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HomeMy WebLinkAboutSE Intertie US Dept of Energy Approval 2000a JUN-07-00 WED 04:42 PM 06/06/00. 14: ; P, 02/03 : cae ae eee Pe eee, + GOY STATE OFF : Qoo1/o06 NEWS FROM THE OFFICE OF - FRANK MURKOWSKI united States Senator Alaska “Ror Immediate Release: Contact: Chuck Kleeschulte or Cindi Bookout’ - ' June 7, 2000 O. (202) 224-9306; H (301) 283-4149; O 224-8767. (Email: chuck_klesschulte@murkowski. senate. gov). : oe MURKOWSEI WINS PANEL APPROVAL FOR SOUTHEAST INTERTIE: : . WASHINGTON -- In an effort to promote economic development in Southeast ‘ Alaska in the face of the downturn of its timber industry, Alaska Sen. Frank: -: Murkowski today won, Senate Energy and Natural Resources Committee approval for at legislation to authorize the Southeast Alaska power intertie. : ‘Murkows#1 and Sen. Ted Stevens this spring introduced legislation(S 2439) : to enable the Secretary of Energy to assist in organizing financing for construction - : of the Panhandle’s power grid. Communities in Southeast currently intend to form a . State-chartered regional power authority to finance and manage the intertie.. The: . .. federal legislation would allow Congress simply to assist communities in assembling funding for the project. similar to how the Central Arizona and Central Utah power . ‘projects were financed and built, : 3 “In the last decade, known by most of the country as the greatest: poorh oe '? eentury, Southeast Alaska has lost 2,800 jobs and well over $100 million in payro’ ’ Many communities have lost population and income. Wrangell and Petersburg SS ; last 13 percent of their salary income, Ketchikan 12 percent and personal income _ is down from 5 to 11 percent throughout the region. f “In other areas of the.country high-tech cormpanies have replaced resource- based industries. But there’is no comparable replacement industry for: Southeast, the biggest reason is lack of affordable power. This bill is intended to help solve that ': problem,” said Murkowski, who-noted that federal assistance is warranted eince the * vast majority of Southeast Alaska is owned and controlled by the federal | government. Murkoweki noted that power rates vary in. the Panhandle, For example Rake’ pays 38 cents pe kilowatt hour ‘for its diesel-generated electricity. He said construction of a regional intertie would allaw lower-cost hydroelectric ding to flow to all villages, reducing diesel-fired generation and use:costs, provi g reliable and clean sources ‘of backup power and cutting air pollution; The Senator argued during the meeting that the authorization; which was introduced at the request of the Southeast Conference, the organization of mayors representing all Southeast Alaska communities, will not obligate the federal government to be involved in construction.of the intertie and that-there is no interest in the government owning or managing any part of the system, ..He added the authorization in no way changes any environmental regulations ma the JUN-07-00 WED 04:42 PM 06/08/00 14:30 Fix P, 03/03 : — — — — ee eee ———= SOY STATE OFP 002/006 Murkowski: SE Intertie wins Energy Panel Approval _ June 7, 2000 : “The era of the federal government constructing, owning or operating new power facilities has passed. The federal government can provide valuable assistance to a group of Seraniettten that seek to get their region back on the road to economic recovery. This is a good bill becanse it encourages local self-reliance,” said Murkowski. The mtertie is a five-phase proposal that calls on first tying the Swan Lake and Tyee hydroelectric projects in Ketchikan and Wrangell together. sending some of that power to Metlakatla, then connecting Sitka and Kake to the Ketchikan system, and then extending the lines north to tic mio Juneau's power. provide power to Angoon, Tenakee Springs, Hoonah and then to complete extending power to tie into Skagway and Haines and eventually to cover the rest: of Prince of Wales Island. . . “The bi2 faced some opposition from members who argued against authorizing al five phases of the project. Murkowski, however, argued that authorization does” _ Hot mean the federal government! will-necessarily finance the entire line. < . ‘: "One of the things that is different here (in Southeast} is that the state has |. already funded construction of the dams. The state has paid for the Swan Lake and . | Tyee Lake dams ($128 million). They are mountain ie tapped from the bottom ‘ ha aving no affect on fish streams. . : “The state is noi getting a free. ride. Alaska is never going to get federal help a for big water projects, we are si 4s some federal assistance for wuseabisitins . through an area totally owned by the federal government....We feel our needs are |: a@ifferent,” said Murkowski in nox! of the bill, that easity eee out ot the panel “om a voice vote. -30- MEDIA NOTE: There will bea satellite feed giving the senator's ‘arguments f for the tine during today’s hearing, The feed, a 5-minute feed, will run from 2 to 2:05 p.m. ADT this afternoon on Telestar 5, traneponder 5V, channel 5, downlink 3800. Audio will be available by calling 1-800-546-1267 then pressing 322. Digital audio is available on the web at; www. ELE ere Ofte RE W. . " vur ni_aAg_an mum anean ou N-GO-UU fun UoruN Fit eCaveevon TUR 14.48 Das Written Statement of the U.S, Department of Enetgy : ~ on §, 2439, Southeastern Alaska Intertic submitted tothe - Committee on Energy and Natural Resources’ United States Senate June 6, 2000 _ Mr Chairman, in tespvase to your request the Department of Energy hereby submits written testimen, providing our views on $. 2439, This bill would authorize Congress to z _wcoptiate to DOE “such sums as may be necessary to assist i in the coustruction of the Southeastern Alaska Intertie system as generally identified in Report #97-01 of the Southeast Conference. . L Mr, Chairman, the Department of Energy does not support tae enactment of S. 2439. Additional analysis ‘of the proposed intertie and possible =!ernatives should be undertaken before Congress authorizes the expenditure of a substan’ial sum of domestic discretionary finds ~: approximately $450 million. . The Administrition recognizes that distribution ite transmission infrastructure costs to pride electric setvice to sparsely populated areas can be higher than the costs of providing service to more densely populated regions. The Rural Utilities Service (RUS) and, its predecessor, the Rural Electrification Administration (REA), have done a tremendous job of telning to elecisify a America by making loans available to vezal cooperative utilities. . However, loans are not issued automatically. In some areas the cost of providing service is so prohibitive that ioans are not issued because of poor prospecis of repayment. Thetis why 5. 1947, the Adniaistration’ s comprehensive electricity -restr votaring legislation, proposes th Congress ‘authorize $20 million ammuatly for seven years to fund a rural and remote commaunities : The Department of Energy recognizes that certain corr-uunities in southeastem Alasica saifer from relatively high energy costs and that if ts possible that t the RUS loan program may noi be sbie to: ‘help this region reduce its eleciic costs. Moreover, many sma!l communities i-, che area currently rely’ extensively on diesel-powered generation: for their electricity supply. It is important ‘that the region diversify its source of electriciiy Sor both environmental and economic veasons, The Adiinisivation 8 proposed electricity reste: “unag bill L would a help part of the region move in thet direction by authorizing $20 million tc si-.vice financiel assistance to Alaska ‘to SUN, -06-00 TUE 06:07 PM P. 04/04 eee 06/06/00 TUR 18:48 FAX . Boos ensure the availability of adequate electrical power to the greater Ketchikan. area in sourbeast Alaska, including the construction cfan intertie.” The intent of this provision is toc: Bixthos ize funding that could be used to pay for th-z alternative that is ultimately determined : ty, be othe best meens of making additional power av. ‘ilable to this area, This could inc’, ude the constriction ofa subset of the intertie that is being fice S. 2349 to make zxcess hydropowe: -iapabity, available to certuin communities ir the area, and cov! also include alternative aie designed to reduce reliance on 6 esel ge wation in the Ketchikan area. * ; . Nevertheless, we b ‘uve more analysis is needed before Congress considers Ss: 2439, While the bill ¢--.. not include a specific price tag for the proposed southeastern’ Alisks inte, DOE 1 .crstands that approximately $450 million in federal fumding would be required: Given ..¢ amount that would be needed, it is essential that Congress and the Administration thoroughly examine the proposed intertie and all possible alternatives. For example, great advances have; been made in fuel cell technologies, Although natural gas may not be available in the region, it is possible that fuel ceils operating on sitemnative fusls could be used to replace existing diesel generation. In addition, there could be some potential for locally produced hydropower in certain communities in the region: Moreover, it might be less expensive to promote inereaoini energy. efficiency initiatives aimed at reducing the region's reliance on dirty and costly diesel generation. These and other possibilities should’ be thoroughly examined before Congress commits itself’ to expend $450 million on the proposed intertie. Thank you for this: oppormunity te xo sudmuit our views on this legislation, re ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY / = ALASKA =_, ENERGY AUTHORITY 480 WEST TUDOR ANCHORAGE, ALASKA 99503 907 / 269-3000 FAX 907 / 269-3044 MEMORANDUM TO: Randy Simmons Executive Director FROM: Art Copoulos LY Project Manager DATE: May 23, 2000 SUBJECT: HVDC vs. HVDC Light This memo is to clarify the differences between High Voltage Direct Current (HVDC) and HVDC Light. Some confusion has arisen because | have referred to HVDC Light as a new unproven technology, yet HVDC is an old proven technology. HVDC Light is really both — it is a new application of an old technology. It has all the advantages of the old HVDC technology and attempts to overcome its limitations with several new technologic advances. A more detailed explanation is as follows: Direct Current (DC), as its name implies, does not change its direction of current flow. The flow of current is in one direction with a return current in the opposite direction. This is distinguished from Alternating Current (AC), where current periodically can reverse flow direction. In the early history of electric power distribution, DC power transmission technology was the most common way to distribute power. Over time, however, and for a variety of reasons such as reliability, ability to regulate voltages better, convenience, low cost of AC equipment, and the flexibility for load growth, low voltage AC systems replaced DC systems as the recognized ideal distribution system for providing the highest quality of service. Today, a network of AC equipment and power distribution is in place throughout the world. With this AC network in place, the applications for DC power is limited, not only for the reasons described above, but also due to its incompatibility with in place AC systems and equipment. There are however, some unique situations, where DC is still advantageous to use over AC. These situations include large point-to-point transmissions, often over vast distances across land or underwater, and asynchronous links between 2 AC systems. alae Wi Vy ottasy The main reasons that DC is still advantageous to use over AC in the case of long distance transmissions is that it can be applied with less losses over longer distances and with stronger cables. In long-distance applications exceeding 50-100 kilometers, a conventional HVAC Memorandum May 23, 2000 Page 2 system is technically difficult or costly to use due to the higher amount of line losses compared to HVDC. In the ABB Power Systems (ABB) attachment, a variety of HVDC power transmission schemes are described. In most cases described, the HVDC system was employed because of the long distance (100 kilometers +) or long sea crossing involved. HVDC Light is a scaled-down version of a conventional HVDC power transmission system that uses new semiconductor technology to allow the bulky components of an HVDC system - such as power converters, switches, filters and transformers - to be much smaller, and capable of doing more. According to ABB, the Swedish designer, manufacturer, and supplier of HVDC Light, there are a number of advantages in comparison to both HVDC and HVAC. The advantages of HVDC Light in comparison to HVDC are described below. The advantages of HVDC Light in comparison to HVAC are described in my February 9, 2000 memo that is attached for reference. Vi f HVDC Light in comparison to HVD rdi ABB e HVDC Light requires fewer and smaller components and can be designed as a modular system. e HVDC Light can be more easily serviced and maintained. e HVDC Light is much more compatible with existing AC systems. HVDC Light voltage source converters can switch current on or off so that the output voltages and currents on the AC side can be more easily controlled. The HVDC Light voltage source converters automatically adjust the voltage, frequency, and flow of active and