The URL can be used to link to this page

Home My WebLink AboutSuWa184Alaska Resources Library & Information Services Susitna-Watana Hydroelectric Project Document ARLIS Uniform Cover Page Title: Alaska Railbelt regional integrated resource plan (RIRP) : draft report presentation SuWa 184 Author(s) – Personal: Author(s) – Corporate: Black & Veatch AEA-identified category, if specified: AEA-identified series, if specified: Series (ARLIS-assigned report number): Susitna-Watana Hydroelectric Project document number 184 Existing numbers on document: Published by: [Overland Park, Kan. : Black & Veatch, 2009] Date published: December 10, 2009 Published for: Date or date range of report: Volume and/or Part numbers: Final or Draft status, as indicated: Draft Document type: Slide presentation. No commentary. Pagination: 88 p. Related work(s): Pages added/changed by ARLIS: Notes: All reports in the Susitna-Watana Hydroelectric Project Document series include an ARLIS- produced cover page and an ARLIS-assigned number for uniformity and citability. All reports are posted online at http://www.arlis.org/resources/susitna-watana/ Alaska Railbelt Regional Integrated Resource Plan (RIRP) December 10, 2009 Draft Report Presentation December 10, 2009Page -1 Agenda Introductory Comments and Introductions Project Overview/Executive Summary Situational Assessment Methodology Considerations Key Assumptions Susitna Analysis Summary of Results Financial Analysis Risks and Uncertainties Implementation Action Plan (2010-2012) Questions and Answers Concluding Comments December 10, 2009Page -2 Consultant Team Black & Veatch –Prime HDR, Inc. –Susitna Analysis EPS, Inc. –Transmission Stability Analysis Seattle-Northwest Securities –Financial Analysis December 10, 2009Page -3 Advisory Working Group Members Norman Rokeberg, Retired State of Alaska Representative, Chairman Chris Rose, Renewable Energy Alaska Project Brad Janorschke, Homer Electric Association Carri Lockhart, Marathon Oil Company Colleen Starring, Enstar Natural Gas Company Debra Schnebel, Scott Balice Strategies Jan Wilson, Regulatory Commission of Alaska Jim Sykes, Alaska Public Interest Group Lois Lester, AARP Marilyn Leland, Alaska Power Association Mark Foster, Mark A. Foster & Associates Nick Goodman, TDX Power, Inc. Pat Lavin, National Wildlife Federation -Alaska Steve Denton, Usibelli Coal Mine, Inc. Tony Izzo, TMI Consulting December 10, 2009Page -4 Project Overview / Executive Summary December 10, 2009Page -5 Some Definitions REGA means “Railbelt Electrical Grid Authority” GRETC means “Greater Railbelt Energy & Transmission Company” RIRP means “Railbelt Integrated Resource Plan” REGA study determined the business structure for future Railbelt G&T GRETC initiative is the joint effort between Railbelt Utilities and AEA to unify Railbelt G&T RIRP is the economic plan for future capital investment in G&T and in fuel portfolios that GRETC would build, own and operate Three Discrete Tasks December 10, 2009Page -6 What is an RIRP? Current Situation •Limited redundancy •Limited economies of scale •Dependence on fossil fuels •Limited Cook Inlet gas deliverability and storage •Aging G&T infrastructure •Inefficient fuel use •Difficult financing •Duplicative G&T expertise RIRP Study •Plan that economically schedules what, when, and where to build, based on available fuel and energy supplies •50-year time horizon •Competes generation, transmission, fuel supply and DSM/energy efficiency options •Includes CO2 regulation •Includes renewable energy projects •Arrives at a plan to build future infrastructure for minimum long-run cost to ratepayers •Considers fuel supply options and risks December 10, 2009Page -7 Limitations of RIRP Does not set State energy policy Directional Identified/generic/actual projects Agnostic to owner/developer of projects December 10, 2009Page -8 GRETC Vision A statutory company Privately owned not-for-profit company with public responsibilities defined in law Own and operate Railbelt power generators and transmission lines Build infrastructure specified in the RIRP Significant financial muscle to shoulder long-term debt Make use of State and federal financial underwriting To benefit all Railbelt ratepayers equally Regulated by RCA under tailored regulations or non- jurisdictional with strong bond covenants December 10, 2009Page -9 Stakeholder