Counsel to Advise on Canadian Regulatory and ROW Issues ¢ Bennett Jones LLP advised on several unique Canadian issues. ¢ Conclusions: — Regulatory issues and ROW issues may delay the project but are not “show-stoppers.” Northern Pipeline Act ¢ Parties have questioned whether the Northern Pipeline Act (“NPA”) Certificates held by Foothills remain valid — Stale and dated? ¢ Bennett Jones advises NPA Certificates probably still valid, provided regulators agree that the Project proposed by TC Alaska fits within the parameters of the NPA and Certificates. ¢ Issue is one of timing * Time for resolution included in State’s evaluation. Alberta Facilities Parties have claimed that TC Alaska’s proposal that Alaska gas flow onto its Alberta System is inappropriate. Bennett Jones concludes claims raise legitimate issues that may be resolved by U.S. and Canadian regulators and sophisticated shippers in negotiations. Issue is one of timing Time for resolution included in State’s evaluation. First Nations/ROW issues Canadian government and TC Alaska will have duty to “consult” with First Nations. Duty is greater than in 1970s when NPA was enacted. TC Alaska recognizes duty and has substantial history of such consultations Issue will affect any pipeline through Canada. Timing included in State’s evaluation. Possible New Policy in Canada * Press reports and public comments of Canadian officials’ statements indicate Canada will adopt policies to expedite and facilitate any Alaskan pipeline project based on bad experience with MacKenzie. * Public comments filed by the Canadian Minister of Natural Resources indicate Canadian Government recognizes the need for efficient review processes to match the U.S. timeline TransCanada Alaska Project: From Costs and Schedule to Tariffs Sheraton Hotel, Anchorage May 28-30, 2008 Plenary Session 3 TC egska Project-Costs/Schedule/T: ariffs AGIA Apalyele Teehalem lenny. —— Why Cost/Schedule Ranges? ¢ Single point estimates for large complex projects may not be realistic or achievable ¢ Understanding and applying the ranges in which the costs and schedule durations are likely to fall will result in a much more realistic and accurate analysis Analysis Methodology * Develop subproject/activity estimates for cost and schedule — Based on 2007 dollars (removes uncertain cost escalation risk from the base analysis and) — Cost escalation is applied later in the NPV analysis as a sensitivity Analysis Methodology ¢ Apply a combination of expert judgment of ranges/distributions and probabilistic analysis — Project scope risk is addressed by ranging of costs and schedule duration ¢ Perform Monte Carlo simulation, which is a well proven and long accepted method ¢ Provide cost and time-risk probability distributions for NPV analysis Cost and Schedule Distributions ¢ Developing Cost-Risk Probability Distribution — Define the Cost-Risk Model — Best case and Worst case — Calculate Cost-Risk Distribution ¢ Developing Time-Risk Probability Distribution — Define the Time-Risk Model — Best case and Worst case — Calculate Time-Risk Distribution AGIA Example DRAFT. Work-in-Progress: Cost-Risk Profile Pipeline Example 100% 90% 80% 70% 60% & 50% 40% 30% 20% 10% 0% 7p00 DRAFT: Work-in-Progess: AGIA Example ef 100% Binding Open 90% GTP Second Gas & Proj. Second Gas Season Finish I 80% (45 befa) 70% GTP First Gas & 60% Project First Gas 25 bi Development e = 50% Phase Finish ‘AK Pipeline & 40% ~ Yukon-BC Pipeline Finish (4.5 befd) 30% Issuance ‘Start of 20% \AK Pipeline, Yukon- BC Pipeline >P 10% 0% 010208 01/01/09 01/01 10 01/0111 0100212 010113 01/014 0101/15 010216 0101/7 O1.01N8 1/01/19 010220 01101721 0101/22 0101123 Costs/Schedule Analysis-Pipeline Costs ¢ Started with review of TransCanada cost breakdown by subproject ¢ Prepared independent cost estimates using same subproject breakdown ¢ Selected final base cost for analysis and ranging ¢ Established best/worse case ranges ¢ Established other Miscellaneous Costs Costs/Schedule Analysis-Pipeline Schedule e Started with review of TransCanada schedule by subproject e Prepared independent schedule and activity logic e Established final schedule for ranging e Established best/worse case schedule activity durations Costs/Schedule Analysis-Gas Treatment Plant Costs ¢ Started with review of TransCanada cost breakdown by subproject ¢ Prepared independent cost estimates using same subproject breakdown * Established best/worse case ranges ¢ Established other Miscellaneous Costs Costs/Schedule Analysis-Gas Treatment Plant Schedule e Started with review of TransCanada schedule ¢ Prepared independent schedule and activity logic e Established final schedule for ranging e Established best/worse case schedule activity durations AGIA TransCanada Application - Base Case TransCanada base cost estimate is $25.1B AGIA TransCanada Application - Base Case Risk N le for Base Case 4 f 00% - nce a Season Finish r GTP Second Gas & 20% Proj. Second Gas t (45 befd) 70% -- Sie eels pte cb ad dead --}--]-----Hf__1 “GTP Fst Ges @ + eet 0% Project First Gas (2.25 betd) P= -[ AK Pipeline & apocrenfeeteesfeotee 40% Yukon-BC Pipeline Lt Finish (4.5 betd) 20% CPCN Issuance + Start of : 2% |AK Pipeline, Yukon-}— 2 Bhan ea en ef baw danab abe denne ~-+--4 f+ --4| BC Pipeline & GTP }-:-- fF J -.} 4p annonfendenepanten 10% o% 1208 «110 IND 2 VID he HANS 1 Tet 11 uaa TransCanada adjusted first gas schedule is 14/18 Details of costs/schedule to be discussed in Breakout Sessions 3 &4 Net Present Value (NPV) Analysis and Results vd BUILDING A WORLD OF DIFFERENCE BLACK & VEATCH Net Present Value (NPV) Analysis Plenary Session No. 4 Alaska Gasline Determination Public Forum May 28 — May 30, 2008 Ewe OU Key Conclusions 4.5 Bcf/d TransCanada Proposal has Positive NPV Benefits to All Stakeholders NPV Results are Sensitive to Many Factors with Commodity Prices being the Most Significant e Producer NPV Remains Positive with Low Market Price Assumptions Production from Proven Reserves Drive Positive Stakeholder NPV Smaller Initial Pipeline Capacity and Contract Period for Smaller Pipeline Configurations Reduce Reserve Risk Relative to the Proposal Base Case Tariffs for Smaller Pipeline Configurations Increase by 13% to 21% Relative to the 4.5 Bcf/d Proposal Base Case NPV for Key Stakeholders Indicates Positive NPV for the Conservative Base Case NPV Decrease for the 3.5 Bcf/d Low Volume Sensitivity Case is Steeper 5/27/2008 = Ere e600 What is Net Present Value? Present Value of $100 Cash Flow in Future Requires an estimate of Discount Rate = 5% cash flows - capital expenditure, operating expenses and revenue e Requires an assumption about the Value of $100 in the future 8 8 40.00 | discount rate (or | 20.00 | investment return) | 0.00 | e A future $ is worth less 123 4567 8 9 101112131415 16 17 181920 thana.current $ nia NPV basis ‘BEv-3 5127/2008 = BLACK & VEATCH Impact of Discount Rates e The higher the discount Present Value of $100 Cash Flow in Future Years rate, the less a future $ Sensitivity to Discount Rate is worth today » om e Alternative discount 2 100.00 rates were required per 2 AGIA = 8000 s e Discount rates vary by 3 60.00 stakeholder: 3 40.00 __5% DiscountRate e State -5% ¢ —— 8% Discount Rate 2 20.00) | soutind Giscourniiats e TransCanada — F400 15% Discount Rate 8.8% 123 4 5 6 7 8 9 1011 12 13 14 15 16 17 18 19 20 . Producers — 10% and 15% Bey-4 5/27/2008 | eee AN Impact of the Gasline: Cash flows and NPV calculated are the difference between oil+gas and oil only operations. Oil + Gas $$ Oil Only $ Cash Flows from Gas $ i} ERENCE® ele Se ie] The NPV Modeling Approach Utilized by Black & Veatch ee ence eee ee ed Capra | Timing! ' 1 Scheduling ; ft 1 4 Meee ewe See te LT BRV-6 5/27/2008 Cee 673.107] Capex ] OpEx Divisible Ups Productio mane -| waver] - [remeczoom | ‘State Federal Producer Shae Share ‘State Corpotate income Tax [__pev-7 : se E 5/27/2008 a ite VEATCH Model Inputs: General Base Case Inputs e Pipeline remains full throughout study period e Proposal Base Case: e Contract life of 25 years; Depreciable life, for ratemaking purposes, of 25 years e Conservative Base Case & Low Volume Sensitivity Case: e Contract life of 20 years; Depreciable life, for ratemaking purposes, of 20 years e Pipeline interest rate of 7.06% (Goldman Sachs) e Cost and price escalation (converting real $’s to nominal): e CapEx = 4% © OpEx = 3% e Price = 2.5% e Expected in-service date of 6/2020 BBY. 8 5/27/2008 . BLACK & VEATCH Project Costs Based on the Technical Team’s Analysis: Distribution of Current Dollar Costs AGIA TransCanada Application - Base Case Cost-Risk Prot Ba 4 DRAFT: Wortin- Progress, pe Canes: 90 tend 5 335 3 3 3 F 3 3 Base (4.50) Cost 5 integrated Project 080321.x18 Total Chat Printed: 3119/2008 | BLACK & VEATCH Price Assumptions Utilized (Detailed Review in Gas Pricing in North America Breakout Session) $4500 7— Wood Mackenzie AECO Forecast $4000 1 Uameanenes | mittiidasrnsnamnsreninsigl ——BV Base Case Forecast $35.00 eveo |) | | See $3000 | —8VP80 Seal 2 = Historical 2007 AECO Price with Inflation 2 $2500 i $2000 z $1500 DD cerca eee lO secennsteenl i fer ere ce el lett telnet delehlaeeceleoh ¢ + 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 5/27/2008 a eee ee eT Production Assumptions: 4.5 Bcf/d Proposal Base Case OPBUState Existing @ Point Thompsom G State - Yet-to-Find G Fed-Onshore - 25 Yet-to-find production assumes a 50/50 mix of 15 State/Fed Onshore reflecting ratio of available 10 reserves BD pe 20 os oo 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 __Bay-11 = BLACK & VEATCH Positive Netbacks Are Expected Under All Price Forecasts $45.00 @™ Nominal AECO Tanff Wood Mackenzie AECOPrice Forecast —— EIA AECO Price Forecast ——BV Base BYP10 —BV P90 $40.00 $3500 fo nace eeetttte tte e tect ete eet tygeesceeeeeeee $30.00 $25.00 $20.00 Nominal $MMBtu $15.00 $10.00 $5.00 2020 2024 2028 2032 2036 2040 2044 BLACK & VEATCH Positive Netbacks Produce Positive Cash Flows for All Stakeholders $55.0 a Be mState $45.0 7° paggregate Producers Canadian Govemment £ $35.0 7 U.S. Govemment 2 250 4. 2TransCanadg a “ BAW) ht teach etetersctrt ersten $5.0 foe eee ($5.0) T + T 1 & 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2008 2010 2012 2014 2016 20 Capital investment by TransCanada to construct the project. a is y c RE E ie Nee RN ie | Expected State of Alaska NPV, is $66.1 billion $300 g = a a Discount Rate: cash 2% 5% 6% 8% Flow ee BLACK & VEATCH Price is a Key Driver to Variations in the NPV, to the State of Alaska Base Case cc Wood CommodityPrices P10 P90 Modena Cost Escalation % Capen 5% Ope 2% Capes, 2 Opes sh Upstream Capital Costs: 100% ease 50% Decrease Base Care TransCanada Capkal Cost mem corns Pipeline interest Rate 7.08% TransCanada Schedule Pan P10 Bare Care i t Peus0 Production Scenarios PeU 3 SBCFidt No PT eet $2000 «$600 «S80 $000 $1200 $400 State NPV, ($Billion 2008) =] BLACK & VEATCH The impact from price uncertainty swamps estimated capital cost and schedule uncertainty. 100% ictal | 4.5 RECO | Schedule-Cost Uncertainty } | — -4.5 AECOw/ only TC Schedule- | Cost Uncertainty | 60% fovenseeecoeee- 70% | = | z &% 3 0% | 2 | BY pom teeter ole Uncertainty analysis =|... | required the use of the lower BOG prssnessransegg cores fog onnene nee B&V forecasts. Results = [-------- indicate no likelihood for a negative NPV to the State. | 1006 penn enagfeannene nn 0% { 90 $60 $100 $150 $200 $250 $2008 Billions NPV; il ov RLD OF DIFFERE Price Scenarios Wood EIA2008 BVMean BVP10 NPV for the State is Expected to be Positive Under all a Cee Oyster BV P80 Like the State, NPV for the Producers is Ex Substantial under Base Case Assumptions $560) | Se $13.5 BNPVIO. @NPVI5 $12.0 $9.0 $6.0 $ Billions (2008) $3.0 $0.0 + Aggregate YTF Proven Reserves Producers i] Eee Ose pected to be Existing reserves provide the greatest amount of NPV benefit to the producers due to the low expected capital outlay required to flow into the Gasline. YTF NPV is understated due to the analysis life of 25 years. If the analysis is expanded to 35 years, YTF NPV improves to $3.9 billion at a 10% discount rate. 5127/2008 _ @ Eee 87 2.\0es Producer Sensitivity to Key Variables is Similar to the State Gene Senstnty rte sme i . i H Wood Commodity Prices {P10 POD Madeerzie i : , ; : Pree Com €seatation acme One ‘Upstream apal Costs BaweCae TransCanada Schedule: OmeCue Maan Capt ‘TransCanada C apital Cost Pipetine interest Rate ams : i rous0 : - PBU 3.5 BCF Ai, No PT Bora; PT ; : Bondone 15.0) + $5.0 $10.0 $15.0 $20.0 Producer NPV.o (SBillion 2008) = Ewe ise The producers have a very low likelihood for a negative NPV.,, from low prices, no likelihood from cost scope risk. 100% 4.5 AECOw’ Price and TC ‘Schedule-C ost Uncertainty —— ~4.5AECOw only TC Schedule- Cost Uncertainty 0% | 80% | 70% yo----~ ono | 60% f= | 50% Foon Uncertainty analysis | required the use of the lower | 0% Lessee Le) B&V forecasts. Results indicate less than a 5% 20% +--+ chance of a negative NPV to the Producer. 40% Probability (%) Chance of negative NPV 9 is ~5% | | | $10 SF $0 6 10 $15 $20 $25 $0 $6 $40 $2008 Billions NPV 49 i] Le Nee A Ni NPV for the Producers is Expected to be Positive Under all Price Scenarios Producer NPVis $250 —______—__—— Wood Mackercie EIA 2008 ] "Wood Mackenzie = GEIA2008 . 8 BVMean fs A ‘ ele eR ee] Project Cash Flows are Favorable if Built Today Real prices are shown (no inflation) against the projected tariff based on today’s capital costs (no inflation). Today’s AECO forward market is $9.62/MMBtu. (EEEEED 4 5 Case Tarif (Appromm ate Real) "Wood Mackenzie AE CO (Real) ————-BV AECO Base Real) 8200 }---- BBV AECOP 90 (Real) —#—BVAECOP10 (Real) a 3 3 5 Gm Price (Real S/MMBtu) soo 2020 2022 2024-20 2028 2030 2320 203638 2040 2042 2044 Implications to YTF Producers NPV with Varying Upstream Capital Costs ie Ce 80s.) Aggregate Producers (65) __ Producer NPV. Producer NPV, $200 mBase Case Base Case 250% Decrease (G1GD) veo seoreersscreestcu 50% Decrease 2... 100% Increase $03 505 YTF Proven Reserves Aggregate YTF Proven Reserves Producers 30% % of YTF Gas Required to Fill Pipetine a x 0% 20% fo-------- 25 Years YTF Gas Required to Keep Pipeline Full under Different Contract Periods 25 Years 20 Years Contract Period = BLACK & VEATCH 020 Years 15 Years SS Ra RE PA Ba? Bene ana PO DUDE REDO A Ay PIS OI IEEE RAO SRS I PDS IY BAY PODS ee Nie ee Nie 2082 2044 @ Fed-Onshore 2030 2032 2034 2036 2033 240 4.0 Bcfid Case B State - Yetto-Find ions 2a 2028 Assumpt 0 PBU/State Existing Fi ind production Yet-to: assumes a 50/50 mix of State/Fed Onshore reflecting ratio of available reserves 224 Produced ion 2022 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 mmm 4.5 Case Transportation Cost ——45 Case Total Revenue ‘= * °45 Case Total Revenue - 0 YTF GAS Is 45 40 35 3.0 25 2.0 15 1.0 os 0.0 + 2 2 Q Q & & & @ (suogig §) 1s0D/enuercy $700 #00 7- E ° ra ho ov 2 — n ° a £ © S vo a ° 2 oD Oo 3 “x Ww 2 > a 2 — o o = ao ° - a Gas Product 3 . =) Ole Nie Production Assumptions: 3.5 Bcf/d Case 5.0 ia O PBUState Existing © State - Yet-to-Find GFed-Onshore --------- 4s 40 35 3.0 = 25 Yet-to-find production a assumes a 50/50 mix of 2.0 State/Fed Onshore reflecting 15 ratio of available reserves 1.0 Os - 0.0 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 _ Bey. 27 ss DS GT arenes SETA. ol a ‘ ete eA Niel Expected Tariffs from the North Slope to the AECO Market AECO Tariff $10.0 4.5 Befid 4.0Bcfld 3.5 Befld Nominal $/MMBtu a o Oo 4.5 Befid 4.0 Befld 3.5 Befid a Ee ee eR Niel TransCanada NPV,, is Significant under Proposed Terms and Base Case Assumptions TransCanada NPV¢.2 $10.0 45 Betld 4.0 Befid 3.5 Befld $8.0 $6.0 $4.0 $ Billions (2008) $2.0 $0.0 4.5 Befid 4.0 Befid 3.5 Befid i BLACK & VEATCH The State’s NPV, Project is Lower with Lower Project Capacity but Remains Significant State NPV, $80.0 $70.0 $60.0 $50.0 $40.0 $30.0 $ Billions (2008) $20.0 i] BLACK & VEATCH Producer NPV Shows a Similar Trend When Compared to the State and TransCanada Aggregate Producer NPVio $200 4 $180 $160 4 $140 4- $120 4- sio0 +- $80 +- $60 +- $40 +- $20 4.5 Betis 4.0 Bet 3.5 Betd 4.5 Betid 4.0 Beta 3.5 Betd Liquid Natural Gas (LNG) Analysis and Results LNG Price Overview May 2008 Presented by Rob Shepherd — Senior Associate Gas Strategies Consulting bY Key messages = Gas Markets Regional not Global = Spot LNG Market too thin to support new investment = Asian markets normally provide premium prices = Asia dependent on LNG = Prepared to pay some security premium to lock in volumes = Relativity to HH very volatile = Premium Limited by Spot LNG Movements = Which are Growing = Asian Prices Linked to Crude Oil = Each contract has its own price = Can only be revised at approx 5 year intervals = GS Scenarios based on likely market in 2015-2020 2 © Gas Strategies Consulting Asian contract prices normally sit above HH; market now more interconnected with greater volatility Asia markets provide higher prices *Asia dependent on LNG +Propared to pay some security premium to lack Relativity to HH um meee very volatile AES ILA BASE Te convergence *LNG can be —~ moved out of US -Asia— premium market “US — tow price i | | (not as easy as | Crude olf ave 1979-98 = $23/DbI $ off) * SRI PI Source’ Gas Strategies Consuking © Gas Strategies Consulting Asian Premium is limited by growing flexible supply nas = 2007 US supply 16 mtpa = 50 mtpa of new supply for US, UK under construction = Can potentially be diverted to Asia = US, UK Markets liquid = (Unlike Asia to US) = Shipping and contractual constraints Some Asian Premium will remain driven by security concerns © Gas Strategles Consulting Gas Strategies Scenarios - Base Case Scenario sees an easing in the tightness of supply Rising gas and LNG demand will continue Rate of growth depends on ' economic activity Main factor affecting price liegaankheehanais will be the availability of cumanieniine: acidic <csngasian supply a Scenarios primarily based Moderate easing of the current tight on differences of supply in market relation to demand Supply and demand balanced Pricing in different Continuation of long term contracts scenarios reflects sana 7 traditional formula experience of contract oe P = 0.1485 Oil($/bl) + 0.9 pricing over last 20 years Ramoval Gf=S—curve® Short term cargo prices vary according to current conditions 5S © Gas Strategies Consulting Valdez Netbacks from Scenario Prices, gives reduction in premium by $1/MMBtu Scenario Real Netback Prices © Gas Strategies Consulting | Ya 17 UU Public Forum : Sheraton Hotel, Anchorage May 28-30, 2008 Plenary Session 5 LNG Analysis and Results AGIA Analysis Technical Team LNG Cases Case 1a - 2.7 bcf/d to Valdez - 48”/42” pipeline Case 1b - 4.5 bcf/d to Valdez - 48/42” pipeline Case 1c —a 1.8 bcf/d expansion of Case 1a (to a total 4.5 bcf/d) after 5 years Case 2 - TransCanada’s Y line - 6.5 bcf/d to Delta Junction, 4.5 bcf/d to Alberta and 2.0 bcf/d to Valdez - 48” pipeline to Alberta and 30” pipeline to Valdez Case 2a — Same as Case 2, but the pipeline from Delta Junction to Valdez and the LNG plant are delayed 5 years Case 3 - 4.5 bcf/d to Valdez - 48” pipeline — PRIMARY COMPARATIVE CASE LNG Analysis Assumptions/Methodology LNG facility located at Valdez Pipeline route follows TAPS Rich gas case — no NGL extraction Volumes to Valdez = GTP outlet less pipeline fuel — no in-state delivery GTP and pipeline schedule and cost factored from TransCanada’s proposed project LNG Analysis Assumptions/Methodology LNG costs developed from factoring recent worldwide projects Miscellaneous and development phase costs factored from TransCanada application analysis All costs in 2007 dollars Start of LNG project one year later than TransCanada project Note - Cost/schedule details to be presented in Breakout Sessions 6 & 7 AGIA LNG Options Cast-Risk Profile for NG 2: 4.59 befd & ntegrated Project 40,000 60,000 Polential Dulcome SRulions AIGA LNG Options jel efor LNG? 100% Pipeline: GTP to Delta Jct 90% PERE FOURTHGASFLOW cow | Pipeline: Sere | DeltaJctto Valdez | 50 BCF | | THIRDGASFLOW Vi arene t 9.20 CFD) 60% ——, LNG Second Gas ‘CONDGAS! (2.20 BCFD) « (220 ew 50% T FIRSTGASFLOW ave 1.10 BCFD) 20% ; | #50 BCFO) LNG Fourth Gas 20% (4.40 BCFD) GTP First Gas 188) ene ———} LNG ThirdGas_ |}—j——-—— 8.30 BCFD) 0% tae tang a0 wnat tena 12e3 rane Liquid Natural Gas — Analysis and Results — Financing Plenary Session #5 May 30, 2008 For any Project Financing a Range of Risks are Assessed in Determining Credit Strength Project investors are relying on two sources or repayment — Strength of sponsor - ability to get project financed, constructed and operating effectively — Strength of projact economics - dependable revenue stream Project econornics are driven by — Cost and constructability — Quality of oftake credits and contracts — Underlying factors = Source and price of inputs = Markets for outputs = Operating risks Regardless of sector, these sreas are thoroughly reviewed by credit anslysts at rating agencies, bonds and investors Business & Legal Project Risks Framework Country Risks Force Majuere — Technology — Jurisdiction — Source of inputs Non performance — Construction — Choice of law — Facility - Construction — Inputs/Reserves — Form of Project — Buyer - Inputs — Market Company - Process — Operational — Contractual Agreements - Operations — Financial Structure Conceptually, the analysis of an overland gas pipeline and an LNG project are similar However, project and sector speciics dive overall analytic complexity Sn ooo 2 LNG Project Complexity For a successful project financing, every step in the chain has to be analyzed, largely or fully contracted, and controllable risks substantially mitigated m@ There are a range of incremental credit issues that would be analyzed in depth by potential LNG project developers, investors, and other participants — Country risk (shipper, buyer) — Currency risk — Liquefaction and regasification technology risk — Ship construction (or leasing), cost, timing, reliability — Shipping risks — weather, damage/spill, junsdiction issues — Gas supply - price and adequacy — Jones Act limitations — Safety and terrorism ® Commercial boundaries could be drawn any number of ways — Integrated project, supply to delivery — Different combinations Integrated Project era com ts ey ~- Analyzed by GS, BV and Gas Strategies Summary of Key Assumptions for the Alaska LNG Analysis ™ Capacity - Three capacity cases were developed, a4 5 ocf all LNG project which is most comparable to the Proposal Base Case; a 2.7 bef all LNG project; and a 2.0 bcf expansion LNG spur to Valdez @ Project Costs - Project costs estimates were developed for the portions of the LNG alternatives from gas treatment through and including the costs of shipping but excluding the cost of regasification ® LNG Prices — Natural gas prices in North America have a relationship to world oil prices but are also driven by natural gas market specific supply and demand factors = LNG Market Assumptions — — The market for LNG volumes is substantially more developed in Asia than in North America We assume that cargoes from any Alaska LNG plant will be principally sold to Asia buyers via long-term contracts — Asa result of the cost and complexity of LNG projects, the LNG market is in large part a long term contracted market, 1.6, an LNG developer will not build without long-term LNG sales contracts at volume and price levels which prode adequate revenues for amortization of costs, financings and to mest equity return targets interest Rates - We have assumed the same interest rate matrix for LNG- and Proposal-based cases @ Federal Loan Guarantee - Based on the Federal Loan Statute code, we have assumed no Federal Loan Guarantee will be available for any LNG related project costs @ Key Unknowns — Equity sponsor, gas purchaser, ship builderfoperator, finance pian framework. business structure of “project” gorgmen Summary of LNG Cases vs. Proposal Base Case LNG ¥ Line Proposal jon of 20 bet Guse Case BULNG 27 bef _—ANLNG 45bet 5 Totat* Sources of Funds Equity Tee750 15,400.0 76,0000 11,9500 Debt 38,568.4 37,038.3 8,468.9 26,8573 Interest Earnin 381.0 366.4 336.2 3825 Tota Sources of Funds — S584 385.6 $4805.1 22.1993, Uses of Funds Project Costs’ Development Costs 301.4 276.5 276.5 3660 Capital Expenditures 44,8351 40,838.7 64,7989 31,8435 Propary Taxes $33.6 1,823.0 2387.0 8521 ‘Subtotal 7588.8 QTR2 67,9824 Boris Other Costs Captatzes Irterest 7,305.3 9,728.5 14,7758 $1208 Debt Service Reserve Fund 8178 373.0 338.1 3781 Financing Fees 1,651.6 1,065.9 1,728.8 6223 Subtotal 9.8547 11174 188427 q1182 Total Uses of Funds ‘S5O248 33.955.6 G4905.1 39.189.8 ‘Statiaticn Ayerage Annual Dstt Service Fase S328 $5 0654 Sarie7 Average Debt Service Coverage 1.62 1.64 x 1.78% 1.09% Weighted Average Cost of Debt 705% 7.05% 718% 720% Weighted Average Cost of Capital 9.11% 7.95% 3.58% 9.96% Transportation Cost (per Dekathermr)'* $473 sara $946 $456 / $10.40 * Provicied by Black & Visach 2p 2025, ncludes Gas Treatment Part, al aopcable ppsine segments, andor Aberts Tartt, LNG Plart and shpong costs where applicable 2 Shipping conta provided by Oar Skategeo + Sources and uses in ation lo Proposal Base Case sources and uses. 5 Summary of Findings — Alaska LNG Options Are the LNG cases analyzed viable from a financing standpoint? | Magnitude of financing will prove quite challenging — Greater equity percentage will be required than qasline — same LNG projects are done with 100% equity — No Federal Guarantee — Will need constructioncompletion protection — Will need strong creditworthy contracts for - Gas sales to Project - Shipping - Regas casts - Gas purchase from Project | The fundamental underlying economics of an Alaska LNG project may provide the basis for a financeable project — Comparison of projected market gas prices vs. fully loaded costs — Strength of potential sponsors and gas purchasers — Business and financial arrangements ™@ fn order fo reach a more definitive conciusion, a great deal more needs fo be known — Without additional clarity regarding participants and business terms, i's hard reach conclusions about overall viability - Equity sponsor - Gas purchaser = Ship builder/operator - Finance plan framework - Business structure of "project a S— Disclaimers The analysis and conclusions set forth herein are based on economic, financial, political, market and other conditions as they exist and can be evaluated on the date hereof, and we have not undertaken to reaffirm or revise our findings or otherwise comment upon any conditions or events occurring after the date hereof. Our analysis and conclusions also involve numerous assumptions and uncertainties, many of which cannot be verified or ascertained presently. Goldman Sachs does not provide accounting, tax or legal advice, and we make no representation as to the appropriateness or adequacy of the information contained herein or our procedures for, and express no view as to, the tax, accounting or legal treatment of any matter. Goldman Sachs and its affiliates, officers, directors, and employees, including persons involved in the preparation or issuance of this material, may from time to time have “long” or “short” positions in, and buy or sell, the securities, denvatives (including optons) or other financial products thereof, of entities mentioned herein In addition, Goldman Sachs and/or \ts affiliates may have served as an advisor, manager or co- manager of a public offering of securities by any such entity and/or for any other securities- or asset-related transaction. Further information regarding this material may be obtained upon request. This material provided by Goldman Sachs is exclusively for the information of the Commissioners of the State of Alaska Departments of Natural Resources and Revenue and senior management of the State. In addition, unless indicated othemise, further use by the State of information and data contained herein sourced to third parties would require approval from such third parties given directly to the State re] BUILDING A WORLD OF DIFFERENCE® BLACK & Watian f . = ey 2. bh 4 Liquid Natural Gas (LNG) Analysis and Results Plenary Session #5 NPV Analysis Alaska Gasline Determination Public Forum May 28 to 30, 2008 Draft Work in Progress — Privileged and Confidential re] Ole tee Key Conclusions e LNG Projects Have Higher Capital Costs and Therefore Greater Risk than a Pipeline Project e Additional Fuel Shrinkage Compounds the Risk for a LNG Project e Price Remains the Primary Risk to a LNG Project e LNG Projects Have Positive NPVs with Base and High LNG Price Assumptions e LNG Project NPV are Overstated due to Expected In-Service Ramp-Up e The 4.5 Bcffd Proposal Base Case Project Produces a Higher NPV than a 4.5 Bef/d LNG Project e AHigh Oil to North American Gas Price Relationship is Required for an LNG Project to be Favorable Draft Work in Progress ~ Priviagad and Confidential 2. iO le ee ee) LNG Project Scenarios Evaluated 4.5 Befid Scenario e Project Capacity: 4.5 BCF/d e In-Service Date: 2022 e Capital Cost: $43.1 billion e Beginning Capacity: 4.5 Bcf/d to Alberta In-Service Date: 2022 Expansion Capacity: 2.0 Bcf/d to Valdez LNG In-Service Date: 2025 e Capital Cost: $48.6 billion Oraft Work in Progress ~ Privieged and Confidential re] ole ee ee LNG Project Scenarios Evaluated (continued) 2.7 BCF/d Scenario e Project Capacity: 2.7 Bcf/d e In-Service Date: 2022 e Capital Cost: $27.4 billion 2.7 Bcfid Expanded to 4.5 Bcfid Scenario Beginning Capacity: 2.7 BCF/d In-Service Date: 2022 Expansion Capacity: 1.8 BCF/d (Total 4.5 BCF/d) In-Service Date: 2025 Capital Cost: $39.7 billion @ 10 le te ie As Expected, Higher Capital Costs Create a Higher Tariff An overland tariff is 48% of a comparable LNG tariff Assumed an open with an overland project access project with cost of 73% of an LNG commercial terms project. ‘Gore Find GiiPiehe ‘GUN Fal similar to those yukon Alberta proposed by TransCanada A main difference is cost of debt as determined by tl i | Goldman Sachs Ys a 7. Liquefaction facility costs in Valdez are a primary driver to a higher tariff 45 Befd LNG Project 4.5 Getic Proposal Base Case Draft Work in Progress — Privieged and Confidential ie oe BLACK & VEATCH Expected LNG Tariffs for the LNG Project Configurations Considered Tariffs also include the cost to ship LNG from $15.0 7 —— ~ Valdez to markets in Asia. ZAK Pipeline Estimated cost in 2022 of [LNG Shippin $1.01/MMBtu. $120 pene $9.40 i x0 $6.0 2.7LNG 2.7LNG +1.8 45 LNG 4.5 AECO +2.0 LNG LNG Estimated Fuel Loss for LNG Projects = 0 lee BS Nie! Shrink when compared to an overland project is 7.6% greater. LNG Scenarios - Fuel Loss This results in an incremental m=GTP ZAK Pipeline COLNG Plant 17% 17% cost, when compared to an overland route, of roughly $0.40/MMBtu in 2022. 