reactive power according to the needs of the AC system rather than relying on the AC networks ability to keep voltage and current stable. e HVDC Light has also improved on the cables that were previously used in HVDC transmission. HVDC Light uses an extruded HVDC cable rather than paper insulated oil- filled cables, or mass impregnated non-draining cables that were previously used in HVDC transmission. According to ABB, these improvements allow direct ploughing underground, insulated aerial cables, and underwater cables in severe conditions. Both HVDC Light and HVDC can use steel armor submarine cables, which is a significant advantage in comparison to HVAC cables. Although HVDC is old technology, aspects of the HVDC Light technology such as the semiconductor technology, modular systems, and voltage source converters are new and largely unproven. In 1999, ABB only had one installation fully completed and operational. However, a number of new installations were in progress and according to EPRI the use of HVDC, employing ABB’s HVDC Light or other similar systems is expected to grow dramatically. Attachments cc? David Germer, Deputy Director - Business Development and Rural Energy Dennis McCrohan, Deputy Director — Project Development and Operations Stan Sieczkowski — Operations and Maintenance Manager HVDC -— Power Transmissions oMiaiee [tao eS Back-to-back SCHEME 1. GOTLAND 2. SKAGERRAK 7 & 2 3% CAHORA BASSA Direct voltage per 50 250 133 converter, kV Direct current, A 200 1000 1800 Reactive power supply Capacitors Capacitors Capacitors Synchronous condensers Synchronous condensers Converter station location Vastervik, 130 kV Kristiansand, 275 kV Songo, 220 kV and AC grid voltage Visby, 70 kV Tjele, 150 kV Apollo, 275 kV Lenght of overhead - 113 km 1420 km DC line AC grids at both ends Asynchronous Control Constant power in Constant power either direction Emergency change of On manual or automatic - power flow order to preset value Main reason for choosing HVDC system Long sea crossing, frequency control Sea crossing Long distance Main supplier of converter equipment 4. INGA-SHABA §. CU-PROJECT 6. NELSON RIVER 2 7. ITAIPU 500 400 250 300 560 1250 2000 2610 Capacitors Capacitors Capacitors Capacitors Synchronous condensers Power generator Synchronous condensers Inga (Zaire River), 220 kV Kolwezi (Shaba), 220 kV 1700 km Coal Creek, 235 kV Dickinson, 350 kV 687 km Henday, 230 kV Dorsey, 230 kV 940 km Foz do Iguagu, 500 kV Ibiuna, 345 kV 785 and 805 km, respectively Asynchronous Synchronous Asynchronous Foz do Iguagu, 50 Hz Ibiuna, 60 Hz Constant power or constant frequency in Shaba Constant power, damping control Constant power Constant power, damping control Long distance Distance, environment, stability benefits Long distance Long distance, 50/60 Hz conversion ABB: Converters, controls, ABB ABB/Siemens/AEG ABB system responsibility GE: Transformers, filters synchronous condensers SCHEME 8 GOTLAND 2 9. DURNROHR 10. PACIFIC INTERTIE UPGRADING Direct voltage per 150 converter, kV 145 100 Direct current, A 914 3790 2000 Reactive power supply Capacitors Capacitors Capacitors Synchronous condenser Converter station location Vastervik, 180 kV Dirnrohr, 420 kV Celilo, 230 kV and AC grid voltage Visby, 70 kV CSSR side, 420 kV Sylmar, 230 kV Lenght of overhead 7 km 1360 km DC line AC grids at both ends Asynchronous Asynchronous Synchronous Control Constant frequency Constant power in Constant power in either direc: on Gotland either direction tion and small signal modulatio Emergency change of On manual or automatic power flow order to preset values Main reason for choosing HVDC system Long sea crossing Asynchronous link Long distance, rapid control Main supplier of ABB ABB/Siemens/AEG ABB converter equipment 11. CHATEAUGUAY 12, INTERMOUNTAIN 13. HIGHGATE ene 140.6 500 57 3600 Capacitors 2 x 3600 1920 3600 Capacitors and SVC. Capacitors Capacitors Hydro-Quebec side, 315 kV U.S. side, 120 kV Intermountain, 345 kV Adelanto, 500 kV 785 km Highgate North, 120 kV Highgate South, 115 kV New Mexice side, 345 kV Texas side, 230 kV Synchronous Asynchronous Asynchronous Asynchronous Constant power, damping control Constant power Constant power in either direction Constant power, reactive power control Automatic power reduction triggered by AC-signal Asynchronous link Asynchronous link Long distance Asynchronous link ABB/Siemens ABB ABB ABB SCHEME 15. VINDHYACHA, 16. BROKEN HILL 17. GOTLAND 3 Direct voltage per 70 8.3 converter, kV 150 Direct current, A 3600 2400 914 Reactive power supply Capacitors Synchronous condenser 22 kV 6.9 kV Capacitors Capacitors Synchronous condenser Vastervik, 130 kV Visby, 70 kV Converter station location and AC grid voltage Northern system, 400 kV Western system, 400 kV Lenght of overhead DC line 7 km AC grids at both ends Asynchronous Asynchronous Control Constant power in either Constant 40 Hz frequency Constant frequency direction, damping control on Gotland Emergency change of Automatic power reduction - power flow triggered by AC signal Main reason for choosing Asynchronous link Frequency control Long sea crossing HVDC system Main supplier of ABB ABB ABB converter equipment 18 RIHAND-DELHI 19, KONTI-SKAN 2 20, QUEBEC ~ NEW ENGLAND 500 285 450 400 1568 1050 2200 1250 Capacitors Capacitors Capacitors Capacitors Rihand, 400 kV Lindome, 130 kV Radisson, 315 kV Dannebo, 400 kV Dadri, 400 kV Vester Hassing, 400 kV Sandy Pond, 345 kV Rauma, 400 kV Nicolet, 230 kV 1480 km 814 km 61 km 33 km Synchronous Asynchronous HQ synchronous NEH asynchronous Synchronous Constant power, Constant power in Multiterminal, constant power } Constant power, damping control either direction control, frequency control damping control On manual or automatic On manual or automatic Isolation of Radisson from Sea crossing order order to preset value the AC system at severe AC disturbances Asynchronous link Long distance, stability Sea crossing, asynchronous link ABB BHEL, India, main contractor ABB subcontractor to BHEL under licence agreement SCHEME 22, PACIFIC INTERTIE EXPANSION 23. GEZHOUBA ~ SHANGHAI 24, NEW ZEALAND DC HYBRID LINK Direct voltage per 500 500 350 converter, kV Direct current, A 1100 1200 1600 Reactive power supply Capacitors Capacitors Capacitors Synchronous condensor Converter station location Celilo, 500 Kv Gezhouba, 500 kV Benmore, 220 kV and AC grid voltage Sylmar, 230 kV Nan Qiao, 230 kV Haywards, 220 kV Lenght of overhead DC line 1360 km 1000 km 575 km AC grids at both ends Synchronous Asynchronous Asynchronous Control Constant power in either direc-}| Constant power, Constant power, frequency tion and small signal modulation} reactive power control and damping control Emergency change of On manual or automatic On manual or automatic Frequency control of power flow order to preset value order to preset value isolated Wellington area Main reason for choosing Long distance, Long distance, Long distance including HVDC system rapid control stability benefits sea crossing Main supplier of ABB/Siemens converter equipment 25. SKAGERRAK 3 26. BALTIC CABLE 27, KONTEK PADGHE 350 1260 1500 1500 Capacitors Capacitors Capacitors Capacitors Synchronous condensor Kristiansand, 300 kV Kruseberg, 400 kV Bjeeverskov, 400 kV Chandrapur, 400 kV Tjele, 400 kV Herrenwyk, 380kV Bentwisch, 400 kV Padghe, 400 kV 113 km 12 km 736 km Asynchronous Asynchronous Synchronous Constant power, frequency and damping control Asynchronous Constant power in either direction Constant power, frequency and damping control Constant power, frequency and damping control On manual or automatic order Long distance, stability On manual or automatic order to preset value On manual or automatic order to preset value On manual or automatic order to preset value Sea crossing asynchronous systems Sea crossing Sea crossing ABB ABB ABB ABB/BHEL SCHEME 29, LEYTE-LUZON 30. SWEPOL 31. BRAZIL-ARGENTINA INTERCONNECTION 350 450 Direct voltage per 70 converter, kV Direct current, A 1260 1330 3930 Reactive power supply Capacitors Capacitors Capacitors Converter station location Ormoc, 230 kV, Starnd, 400 kV Garabi, Brazil, 525 kV and AC grid voltage Naga, 230 kV Slupsk, 400 kV Argentina, 500 kV Lenght of overhead 433 km - Back-to-back DC line AC grids at both ends Asynchronous Asynchronous Brazil, 60 Hz Argentina, 50 Hz Control Constant power, Power control, Constant power frequency control emergency power control Emergency change of On manual or automatic On automatic order On automatic order power flow order to preset value to set values to preset values Main reason for choosing HVDC system Long distance including sea crossing Long distance and sea crossing Different AC system frequences Main supplier of ABB ABB ABB converter equipment 32. ITALY-GREECE 33. THE THREE GORGES ~ CHANGZHOU 1250 3000 Capacitors Galatina, 400 kV Arachthos, 400 kV Capacitors Longquan, 500 kV Zhengping, 500 kV 890 km Asynchronous Constant power Constant power Frequency control Sea crossing Long distance Asynchronous networks ABB ABB ABB HVDC Projects >ridwide Thyristor Valves 1970 - 6, Nelson River 2 5. CU-Project oe ol, Be diag’ 4 a 10. Pacific Intertle Upgrading 22. Pacific Intertie Expansion 12. Intermountain 14, Blackwater, SE-771 80 Ludvika, Sweden Tel: +46 21782000 Fax: +46 21611159 e-mail: info.sepow@se.abb.com E g ADD 5 2 ABB Power Systems AB z HVDC Division 2 Z 2 Presented at Cigré Symposium, Kuala Lumpur, Malaysia, September 1999 SUPPLY TO RAPIDLY GROWING CITIES AND AREAS FIDEL S. CORREA THE PHILIPPINES SUMMARY The use of geothermal power contributes significantly to environmental improvements on a national as well as a global scale. The Leyte geothermal resources have the potential for pro- viding low cost and highly reliable energy, much needed to meet the Philippines’ growing power requirements. The HVDC interconnection is beneficial to both industry and the inhabitants of the Manila area, not only through the added power influx, but also through the inherent sta- bilizing effect of an HVDC link on the AC network KEYWORDS: HVDC - Converter - Electrodes - Cable terminal stations - OH transmission line - MACH. 1. BACKGROUND The main objective of the Leyte-Luzon HVDC Power Transmission Project is to interconnect the power systems of Leyte and Luzon Islands with an HVDC transmission link. The project enables transmission of the electrical gen- erating capacity of the geothermal reserves in Leyte to various load centers, and will interconnect two of the ex- isting island grids of the Philippines as part of an overall plan to combine the existing Luzon, Visayas and Mindanao grids into a single national grid. See Fig. 1. It will also facilitate the use of the geothermal generating capacity in the Leyte area. The project forms a vital link in Napocor’s Power Development Program since, through the interconnection of generating assets, it is possible to balance energy supply and demand requirements more efficiently. With the normal power-flow direction from Leyte to Luzon, the Ormoc converter station will act as the rectifier and Naga converter station as the inverter. This means that from LEIF R. WILHELMSSON*) NATIONAL POWER CORPORATION ABB POWER SYSTEMS AB SWEDEN JACQUES F. ALLAIRE HYDRO QUEBEC INTERNATIONAL CANADA the geothermal fields of Tongonan in Leyte, power will be fed into the Luzon grid, thereby feeding the Manila area through the existing AC grid. The converter, electrode and cable terminal stations were contracted to a consortium consisting of ABB Power Sys- tems AB, Sweden; ABB Power Inc., Philippines and Marubeni Corporation, Japan. Leyte-Luzon HVDC transmission Philippines Fig. 1. Leyte-Luzon HVDC transmission Philippines. * Leif R. Wilhelmsson, ABB Power Systems AB, SE-771 80 Ludvika, Sweden 2. FINANCING The project was primarily funded by a USD 113 million loan from the World Bank, which also provided extended co-financing amounting to USD 100 million. Financial as- sistance was also extended by the Export Import Bank of Japan through a USD 56 million loan, as well as by the Swedish Board for Investment and Technical Support, and by the Global Environment Trust Fund through separate grants of USD 41 million and USD 15 million respec- tively. Local counterpart funding was raised by Napocor through internal cash generation. 3. MAIN SYSTEM COMPONENTS The Leyte-Luzon HVDC monopolar system is composed of the following major components, as shown in Fig. 2. Converter Station 230 kV AC Fig. 2. Schematic of the HVDC interconnection. * Converter stations located in Naga (Luzon) and Ormoc (Leyte) * HVDC cables across the San Bernardino strait, 23 km (one cable is redundant). * Cable terminal stations located in Cabacungan (Samar) and Sta Magdalena (Luzon) + Shore electrodes located in Albuera (Leyte) and Calabanga (Luzon). * Overhead bipolar transmission line in two sections of 180 km (Luzon) and 240 km (Leyte-Samar). * Electrode lines, 15 km in Luzon and 25 km in Leyte. 4. CONVERTER STATIONS The converter valves, smoothing reactors (240 mH) and converter transformers are of the same design at both sta- tions for 440 MW at 350 kV direct voltage and 230 kV alternating voltage. The valves are suspended quadruple valves, air-insulated, water-cooled and the transformers are ofa single-phase three-winding design. At the converter station at Ormoc, there are three identical filter banks (35 MVAr each) on the AC side, each with an 11th/13th double-tuned branch and a high pass broadband branch. The converter station in Naga is equipped with two filter banks (70 MVAr each) of similar design as in Ormoc, and one 3rd harmonic high pass filter bank (78 MVAr). Each of the filter banks in both stations is connected to the converter station 230 kV AC bus via a power circuit breaker. The use of overhead lines makes it necessary to filter har- monics from the outgoing direct current and of that rea- son a DC filter to shunt the harmonics is installed. 