Involvement Process December 10, 2009Page -10 Key Drivers Resource-specific risks Gas availability and price Acceptability of large hydro and other renewables Potential CO2 costs Limited transmission network Required financing Regional vs. individual utility focus December 10, 2009Page -11 Evaluation Scenarios December 10, 2009Page -12 Results –DSM/EE Resources Energy Requirements (MWh) 0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 8,000,000 20112014201720202023202620292032203520382041204420472050205320562059YearEnergy Requirements (MWh)Without DSM/EE With DSM/EE December 10, 2009Page -13 Results –Scenario 1A Energy By Resource Type 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal Wind Municipal Solid Waste Geothermal Hydro Purchase Power Fuel Oil Nuclear Coal Natural Gas December 10, 2009Page -14 Results –Scenario 1B Energy By Resource Type 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal Wind Municipal Solid Waste Geothermal Hydro Purchase Power Fuel Oil Nuclear Coal Natural Gas December 10, 2009Page -15 Results –Scenario 2A Energy By Resource Type 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 20112014201720202023202620292032203520382041204420472050205320562059Energy (GWh)Ocean Tidal Wind Municipal Solid Waste Geothermal Hydro Purchase Power Fuel Oil Nuclear Coal Natural Gas December 10, 2009Page -16 Results –Scenario 2B Energy By Resource Type 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal Wind Municipal Solid Waste Geothermal Hydro Purchase Power Fuel Oil Nuclear Coal Natural Gas December 10, 2009Page -17 Sensitivity Cases Scenario 1A Without DSM/EE Measures Scenario 1A With Committed Units Included Scenario 1A Without CO2 Costs Scenario 1A With Higher Gas Prices Scenario 1A With Fire Island Scenario 1A Without Chakachamna Scenario 1A With Chakachamna Capital Costs Increased by 75% Scenario 1A With Susitna (Lower Low Watana Non-Expandable Option) Forced Scenario 1A With Susitna (Low Watana Non-Expandable Option) Forced Scenario 1A With Susitna (Low Watana Expandable Option) Forced Scenario 1A With Susitna (Watana Expansion Option) Forced Scenario 1A With Susitna (Watana Option) Forced Scenario 1A With Susitna (High Devil Canyon Option) Forced Scenario 1A With Modular Nuclear Scenario 1A With Tidal December 10, 2009Page -18 Results –Economics Case Cumulative Present Value Cost ($000,000) Average Cost (¢ per kWh) Renewable Energy in 2025 (%) Total Capital Investment ($000,000) Scenarios Plan 1A $12,925 4.60 49.17% $10,035 Plan 1B $12,916 4.59 54.78% $10,014 Plan 2A $20,978 4.29 53.57% $18,226 Plan 2B $21,507 4.40 55.55% $22,175 Sensitivities 1A Without DSM/EE Measures $13,262 4.40 51.10% $9,791 1A With Committed Units Included $13,863 4.93 32.03% $9,592 1A Without CO2 Costs $10,402 3.70 14.36% $8,685 1A With Higher Gas Prices $14,945 5.31 61.94% $9,798 1A With Fire Island $12,965 4.61 54.78% $10,502 1A Without Chakachamna $13,273 4.72 22.80% $9,179 1A With Chakachamna Capital Costs Increased by 75% $13,273 4.72 22.80% $9,179 1A With Susitna (Lower Low Watana Non- Expandable Option) Forced $15,209 5.41 54.70% $13,166 1A With Susitna (Low Watana Non-Expandable Option) Forced $14,898 5.30 60.18% $14,742 1A With Susitna (Low Watana Expandable Option) Forced $15,437 5.49 60.18% $15,274 1A With Susitna (Low Watana Expansion Option) Forced $15,943 5.67 61.58% $15,902 1A With Susitna (Watana Option) Forced $16,281 5.79 61.82% $16,049 1A With Susitna (High Devil Canyon Option) Forced $16,238 5.77 61.82% $16,016 1A With Modular Nuclear $12,591 4.48 49.05% $9,864 1A With Tidal $12,198 4.34 59.10% $10,052 December 10, 2009Page -19 Results –Emissions Case CO2 (million tons) NOx (million tons) SO2 (million tons) Scenarios Plan 1A 176,205 222 36 Plan 1B 169,440 216 33 Plan 2A 287,321 281 240 Plan 2B 250,460 245 75 Sensitivities 1A Without DSM/EE Measures 181,208 242 242 1A With Committed Units Included 219,645 351 273 1A Without CO2 Costs 222,614 295 383 1A With Higher Gas Prices 166,406 248 268 1A With Fire Island 166,934 223 39 1A Without Chakachamna 219,110 223 35 1A With Chakachamna Capital Costs Increased by 75% 219,110 223 35 1A With Susitna (Lower Low Watana Non - Expandable Option) Forced 158,703 210 35 1A With Susitna (Low Watana Non - Expandable Option) Forced 127,589 207 38 1A With Susitna (Low Watana Expandable Option) Forced 127,589 207 38 1A With Susitna (Low