1 2.7 ING +18 45LNG 4,5AECO+2.0 LNG LNG Draft Work in Progress — Privileged and Confidentia’ | Ole ee Niel Estimated State NPV, is Substantially Positive for all LNG Project Configurations Considered Y-Line project produces a substantial NPV for the State. The 2.0 Bcf/d LNG expansion provides an additional $19.4 billion NPV, to the State. 2.7 Bet LNG 2.7 Betd LNG Expanded 45Bc#d LNG to 4. Beto LNG 65 Bcffe Y-Line =] lee BS ee] LNG Price Scenario Impacts on the State NPV, for the 4.5 Bcf/d LNG Project Base Case Price Low Case Price High Ca Draft Work in Progress — Privileged and Confidentia | LW le eB ee Producers Generate Positive NPV with the 4.5 Bcf/d LNG Project for Base and High Case Price Scenarios Aggregate Producer NPV,; Narre 45 wa Prost mw Base Case Price (Low Case Price aHighCase Price mBase CasePrice Low Case Price SHighCase Price $86 ($13) ae Base Case Price Low Case Pnce High Case Price Base Case Price Low Case Price High Case Pnce The Low Case LNG price scenario generates an expected negative NPV under base case assumptions. Occurrence is based on a surplus of supply into the Asian markets with North America becoming the market of last resort. @ BLACK & VEATCH Expected Margin between a LNG and Pipeline Project $300 4.5 Bef/d LNG Netback is HIGHER than a4 5 Bot/d Py $800 ee _ a 4 5 Bcf/d LNG Netback is LOWER than a 4 5 Bef/d Pipeline LNG High Case: Price Della NO Price - AECO) LNG Base Case Price Dota (LNG Price -AECO) — —LNO Low Case Price Dette (LC Price - AECO) —— Transporation Osta (LNG Tart Less Pipetine Tat plus incramerta Ful) "2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 | ele ees ee) Comparing Expected NPV, Results for the State between a LNG and a Pipeline Project Z7ECHDLNG 27BCHdLNG 4S BcfoLNG 4.0BcI 35 Betta Low Expanced 45 Conservative Volume Bete LNG Base Case Sermitly Case @ lee es ee) Understanding Implications to State NPV, from Cost and Schedule Uncertainty: 4.5 Bcf/d Pipeline vs. 4.5 Bcf/d LNG 100% e@ No price uncertainty com 4. TFS BCEALNG wih Base CaseLNG prices was included won f- nH Beli Propecas Besa Cove © LNG proj has 70% greater risk due to high z 00% foenenenedpene ace piclbsedudtendlf on | capital (and higher 2 ASAECO 451MG tariff a x} Ste MPVIE WEI 54g ug0 fo aris) & ws i © Essentially no probability that the LNG project will generate a NPV that is higher that an overland project under base case assumptions. De ne 10% 0% + $20 #10 wv m0 x0 0 40 60 $60 $70 80 $2008 Billions NPV, Draft Work in Progress ~ Prvieges and Confidentia ie} 1-10 le eB ee Comparing Expected NPV Results to the Producer between a LNG and a Pipeline Project Producer NPY... 4.5 LNG Project (13) a ($0.8) 458d A5BcMLNG 45BcMdLNG 45BcidLNG 45 Bet 45 Bcd ING 45 Bc LNG 45 Bcf LNG ProposalBase Base Case LowCase Price HighCase Proposal Base Ease Case Low Case Price High Case Price Case Price Price Case Price ie} le ee ie) Understanding Implications to Producer NPV,, from Cost and Schedule Uncertainty ——45 Bet d LNG with Base Case LNG prices ——45 Bet d Proposal Base Case Analysis indicates the probability of an LNG project generating a higher NPV is 0 under the Base Case LNG price and Wood Mackenzie price expectations. Probability (% * we $10 $12 city #16 19 $2008 Billions NPV Draft Work in Progress — Prvieged and Confidentia’ ie ele Bs ee) Current Market Relationship between Oil and Gas Prices is Substantially Higher than Historical Average Oil and gas forward markets show that the relationship will return to average levels. Wood Mackenzie is forecasting a much quicker return than the forward markets. 5 3 ——— Current F onward Market for WIIOiIPrice to Henry Hud Gas Price (S$/EBL vs S/MMBtu) ———Wood Mackenzie Forecast for WT! Cil Price to Henry Hub Gas Price (SEL vs §/VMBtu) = = = Historical Average WTI Oil Price to Henry Hub Gas Price Ratio ($/BEL to SMIVEWu) Nominal 08 to Gas Price Ratie (} BBL to $ MMBu) 2006 2011 2014 «2017 2020 M23 2026 2029 2032 235 238 2041 wes | ie lee BS ee] Sensitivity Analysis of Different Oil to Gas Price Ratios e Analysis focused on the impact of a sustained mmm Base Case Doita (Aon LNG - AECO) high oil prices ——Scenanio (Oilto Gas R atio 8) Deka (Avian LNO - AECO) comer sehen apersoe Assumed the Base Case ‘Sconmio (Otto Gee Rac 11) Det (Aan LNG - AECO) LNG price scenario. Note that Gas Strategies (plus others) do not expect permanent separation of Asian LNG prices from North America prices Generated oil prices based off of the assumed ratio oil to gas ration and the Wood Mackenzie base case projections for Henry Hub 2020 2022 202 2026 2028 20% 2032 034 2036 2038 2040 2042 2044 ee Ole eB eT Implications to LNG Project NPV from High Oil Prices e High oil prices must be maintained in order for LNG project NPV to be greater than an overland route « Based on Base Case LNG price assumptions e Results assuming a High Case LNG price show that ratios must remain above historical levels: e State 9 to 1 or greater « Producer 10 to 1 or 11 to 1 depending in discount rate High Oil Price Results with the Base Case LNG Price Scenario U.S, Government Producer NPVs NPVio ($184) 9 to 1 Oilto Gas Ratio ($4.4) 10 to 1 Oilto Gas Ratio 11 to 1 Oilto Gas Ratio Is AGIA worth $500 Million? 9-d ls AGIA Worth $500 Million? Alaska Gasline Determination Public Forum May 30, 2008 Why $500 million? State investment creates urgency — Since November 2007, two separate producer project announcements State investment buys progress — Enforceable commitments that add value and move the project forward * Licensee must provide and commit to project timeline * Licensee must push beyond open season FERC State investment buys provisions — Tariff rates (70/30 D/E) — Access — Expansion — Reduced project cost @ @ ‘ Why $500 million? ¢ State investment creates urgency — Since November 2007, two separate producer project announcements — Strong bargaining position for future discussions — Avoids repeating the mistakes of SGDA * Over $10 Billion in concessions ¢ No enforceable timeline ¢ No expansion provisions * No commitment to D/E ratio Why $500 million? ¢ State investment buys progress — Not a subsidy * Quid pro quo, “Something for something” ¢ Must commit to project timeline * Must push beyond open season regardless of outcome * Delay costs the state — Intrinsic value ~ deferred revenue from gas commercialization — Extrinsic value * weakened bargaining position @ @ ® Why $500 million? ¢ State investment buys provisions — Tariff rates * (70/30 Debt-to-Equity Ratio) means lower cost transportation * Distance-sensitive rates allow for lower cost energy for Alaskans — Access * Periodic solicitation * Required action with sufficient interest and commitment — Expansion * Rolled-in rates create a level playing field: everyone pays the same rate for the same service * Rolled-in rates have proven to be key to unlocking frontier basins * 15% cap on roll-in rate increase protects anchor shippers from unreasonable rate increases — $500 million credit to rate base pays for itself in increased future revenues BREAKOUT SESSIONS Analysis of Project Costs and Tariffs Commercial Keys to LNG Cost Overrun Risk: Sources and Management Economics of Undiscovered Reserves Employment on the Gasline Project Evaluating TransCanada’s Commercial and Tariff Terms Financing LNG Projects zo9™moo w > Fiscal System Risk Gas Pricing in North America - In-State Energy Is TransCanada Potentially Liable to its Former Partners? Legal and Political Factors Affecting Producer Participation in a TransCanada Project LNG Pricing in Asia LNG Project Costs Natural Gas Exploration Potential in the Alaskan Arctic Pipeline Expansions Pipeline Negotiations and the Role of FERC Pipeline Project Finance Point Thomson: Resources, Availability, and Effect on Project Economics Price Risk and Project Returns cHwMpprwroOZzESr RK Prospects for an Alaska LNG Export Project Analysis of Project Costs and Tariffs “Alaska Gasline Determinat Public Forum Sheraton Hotel, Anchorage May 28-30, 2008 4.5 bcf/d Base Case - Technical Team Input Cost *Development *GTP *Alaska Pipeline eCanadian Pipeline «Integrated Project *Miscellaneous Schedule *Subprojects Integrated Project Spend Curves (cash flow) AGIA TransCanada Application - Base Case Cost Risk Profile for Base 4.50 bet AGIA TransCanada Application - Base Case 14,000 9.000 o900 14,000 AGIA TransCanada Application - Base Case Risk Pr for Base Case: 4.5 f Yukon.AC Pipeline AGIA TransCanada Application - Base Case 4 f Miscellaneous Costs - Base Cases ¢ Line Pack 23,682 mmcf ¢ Fuel — Pipeline 116 mmcf/d —GTP 240 mmcf/d * O&M —PL- AK $66 million/Yr —PL- Can $85 million/yr —GTP $130 million/yr * Escalation -—O&M 3.0%/yr — CAPEX 4.0%/yr AGIA TransCanada Application - Base Case me-Risk Model Profile for Base Case: 4.50 betd (Base Case) integrated Project 40% 2% + 20% eel : 10% 4 + 4 4 ‘ y t om wes NUH wind td WB ane WHT we qr wm wits ‘Spend Curve for Development Spend Curve'tor Execution ToT smo “ > 7 % ae 0 5 7 0 to ; So 20 2 29 «0 0 20 20 20 0 10 09 - ° ofp DD oD DO DO D © ° 0 © » © 5 0 7% © © 100 soTime Time Commercial Keys to LNG Commercial Keys to LNG May 2008 Presented by Rob Shepherd — Senior Associate Gas Strategies Consulting Putting an LNG chain together is complex, it varies by market and is particularly difficult in Asia = Gas is not oil Oil is a truly global commodity in which demand can be assumed - price varies Projects easy to launch on this basis Gas is more costly to transport and more rigidly fixed to regional markets — often with a single buyer Assuring demand means securing a long term buyer And then building the whole delivery chain to the specific buyer . The US gas market is different from others = US gas market is very similarly to the global oil market — volume is assured, price varies = New development relatively straightforward = LNG is very challenging- especially into Asia Pacific markets = Costs are high, requiring large reserves and a long period of operation to justify investments All elements of the chain need to be connected with legal agreements to ensure the LNG once produced will be sold over the life of the project (ca. 25 years) The scale of projects usually means several companies will be involved (plus governments). Getting and retaining alignment and negotiating all agreements is a major challenge. Many projects fail. The spot market is a small part of the LNG industry, not liquid and not a basis for large scale investments © Gas Strategies Consulting The gas chain is very different from the oil Oil has high energy density Liquid can be easily stored and cheap to transport long distances Has a low cost delivery chain Oil's has produced a global liquid traded market Gas has low energy density Gas is much more costly to transport and store than oil Fixed links from field to Distribution market and often single b ial cccciomi Buyer and seller dependent on each other LNG improves energy densif but at a cost © Gas Strategies Consulting US Gas market is very different compared to the “ai Asian LNG market = Competitive, liquid, traded market US market liquid — Henry Hub (HH) This liquidity assures gas will be consumed Alternative transport routes More like oil = Actual or de facto monopolies, price control Fixed routes to specific buyers Seller depends on buyer and vice versa Therefore LT contracts to reduce offtake risk and specify price (oil linked) = Chain put in place before delivery © Gas Strategies Consulting The characteristics of the Asian markets make aa’ Commercially contracting LNG different to the US LNG’s Share of Overall Gas Consumption Selection of Asian LNG spot trades against LT Contracts eos BB e 882888 Percentage of gas consumed SF LSS we & eo vee +o = = a = Leading Asian markets depend on LNG unlike the US = Asian markets require security of supply = The illiquidity of Asian markets means you need a sound buyer and assurance that the market can consume the gas = The spot market is active but represents a small part of the total = And suffers liquidity crises = The spot market can not be relied upon to secure large projects = Spot prices are short term responses to specific conditions. Prices are generally higher than long term contracts © Gas Strategies Consulting Only 7.4% of world gas trade is LNG - Qatar, Malaysia and Indonesia dominate LNG supplies Trade of global gas Line 7.4% Pipeline Trade 19.1% LNG Supply by Country Qatar 17.1% Australia Indigenous 35% Mataysia 12.9% Alm Dhvabi_/ 39% 10.9% |_E. Gano 0.6% 4.0% Alaska nyt 0.5% 9.5% = Intemational Trade limited by cost of transport = No global gas market — unlike oil = Regional markets and regional pricing = LNG provides some limited interconnection Source: Gas Strategies Consuking © Gas Strategies Consulting Commercial contracts critical for viability of LNG chain to ensure financing and construction Construct Finance ey All elements of chain need to be connected with legal agreements to ensure the LNG produced will be sold over the life of the project (ca. 25 years) to support investment risk = Before finance can be raised = Before construction starts Makes LNG development complex = Contracts inflexible = Liable to delays © Gas Strategies Consulting Scale of projects sees a number of companies involved, as would be the case for Alaskan LNG campy conpay® conpaye company X% i % p% \ Q Tl ‘<eeemaies x wef \y % P %f/ Q LNG Sales CompanyA CompanyB CompanyC CompanyD The scale of projects usually means several companies will be involved (plus governments) Getting and retaining alignment and negotiating all agreements is a major challenge Concer to restrict project risks drives large companies to want to maintain control Accommodating future new gas suppliers is not easy — needs careful structuring At best new supplier will need to wait for an expansion © Gas Strategies Consulting hy The End Result - Typical Contractual Structure PROJECT OPERATOR LENDERS PRODUCT OFFTAKER \ 7 LOAN AGREEMENT SALES CONTRACT r. v sf A SHARE. 4” —sSVA ) < PROJECT wi HOLDERS Z COMPANY ve nN ~ “a CONTRACTOR SUPPLY CONTRACT INSURERS \ SUPPLIERS GOVERNMENT © Gas Strategies Consulting 3 9 Complexity in projects has seen delays and 5 ¥ failure = Discovery Date = Start Date = Nigeria —- 1950s = First delivery from Nigeria, Bonny Island — 1999 Indonesia — Arun field —- 1971 = First delivery from Arun, Indonesia — 1978 Australia — North Rankin field " First delivery from North Rankin, - 1971 Australia — 1989 Qatar — North Field - 1971 First delivery from North Field, Qatar - 1999 Mis-alignment of participants (Venezuela) Loss of market (UK 1960s, US 1980s, Japan late 90s) National politics (Bolivia, Venezuela) International politics (Iran) Severe cost inflation exacerbates these problems (Sakhalin, Snovhit) © Gas Strategies Consulting 10 os LNG Quality Criteria are different in each market — consequence of regional markets = Markets have established = =— =| oo their own gas quality to in| we] ee |e | a Waronee Wak} 305] oa) > 10) >| 8 burn in appliances Wanane wax 3 | wee [we wos | we Thane wax | ooo | wo] - wo) - | - = Asian GHV requirement Prepame wot 0.99 cr} - 25 - - ae | —far| higher than US eC aa *: | m@ Once distribution | sis Ch infrastructure built the Me/nn3 | as TotalSulpho mesma oo | wo | - or | - gas quality is highly ayi aus every “Am | 8 | i ia unlikely to change Vawme wee) | NE) 2A88 | Mae ages ten) see }to") LPG Extraction not incomes Lise jase] || possible for Alaska if =< rE Asian spec is met © Gas Strategies Consulting 1 Key Messages = LNG projects must be developed as integrated chains, both commercially and logistically, securing: supply, liquefaction, shipping, re-gas and market offtake = Projects cannot be launched into the LNG spot market — they require long term (20 year) take or pay SPAs to secure revenue stream = Asian LNG will continue to be priced by linkage to crude oil = The contract price will be set by perceptions of LNG supply and demand during SPA negotiations = Requirements for third party access can be accommodated but only after principal companies have secured capacity requirements = Asian markets require high CV gas © Gas Strategies Consulting @ Cost Overrun Risk: Sources and Management Economics of Undiscovered Reserves Fe] RLD OF DIFFERENCE BLACK & Wid vret Alaska Gasline Determination Public Forum Economics of Undiscovered Reserves Anchorage, Alaska May 28-30, 2008 =] Eee Use Scope of Presentation and Key Conclusions e Scope: e This presentation examines the economics for producers of unproven reserves, the yet-to-find (YTF) gas as a result of the AGIA Gasline project e Key Conclusions: e YTF Producers have positive NPVs under baseline assumptions e $1.6 to $1.5 billion NPV,, for Proposal Base Case and Conservative Base Case e $0.3 billion NPV, for Proposal Base Case and Conservative Base Case e YTF Producers have greater exposure than Proven Reserves Producers to commodity price changes, upstream costs and cost escalation assumptions a Eee Os.) Presentation Outline >» Key Assumptions > Baseline YTF Producer NPVs > Sensitivity Analysis » Impact of prices on YTF economics » Impact of upstream costs on YTF economics » Impact of cost escalations on YTF economics @ BLACK & VEATCH Overview of Assumptions for Unproven Reserves e Reserve assumptions are based on Long NETL’s study Ter Near Term m Total a 2005 2015 2005 e Analysis assumes that YTF gas will cejiotsn' cs a = be produced ea decline begins at Colville-Canning & State 10.0 TCF 23.3 TCF 33.3 TCF the proven reserves fields and Beaufort Sea space become available on the Beaufort Sea OCS voter | 2ootcr | 210 TCF pipeline Chukchi Sea OCS: OTCF 50.0 TCF 50.0 TCF e Equal volumes are assumed to be = Torer i ouoverl rau rce produced from State YTF and Federal Onshore YTF given the ANWR 1002 Area otcr | 20TcF| 20TCF uncertainty of the relative timing of their development and the rese TOTAL ARCTIC ALASKA 120 TCF | 1253 TCF | 1373 TCF available Source: Alaska North Slope Oil and Gas: A Promising Future or an Aree io Dectine?, published by the U.S. DOE, National Energy Technology Laboratory w Eee Byte Stylized Assumptions Impacting YTF Producers e Capital expenditure is spent on an as-needed basis to develop reserves needed to keep the pipeline full e No assumption is made on the lumpiness of development activities e YTF gas production is expected to incur higher production cost than production from proven reserves since extensive infrastructure is not already in place for the development of these fields e Production expected to start once decline begins at the proven reserves fields, around 2030. e Baseline analysis period of 25 years may not capture complete picture of YTF economics e Analysis reviews producer economics for YTF gas over 35 years to incorporate benefits accrued by these producers in later years m BLACK & VEATCH YTF Gas Production for 4.5 Bcf/d Pipeline DPBU/State Existing @Point Thompsom | B State - Yet-toFind @Fed-Onshore Ml (A ] | | 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 . Ere Os Ver Presentation Outline >» Key Assumptions >» Baseline YTF Producer NPVs > Sensitivity Analysis > Impact of prices on YTF economics » Impact of upstream costs on YTF economics » Impact of cost escalations on YTF economics = BLACK & VEATCH YTF Gas is required for 15% to 26% of the contracted volume on the pipeline Et VORLD OF DIFFERENCE® % of Contract Volume Requiring YTF Gas 45% fone 45 Befld 4.0 Befid B35 Befid % 15%15% 10% 4 5% 4... RBM Be MM Bid Se 8%. ay. ----- 0% +r T 25/25 20/20 16/15 Contract Period/Depreciation Life (years) (aspen i} BUILDING ORLC FERENCE® eS ee Analysis indicates positive YTF Producer NPV for different volume scenarios @ ee re anette Eee O02] eriod $ Billions (200€ i] Eee O20 YTF Producer IRR assuming a 35 year analysis period indicates an IRR of over 25% 29% 29% 29% faeeeooe--++-- ummm ons conneescsccsneencccnnneseecesnuesscecensneessecennneeeeesenae 27% 27% 4 -------------- MMMM === === 22 n noone ae nna nnennennen 27% 4 ------------- ARMM ===> oven eens eee nee nenennne 26% 45 Befid 4.0 Befid SOR SAS w BLACK & VEATCH Presentation Outline >» Key Assumptions > Baseline YTF Producer NPVs > Sensitivity Analysis » Impact of prices on YTF economics » Impact of upstream costs on YTF economics » Impact of cost escalations on YTF economics a. BLACK & VEATCH Key uncertainties impacting Producer NPV are commodity prices, cost escalation and upstream capital costs dee come —— i H i H : Wood Comm dity Prices P90 Mackenzie me Cost Escalation 2ecapex 2%.0F0% cs ‘Upstieam Capital Costs y ‘sox vecrea ‘Base Case TransCanada Schedule : P10 Base Case ese cont ‘TransC nada Capital Cost Pipeline Interest Rae 700% i ; reuse Production Scenarios: PEUSABCE OPT weer wot. soso tO 2 Producer NPV o ($Billion 2008) = BLACK & VEATCH Commodity prices would need to fall by about 30% to 40% for YTF producers to experience negative NPV YTF -*% Price Drop for 0 NPV. YTF . % Price Drop for 0 NPVs 0% o% “10% 4--+ “10% 4. 20% 4--+ -20% 4-- ® -D% 4-4 -30% 4-- 40% 4--- 240% fos 7 | 0% -| B45 BdMwithPT ©4BdM OISBdld 53%52% MéSBcnOwnPT Abed O35ECd | 0% J J -60% 4 25/25 20/20 185 2575 2020 4545, Contract Period Depreciation Life (years) Contr act Period Dept ectation Life (years) EW e 0 s.00 Alternate Price Forecasts Considered $45.00 Wood Mackerie AECO Forecast $40.00 —EIAAECOForecast enn nnn nennnnnnnnsy —BV Base Case Forecast $35.00 BV P10 $30.00 | —BVP90 “Historical 2007 AECO Price with ifiation $25.00 $20.00 Nominal $/MMBtu (616 00h sceeesoscecereecepreces cere seem $10.00 }----------- po ----- capa OO sss OOOO cacao ncn eenntnenteneneneesee SSID foc c eee neeeeste I eens oI Sec nce ov stovnt neces vovwwaeu eu ocsuvovsuaeuwuewesecwevevucees 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 BLACK & VEATCH YTF Producer NPV,, is positive for all except the lowest price scenario considered YTF NPV $3.0 ; m45 Bet 40Bctd 3.5 Betd $2.5 $2.4 25 $2.0 $15 $10 $ Billions (2008 $05 $00 ($0.5) 4 GO ay Sseeseee=t2s| go.sys0.4) ($1.0) Wood BV Mean ElA2008 BVP10 BYVP90 Mackenzie i] BLACK & avira) YTF Producer NPV,, is positive for all except the lowest price scenario considered YTF NPV;; $3.0 m45Befd m40Bcid 3.5 Betd G25 fennel cee eee cence ee enee eee reeeceeeenesaeeeneeeeeneeceteeeneeees ODN ooo rw cnn crane wneomsenenntcatvean conten wewnvenvdoersanvucvanensienmarenniVereaecouses GAS — ice canenisonvemsues nenecosessevovassaesavessseecesesewsastovenerreonsseseon woe $10 $ Billions (2008 $05 $0.0 ($0.5) seoceeoseneeeeeed $9.9) {80:3) ($1.0) Wood BV Mean EWA 2008 BVP10 BYVPSO Mackenzie = Eee User YTF Producer IRR for Proposal Base Case Assuming 35-year analysis period indicates IRRs over 20% for all except the lowest price scenario. Upside IRR with higher prices is greater than 35% Wood BV Mean EIA 2008 BVP10 BV P90 Mackenzie a eee Ose Cost Escalation Assumptions e Baseline cost escalation assumptions: e Operating expenses - 3% e Capital expenses — 4% e Low escalation assumptions: e Operating expenses — 2% e Capital expenses — 2% e High escalation assumptions: e Operating expenses — 5% e Capital expenses —- 6% | BLACK & VEATCH YTF Producers are impacted by capital and operating cost escalation assumptions — higher escalation drives NPV,, negative YTF Producer NPVjo 4.5 Bef with PT 04 Befid 03.5 Befid “$2.5 § $ Billions (2008) Base Escalation Low Escalation High Escalation =] Eee hse YTF Producers are impacted by capital and operating cost escalation assumptions — higher escalation drives NPV,, negative YTF Producer NPV, $5 45 Befid with PT 4 Bed 35 Betid G4 paceenececcececeeeeeesneceeeccenneeeenecesceeeseccenecsesceeesceenescsnssesesecsesceescenseeeeeeeee 2 8 x 2 a 8 fannnnessereroceeesccreceeneeccreneeee Brig np atsteseneenscasesssnesecncsssnsasseseenessnee ($0.4) ($0.3) -$1 $0.4) Base Escalation Low Escalation High Escalation @ = Eee Sys YTF Producer IRR for Proposal Base Case Assuming 35- year analysis period 40% Base Escalation Low Escalation High Escalation = BLACK & VEATCH Upstream Capital Cost Sensitivities e Upstream capital cost assumptions are based on the NETL study and incorporate recent cost spikes experienced by the upstream industry since 2005 e Analysis looked at a 50% decrease and a 100% increase in the capital cost over the assumed levels =] paaratese Ee hs uc Upstream Capital Costs Impact YTF Producer NPV,, Producer NPV1o m Base Case __ @50% Decrease © 100% Increase Aggregate YTF Proven Reserves = ORLD OF oa Eee eas Ae Upstream Capital Costs Impact YTF Producer NPV,, Producer NPV;5 $200 mBase Case $150) dee ....-, BSOWIDOCTONSS & 100% Increase i i $5.0 san Seat o LD Fl “ Yj $00 4 - ($5.0) Aggregate YIF Proven Reserves Producers | BLACK & VEATCH Conclusions Revisited e YTF gas is needed for 15% to 25% volume of contracted volume on the pipeline for the Proposal Base Case and Conservative Base Case e YTF Producers have positive NPV,, and NPV,, (not shown) under baseline assumptions e $1.6 to $1.5 billion NPV,, for Proposal Base Case and Conservative Base Case e YTF Producers have greater exposure than Proven Reserves Producers to commodity price changes, upstream costs and cost escalation assumptions Employment on the Gasline Project AGIA Employment on a Gasline Project Strategic Training Plan Ee é a me The Goal: » Deliver an Alaska workforce prepared for Careers in construction, operations, management and other occupations related to natural resource development including a gasline. The Call to Action: Engage Stakeholders to Build Capacity The Need: Close the Alaskan Skills Gap The Promise: Put Alaskans to Work The Strategy: Enhance Existing Programs The Plan: Five Years, Three Phases The Purpose: Anchored in Collaboration & Innovation Four Strategies: 1.0 Increase awareness & access to careers in natural resource development. Public Awareness Campaign. One Stop Information on Jobs and Training 2.0 Develop Comprehensive Career and Technical Education System ¥ — NJ ¢ elk en eh YES) ere iL Skill Standards OTS » K-12 Career Planning and Counseling » Integrated System for Youth & Adult » Coordinate Existing Training Programs 3.0 Increase Registered Apprenticeship and OJT » Increase Job Training for Entry Level Jobs » Increased Apprenticeships in Construction » Employer incentives for Apprenticeship & OJT » Funding to Support Apprenticeships & OJT % —.. 