5. SHORE ELECTRODE Leyte-Luzon, being a monopolar system, implies that low resistivity and economical current return path is required. Shore electrodes were considered as the most appropriate solution and have minimum impact on the environment. The electrodes located in Albuera (Leyte) and Calabanga (Luzon) are composed of 40 sub-electrodes each having two units for a total of 80 units per site. The sub-elec- trodes are installed in two parallel rows over a distance of about 200 m along the shores at depths varying from 10 to 13 m. Currents between sub-electrodes are balanced by mean of resistors located in the electrode building and connected in series with each sub-electrode cable. Elec- trode line equipment required for detecting faults on the line is also housed in the same building. The access roads and facilities that have been used to build the electrodes are now much appreciated by fishermen and the local population. Beaches have been restored to their original condition and opened for public use. Measure- ments performed during commissioning have shown that no appreciable step and touch voltages can be detected. This proves that it is safe for all living creatures in the area. Additional monitoring continues and should demon- strate the proper operating behavior of the electrodes. 6. HVDC CABLES AND CABLE TERMINAL STA- TIONS Two 350 kV 440 MW oil-filled cables were chosen for crossing the San Bernardino strait over a distance of 23 km between Sta Magdalena on Luzon Island and Cabacungan on Samar Island. The cables are buried from cable terminal stations out to a water depth of about 10 m. One cable is capable of carrying continuously rated cur- rent and overload current, which means that the other cable can be considered fully redundant. In normal operation, cables are paralleled, thus contributing to reduced system losses. A Japanese consortium consisting of the Nissho Iwai Corporation; Hitachi Cable, Ltd.; Fujikura Ltd. and the Kanematsu Corporation was awarded the contract for the design, manufacture, delivery and supervision of the installation of the cables, including cable terminations and protective arresters. Oil treatment plants and storing fa- cilities for spare cable sections were also included in the scope of supply. The cables were transported and laid in April 1996. Field tests were successfully performed in early 1997 and the cable terminal stations were completed later in the same year. Even if the best route had been selected based on previous sea bottom surveys, it was not possible during cable lay- ing to avoid all rocks, boulders, holes and dips in the sea- bed. Extensive use of remote operated cameras helped in avoiding major obstacles, but this was not sufficient. It had been contractually agreed that cable protection was needed for suspension lengths greater than 7 meters for sea current velocities above 3 knots, measured at 2 meter above the sea bottom. With the assistance of the remote video camera recorders, it was found that a number of sus- pension lengths exceeded the contractually agreed length. Various cable protection methods were evaluated. Rock dumping was found to be the most appropriate method, considering the very rough and uneven seabed. About 45 cable sections, totalling 1.5 km, were protected by rocks with average diameters ranging from 50 to 125 mm. A post- work survey has shown that so far, the method seems to be acceptable. No problem has been experienced with the cables since installation in April 1996. The cable terminal stations contain the cable sealing ends, protective arresters, oil pump plant, monitoring equipment, telecommunications equipment, auxiliary supplies and all necessary disconnectors and ground switches for parallel- ing the two cables and the overhead transmission circuits. 7. HIGH VOLTAGE OVERHEAD TRANSMISSION AND ELECTRODE LINES The HVDC overhead bipolar transmission line runs from Ormoc converter station, through Leyte and the Samar Is- lands, where it ends at the Cabacungan cable terminal sta- tion. From the Sta Magdalena cable terminal station on Luzon Island, the line runs all the way to the Naga con- verter station. More than half of the line’s route is through mountainous terrain, very steep in places and with risks for landslides. Most of the other half of the line passes rice fields and other cultivation. Because of the various types of soils found along the line’s route, different foun- dations were used as well as different tower designs. One of the most important aspects in the design of the line has been the capability to withstand wind velocities of up to 270 km per hour. This has resulted in a more stringent design criteria than that for seismic considerations. Atmospheric pollution has been considered and adequate creepage distances have been included in the design. Be- cause the Philippines is a tropical country, vegetation un- der the line grows very quickly and requires regular clear- ing. To assist in fault localization, a DC line fault locator has been incorporated in the converter station equipment. The electrode lines run from the respective converter sta- tions in Ormoc and Naga to the respective electrode sta- tions in Albuera and Calabanga. ABB SAE Sadelmi S.p.A., Italy was awarded the contract for the electrode and overhead transmission lines. 8. CONTROL SYSTEM For HVDC (High Voltage Direct Current) applications, the control and protection system plays an essential part in the overall performance of the transmission system. The control and protection system MACH™ (Modular Ad- vanced Control for HVDC), uses the latest technology from the fields of electronics and microprocessors. MACH is a fully computerized control and protection system. The main characteristics of the MACH are the high de- gree of functional integration and the open systems inter- face approach. The open systems strategy is reflected both in the use of industrial standard serial and parallel com- munication buses, as well as in the use of standard formats for all collected data (such as events, alarms and distur- bance data). Integrated with the MACH control and protection equip- ment is the Station Control and Monitoring (SCM) sys- tem. Workstations (PCs) are interconnected by an Ethernet local area network. The distributed system for remote I/O, for control as well as for process interfacing with the SCM system, consists of a field bus network. The HVDC transmission link can be remotely controlled from the dispatch center in Manila (Diliman), where all major alarm/indication functions are available. The control system for Leyte-Luzon includes an Emer- gency Power Control mode and a Frequency Control mode in addition to the normal power control. The main pur- pose of the Emergency Power Control (EPC) is to quickly and automatically change the DC power when certain AC parameters deviate from their nominal values. This is done to perform fast power support in case of disturbances in the Luzon AC network. The EPC modulation is available in the Naga converter station and operates only during nor- mal power direction and requires operational telecommu- nications. The Frequency Control mode is active in Ormoc during normal power direction. The Frequency Control will hold the frequency of the Leyte (Visayas) AC network at 60 Hz, +/- a preset deadband. In the event of loss of one of the geothermal machines, or a trip of the Cebu cable, the frequency control will make a contribution to the Power Control in order to adjust the power transmitted on the DC link and keep the frequency within the deadband. However, any action from the Emergency Power Control at Naga will override and disable the Frequency Control at Ormoc. 9. SYSTEM TESTS This is the first time that an HVDC system is directly con- nected to a network almost solely supplied by geothermal power. The Leyte-Luzon HVDC power transmission sys- tem is the largest load for Leyte geothermal power gen- eration. The second largest load comes from the islands of Cebu, Negros and Panay, partly fed by the 200 MW, 230 kV interconnection composed of overhead transmis- sion lines and cables. In order to accommodate the loads during the system tests, notice of approximately one day was necessary to allow for the preparation of an adequate number of steam wells and machines. One important aspect to consider when relying on geo- thermal power is not only the necessary planning to pass from one power level to another, but also the consequences of load rejection for the plants and environment. Trips and blocks of the HVDC system result in steam being released to the outside environment. When power transmission is not quickly reestablished, wells have to be closed. By modulating its power, the HVDC system is capable of com- pensating for possible load/frequency variations on the Leyte-Cebu system. Loss of HVDC cannot be compen- sated by the Visayas network absorbing more power. In the same way, loss of the Visayas network load cannot be compensated by the HVDC if it is already operating at rated power. Consequently, under these operating condi- tions, the Leyte machines must be shut down. The system test was completed on July 12,1998. After four weeks of trial operation, the HVDC link was taken into commercial operation on August 10,1998. A separate paper regarding commissioning and system tests of the Leyte-Luzon HVDC Power Transmission Project will be proposed for Cigré 2000 in Paris. 10. OPERATING EXPERIENCES Operational experiences since the fall of 1998 are very positive. High availability and reliability of the HVDC system is expected in the future. During the system test period, and during the first part of the burn-in period, there were a few unexpected trips caused by various reasons. 11. ENVIRONMENTAL COMPLIANCE The Leyte project assists in the development of critically needed energy in the Philippines and supports the use of an energy source that is both environmentally preferable and indigenous based. Furthermore, the project will have a meaningful impact on global warming emissions since an alternative coal-fired based plant would cause carbon dioxide (CO,) emissions that were 15 to 20 times greater. The use of geothermal steam for power generation, fol- lowed by re-injection of exhaust liquids into the ground, offers considerable environmental advantages over fossil fuel energy sources in terms of reducing emissions of sulfites, NOX and particulates. 12. FUTURE EXTENSION The project contains certain pre-investments for a future addition of a second pole. Such pre-investments include part of service building, spare parts for each station (in- cluding converter transformers and oil-filled smoothing reactors with foundations), design of equipment for future installation as well as site preparation for the bipolar sys- tem. Furthermore, the bipolar HVDC overhead transmis- sion line and cables are already installed and commis- sioned, simplifying the conversion to a full bipolar system ata later stage. In addition, about three-quarters of the bipolar AC filter configuration is already installed at the monopolar stage. An HVDC interconnection between Leyte and Mindanao is under investigation that would complete the overall plan to interconnect the existing Luzon, Visayas and Mindanao grids into a single national grid. 13. CONCLUSION With this first HVDC link between the islands of Leyte and Luzon, the first part of the overall plan to interconnect the existing grids on Luzon, Visayas and Mindanao has been achieved. The Leyte geothermal resources have the potential for pro- viding low cost and highly reliable energy much needed to meet the Philippines’ growing power requirements. The development of geothermal resources implies the use of an environmentally preferable energy, avoiding coal and oil imports, and resulting in a more robust generating sys- tem. Furthermore, as the Leyte-Luzon project is a major step in the overall interconnection of the grid, it would offer potential long-term benefits associated with the bet- ter use of the country’s energy resources in power gen- eration, as well as the opportunity to improve the operation of the power system, to reduce reserve capacity, and pro- vide more reliable service. Presented at Distribution 2000 Conference, Brisbane, Australia, November 1999 Network interconnection using HVDC Light Authors Anthony S Cook, TransEnergie, Australia Pty. Ltd, Brisbane, Qld., Australia 4000 Mike Wyckmans, ABB Transmission and Distribution Limited, Vic 3140, Australia Lars Weimers, ABB Power Systems, HVDC Division, SE-771 80 Ludvika, Sweden Kjell Eriksson, ABB Power Systems, HVDC Division, SE-771 80 Ludvika, Sweden Abstract The HVDC Light is an electric power transmission technology for small and medium size transmissions. This technology is well suited for connection of networks that otherwise are difficult or impossible to interconnect. Accurate control of the transmitted active power and independent control of the reactive power in the connected ac networks contribute to this as will be exemplified. HVDC Light is designed as standard units between 5 and 150 MW and are built in movable housings. This together with the above technical characteristics make them suitable for power exchange as a business concept and even opens up possibilities for leasing of transmission units. Keywords Transmission, HVDC Light, deregulation, electricity market, controllability. 