Watana Expansion Option) Forced 140,912 208 38 1A With Susitna (Watana Option) Forced 138,140 209 39 1A With Susitna (High Devil Canyon Option) Forced 134,780 208 39 1A With Modular Nuclear 162,858 224 37 1A With Tidal 153,908 213 33 December 10, 2009Page -20 Conclusions –Preferred Resource Plan DSM/EE Programs (2011) Anchorage and GVEA MSW (2012) Fire Island Wind (2012) Southcentral Power Plant (2013) Glacier Fork Hydro (2015) Nikiski Wind (2017) Anchorage Simple Cycle Turbine (2018) GVEA Combined Cycle (2020) Parallel pursuit of Chakachamna/Susitna/Glacier Fork Multiple transmission projects December 10, 2009Page -21 Conclusions –Other Regional resource plan –historical cross-road Increased reliance on DSM/EE and renewables Robust transmission network Need for frequency regulation Spreading of risks Foundation for economic development Cost of renewables future if large hydro is not development Larger loads = lower unit costs December 10, 2009Page -22 Conclusions –Regional or Individual Utility Future 0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 20112014201720202023202620292032203520382041204420472050205320562059YearAnnual Cost of Power ($000,000)Scenario 1A With Committed Units Scenario 1A Base Case December 10, 2009Page -23 RIRP Plan 1A Capital Expenditures and Debt Capacity of the Railbelt Utilities Conclusions –Financing the Future Capital Expenditures High Debt Capacity Low Debt Capacity December 10, 2009Page -24 Conclusions –GRETC as the Enabler Current Situation •Limited redundancy •Limited economies of scale •Dependence on fossil fuels •Limited Cook Inlet gas deliverability and storage •Aging G&T infrastructure •Inefficient fuel use •Difficult financing •Duplicative G&T expertise RIRP Study •Plan that economically schedules what, when, and where to build, based on available fuel and energy supplies •50-year time horizon •Competes generation, transmission, fuel supply and DSM/energy efficiency options •Includes CO2 regulation •Includes renewable energy projects •Arrives at a plan to build future infrastructure for minimum long-run cost to ratepayers •Considers fuel supply options and risks RIRP Results •Increased DSM/energy efficiency •Increased renewables •Reduce dependence on natural gas •Increased transmission GRETC -Enabler REGA Study Proposed GRETC Formation Future Situation •Robust transmission •Diversified fuel supply •System-wide power rates •Spread risk •State financial assistance •Regional planning •Wise resource use •Respond to large load growth •Technical resources •New technologies 10-Year Transition Period Financing Options •Pre-funding of capital requirements •Commercial bond market •State financial assistance (Bradley Lake model) •Construction-work-in-progress December 10, 2009Page -25 Conclusions –Resource-Specific Risks Relative Magnitude of Risk/Issue Resource Resource Potential Risks Project Development and Operational Risks Fuel Supply Risks Environmental Risks Transmission Constraint Risks Financing Risks Regulatory/ Legislative Risks DSM/EE Moderate Limited N/A N/A N/A Limited - Moderate Moderate Generation Resources Natural Gas Limited Limited Significant Moderate Limited Moderate Moderate Coal Limited Moderate- Significant Limited Moderate - Significant Limited - Significant Moderate – Significant Moderate Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Large Hydro Limited Significant N/A Significant Significant Significant Significant Small Hydro Moderate Moderate N/A Moderate Moderate Limited - Moderate Limited Wind Moderate Moderate N/A Limited Moderate Limited - Moderate Limited Geothermal Moderate Moderate N/A Moderate Moderate – Significant Limited – Moderate Limited Solid Waste Limited Moderate- Significant N/A Significant Moderate Limited – Moderate Limited- Moderate Tidal Limited Significant N/A Significant Moderate - Significant Moderate – Significant Moderate - Significant Transmission Limited Significant N/A Moderate N/A Significant Moderate - Significant December 10, 2009Page -26 Conclusions –Transmission Projects December 10, 2009Page -27 Recommendations Form GRETC Establish State energy policies Large hydro DSM/EE RPS and pursuit of other renewables System benefit charge Select preferred resource plan Public outreach program December 10, 2009Page -28 Recommendations (continued) Address level/form of State assistance Address short-term