4,0 Increased Training for Operations, Technical, & Management Workers >» Expand Programs for Critical Jobs #, } > Recruit More Alaska High School Grads A » Increase Internships and Work-Coops for Secondary and Post Secondary » Better Articulation between Job Training and Management Programs » Help Workers Keep Pace with Jeciilos/ and Skill Upgrades Next Steps » Outreach: Construction Industry and Job Training Representatives Travel across Alaska. > Implementation: Training programs enhanced to open more opportunity to all Alaskans in preparation for gasline jobs. » Web Site: labor.state.ak.us » Click on: AGIA Training Strategic Plan Modeling of Short- and Long-Term Employment Generated by Construction and Operation of an Alaska Natural Gas Pipeline Project Employment projections generated for ... Construction of pipeline and installation of Gas Treatment Plant and LNG facility woe Operation of a pipeline and facilities 4/\~ Exploration and Development work on the North Slope spurred by operation of natural gas pipeline £2 ARCADIS Sources of Data ¢ Construction — Information from TC Alaska contained in its AGIA Application and other information provided to the State of Alaska — Data generated by State pert consultants for the LNG options « Operations — Data generated by State’s expert consultants ¢ Exploration and Development — Information from Division of Oil and Gas §@ ARCADIS How we generated our results Cost information input to IMPLAN economic modeling software Direct, Indirect, and Induced employment modeled Assumptions: Gas Treatment Plant and LNG facility built outside Alaska Production facilities for new natural gas fields built in Alaska Denali™ Project construction employment equal to TC Alaska-generated employment Denali™ Project E&D employment equal to LNG option §@ ARCADIS x Results: Construction Employment Any natural gas pipeline project will create thousands of short-term construction jobs Construction employment will be highest during a 4 year peak period LNG option — 16,000 jobs in peak year TC Alaska — 15,000 jobs in peak year 6 ARCADIS Results: Pipeline Operations Employment « LNG option: ~600 operations jobs in PNEES.C — Pipeline operations jobs are equal to TC Alaska — ~400 jobs at LNG plant in Prince William Sound * TC Alaska: ~200 operations jobs in Alaska 62 ARCADIS Results: Exploration and Development Employment ¢ TC Alaska: ~72,000 direct jobs (2015-2045) > ¢ LNG or Producer Project scenarios: ~47,000 direct jobs (2015-2045) 62 ARCADIS 7 Results: Exploration and Development Employment ¢ E&D jobs may be created years earlier under TC Alaska scenario than under LNG or Producer Project scenarios ¢ Timing of E&D job creation is tied to: — Effective open access — Timely capacity expansio' — Low tariffs §@ ARCADIS © Evaluating TransCanada’s Commercial and Tariff Terms Alaska Gasline Determinatio Public Forum Wednesday May 28, 2008 BLACK & VEATCH ANGTS Project « Comparison to risk sharing norms in the natural gas. pipeline industry BLACK & VEATCH * ROE Reduction for Cost mine ¢ 0.05% ROE reduction for every 1% cost ove: * 20% cost overrun > 1% ROE Reduction * 40% cost overrun > 2% ROE Reduction * 200 basis points is maximum ROE Reduction. Saat vearce allio Higher Equity Percentages Increase Tariff, as expected. BaseCase D/E-7080 DF-6040 D/E-5050 Note: A 50/50 Debt/Equity is well within industry norms BLACK —_- allio 2 percent reduction in TC Allowed ROE results In $0.28/MMBtu reduction in Tarlff compared to Base Case. @K Pipeline Yukon-BC -- $5.22 ZT gm Alberta Base Case 881% BLACK & VEATCH Tariff mGTP @AK Pipeline @Yukon-BC Mélb Interest Rate = TransCanada ROE - 12% Use of U.S. Loan Guarantee for Cost Overruns reduces Tariff by $0.18 per MMBtu for a 20% cost overrun and $0.35 per MMBtu for a 40% cost overrun when compared to the same overrun without this mechanism in place. Base 20% Cost 20% Cost 40% Cost 40% Cost Case Overrunw/ Overrun Overrun w/ Overrun Loan w/o Loan Loan wio Loan Note: ROE Reduction Provision of TC Proposal is turned ‘On’ for all of the above sensitivities Fe BLACK & VEATCH afi ROE Reduction Provision reduces Tariff by $0.04/MMBtu for a 20% cost overrun and $0.09 for a 40% cost overrun. wGTP BAK Pipeline © Yukon-BC MAlbena Base Case 20% Cost 20% Cost 40% Cost 40% Cost Overrunw/ = Overrun = Overrunw/ = Overrun. ROE wio ROE ROE wio ROE Reduction Reduction Reduction Reduction Note: U.S. Loan Guarantee Mechanism of TC Proposal is turned ‘On’ for all of the above sensitivities. aa BLACK & VEATCH Aggregate Producer NPV, $12.5 Base Case 20% Cost 2% Cost 40% Cost 40% Cost Overrun wi Overrunw/o Overrunw/ Overrun w/o Loan Loan Loan Loan BLACK & VEATCH Base Case 20% Cost 20% Cost 40% Cost 40% Cost Overrunw/ Overrun Overrunw/ = Overrun Loan w/o Loan Loan w/o Loan BLACK & VEATCH Precedent? B) Might TC’s offer be improved upon after Negotia 5 Process? « Answer to both questions is “Yes” BLACK & VEATCH ~ Portland Nature Transmission — Rockies Express Pipeline a BLACK & VEATCH — Similar to what was offered on Alliance ¢ Negotiating Process May Improve Terms — Fixed premium may be eliminated, ROE base reduced — More overrun risk may be borne by TC Alaska a. ‘ BLACK & VEATCH aNAD ae * Longer depreciation period with same ¢ > Lower tariffs ¢ Shorter contract length with same depreciation peri > Less initial shipper risk BLACK & VEATCH — Average Reserve/Resource Life Index = 55.4 years for Alaska. — Alaskan Gas Supply Adequate for a 35-Year Project « Goldman Sachs’ suggests financeability of different lengths Sia exten allio *« Demands for Gas Supply in Canada « Synergy Between an Alaskan Pipeline Project and TransCanada’s Strategic Financial Interests BLAGK & VEATCH ty + Much of the tariff must still be defined — This will usually take place in the form of a neg « AECO-C terminus provides marketer shippers with valuable liquidity and optionality ° Esters for anchor shippers to take equity in the project BLACK & VEATCH af D Financing LNG Projects Financing LNG Projects Breakout Sessions #6 and #7 May 30, 2008 1 A SS S$ TES For any Project Financing a Range of Risks are Assessed in Determining Credit Strength Project investors are relying on two sources or repayment — Strength of sponsor - ability to get project financed, constructed and operating effectively — Strength of project economics - dependable revenue stream Project economics are driven by — Cost and constructability — Quality of offtake credits and contracts — Underlying factors - Source and price of inputs - Markets for outputs - Operating risks Regardless of sector, these areas are thoroughly reviewed by credit analysts at rating agencies, bonds and investors Business & Legal Project Risks Framework Country Risks Force Majuere — Technology — Jurisdiction — Source of inputs — Non performance — Construction — Choice of law — Facility - Construction — InputsReserves — Form of Project — Buyer - Inputs — Market Company - Process — Operational — Contractual Agreements - Operations — Financial Structure | Conceptually, the analysis of an overland gas pipeline and an LNG project are similar However, project and sector specifics drive overall analytic complexity Credit Analysis of LNG Projects is Inherently More Complex then for Overland Pipelines Credit Factor LNG Considerations Reserves Ld a ‘Similar GTP Y we Similar Transport Pipeline a v7 Liquefaction NA v @ Each has substantial cost, technology, and completion risks Shipping NA v ® Shipping has jurisdictional/choice of law and currency risks Regasification NA v @ Shipping, re-gas and purchase contract have country and currency risk Country Risk Minimal ¥ Market Large, liquid, Contracted, buyer predictable specific market, market some spot sales 3 LNG Project Complexity For a successful project financing, every step in the chain has to be analyzed, largely or fulty contracted, and controllable risks substantially mitigated @ There are a range of incremental credit issues that would be analyzed in depth by potential LNG project developers, investors, and other participants: — Country risk (shipper, buyer) — Currency risk — Liquefaction and regasification technology risk — Ship construction (or leasing), cost, timing, reliability — Shipping risks — weather, damage/spill, jurisdiction issues — Gas supply — price and adequacy — Jones Act limitations — Safety and terrorism = Commercial boundaries could be drawn any number of ways — Integrated project, supply to delivery — Different combinations Integrated Project “Force Majeure” Risk is a Good Proxy for an Overall Project Risk Assessment Force Majeure clauses in project agreements may excuse parties from performance as a result of events outside their control Can impact each element in the financing — Project suppliers (construction, materials, gas supply, etc.) — Construction — Operations — Offtakers As such, risk of a Force Majeure event is greater when there are more participants, agreements, and steps in the process Standard & Poor's Force Majeure Benchmarks: Force Majeure Risk Exposure Benchmark Scores! ‘Score Characteristics Examples 1 Highly near, simple operations Tot roads: Loose Irkages Pipetnes Geographicaly spread out Hydrostectrc power plants 5 Greater complexty of operations Cosl-fred power plants ‘Tighter inkages of sequential operations Mines 10 Highly complex operations Petrochemical plants Extreme tight linkages among Refineries ‘sytem Highly specialized equpmert used Liquefied natural gas ‘Operating accidents can be costly Nuclear power plants ‘ Source: Standard & Poors, 2007 Global Project Finance Yearbook. The Ras Laffen Complex of Projects Provides a Good Snapshot of the Complexity of Financing LNG Projects @ LNG projects developed jointly by State of Qatar and ExxonMobil ™@ Several phases of project development undertaken by same sponsors, but each with own separate project company ™ Total expected complex could reach 7 LNG trains at a cost of roughly $15 billion — An additional 7 trains could be developed by related “QatarGas” family of companies Seo cinng uA Rd CO eC The Initial Ras Laffen Project was Funded via a Series of Project Finance Transactions initial Ras Laffan Business Schematic Key Elements of Finance Structure ae Soa | Sponsor completion guarantees ExxonMobil debt service support up to $200 mm per year | Strong offtaker and gas purchase contract — Korea Gas - Kogas obligated under 25 year contract for 90% of capacity | Project has access to reserves of roughly 900mm tef Initial debt/equity funding split of 47%/53% | Construction costs and risks managed via EPC contracts Secs" Summary of Key Assumptions for the Alaska LNG Analysis Capacity — Three capacity cases were developed, a 4 5 bef all LNG project which is most comparable to the Proposal Base Case; a 2.7 bcf all LNG project; and a 2.0 bcf expansion LNG spur to Valdez & Project Costs — Project costs estimates were developed for the portions of the LNG alternatives from gas treatment through and including the costs of shipping but excluding the cost of regasification LNG Prices — Natural gas prices in North America have a relationship to world oil prices but are also driven by natural gas market specific supply and demand factors LNG Market Assumptions - — The market for LNG volumes is substantially more developed in Asia than in North America. We assume that cargoes from any Alaska LNG plant will be principally sold to Asia buyers via long-term contracts — As aresult of the cost and complexity of LNG projects, the LNG market is in large part a long term contracted market, i.e., an LNG developer will not build without long-term LNG sales contracts at volume and price levels which provide adequate revenues for amortization of costs, financings and to meet equity return targets © interest Rates - We have assured the same interest rate matrix for LNG- and Proposal-based cases = Federal Loan Guarantee — Based on the Federal Loan Statute code, we have assumed no Federal Loan Guarantee will be available for any LNG related project costs Key Unknowns — Equity sponsor, gas purchaser, ship builder/operator, finance plan framework, business structure of “project” Summary of LNG Cases vs. Proposal Base Case LNG ¥ Line Proposal Expansion of 2.0 bef Buse Caxe BU LNG 27 bet BULNG 45bch to 6.5 Totai* ‘Sources of Funds Equity 16,6750 16, 450.0 26,000.0 77,950.0 Dent 37,039.3 58,468.9 26,857.3 rest Earnit 366.4 382.5 Uses of Funds: Project Costs" Development Costs 301.4 44,835.41 Properly Taxes Subtotal a Other Costs Capitatzed Interest 7,385.3 Debt Service Reserve Fund 8178 Financing Fees 1,651 Subtotal 38547 i eBay aie LT ee ‘Statistics ‘Average Annual Debi Service T3348 $320.5 $5,0664 sarieT Average Debt Service Coverage 1.82x 1.64 x 1.75% 1.89 x Weighted Average Cost of Debt 7.06% 7.05% 7.18% 7.20% Weighted Average Cost of Capital 9.11% 7.95% 8.55% 9.88% Transportation Cost (per Dekatherm)'?# $473 sa74 $9.46 $4.66/ $10.40 + Provided by Black & Veeich 7in 2025, includes Ges Treatmert Plat, ell applicable pipeline segments, endior Aberte Ter, LNG Plant and shipping costs where applicable. 2 Shipping costs provided by Gas Srateyies. * Sources and uses in addition to Proposal Base Case sources end uses. 9 Summary of Findings — Alaska LNG Options Are the LNG cases analyzed viable from a financing standpoint? @ The fundamental underlying economics of an Alaska LNG project may provide the basis for a financeable project — Comparison of projected market gas prices vs. fully loaded costs — Strength of potential sponsors and gas purchasers — Business and financial arrangements © inorder to reach a more definitive conclusion, a great deal more needs to be known — Without additional clarity regarding participants and business terms, it's hard reach conclusions about overall Viability - Equity sponsor Gas purchaser Ship builder/operator Finance plan framework Business structure of “project” Magnitude of financing will prove quite challenging — Greater equity percentage will be required than gasline — some LNG projects are done with 100% equity — No Federal Guarantee — Will need construction/completion protection — Will need strong creditworthy contracts for - Gas sales to Project = Shipping - Regas costs = Gas purchase from Project 1 LL 10 Disclaimers The analysis and conclusions set forth herein are based on economic, financial, political, market and other conditions as they exist and can be evaluated on the date hereof, and we have not undertaken to reaffirm or revise our findings or otherwise comment upon any conditions or events occurring after the date hereof. Our analysis and conclusions also involve numerous assumptions and uncertainties, many of which cannot be verified or ascertained presently. Goldman Sachs does not provide accounting, tax or legal advice, and we make no representation as to the appropriateness or adequacy of the information contained herein or our procedures for, and express no view as to, the tax, accounting or legal treatment of any matter. Goldman Sachs and its affiliates, officers, directors, and employees, including persons involved in the preparation or issuance of this material, may from time to time have “long” or “short” positions in, and buy or sell, the securities, derivatives (including options) or other financial products thereof, of entities mentioned herein. In addition, Goldman Sachs and/or its affiliates may have served as an advisor, manager or co- manager of a public offering of securities by any such entity and/or for any other securities- or asset-related transaction. Further information regarding this material may be obtained upon request. This material provided by Goldman Sachs is exclusively for the information of the Commissioners of the State of Alaska Departments of Natural Resources and Revenue and senior management of the State. In addition, unless indicated othemise, further use by the State of information and data contained herein sourced to third parties would require approval from such third parties given directly to the State ee 11 Fiscal System Risk Stabilization Clauses Needs and Practice In The Petroleum Sector May 30, 2008 — US and Canada — State and Province ¢ Pipeline Owners __* International Oil Companies (|OCs) oe _—PBU & Existing ¢ Unit Netback less Costs = Taxable Value * Taxable Value less Tax = IOC Profit price risk — They have many financial tools at their disposal to manage this risk * Since the Taxable Value is based on Market Price the State is also taking a degree of market price risk a — Additional risks if royaltyistakeninkind = A gulated tariff setting y mech: boundaries o on how much can be — Allowed rate of return — Expected throughput — Total cost structure — Maximum tariff — Defined terms of service = * AGIA provisions are for this purpose — Filed rate case —- Contracts for firm service ¢ For the lOCs and the State there are means to minimize tariffs paid — |OCs can participate in regulatory hearings — |OCs can negotiate rates at levels below the _ regulatory maximum ized tariffs provide presictabily anc oft — For PBU expected to be very small a —For TYF, unknown as to degree of needed ~ exploration and appraisal ¢ State does not mandate use of Alaskan goods and services that then result in costs above those that the |OCs could | otherwise obtain —1lOCs seek “incentives” to protect agé anticipated downside/low return —lOCs seek “stability” to ensure that rewards are commensurate with the risks —lOCs seek “predictability” in order to sign long term contracts to ship gas | ‘ability? — Does Stability mean a fixed amount or an | fiscal system? * ACES is a variable fiscal system — Impact/needs vary by operation + PBU * Other Existing * State YTF + Federal YTF eeanalienge | is to find mechanisms that come i _ Play if needed — but not granted gt “The long term and capital intensive charac investments in the international oil and gas .. industry underlines the vulnerability of the ... investor to unilateral action ... .. The provision of a guarantee for stability in the contract is one way of mitigating that risk ..” around the world is that many of th not offer clauses to provide ‘stabilisatio and in those cases the IOCs appear to have no difficulty living with this.” ats peseeetsationin Investment Contracts and Changes of Rules in Host Counties: Sooke “contract language which freezes the provisions of a national system of law... [as of] ... the date of the contract in order to prevent the application to the contract of any future alternations of this system” “ Those States that do provide a form of stabilisation may nonetheless offera degree of protection that is much less sweeping in scope than that implied in the [previous] quotation ” “ Whatever its attractions to an IOC, it appears that a stabilisation clause is not mandatory requirement for a host government that seeks to attract investment into its petroleum sector ” 5 coun have a good dealing with [OCs and as a result t! is that political risk is low. Such countries not offer stablisation provisions to an |OC (Norway and the UK are examples of this).” “In other cases the perception of political risk may well be high but the perception of geological risk is low enough for the |OCs to accept a contract ___ without stabilisation provisions (Saudi Arabia, a7 Brazil).” ai Rocks trump scissors ! sts, these tend | rock/OECD countries + Whats it that |OCs seek to have stabilized? — Why are these components more at risk than in other places? — Upstream terms? ¢ PBU and Existing? ° YTF? ___ — Pipeline terms? that is being request freezing of terms, or holding returns reasonable band of expectations ? — Can Governments change terms if other things improve for investors ? — Many moving parts, including multiple taxes * Alaska gas development investments are acknowledged as big (in an overall sense) _____ —l0Cs need to explain what they need, why it is ee ecessary andwhentheyneedit = =~ Gas Pricing in North America Fe] BUILDING A WORLD OF DIFFERENCE BLACK & ia \ret Natural Gas Pricing in North America Breakout Session Alaska Gasline Determination Public Forum May 28 — May 30, 2008 a Ewe Rac) How is natural gas valued in the North American market? e Gas delivered to different locations has different prices: e Dependent on: e Supply/demand balance e Pipeline infrastructure e Henry Hub vs. AECO e State relied on range of forecasts (EIA, Wood Mackenzie, B&V) e B&V forecast allows consideration of prices over very wide range of assumptions of supply/demand drivers By -2 9/27/2008 a WORLD OF DIFFERENCE® BLACK & VEATCH Price Forecasts Reflect an “Educated” Opinion on Future Market Developments e Natural gas price forecasts are available from different sources: e EIA- available to the public every year e Industry experts — e.g. Wood Mackenzie, B&V e Financial Institutions - NYMEX, Banks e All price forecasts are generated with subjective assessments, e.g., projected market conditions, using an economic based model e Nominal price vs. Real price: e Nominal price is the price in terms of “dollars of the day”. Historical spot prices are all nominal. e Some forecasts are expressed in terms of real price, i.e., constant dollars e The difference between nominal and real reflects changing purchasing power of currency over time - “inflation” =| BLACK & VEATCH EIA Annual Energy Outlook 2008 Natural Gas Forecasts e Available from DOE EIA website in April 2008 Tn | © Available for deliveries | at Henry Hub only, o) adjusted to AECO price ‘ using historical | — EIA Henry Hub Forecast $26.00 —EW AECOF orecast $20.00 differentials between AECO and Henry Hub $16.00 ‘| @ Projected period from 2008 to 2030,extended to 2045 using the growth Nominal §MMBtu $10.00 tate between 2020 and 96000 sopren one esepnonnen ncnreenennannanae scans cnnnennencsnnoancarnnennennncenceneccaenorsn | 2030 . | @ Projection in 2006 2008 2011 2014 2017 2020 2023 2026 2029 2032 2035 2038 2041 2044 dollars, translated into nominal dollars using 2.5% inflation By -4 si2772008 = EW thse Wood Mackenzie Natural Gas Price Outlook e Most, if not all, the major North Slope producers are clients of Wood Mackenzie 39500 $3000 Wood M eckenaie AECO Forecast Wood M ackenae Henry Hub Forecast ; _e Available for deliveries at Henry Hub and AECO $2500 _e Price projections from 2008 to 2027,extended by Black & Veatch to 2045 using the growth rate between 2020 and 2027 + @ Projection available both in 2008 dollars and nominal dollars translated using a 2.5% inflation rate 2. BLACK & VEATCH Varying Assumptions Highlights Price Forecast Risks e Forecasted prices from all sources are “point” estimates, all dependent on a specific set of assumptions e None are expected to be on the dot “correct” e Price uncertainty and associated risks could be better illustrated using a forecasted price distribution Probability Range of Price e Black & Veatch assumes that the majority of price risks comes from uncertainty in fundamental factors re) Ee Use Overview of the North American Regional Gas Model Utilized by Black & Veatch e An integrated model of all supply basins, demand centers and pipeline across North America a Major inputs into the model include e Projected demand e Projected supply curve determined by finding and development costs and reserve estimates P: ARNG Foohits Ppdine w Krgsgam =F e Other supply volumes such as LNG - e Pipeline capacity and cost | ee hse “Economics 101” - Fundamental Analysis Determines Price from Supply and Demand Supply Price Demand Quantity a BLACK & VEATCH Finding & Development Costs ~ Supply Curve: It’s all about the rocks! e The cost and reserve assumptions come from the 2003 National Petroleum Council study, updated to 2007 levels using the Significant IHS/Cambridge .| reserves can be P || proved and ready Upstream Capital Cost Finding and Development Cost (Nominal /MMBt) for production at Index or the Canadian below $4/MMBtu Petroleum Engineer Association cost Accumulative Reserve Additions (Tet) estimates i) Eee Racal F&D cost assumptions in base case are conservative: cost have grown significantly in the past several years. e The shape of the curve shows that F&D costs will stay at the assumed level for a long period e Meanwhile, according to IHS/CERA upstream capital cost index: (The) “cost... have doubled since 2005” e Asreported in the Gas Daily of April 14, 2008, Oppenheimer analyst Fadel Gheit stated in a report that the F&D cost for “the eight majors jump to $19.55/BBL of oil equivalent and $14.77/BBL of oil equivalent (“boe”) for the independents”, which is equivalent of $3.25/Mcf. i) Eee hia Black & Veatch Base Case Assumptions Assume F&D Costs Decrease Over Time e Technical innovation: e Technical advancement that could lead to superior drilling technique, rise in drilling success rate, reduction in drilling cost and increase in per well recovery e Real cost escalation: e Rising cost in labor and materials e Technical innovation rate is assumed from the National Petroleum Council study and real cost escalation from Bureau of Labor Statistics analysis ===> Overall impact is a forecasted real cost reduction of 25% in 34 years By -11 8927/2008 | s OF DIFFERENCE® BLACK & VEATCH Black & Veatch Base Case LNG Imports into the US Market are Assumed to be “Price Takers” not “Price Setters” 8 Wood Mackenzie 17 Befid by 2025 14 davereneneseeessesesesecceseeeeesescesssssesnnsensnnne Black & Veatch B12 p19 Bef by 2028 so E ee le 5 > Bonn fencers — 26 ieee a — o BY -12 5/27/2008 | BLACK & VEATCH Total Overall Demand is Assumed to be Flat with Power Demand Decreasing after 2016 (a conservative assumption) Black & Veatch Assumptions Residential and Commercial _Industrial Power U.S. Total 0.31% -0.80% 0.06% 2042 2016 2016 20.3 19.5 61.3 Comparing Assumptions for Gas Consumption from Power Generation : B&V base case assumption (based on EIA) — (0.8%) decline rate Wood Mackenzie assumption — 2.5% growth rate Wood Mackenzie Assumptions Max Year Max Rate (Bcfid AARG (%/Yr) Residential Commercial Industrial Power 0.10% 0.20% -0.40% 2.50% 2023 2023 2010 2024 2010 2024 13.45 8.74 w@ Eee hae $35.00 $30.00 }- $25.00 8 Price (Nominal $MIMBtu) Black & Veatch Base Case Forecasts - AECO —BVAECO Forecast — BV Herry Hub Forecast $10.00 f-------2-2020-eeeroce e Projection from 2008 to 2042; extended to 2045 using the | growth rate between 2020 and 2042 Projection in 2008 dollars, translated into nominal dollars using 2.5% inflation Available for deliveries at all points 2009 BV -14 2013 2017 2021 2025 2029 2033 (2037 2041 2045 :, in Canada and Lower 48 states. 400 800 $200 00 90.00 s.00 $200 $3.00 $4.00 Price Delta (S) @P10 @Ps0 Bf Sooo ewereeeeeeneqepcpece seen setae ereermewae termes re eee 00 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 v-16 e [a aa Techimprovemert & Cost | Escalation | Power Generation | | WCSB F8D Costs e No Industrial Demand ° GOM and Rockies F8D = sce oO ‘| e High power e Increase in gas a BLACK & VEATCH High cost escalation and increase in power generation could increase AECO price up to $3.00 in 2022 WCSB finding and development cost also increases AECO price High LNG import volume, industrial demand and GOM and Rockies F&D cost all increase AECO price, but not so significantly i] BLACK & VEATCH generation case assumes a $60/ton emissions tax starting in 2015 and low availability of renewables demand from the power sector by 80% in 2025 =| BLACK & VEATCH 30.0 20.0 z 3 15.0 a 10.0 60 oo Scenario Analysis — Range of LNG Import e The range of LNG ———Base Case 207-- volumes are based on the EIA AEO 2007 sensitivity scenarios e The high LNG scenario assumes that the LNG will serve Scenario Analysis — Range of Industrial Demand US Lower 48 e US industrial demand range is e Canadian industrial demand ‘300s 2010 2012 2018 2016 2018 2020 20%: 2021 2028 2028 2030 2092 2004 2096 2086 200 2012 more than 1/3 of total US demand =| Eee sca driven by different economic growth range driven by oil sands Canada B ——BV Base — BvPIO ——BV P90 AECO Price Distribution Over-time e Nominal AECO price grows faster than the 2.5% inflation rate over time e The distribution m2 86032 38. 2402044 e P10, Base and P90 re) BLACK & VEATCH uncertainty grows over time, consistent with increasing uncertainty on fundamental drivers correspond to $6, $11 and $15 real price in 2045 a $45.00 $25.00 $20.00 Nominal $/MMBtu $15.00 $40.00 +-- $30.00 7-- $10.00 f--o-- eos nn Forecast Scenarios. "Wood Macken zie AECO Forecast EIA AECO Forecast BV Base Case Forecast — —BVPO ——BV P90 $35.00 +-- Historical 2007 AECO Price with Inflation e Price growth is ~ e@ Augmented by demand 206 AI2 NE 2020 «2024 2B 232 236 2040 «(244 BLACK & VEATCH Real Price Growth at AECO is Expected Under All Price supported by the growing indigenous supply constraint e The rocks are getting harder and more costly to crack growth from the power generation sector and Canadian oil sands e BV P90 and Wood Mackenzie price grow the fastest Awide range of prices enable a sensible assessment of the NPV price risk In-State Energy In-State Energy Alaska Energy Plan Alaska Energy Authority AGIA is Designed to Maximize Alaskans Opportunity to Access Affordable North Slope Gas Off-take Points » Distance Sensitive Transportation Rates » Lowest Reasonable Tariff on Main Line True “Open Access” Provisions e Does Not Interfere with “Bullet Line” True “Open Access” » Explorers have that —Pipeline capacity will be expanded if new gas is found (expansion provisions) ====New gas willspay-afair transportation rate (rolled-in rates) e Creates a competitive and active North Slope Gas basin » Provides long-term careers in the gas basin How Does AGIA Lower Cost of In-State Gas? The Large Pipeline provides economies-of-scale to keep transportation.costs low for a spur line to Alaska markets eCompetition in North Slope Gas basin maximizes opportunity to match a willing seller with an Alaskan market “Bullet Line” Oe M(t mil LOM Coie Pm tale m items) Lhe can provide financial support without conflicting with the AGIA project e Will not provide the economies-of- ===scale-of-a-spurine off the main line, but may be able to be completed sooner e State needs to evaluate this option when considering other railbelt energy projects AEA Energy Plan Goals e Reduce the cost of energy to Alaska © Rapidly identify and deploy solutions e Complete analysis by December 2008 Deploy solutions as soon as identified. Plan Objectives e Identify and deploy energy sources that are vertically integrated, economic, long-term stable priced, and sustainable. Guiding Principals ad © Provide energy in a form that can be used in existing infrastructure. © Evaluate costs on a delivered basis. e Use low-profit business structure. e Minimize risk of technology failure. e Engage Alaskans in the solution. e Seek the lowest cost energy to each community. CEp Global Exergy Flux, Reservoirs, and Destruction Plants Methane Hydrate Identify the current fuel usage and costs Initial Usage estimates = Bulk Fuel Loan data * Tank Sizing estimate: 1,000 gallons per year per person. = PCE participation = Crowley and Yukon Western deliveries be md 0-9-1 Determine the current cost of fuel Selawik- Energy Flow Model FUEL ONLY PERSO C lio Same ascent) ieee) Wind Seem e et me arco arty Space Heating ores tore Selawik Yearly Energy Tc BYTE Mie Tem an Reb moms ci tenants tai Residential Base per household $ 2,500 Sawai) BY $ 9.000 Yearly Total (Community Facilities Commercial Regional Energy Cost Comparison Southeast (hydro) Anchorage (gas) Electric $1,117 Heating $ 834 Transport 3.474 Total Energy $5,425 % of Income 9.8 % Fairbanks (Diesel) Electric $ 1,534 Heating $ 4,027 Transport 3,521 Total Energy $9,082 % of Income 22.4% Electric $..1,259 Heating $ 2,881 Transport 1,832 Total Energy $ 5,972 % of Income aR Rural (Diesel) Electric $ 1,753 Heating $ 6,596 Transport AP a Total Energy $10,291 % of Income 40.2% 12 Potential Technologies and Fuels Hydroelectric Natural Gas Wind Propane Solar Coal Tidal Diesel Wave Coal Bed Methane Biomass Nuclear Geothermal Gasification Municipal Waste Fischer-Tropsch Conservation ce Locally Available Fuel Supplies Visits to 25 communities to listen to locals on available energy sources. Size for the local need Determine energy delivery method. Develop energy production and delivery method and costs. Local Control using Local Fuels to make Local Energy. Rapid Option Selection e Determine the technology option which will deliver a usable fuel that meets the local needs at the lowest cost. e Local Feedback Regional Energy Cost Comparison Anchorage (gas) Electric $1,117 sams |(-7-11 (11 a <2 LL) Transport BL} Total Energy $5,425 % of Income ty e Fairbanks (Diesel) Electric $ 1,534 Heating $ 4,027 Transport RAY Total Energy $9,082 % of Income 22.4% Southeast (hydro) Electric $.1,259 $ 2,881 Transport 1,832 Total Energy $ 5,972 % of Income KSI) Ue BI C=tt-1)) =il-Yei dale $ 1,753 Heating $ 6,596 Transport 1,941 Total Energy $10,291 % of Income 40.2 % ie) Resources e Engage both public and private sectors in identifying a solution — AEA Team and passionate Alaskans — Local Businesses — Entrepreneurial Business training — Financial Institutions — State of Alaska financial support Schedule: Alaska Energy Plan Jan Feb Mar Apr May Jun July Sep Oct Nov Current Status ad ® Identifying local fuel needs and resources e Evaluating technology » Regional trips to 25 communities complete by June 4*, 1 -2 teams to cover communities » PowerPoint on the AEA website e Developing the technology matrix. Regional Energy Cost Comparison Anchorage (gas) Southeast (hydro) Electric a Electric $1,259 en C1); a er <7 kL $ 2,881 Transport 3.474 Transport 1,832 Total Energy $5,425 Total Energy $ 5,972 % of Income 9.8 % % of Income ARS 3 Fairbanks (Diesel) © Rural (Diesel) Electric $ 1,534 Electric $ 1,753 Heating $ 4,027 Heating $ 6,596 Transport cay a Transport see S| Total Energy $9,082 Total Energy $10,291 % of Income 22.4 % od Meret ia Questions ??? Contact Information: Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, Alaska 99503 (907) 771-3073 www.akenergyauthority.org Comment c-mails to: energycoordinator@aidca.org @ Is TransCanada Potentially Liable to its Former Partners? Is TransCanada Potentially Liable to its Former Partners? Allan Van Fleet Greenberg Traurig, LLP TC Withdrawn Partners Issues * Is there significant risk that, if TransCanada builds the AGIA pipeline, it would be liable for billions of dollars to former partners of the Alaskan