1.0 Introduction Governments world-wide are increasingly using competition in the electricity industry as a means of achieving cost effective outcomes, and the Australian National Electricity Code constantly stresses the importance to the National Electricity Market of competitive, market-oriented outcomes. However, while competition in the generation sector is now well established, to date the achievement of market outcomes in the provision of network services has been ignored or neglected. This situation is largely due to outdated assumptions regarding economies of scale and scope and the inevitability of loop flow. These assumptions have hindered the deployment of advanced technologies, including HVDC Light. Such technologies will greatly facilitate market-driven network services, and over time will produce the same effects in the network sector that the introduction of gas turbine and combined cycle technology has produced in the generation sector, where competition is now taken for granted. This paper first reviews the historical role of network services. It then outlines how competitive power markets have changed that role, and the basis for competition in the provision of network services. The HVDC Light technology is described in some detail. The part that technologies such as HVDC Light will play in the development of competitive network services is discussed. The discussion is illustrated through the Directlink project, which is based on the HVDC Light technology. 2.0 The Provision and Role of Network Services The introduction of competitive power markets has added considerable complexity to the provision of network services and thereby changed the fundamental role of network services. Historically, the role of the vertically integrated utility was to plan the development of the power system for reliable and secure operation. In that regulated environment the utility planned both new generation and network services. New generation was designated as base load, intermediate or peaking plant, based on its position in the merit order. With the level of operation of each generation facility known in advance with reasonable certainty it was relatively straightforward for the utility to provide sufficient network capacity consistent with that level of operation. With the advent of competition in the generation sector Independent Power Producers (IPPs) plan new generation facilities in response to market forces. In such an environment the network service provider has little or no information regarding the location or level of operation of generation facilities, and therefore the required level of network service. To further complicate matters the required level of network service is a random variable determined by the power market in response to generator bids. The role of network services has also changed as a result of the introduction of competitive power markets. Whereas historically the role of network services was to play a passive role transporting power from generation facilities to the load center, network services are now seen as actively competing with generation. The debate over the South Australia New South Wales Interconnection (SANI) is a good illustration. If SANI was to be constructed remote generators in New South Wales would have direct access to the South Australian market, and be able to compete with local South Australian generators to supply the South Australian load. In that case SANTis equivalent to a ‘virtual generator’ located in South Australia. The basic issue with SANI was who should pay for new network services. That is, should generators receive the benefits of access to the South Australian market at no cost, while consumers receive little or no benefits but incur the bulk of the costs? A related issue is whether network service providers should receive essentially risk free regulated returns on investments that are competing in the energy market. The Australian response to these issues has been to further examine the competitive provision of network services. 3.0 Competition in Network Services The National Electricity Code defines both ‘regulated’and ‘non-regulated’ network services. Provided the network service is ‘justified’ under the terms of the Code, the owners of a regulated network service receive a fixed, annual revenue from their investment. On the other hand the owners of a non-regulated network service must earn their revenue in the market by charging market participants who use that network service. Non- regulated network services do not need to be justified under the Code. As a first step in the provision of competitive ‘non-regulated’ network services the National Electricity Code Administrator (NECA) developed the Safe Harbour Provisions for Entrepreneurial Interconnectors (SHPs). The SHPs recognise that network services do not just play a passive role transporting power, rather that they can actively participate in the power market. The SHPs define the conditions under which network services can compete in the power market. The SHPs as presently drafted are quite restrictive, and should be treated as only the first step towards competitive network services; it is NECA’s intention to further expand the SHPs. In order to meet the SHPs a network service must satisfy a number of conditions, including: e The service must comprise a single two-terminal element of at least 30 MW capacity that directly connects networks in different price regions. e The flow through the service must be independently controllable if the service forms part of any network loop. e The service manager will be required to pay for identifiable services dedicated to supporting the use of the service. In return for satisfying these conditions the network service owner can become an active player in the spot market in competition with other links (either regulated or non-regulated) and supply and demand-side alternatives. The principle source of income for the owner of a non-regulated network service is the spot price differential between the terminals. Other potential revenue sources arise through the deferment of the installation of regulated network services, and the provision of ancillary services. The Directlink project being developed jointly by the New South Wales distributor NorthPower and the Canadian utility Hydro-Quebec will be the first non-regulated network service. The HVDC Light technology ensures that Directlink will satisfy NECA’s Safe Harbour Provisions. 4.0 What is HVDC Light ? HVDC Light is a DC transmission technology which consists of two elements: converter stations and a pair of cables. The converter stations are voltage source converters (VSCs) employing state of the art turn on/turn off IGBT power semiconductors. No communications links are required between the converter stations In addition HVDC Light does not rely on the AC network’s ability to keep the voltage and frequency stable. This gives additional flexibility regarding the location of the converters in the AC system. HVDC Light systems are designed for capacities of up to 150 MVA and for DC voltages up to+150 kV. A 65 MVA station employs a +/-80 kV voltage. The HVDC Light design is based on a modular concept with a number of standardised sizes. Most of the equipment is installed in enclosures at the factory, which makes the field installation and commissioning short and efficient. The standardised design allows for delivery times as short as 12 months. ea Fig. 1 Preinstallation of Gotland HVDC Light The stations are designed to be unmanned and are virtually maintenance free. Operation can be carried out remotely or could even be automatic based on needs of the interconnected ac networks. Maintenance requirements are determined by movable equipment eg the conventional ac breakers and the pumps and fans in the cooling system. The HVDC Light technology itself is designed to be environmentally friendly. Since power is transmitted via a pair of underground cables there is no visual impact, no ground current and the electromagnetic fields from the cables cancel each other. The stations are compact and need little space (a 65 MVA station occupies an area of approx. 800 sq. metres). The appearance can easily be adapted to local environmental requirements. In addition, HVDC Light is a technology that offers the possibility of replacing polluting technology (eg diesel) by environmentally friendly energy over the transmission network. Fig. 2 Ploughing of cable, normally at a depth of 50-70 cm. 4.1. HVDC Light Cables The HVDC Light extruded cable is the outcome of a comprehensive development program, where space charge accumulation, resistivity and electrical breakdown strength were identified as the most important material properties when selecting the insulation system. The selected material gives cables with high mechanical strength, high flexibility and low weight. Extruded HVDC Light cables systems in bipolar configuration have both technical and environmental advantages. The cables are small yet robust and can be installed by ploughing, making the installation fast and economical. 5.0 HVDC Light Characteristics 5.1 Controllability The HVDC Light converter station output is determined electronically by control of a high frequency, kHz range pulse width modulation (PWM). Control of the PWM »Pepi) makes it possible to create any phase angle or amplitude within ratings. Control signals to a converter can almost instantaneously change the output voltage and current to the ac network. Operation can take place in all four quadrants of the real - reactive power plane i.e. active power transmission in either direction can be combined with generation or consumption of reactive power. From the system viewpoint an HVDC Light installation corresponds to an electrical machine without inertia. It can operate as a generator or motor and be changed between these states. These features mean that active power can be controlled to match the changing needs of a consumer or distributor ( by power order changes or by frequency control). Power can also be controlled to match an agreed power contract. ree an 'sa8, f op. 02 ‘epuy Fig. 3 PQ diagram, station 1, rectifier 5.2 Reactive power support and control Reactive power generation and consumption of an HVDC Light converter can be used for compensating the needs of the connected network within the rating of a converter. As the rating of the converters is based on maximum currents and voltages the reactive power capabilities of a converter can be traded against the active power capability. The combined active /reactive power capabilities can most easily be seen in a P-Q diagram (positive Q is fed to the ac network). 5.3 Power Quality The reactive power capabilities of HVDC Light can be used to control the ac network voltages, and thereby contribute to an enhanced power quality. In the presence of a fault which would normally lead to an AC voltage decrease the converter can be rapidly deblocked and assist with voltage support to avoid severe disturbances in local industries that are sensitive to voltage dips. The response time for a change in voltage is 50 ms ie for a step order change in the bus voltage the new setting is reached within 50 ms. With this speed of response HVDC Light will be able to control transients and flicker up to around 3 Hz, thereby helping to keep the AC bus voltage constant. 