and long-term gas supply issues Develop regional portfolio of DSM/EE programs and provide start-up funding Begin detailed engineering/permitting activities associated with selected generation and transmission projects Pursue Chakachamna, Susitna and Glacier Fork to determine if any of these projects can be built December 10, 2009Page -29 Recommendations (continued) Form regional entity (if GRETC is not formed) to develop DSM/EE programs and renewable projects Pursue Federal funding for DSM/EE programs and renewable projects Streamline siting/permitting process for transmission projects Develop regional frequency regulation strategy Develop competitive power procurement process and standard power purchase agreement December 10, 2009Page -30 What it Means? 10% / 8% 50% $10 billion $0.5 –$1.5 billion 7.3% December 10, 2009Page -31 Situational Assessment December 10, 2009Page -32 History of Independent but Cooperative Decisions Infrastructure Investments Alaska Intertie Bradley Lake Hydro Project Gas Supply ML&P’s investment Attractive historical prices Innovative Solutions GVEA’s BESS Joint Operations and Contractual Arrangements Intertie Operating and Reliability Committees Full requirements contracts Economy sales December 10, 2009Page -33 Summary of Issues Cost Issues RAILBELT Future Adopt New Direction Maintain Status Quo Businesses and Consumers Power Costs Future Resource Options Uniqueness of the Railbelt Region Natural Gas Issues Infrastructure Issues Load Uncertainties Political Issues Cost Issues RAILBELT Future Adopt New Direction Maintain Status Quo Impact on Railbelt Reliability Sustainability Risks Future Resource Options Uniqueness of the Railbelt Region Natural Gas Issues Infrastructure Issues Load Uncertainties Political Issues Management Risk December 10, 2009Page -34 Methodology Considerations December 10, 2009Page -35 Methodology Considerations Time horizon –50 years Models used –Strategist®and PROMOD® Hydroelectric methodology Transmission analysis Financial analysis December 10, 2009Page -36 Key Assumptions December 10, 2009Page -37 General Assumptions RIRP conducted assuming GRETC in place Study period: 2011-2060 Objective Function: 2011 Cumulative Present Value Costs December 10, 2009Page -38 Costs Included Railbelt system fuel costs Railbelt system non-fuel O&M costs Railbelt system CO2 emission allowance costs Capital costs for new Railbelt generation Capital costs for new Railbelt transmission Costs Not Included Existing generation capital costs Existing transmission capital costs Distribution costs December 10, 2009Page -39 Evaluation Scenarios December 10, 2009Page -40 Significant Load Growth Opportunities Large new loads (mines, etc.) Conversion from gas to electric space and water heating Electric vehicles December 10, 2009Page -41 Resources Considered Demand-Side Management/Energy Efficiency (DSM/EE) Measure Categories Conventional Generation Resources Renewable Resources Residential Simple Cycle Combustion Turbines Hydroelectric Projects Appliances LM6000 (48 MW) Susitna Water Heating LMS100 (96 MW) Chakachamna Lighting Combined Cycle Glacier Fork Shell 1x1 6FA (154 MW) Generic Hydro – Kenai Cooling/Heating 2X1 6FA (310 MW) Generic Hydro - MEA Commercial Coal Units Wind Water Heating Healy Clean Coal BQ Energy/Nikiski Office Loads Generic – 130 MW Fire Island Motors Generic Wind – Kenai Lighting Generic Wind - GVEA Refrigeration Geothermal Cooling/Heating Mt. Spurr Municipal Solid Waste Generic – Anchorage Generic - GVEA Other Resources Included in Sensitivity Cases Modular Nuclear Tidal December 10, 2009Page -42 Planning Reserve Margin 30 Percent for GRETC No capacity credit is given for wind Operating Reserves Operating reserves –150% times largest unit on the system times area’s share Area’s share = area’s largest unit / sum of all utility participants’ largest units Spinning reserves –100% times largest unit on the system times area’s share BESS included as 27 MW of spinning reserve in GVEA’s area SILOs not included December 10, 2009Page -43 Assumed Transmission System Transfer Capability Alaska Intertie Current –75 MW south and north 2024 –130 MW south and north Southern Intertie Current –60 MW south, 75 MW north 2016 –110 MW south, 120 MW north December 10, 2009Page -44 Natural Gas Prices 4 6 8 10 12 14 2010 2015 2020 2025 2030 YearGas Price ($US / MMBtu). Forecast