Northwest Natural Gas Transportation Company? * Is there significant risk that third parties working with TransCanada would be liable to Withdrawn Partners? * Are there ways to reduce uncertainty? ANNGTC Partnership History Alaska Natural Gas Transportation Act authorizes the President to select amore competing pipeline propasals President Carter selects 2 project, the Alaska portion of ‘which was to be built by Alcan Pipeline Company. + To be privately financed + Equity investment to be at risk 4 = Consumers would not bear the risk of non-completion ‘Managing partner and operator Northwest Alaskan Pipeline Co, withdraws _ FERC issues conditional certificates to the selected developers, including Alcan Alcan, renamed Northwest Alaskan Pipeline Company, Only partners left are: forms ANNGTC Partnership with 5 other companies. = United Alaska Fuels *+ Original partners include United Alaska Fusts + TransCanada Pipeline USA, Ltd. Corp., which was later acquired by » Transtanada subsidiary Partners contribute = $200 million in equity capital * Undertook pretininary work = Obtained federal rights of way + Obtained Clean Water Act permits + Applied for State permits and easements + Entered agreement with 3 ANS producers (later terminated by the producers) Project founders; partners begin withdrawing, ETA) USP PERL BESTE CCE OER Ene eed eky 1 Dees Ue) Us) Partnership Agreement § 4.4.4 Withdrawn Partner Payments ALASKA NORTHWEST RATURAL GAS ORTATION COMPANY GENERAL PARINERSHI? AGREDCNT 31,2978) Contingent Liability * 2007 Partnership Report to the FERC indicates that the contingent liability to Withdrawn Partners were = $9 billion as of December 31, 2006 * > $2.6 billion owed to Withdrawn Partners that are now TransCanada affiliates * Vast majority of contingent liability represents return on “funds used during construction” at 14% per annum ANNGTC and AGIA * The ANNGTC Partnership chose not to submit a proposal under AGIA * Two TransCanada subsidiaries submitted a proposal conforming to AGIA requirements: — TransCanada Alaska Company LLC — Foothills Pipe Lines Ltd. Neither was a ANNGTC partner * AGIA line does not use ANNGTC assets, right of way, or FERC certificate, is not the line the President selected in 1997 6 The Contingent Liability is NOT the Debt of the AGIA Applicants or Their Parent * Contingent Liability is the debt of the Partnership, not individual partners * Unlikely that New York law would put that burden on the two remaining partners ¢ Under Delaware law, the TC AGIA Applicants and their parent are legally separate from their affiliates in ANNGTC Partnership * “Piercing the corporate veil” is difficult Sempra Energy Letter to AK Legislative Budget & Audit Committee 4s “...we are unaware of any obligation under the ANNGTC General Partnership Agreement that is being violated by TransCanada.” Third Parties Have No Exposure for the Contingent Liability * Joint venturers do not assume the debts of their partners (assuming the TC AGIA applicants have any liability) * No tort liability unless third party found to have caused TC AGIA applicants to violate duties * Claims so weak that anyone asserting such liability may be guilty of tortious interference with the AGIA project Partnership Agreement § 4.1.4 FERC Approval and Capital Accounts 4.1.4 Qualified Expenditures, and the value of “1 assets generated thereby, shall be subject to review and _| Verification by the FERC, and only those expenditures, and the values ascribed to such assets, found by the FERC to reflect reasonable and necessary expenditures, prudently incurred, shell be retained in the Capital Accounts, and tk} then only to the extent that FERC authorizes the inclusion "| thereof as a capital expenditure appropriately made on : 7 behalf of the Pazcnership for inclusion in rate base Any disallowance by the FERC of an emount included in any Capital Account under Section 4.1 shall be reflected forth- | with in retroactive adjustment of (i) the Capital Account ['""* j from which such amount was so disallowed and (ii) all other . Capitel Accounts affected by such disallowance in accordance with this Agreement FERC and the Contingent Liability * Virtually all the ~ $9B Contingent Liability is 14% return on “funds used during construction” * There has been no construction of a ANNGTC (Alcan) pipeline * The Partnership funds have not been used during construction ¢ At most, the Contingent Liability that FERC would recognize is the original $200M investment < 1% of the AGIA project budget = 40% owed to TC affiliates 11 Ways to Reduce Uncertainty * Initiate a FERC proceeding to determine what amount, if any, of the Contingent Liability FERC would approve in the TC AGIA rate base * TC could file a declaratory judgment action in state or federal court against ANNGTC Withdrawn Partners to determine what, if anything, is owed them if TC builds the AGIA pipeline * ANNGTC could file for bankruptcy to determine liability, if any, to Withdrawn Partners + Joint venture and other agreements with TC _ Applicants can be drawn to insulate third parties from liability 12 a Allan Van Fleet GreenbergTraurig # Recognized nationally and internationally as antitrust and business tort litigator Tortious interference/fiduciary duty cases: — Pennzoil v. Texaco — DiPortanova v. Quintana Petroleum Antitrust cases (plaintiffs): — Sun Microsystems v. Microsoft — Cyrix v. Intel — Jindal Steel v. U.S. Stee/ — General Atomic v. Gulf Oil Vice Chair, American Bar Association Section of Antitrust Law (nominated; will become Chair 2010) is Legal and Political Factors Affecting Producer Participation in a TransCanada Project LNG Pricing in Asia Dy ve LNG Prices May 2008 Presented by Rob Shepherd — Senior Associate Gas Strategies Consulting ») Key messages = Gas Markets Regional not Global = Spot LNG Market too thin to support new investment = Asian markets normally provide premium prices = Asia dependent on LNG = Prepared to pay some security premium to lock in volumes = Relativity to HH very volatile = Premium Limited by Spot LNG Movements = Which are Growing = Asian Prices Linked to Crude Oil = Each contract has its own price = Can only be revised at approx 5 year intervals = GS Scenarios based on likely market in 2015-2020 © Gas Strategies Consulting 2 LNG pricing is dominated by 3 regional markets, f each with its own regime Three Basic Regimes USA — Henry Hub : Secmsanie ae Europe — Oil Linkage for Long-term Products or Brent LNG contracts Linkage Asia — Crude Oil Linkage yt <= «Rigid tong term contracts | =Very minor variation between contracts - re eLNGeasilydivetedto © iS —— approx. res - - NBP market in UK nae ‘ arts] ” Each contract has its =Emerging north west ~ awn price hubs, still immature; TTF “= © Gas Strategies Consulting ‘Spot/Short Term: LNG Spot Market is Very Thin- = Setmutmr gz (2d. Often above contract prices ™ “ Crisis of Winter 05/05 | Asia must pay 2 premium Sporadic spot cargo imports from AB are related 8 a ner NYMEX HH Japanese LNG oortract average Korean LNG comract serage © Japanese © Korean a Tabanese New Kogas Formula ww Gas OUaegIes Vonsuluriy Asian contract prices normally sit above HH; market A now more interconnected with greater volatility Asia markets provide higher prices “Asia dependent on LNG “Prepared to pay some to lock ‘apart sega 10 to Relativity to HH very volatile | ae | Price convergence *LNG can be moved out of US -Asia— premium market (not as easy as US — low price -Crude off ave 1979-98 = $23/pbI Source: Gas Stratagies Consuting © Gas Strategies Consulting NY Asian Premium is limited by growing flexible supply = 2007 US supply 16 mtpa 50 mtpa of new supply for US, UK under construction Can potentially be diverted to Asia » US, UK Markets liquid = (Unlike Asia to US) = Shipping and contractual constraints Some Asian Premium will remain driven by security concerns © Gas Strategies Consulting Asian contracts have Crude Oil Linkage, where most existing contracts have Japanese ‘S’-Curve Price Formula = Each contract has its VA ICC = s20/bbI own price = Linked to oil = Quite similar when market is stable = Basic Formula 1986 - 2000 P=0.1485JCC +A A between $0.7 and $0.9/MMBtu m= ‘S’ Curve protects Pende against low oil price in $11 $15 $24 $23 — Applicable Range — exchange for upside = Most contracts still of this form © Gas Strategies Consulting 7 Rapid market changes lead to scatter of prices and renegotiation 2001 - 2004 Over 10 liers and potential producers were offering s supply Buyers achieved lower a reduction in the oil price linkage Price ceilings at around $25/Bbl oil prices in some contracts Rest as much lower LNG al oil prices innew Pontracts LNG Price in $IMMBtu 2005+ Retum to “sellers’ market” has strengthened position of producers Qatar has Pushed the LNG price to crude oil at $100/BbI oil in its most recent deals Wide scatter of price Opened up by the sudden rise in oil price Virtually all legacy contracts renegotiating © Gas Strategies Consulting Gas Strategies Scenarios - Base Case Scenario sees an easing in the tightness of supply ny AW Asia demand vs contracts and renevels Rising gas and LNG demand will continue Rate of growth depends on economic activity 3” = Main factor affecting price will be the availability of supply Scenarios primarily based on differences of supply in relation to demand Pricing in different scenarios reflects experience of contract pricing over last 20 years © Gas Strategies Consulting 2 a & a & g & 3 & MEAL Acls Exctng Contract mmm AMAsia indonesianshortiat 0» Monte Carlo new supply g g § Alfela Renewal 200 014 200 Aipsia Demand Moderate easing of the current tight market Supply and demand balanced Continuation of long term contracts linked to oil Reversion to traditional formula P =0.1485 Oil$/bbl) +09 Removal of “S — curve” Short term cargo prices vary according to current conditions ny worldwide Supply severely constrained Asia Pacific pays a premium price to secure supply Long term contracting prevails Current oil price parity continues P= 0.162 Oil($/bbl) +1.0 Removal of “S-Curve” Short term cargo prices vary according to current market conditions and tending to be above long term prices Weak economic growth and decline of LNG production costs encourages LNG development Relative excess of LNG worldwide USA is market of last resort therefore LNG priced to compete against HH as the alternative — adjusted for freight P=09HH-05 Market more liquid Long term contracts prevail in Asia but short term volumes are increased. © Gas Strategies Consulting High Case Scenario sees supply severely constrained / Low Case Scenario sees relative excess of LNG AiLAsis Demand pecbabie orty ” eueees ¢ Boa & & & € & & 2 & 3G mer cone ve romans nes Prat re To “oe rae MET An Dera Total Derandfind other Asia/WNA) = wo wo 7] i *| - Sooo as iis : a #2 @ @€ §€ #€ &€ § € Bg ® #8 &@ & &8 & & 8 & 8 mor Coceaceed MELT Cornacsice Avia Protubia re AP Teal ‘7 Prova ere ME Total he es AP Toa Poste Mew ME td Souci Rew AP Teta Spaniatve tea ME Total) —Onerand Valdez Netbacks from Scenario Prices, gives reduction in premium by $1/MMBtu Scenario Real Netback Prices © Gas Strategies Consulting LNG Project Costs Alaska Gasline Determinatio Public Forum Sheraton Hotel, Anchorage May 28-30, 2008 LNG Cases Case 1a - 2.7 bcf/d to Valdez - 48”/42” pipeline Case 1b - 4.5 bcf/d to Valdez - 48/42” pipeline Case 1c — a 1.8 bcf/d expansion of Case 1a (to a total 4.5 bcf/d) after 5 years Case 2 - TransCanada’s Y line - 6.5 bcf/d to Delta Junction, 4.5 bcf/d to Alberta and 2.0 bcf/d to Valdez - 48” pipeline to Alberta and 30” pipeline to Valdez Case 2a — Same as Case 2, but the pipeline from Delta Junction to Valdez and the LNG plant are delayed 5 years Case 3 - 4.5 bcf/d to Valdez - 48” pipeline — PRIMARY COMPARATIVE CASE LNG Analysis Assumptions/Methodology LNG facility located at Valdez Pipeline route follows TAPS Rich gas case — no NGL extraction Volumes to Valdez = GTP outlet less pipeline fuel — no in-state delivery GTP and pipeline schedule and cost factored from TransCanada’s proposed project LNG Analysis Assumptions/Methodology LNG costs developed from factoring recent worldwide projects Miscellaneous and development phase costs factored from TransCanada application analysis All costs in 2007 dollars Start of LNG project one year later than TransCanada project AGIA LNG Options Cost-Risi Profile for LNG 3: 4.50 befd (48°) Oevelopment Phase 500 600 otentisi Quicome SMillions AGIA LNG Options et-Risk Profile far D oct (48° Gas Treatment AGIA LNG Options k Profile for LNG 3: 4.50 befd (48°) P to Deita Junction Pipeline AGIA LNG Options Cast-Risk Profile far LNG 3: 4.50 bcfo (48°) Delta Junctian to Valdez Pipeline AGIA LNG Options Cost-Risk Profile for LNG 3: 4.50 befd (48°) NG Plant 20,000 25900 sop00 Potential Qutcome $Milliors LNG Plant Cost-Risk Ranges | LNG P25 Value (75% probability | P75 Value (75% probability of Cases | Volume of exceeding value) not exceeding value) T | 19 mmtpa $10.8B $17.6B 2.7 Bcefiday |} i Son ea en Sees (2.45 befd) 568 S/T | 926 S/T + 2.7 Befiday 31.5 $17.4B $27.9B Expansion [| TT ea —— = Option (4.06 beta) 552 S/T 885 S/T Y-Line 13.9 $8.1B $13.7B epton (1.79 befd) 582 S/T 985 S/T 31.5 $17.4B $27.9B 4.5 Befiday + | (4.06 befd) 552 S/T 885 S/T LNG Facility Cost Comparison Project | Project | Project Output (mmtpa) Facility Costs ($8) Original $/mmtpa (Original) $/mmtpa 2007 $ Alaska e (1) Includes liquefaction, storage, and shippingterminal (2) Adjustments include Location, Productivity, Escalation to 2007, Winterization, Removal of NGL facility LNG Facility Cost Comparison ¢ LNG liquefaction facility cost was decreasing due to economies of scale from 1997 $250/mmtpa to 2003 $95/mmtpa * Since 4 Qtr 2004 dramatic cost escalation based on commodities/installation cost increases and demand for LNG facilities * Base input at best case P5 $350/mmtpa to worst case P95 at $1250/mmtpa ¢ Base mean value on adjusted basis approximately $800/mmtpa AGIA LNG Options Cost-Risk Profile for NG 3: 4.50 befd (48°) integrated Propubi 40,000 50,000 ential Quicome SMillions AIGA LNG Options | file for LNG 3:4 e nt Phe Development Phase | Developm ent Phase Finish f Regulatory (FERCIRCA) Approval (CPCN} I I Binding LL Open : | I 4 1208 1B IAD ANAT 12N2 1ANI 1MAd IANS WANS WA? 1AM 1AM 1RA@D 1AM 1AR2 Ine AIGA LNG Options Model Profile for LNG 3: 4 5¢ $35 Treatment Plant 1203 1109 INNO 1AN1 1092 14N3 IANA IHAS ORB TANT 1AM’ IANs tan IMM 1n22 1A03 AIGA LNG Options el e ING3 4 GTP to Delta Jet Pipeline Gas (4.80 BCFD) +—t t Delta Jct to Valdez Pipeline Gas (450 BCD) AMO ANT 12N2 1AN3 1AN4 TANS 1ONB InAT InAs IMAG AIGA LNG Options Model Profile tor LNG 3: 4 NG Plant } LNG Fourth Gas |} (4aogero in [ I LNG Third Gas @20ECFDIn LNG Second Gas (2208CFD Im eae el LNG First Gas {1.10 8CF 0 inp T | a ret pop t 10% | oO 12M 110] 1MAO IAM1 12N2 INI IANS INNS 1OMe INAT NAB 1ANG 10m 1AM 11M AIGA LNG Options ‘ file for LNG 3 snes NDOT DN tS ene INT oe 1G AIGA LNG Options LNG 3: Pipeline: aa Deena FOURTHGASFLOW Pipeline: (4.40 BCFD) DeltaJctto Valdez 4.50 BCE } THIRDGASFLOW 8.30 BCFD} LNG Second Gas anne SECONDGASFLOW (2.20 BCFD) LNG First Gas {1.10 BCFD) uasieeueaeentamneneenienss | GTP Second Gas | (4.50 BCFD) LNG Fourth Gas (4.40 BCFD) FIRSTGASFLOW (1.10 BCFD) GTP First Gas @.25 BCFD) LNG Third Gas (3.30 BCFD) 12723 Natural Gas Exploration Potential in the Alaskan Arctic Natural Gas Exploration Potential in the Alaskan Arctic Bob Swenson - State Geologist Dave Houseknecht - USGS Gil Mull photo Stratigraphy — Known & Potential Source Rocks CENTRAL NORTH SLOPE STRATIGRAPHY sw Gubik Fm. eee | ae Wa) eI] t 2 = Hue Shale < Seabee cretaceous 10- racecar < GRZ (HRZ) JURASSIC pe mel mate fA < Shublik BEAUFORTIAN TRIASSIC PERMIAN bd ; PENNSYLVANIAN = < Lisburne (Kuna) MISSISSIPPIAN Geer < Kekiktuk ELLESMERIAN PRE- MISSISSIPPIAN FRANKLINIAN < MEGASEQUENCES) = * Allochthonous rock units Nonmarine J Marine slope & basin Hiatus or erosion [J Granite Marine shelf Condensed marine shale [fj Metasedimentary [jj Carbonates SOUTH Brooks UPLIFT & COOLING NORTH SLOPE Prudhoe Bay Elevation (km) pre-Mississippian (deformed) DEEP BURIAL Cretaceous-Tertiary Modified from Bird and Bader (198 400 km / 250 mi Foothills Cross Section - Oil and Gas Shows Paul Decker, DOG Source Rock & Hydrocarbon Characterization Synthesizing a decade of organic geochemical analyses and integrate with regional geologic data Characterization of hydrocarbon occurrences Locations of Porosity and Permeability Outcrop Samples 1999-2002, Brooks Range Foothills and North Slope, Alaska boa o Maik avien ~ Crooies Sampled Unis A :Sctrager Bist Fomation Torok Formation tuk Formation @ Tuvak Formation © Fortress Min Formation WStsikpuk Formation BNanusnuk Formapon @Pcooviestone Sanastone @usdume Umestone © Gteas sanastone (A Orpiouak Formation Figure 1. Satellite image showing locations and g c formations of porosity end permeability samples from 1999-2002, Brooks Range Foothills and Alaska of outcrop samples trom North Slope, Alaska Siksikpuk O Torok ALisbume * Otuk x Cobblestone © Schrader Bluff + Okpikruak A Fortress Mtn OGilead * Nanushuk = Tuluvak ey en sete Retr oI) a FE perce) peg EIEYIN |= hy aeoros li leect=b< Boake) | 910] (oL-To ML -ble] [OL Buidde;- o1Bojoasy sbuey syooig reas werddremempr tg sturine 9 venue vane ENO anu 0 were van 0 husestodo) ous veten voomaey nee ay sy Ayo sno won Ye hase, amen: a oom g wees ogee y umunow wane IES CMe aL Cos Le Mole bor sItM ULV CWC BOM PMslellUl Sit Le lele) Urey bI-sTUL-Jet] oye) Ulos tor DU LC MigleL dels U Shen oe MDL lel L el Ayunyew jewsay) MO] JO 8UOZ WUYUOD eyep yoeJ} UOISSI ei 0 To] belts ted bo 1-2] ab tel ab hg ol Fol 8] 71-28) elUiTeyTiat=] Ui E1=3= R-] TIP ese merle plaleloy 24} JO AlO}SIH UOI}eWINYXy pue jeiing jeuolbay A at ns oe Wyoming Gas Reserves & Production History Wyoming Gas Reserves & Cumulative Production 1977 - 2006 Q o gQ o addition of “unconventional” continuous-type resources eos o mostly conventional resources Cumulative Production Gas Volume (trillion cubic feet) nN wo ° Oo —_ Oo Proved Reserves Data from EiA 4980 1985 1990 1995 2000 2005 Year Undiscovered Conventional Gas Potential Mean Estimates of Undiscovered, Conventional Gas Resources Digital Shaded Relief Map of Alaska and Adjacent Areas ‘of Canada and Russia Known Gas Accumulations in Arctic Alaska Other Known Accumulations ™ Possible Gas Reserves (BCF) Onshore Known Reserves at : Gubik 600 Prudhoe Bay —24,526 : : ih: Square Lake Pt. Thomson 8,000 i Meade Pt. Mcintyre 1,526 3 é Umiat Kuparuk River 1,150 » ET Foye 2 East Umiat Duck Island 843 East Kurupa North Star 450 exer Kemik Colville River 400 — Wolf Creek Barrow-Walakpa 34 Milne Point 14 TOTAL 35,417 Data from AK-DOG Annual 2006 Rpt. Data from Thomas et al., 1996 (DOE) & Sherwood, 2004 (MMS) 2008 (USGS) 2006 Proved Gas Reserves: Top 15 States - OCS Region n Oo AK-DOG Arctic Alaska Gas Reserves 35.417 TCF North Slope Reserves not reported by EIA 26.857 TCF b o North Slope Reserves reported by EIA 8.560 TCF EIA Alaska Total 10.245 TCF North Slope acilities reserves” 8.560 TCF* Cook inlet 1.685 TCF* nN ao o o Proved Gas Reserves (trillion cubic feet) 3 0- L Arctic Alaska “stranded” reserves Data from EIA & ARDOG Alpine Play in NPRA — More Gas than Oil??? _ ~500 mmbo 1700 bopd ee Ne] rane ely +17.4mmcfpd | GOR 840 lobe i No Gas Cap VV aK | No Water Leg | exe) +6.8 mmcfpd B 60° API eee | or Oil + Gas PoReye at: Burger Prospect Nanushuk Fm. BURGER CONDITIONAL* DISCOVERED RESOURCES-YEAR 2000 Pool Area | Gas Resources (Tef) I Condensate] (Mmb) Fill Model | (Acres) | 05 2 | F95 Minimum _ | 2 | | 107 203 199,803 | 8496 | 27472 | 63.210 | 371 ‘| *No geological risk has been applied to these gas resource estimates. Success factors associated with reservoir presence (0.90) and sufficient (>10%) porosity for productive reservoir formation (0.75) yield an overall geologic chance of success of 0.675 for Burger pool discovered resources. Risked mean gas resources for the 2000 assessment would then be: 5.150 tcf (minimum case); 9.476 tcf (most likely case); and 18.544 tef (maximum case). Risked mean NGL liquid resources for 2000 would be: 265 mmbo (minimum case); 489 mumbo (most likely case); and 948 mmbo (maximum ¢; Miles from West End of Line “Unconventional” Gas Resources (continuous resources) OTs eb atte Basin-centered Gas baht lee} x4 Tf 4 Chukchi Sea Potential for Undiscovered Petroleum in Arctic Alaska Mean Estimates of Undiscovered, Conventional Natural Gas in Arctic Alaska (trillion cubic feet) Non- Associated Associated Total te Resources) Gas Gas Gas ae Onshore & State Offshore Areas (USGS estimates) NPRA 61.35 11.68 73.03 Central North Slope 33.32 4.20 37.52 ANWR, 1002 Area 3.84 * 6 8.60 Subtotal 98.51 119.15 le) Sources: OCS estimates from MMS; onshore & state waters estimates from USGS Pipeline Expansions Pipeline Negotiations and the Role of FERC Pipeline Negotiations and the Role of the Regulators Alaska Gasline Determination Public Forum May 28 - 29, 2008 Discussion Topics + Brief overview of the negotiation process for building a major pipeline project * Role of Federal Regulators ¢ Federal regulators will not always take care of Alaska’s interests * TransCanada’s proposal is an “opening offer” and will be negotiated * Successful project will require a fair allocation of risks, costs and benefits * Conclusions Overview of the Typical Process for Negotiating Transportation Contacts for a Major Pipeline * Pipeline sponsor will identify a potential project and market + Begin technical work on the proposed project which increases as it becomes more real * Significant negotiations begin with potential shippers/customers — Technical work is refined based on customer feedback — Preliminary rates and terms for transportation service developed * Non-binding Open Season is often conducted to provide equal access to all interested parties— more negotiations + Binding open season to secure firm commitments * Precedent agreements and ultimately firm transport agreements Role of the FERC/NPA/NEB «+ What the Regulators do — Review and approve open season procedures — Administer the environmental review process — Hold pre-filing conferences for interested parties — Approve the certificate application — Monitor construction process — Resolve disputes after pipeline goes into operations + What the regulators don’t do — Control or limit costs — Set terms for contracts between the pipe and shippers — Establish key components driving rates (e.g., capital structure) — Establish deadlines Regulators Won't Necessarily Be Protecting Alaska’s Interests ¢ Won't ensure physical access and expansions for new shippers * Will only establish conventional recourse rates unless presented with innovative rate methodologies like: — Levelized rates — Term-differentiated rates — Capital structures — Cost overrun recovery mechanism — Federal loan guarantees to cover cost overruns * Won't impose project deadlines Regulators Won't Necessarily Be Protecting Alaska’s Interests (cont'd) « ANGPA “mandatory expansion” provisions risk litigation, delay and uncertain outcome. (Separate breakout presentation). + FERC Order 2005 does not mandate that: — Sponsors conduct open seasons for the project by any date certain: — Sponsors hold subsequent open seasons to test market demand for new capacity; — Sponsors expand to meet new demand in reasonable engineering increments with commercially reasonable terms; — File for certificate approval or accept certificate; — Sponsors propose rolled-in rates for expansions. — Project rates be lowest possible (70/30 debt/equity structure) TransCanada has committed to all these. TransCanada’s Proposal Will be Negotiated ExxonMobil characterization as an opening offer Context for evaluating their proposal — Negotiations and agreements with multiple shippers with different interests — Approval by the regulators Importance of long-term firm contracts means the producer/shippers will have considerable bargaining power Denali provides additional negotiating leverage Process will take time and a lot of give and take Major Risks Capital costs and potential overruns Gas reserves/production for the pipeline — Development costs — Within economic reach of pipeline Gas prices in Alberta and U.S. Schedule delays and attendant impacts on costs — Pipeline and GTP — Development of reserves “~ * Equity participation by the . shippers + Negotiated levelized rates ° + Adjustments to ROE’s for cost overruns + Recovery of cost overruns tied to minimum market prices for gas + Federal loan guarantee * Bridge shipper concept Opportunities to Share Risks and Move the Project Forward Terms proposed by TransCanada: Additional terms that may be considered: Improvement in terms offered by TransCanada Depreciation rates and contract terms Project milestones and triggers with termination rights with negotiated sharing of costs Additional risk sharing on cost overruns legislative actions Conclusions * Unique project with a long history of regulatory and * Regulators have an important role but they won't necessarily provide the best outcome for Alaska. + With the requirements of AGIA, the negotiation process between the producer/shippers and TransCanada will provide the means to accomplish the State’s objectives * Process will take time and a lot of give and take 10 Pipeline Project Finance Pipeline Project Finance Breakout Session #1 and #2 May 28, 2008 4 gogman] Project Financings are Common in the Energy and Oil & Gas Sectors Amount Borrower Name Project Nume {Sim} Country Sector Finuncial Close Emirates Aluminum - EMAL Abu Dhabi Aluminum Smelter $7,050 ‘United Arab: Processing Piart 12-Dec-2007 Emrates Qatar Liquefied Gas Co Ud Qatargas 4 ‘6714 Qatar Oil Refinery 30-Ju+2007 (Qatargas) V JUNG and LPG Plants Fujian Refining & Fujan Refining and Ethylene 5,600 China Petrochert 6-Sep- 2007 Petrochemical Co Lid- FREP Joint Venture Project Chemical Plant Qaaum Qatar Aluminum Plant 4733 Qatar Processing Plart 23-Aug-2007 Red de Carreteras de FARAC Toll Road PPP 4,280 Mexico Road 27-Sep-2007 Occidente Ambatovy Minerals SA Ambatovy Nickel Project 3,700 Madagascar Mining 22-Aug-2007 Tokyo Crimson Energy Mirant Acquisition: 3,678 Philppines: Power 7-Jur 2007 Holdings Corp (Miran) Bombela Concession Co Pty Gautrain Rapid Rail Link 3,630 ‘South Africa Rat infrastructure 25-Jan-2007 Ltd Yucpa Finance BV ‘Western Energy Development 3,500 Venezuela Oll Refnery 21-Feb-2007 ‘and Anaco Project - PDVSA LNG andLPG Plants Jubail Power & Marafig WPP 3,500 ‘Saudi Arabia Power 14-May-2007 Water Co Source: Project Finance Magazine March 2008 Ieee emeeteaeneemeeteememen meetin comercial Project Finance Loans are Based on a Complex Set of Contractual Arrangements @ Ina project financing, the lender's source of repayment is limited to project revenues and assets Prerrae% ota neni a gman} ~=Project Finance Investors a Limited Appetite for Certain Risks Projectinvestors Generally Lenders will take ttmited completion risk — construction risk typically mitigated through combination of oak at strenght of — Strong EPC contracts (fixed price, date certain, tum key contract) that includes Iqudated damages with creditworthy contractor eee — Substantial project contingencies included in contract price downside nsk — Owner / sponsor pre-completion guarantees — wil repay debt if project not completed analysis — Independent engineer's strong involvement to insure that project is buft on budget and on time - Report demonstrates viabilty of project budget, schedule, technology and cost - Has oversight limited approval role during construction Lenders will want to insure that ail funding needs are provided for — Project funding is fully secured via equity commitments, project debt funded and / or bank commitments, — Offtake or capacity contracts in place with limited outs in order to obtain financing — Independent feasibility study demonstrates viable relationship between project revenues arising from contracts and the costs of the fully funded / committed capital structure = Lenders will assess operating risk as part of the overall project - seek protections from revenue interruption — Strong, creditworthy operator with direct experience — Ability to replace operator with a “qualified operator” — Limited force majeure — Insure everything commercially insurable ~ casualty, earthquake, terrorism, business interruption — Limited planned outages — Project operating and debt reserves = The project credit will be based heavily on contracted cash flows — Strong, contracts with creditworthy oMtaker — Price and volume contracted — Lenders will give limited credit to uncontracted cash flows unless there is strong market demand — Ability for market to absorb supply (market consultant study) godman) ~=TransCanada Alaska Pipeline Proposal Project Finance Credit Summary Credit Factor ‘Typical for Investment Grade ‘Trans Canada Proposal Spewort 18 Strong pijedt sponsor() with project exes (+) TransCanada — welleapitaid, highly expest sponse and finial eqerience ‘wath arong mostire: to complete promect (9 Highly red /tongfimmcials (9) Mos Biely ote equty puticipants ar fnancally tang producers Reserves /Gas Supply Divernfied rapply with proven mverres (+) Protos Bay ald mos cutai but lime life (© Managuble acl predictable oats © prodice Pot Thompson moataiey Solid YTF prompects ($4) Consensus om sabstatia! YTF volumes Come ruction and © Masuguble wed predcble entrcton poem +74, Scope andcomplenty of pact withoa! precedent Comoletion Rick ‘teclmology, hedale CO Contanetion amracramant and scale moet iealy wala oot ‘© Ovemun and delay risk mitigated aoagh EPC cotract, ‘rankey EPC approach sponsor guanatas, ee. © No monsorcompletion guarantee () Federal low: Guaratee over faciliy (+) Sponsor financial meetives to complete on budget Oak Contract 18 Shp or pay contract wath moestment Gade oF ad (@)——- Most ly shippers are ray soon ond Rates cekunced shippers (+) Proposed terms, to extent detailed, provide solid source Lintedoats of wcurty 18 Rates adequiteto covnr debt with covamge and targeted ety eral (Cas Met) Nethack Rick @ Indepandent fuasiiy tudy nerews capacity of maskel to () Neth Ameria made tenendouly divese with laree _rotb new sapply and veres pres wed i pect capacity absosb sappy feasbilty mals ()—_Nelback risk resto asmaming capital and fuancing costs do rot nbstartially iemase Finwes Plan ‘8 Mima equity 209% — mom equity viewed as trench (9) 70th dae 150% equity during contraction (8 Full prope funding obtamed or commited ut cbsing () Federal Lows Guarartoe 1 Adequate contingwces and over facilities MRedaces captalcost 1 Debt eserves in pice daring opemticns BO ven facility 1 Appopnite soocture Sreficert musket arcing (2) Shappar wath strong undying credits 1 Sponsor pre-completion guumatee Sian and length of constroction wil test paject fume marlat opacity. Operating Risk (0 Expert opantor wih linied phoned detdowss ©) TraCmuds a teomg operator (© Stomg maine plat 1) Complex opesting eacemnant ‘8 hasurable business iterroption events covered (@)Ponte Regaine (1) Near Moody’s and S&P Ratings Scales Aw Aal Ratings are a relative ranking of ability and willingness to repay . 