6.0 Experience to Date 6.1 Operational Experience and Marketing The operational experience to date is based on results from two projects viz e the Hellsjén 3 MW demonstration project, which has been in operation since March 1997, and e the 65 MVA Gotland project, which was commissioned in July 1999. Performance to date is as expected; the test results show that HVDC Light is a transmission technology that has come of age. The market response for HVDC Light since it was introduced in May 1997 has been enormous; thus far 3 HVDC Light and 3 SVC Light contracts has been awarded to ABB. One of the driving forces behind the interest in HVDC Light is the worldwide deregulation of electricity markets. HVDC Light is suitable for projects up to 200 MW and has a competitive edge with short delivery times and the simplified permitting process since cables are used instead of over-head lines. Table 1 HVDC Light and SVC Light projects Project Size, MVA _Distance,km In service Hagfors 22(0-44 N/A 99-05 MVAr) Gotland 60 70 99-07 Directlink 180 65 99-12 Tjzreborg 8 4 00-03 RWE 19 (0-38 N/A 00-06 Energie MVAr) 7.0 Applications HVDC Light can be employed to best advantage in the following circumstances. e Supply of isolated loads That is, supply to a distant town, mine or island or even a production platform in the sea needing power from the mainland. e Asynchronous grid connection A connection between two networks with different frequencies. An asynchronous connection can also be used to safeguard the power quality of a sensitive load. e Infeed of small generation HVDC Light can be used to transmit power from isolated generation to a grid or toa separate load. Such infeed could be from wind, hydro, tidal, solar etc without affecting the power quality of the receiving network. e DC grids HVDC Light is an excellent component for multi-terminal connections, paralleling and for constructing de grids. Two important features of HVDC Light are: e the ability to transmit power over a long distance with a complete underground connection, and e the controllability of reactive power individually for the two converter stations combined with active power control. This gives power quality advantages. Fig. 4 Directlink map 8.0 Directlink Directlink is a 180 MVA HVDC Light project that will link the regional electricity markets of New South Wales and Queensland. Directlink will be a non-regulated project, operating as a generator by delivering energy to the highest value regional market. By directly participating in the spot market Directlink will earn a market- based return for its owners. That return could include substantial revenues during periods of scarcity in either Queensland or New South Wales, when the market clearing price could rise to as much as $5,000/MWhr. Some of the Directlink capacity may be sold through financial hedging instruments eg capacity rights. These instruments would shift risks and returns between the project’s owners and users, permitting both parties to better hedge their financial profile. Directlink employs the HVDC Light technology, the development advantages of which include: e In order to facilitate permitting the HVDC Light cable will be installed along existing rights of way for its entire 65 km route, with a substantial portion underground. e The flow of energy over HVDC Light facilities can be precisely defined and controlled, thereby meeting NECA’s Safe Harbour Provisions. The ability to control power flow over the facility also means that the capacity rights required for fully commercial network service are readily defined. e The Voltage Source Converter terminals can act independently of each other to provide ancillary services (such as var support) in the weak networks to which Directlink connects. e The use of the HVDC Light technology will greatly reduce the Directlink construction and commissioning period. Rapid response to market conditions must be a feature of market-driven transmission projects. 9.0 Conclusions It is widely recognised that the role of network services has changed as a result of the introduction of competitive power markets. HVDC Light is a new DC transmission technology that has important advantages for application in competitive markets. These advantages include its modularity, standardised design leading to short delivery times, and compact stations and cables reducing environment impacts and controllability giving possibilities to match the power need and/or to control the voltage in the network. These features mean that HVDC Light facilities can be installed quickly in response to competitive market signals. 10 References (1] Asplund, G, Eriksson, K, Svensson, K: “DC Transmission based on Voltage Source Converters”, Cigré SC14 Colloquium on HVDC and FACTS in South Africa, 1997. [2] Asplund, G, Eriksson, K, Drugge, B: “Electric power transmission to distant loads by HVDC Light”, Distribution 2000, Sidney, Australia, 1997. [3] Asplund, G, Eriksson, K, Jiang, H, Lindberg, J, Palsson, R, Svensson, K: “DC Transmission Based on Voltage Source Converters”, Cigré Conference, Paris, France, 1998. HVDC Light, a tool for electric power transmission to distant loads Gunnar Asplund Kjell Eriksson* by Ove Tollerz ABB Power Systems AB ABB Power Systems AB ABB High Voltage Cables AB Sweden SUMMARY HVDC Light is a newly developed technology for electric power transmission by HVDC based on Voltage Source Converters. This has many interesting characteristics that make it a very promising tool for transmission of electric power to distant loads, where no other transmission is possible or economic. The technology is presented here and its application to a pilot transmission, which is now operating in a commercial network since March 1997. Special emphasis is given to the possibility to serve the loads in a connected AC network without own generation. New DC power cables based on a modified triple extrusion technology and a specially designed DC material have been developed. DC power cables with ratings 2 x 25 MW at 100 kV can be accomplished weighing only 1 kg/m per cable. Such cables can be installed at low cost by e.g. ploughing technique and aerial cabling. Larger cables can transmit much more power. Voltage Source Converters together with these cables constitute an excellent tool for providing power to any distant location. Thereby the advantages of a large network can be brought to basically any place. A few applications are presented to show this. The state of the art considers ratings in the range of 1-150 MVA and with direct voltages up to around +100 kV. The converters will be based on a modularised concept for serial production of standard sizes in order to keep size, delivery time and cost low. Keywords: HVDC, Voltage Source Converters, transmission, PWM, distant loads *P O Box 703, S-771 80 LUDVIKA, Sweden Sweden Sweden For the future both power and voltages will increase and extension to pure DC networks will be possible. 1, INTRODUCTION The HVDC technology has been successful to connect AC networks that for technical or economical reasons cannot be connected by AC transmission. The present technology uses circuits with PCC (Phase Commutated Converters) and is based on thyristor valves with semiconductor devices that can be turned on by a positive gate pulse when the main voltage is positive. To turn off the thyristors need a negative voltage across the main terminals. This is normally achieved by commutating the current to the valve in the next phase. Thereby the present technology has inherent weaknesses, which to some extent limit the use of HVDC as the means to overcome these weaknesses are relatively expensive. These are the need for rotating machines in the receiving network and the risk of commutation failure, which means that for some cycles there is no transmission of power. These weaknesses can be overcome by using Voltage Source Converters (VSC) which have now been de- veloped for high voltage application. The Hellsjén Project is the world’s first VSC HVDC transmission. It is rated 3 MW and +10 kV DC. The link is in operation in a commercial network since the beginning of March 1997 between Hellsjén and Grangesberg in central Sweden on a 10 km long de- commissioned AC line. The operation experience has been entirely positive. The transmission performs as predicted, both during steady-state and transient conditions. The measurements have indicated that the converters will be able to fulfil applicable requirements on sound power level, harmonic distortions, telephone disturbances and electromagnetic fields. 2. VSC TECHNOLOGY AND PULSE WIDTH MODULATION (PWM) In industrial drives the PCC (Phase Commutated Converter) technology which is used in HVDC is now almost totally replaced by VSC (Voltage Source Converter) technology. The fundamental difference between these two technologies is that VSC:s need components that can switch off the current and not only switch it on as is the case in PCC:s. As in a VSC the current can be switched off, there is no need for a network to commutate against. In HVDC-applications it could then be of interest to use VSC technology in order to supply passive networks, that is areas which lack rotating machines or networks that does not have enough power in the rotating machines (too low short circuit power). By use of higher switching frequency components it is possible to use Pulse Width Modulation (PWM) technology. Then only one converter is needed and the AC voltage is created by switching very fast between two fixed voltages. After low pass filtering the desired fundamental frequency voltage is created. In this case it is not necessary to have a transformer for the functioning of the converter. See figure 1. +-ld tk ples — J} iT Figure 1 shows one phase of a VSC converter using PWM With PWM it is possible to create any phase angle or amplitude (up to a certain limit) by changing the PWM pattern, which can be done almost instantaneous. Hereby PWM offers the possibility to control both active and reactive power independently. This makes the VSC using PWM a close to ideal component in the transmission network. From a system point of view it acts as a motor or generator without mass that can control active and reactive power almost instantaneously. Furthermore, it does not contribute to the short circuit power as the AC current can be controlled. Figure 2 shows the PWM pattern and the fundamental frequency voltage in a Voltage Source Converter 3. IGBT From the above it appears advantageous to shift from present Phase Commutated Converter Technology for HVDC to VSC and PWM. Why has this not happened a long time ago? The correct answer is that there have not been semiconductor components available that have been good enough for the task. In this respect the IGBT is a very interesting component, as it is a MOS-device and the power need for the control of the component is very low and can be fed from the snubber circuits. This makes series connection possible with good voltage distribution even at switching frequencies in the kHz range. There is a fast development of the IGBT:s and components for the voltage of 2.5 kV has recently become available in the market and soon higher voltages are expected. The market for IGBT:s also increases very fast which add to the knowledge base of the technology itself and makes it an interesting component for small scale HVDC applications. 4. CONVERTER OPERATION PRINCIPLES The converter consists of a six-pulse bridge, two- level, with series connected IGBT:s in each valve, or can be a three level converter. Figure 3 shows the main equipment of a typical transmission Every IGBT is provided with an antiparallel diode. Auxiliary power to the gate drive unit is generated from the voltage across the IGBT. The semiconductors are cooled with deionized water. Turn on/off of each single IGBT is ordered via an optical link from the control equipment on ground potential. The main advantages of converters with IGBT:s are: e high impedance gate which require low energy to switch the device e high switching frequency due to short switching times and by that low switching losses The objective for the DC capacitor is primarily to provide a low inductive path for the turned-off current and an energy storage to be able to control the power flow. The capacitor also reduces the harmonics on the DC side. The converter generates characteristic harmonics related to the switching frequency. The harmonic currents are blocked by the converter reactor and then the harmonic contents on the AC bus voltage is reduced by a high-pass filter. The fundamental frequency voltage across the reactor defines the power flow between the AC and DC sides. The converter firing control calculates a voltage time area across the converter reactor to control the current through the reactor to the reference value. The current order to the controller is calculated from the set power/current order or the DC voltage control, and a corresponding PWM pattern is generated. The active power flow between the converter and the AC network is controlled by changing the phase angle (5) between the fundamental frequency voltage generated by the converter Ug and the AC voltage on the AC bus. The power is calculated according to the formula assuming a lossless reactor. Ug*Un* sind Xi P= The reactive power flow is determined by the amplitude of Ug according to formula. The amplitude is controlled by the width of the pulses from the converter bridge Ug. Ug * (Ug —Un* cosd) g XI The transmission starts up by energising the two stations separately. The AC breakers are closed which means that the DC busses are energised through the antiparallel diodes in the bridge. When the gate drive units are charged the converters in the two stations can be connected by the switches on the DC side. The first converter which is deblocked will control the DC voltage and when the other converter is deblocked the transmission of active power can start. Normal operation modes mean that each station controls its reactive power flow independent of the other station. However, the active power flow into the DC work must be balanced which means that active power out from the network must equal the active power into the network minus the losses in the system. Any difference would mean that the DC voltage in the system will rapidly change. To achieve power balance one of the stations is controlling the DC voltage. This means that the other station can set any active power order within the limits for the system. The voltage controlling station will adjust its power order to ensure power balance, meaning constant DC voltage. This will be achieved without telecommunication between the stations just based on measurement of the DC voltage. 