of Railbelt Gas (purchase price for electric utility) Forecast of LNG Delivered in Japan Projection of ConocoPhillips-ENSTAR Contract (2008, terms through 2013) Projection of Marathon-ENSTAR Contract (2008, terms through 2017) Armstrong (North Fork)-ENSTAR contract (2009, floor & ceiling) December 10, 2009Page -45 CO2 Allowance Costs Year $/ton 2012 18.41 2020 39.70 2030 103.78 2040 213.91 2050 440.89 2060 564.38 December 10, 2009Page -46 Committed Units Plant Name Area Capital Cost ($000) Maximum Winter Capacity (MW) Commercia l Online Date Southcentral Power Project Anchorage 281,100 187 2013 ML&P 2500 Simple Cycle Anchorage 43,200 33 2012 MLP LM6000 Combined Cycle Anchorage 95,200 73 2014 Healy Clean Coal Project GVEA 95,000 50 2011/2014 HEA Aeroderivative HEA (1) 34 2014 HEA Frame HEA (1) 42 2014 Nikiski Upgrade HEA (1) 77 (34 incremental) 2012 Eklutna Generation Station MEA 269,900 180 2015 Seward Diesel #N1 City of Seward 7,200 2.9 2010 Seward Diesel #N2 City of Seward 1,100 2.5 2011 (1)HEA has requested that their cost estimates remain confidential while they are obtaining their bids. December 10, 2009Page -47 Transmission -GRETC Concept Transmission system to be upgraded over time to remove transmission constraints that currently prevent the coordinated operation of all the utilities as a single entity. This is projected to happen within ten 10 years. December 10, 2009Page -48 Starting Assumptions for Transmission Analysis Study to include all the utilities' assets 69 kV and above. These assets, over a transition period, flow into GRETC and form the basis for a phased upgrade of the system into a robust, reliable transmission system that can accommodate the economic operation of the interconnected system. Assumes that all utilities participate in GRETC with planning being conducted on a GRETC basis. The common goal will be the tight integration of the system operated by GRETC. December 10, 2009Page -49 Railbelt Transmission Projects Projects classified in following categories: Transmission projects to connect new generation projects to the grid (Generation Interconnections) Transmission projects to upgrade the grid required by new generation projects (Generation Upgrades) Replacement projects that need to be done because of age and condition (Replacement) Upgrade projects to the grid to implement the GRETC concept, based on existing generation (GRETC) December 10, 2009Page -50 Load Profile –2011 Peak GVEA Area Load 238 MW MEA Area Load 146 MW Anchorage Area Load 412 MW Kenai Area Load HEA/SES 97 MW December 10, 2009Page -51 Recommended Transmission Projects No. Transmission Projects Type Cost ($000) Priority 1 Soldotna – University New Build (230kV) $161,250 1 2 Soldotna – Quartz Creek Upgrade (230kV) $84,000 1 3 Quartz Creek – University Upgrade (230kV) $112,500 1 4 Lake Lorraine – Douglas New Build (230kV) $46,200 2 5 Douglas – Healy Upgrade (230kV) $12,000 2 6 Douglas – Healy New Build (230kV) $252,000 3 7 Beluga – Pt. Mackenzie New Build (230kV) $67,700 3 8 Douglas - Teeland Upgrade (230kV) $37,500 3 9 Healy – Gold Hill Upgrade (230kV) $145,500 4 10 Hea ly – Wilson Upgrade (230kV) $145,500 4 11 Soldotna – Bradley Lake Upgrade (115kV) $61,800 4 12 Daves Creek – Seward New Build (115 kV) $28,000 4 13 Eklutna – Lucas New Build (230kV) $13,300 5 14 Lucas – Teeland Upgrade (230kV) $26,100 5 15 Lucas – Teeland New Build (230kV) $26,100 5 16 Pt. Mackenzie – Plant 2 Replacement (230kV) $32,200 6 December 10, 2009Page -52 Susitna Analysis December 10, 2009Page -53 Susitna Hydroelectric Project December 10, 2009Page -54 Project Location December 10, 2009Page -5555 Watana DamDevil Canyon Dam Watana ReservoirDevil Canyon Reservoir N Potential Project Sites High Devil Canyon Dam December 10, 2009Page -56 Evolution of Susitna Project Studies 1983 Submittal of FERC license application 1985 Revised FERC license Phased project development 1986 Project shelved Reason was drop in price of fossil-fuel generated power March 2008 Interim Susitna Report Re-evaluation of cost, energy, schedule and economics of 5 of the 1980s project alternatives Fall 2009 RIRP support Development of alternative projects tailored to system loads and costs Nov. 2009 Final Susitna Report Evaluation of cost, energy, and schedule of 9 project alternatives 56 December 10, 2009Page -57 Fall 2009 RIRP Work Identify lower cost