7 obligations eater trd Prime Grade 4 Key Rating Agency Commentary Regarding TransCanada Moody's ‘Stan: &Poor's Serior Uneecured Rating Outbok a, a Senior Unsecured Rating Outlook eae Key Strengths '™ Predominately iow risk, regulated gas pipeline operations: wih clear focus on gas transmission and power businesses '® Strong competitive position driven by importance of ‘TransCanada's Canadian pipelines in transporting gas out of the WCSB @ TCPL's electrictty generation assets tend to be characterized by etther low marginal cost of production or long-term power purchase agreements with highly rated courterparties @ Stable and predictable free cash flow generation Key Strengths | Bushes profie is “excellent” driven by predictable ‘earnings from TCPL's mature, wholly-owned Canadian and US natural gas transmission systems which are supported bby transparent regulation © Strong compettive position driven by importance of ‘Canadian pipelines in transporting gas out of the WCSB Investments in other pipeline operations provide a stablizing offset to gradually declining eamings trom tradtional pipelines © Consistert free cash flow generation remains @ fundamental Company strength and provides a buffer against cost overruns and other project setbacks Key Weaknesses |= Weak financial profile for the rating category - high leverage criven by deemed capta structure allowed on ‘Canadian regulated pipelines and mitigated by generally ‘more supportive regulatory and business erwrorments in Canada © Long-term decining WCSB production leads to increasing ‘supply risk (may be offset by non-conventional production) | Increasing exposure to power and unregulated businesses that may necesstate lower corporate leverage to offset @ tise in business risk Growing portfolio of projects exposes the company to Increasing levels of execution risk including allocation of ‘management resources, management of construction cost ‘and schedule risks and financing risk Key Werknexxcs = Somewhat high leverage levels although credit ratios remain acceptable for ts ratings '® Increasing eamings volatiity as TCPL purchases power for resale into primariy unregulated markets (somewhat mitigated by forward sales contracts) @ Deciining rate base (related to maturity of gas production in western Canada) and ROE (due to linkage to interest fates) has reduced earnings in recent years '@ Near-term cost and operating uncertainty related to Bruce ARestart ' Moody's has assigned an A2 corporate rating to Trans Canada PipeLines Ltd., which is an operating company and interme diate holding company of TransCanada Corp. The A3 rating on TransCanada Corp. reflects the effect of structural subordination of TransCanada Corp. to debt at TransCanada PipeLines. 7 Cases Under Consideration Proposal Base Case GS and Other Assumptions S Propet Coats © terest Raves © 4% Return on Equty Indicative Capit! © Cost overrunicompiction —-Stuctire fish on shioperstewestors © Vee of Fedora! toan Alternatives to Base Case i | co a © 27 BOF to Valdez 4 5BCF to Valdez © Y Line Expansion of 2.0 BCF to 6.5 Total BCF oma} @ Proposal Base Case: P50 Construction and 10 Year Average Rates/Credit Spreads © Svess Tests: P95 Construction, Base Rates P50 Construction, P35 Rates P95 Construction, P95 Rates Er ets ia Ear Rega iias Base Case ett tas = 408Cr © 20-year Shp or Pay Contracts © 20-076 25 yoo" Depreciation Cases Analytic Scope © Comparative Financal Anaiysss © Comparative Credit Discussion © Feasibity Assessment Key Proposal Assumptions that Impact the Financing Structure ™@ The Project is a 4.5 bcf/day system to transport natural gas from Prudhoe Bay to the Alberta market hub; @ 25-year ship-or-pay contracts with market standard shipper credit requirements; ® Debt is non-recourse to TransCanada (i.e., the debt is ‘project debt’); ®@ Capitalization of 70% debt and 30% equity during construction; ™@ Capital cost overruns to be financed through federally guaranteed cost overrun loans; @ Federally guaranteed capital cost overrun loans to be repaid through shipper surcharge; and @ No project completion guarantee or pre-completion debt guarantee from equity sponsors is assumed. it is important to note that these assumptions undertie all of our conclusions with regards to the Proposal, and unless otherwise noted, any cases based on the Proposal. Sec" Developing the Proposal Base Case Capital Structure Key Drivers Funding Considerations ® Annual Funding Requirements @ Timing of Equity vs. Debt @ Mix of Funding Sources @ Debt Bank Loans vs. Bonds @ Use of the Federal Loan Guarantee ®@ Allocation of Federal Loan Guarantee @ Interest Rate Assumptions Allocation of Funding Sources @ Equity requirement is significant and front a lenders and to ensure investment grade Tatings @ Optimize impact of EES Girertos Guarantee ® Minimize overall 2008 2014 2015 2016 2017 2018 2019 interest costs + fonds eued/ Loans Commiied 10 Summary of Findings Proposal Base Case Is the Proposal Base Case viable from a financing standpoint? @ Goldman Sachs believes that the Proposal Base Case is financeable based on the following — Strength of project sponsor — Strength of prospective shippers — Proposal assumptions regarding contracts and cost over-run surcharge — Federal loan guarantee and cost over-run facility — Financial - Strong debt service coverage - Attractive equity returns - Favorable relationship between gas price forecasts and tariff ® Ongoing considerations — Obtaining shipper commitments — Obtaining federal loan guarantee commitments — Develop strong overall credit package — Strong project finance market 1 Disclaimers The analysis and conclusions set forth herein are based on economic, financial, political, market and other conditions as they exist and can be evaluated on the date hereof, and we have not undertaken to reaffirm or revise our findings or otherwise comment upon any conditions or events occurring after the date hereof. Our analysis and conclusions also involve numerous assumptions and uncertainties, many of which cannot be verified or ascertained presently. Goldman Sachs does not provide accounting, tax or legal advice, and we make no representation as to the appropriateness or adequacy of the information contained herein or our procedures for, and express no view as to, the tax, accounting or legal treatment of any matter. Goldman Sachs and its affiliates, officers, directors, and employees, including persons involved in the Preparation or issuance of this material, may from time to time have "long" or “short” positions in, and buy or sell, the securities, derivatives (including options) or other financial products thereof, of entities mentioned herein. In addition, Goldman Sachs and/or its affiliates may have served as an advisor, manager or co- manager of a public offering of securities by any such entity and/or for any other securities- or asset-related transaction. Further information regarding this material may be obtained upon request. This material provided by Goldman Sachs is exclusively for the information of the Commissioners of the State of Alaska Departments of Natural Resources and Revenue and senior management of the State. In addition, unless indicated otherwise, further use by the State of information and data contained herein sourced to third parties would require approval from such third parties given directly to the State 12 Point Thomson: Resources, Availability, and Effect on Project Economics ee. omaroreeae Point Thomson Reservoir Study eaters 08 and Gas Technolo Purpose / Scope * PetroTel Inc. conducted an independent evaluation of the Point Thomson reservoir to determine the resources contained in the reservoir and analyze possible recovery methods * Two main objectives: — Construct three-dimensional (3D) geologic models to evaluate the proven and potential hydrocarbon resource — Dynamic reservoir simulation to test potential development and off- take scenarios — Determine the impact on ultimate recovery of both gas, associated condensate and oil * Focused on the Thomson sand and does not include resources tested from the underlying Pre-Mississippian strata or overlying Brookian accumulations ‘NATURAL ) RESOURCES Point Thomson Reservoir Study ante Geology / Volumetrics * Eleven 3D geologic models were constructed * In addition to gas and condensate, Thomson sand also contains a thin and potentially discontinuous oil-rim that tested over 182 API gravity oil * No definitive, production test exists in the oil-rim of the Thomson reservoir * Range of volume in the oil-rim varied in the models due to uncertainty of the depth of fluid contacts * Original in-place hydrocarbon volumes from geologic models: * Gas= 8.5-10.4 trillion standard cubic feet (TSCF) * Associated condensate = 490 — 600 million stock tank barrels (MMSTB) * Potential oil (oil-rim) = 580 - 950 MMSTB ‘NATURAL, RESOURCES Point Thomson Reservoir Study Testers OM and Gas Hechotony Reservoir Modeling- Over 70 simulations Cases were run to model different recovery methods including primary depletion, gas cycling, and oil rim production * Scenarios were designed to test and evaluate key sensitivities to recovery method * Well configurations * Operating constraints * Number of development wells ¢ Evaluated impact of variables on ultimate recovery with development method * No physical constraints such as location of surface drill sites and facilities or drilling departures were modeled ‘WaruRAt RESOURCES Point Thomson Reservoir Study Reservoir Simulation - Primary Depletion Primary depletion (gas blowdown) fastest - but recovers the least total hydrocarbons — Up to 70% of gas recovered (6-7 TSCF) with 22 wells in 12-15 years — Condensate recovery is approximately 26% of the in place volume (127-156 MMSTB) — The majority of the condensate is left in the reservoir by condensation below dew point Pressure maintenance required to increase condensate recovery Reduction of reservoir pressure during primary depletion significantly reduces potential recovery from the oil-rim Gas blowdown and sale of the gas can be done at any time after cycling and recovery of the condensate and oil & ‘NATURAL RESOURCES, NATURAL. RESOURCES Point Thomson Reservoir Study Reservoir Simulation - Gas Cycling Maintain reservoir pressure until all economically recoverable condensate and oil are produced Gas cycling applied in the gas cap in conjunction with development and gas injection in the oil-rim Gas cycling for 20 years increases the oil recoveries: Condensate - 76% (370-450 MMSTB) Oil Rim -43% (250-400 MMSTB) Gas cycling for 10 years results in oil recoveries of: Condensate -62% (300-370 MMSTB) Oil Rim -39% (225-370 MMSTB) Subsequent blowdown of the gas cap after 10 and 20 years cycling recovers 57% and 56% (4.8-5.9 TSCF) of original gas in place Point Thomson Reservoir Study Reservoir Simulation - Oil Rim Development Oil-rim not adequately delineated or tested — Additional wells are needed Oil Rim Production: — Would likely require of horizontal wells — Requires pressure maintenance to sustain maximum oil prod ucibility * Gas cycling, direct lean gas injection, miscible gas injection (CO,), water injection or aquifer encroachment — Gas injection helps reduce the viscosity, improve swelling, and mobilize oil — Use of offsite gas, such as waste CO, from Prudhoe, may maximize recovery In primary depletion potential oil-rim recoveries varied from 3-16% (30-150 MMSTB) of original oil in place depending on number of wells drilled * Gas cycling for 20 years could potentially recover close to 45% (250-400 MMSTB) of the in-place volume of the oil-rim Uncertainty in the original oil-rim volume and potential ultimate recovery Delineation of the ail-rim during gas cycling will determine the scale of development bye. — Point Thomson Reservoir Study Conclusions ¢ Primary depletion may recover 6-7 TSCF of gas and 210-305 MMSTB of condensate and oil * Results in the lowest hydrocarbon recovery of a retrograde condensate reservoir * Gas blowdown can be done after gas cycling and recovery of the condensate and oil * Gas cycling for 20 years may recover 5-6 TSCF of gas and 620-850 MMSTB of condensate and oil * Gas cycling may delay gas sales, but can potentially increase recovery of condensate and oil by over 500 MMSTB * Additional wells needed to delineate and test the Thomson oil-rim * Delineation of the oil-rim during gas cycling will determine scale of development ¢ Pressure maintenance required to sustain maximum producibility and recovery of oil and condensate Fe] BUILDING A WORLD OF DIFFERENCE® BLACK & Wa Vkes) Alaska Gasline Determination Public Forum Point Thomson Availability — Effect on Project Economics Anchorage, Alaska May 28-30, 2008 =) BLACK & VEATCH Scope of Presentation and Key Conclusions e Scope of the Presentation: e This presentation examines the economics for the Alaska Gas Pipeline Project without Point Thomson gas e AConservative Base Case of a 4 Bcf/d pipeline and a Low Volume Sensitivity Case of a 3.5 Bef/d pipeline were considered in the absence of Point Thomson gas e Key Conclusions: e Smaller pipeline configurations with a capacity of 4 Bcf/d and 3.5 Bef/d in the absence of Point Thomson gas at the start of pipeline operations are economically attractive for all stakeholders e NPV results are robust to conservative assumptions, including gas price and project costs $70.0 $60.0 $50.0 $40.0 $30.0 $ Billions (2008) $20.0 $10.0 i} Eee 07s. 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 i] 1 Ne aN Producer netbacks positive without YTF gas Revenue vs. Transportation Coss 4.0 Befid (3.5 PBU, No PT) Transportation Costs Revenues nen nennnnsnnsnnsnnnnseesens — — Revenues with No YTF Gas ——+ r a 2020 2023 2026 2029 2032 2035 2038 2041 2044 = = BLACK & VEATCH There is a 13% increase in tariff in the Conservative Base Case AECO Tariff M45Bcfid 4.0Bcfid 3.5 Befld = BLACK & VEATCH State NPV,, at $61 billion, remains very attractive for Conservative Base Case 45 Betid 4.0 Befid 3.5 Betid i] BLACK & VEATCH Aggregate Producer NPV,, at over $12 billion is only 9% lower and represents attractive returns Aggregate Producer NPV. $ Billions (2008) 4.5 Befld 4.0 Befid 3.5 Befid i - F DIFFERENCES Ee e077 V0] Commodity prices and cost escalation were found to be the factors having significant impact on project economics ome s BmeCme Aasurption VUE . ro ute ‘Cost Escalation 0% Copex 5% Opex ; ’ 2% Copex, 2% Opex a Caper : - : Be one UpstreanC apital Costs i Seer eanae { sompecoese i Base Case TransCanada Schedule i ‘pao | p10 i — tain canta Transt anada Capita Cost p10 Pipeline terest Rate: i leon acd i rouse Production Scenatios POUS.SOCFAt NoPT ermey $60 $ $59 $100 $150 $200 Producer NPV» ($Billion 2008) i) Ewe e073. Project economics in the absence of Point Thomson gas were analyzed under various alternate price forecasts $46.00 Wood Mackerzie AECO Forecast $40.00) ew AECO Forecast ——BV Base Case Forecast $35.00 BvPt0 $3000 | —BVP90 ‘Historical 2007 AECO Price with tation $2500 4 -------------- ene n ene e ne ne nee nett eect eee eee enn een: $20.00 4o------nenee ence eee ceeee eect eet eee eee e tenet eeen een yee! Nominal $MivMBtu $15.00 4--------+----enenne ee ne nee e ee eee ence eee $10.00 4 ---------appee ocean SEDO panne ne Smetana See occ ncnnnnenennnnennenneneenenecnsenensesnaccesanscsense 2008 2012 2016 2020 2024 2028 2032 2036 = 2040 2044 ~ BLACK & aio] Producer NPV,, (like State NPV, - not shown) remains positive even in the lowest price case considered Aggregate Producer NPV;5 $20.0. 45 Beffdwith PT 4 Bctd 3.5 Betd $ Billions (2008) a $0.2 Wood BV Mean EIA08 BYP10 BV P90 Mackenzie = BLACK & VEATCH Project Cost escalation assumptions e Baseline cost escalation assumptions: e Operating expenses - 3% e Capital expenses - 4% e Low escalation assumptions: e Operating expenses — 2% e Capital expenses — 2% e High escalation assumptions: e Operating expenses - 5% e Capital expenses - 6% = BLACK & VEATCH Producer NPV,, (like State NPV, — not shown) remains positive even with higher tariffs due to cost escalation Aggregate Producer NPV,; $20.0 $18.0 4---- $16.0 4... $12.0 $10.0 $8.0 $6.0 $4.0 $2.0 @45 Betid 04.0 Befid 03.5 Betid $ Billions (2008) Base Escalation Low Escalation High Escalation 12 wl See Appendix: Key Assumptions Proposal Base Case Conservative Base Case _Low Volume Sensitivity Case Pipeline Capacity 45 Befid 40 Befid 3.5 Befid Start Date 2020 2020 2020 3.0 Befld—PBU;0.9BcfidPT | 3.5 cfd - PBU; 3.0 Beffd - PBU; Production Assumptions — | 0) 5 actid State Existing 0.5 Betid State Existing; NoPT | 0.5 Bcfld State Existing; No PT FT Contract Period 25 years 20 years 20 years Depreciation Life 25 years 20 years 20 years Study Period 25 years 25 years 25 years Capital Cost $2008 billions | $31 3 billion $29.4 billion $27.8 billion Cost Escalation 3% operating costs escalation 3% operating costs escalation 3% operating costs escalation 4% capital costs escalation 4% capital costs escalation 4% capital costs escalation Price Assumption Wood Mackenzie Base Case Wood Mackenzie Base Case Wood Mackenzie Base Case kk. — Point Thomson Reservoir Study Purpose / Scope PetroTel Inc. conducted an independent evaluation of the Point Thomson reservoir to determine the resources contained in the reservoir and analyze possible recovery methods Two main objectives: — Construct three-dimensional (3D) geologic models to evaluate the proven and potential hydrocarbon resource — Dynamic reservoir simulation to test potential development and off- take scenarios — Determine the impact on ultimate recovery of both gas, associated condensate and oil * Focused on the Thomson sand and does not include resources tested from the underlying Pre-Mississippian strata or overlying Brookian accumulations EE L- RESOURCES 7 . =— Point Thomson Reservoir Study abbott OM ane Gk Technet Geology / Volumetrics * Eleven 3D geologic models were constructed * Inaddition to gas and condensate, Thomson sand also contains a thin and potentially discontinuous oil-rim that tested over 182 API gravity oil * Nodefinitive, production test exists in the oil-rim of the Thomson reservoir ¢ Range of volume in the oil-rim varied in the models due to uncertainty of the depth of fluid contacts * Original in-place hydrocarbon volumes from geologic models: * Gas= 8.5-10.4 trillion standard cubic feet (TSCF) * Associated condensate = 490 — 600 million stock tank barrels (MMSTB) * Potential oil (oil-rim) = 580 - 950 MMSTB en LL. RESOURCES . mide Point Thomson Reservoir Study 4 Reservoir Modeling- Over 70 simulations * Cases were run to model different recovery methods including primary depletion, gas cycling, and oil rim production * Scenarios were designed to test and evaluate key sensitivities to recovery method * Well configurations * Operating constraints * Number of development wells * Evaluated impact of variables on ultimate recovery with development method * No physical constraints such as location of surface drill sites and facilities or drilling departures were modeled WATuRAL RESOURCES Point Thomson Reservoir Study Reservoir Simulation - Primary Depletion * Primary depletion (gas blowdown) fastest - but recovers the least total hydrocarbons — Upto 70% of gas recovered (6-7 TSCF) with 22 wells in 12-15 years — Condensate recovery is approximately 26% of the in place volume (127-156 MMSTB) — The majority of the condensate is left in the reservoir by condensation below dew point ¢ Pressure maintenance required to increase condensate recovery * Reduction of reservoir pressure during primary depletion significantly reduces potential recovery from the oil-rim * Gas blowdown and sale of the gas can be done at any time after cycling and recovery of the condensate and oil tae nnn Point Thomson Reservoir Study Reservoir Simulation - Gas Cycling Maintain reservoir pressure until all economically recoverable condensate and oil are produced Gas cycling applied in the gas cap in conjunction with development and gas injection in the oil-rim Gas cycling for 20 years increases the oil recoveries: Condensate - 76% (370-450 MMSTB) Oil Rim - 43% (250-400 MMSTB) Gas cycling for 10 years results in oil recoveries of: Condensate -62% (300-370 MMSTB) Oil Rim-39% (225-370 MMSTB) Subsequent blowdown of the gas cap after 10 and 20 years cycling recovers 57% and 56% (4.8-5.9 TSCF) of original gas in place "NATURAL RESOURCES * Oil-rim not adequately delineated or tested — Additional wells are needed Point Thomson Reservoir Study cts 8 Of and Gas echnciog Reservoir Simulation - Oil Rim Development * Oil Rim Production: — Would likely require of horizontal wells — Requires pressure maintenance to sustain maximum oil prod ucibility * Gas cycling, direct lean gas injection, miscible gas injection (CO.), water injection or aquifer encroachment — Gas injection helps reduce the viscosity, improve swelling, and mobilize oil — Use of offsite gas, such as waste CO, from Prudhoe, may maximize recovery ¢ In primary depletion potential oil-rim recoveries varied from 3-16% (30-150 MMSTB) of original oil in place depending on number of wells drilled * Gas cycling for 20 years could potentially recover close to 45% (250-400 MMSTB) of the in-place volume of the oil-rim + Uncertainty in the original oil-rim volume and potential ultimate recovery * Delineation of the oil-rim during gas cycling will determine the scale of development =. Point Thomson Reservoir Study Conclusions * Primary depletion may recover 6-7 TSCF of gas and 210-305 MMSTB of condensate and oil * Results in the lowest hydrocarbon recovery of a retrograde condensate reservoir * Gas blowdown can be done after gas cycling and recovery of the condensate and oil * Gas cycling for 20 years may recover 5-6 TSCF of gas and 620-850 MMSTB of condensate and oil * Gas cycling may delay gas sales, but can potentially increase recovery of condensate and oil by over 500 MMSTB * Additional wells needed to delineate and test the Thomson oil-rim * Delineation of the oil-rim during gas cycling will determine scale of development * Pressure maintenance required to sustain maximum producibility and recovery of oil and condensate Price Risk and Project Returns 4 BUILDING A WORLD OF DIFFERENCE BLACK & VEATCH Alaska Gasline Determination Public Forum Price Risk & Project Returns Anchorage, Alaska May 28-30, 2008 re} BLACK & VEATCH Scope of Presentation and Key Conclusions e Scope: e This presentation examines the impact to stakeholder NPV from variations in AECO natural gas commodity prices e Key Conclusions: e Commodity prices have a significant impact on State and Producer Economics e Various price forecasts were considered based on multiple industry sources: e Analysis indicates strong economics for State in all the price scenarios considered e Analysis indicates strong economics for Producers in all except the lowest price scenario considered e Analysis assuming flat real prices was performed to understand sensitivity of returns to price levels e Analysis indicates that at flat real price levels between $5/MMBtu and $10/MMBtu, Producers have positive NPVs discounted at 10% and 15% e Range of NPV with price uncertainty show less than 10% probability of negative NPV for Producers and 0% probability of negative NPV for the State i} Eee hse Presentation Outline >» Approaches to Understand Price Risk & its Impact on Project Retums » Alternate Price Forecasts » Flat Price Analysis » Range of Price Uncertainty >» Summary & Conclusions | BLACK & VEATCH $46.00 > - ~ === 7 Wood Mackerzie AECO Forecast $40.00 | __ ew acco Forecast —BV Base Case Forecast $35.00 BVP10 $3000 | —~BVP90 acseontessareersonnenennrnaronen i Historical 2007 AECO Price with ftation & 3 £ 5 z 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 218 Xe eB NE Importance of Commodity Prices to State NPV ‘Sensithine ara tannin . , ; . 7 ‘Commodity Prices: P10 Ps0 ‘Mackenzie Prices Cost Escalation 6% cape 5% opex nce UpstreamC aphal Costs Bese Cone ‘Trans anada Capita Cost menicgaa Pipeline imerest Rate 708% Trans anada Schedule Base Case PBU 3.0 Production Scenarios BOF AL PT Blowdown: $- - im0 - es 7 $609 = 00 : "$100.0 "$1200 "ssn State NPV; ($Billion 2008) BLACK & VEATCH Importance of Commodity Prices to Producer NPV ome BaseCme Qmuantion ' Wood ‘Comm dity Prices: :P10 Mackenzie : Prices: Cost Escalation 4% Capex, ‘Fh Opex Upstream Capital Costs Base Case TransCanada Schedule Base Case Mean Capitel Trans anada Capital Cost Pipeline Interest Rate = : . PBU30 Production Scenarios PBU 3.5 BCFA; NoPT BCFiq PT i = ae eee coe $6.0) $- $50 $109 $15.0 $200 Producer NPV4» ($Billion 2008) @ i=} 0 le € 7 ave Comparison of commodity prices with estimated tariff shows positive netbacks even with the lowest price scenario considered. $45.00 = Nominal AECO Tan ——Wood Mackenzie AE CO Price Forecast ——EIA AECO Price Forecast $3600) vps 0 eeeeeseeesnoe BY PIO $40.00 $30.00 i $25.00 j $20.00 $15.00 $10.00 $5.00 2020 2024 2028 2032 2036 2040 2044 a BLACK & VEATCH State NPV, Remains Significant in all Price Scenarios Considered State NPV, $140 40Bcfid 03.5 Betid $120 $100 $80 $60 $40 $20 Mackenzie @ BLACK & VEATCH Producer NPV,, for Proven Reserves Remains Positive even with the Lowest Price Scenario Proven Reserves NPVio - M45 Befid m4.0Bed 3.5 Befid .......! PAE cag = $ Billions (2008) ~$2.5$2.0 ~~ a $14. Wood BV Mean EIA 2008 BV P10 BV P90 Mackenzie @ LW Neg. VEATCH Similarly, Producer NPV,, for Proven Reserves Remains Positive for All Scenarios Considered Proven Reserves NPV,; $20.0 $18.0 $16.0 $14.0 $12.0 $10.0 $8.0 $6.0 $4.0 $2.0 $- $ Billions (2008) Wood BV Mean EIA 2008 BVP10 BV P90 Mackenzie | BLACK & ave) Impact of Prices on Unproven Reserves — Producer NPV,, is Positive in All Except the Lowest Price Scenario YTF NPVi9 $3.0 45 Betid 40Bcfid 3.5 Bcfid $2.5 go $25 4 $2.0 $15 $1.0 $ Billions (2008 $0.5 $0.0 ($0.5) pereeceseeseseeeeeeeeeeeeeeereeteeeeteeteteeteneeneseetee -($0. ($0.5) ($0.4) ($1.0) Wood BV Mean EIA 2008 BV P10 BVPS90 Mackenzie ma Eee ase Producer NPV... Shows Similar Results to YTF YTF NPVi5 $3.0 H45Bcid §4.0BcHd 3.5 Befid SQL) sb cere scee ce mrsecreeecereserssees tact cence ence cnaenedannrcunecnnnsnenansnsncens 2 SB $1B peconeesnsessseenseesnnsenneecrsneenneonsnnnsoneccnesensssnescuneccnesenecensetnsesueeesnaeecnesenstennesnaete x BD S10 panneeeneneece reece ectencteneentennetnneeunnetnneeuneennenuneetnneennetonetngergeetnnt = $0.3 $0.2 . $05 Jo $0.3 0 $0.4 aot ee : $0.1 . soo | MS men SO $0.0 aon Dy seccccececececentgteeterceeetssceewc acetate ent -($0.3):($0.3) ($1.0) Wood BVMean _— EIA 2008 BV P10 BV P90 Mackenzie a Ere se Presentation Outline » Approaches to Understand Price Risk & its Impact on Project Returns » Alternate Price Forecasts » Flat Price Analysis » Range of Price Uncertainty » Summary & Conclusions 13° = Ene Use Analysis of Impact of Price Levels - Flat Real Prices e Analysis $30.00 = - ~ ] investigated the Real Flat $5 —"RealFlat$6 —~Real Flat $7 —Real Flat $8 —ReaFlat$9 —Real Fiat $10 $5.00 FESS LLLP ELLE PELE L SS impact of price levels on project economics Flat real prices levels from $5/MMBtu to $10/MMBtu were considered for natural gas price at AECO 2.5% inflation assumed to estimate dollars of the day prices 14 | re} BLACK & VEATCH Price levels have a significant impact on Producer NPV. NPV, remains positive with real prices in $5-$10/MMBtu range. Aggregate Producer NPVio $Billion 2008 4.5AECO 4.5AECO 4.5AECO 4.5AECO 4.5 AECO 4.5 AECO $5Real $6Real $7Real $8Real $9Real $10 Real a Ee Bs Producer NPV,, remains positive with real prices in $5 - $10/MMBtu range. Aggregate Producer NPVi5 $20.0 $Billion 2008 $5 Real $6 Real $7Real $8Real $9Real $10 Real a Eee hse Presentation Outline > Approaches to Understand Price Risk & its Impact on Project Retums » Alternate Price Forecasts » Flat Price Analysis » Range of Price Uncertainty >» Summary & Conclusions | BLACK & VEATCH ———e There is significant uncertainty in the fundamental factors impacting commodity prices. A distribution of commodity prices was created incorporating the uncertainty in fundamental factors impacting prices Analysis considered the range of State m0 2s wSSRDs20k—si0HCiHTCC SCC and producer NPV with price uncertainty 18 : . | ew eae Estimated Range of AECO Prices - 2022 X <= $4.54 X <=$16.91 014 80% OH O12 perneeeeee fees MB eee nec cen cce cen ceeceedenenencenceensenceneeseneensensenensencensesensensensesensenssnsensessenten Mean =$9 50 O41 po . a Standard Deviation=$3.95 © ree 0.08 f-----------4 sevcscesscececenscescenseecestensenscenseeeensensteseenscescesenstensensennscassensseaed Proability 004 002 +. feccneenanccnessseccssceenesensssensssssesssecsssssnsseresseneesenueenesenee $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 Nominal $/MMBtu Lei W Xe eA Ne | Estimated Range of AECO Prices - 2030 X <= $7.90 X <= $23.47 oe a 0.09 p= 0.08 +-------- Mean =$13.95 | 007 +-------- iS cececeteeeeeee Standard Deviation=$5.11 00 ------ eee 008 }.---- ae i jon coos 004 +-- err aacenncecbececennsesencssnnesnnesesssesersesancesnsseesseeenssesntsesnsessseesssensesed 0.03 +-- sonst exevert aqnnesaynannanbineanannsinacunsnaenwssisnacbaueshanqecesseas-tnncva=saenessnenll 0.02 0.01 $0 $10 $20 $30 $40 $50 $60 Nominal ($/MMBtu) i] Eee Rae Range of State NPV, shows that there is 0 probability of the State NPV from the project becoming negative despite the uncertainty in prices. DG ome enon =n nnn nnn ras pnanesannnnacnesessetoteetemceceunciae Probability (%) 8 & 40% 30% f--- 3.5 Befid Low Volume Sensttivity Case DOM sscesencpoafecsssncnadacesnsnansencoee, . ——41 Betld Conservative Base Case 10% Pres ~~ +45 Betid Proposal Base Case 0% i i 4 cu $50 $100 $150 $200 $250 $2008 Billions NPV, ) Ee eRe Range of Producer NPV,, shows that there is only about 5% probability of the Producer NPV from the project becoming negative despite the uncertainty in prices. 