5. CABLES The new HVDC Light cables have insulation of extruded polymer. Until now, the cables used for HVDC transmission and distribution, have been paper insulated cables, low pressure oil filled cables (LPOF) or mass impregnated non draining cables (MIND). There are several drawbacks with these designs. The LPOF cable needs auxiliary equipment to maintain the oil pressure and can not be easily installed. The MIND cable has limitations in the operating conductor temperature. There are of course also environmental oil spill concerns that are associated with the LPOF cable. Paper insulated cables are not feasible for aerial cables because of sensitivity to repeated bending. HVDC Light cables are laid in pairs with antiparallel currents and thus eliminating magnetic fields. In HVAC there has been a change of technology going from paper insulated cables to extruded, mostly XLPE cables. The preference of extruded cables also for applications in HVDC has been obvious for a long time. Several reports have been published where XLPE has been tested for HVDC applications but without success. One reason has been the existence of space charges in the insulation leading to uncontrolled local high electric fields causing dielectric breakdowns. Another reason has been uneven stress distribution due to temperature dependent resistivity causing overstress in the outer part of the insulation. This HVDC Light cable development work with the objective to type test an extruded HVDC cable, was initiated a couple of years ago. It has now resulted in an extruded cable for HVDC that is an important part of the HVDC Light concept and opens new opportunities for future power transmission and distribution. Figure 4 shows a HVDC Light cable pair with 5.5 mm extruded insulation The extruded HVDC cable that has been developed and which is also in short lengths included in the Hellsjén project is of a design shown in Figure 4. The design can transmit at least 2 x 25 MW at 100 kV and weighs only 1 kg/m. It is a triple extruded cable with a 95 mm? aluminium conductor and 5.5 mm insulation thickness. The design also includes a copper wire screen with a cross-section of 25 mm” due to standard reasons. The outer sheath is made of HDPE making this cable easy to handle and to install for instance using a ploughing technique. In order to achieve the necessary performance of the extruded cable, a special material had to be developed as well as modifications to the cable extrusion process. The voltage breakdown values of the cable up to now have been difficult to establish. The reason is breakdowns at the test terminations since the voltages are very high and in combination with the small outer diameter of the cable, the electrical stresses in the termination become the limiting factor in testing. The short term breakdown voltage for this type of cable can therefore at present only be said to well exceed 600 kV. A long term test with daily load cycles to qualify 100 kV in continuous operation is currently in progress. 6. PRACTICAL FEATURES OF THE HVDC LIGHT The technical characteristics of the VSC make it feasible for a variety of transmission applications for which conventional HVDC is unable to compete to- day, either from economical or from technical point of view. 20 MW 418 xt2im Figure 5 shows a typical layout of an HVDC Light converter The VSC has a simple and straightforward circuit solution. The technical simplifications such as small filters, no transformers, less switching equipment and simple civil works contribute to small footprint, robust mechanical design and easy handling. By this the converter equipment can be placed in simple module type housings, see Figure 5. A VSC converter station with ratings up to 20 MW and below +30 kV will occupy an area less than approximately 250 square meters. The modular design will give opportunities to preinstall the equipment at factory and run highly complete tests before shipment. It will easily lend itself to a considerable degree of standardisation and to installations which can be relocated, when needed. The plant production process will be based on a set of standardised sizes with module drawings ready on the shelf. The need for engineering will be limited and for a normal project basically all equipment will be defined already from start. The simple circuit solution makes it possible to design a station, that does not need stops for regular scheduled maintenance. The scheduled maintenance could be limited to checking of movable equipment such as pumps and fans for cooling, resins for cooling water quality. Automonitoring of status so that faults will be automatically detected and alerted will give the possibility to rapidly exchange faulty equipment. 7. DISTANT LOAD APPLICATIONS Electrical systems are mostly built as meshed networks with multiple interconnections between various loads and generation stations. In such a network the power can be exchanged via different routes and the cost of power can be considered common to the all loads in the network. There are, however many places, small cities, villages, mines etc., that are located far from any network. Such a place we call a distant load. The supply of power to a distant load can be made by a radial transmission from a meshed network or by local generation. For small loads below 150 MW, local generation has been necessary, for distances beyond what has been possible to reach with an AC transmission. Traditional HVDC has not been cost effective in this power range, because it did not have the technical possibilities to feed power into an isolated load without synchronous machines. HVDC Light will now provide an excellent alternative for power transmission to small distant loads (see Figure 6). The characteristics that make HVDC Light suitable for feeding distant loads are particularly: e It can feed power into an isolated load without any synchronous machines, generators or compensators. ° The active and reactive power can be controlled independent of each other in an HVDC Light station. A receiving station can control both the voltage and the frequency of the power fed into a network in the same way as a generator. Electrically this corresponds to connecting the load to a close generator. . The current from the converter into the load is limited by the current control of the converter. Thus the short-circuit current from the converter is limited and no short-circuit contribution is necessary. Long distance AC transmission with overhead lines has to go to higher voltages with increasing distances and at long distances it becomes technically impossible or economically too costly. In many cases local generation is the only possibility and if no natural, local generation resources exists the natural choice has been diesel generators, which are run by high cost fuel. DC transmission has no natural limitation to distance. It is limited by which losses can be accepted and if losses are too high a larger conductor area may be used. Thus even for very long distances an economic optimisation of the conductor area with acceptable transmission losses could be reached. The newly developed extruded DC cables are very effective with regard to direct voltage capacity and thereby give possibilities for high power compared to a similar AC cable. Thus these cables together with the converters will make the HVDC Light concept a low cost alternative for long distance transmission to small loads compared to AC cables but also compared with AC overhead lines. It is possible to design for converters in the range 1- 150 MVA and with voltage ratings up to +100 kV. By the HVDC Light concept DC transmission will economically extend in rating to a few MW thanks to the reduced costs of converters and cables in the low power range and the possibility to operate without synchronous machines in the receiving end. In many places overhead lines meet objections from environmental point of view. The HVDC Light concept will now be the natural alternative to make transmission of power more environmentally friendly. Many times there is a possible generation resource, that could be developed for a distant load. Due to transmission difficulties, technical or economical such a development was not realised. Together with an HVDC Light transmission the possibilities may now improve so that it becomes economical to give the distant load its own generation from a distant source. Examples of such generation are small hydraulic generators, wind mill farms and solar power. By use of a block connection from a small hydraulic generator to the HVDC Light converter it would be possible to take advantage of the converter characteristics and design the generator for a higher frequency and thus decrease weight and cost of the generator. Another possibility is to use an asynchronous generator. A variable frequency can be used for wind mills too, by which they can operate always at the speed that gives maximum power. 8. CONCLUSIONS The development of power semiconductors, specifically IGBT:s and extruded DC cables led to that small scale HVDC in combination with cables can offer a number of new applications to serve the needs of utilities. vf Wind Power Small Scale Hydrapower HVDC Light Extruded dc- cable Such installations have several characteristics that make them very attractive. ¢ Opportunity to transmit small scale power long distances via cable Opportunity to connect to passive load Separate control of active and reactive power No contribution to short circuit currents No need of fast communication Low complexity thanks to few components Opportunity to operate without transformers Small and compact In many cases this will be a very interesting alternative to local generation or conventional AC transmission in order to provide power to distant locations. 9. REFERENCES Article: Asplund G, Eriksson K, Svensson K (1997) CIGRE SC14 Colloquium in South Africa 1997: DC Transmission based on Voltage Source Converter Figure 6 shows small scale generation application for distant loads i ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY a> ALASKA @@—_ ENERGY AUTHORITY 480 WEST TUDOR ANCHORAGE, ALASKA 99503 907 / 269-3000 FAX 907 / 269-3044 MEMORANDUM TO: Randy Simmons, Executive Director David Germer, Deputy Director — Business Development and Rural Energy Dennis McCrohan, Deputy Director — Project Development and Operations FROM: Art Copoulos, Project Manager Jey | DATE: February 9, 2000 SUBJECT:. HVDC Light Seminar Last week, along with Corry Hildenbrand of Alaska Electric Light and Power, | attended a seminar on High Voltage Direct Current (HVDC) Light, hosted by BC Hydro and conducted by ABB Power Systems (ABB), the Swedish designer, manufacturer, and supplier of HVDC Light. HVDC Light, is anew HVDC power transmission technology marketed by ABB as an alternative to conventional AC power transmission and older versions of HVDC power transmission. The technology uses HVDC power transmission to link up with AC distribution networks using several new technologies, namely voltage source converters, pulse width modulation, and extruded polymer cables. Detailed technical descriptions of these new technologies are included in the attached papers. The technology appears to offer many technical advantages well suited for Alaskan applications. Being able to distribute power over long distances, more power for a given conductor size compared to AC, in small or existing rights-of-way, underground, in deep and rocky seabeds, and more readily from small scale hydro or wind generators, are all potential technical advantages that could help make power distribution more cost effective or feasible in Alaska. In addition to these technical advantages, external driving forces such as limited access to new rights-of-way, load growth, greater reliability requirements, expanding electrical networks, all combine to make the technology attractive. |! would add, however, that the technology is very new with limited practical applications to date and major uncertainties exist so we should proceed very cautiously. The Electric Power Research Institute (EPRI), is predicting a significant growth in the use of HVDC power transmission in the next ten years - a significant number of installations by the year 2005 and a large majority of new installations by 2010. As the technology matures, the costs are expected to come down improving the overall economic benefits. Based on the many advantages identified by ABB and EPRI’s predictions, it is recommended to fully evaluate the Memorandum February 9, 2000 Page 2 HVDC alternative on a case-by-case basis prior to installing any new transmission lines over significant distances in Alaska. Also, since there is such a variety of utilities scattered throughout different regions of the state, at some point, it may be advantageous to study the benefits of interconnection with HVDC from a statewide perspective. Listed in the following pages is a summary of potential advantages and disadvantages of HVDC Light. The advantages section is based only on ABB's presentation. Attachments CC: Stan Sieczkowski, Operations Manager Peter Crimp, Development Specialist II Karl Reiche, Projects Development Manager Corry Hildenbrand, Vice President - Energy Resource Development, AEL&P Potential Ad f HVDC Light Syst One less conductor - 2 conductors vs. 3. Only 2 conductors are required to transmit HVDC power vs. 3 for HVAC. The 2 cables operate in a bipolar mode with positive polarity on one cable and negative polarity on the other. ABB claims they can run the system in a mono-polar mode (1 conductor), but this possibility is largely unproven and could potentially violate electrical codes. Theoretically, in a 2 conductor