alternatives Estimate energy and cost Determine firm capacity 57 Firm Capacity “the amount of power the project can generate on a continuous basis from Nov. 1 through April 30 with 98% reliability” December 10, 2009Page -58 RIRP Project Configurations Studied All Single Dam Configurations Lower Low Watana 620’ high dam, 380 MW Low Watana (1985 Phase 1 development) 685’ high dam, 600 MW Low Watana (non-expandable) Watana 880’ high rockfill dam, 1,200 MW RCC Watana 880’ high roller compacted concrete (RCC) dam, 1,200 MW High Devils Canyon 855’ high RCC dam, 775 MW 58 December 10, 2009Page -59 Project Comparison December 10, 2009Page -60 Study Results 60 Alternative Dam Type Ultimate Capacity (MW) Firm Capacity, 98% (MW) Construction Cost ($ Billion) Energy GWh/yr) Schedule (years from start of Licensing) Lower Low Watana Rockfill 380 170 $4.1 2,100 13-14 Low Watana Non- expandable Rockfill 600 245 $4.5 2,600 14-15 Low Watana Expandable Rockfill 600 245 $4.9 2,600 14-15 Watana Rockfill 1,200 380 $6.4 3,600 15-16 Watana RCC Roller Compacted Concrete 1,200 380 $6.6 3,600 14-15 Devil Canyon Concrete Arch 680 75 $3.6 2,700 14-15 High Devil Canyon Roller Compacted Concrete 800 345 $5.4 3,900 13-14 Watana/Devil Canyon Rockfill/Concrete Arch 1,880 710 $9.6 7,200 15 -20 Staged Watana/Devil Canyon Rockfill/Concrete Arch 1,880 710 $10.0 7,200 15 -24 Alternative Dam Type Ultimate Capacity (MW) Firm Capacity, 98% (MW) Construction Cost ($ Billion) Energy GWh/yr) Schedule (years from start of Licensing) Lower Low Watana Rockfill 380 170 $4.1 2,100 13-14 Low Watana Non- expandable Rockfill 600 245 $4.5 2,600 14-15 Low Watana Expandable Rockfill 600 245 $4.9 2,600 14-15 Watana Rockfill 1,200 380 $6.4 3,600 15-16 Watana RCC Roller Compacted Concrete 1,200 380 $6.6 3,600 14-15 Devil Canyon Concrete Arch 680 75 $3.6 2,700 14-15 High Devil Canyon Roller Compacted Concrete 800 345 $5.4 3,900 13-14 Watana/Devil Canyon Rockfill/Concrete Arch 1,880 710 $9.6 7,200 15 -20 Staged Watana/Devil Canyon Rockfill/Concrete Arch 1,880 710 $10.0 7,200 15 -24 December 10, 2009Page -61 Conclusions Of all the renewable resources in the Railbelt region, the Susitna projects are the most advanced and best understood Project is considered to be technically feasible Environmental and seismic risk is considered manageable 61 December 10, 2009Page -62 December 10, 2009Page -63 Summary of Results December 10, 2009Page -64 Limitations of RIRP Does not set State energy policy Directional Identified/generic/actual projects Agnostic to owner/developer of projects December 10, 2009Page -65 Results –DSM/EE Resources Energy Requirements (MWh) 0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,000 7,000,000 8,000,000 20112014201720202023202620292032203520382041204420472050205320562059YearEnergy Requirements (MWh)Without DSM/EE With DSM/EE December 10, 2009Page -66 Results –Scenario 1A Energy By Resource Type 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal Wind Municipal Solid Waste Geothermal Hydro Purchase Power Fuel Oil Nuclear Coal Natural Gas December 10, 2009Page -67 Results –Scenario 1B Energy By Resource Type 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal Wind Municipal Solid Waste Geothermal Hydro Purchase Power Fuel Oil Nuclear Coal Natural Gas December 10, 2009Page -68 Results –Scenario 2A Energy By Resource Type 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 20112014201720202023202620292032203520382041204420472050205320562059Energy (GWh)Ocean Tidal Wind Municipal Solid Waste Geothermal Hydro Purchase Power Fuel Oil Nuclear Coal Natural Gas December 10, 2009Page -69 Results –Scenario 2B Energy By Resource Type 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 20112014201720202023202620292032203520382041204420472050205320562059ENERGY(GWh)Ocean Tidal Wind Municipal Solid Waste Geothermal Hydro Purchase Power Fuel Oil Nuclear Coal Natural Gas December 10, 2009Page -70 Sensitivity Cases Scenario 1A Without DSM/EE Measures Scenario 1A With Committed Units Included Scenario 1A Without CO2 Costs Scenario 1A With Higher Gas Prices Scenario 1A With Fire Island Scenario 1A Without Chakachamna Scenario 1A With Chakachamna Capital Costs Increased by 75% Scenario 1A With Susitna (Lower Low Watana Non-Expandable Option) Forced Scenario 1A With Susitna (Low Watana Non-Expandable Option) Forced Scenario 1A With Susitna (Low