100% : > — -3. i i ae 5 Betid Low Volume Senskivity Case | 4.0 Befid Conservative Base Case 4 80% - = +45 Bet Proposal B C 70% 60% 50% Probability (%) 40% poo 30% 20% 10% $5 0 6 $10 15 $20 $25 $30 $35 $2008 Billions NPV49 | Eee aus Range of Producer NPV,, shows that there is less than 10% probability of the Producer NPV from the project becoming negative despite the uncertainty in prices. 100% 7— T a 7 : —~ =35 Betd Low Volume Senskivity Case 90% ———— 40 Betid Conservative Base Case 80% f ~ - “45 Betid Proposal BaseCase : 70% +----- eee poop pers deccnccccerheceeeeees ee 5 eon f = = ee i ci 40% 10% f------ i i i 4 “82 $0 2 4 6 # $10 $12 $14 $16 $2008 Billions NPVis5 | Ere 87s.) Conclusions Revisited e Commodity prices have a significant impact on State and Producer Economics e Various price forecasts were considered based on multiple industry sources e Analysis indicates strong economics for State in all the price scenarios considered e Analysis indicates strong economics for Producers in all except the lowest price scenario considered e Analysis assuming flat real prices was performed to understand sensitivity of returns to price levels e Analysis indicates that at flat real price levels between $5/MMBtu and $10/MMBtu, Producers have positive NPVs discounted at 10% and 15% e Range of NPV with price uncertainty show less than 10% probability of negative NPV for Producers and 0% probability of negative NPV for the State 24 @ Prospects for an Alaska LNG Export Project Prospects for Alaskan LNG Presented by Rob Shepherd — Senior Associate Gas Strategies Consulting Asian markets critical in Marketing Alaskan im” LNG = Asian markets are and expected to remain higher priced than US = Alaskan Project is Large by LNG standards = “Y" scheme is 2.0 Bef/d or 13.9 mtpa = 45 Bef/d is 31.5 mtpa = Compare Sakhalin 9.6 mtpa a US West Coast would struggle to absorb this volume = Has inadequate terminal capacity = Jones act issue for shipping = Therefore main target is Asia © Gas Strategies Consulting Asian markets have historically dominated LNG trading and will remain key buyers LNG Trade by Importer 1964 - 2007 m Americas m Europe — China @ india @ Taiwan Korea § Japan > @ nN $ & v & s ed & & 5 & es & ss s s Source: Gas Strategies Consuting © Gas Strategies Consulting i" Leading Asian markets are very dependent a On LNG LNG’s Share of Overall Gas Consumption 100 _ 80 70 60 40 30 20 . il aa 0 = x Percentage of gas consumed a o - vy a & i s & e Y ae oe a ae of Source: Gas Strategies Consutting © Gas Strategies Consulting Japan, South Korea and Taiwan have well established LNG Markets Dominated by Japan = Largest LNG market — 66.9 million tonnes in 2007 South Korea has grown more rapidly = Now 24.5 million tonnes Taiwan has not entirely fulfilled potential = Current take 8.4 million tonnes All currently starved of supply = Indonesian supply shortfall = Some recovery in Japanese growth in recent years = Earthquake damage to Japanese nuclear power = Delays to new LNG supply Currently a sellers’ market © Gas Strategies Consulting ) Tightness in supply has fed supply/demand x gap in Japan, Korea, Taiwan JKT demand vs contracts and renewals amg JKT Existing Contracts mam JKT Indonesian shortfall JKT Renewals —=JKTLNG Demand Source: Gas Strategies Consuting © Gas Strategies Consulting China - An emerging market for gas but price sensitive and requires development Hungry for energy = But has cheap coal = Limited gas infrastructure = NewLNc requires: = New terminals and often: = New transmission and distribution = Conversion of town gas supply One operational terminal = Guangdong = Already being expanded Two more under construction = Fujian = Shanghai 7 others planned © Gas Strategies Consulting Gap requires LNG until 2015 when pipeline sie imports may start to be possible China demand vs contracts and renewals: fmm China Exsitng contracts China Renewals —China demand Source. Gas Strategies Consuting © Gas Strategies Consulting ) Supply to meet Asian gap quite uncertain = Alaska target start date around 2020 = Asia requires about 100 million tonnes new supply by then = 22 newLNG projects announced in Pacific and Middle East = In total about 175 mtpa excluding Alaska Potential for large oversupply? But LNG projects notoriously difficult to develop =» 10 high cost =» 6 using new technology = 6 have only inexperienced partners » 8 are in politically challenging environments (3 in Iran) We have used a monte carlo technique to estimate likely arrival of new supply © Gas Strategies Consulting Announced Supply Arrives Early Total Demand §@nci other Asna/ Wr BLA) 600 = (mmm 4? C ontractec m@mmiE LT Contacsinto Asa =“ te Probable wwe To << Possible NewAP Total 44 ~~ Speatsine NewAP Tot ~~ Speake NewME Toi = ——Dcmand Source: Gas Strategies Consuting © Gas Strategies Consulting i» Best Case supply from Monte Carlo om! analysis g# 8 8 MMB AI Asia ExstingContacts ml Al Asia Indonesian short Al Asia Renevals OC Moate Carb sewsapply — Al/eia Demand Source: Gas Strategies Consuting © Gas Strategies Consulting Main Messages = Asia requires 100 million tonnes of new LNG by 2020 = On our base case there is room for Alaska LNG = This depends on delays to some of the announced projects = These delays are very likely = Market would take about 10 years to absorb 4.5 Bcfid project volume = Smaller projects rather quicker = Sakhalin takes 5 years and is 1.3 Bef/d = Some of balance can be sold in west coast US © Gas Strategies Consulting Pea TSE aa eee. GENIN Tyrael A CALL ne BKC ee eS cueai iit eis 11 51 53 62 68 Commissioners AGIA Training Steering Committee Executive Summary Training Strategic Planning Document: A Call to Action Draft AGIA Training Strategic Planning Document, January 2008 Strategies 11. = Strategy 1.0 Increase awareness of and access to career opportunities in natural resource development. 17. Strategy 2.0 Develop a comprehensive, integrated Career and Technical Education system for Alaska that aligns training institutions and coordinates program delivery. 29 = Strategy 3.0 Increase opportunities for registered apprenticeship in skilled occupations and expand other structured training opportunities. 39 ~=Strategy 4.0 Increase opportunities for development of appropriate training programs for operations, technical and management workers. Inside the AGIA Report AGIA Occupations Educational Training Providers for AGIA Occupations Glossary = <x at a YU oO w oa <x me Ee n Oo = = < pe be <x o <x AGIA TRAINING STRATEGIC PLAN Members and Staff Industry Members Edgar Cowling, Conoco Phillips Dave Rees, BP Dave Matthews, HC Price Tony Delia, Arctic Slope Regional Corporation Bonnie Jo Savland, Alyeska Pipeline Training and Education Members Karen Martinsen, Sitka Education Consortia Mike Andrews, Alaska Works Partnership Janelle Vanasse, Bethel Regional High Wendy Redman, UA Statewide John Hakala, U.S. Department of Labor, Office of Apprenticeship Department Members Commissioner Clark Bishop Fred Esposito, Director AVTEC Greg Cashen, Director Alaska Workforce Investment Board Staff Michelle Unrein, Administrative Assistant Brynn Keith, Chief Research and Analysis Guy Bell, Assistant Commissioner Tom Nelson, Director Employment Security Division Corine Geldhof, Director Business Partnerships Division Mike Shiffer, Assistant Director Business Partnerships Division Consultant and Writer Mary Lou Madden AGIA TRAINING STRATEGIC PLAN AGIA TRAINING STRATEGIC PLAN Executive Summary AGIA Training Strategic Planning Document: A Call to Action The Need: Close the Alaskan Skills Gap Alaska stands at a crossroad of vital need and compelling opportunity. The state is in its twentieth year of steady economic growth with 48,000 new jobs projected by 2014, however in some regions unemployment is among the highest in the nation, and is ranked fifth in the nation for teens not in school and not working. Vast supplies of oil, gas, and minerals make Alaska one of the most resource rich regions in the world, yet the state faces a workforce skills gaps in critical occupations where there are either a high number of non-residents, or a significant percent are over the age of 45. The Promise: Put Alaskans To Work Among the most promising economic drivers is the potential construction of an Alaska gas pipeline, but the state’s workforce preparedness system, including public K-12 and post-secondary education, is not meeting current industry demand. Not to be repeated is the fact that when the Trans-Alaska Pipeline System was built 30 years ago, most jobs were filled by nonresidents; Alaska’s workforce was simply not prepared. Governor Sarah Palin championed the passage of the Alaska Gasline Inducement Act (AGIA) in 2007. The AGIA statute’s call to action is particularly timely as it is widely understood that Alaska’s natural resources must be responsibly developed to the maximum benefit of all Alaskans. The Strategy: AGIA Training To Enhance Existing Programs The AGIA Training Strategic Planning Document is designed to enhance Alaska’s exist- ing training programs so that Alaskans are afforded the opportunity to upgrade skills and acquire new ones in preparation for gasline jobs. The plan identifies four broad strategies to address the workforce needs of the existing labor skills gap and AGIA: 1) increase awareness of an access to career opportunities in natural resource development, 2) develop a comprehensive, integrated career and technical education system that aligns training institutions and coordinates program delivery, 3) increase opportunities for registered apprenticeship in skilled occupations and expand other structured training opportunities, and Zz < a a Ye o w Ee < fe BS n oO 4 2 < fe = < oS <x NW1d JIDALVALS ONINIVAL VIOV 4) increase opportunities for development of appropriate training programs for operations, technical, and management workers. The Plan: Five Years, Three Phases While this document remains subject to updates, the training plan outlines a five-year strategically phased approach for accomplishing its strategies. m= Phase one - establish industry skill standards for training and extend accreditation to regional training centers; m™ Phase two is to address the existing “skills gap” and will require significant new investments in public post secondary training programs with significant expansion of registered apprenticeship programs; m= Phase three will require information on the number of jobs created by the gasline project and focus on training for those jobs. The plan includes the Alaska Department of Labor and Workforce Development Research and Analysis Section's newly identified 113 AGIA related occupations; future updates will feature more precise job projections and a skills inventory and outreach component to the Alaska Labor Exchange System (ALEXsys), supporting gasline employer recruitment and resident hire. The Purpose: Anchored In Collaboration and Innovation The plan’s overall purpose is to bring Alaska into a new era of collaboration and inno- vation among educators and training providers combined with strategic investments in connected, regionally delivered and accredited programs to create world class training and education systems for Alaska. The plan will guide the Alaska Workforce Investment Board about where and how to invest in training. The Call For Action: Engage Stakeholders To Build Capacity The call for action now is to engage educators, trainers, sponsors of registered appren- ticeship, and business and industry in committing to finance and execute the plan's strategies. The results will transform Alaska’s workforce preparedness system, catalyze a spirit of innovation, and ultimately create a new economy, beyond the boom and bust cycle, where new business and industry is encouraged by the state's collective capacity and expertise to train a local workforce. The Alaska Gasline Inducement Act of 2007 requires that “the Commissioner of Labor and Workforce Development shall develop a job training program that will provide training for Alaskans in gas pipeline project management, construction, operations, maintenance and other gas pipeline related positions” (AS 43.90.470). To fulfill this charge, Commissioner Click Bishop sought the advice of concerned and knowledgeable Alaskans in identifying strategies that would best prepare the state’s workforce for the demands of gas pipeline construction. A cross section of industry, labor, education and state government representatives have been involved in the planning effort. A list of participants is attached as Appendix A. Participants in the planning process began with an examination of the existing training environment. They quickly determined that although steps have been taken by both government and the private sector to address worker shortages and skill gaps, the system is not meeting current workforce development demands, much less the added demands of AGIA. Participants also realized that there are other major natural resource development projects underway or in the planning stages—projects that demand many of the same skills needed for pipeline construction. The planning participants concluded that focusing only on a gas pipeline would ignore these larger issues of capacity and competition for workers. They therefore adopted a broader goal for their efforts. Goal: Deliver an Alaska workforce prepared for careers in construction, operations, management and other occupations related to natural resource development including a gasline. m When examining current capacity, participants identified these areas as needing particular attention: m Making better use of current workforce development resources through greater cooperation and coordination. m Recognizing industry's major contributions to worker training and leveraging these resources by expanding public/private partnerships. = Creating better connections between Alaskans and the career opportunities opened up by a gasline and other development projects. AGIA TRAINING STRATEGIC PLAN NV1d JIDALVALS ONINIVAL VIOV The plan presented on the following pages addresses these points. It consists of a set of recommended strategies that, if implemented, will position the state to “grow its own” workforce for AGIA and for other large projects. The suggested activities are not directed specific jobs or occupations. They are intended to build a flexible system of workforce development that can anticipate and respond to a variety of demands and that will serve Alaskans well into the future. Planning participants recognize that implementing the plan will call for significant additional investment by the State of Alaska. In order that this investment yields the greatest return, it must be directed at high need, cost effective proposals. The groups strongly recommend that the Alaska Workforce Investment Board review and prioritize all requests for operational and capital training funds—a role well within the Board's charge of overseeing and coordinating Alaska’s workforce development policies and programs. To fulfill this function effectively, the Board must be empowered and strengthened. This requires adequate budget and staffing, including a full-time AWIB position to oversee AGIA training plan implementation. The planning groups have been guided by the Principles for Alaska’s Vocational and Technical Education and Training System found in Alaska’s Future Workforce Strategic Policies and Investment Blueprint. Participants reviewed and endorsed the good planning efforts that have already been accomplished—for example, the Construction Workforce Development Plan adopted by AWIB in 2006 and the Vocational Education Comprehensive Plan for Alaska developed by DOLWD in 2004—and have incorporated many of the recommendations from these plans. Planning participants also reached consensus on the following points: m Industry employers, trade associations, trade unions, apprenticeship sponsors, local, state and federal agencies and public and private educational institutions all have a role in workforce development. m= Program planners and decision makers need accurate information on employment demand and supply. Preparation of the future workforce must start early in the educational process. Public/private partnerships are essential. Training needs to be based on industry standards. State training dollars should be targeted at programs that meet industry needs and standards, incorporate proven strategies and techniques (“best practices”) and demonstrate measurable outcomes. m Training for the gas pipeline needs to emphasize long-term careers as well as short- term jobs. In addition to the development of a strategic plan, DOLWD has begun building the data foundation for the AGIA job training program. Working with industry partners, DOLWD staff identified those occupations needed in the construction of a natural gas pipeline. In 2006, over 16 percent of workers in these occupations were nonresidents and over 37 percent were over the age of 45 - statistics that point to both current and future skills gaps. (See Appendix B.) Unless these skills gaps are addressed, both sides of the labor market will suffer. Alaska’s employers will have difficulty finding the types of workers they need and significant numbers of Alaskans will remain either unemployed or discouraged. The plan is not complete; rather, it provides a framework for further action. It will be revisited and refined frequently as more detailed information about the gas pipeline and other major projects becomes available. Carrying out the identified strategies will require concentrated effort on the part of responsible parties—the State of Alaska, industry and private training providers. Through this cooperative effort, the planning groups believe that the state can achieve the following vision: Alaskans are trained and ready for gas pipeline and other natural resource development jobs and these jobs are made available to Alaskans. AGIA TRAINING STRATEGIC PLAN AGIA TRAINING STRATEGIC PLAN Industry and the state need to promote understanding among Alaskans about the career opportunities opened up by the development of the state’s natural resources. Further, Alaskans need information on how to prepare themselves to access these opportunities. This strategy can be implemented by: = Conducting public awareness campaigns. m= Developing a comprehensive, one-stop information system on training opportunities and job openings in Alaska. Funding: = Industry m= State general fund & <x - a Vv o w e < fe gE n oO = = < fe e <x oO <x NW1d JIDALVALS ONINIVAL VLOV Strategic Element 1.1 Conduct public awareness campaign Rationale The development of Alaska’s natural resources offers enormous career opportunities for state residents. However, even those most closely involved in workforce training do not have a complete understanding of the employment demands of the various large scale projects that are underway or in the planning stages. Parents, high school students and adult workers have much more limited information on which to base career planning and goals. Action Steps ® Retain professional assistance in crafting a multi-faceted public awareness strategy phased to the development of the gas pipeline and other major resource development projects = Develop communication strategies effective in recruiting rural, Alaska Native and minority residents into training and jobs = Identify best practices to be highlighted in the campaign = Develop consistent—branded—messages AaqiA ALASKA GASLINE INDUCEMENT ACT Responsible Parties = DOLWD/AWIB = Business/industry partners Resources = Funding » State general fund » Industry = People m= AGIA Training Plan Coordinator Timeline FY09 Evaluation Public awareness/communications plan is in place and being implemented as phased. AGIA TRAINING STRATEGIC PLAN NV1d JISALVALS ONINIVAL VIOV Strategic Element 1.2 Develop a comprehensive, one-stop information system on job openings and training opportunities in Alaska. Rationale Once Alaskans are made aware of the employment opportunities provided by natural resource development, they need to know how they can access these jobs or the training/retraining they might need to become prepared for employment. At present, this information is scattered and not always current. A centralized clearinghouse of information that can be accessed on-line can provide a link between individuals and opportunities. Action Steps = Create an inventory of available training and job openings, emphasizing jobs related to natural resource development Disseminate the inventory through interactive electronic and print media Provide for updating and maintenance of the system Provide incentives for trainers and employers to participate in the inventory Increase support for packaging and disseminating regional employment data Responsible Parties = DOLWD/Employment Security Division m= Alaska Commission on Postsecondary Education (ACPE) aqcie ALASKA GASLINE INDUCEMENT ACT Resources m= Materials/systems » ALEXsys employment data base » AKCIS career information data base m= Funding » State and federal workforce development dollars = People » AGIA Training Plan Coordinator Timeline FY09 Evaluation A centralized, electronic source of information on training and job opportunities is established and maintained. AGIA TRAINING STRATEGIC PLAN tegy 2. a comprehensive, integrated Career and ical Education system for Alaska that aligns as institutions and coordinates program delivery. Building a strong, flexible workforce to meet Alaska’s resource development needs requires a healthy CTE system—one that prepares high school students for further training and work and that provides opportunities for adults to maintain job skills or acquire new ones. At present, there is little state investment in career and technical education at the secondary level and only limited support at the postsecondary level. In addition, there is no system in place to assure that CTE operating and capital dollars are being spent in the most effective manner to meet high priority needs. Better coordination among existing training institution and closer alignment of program offerings are essential to increasing the state’s capacity to grow its own labor force. This strategy can be implemented by: Developing a state initiative for career pathways Establishing and implementing standards for Alaskan training programs Incorporating career counseling and planning in the K-12 system. ae ee oe | Creating an integrated system of out-of-school youth and adult training and education = Coordinating program development and delivery among the existing training programs. Funding: = TVEP and STEP dollars = State General Fund m= WIAA and other federal training programs = Industry AGIA TRAINING STRATEGIC PLAN NW1d JISALVALS ONINIVAL VLOV Strategic Element 2.1 Develop a state initiative for career pathways Rationale Alaskan students need a clear picture of the careers available to them and what it takes to prepare for their chosen careers. Students also should have easy transitions from one educational level to another. Career pathways—which lay out the academic and technical instruction related to a particular career—can assist students in planning their education and in securing employment in their field of choice. Action Steps Identify models for mapping career pathways Survey Alaskan school districts and the private sector Secure examples from national sources “Alaskanize” nationally developed career pathways, where necessary, to fit local conditions Utilize business/industry/education consortia to develop industry-specific pathways if no model exists Provide electronic and print resources and pathways templates to public and private training providers Require state-funded training programs to develop and implement career pathways, including articulation between one educational level and the next Encourage private postsecondary training institutions to develop and utilize career pathways Revitalize the Career and Technical Student Organizations (CTSOs), such as DECA, Junior Achievement, etc. Reestablish and fill the AWIB Secondary/Postsecondary Liaison position Aaqcia ALASKA GASLINE INDUCEMENT ACT Responsible Parties m= Alaska Department of Education and Early Development (secondary school career pathways) = DOLWD (state-funded training centers) = University of Alaska system = Private training providers = Business/industry consortia Resources = Models and materials: » National career pathways initiatives » Alaska developed career pathways = Funding: » State general fund » Federal (Carl Perkins IV, WIA) » Industry Timeline Begin immediately, based on the requirements of Carl Perkins IV. Provide state funding by FY 10. Evaluation All publicly-funded (secondary and postsecondary) training programs will be part of a published career pathway that is available to students, parents and other interested parties. AGIA TRAINING STRATEGIC PLAN Strategic Element 2.2 Incorporate career counseling and planning into the K-12 system. NW1d JIDSALVALS ONINIVAL VLIOV Rationale Alaska’s K-12 student population is its greatest pool of potential workers. Better information about career options in the state is a first step. However, students also need assistance in making realistic career choices and taking concrete steps to meet their career goals. Parents play an important part in forming their children’s aspirations and choices and need to be involved in career planning. Industry has information and resources that can help students make wise choices. Action Steps = Encourage school districts to utilize the Alaska Career Ready Certificate as an impetus for career planning for all students = Create and disseminate a template for career plans, based on career pathways m= Provide awareness and training for counselors and teachers in career pathways and career plans = Utilize industry consortia for career information and guidance materials and presentations = Use district-to-district volunteers to assist school districts with planning = Develop and disseminate models for involving parents in career awareness and planning = Identify and disseminate strategies for using community resources in career exploration and planning Aaqcie ALASKA GASLINE INDUCEMENT ACT Responsible Parties = DEED = Local school districts = DOLWD Resources » Materials and models » State and local school district career planning templates » DOLWD career guides and publications » Industry consortia-developed career information materials = Funding » State general fund m= People: » DEED Career and Technical Education Staff » DOLWD Career Counselors Timeline Fall 2009 Evaluation All Alaskan high school graduates have a written career plan based on their selected career pathway. AGIA TRAINING STRATEGIC PLAN NW1d JIDALVULS ONINIVAL VIOV Strategic Element 2.3 Establish and implement standards for Alaskan training programs. Rationale All training should lead to employment by assuring that successful completers demonstrate the technical skills and work attitudes required by industry. To meet the needs of industry and students, training programs must be consistent across the state. Developing and enforcing training standards can provide these assurances. Programs and processes that produce demonstrated student success and job placement need to be identified as “best practices” and adopted widely in training efforts. Action Steps Identify and disseminate information about available industry standards Identify nationally-adopted standards, where available Use business/industry/education consortia to develop or “Alaskanize” standards if national models are not available or not sufficient for local conditions Inventory training programs to assess if they are based on recognized industry standards If current programs—either publicly or privately funded—do not meet standards, provide assistance for » Curriculum development » Professional development » Equipment/materials needed to meet standards » Expense of undergoing industry certification review Require all state-funded training to be based on industry standards, leading to appropriate industry certification for successful completers Require all state-funded training programs to adopt and implement an employability and soft skills assessment program Recognize training programs that meet or exceed standards AqiA ALASKA GASLINE INDUCEMENT ACT Responsible Parties = DEED = DOLWD/AWIB Resources = Models and materials: » National standards developed by various industries » Existing employability and soft skills assessment programs (WorkKeys/WIN®, Youth Employability Skills, SCANS). Funding: = State General Fund m= Federal (Carl Perkins, WIA) = Industry Timeline FY09 budget request Evaluation All state-funded training programs meet appropriate industry standards and demonstrate inclusion of employability and soft skills. AGIA TRAINING STRATEGIC PLAN 2 NW1d JIDEaLVALS ONINIVAL VIOV Strategic Element 2.4 Coordinate program development and delivery among existing training programs. Rationale Alaska’s limited training resources must be deployed in the most efficient and effective manner if the state’s workforce development needs are to be met. Unnecessary duplication of programs, programs that are not adequately resourced, facilities that are underutilized or substandard, competing administrative structures all dilute the ability of the current system to respond to demand. Action Steps = Create a network among existing state-supported regional training centers that will: » Provide technical assistance in meeting program standards » Serve as an umbrella for national accreditation of these centers » Rationalize program delivery among the centers m Strengthen the statewide organization of career and technical training providers as a vehicle for coordination and communication ™ Incentivize private providers to meet state standards and recognize those that do m Require requests for state operational and capital training dollars to be funneled through and prioritized by the Alaska Workforce Investment Board aqia ALASKA GASLINE INDUCEMENT ACT Responsible Parties = DOLWD/AWIB = State-funded training centers m= Statewide career and technical training providers Resources m= Funding: » TVEP/STEP/state general fund » WIA, Denali Commission and other federal training programs » Industry Timeline FY09 budget request Evaluation State training dollars are allocated in line with AWIB priorities. There is minimum duplication of training programs and where duplication exists, it is based on demonstrated need. AGIA TRAINING STRATEGIC PLAN Strategic Element 2.5 Maintain a robust support system for youth and adult vocational education. NW1d JIDALVALS ONINIVUL VLIOV Rationale Many youth and adults seeking to enter jobs in natural resource occupations need skill development before they can be successful. Data indicate that there is a considerable pool of workers who have some of the skills required for these occupations, but need foundational skills upgrades, remediation, and/or remediation in order to compete successfully for good jobs. Other adults may need additional educational services such as Adult Basic Education (ABE), General Educational Development (GED), English as a Second Language, and math and language training. Prospective workers may also require other types of supportive services while in training or apprenticeships. These services can be as small as a referral for child care services to funding a complete physical exam, but are required to keep the student in class and allow them to be successful. Action Steps ® Increase support for ABE and ESL programs in all regions of the state. = Identify and widely disseminate information on Web-based instruction for skills upgrading in various occupations. = Increase individual electronic access to the Alaska Job Center Network (AJCN) and the Alaska Career Information System (AKCIS). m Encourage the use of all available supportive services provided through workforce development grantees, social service organizations, and the One- stop Job Centers, particularly training and employment services. Responsible Parties m DOLWD = ABE/GED Grantees = Job Center Network Aci ALASKA GASLINE INDUCEMENT ACT Resources = Marketing materials m AKCIS & ALEXsys systems m= Funding (state and federal funds) = Personnel (job center staff and partners; providers of ABE/GED; WIA & STEP grantees) Timeline FY09 Evaluation = Youth and adult workers have information about obtaining natural resource development jobs. = Reduce attrition in job training and apprenticeship programs. AGIA TRAINING STRATEGIC PLAN opportunities for registered seship in skilled occupations and expand Registered Apprenticeship is a national training system that combines paid learning, on-the-job and related technical and theoretical instruction in a skilled occupation. The purpose of a Registered Apprenticeship program is to enable employers to develop and apply industry standards to training programs that can increase productivity and improve the quality and safety of the workforce. Apprenticeship programs are the primary vehicle for the considerable private sector investment in workforce development. Certifications earned through Registered Apprenticeship programs are recognized nationwide as portable industry credentials. Registered Apprenticeship has been utilized successfully in Alaska for over 50 years, primarily in the construction industry. There are other models of structured training such as certificate and degree programs that use internships, cooperatives and mentorships. Many college and career and technical education programs utilize these models in engineering, project management, and similar ini where on-the- Job (ou) ree are required. This strategy can be implemented by: = Increasing job training through construction academies, career and tech- prep programs, and pre-apprenticeship programs for entry-level employment. = Increasing employment opportunities for apprenticeships on all construction and infrastructure projects in Alaska. = Developing training incentives for employers who utilize apprenticeships and other structured OJT. = Establishing a funding mechanism to support apprenticeships and other structured training opportunities. Funding: = Davis-Bacon training benefit. = Tax credits/WIA funding, and public and private investments. = State training fund established through AS36.05.045 m= Industry AGIA TRAINING STRATEGIC PLAN NW1d JIDALVALS ONINIVUL VIOV Strategic Element 3.1 Increase job training through construction academies, career and tech-prep programs, and pre- apprenticeship programs for entry-level employment. Rationale Training that utilizes actual work experience along with classroom instruction is a time-proven method for placing people in jobs. The success of construction and other skill academies in all parts of Alaska and with youth and adult workers indicates that such efforts are cost-effective preparation for entry-level positions. Tech prep programs transition secondary students to postsecondary programs, including apprenticeship. Action steps m Increase state funding for workforce development programs that utilize structured training opportunities m Use state dollars to leverage private support for structured training opportunities ™ Increase state support for tech prep programs at both the secondary and postsecondary level. Responsible Parties = DOLWD = DEED | University of Alaska = Private sector training entities Acie ALASKA GASLINE INDUCEMENT ACT Resources = Funding » State training fund » Industry support for academies Timeline FY09 Evaluation Skill academies are offered in various regions of the state. Tech prep opportunities are available in all state high schools. Training programs at all levels utilize some form of structured, on-the-job training. AGIA TRAINING STRATEGIC PLAN Strategic Element 3.2 Increase employment opportunities for apprenticeships on all construction and infrastructure projects in Alaska Rationale Employers have long been the major source for job training. Private investment in specific skill development—primarily through union and non-union apprenticeships—far outstrips public expenditure for occupational training. Currently in Alaska, there is considerable room for expansion of apprenticeship opportunities on both public and private projects. Action Steps Require apprenticeship employment on all state funded construction projects @ Inform employers of the benefits of apprenticeship utilization Create an information system that tracks apprenticeship hire by trade Responsible Parties = DOLWD | = State government agencies having capital projects = Private employers NV1d JIDAaLVALS ONINIVAL VLIOV aqia ALASKA GASLINE INDUCEMENT ACT Resources = Funding » State capital projects » Davis-Bacon training benefit » Union training trusts » Industry m= Persons » Federal Apprenticeship Office » State Apprenticeship Coordinator Timeline Begin in FY09 capital budget Evaluation Apprenticeship slots are utilized on all state-funded construction projects, including major maintenance. Number of apprentices employed on private projects increases, as indicated by the apprentice tracking information system. AGIA TRAINING STRATEGIC PLAN NW1d JIDALVALS ONINIVAL VLOV Strategic Elements 3.3 Develop training incentives for employers who utilize apprenticeships and other structured OJT. Rationale While many employers already use apprentices, there is considerable room for growth, particularly among smaller firms. Identifying and providing appropriate incentives can be a cost-effective way for the state to leverage private funding and to increase apprenticeship and other on-the-job training slots across many skill areas. Action Steps = Identify incentives that have been used elsewhere to encourage apprentice @ and other OJT utilization = Adopt those incentives that would be most effective in the Alaska context m Provide technical assistance to firms wanting to establish or increase apprentice/ OJT use Responsible Parties = DOLWD Aq ALASKA GASLINE INDUCEMENT ACT Resources = Funding » WiA/other federal workforce development funds » State general fund m= People » State/Federal Apprenticeship Coordinators Timeline FY09 Evaluation Incentive system is in place and is being utilized by employers to develop or expand apprentice/OJT utilization, as indicated by the apprentice tracking information system. AGIA TRAINING STRATEGIC PLAN Strategic Element 3.4 Establish a funding mechanism to support apprenticeships and other structured training opportunities. NW1d JIDALVALS ONINIVAL VLIOV Rationale Legislation exists (AS36.05.045) that assesses a fee on all state and federally funded construction projects. Currently, these funds accrue to the general fund, but they could be used to establish a training fund that is a separate account subject to Legislative appropriation under the authority of the DOLWD Commissioner. Funds deposited into the account would not lapse at the end of the fiscal year, unless otherwise provided for by the Alaska legislature. The approximately $2 million dollars per year generated could provide partial funding for the activities recommended in this plan. Additional appropriations could be made to the fund, as determined by the Legislature. ee is Action Steps = Introduce legislation to establish a training fund from receipts collected under AS 36.05.045. Responsible Parties = Alaska Legislature = DOLWD Acie ALASKA GASLINE INDUCEMENT ACT Resources = Funding » AS36.05.045 fees » Additional appropriations to the fund Timeline 2008 legislative session Evaluation AS36.05.045 is amended to establish a training fund. Annual appropriations are made to the fund from assessed fees. AGIA TRAINING STRATEGIC PLAN These jobs range from professionally-certified and degreed positions to support functions for industries impacted by natural resource development. Degree programs such as engineering and science, process operations and technical positions require both academic/conceptual education and work-place application. This strategy can be implemented by: F & & Expanding programs in the postsecondary system for critical jobs such as engineering, environmental sciences, etc. Recruiting more Alaskan high school graduates into these programs. Increasing internships and work-cooperatives for both secondary and postsecondary students. Assuring better articulation between incumbent workers and management programs/degrees. unding: Increased funding for UA and other postsecondary institutions in target programs Tax credits for internships Support for applied academics as part of state funding for career and technical education Industry contribution to specific certificates and degrees AGIA TRAINING STRATEGIC PLAN Strategic element 4.1 Expand programs in the postsecondary system for critical jobs such as engineering, environmental sciences, technical operations and management. Rationale Professional, technical and managerial employees have highly-transferable skills that provide excellent long-term career prospects. At present, these occupations have a large number of non-resident hires. The state’s current capacity to train for these careers is severely strained. Expanding capacity to meet additional demand requires considerable lead time in order to secure the necessary faculty and to recruit qualified students. Action Steps @ = From DOLWD data, identify the high priority occupations in which there are the significant current shortages = Assess in-state postsecondary capacity to address these shortages = Engage the University of Alaska, state/regional training centers and other certificate/degree granting institutions in developing a comprehensive plan to expand capacity = Prioritize funding requests for program start-up or expansion through AWIB = Explore loan forgiveness for students completing degree programs in target areas for which no in-state program is available Responsible Parties DOLWD/AWIB University of Alaska AVTEC/State-funded training centers Private certificate/degree granting institutions NW1d JIDALVALS ONINIVAL VLOV ZB 8efG& AaciA ALASKA GASLINE INDUCEMENT ACT Resources = Materials and equipment » Industry = Funding » TVEP and STEP dollars » State general fund » Industry for specific programs Timeline Spring 2008 Evaluation State capacity in certificates and degree programs in professional, technical and managerial occupations is sufficient to meet industry needs. AGIA TRAINING STRATEGIC PLAN NV1d JIDALVALS ONINIVAL VLOV Strategic Element 4.2 Recruit more Alaskan high school graduates into programs leading to professional, technical and managerial certificates/degrees. Rationale Because these occupations provide excellent long-term potential, they make attractive career choices for Alaskan youth. However, students who wish to pursue careers in these areas need begin preparation early by taking the necessary math and science courses in high school. Action Steps = Start early in the educational process to encourage students in these careers, using proven success strategies such as those used in the Alaska Native Science and Engineering Program (ANSEP) m Expand the use of applied academics in secondary math and science courses m Increase summer engineering, science and technology camps = Develop tech prep and other secondary/postsecondary articulation agreements in these occupational areas = Utilize the regional training centers as pipelines for transitioning rural high school completers into these programs = Initiate a state matching program for scholarship support for students in these programs Responsible Parties = DEED/School districts = University of Alaska = DOLWD m AVTEC/State-funded training centers = Industry consortia AaqiAa ALASKA GASLINE INDUCEMENT ACT Resources = Models and Materials » ANSEP » Existing math and science camps = Funding » State Foundation funding » State general fund » Federal/state grant funds for camps » Industry = People » DEED program specialists » UA program faculty ‘Timeline FY09 Evaluation Increased numbers of Alaskan high school students enroll in certificate and degree programs leading to professional, technical and management careers in natural resource development. AGIA TRAINING STRATEGIC PLAN Strategic Element 4.3 Increase internships and work-cooperatives for both secondary and postsecondary students. Rationale All students—whether they are training for a skilled craft or for a professional or technical occupation—benefit from on-the-job experience during their training program. Such experience can also lead to job placement after training is completed. Many of the major employers in natural resource industries already use internships and other forms of work experience to recruit their workforce. However, there is the potential for expanding these opportunities beyond the core companies. Action Steps = Identify existing internship and work cooperative programs = Disseminate successful industry practices in providing meaningful work experiences m Use industry to industry contacts to promote such programs and practices m Provide technical assistance to companies that want to develop internships m= Encourage continued cooperation between industry consortia and certificate/degree program staff NV1d JIDALVULS ONINIVAL VLOV Acie ALASKA GASLINE INDUCEMENT ACT Responsible Parties = Certificate/degree program faculty and staff = Industry consortia Resources = Models and materials » Model internship/work experience programs » Industry consortia m= Funding » Industry employers » TVEP Timeline FY09 Evaluation Students in certificate and degree programs leading to professional, technical and | managerial occupations have meaningful on-the-job experience as part of their educational program. AGIA TRAINING STRATEGIC PLAN NV1d JIDALVULS ONINIVAUL VIOV Strategic Element 4.5 Increase job opportunities by expanding capacity to deliver incumbent worker training focused primarily on helping workers keep pace with technological changes and including journeyman craft worker skills upgrades. Rationale Many of the current workers are required to keep pace with technological changes and journey level craft workers in particular need opportunities for skill upgrades to keep or advance in their job. Action Steps = Expand flexibly offered incumbent worker training. = Offer short term, developmental instruction in technology and skill upgrades. @ Responsible Parties m Postsecondary program faculty m State-funded training centers = Industry associations = Apprenticeship sponsors Strategic Element 4.4 Assure better articulation between incumbent workers and management programs/degrees. Rationale Many of the supervisors and managers needed for the gas pipeline and other natural resource development projects will come from the current workforce. These workers often already have much of the knowledge and skills imparted in a formal certificate or degree program. Recognizing this prior experience in terms of college credit can accelerate program completion. Short courses on specific supervisory and management topics can also speed the advancement of current workers. Action Steps m= Expand the use of awarding of credit for prior experience in university-level professional or technical certificates and degrees m= Offer short term, developmental instruction in supervision, safety management and other topics identified by industry NV1d JIDALVALS ONINIVAL VLOV Responsible Parties m= Postsecondary program faculty = State-funded training centers = Industry associations m Apprenticeship sponsors aqcie ALASKA GASLINE INDUCEMENT ACT Resources = Models » Associate Degree in Apprenticeship Technologies = Funding » Industry, for professional development of current workers Timeline FY10 Evaluation Incumbent workers advancing to supervisory positions have access to the necessary developmental instruction and to certificate/degree programs that acknowledge their prior experience. AGIA TRAINING STRATEGIC PLAN NV1d JIDFLVALS ONINIVAL VLIOV Strategic Element 4.5 Increase job opportunities by expanding capacity to deliver incumbent worker training focused primarily on helping workers keep pace with technological changes and including journeyman craft worker skills upgrades. Rationale Many of the current Action Steps m= Expand flexibly offered incumbent worker training. = Offer short term, developmental instruction in technology and skill upgrades. Responsible Parties m Postsecondary program faculty = State-funded training centers = Industry associations m= Apprenticeship sponsors Soi ALASKA GASLINE INDUCEMENT ACT Resources = Models » Contract and corporate training programs = Funding » State General Funds > STEP >» WIA Timeline FY10 Evaluation Incumbent workers advancing in and maintaining employment in their given field. AGIA TRAINING STRATEGIC PLAN AGIA TRAINING STRATEGIC PLAN Inside the AGIA Report Gasline Occupations A list of 113 occupations considered significant inconstructing a natural gas pipeline. indicates the phase(s) th: significant demand.? Summary Statistics for All Gasline Phases A general progression of the gasline project. Phases may, at times, overlap or run concurrently. A at the occupation will be in Statewide Labor Force Indicators Statistical data providing measurements relating to the statewide labor force. The occupational numbers in this table are not industry or project specific (e.g. gasline construction), but are statewide numbers which include all industries combined. AGIA Occupations Select statewide labor force indicators which estimate nonresidency and older worker AGIA Occupations > Percent Nonresident Workers? information. Ta Summary Statistics for All Gasline Phases’ Training Levels % Percent of Workers Age 45+? Counts of occupations by training % Percent of Workers Age 50+? requirements. The training level p abbreviations used in the table are defined in Ui nel footnote 11 at the end of the report. w Groups —_ The report is organized by ten occupational AGIA Occupations Statewide Labor Force Indicators groups, each consisting of occupations that Tuesday December 18 2007 sone cc coma te | reas PSS pete ode ec the functions pron perros Fenty fend wenn seme ell ae oe eee Now: Employment totabs are not restricted to pasiine occupations, Anasterisck (*) means data ate suppressed due to confide ntality The "Wi" means data are not available. The occupational numbers in this table are not industry specific or project specific (e.g. gasline construction), but are statewide numbers which include all industries combined. Pai Group and AGIA Totals Summarized counts and calculations on presented data. AGIA Occupations Summary Statistics for All Gasline Phases’ Statewide Labor Force Indicators AGIA Occupations Design’ —— Alaska Employment | Worker Open 5 % Percent Nonresident Workers? 16.4% Alaska Worker Data Estimated Demand Potential Supply Projections Demographics’ fo Season 2004-2014)3 | (2006) (2004-2014) (2006)° Phases “+ Percent of Workers Age 45+° 37.4% * Percent of Workers Age 50+9 24.3% jon.nsuess. = dial =a 3 ae g quar ©) anp sBuuadg jenuuy Training Levels ovr | saTOrT LTOJT 2S Ee. s]aao7] Buiter] On.1SUO} Pur u squensitioy Jo Joquny YS S82] UL ps ©) anp s8uuad¢, Carpenters 1,791} 4,855] 5,383] 10.9] 3 .73 | LTOIT ‘Cement Masons and Concrete Finishers Construction and Building Inspectors Construction Laborers 3,605 3 $20.57 |MTOJT] 1,681 9 3 | $39.87 BA Construction Managers Crushing, Grinding, and Polishing Machine Setters, Operators, and Tenders 1o1| _141| 39.6] Electricians 697) 2,164 2an| 14.2] 3 .0 | $29.93 tics Explosives Workers, Ordnance Handling Experts, and Blasters s $23.86 pe) : [Mrosr First-Line Supervisors/Managers of Construction Trades and Extraction Workers First-Line Supervisors/Managers of Helpers, Laborers, and Material Movers, Hand First-Line Supervisors/Managers of Production and Operating Workers Helpers, Construction Trades, All Other $37.24 |wiexp $21.20 | WkExp $30.94 | WkExp * | STOJT Helpers--Carpenters PS [SESS | NUNES TS LS $14.88 | STOJT | $15.65 | STOJT ims Note: Employment totals are not restricted to gasline occupations. An asterisck (*) means data are suppressed due to confidentiality AGIA Occupations Summary Statistics for All Statewide Labor Force Indicators AGIA Occupations ALEXsys > Percent Nonresident Workers2 5 Alaska Worker Data | Estimated Demand | Employment Data (2006) (2004-2014)? (2006) | i “* Percent of Workers Age 45+9 “ Percent of Workers Age 50+° oue zls 21 oF g| & Bloc al anp s8uuadg jenuuy ys8unsog Oy Jo Jaquinyy 4 dof Jo sequin y Training Levels ‘OsT| MTOST | LTOST | WkExp | 25 | 2 | 13 | 13 juapisatuony wed. uonednazo Jat ssunsog uo Helpers--Pipelayers, Plumbers, Pipefitters, and Steamfitters Helpers--Production Workers Highway Maintenance Workers Insulation Workers, Floor, Ceiling, and Wall Insulation Workers, Mechanical Millwrights Painters, Construction and Maintenance $20.75 Plumbers, Pipefitters, and Steamfitters | ~ ~ a T — | s $28.34 | LTOJT Sheet Metal Workers Structural Iron and Steel Workers — $27.11 LTOJT Welders, Cutters, Solderers, and Brazers _ $24.70 | LTOJT Welding, Soldering, and Brazing Machine Setters, Operators, | and Tenders | | F 15 |STOJT] MTOIT | LTOJT | WkExp Group Totals 7,216| 2,317 Bus and Truck Mechanics and Diesel Engine Specialists $24.41 | Voc Crane and Tower Operators * |LTOJT Excavating and Loading Machine and Dragline Operators $23.53 |MTOJT| Note: Employment totals are not restricted to gasline occupations. Anasterisck (*) means data are suppressed due to confidentiality. ‘The "na' means data are not available. “a i 1 < = = Summary Statistics for All Gasline Phases = de Labor Fo nity es AGIA Occupations Design’ | | rena | ALEXsys Alaska Employment | Worker Occupation “ Percent Nonresident Workers? 16.4% Sacer Alaska Worker Data | Estimated Demand | Employment Data Potential Supply | —_—_—Projections |Demographics| Characteristics . Phases | (2004-2014)? (2006) (2006) | 2004-2014)? | (2006)? * Percent of Workers Age 45+° 37.4% ae | 7 + a —— — —, 4 a “> Percent of Workers Age 50+2 24.3% | 8 | | 83 ay | s| | se | 3 a|?z gS a "2 Training Levels*! O° z 3 0,5) p 9 g = 7 —— T — 3 s| 38 ‘@ 2 gr =| stost| MTO LTOJT [ WkExp | voc | AA | BA | BA+ < a S| £ | 2 > 3 3| as os [soe 6 7 18 3 zg §| 2 2) 3 & 2 7 1 FT 7 | 8 gs) ~ | = 3 | Equipment Operators (Continued) First-Line Supervisors/Managers of Mechanics, Installers, and ] ] ] ] | Repairers v 89) 11.1 20 | 47 | 17 97) 57 217 81 57| 1,089 1,285} 18] 62.6] 39.2 | $31.62 | WkExp. Industrial Machinery Mechanics | | | | | | | | v 34] 16.3 4] 12} 70; 61) 09 61 23} 42| 431| 467| 84] $4.9] 364 | $27.67 | LTOJT Maintenance Workers, Machinery - TT" : ] | | | I] 7 viv 289} 74) 25.6 *| *| 29) 141) 49] 135 109 55 . *| +! so4 Mobile Heavy Equipment Mechanics, Except Engines l_ 1 =i | | | | | __] | TI |v¥iv 796| 180) 22.6 | 18 36 | $5} 135] 25] 193 10 76 842] 1,019] 21] 42.7 Operating Engineers and Other Construction Equipment YT | | | | ] | | T | Operators mnand 4,192) 767) 18.3 82 71} 153| 140) $86} 4.2| 941 366] 1,448] 2,741] 3,561| 29.9] 49.9] 31.0 | $27.32 |MTOJT| Paving, Surfacing, and Tamping Equipment Operators tT Too a aa T T T | io viv 98] 15] 153 . . . 18) 106) 5.9] 60 10} 70) : “| *| 291] 233 . [Tory Pile-Driver Operators TTT | —- I j == IT | viv * * * 2 28 17] __50/ * *| +) 37.7] 27.4 | $25.12 |MTOJT| Truck Drivers, Heavy and Tractor-Trailer | | | 7 | | T — mnand 3,090 13.6 40 55| 95} 381] 1,065] 28] 710 142] 712} 3,380] 3,781/ 11.9] 48.8 | 33.6 | $21.12 |MTOIT| STOIJT] MTOJT | LTOJT | WkExp| VOC | AA | BA | BA | ] Group Totals } ih = oat 7 aT wri 6 i 11,002| 1,879) 17.1 See footnote 3 | 850 2,622 3.1| 2,722 779| 2,791! See footnote3 | 49.2 | 31.8 Material Handling First-Line Supervisors/Managers of Transportation and ] ] T T Material-Moving Machine and Vehicle Operators | | | v 473) 46 o7 7 | 1S | 22 4! 69 17.3 227) 28 97 635 702) 10.6] 603 Laborers and Freight, Stock, and Material Movers, Hand | | | | | | | it | v| 6,531] 1,228) 18.8 27 | 120 146 371) 768) 2.1 2,247) 1,270| 1,364) 3,667 3,932} 7.2 25.7 Order Clerks a rT 4 | | | v | 374 17 45 *| ° * 12] sel 4.0 169) 83 38} * 7h = 30.3 “Stock Clerks and Order Fillers 7 TT | = == 7 = Hs t. | Zi 2,891 378 13.1 | O| 124] 124] 492} 1,221] 25] 947] 377] 326) 3,348] 3,202) 4.4] 23.9 7 Total STOIT] MTOIT[LTOIT [WkExp| VOC | AA | BA] BAr | - T T T iroup Totals lca o co " a re 9 | 19269 1,669| 16.3 See footnote 3 879| 2,106} 2.4| 3,590) 1,758| 1,825) See footnote 3 27.1 Logistics Bus Drivers, Transit and Intercity ] ] T T ll 17 | 130 17 349 79 267) 523 580) 10.9] 61.0 mployment totals are not restricted to gasline occupations. An asterisck (*) means data are suppressed due to confidentiality The “n/a“ means data are not available. AGIA Occupations Percent of Workers Age * Percent of Workers Age Training Levels!! “+ Percent Nonresident Workers? Summary Statistics for All 45+9 50+9 16.4% 37.4% 24.3% (Continued) Desi gn/ Permit’ Open Season Phases AGIA sete Te te | | ALEXsys Alaska Worker Data | Estimated Demand Employment Data (2006) ” (2004-2014)? 7 quapisaiwoy, juonedno90 s®uuadg jen qwapisau Potential Supply Statewide Labor Force Indicators Alaska Employment Projections quoWAojdury Worker Demographics (2006)° Occupation Characteristics Dispatchers, Except Police, Fire, and Ambulance ] 190} 3.9| 166 41| 79! s67| 587 37.2 | 23.7 | $20.41 |MTOST| Purchasing Agents, Except Wholesale, Retail, and Farm | | | Products 368) 45] 122] 6 12| 18 8| 5.6| 104 30] 29] 499] ss6| 11.4) $4.1 | 37.5 | $27.74 | WkExp Truck Drivers, Light or Delivery Services Lee | - — Tf _f fy __ fT 1,705} 278} 163| 41 20| 60| 281] 537} 19] 635] 354] 256] 2,127| 2,534] 19.1] 33.7 | 21.6 | sis.s6 | stosr Group Totals ra Operations tT 2 |_o STOJT] MTOIT | LTOIT | WKEXp 652| 17.5| See footnote 3 987; 2.1| 1,254] 504 Gas Plant Operators Plant and System Operators, All Other ‘Gas Compressor and Gas Pumping Station Operators See footnote 3 29.8 29| 44.9 $27.24 | LTOJT. Group Totals Administration 2 [sTosT] MTOIT | IT | WkE STOST] MTOST | LTOJT | WkED 0 A o | 59) See footnote 3 Bookkeeping, Accounting, and Auditing Clerks Note: Employment totals are not restricted to gasline occupations. Anasterisck (*) means data are suppressed due to confidentiality. 