Watana Expandable Option) Forced Scenario 1A With Susitna (Watana Expansion Option) Forced Scenario 1A With Susitna (Watana Option) Forced Scenario 1A With Susitna (High Devil Canyon Option) Forced Scenario 1A With Modular Nuclear Scenario 1A With Tidal December 10, 2009Page -71 Results –Economics Case Cumulative Present Value Cost ($000,000) Average Cost (¢ per kWh) Renewable Energy in 2025 (%) Total Capital Investment ($000,000) Scenarios Plan 1A $12,925 4.60 49.17% $10,035 Plan 1B $12,916 4.59 54.78% $10,014 Plan 2A $20,978 4.29 53.57% $18,226 Plan 2B $21,507 4.40 55.55% $22,175 Sensitivities 1A Without DSM/EE Measures $13,262 4.40 51.10% $9,791 1A With Committed Units Included $13,863 4.93 32.03% $9,592 1A Without CO2 Costs $10,402 3.70 14.36% $8,685 1A With Higher Gas Prices $14,945 5.31 61.94% $9,798 1A With Fire Island $12,965 4.61 54.78% $10,502 1A Without Chakachamna $13,273 4.72 22.80% $9,179 1A With Chakachamna Capital Costs Increased by 75% $13,273 4.72 22.80% $9,179 1A With Susitna (Lower Low Watana Non- Expandable Option) Forced $15,209 5.41 54.70% $13,166 1A With Susitna (Low Watana Non-Expandable Option) Forced $14,898 5.30 60.18% $14,742 1A With Susitna (Low Watana Expandable Option) Forced $15,437 5.49 60.18% $15,274 1A With Susitna (Low Watana Expansion Option) Forced $15,943 5.67 61.58% $15,902 1A With Susitna (Watana Option) Forced $16,281 5.79 61.82% $16,049 1A With Susitna (High Devil Canyon Option) Forced $16,238 5.77 61.82% $16,016 1A With Modular Nuclear $12,591 4.48 49.05% $9,864 1A With Tidal $12,198 4.34 59.10% $10,052 December 10, 2009Page -72 Results –Emissions Case CO2 (million tons) NOx (million tons) SO2 (million tons) Scenarios Plan 1A 176,205 222 36 Plan 1B 169,440 216 33 Plan 2A 287,321 281 240 Plan 2B 250,460 245 75 Sensitivities 1A Without DSM/EE Measures 181,208 242 242 1A With Committed Units Included 219,645 351 273 1A Without CO2 Costs 222,614 295 383 1A With Higher Gas Prices 166,406 248 268 1A With Fire Island 166,934 223 39 1A Without Chakachamna 219,110 223 35 1A With Chakachamna Capital Costs Increased by 75% 219,110 223 35 1A With Susitna (Lower Low Watana Non - Expandable Option) Forced 158,703 210 35 1A With Susitna (Low Watana Non - Expandable Option) Forced 127,589 207 38 1A With Susitna (Low Watana Expandable Option) Forced 127,589 207 38 1A With Susitna (Low Watana Expansion Option) Forced 140,912 208 38 1A With Susitna (Watana Option) Forced 138,140 209 39 1A With Susitna (High Devil Canyon Option) Forced 134,780 208 39 1A With Modular Nuclear 162,858 224 37 1A With Tidal 153,908 213 33 December 10, 2009Page -73 Financial Analysis December 10, 2009Page -74 RIRP Plan 1A Capital Expenditures and Debt Capacity of the Railbelt Utilities Debt Capacity vs. Capital Requirements Capital Expenditures High Debt Capacity Low Debt Capacity December 10, 2009Page -75 Greater Railbelt Energy & Transmission Company Funding Concept for Large/Long Useful Life Assets 1-40 Years Formation/Maturation 41+ years Stability Power Sales Agreements Buy/Sell Services Repayment of Low-Interest Funding GRETC GRETC Debt Capital Markets Grant and Low Interest Construction/Long-Term Funding *30-40 year Funds P&I Power Sales Agreements Buy/Sell Services Credit December 10, 2009Page -76 Strategies to Lower Capital Cost of RIRP to Ratepayers Ratepayer benefits charge “Pay-go” vs. borrowing for capital Construction Work in Progress State financial assistance Repayment flexibility Credit support/risk mitigation Potential interest cost benefit December 10, 2009Page -77 Comparison of Capital Rates for Base Case Scenario and Alternative* Scenario Fixed Rate Charge for Capital - 0.02 0.04 0.06 0.08 0.10 0.12 0.14 20112016202120262031203620412046205120562061206620712076$/per kWhBase Case Alternative Case *Alternative scenario includes $0.01 Consumer Benefit Charge through 2027 December 10, 2009Page -78 Capital Funding Sources •Rate Payer Benefits Charge •Debt Capital Markets •Asset Transfers •State Funds Setting Stage for Funding GRETC Steps Toward Funding Define GRETC Organizational Structure Develop Phased Transition Plan Identify State’s Role in Funding Initiate Dialogue with RCA GRETC Utility Managed Corporation December 10, 2009Page -79 Risks and Uncertainties December 10, 2009Page -80 General Risks Organizational Fuel supply Inadequacy of transmission network Market development