102| 146| _356| ‘zal 3.2| 1,489] 5,865) 8.1| 41.8] 269 | $18.08 |MTOIT| Budget Analysts 7 | | rT = | - | | | o.1 2. i an 141 4 s| 16} 30| 19| $3 u 6| 226} 241| 66] soo] 314|$3065| BA ‘Computer and Information Systems Managers | ] | | | | y | 345 io 22} 31] ual 37] 78 16| 540] 662) 22.6] 57.1] 33.9 | $38.21| BA+ Sapa pas a SSS Sees ae 656 7 | 17} 34) 8s] 25] 108) 20] 13] 715] 662| -7.4] 498] 34.1 $29.90) BA ‘Computer Support Specialists a | + _T T ] — ~ — 1 1,088] 12| 27] 93) 433} 4.7| 236] 110] 40) +95} 1,112] 16.4] 261] 16.2| $2258) AA ‘Computer Systems Analysts | | ~ a | "I a 469 9| 23) 26] st} 3.1] 124] st] ts|_ 793] 928) 17] 46.1 | 274 | $34.63) BA — | : __?6| 81 7 | | 17 ee eee 145] 9} 21| 1s} 14) 09] 59 26] 10) 398 si4| 29.1] sas a ai, 1 = = - Summary Statistics for All Gasline Phases a a alte S AGIA Occupations Desi gn/ | og |_| ALEXsys | Alaska Employment | Worker | Occupation Percent Nonresident Workers2 16.4% pia | > Alaska Worker Data | Estimated Demand Projections Demographics) Characteristics es ° Phases g (2006) (2004-2014) (2006) * Percent of Workers Age 45+ 37.4% cca z ——— ee _——— es “> Percent of Workers Age 50+9 24.3% | 5 G2) FF | ez| ee ; 5 2¢ 2 = 8 Z5| 3 s&) FE \ 3 a £ 2 2 2 = ie Training Levels! | 38l o 8 3 | 23 2 | 2 [MToit [LTo7 [AA | BA | BA Z| 2/2 a| @| ¢& 3 & ae oy 3/2] 3/23] 2] 38 e| 2] & a 28 | 13 | [7 | wl 3 FIEIE|2E) | 3 g 2] g | ———— —1 4) 4/4 =| s im a ® 5 =| co] si 2 5 | 5 i | Administration (Continued) Database Administrators T T T eee | ahd hd v 24 26 46.3 | 26.3 | $33.58) BA Employment, Recruitment, and Placement Specialists | | | | wee . Yiviv viv 5.6 41 5 9 166} 204] 22.9] 44.7] 33.0|$2256| BA | Executive Secretaries and Administrative Assistants r 1 | ,_ td _T Yiv\v m4 3.1| 1,550 569 443 3,362) 3,740| 11.2 41.2 | 28.3 | $18.93 TOIT File Clerks 7 a a TS Pf | ; | i viviv |% 44| 268 131 84/473] 283| -40| 24.8 | 16.8 | $12.68 | sToyT First-Line Supervisors/Managers of Office and Administrative | Support Workers vv v | v 5.2| 678 214] 237] 3,189 48.7 | 31.0 | $23.05 | WkExp Human R ces Assistants, Except Payroll and Timekee | | ia |_ — Pee NNER | |v lv 3.6| 127 69} 45) 518 32.3 | 18.3 | $18.43 | STOJT Payroll and Timekeeping Clerks | a | - yf —\F i Yiviv v 526} 47) 8.9 12 17 29| 66) 184 37 59} 638 41.8 | 25.0 | $19.70 |MTOJT Receptionists and Information Clerks T T_T | | fae ] i! v ‘| v v 3547| 396] 11.2 so 70} 120] 474) 1,961 743| 375| 2,861 25.9 $13.77 | STOJT Training and Development Specialist Sa 1 a Es a | + — —— + | | v I v 239) 10 4.2 S| | 9] 30 98 3.3 | 87 12 26| 310} 355| 14.5] $0.2] 33.3 *| BA STOIT] MTOIT | LTOIT | WEExp AA | BA | BAs | | | Group Totals aol ao Le i ts a 20,306, 1,641, 8.1 See footnote 3 | 2,036| 7,375) 3.6] 6,455} 2,602) 1,905! See footnote 3 38.9 | 25.5 Camps / Catering ‘Cooks, Institution and Cafeteria v 824 20 | 34 | 54 215 345 1.6 218 62 171 1,108} 1,303) 17.6] 54.6 | 34.8 | $16.09 |MTOJT| Cooks, Restaurant _ TT t + = | —- : { | i v| 2,807} 1,006] 35.8 42| 52] 93] 256| 64s) 25] 830 127] 464] 1,663) 2,078} 25] 22.8 Dishwashers — a TTT [ | rf r_T a tI 4 | | | v| 2,157| 726| 33.7 25| _38| 63| 270 608} 207} 275| 1,138 $9.54 | STOJT Emergency Medical Technicians and Paramedics | v | an i | | | 5 | Lt - al - 7 7 ae | | 286 43 15.0 9 1 54 112 44 | 230 22.58 | VO ————— 7 - = +} _}|— —_—|—_}_ —_ { —— 1 —— First-Line Supervisors/Managers of Food Preparation and | | | | Serving Workers a : tt [| 755} 97| 12.8) 1a | 21) 36) 88 230] 27/79] 897 35.0 | 204 | $15.29 | WkExp First-Line Supervisors/Managers of Housekeeping and | | v | | | , aL Janitorial Workers LI 440] 56| 12.7 ui} ao] 2] 4a 98} 52} 403] S14] 27.5] 45.7 | 28.1 | $17.97 | WkExp The "n/a" means data are not available. Note: Employment totals are not restricted to gasline occupations. Summary Statistics for All AGIA Occupations * Percent Nonresident Workers? % Percent of Workers Age 45+9 “> Percent of Workers Age 50+2 Training Levels!! STOIT] MTOIT | LTOJT | W Camps / Catering Food Preparation Workers AGIA Occupations Statewide Labor Force Indicators ALEXsys Employment Data (2006) Alaska Employment Projections (2004-2014)? Alaska Worker Data | Estimated Demand (2004-2014)? Potential Supply Jo soquny | np SBuuadg jen 3,015} 26.1 Worker Demographics) Characteristics (2006)° Occupation 16.0 | $11.66 | STOJT Food Service Managers Janitors and Cleaners, Except Maids and Housekeeping _ Cleaners Laundry and Dry-Cleaning Workers 252 378 fi PE Fee 682| 1,173 +——_| 22} 102 1,170} 28.3 89 314| 387 6 | $16.82 | WkExp ees 2.2 | $13.30 | STOJT 30.8 | $10.99 |MTOJT] Maids and Housekeeping Cleaners Maintenance and Repair Workers, General 710} 1,100| 787|_ 2,727| 3,556| 30.4 140 148 285| 878 1,008 542} 3,826] 4,566) 19.3 23.7 | $10.47 | STOJT 32.9 | $20.48 |MTOST| Group Totals [STOIT] MTOsT | I on [WKE Architectural and Civil Drafters Cartographers and Photogrammetrists Chemical Engineers | 5,418| 20.4) See footnote 3 3,160) 6,933 2.2| 7,830 3,641, See footnote 3 384 18.9 Civil Engineering Technicians Civil Engineers Control and Valve Installers and Repairers, Except Mechanical Door 24.7 16.7 | $22.82 voc 26.7 | $27.42 BA 35.7 | $42.54 BA 26.4 | $26.75 AA 30.6 | $36.68 BA 21.4 | $25.69 |MTOSJT| Electrical and Electronic Engineering Technicians Electrical Engineers Engineering Managers Note: Employment totals are not restricted to gasline occupations. The "n/a" means data are not available. An asterisck (*) means data are suppressed due to confidentiality 24.9 28.2 46.2 | $48.39) BA+ Summary Statistics for All AGIA Occupations Statewide Labor Force Indicators AGIA Occupations Design/ "coat ALEXsys | Alaska Employment Worker Occupation 4 Percent Nonreéidenk Workers™ 16.4% Cee aaa Data rama iDened | Baio Data Posen Supoly =e Pesngapiton Characteristics * Percent of Workers Age 45+° 37.4% aaieeee = pra = anne — | g zSl 3| 2 Ss 2 2 “> Percent of Workers Age 50+9 #| PF) 8 | ge 52) 22/3 . | e& | 28 o| FF|8 3 z| 2 | %o z|38|s Training Levels! 9 3 3 = &| gz] 2 5 = 2 STOIT| MTOST | LTO) 2 & s 3| 2 25 | 28 13 § 3 $ a eba £ 5 | Office & Field Engineering (Continued) Engineering Technicians, Except Drafters, All Other ] ] ] iv 755 11s) 15.2 | 6| 10 | 15 | 13) 42) 32 172) 0 83) 404) 461) 14.1 39.1 | 27.4 | $26.84 | AA Environmental Engineers |) | } | | } T | } | v 224/ 41| 18.3 *| =| 8 17 13 49 13 8| * +] *| 493] 31.9|$34.76| BA —— — — = pe ah ee ad Eat = eae Inspectors, Testers, Sorters, Samplers, and Weighers i | baal eel aoe L; | z i a fou a, [ @ - al a | nl eae | eae i aed ea a ae! | 21| |= { et x = — pe ee Managers, All Other —T | | | | | 2,993) 279 9.3 25 236} 4,556 35.0 | $31.77 | WkExp Materials Engineers Wy. saliaal aa EF ol St . T an Mechanical Drafters iii fl ia fic) | anh si fl 13 oO 0.0 ' 0 ° 0.0 | $34.94 ‘oc i a = =o peer fl | fete te eee Mechanical Engineering Technicians y | i lesa lad 14.0 * 1| * 1 Mechanical Engineers T — ce — v 40.1 14 | 40} 388 23.2 | $40.04 | BA Office and Administrative Support Workers, All Other 7 ae i. i | 8.7 Ss 598) 2,069 22.2 | $17.40 | STOJT | Leal antl won Bact Office Clerks,General L E | ian ai Ye 122] _so| 940| 6,894 23.2 | $14.68 | storr Procurement Clerks | | ] — im | v 14 o| 7 7| 18] 69) 3.8 90 58 19} 281 34.8 | $20.13 | STOIT | Production, Planning, and Expediting Clerks % ith il _ | | 1 7 “Ti til al — a, il 17 | 30 69 14 143 74 42 680 23.0 | $22.96 | STOJT ‘Surveying and Mapping Technicians a [e [- | | | | — i =| iv v 12.3 4 9 13 12 s7| 4.8| 39 25 37| 257 31.5 | 18.7 | $21.36 |MTOJT| Surveyors | I ile — viv) v 18.1 25 83 3.3 | 94 4 148| 425 558) 31.3 32.2 | Telecommunications Equipment Installers and Repairers, | | | | | a a | i Except Line Installers j a id Ul 1 9.9 _26| 126] 4.8] 178] oo] st] 1} 7a7| 10.1) 487 | Weighers, Measurers, Checkers, and Samplers, Recordkeeping] . vi 14.1 4} 40} 10.0] 29 19 12| + *| *! 35.2] 25.3 | $13.67 | STOJT [STOIT] MTOST | LTOJT | WkExp| VOC | AA BA’ | ] Group Totals i. | a 7 - | a 22,956 2,749] 12.0 | 1,114] 6,159} 55 | 6,904| 2,572! 2,373) See footnote3 | 38-9 | 25.9 Ho - - Note: Employment totals are not restricted to gasline occupations. An asterisck (*) means data are suppressed due to confidentiality. The "n/a" means data are not available. AGIA Occupations Summary Statistics for All Gasline Phases Statewide Labor Force Indicators AGIA Occupations Design/ ee | Assia Employment | Worker “ Percent Nonresident Workers? Oren, Alaska Worker Data | Estimated Demand Potential Supply Projections Season | 2004-2014)? | | (2004-2014) - : ; == “+ Percent of Workers Age 45+° Phases “+ Percent of Workers Age 50+2 aos Tutuady jenuur, Training Levels!! STOIT ee voc | 25 [ 28 [| 13 [ 13 | 6 quapisauoN uoron.nsuo; pue u' suoneiedg Environmental Environmental Engineering Technicians Environmental Science and Protection Technicians, Including Health Environmental Scientists and Specialists, Including Health 760| 17.8 Hazardous Materials Removal Workers Landscape Architects STOIT] MTOIT ft TOsT [weep 0 1 0 o Group Totals Health and Safety Engineers, Except Mining Safety Engineers and Inspectors Occupational Health and Safety Specialists $35.92 aor 13 . $38.32 Occupational Health and Safety Technicians 23.9 | 28) 93 5 38. $28.39 Sei eI Hel ME J | il si 2,680| 424/ 15.8 | 0 5 829/13 ; .3 | $13.76 | STOIT T T Security Guards T T Group Totals 3,132} 536| 17.1 965) 14 | See footnote 3 0 Grand Totals 129,751) 21,251 See footnote 3 | 11,670} 36,070} 3.1 |37,723 See footnote 3 Source: Alaska Department of Labor and Workforce Development, Research and Analysis Section (January 2008) Note: Employment totals are not restricted to gasline occupations. An asterisck (*) means data are suppressed due to confidentiality. The "t/a" means data are not available. AGIA Occupations Notes 1. Gasline Phases Gasline construction activities and the demand for workers in various occupations will vary over time, depending on the project’s phase. Phases are not always sequential. Road and Bridge upgrades, maintenance, and repair will occur over the entire life of the gasline project. Some Phase 3 activities will overlap with preconstruction and construction activities. For a more complete description of each phase, see the document Project Phases: AGIA Gasline Construction. Number of Workers/Residency Alaska wage records identify workers in private sector, state and local government covered by unemployment insurance within Alaska. Workers are assigned to the occupation in which they earned the most money in 2006, so a person will be counted only once, even if they worked in multiple occupations. The duration of a worker’s employment is not a factor in the count of workers — a person is counted as a worker once they earn any wages covered under Alaska’s unemployment insurance system. Alaska worker residency is determined by matching the Alaska Department of Revenue Permanent Fund Dividend (PFD) file with the Alaska Department of Labor and Workforce Development wage file. The PFD file is a list of Alaskans who either applied for or received a PFD. Workers included in the wage file are considered Alaska residents if they applied for a 2006 PFD or 2007 PFD. This data is methodologically different than the employment data. For more information on how the worker and the employment data differ, please contact the Research and Analysis Section of the Alaska Department of Labor and Workforce Development at 907.465.4518. N 3. Estimated Demand/Employment Projections Ten year occupational employment projections are produced biennially, and provide the data for Estimated Demand and the Alaska Employment Projections. Estimated and projected employment data includes self-employed workers in that occupation. Self-employment is not normally captured in other measures of employment published by the Alaska Department of Labor, Research and Analysis Section. Growth openings occur when new jobs are created in the economy. Replacement openings occur when workers leave an occupation. Replacement Openings can occur for many reasons, including retirement, leaving the state, or changing careers. Total openings are the sum of growth and replacement openings, and may not total due to rounding. Some occupational projections will fall outside of statistical error measurement guidelines or will disclose confidential information about an employer, and are therefore suppressed. Because of suppressed data, totals for AGIA groups and overall totals cannot be calculated. This data is methodologically different than the employment data. For more information on how the worker and the employment data differ, please contact the Research and Analysis Section of the Alaska Department of Labor and Workforce Development at 907.465.4518. 4. Job Postings Total count of available jobs by occupation posted by employers on ALEXsys in 2006. ALEXsys is the State of Alaska's online job seeker/workforce services system. 5. Registrants Total count of ALEXsys registrants by occupation in 2006. Registrants may identify their interest in or qualification for multiple occupations on their application so individuals may be counted multiple times in this calculation. 6. In Another Occupation Workers were considered qualified for the listed occupation if they had four quarters of prior experience in the years 2004 thru 2006 in that occupation. Workers may be considered qualified for more than one occupation. 7. InLess Skilled Occupation Each worker's primary occupation in 2006 was compared with all occupations in which they had four quarters of prior experience in the years 2004 thru 2006. If the worker had four quarters of experience in an occupation, but was employed in 2006 in an occupation requiring less education, training or experience, then they are counted as potential supply since they are currently “underemployed”. 8. ULClaimants Unemployment insurance claimants with an active claim in 2006. Claimants were matched with 2005 UI wage records to determine their primary prior occupation. 9. Age Worker age is determined by matching 2006 workers with historical PFD files. Only those workers with age data are used to determine the percent of workers older than age 45 or 50. Occupations with a significant number of nonresident workers will have less reliable age information since age data is not available for nonresident workers. 10. Average Hourly Wage Average Hourly Wage data comes from the Research and Analysis Section of the Alaska Department of Labor and Workforce Development, through the Occupational Employment Statistics Survey, a cooperative agreement with the U.S. Bureau of Labor Statistics, and represent statewide average wages for the occupation. 11. Traini evels Training requirements are based on the U. S. Department of Labor’s Bureau of Labor Statistics data. The education groups are as follows: ig req Pi group! STOJT — Short Term On-the-Job Training, typically requiring less than one month of training to attain average job performance. MTOJT — Moderate Term On-the-Job Training, typically requiring between one and twelve months of combined on-the-job experience and informal training. LTOJT — Long Term On-the-Job Training, typically requiring more than 12 months of on-the-job training or combined work experience and formal classroom instruction for workers to develop the necessary skills to attain average job performance. WkExp — Work Experience in a related occupation is generally required to meet these job requirements. Some occupations are supervisory or managerial in nature. VOC ~— Vocational training at the postsecondary level, with program durations from several weeks to more than a year, is required to attain average job performance. AA ~ Associate Degree, requiring completion of a degree program of at least two years of full-time equivalent academic work, is required to attain average job performance. BA ~ Bachelor's degree, requiring completion of a degree program of at least four years but no more than five years of full-time equivalent academic work, is required to attain average job performance. BA+ — Bachelor’s degree plus some combination of additional work experience or continued education beyond the bachelor’s degree is required to attain average job performance in these occupations. Educational Training Providers for AGIA Occupations Training Provider Location Training Programs ABC of Alaska Anchorage Carpenter; Painting; Plumber-Pipefitter; Sheet Metal Worker; Sprinkler Fitter Anchorage 24 Hour HAZWOPER; 40-Hour HAZWOPER Gi eneral Site Worker; 8 Hour Hazwoper Refresher; AED Autor rillator Training; Earthquake Preparedness Training; Electrical Safety Basics; Ergonomics for the Workplace; Excavation Safety; Fall Protection Ba 1AZCOM Program Development; HAZWOPER Awareness; Job Safety/Job- Site Analyses for Your Busin Stairway Safety Basics; Lock Out/ Tag Out Safety; OSHA Records and Record Keeping; Permit-Required Confined Space; Proactive Safety Program for Your Workplace; Respiratory Protection for your Workplace: Scaffolding Safety Basics; Site Safety Audits and Inspections; Tool Box Safety Talks; Winter Safety and Survival; Workplace Safety and Safety Committees; Workplace Violence Deterrent Training Alaska Computer Essentials Anchorage Accounting Technician and Bookkeeping; Administrative Assistant; Web Page Design Alaska Inventor and Entrepreneurs Association Anchorage FastTrac Manufacturing; FastTrac New Venture; FastTrac NPO (Non-Profit); FastTrac Planning; Your Business astTrac Starting and Growing Alaska Ironworkers Anchorage Ironwork Alaska Joint Electrical Apprenticeship & Training Trust Anchorage Lineman; Telephone; TreeTrimmer; Wireman Alaska Laborer’s Training Trust Anchorage Construction or related Alaska Medical Training Services Medical Office Assistant Alaska Operating Engineers Apprentice Training Trust Palmer Construction or related Alaska Technical Center Kotzebue Accounting Clerk; Bldg Maintenance; Clerk Receptionist; Construction Trades; Construction Trades/Plumbing Systems/Electrical Systems; Oil Fired Burner Short Course; Plumbing Systems; Secretarial Alaska Technology Learning Center, Inc Anchorage Introduction to Building Construction; Microsoft IT Helpdesk; Microsoft MCSA; Microsoft Office Specialist; Microsoft Webmaster Educational Training Providers for AGIA Occupations Training Provider Location Training Programs Alaska Trowel Trades Anchorage Cement/Plaster Alaska Vocational Technical Center Seward Basic Life Support; Building Maintenance Seminar Blueprints; Building Maintenance Seminar Electrical; Building Maintenance Seminar Plumbing Rp; Building Maintenance Seminar Sheetrock; Building Maintenance Seminar, Boilers; Building Maintenance Seminar, Carpentry; Business & Office Technology; Carpentry I, Correspondence; Diesel and Heavy Technology; Diesel Engine Technology; Diesel Marine Troubleshooting; Electrical I, Correspondence; Electrical II, Correspondence; Electrical III, Correspondence; Electrical IV, Correspondence; Electrician Apprentice, 1st Year; Electrician Apprentice, 2nd Year; Electri Apprentice, 3rd Year; Electrician Apprentice, 4th Year; Emergency Medical Technician I; Facility Maintenance Construction Trades; Facility Maintenance Mechanical; Food Service Technology; Hazard Awareness; Heavy Equipment Technology; Housing Maintenance, Worker; Information Technology; Information Technology (IT) - Village Internet Agent; Intro to Gas Metal Arc Welding; Intro to Heavy Equipment Operation; Introduction To Computers; Introduction To Excel; Introduction to Microsoft Power Point; Introduction to Microsoft Word; Marine Safety - to save Juvenile; Microsoft Access, Advanced Level; Microsoft Access, Intermediate Level; Microsoft Access, Intro Level; Microsoft Excel, Advanced Level; Microsoft Excel, Intermediate Level; Microsoft Publisher; Microsoft Windows System Maintenance; Microsoft Word, Advanced Level; Microsoft Word, Intermediate Level; Pipe Welding; Plumbing I, Correspondence; Plumbing IV, Correspondence; Power Plant Operation; Serve Safe; Sheet Metal I, Correspondence; Sheet Metal II, Correspondence; Structural Maintenance; Webpage Design; Welding Technology Alaska Works Statewide Construction Trades and Building Maintenance Apprenticeship Arctic Safety Training & Consulting Kenai S-Cook Inlet Training Standards; First Aid/CPR; Hazwoper Refresher; Hazwoper-24 Hrs; Hazwoper-40 Hrs; Health & Safety Asbestos Removal Specialists of Alaska Fairbanks Asbestos Removal Career Academy Anchorage Office Specialist; Travel Specialist Center for Employment Education Anchorage Basic Driver Training-CDL A; Construction Technology Training; Construction Technology Training with CDL; Fast Track-CDL A Charter College Anchorage Business Management Practice; Computer Aided Drafting Assistant; Computer Aided Drafting Associate; Computer Science: Business Applications Concentration; Computer Science: Networking Technology Concentration; Computer Science: Technical Graphics Concentration; Computerized Accounting; Computerized Bookkeeping Associate; Computerized Bookkeeping Specialist; Computerized Office Associate; Computerized Office Specialist; Information Technology Engineering (general - no concentration); Information Technology Engineering: Networking Technology Concentration; Information Technology Engineering: Technical Graphics Concentration; Information Technology Management (general - no concentration); Information Technology Management: Business Applications Concentration; Information Technology Management: Business Management Practice Concentration; Information Technology Management: Computerized Accounting Concentration; Information Technology Management: Computerized Medical Office Administration Concentration Educational Training Providers for AGIA Occupations Training Provider Location Training Programs Delta Mine Training Center Delta Junction Cartography; Drilling; Field Methods; GIS; Hazwoper; Hazwoper Refresher; Mineral; Mining; Underground Training vironmental Management Inc Anchorage Air Monitoring for Asbestos; Asbestos Abatement Refresher; Asbestos Awareness; Asbestos Operations and Mainte; Confined Space Alternate Entry; Confined Space Entry; EPA/AHERA Inspector; EPA/AHERA Inspector Refresher; EPA/AHERA Management Planner R; EPA/AHERA Project Design Refre; EPA/AHERAAsbestos Ab: 3PA/AHERAAsbestos Abatement Su; EPA/AHERAAsbestos Management P; Facility Asbestos Coordinators; Hazardous Materials Transportation; Hazardous Waste Operations; HAZMAT Refresher DOT/IATA; Lead Awareness; Respiratory Fit Test; Supervisor of Hazardous Waste; Training Publications Fairbanks Alaska Carpenter Training Center Fairbanks Carpentry Apprenticeship Fairbanks Area Painting and Allied Trades Fairbanks HazPaint; HazWoper Fairbanks Area Plumber and Pipefitters Fairbanks Plumbing GeoNorth Anchorage Advanced Coldfusion Development; FastTrack to Coldfusion; Intro to Arc GIS I; Intro to Are GIS Il; Programming Arc Objects with VBA Heat & Frost Insulators & Asbestos Workers Local 97 Anchorage Insulators/Asbestos Apprenticeship Hisagvik College Barrow Administrative Computer Support; Arctic Environmental Oil Spill; Business Management; Carpentry Trades Technology; Electr ‘Trades Technology; Finish Carpentry; He: Mechanical vy Truck Operations; Industrial Mechanics Technolog; Land Management; Plumbing & TUBAC Le 1 Bricklayers & Craftsman Anchorage Masonry New Frontier Vocational-Technical Center Soldotna Acct clerk; Clrk Typist Educational Training Providers for AGIA Occupations Training Provider Location Training Programs Northern Industrial Training Palmer Bus Driver; Construction Equipment Training - 5 Week; Construction Equipment Training - 6 Weel Training - 8 Week; Construction Equipment Training 2 Week (short) Courses; NCCER Carpentry I R Carpentry Level 2; NCCER Carpentry Level 3; NCCER Carpentry Level 4; NCCER Concrete Finishing Level 1; NCCER Concrete Finishing Level 2; NCCER Craft Trade Intro: Core Curriculum; NCCER Electrical Level 1; NCCER Electrical Level 2; NCCER Electrical Level 3; NCCER Electrical Level 4; NCCER Gas Pipeline Operations; NCCER Highway/Heavy Construction; NCCER HVAC Level 1; NCCER HVAC Level 2; NCCER HVAC Level 3; NCCER HVAC Level 4; NCCER Liquid Pipeline Operations; NCCER Masonry Level 1; NCCER Masonry Level 2; NCCER Masonry Level 3; NCCER Mobile Crane Level 1; NCCER Mobile Crane Level 2; NCCER Mobile Crane Level 3; NCCER Pipefitting Level 1; NCCER Pipefitting Level 2; NCCER Pipefitting Level 3; NCCER Pipefitting Level 4; NCCER Residential Carpentry Level 1; NCCER Residential Carpentry Level 2; NCCER Residential Electrical Level 1; NCCER Residential Electrical Level 2; Plumbing Level 1; Plumbing Level 2; Plumbing Level 3; Plumbing Level 4; Pro Truck Driver - 3 Week; Pro Truck Driver - 6 Week; Project Management; Scaffolding; Site Layout Level 1; Site Layout Level 2 Northwest Technical Services Inc Anchorage Computer Technology for the WorkPlace Pacific Rim Institution of Safety & Management Kenai EMT I; EMT I Refresher Project Education Residential School Galena Commercial Kitchen Production Satori Group Inc Anchorage Asbestos Abatement; Hazardous Waste Operations & Emergency Response SERRC - Alaska Vocational Institute Juneau Combined Office Skills and Computer Training; Computer Skills; Office Skills Southern Alaska Carpenters Union Training Center Anchorage Carpentry Apprenticeship; Millwright Apprenticeship Southwest Alaska Vocational & Education Center King Salmon Hazwoper-40 Hour; Hazwoper-8 Hour Refresher; NCCER Carpentry Core & Level I; Off System CDL (Commercial Drivers License); Tank Farm Welding Certification Educational Training Providers for AGIA Occupations Training Provider Location Training Programs University of Alaska Anchorage Anchorage Accounting; Apprenticeship Technology; Archit & Engr Technology; Architectural Drafting; Arctic Engineering; Business Administration; Business Computer Info Systems; Civil Engineering; Civil Engineering Drafting; Computer Information Systems; Computer Science; Culinary Arts; Diesel Technology; Electrical Engineering; Electrical Engr - Interdisc; Environmental Quality Engineer; Environmental Quality Science; Finance; Foodservice Technology; General Clerical; Geographic Information Sys; Geomatics; Global Supply Chain Mgmt; Heavy Duty Trans & Equip; Hospitality Restaurant Mgt; Management; Management Information Systems; Occupational Safety & Healt; Office Management & Technology; Office Technology; Pre-Major Accounting; Pre-Major Diesel Tech; Pre-Major Finance; Pre-Major Management; Pre-Major Management Info S; Pre-Major Technology; Public Administration; Science Management; Small Business Administration; Surveying & Mapping; Technology; Telecomm and Electronic System; Telecomm Elect & Computer Tech; UAF/UAA Mech/Elect Engr Consot; Welding Technology Kachemak Bay Accounting; Bookkeeping; General Business; Office Management & Technol; Office Technology; Small Business Administration; Small Business Mgmt; Web Foundations; Welding Technology Kenai Accounting; General Business; General Cleri Petroleum Eng Aide; Small Business Administration ; Mechanical Technology; Office Management & Technology; Office Technology; Small Business Mgmt; Welding Technology Kodiak Bookkeeping; Computer Systems Technology; General Business; General Clerical; Office Management & Technology; Technology; Word/Info Processing Mat-Su A+ Preparation (CompTIA certification); Accounting; Administrative Office Support; Applied Science - Telecommunications and Electronic Systems (TES); Architectural and Engineering Technology; Architectural Drafting; Bookkeeping; Business Administration; Cisco Local Academy Networking - Semester 1; Cisco Local Academy Networking - Semester 2; Cisco Local Academy Networking - Semester 3; Cisco Local Academy Networking - Semester 4; Civil Drafting; Computer Information and Office Systems; Computer Systems Technology; Desktop Publishing and Graphics; General Clerical; MCSE - Semester 1; MCSE - Semester 2; MCSE - Semester 3; Mechanical and Electrical Drafting; Medical Office Support; Net+ Preparation (CompTIA Network+ certification); Office Management & Technology; Office Technology; Small Business Administration; Telecommunications, Electronics and Computer Technology; Web Foundations Prince William Sound Office Management & Technology; Office Occupations University of Alaska Fairbanks Bristol Bay Applied Business; Office Management & Technology Fairbanks Accounting; Accounting Technician; Applied Accounting; Applied Business; Applied Business Mgmt; Arctic Engineering; Business Administration; Civil Engineering; Computer Science; Culinary Arts; Drafting Technology; Electrical Engineering; Engineering; Engineering Non-Major; Environmental Engineering; Environmental Quality Engineer; Environmental Quality Science; Geological Engineering; Management Non-Major; Mechanical Engineering; Medical/Dental Reception; Mining Engineering; Office Management & Technology; Petroleum Engineering; Science Management; Science, Engr & Math Non-Major; Software Engineering Interior-Aleutians Applied Accounting; Applied Business Kuskokwim Applied Accounting; Applied Business; Office Management & Technology Nome Applied Business Educational Training Providers for AGIA Occupations Training Provider Location Training Programs University of Alaska Fairbanks Rural College Accounting; Accounting Technician; Applied Accounting; Applied Business; Applied Business Mgmt; Business Administration; Civil Engineering; Computer Science; Culinary Arts; Drafting Technology; Electrical Engineering; Engineering Non-Major; Geological Engineering; Mechanical Engineering; Medical/Dental Reception; Mining Engineering; Office Management & Technology; Petroleum Engineering; Software Engineering Tanana Valley Accounting; Accounting Technician; Applied Accounting; Applied Business; Applied Business Mgmt; Business Administration; Civil Engineering; Computer Science; Culinary Arts; Diesel/Heavy Equipment; Drafting Technology; Electrical Engineering; Engineering Non-Major; Geological Engineering; Management Non-Major; Mechanical Engineering; Medical/Dental Reception; Mini Engineering; Office Management & Technology; Petroleum Engineering; Renewable Resources; TVC Administrative A: Academy University of Alaska Southeast ; Apprenticeship Technology; Business Administration; Computer Info Office Systems ion to Industrial Construction; Management; Office nvironmental Sci; Public Administration; Small Juneau Accounting; Accounting Technic Construction Technology; Diesel Technology; Environmental Science; Introdu Administration; Power Technology; Pre-Major Business Administ; Pre-Major Business Mgmt Ketchikan Accounting; Accounting Technician; Business; Business Administration; Computer Info Office Systems; Hospitality Industry Mgt; Welding Technology Sitka A ‘ounting; Apprenticeship T nvironmental Technology; Sn hnology; Business Administration; Business Technology; Computer Info Office System I Business Mgmt; Welding Technology Vocational Training & Resource Center Juneau 40 Hour Hazwoper; Commercial Drivers License (CDL) Class A Driver Training; Commercial Drivers License (CDL) Class A/B Refresher; Commercial Drivers License (CDL) Class B Driver Training; Commercial Drivers License (CDL) Class B Fast Track; NCCER Carpentry Level I Wayland Baptist University Anchorage Business Administration; Management; Occupational Education Wilderness Medicine Institute Talkeetna Wilderness First Responder Yuut Elitnaurviat Bethel Auto CAD; Carpentry; Electrical; General Construction; Plumbing Source: fJigible Training Provider Report. Information in this table is from the Eligible Training Provider program (ETP). Each year Department of Labor and Workforce Development, Research and Analysis Section, collects program information from training providers on the State ETP list as required by the Workforce Investment Act, Title I-B. For further information about this report, contact Brian Laurent at 907.465.5854 or at brian.laurent@alaska.gov. Alaska Department of Labor and Workforce Development, Research and Analysis Section (January 2008). AGIA TRAINING STRATEGIC PLAN The following abbreviations are used throughout the plan. ABE Adult Basic Education AGIA Alaska Gasline Inducement Act AKCIS Alaska Career Information System ANSEP Alaska Native Science and Engineering Program AVTEC Alaska Vocational Technical Center AWIB Alaska Workforce Investment Board CTE Career and Technical Education (formerly known as Vocational Education) CTSO Career and Technical Student Organizations ESL English as a Second Language GED Graduate Equivalency Degree DEED Department of Education and Early Development DOLWD Department of Labor and Workforce Development OJT On the Job Training SCANS _ Secretary’s Commission on Achieving Necessary Skills STEP State Training and Employment Program TVEP Technical Vocational Education Program UA University of Alaska WIA Workforce Investment Act AGIA TRAINING STRATEGIC PLAN NV1d JIDALVALS ONINIVAL VLOV This publication was produced in Anchorage, Alaska for the Alaska Department of Labor and Workforce Development Alaska Department of Labor and Workforce Development PO Box 111149 Juneau, Alaska 99811-1149 http://labor.alaska.gov/