Financing and rate impacts Legislative and regulatory December 10, 2009Page -81 Resource-Specific Risks -Summary Relative Magnitude of Risk/Issue Resource Resource Potential Risks Project Development and Operational Risks Fuel Supply Risks Environmental Risks Transmission Constraint Risks Financing Risks Regulatory/ Legislative Risks DSM/EE Moderate Limited N/A N/A N/A Limited - Moderate Moderate Generation Resources Natural Gas Limited Limited Significant Moderate Limited Moderate Moderate Coal Limited Moderate- Significant Limited Moderate - Significant Limited - Significant Moderate – Significant Moderate Modular Nuclear Limited Significant Moderate Significant Limited Significant Significant Large Hydro Limited Significant N/A Significant Significant Significant Significant Small Hydro Moderate Moderate N/A Moderate Moderate Limited - Moderate Limited Wind Moderate Moderate N/A Limited Moderate Limited - Moderate Limited Geothermal Moderate Moderate N/A Moderate Moderate – Significant Limited – Moderate Limited Solid Waste Limited Moderate- Significant N/A Significant Moderate Limited – Moderate Limited- Moderate Tidal Limited Significant N/A Significant Moderate - Significant Moderate – Significant Moderate - Significant Transmission Limited Significant N/A Moderate N/A Significant Moderate - Significant December 10, 2009Page -82 Resource-Specific Risks –Wind (Sample) Resource: Generation – Wind Risk/Issue Category Description Primary Actions to Address Risk/Issue Resource Potential Total economic resource potential is unknown Resource potential may be constrained by Railbelt regional system regulation requirements Complete regional economic potential assessment, including the identification of the most attractive sites Develop regional regulation strategy for non-dispatchable resources Project Development Ineffectiveness and inefficiencies associated with six individual utilities developing wind projects Lack of standard power purchase agreements for projects developed by IPPs Establish a regional entity (e.g., GRETC) or rely on IPPs to identify and develop wind projects Develop regional standard power purchase agreements Develop regional competitive power procurement process to encourage IPP development of projects Fuel Supply Not applicable Not applicable Environmental Site specific environmental issues Comprehensive evaluation of site specific environmental impacts at attractive sites Transmission Constraints Location of new facilities can add to transmission constraints Integration of non-dispatchable resources into Railbelt transmission grid poses challenges Expand Railbelt transmission network Require that all proposed plant locations also include transmission infrastructure analyses and costs as part of any approval process Develop regional strategy for the integration of non-dispatchable resources Financing Cost per kW can be significant Aggressively pursue available Federal funding for renewable projects Regulatory/Legislative Regional commitment to renewable resources is uncertain Establish State RPS targets Develop State policies regarding RECs and Green Pricing December 10, 2009Page -83 Implementation Action Plan (2010-2012) December 10, 2009Page -84 Implementation Action Plan Form GRETC Establish State energy policies Large hydro DSM/EE RPS and pursuit of other renewables System benefit charge Select preferred resource plan Public outreach program December 10, 2009Page -85 Implementation Action Plan (continued) Address level/form of State assistance Address short-term and long-term gas supply issues Develop regional portfolio of DSM/EE programs and provide start-up funding Begin detailed engineering/permitting activities associated with selected generation and transmission projects Pursue Chakachamna, Susitna and Glacier Fork to determine if any of these projects can be built December 10, 2009Page -86 Implementation Action Plan (continued) Form regional entity (if GRETC is not formed) to develop DSM/EE programs and renewable projects Pursue Federal funding for DSM/EE programs and renewable projects Streamline siting/permitting process for transmission projects Develop regional frequency regulation strategy Develop competitive power procurement process and standard power purchase agreement December 10, 2009Page -87 Questions and Answers December 10, 2009Page -88 Concluding Comments