installation, power could still be transmitted in mono-polar operation if one conductor fails, thereby increasing reliability in comparison to HVAC. According to ABB, when the 2 conductors are installed close together, there is no magnetic field since the electric currents are flowing in opposite directions. According to ABB, this means that the cable can be safely buried within a narrow right of way (or it could be on a single pole that is partially hidden in the trees), making permitting easier than conventional HVAC transmission lines. Greater power throughput. According to ABB, HVDC Light can transmit more power for a given conductor size and weight than an AC system. ABB claims that 3 or 4 times voltage can be supplied on a given size conductor using HVDC Light vs. HVAC. Smaller and less conductors creates the opportunity for single pole installations in narrow rights-of-way, which may also be easier to permit. VAC to HVDC ‘ool ie iii deka r —— According to ABB, HVDC Light also creates the opportunity for HVAC to HVDC conversions, although it works best with a new type of DC cable. Since more power can be transmitted across a given conductor size, there are opportunities to convert existing HVAC transmission lines to HVDC so that more power can be transmitted across existing towers and right-of-ways rather than building new towers and acquiring new right-of-ways. Existing 6 conductor AC transmission lines (2 AC systems) could be converted to 3 DC HVDC Light systems, significantly increasing the power throughput on an existing right-of-way and transmission tower. According to ABB, only the insulators would have to be changed out on an existing AC system (in addition to installing the voltage source converters and other associated equipment). Less line | J suitability for long di a According to ABB, there will be significantly less line losses in an HVDC Light system, making it more suitable for long distance power transmission. According to ABB, AC cables are technically difficult or impossible to use over transmission distances exceeding 50-100 kilometers. ‘According to ABB, HVDC Light submarine cables ni stronger than AC cables since they can have a steel rather than an aluminum armor. AC cables require aluminum armor to avoid hysteresis losses caused by the AC magnetic field. HVDC Light submarine cables also eliminate the risk of an oil spill since they have a polymeric insulation rather than a paper/oil filled insulation. These advantages of strength and being oil-free make the cables more suitable for deep waters and rocky bottoms according to ABB. Page 1 of 2 According to ABB, the HVDC Light voltage source converters can switch current on or off so that the output voltages and currents on the AC side can be more easily controlled. The HVDC Light voltage source converters automatically adjust the voltage, frequency, and flow of active and reactive power according to the needs of the AC system rather than relying on the AC networks ability to keep voltage and current stable. This is useful in cases where there are significant power fluctuations as in the case of wind generators. Wind generated “flicker” can be kept under control. An application is described in the attachments —- see Gotland HVDC Light Transmission. Power exchange between networks. Two AC grids adjacent to each other, but running asynchronously can not exchange power. An HVDC Light link could be used to connect the networks. Combined AC/DC System There is the possibility to run combined systems for future conversion to HVDC or simultaneous HVAC and HVDC transmission. Page 2 of 2 Vi igh Unproven performance so far. This is a new technology with a limited number of installations. At this point, although ABB has a number of installations in progress, only one installation is fully completed and operational. Installation of any new technology early in its product life cycle has associated economic risk. D Si Service Provider There are other competitors that claim they can manufacture and supply HVDC systems, but according to BC Hydro staff, ABB has a significant lead in developing the new technology. Details are sketchy, but it appears that HVDC Light is proprietary and the ability of others to compete is unknown. Mai 10 ti Ability to maintain and operate the system over the long term is largely an unknown. Since ABB is based in Sweden, and at this point don’t seem to have “field service staff” in the United States, obtaining service on a new installation may be difficult. Also, expertise in this new technology is likely to be limited outside of ABB. Power Losses in the Converters. According to ABB, there will be significantly less line losses in an HVDC Light system in a long distance power transmission, primarily because of the high line losses in an AC system. In the case of HVDC Light, although there are less line losses in the conductors, there will be heat losses in the converters. The magnitude of these converter losses, as well as the break over when HVDC has less overall losses than HVAC is largely unknown. Page 1 of 1 + 5-12-00 5 759AM 3 2c 458577 182 southeast Alaska Conservation Council SEACC 419 6th Street, Suite 328, Juneau, AK 99801 (907) 586-6942 phone (907) 463-3312 fax infg@seacc.org “a Sega E OF ALASKA-DC ~~ May 11, 2000 Tom Puchlerz Tongass Forest Supervisor Federal Building Ketchikan, AK 99901-6534 RE: Petition for Supplemental EIS Dear Tom: In August 1997, the US Forest Service approved a 57-mile, 200 foot wide right-of-way for the Swan Lake - Lake Tyee Intertie through the Tongass National Forest. The intertie is a high-tension powerline which would connect Wrangell and Petersburg's power source, Lake Tyee, with Swan Lake, the power source for Ketchikan. Since the release of the Final EIS for the project, significant new information has come to light which requires the completion of a Supplemental EIS. The Southeast Alaska Conservation Council (SEACC) and the Tongass Conservation Society (TCS) hereby request that the Forest Service complete a Supplemental Draft Environmental Impact Statement (SDEIS) regarding the Swan Lake - Lake Tyee Intertie, I, Interests of the Petitioners SEACC is a grassroots coalition of 18 volunteer, citizen conservation groups in 14 communities across Southeast Alaska, from Ketchikan to Yakutat, including the Tongass Conservation Society and the Wrangell Resource Council. SEACC's individual members include Alaska Natives, commercial and sport fishermen, hunters and guides, tourism and recreation business owners, high-value added wood product manufacturers, and Alaskans from all walks of life. SEACC is dedicated to safeguarding the integrity of Southeast Alaska's unsurpassed natura! environment while providing balanced, sustainable use of our region's renewable resources. TCS is a local Ketchikan-based non-profit conservation organization with about 180 members. Since 1970, TCS has played an active role in Tongass National Forest policy and management issues. TCS’s members come from all walks of life and rely on a healthy and diverse forest for their livelihoods and quality of life. Il, The Forest Service's Duty to Consider Significant New Information The purpose of Environmental Impact Statements (EIS) prepared pursuant to the National Environmental Policy Act (NEPA) is to “inform decisionmakers and the public of the reasonable LYNN CANAL CONSERVATION, Haings * FRIENDS OF GLACIUR BAY, Gustavus * FRIENDS OF BERNERS WAY, Juneau OCTETY. Ketelikan ON SOCIETY burg * TO) URRA CUD JON COALITION. JUNEAU GROUP AU * NARROWS CONST: ‘TION COUNC ; =00 312: ; 207°" 458579 SENT BY:STATE OF ALASKA-C° + 5-12-00 312:00PM alternatives which would avoid or minimize adverse impacts or enhance the quality of the human environment.” 40 C.F.R.§ 1502.1. In keeping with that purpose, NEPA requires that agencies "shall prepare supplements to either draft or final environmental impact statements if...{t]nere are significant new circumstances or information relevant to environmental concerns and bearing on the proposed action or its impacts." 40 C.F.R. § 1502.9(c)(1)(ii).’ The Forest Service also has a continuing duty to gather and evaluate new information relevant to the environmental impact of its actions. Sec 42 U.S.C. § 4332(2)(A),(B)’ In the Final EIS for the Swan Lake-Lake Tyee Intertie, the Forest Service rejected an underwater intertie alternative because of concems regarding economic and technological feasibility. Since the release of the Forest Service's Final EIS and ROD on the Swan Lake-Lake Tyee Intertie, significant new information has come to light regarding the feasibility of an underwater intertie alternative. It appears now that such an alternative is indeed feasible, and may be, in fact, cheaper to build and maintain than the selected alternative. Because such an altemative would significantly mitigate the adverse impacts on the human environment resulting from the selected alternative and reduce the Forest Service's irretrievable commitment of resources, the agency must fully examine this alternative in a Supplemental DEIS. IIL. Significant New Information Concerning the Feasibility of an Underwater Alternative On March 1, 1999, the Alaska Power and Telephone Company (AP&T) presented the concept of using high voltage direct current technology (HVDC) to transmit power between Lake Tyee and Ketchikan.* According to a letter from AP&T to the Alaska Industrial Development and Export Authority (AIDEA), ABB Power Systems "has developed a new design that is based upon voltage source converters." Using this new technology, AP&T states that HVDC can be used for the economic transmission of smaller loads of 20 to 30 mW. HVDC transmission would use cable, either buried or submarine, or low impact overhead lines, rather than high tension transmission lines that require tall towers. Working with ABB, AP&T developed several routes different from those considered by the Forest Service to connect the Swan Lake and Lake Tyce projects. One of the routes considered was an all-underwater route, with a projected cost of $60 million. Besides being cheaper to build than the $77 million selected alternative, an all- underwater route would have the added benefit of allowing a possible tie-in with Prince of Wales Island's electrical system at Thome Bay. IV, Underwater Route Better Achieves Project's Purpose and Need HVDC transmission using an all-underwater route provides a lower-cost alternative to the selected alternative with much less impact on the human environment. Such an alternative ' See also Marsh v. Oregon Natural Resources Council, 490 U.S. 360, 372 (1989); Headwaters, Inc. v. Bureau of Land Management, 914 F.2d 1174 (9th Cir. 1990), * See also Essex County Preservation Ass'n v. Campbell, 536 F.2d 956, 960-61 (1st Cir. 1976); Sociery for Animal Rights, Inc. v. Schlesinger, 512 F.2d 915, 917-18 (D.C.Cir.1975). > See Letter from Robert S. Grimm, AP&T, to Randy Simmons, AIDEA, (March 1, 1999)(attached). Petition for a Supplemental DEIS for the Swan Lake - Lake Tyee Intertie by SEACC and TCS, March 14, 2000 we SENT BY:STATE OF ALASKA-C™ + 5-12-00 312501PM + 20 158579 would not only meet the Purpose and Need for the Swan Lake - Lake Tyee EIS, but would do so to a far greater degree than the selected alternative. According to the FEIS: "The underlying purpose and need to which this project responds is for KPU to 1) provide a reliable and efficient source of power for the City of Ketchikan's intermediate and long-range needs at reasonable rates while 2) establishing an important link in the long-proposed electrical network for southern Southeast Alaska so that 3) more communities would have access to more power sources or more power customers.” FEIS at 1-6. An underwater HVDC option meets the first part of the Purpose and Need. Indeed, the underwater HVDC may provide a more reliable source of power for Ketchikan than the selected alternative. Any overhead line, such as the approved alternative, will experience outages associated with snow, wind, and blowdown. These disturbances will not be a factor with an underwater cable. An all-underwater route would incur substantially fewer outages, although the duration of any outage may be longer on a submarine cable.’ An all-underwater route would increase reliability by connecting Lake Tyee directly to Ketchikan, without relying on the existing line from Swan Lake to Ketchikan as does the selected alternative. By connecting to Ketchikan directly, the underwater route would be a more reliable source, unaffected by power outages along the line between Swan Lake and Ketchikan. In addition, due to its lower cost, an all-underwater route would be cheaper to implement and may provide more reliable energy at a lower cost to Ketchikan rate-payers. A study commissioned by the State of Alaska found that "the Swan Lake-Lake Tyee electrical intertie would cost more than other alternatives and could result in higher power rates for Ketchikan Public Utility customers,"* The all-undcrwater route may not pose a risk of higher electrical rates for Ketchikan users and therefore may better meet the Purpose and Need of providing a reliable and efficient source of power at reasonable rates. An all-underwater route would also meet the second and third parts of the Purpose and Need. By linking Ketchikan to Lake Tyee, the all-underwater route would go at least as far as the selected alternative in establishing an important link in the long-proposed electrical network for southern Southeast Alaska. In addition, by making a connection to Prince of Wales Island possible, an all-underwater route better meets the third part of the Purpose and Need, by giving "more communities access to more power sources or more power customers.” FEIS at 1-6 (emphasis added), Communities on Prince of Wales Island could have access to power generated at Lake Tyee, Swan Lake, and other potential power projects such as Mahoney and Whitman Lakes. The communities of Ketchikan, Wrangell, and Petersburg would also have access to more power customers, with the addition of Prince of Wales power consumers, Clearly, an all- underwater route meets or exceeds the degree to which the selected alternative met the Purpose and Need for the EIS and should be fully considered in a Supplemental ETS. In 1995, when the Forest Service was selecting which alternatives would be given a hard look in the EIS, it considered looking at an alternative which included a major direct current * See "Swan/Tyee Intertie Proposal," AP&T (April 20, 1999)(attached). * See Bowlen, Scott,” Study: Proposed intertie more costly than other options," Ketchikan Daily News (May 8-9, 1999). Petition for a Supplemental DEIS 4 for the Swan Lake - Lake Tyee Intertie by SEACC and TCS, March 14, 2000 SENT BY!STATE OF ALASKA-DC x + 5-12-00 +12:01PM + 20984585794 (DC) transmission system developed by Teshmont Consultants, Inc. in 1982, The agency dropped further consideration of this alternative in the range of alternatives because of the "high costs involved with the alternative" and the use of "unproved experimental design technology.” FEIS at 2-5. Clearly, the proposal developed by AP&T does not have the same qualities of high cost and unproven design technology, ABB is one of the largest companies in the world and is willing to provide satisfactory warranties for the proposed project.* ABB currently has one light HVDC system in operation and is building seven more systems that use the HVDC technology.’ A recent study of the proposed Sitka-Kake-Petersburg Intertie also recommends the use of light HVDC technology for this route, and calls the light HVDC system "a new emerging technology” that "produces a nearly ideal transmission component that has the potential to change the conventional methods of electric power transmission and distribution."® Given the current feasibility of an all-underwater route, the Forest Service needs to fully evaluate such an alternative in a Supplemental EIS. Even assuming the Forest Service decision to exclude an all-underwater route from consideration was reasonable in 1995, the benefits to the environment and electrical consumers from such a route today requires its full consideration. The only alternatives considered by the Forest Service in detail in the EIS were two overland routes, both of which entailed substantial impacts to area resources, including wildlife and biodiversity, recreational and visual resources, and to the eligibility of Wild and Scenic Rivers. An all-underwater route would reduce the impacts to these various resources to nearly zero, Without such an alternative to consider, the agency is not fully able to "evaluate the comparative merits," including the environmental impacts, of a full range of alternatives. See 40 C.F.R.§ 1502.14(b), In addition, by failing to take a hard look at such an alternative, the agency is unable to fully include discussions of "{mJeans to mitigate adverse environmental impacts" in the EIS. 40 C.F.R.§ 1502.16(h). V. Environmental Concerns and the Impacts of the Proposed Action The Forest Service must consider an all-underwater route in a Supplemental EIS because such an alternative is extremely "relevant to environmental concerns and bearing on the proposed action or its impacts." 40 C.F.R. § 1502.9(c)(1)(ii). By examining an all-underwater alternative, which greatly minimizes impacts to the human environment, the agency can view the environmental impacts of the proposed action with greater clarity. The public and decisionmakers will be better able to make an informed choice about the proposed action and its related environmental impacts if an all-underwater route is considered. A, Fisheries The FEIS states that "[a]ll of the action alternatives have some associated risk of effects to streams and fisheries resources; the magnitude of risk is generally proportional to the extent of ° See Letter from Grimm to Simmons. ” See Karady, George, and Mike Carson, "Sitka-Kake-Petersburg HVDC Intertie Study," City and Borough of Sitka, p.2 (January 2000). "Id. at 15. Petition for a Supplernental DEIS 4 for the Swan Lake - Lake Tyee Intertie by SEACC and TCS, March 14, 2000 ° -D + 5-12-00 + . ’ 5 ’ right-of-way clearing, miles of new or reconstructed road, and the number of stream crossings required." FEIS at 3-85. By examining an all-underwater route, the Forest Service would be able to evaluate an action alternative which effectively negated any risk to streams and fisheries resources because no right-of-way clearing, road construction, or stream crossings would be needed. In comparison, the selected alternative requires 1,297 acres of right-of-way clearing, and 77 total stream crossings. FEIS at 3-75, 3-77. The FEIS also indicates that the amount of right-of-way clearing in high-hazard areas encroaching within 200 feet of a stream channel helps determine the potential effect of surface erosion from the proposed action. FEIS at 3-72. While an all-underwater route would require no such clearing, the selected alternative requires 6,200 feet of right-of-way clearing within 200 feet of a fish stream channel. All other action alternatives require even more. FEIS at 3-78. Finally, the FEIS admits that "[fJactors such as unexpected logging-induced landslides, logging-enhanced blowdown, and impassable culvert installation could contribute to some minor adverse cumulative effects to the Project Area's fisheries resources." FEIS at 3-99. No such cumulative impacts would be associated with an all-underwater route. Clearly, the consideration of an all-underwater route would give the public and decisionmakers a better understanding of the potential impacts to fisheries due to the action alternatives. B. Wildlife and Biodiversity According to the FEIS, "[t]ransmission line and road construction are likely to generate direct, indirect, and cumulative effects on wildlife in the Project Area." FETS at 3-190. The FEIS nares these effects to include :"(1) habitat removal/alteration, (2) disturbance from project activities, (3) increased human access, (4) collision / electrocution, (5) hampering wildlife movements." Id. While all of the action alternatives would necessitate varying levels of such impacts, an all-underwater route would have virtually no impact on wildlife habitat. The Forest Service concluded that all of the action alternatives would reduce habitat capability for deer, mountain goats, brown bears, marten, wolves, gray wolves, river otters, red squirrels, Vancouver Canada geese, bald eagles, and other wildlife species. An all-underwater route would reduce these impacts to virtually zcro and thus provides a better opportunity to evaluate the impacts and environmental concerns regarding wildlife due to the action altematives. C. Aircraft Safety The FEIS states that "[t]he potential for an increased risk of aircraft wire-strike accidents is the primary aviation-related consequence of constructing the Swan Lake - Lake Tyee Intertie using the proposed aerial wire crossing routes." FEIS at 3-421. New transmission line crossings over Eagle Bay, Bell Arm, Behm Narrows, the outlet from Long Lake, Shrimp Bay, and across the Cleveland Peninsula "would increase the risk of aircraft wire-strike accidents in the Project Area," FEIS at 3-428. The FEIS further specifies that "the potential for a significant risk increase is greatest at Behm Narrows and Shrimp Bay." FEIS at 3-428, While the FEIS outlines mitigation measures that will be used to minimize the potential risk of wire-strikes, such as wire- marking and wamings on aeronautical charts, the risk of air-strikes cannot be eliminated under Petition for a Supplemental DEIS 5 for the Swan Lake - Lake Tyee Intertie by SEACC and TCS, March 14, 2000 #7 tans . 14 SENT BY:STATE OF ALASKA~D + 5-12-00 +12503PM 5 20 585 any of the action alternatives. In contrast, an all-underwater route eliminates any possible risk of wire-strike and this provides a better opportunity to evaluate the impacts on aviation safety due to the action alternatives. D. Recreation and Visual Resources According to the FEIS, "[ijntroducing human-made elements such as transmission lines, cleared rights-of-way, and roads into a natural landscape can change the quality of the landscape and type of recreation experiences possible to Forest Users." FEIS at 3-396. All action altematives would convert between 18,860 and 18,490 acres of Primitive ROS settings to other settings. Id. Recreationists expecting a pristine environment would view these changes negatively, In contrast, an all-underwater route would have comparatively little impact on recreational uses because very little change to the landscape would be required. The FEIS also reveals that all action alternatives will negatively affect visual resources, with Alternative 2 causing more adverse effects than Alternative 3, FEIS at 3-346. Alternative 2 would pass near 11 Key Viewing Areas, compared to Alternative 3, which would be visible from 9 Key Viewing Areas. An all-underwater alternative, in contrast, would create virtually no impact on visual resources and will not affect any of the Key Viewing Areas in the Project Area. Clearly, an all- underwater route provides a better opportunity to evaluate the impacts on visual resources due to the action alternatives. E. Wild and Scenic Rivers All action alternatives would affect rivers eligible for inclusion in the Wild and Scenic Rivers System. Alternative 2 would reduce the outstandingly remarkable qualities of Eagle Lake and River and Alternative 3 would affect a portion of Anan Creek. Alternative 2, the selected alternative, will reduce Eagle Lake and River's outstandingly remarkable fish and recreation values by posing 4 risk to fisheries resources and by changing the recreation setting of the watershed from primitive to developed. In the Modified 1997 Tongass Land Management Plan, the Forest Service decided that Eagle Lake and River is unsuitable for designation as a Wild River because of "the substantial resource development opportunities that would be foregone" if designation were granted. April 1999 TLMP ROD at A-16. This may or may not be true at this point, given the new information regarding the feasibility of an all-underwater altemative. While Eagle lake and River was not found suitable for inclusion in the Wild and Scenic Rivers system by the Forest Service, it is still possible that Congress may decide to grant Wild River status to this watershed. The construction of the selected altemative will diminish the outstandingly remarkable fish and recreation values of Eagle Lake and River, making it ineligible for such designation by Congress. In contrast, an all-underwater route would create no impacts on potential Wild and Scenic Rivers, and thus provides a better opportunity to evaluate the impacts on Wild and Scenic Rivers due to the action alternatives. F. Irreversible Commitment of Resources Because old-growth habitat lost during right-of-way clearing would not be allowed to become reestablished during the life of the project, its loss constitutes a irreversible commitment Petition for a Supplemental DEIS 6 for the Swan Lake ~ Lake Tyee Intertie by SEACC and TCS, March 14, 2000 1# 8 ws ’ 2026458577 SENT BY:STATE OF ALASKA-DG- + 5-12-00 +12:04PM + of resources, Some 814 acres of old-growth habitat would be irreversibly lost under the selected alternative. FEIS at 3-435. In contrast, an all-underwater route would result in little, if any, irreversible commitment of old-growth habitat, and thus provides a better opportunity to evaluate the irreversible commitment of resources due to the action alternatives. Conclusion Clearly, the advent of HVDC technology and its potential use to connect Ketchikan with the power source at Lake Tyee present "significant new circumstances or information relevant to environmental concems and bearing on the proposed action or its impacts.” 40 C.F.R. § 1502.9(c)(1)(ii). This significant new information reveals that an alternative exists which provides means to mitigate the adverse environmental impacts associated with the selected alternative. The consideration of such an alternative would more sharply define the issues presented in the EIS and provide a clearer basis for choice among options by the decisionmaker and the public. See 40 C.F.R. 1502.14. Therefore, for the reasons provided in this petition request, the petitioners formally request that the agency prepare a Supplemental DEIS which takes a hard look at an all-underwater route for the proposed intertie which uses light HVDC technology. Thank you for your attention to this important matter. Marc Wheeler Eric Hummel SEACC LCS Petition for 2 Supplemental DEIS for the Swan Lake - Lake Tyee Intertie by SEACC and TCS, March 14, 2000 _4 PRGrOSED SOUTHEAST ALASKA {ELECTRICAL INTERTIE Are Tek JUNE, 1999 nen Yooper! x VArAOudA M1 SSiM JBSTATION rISHAM ec 1 DRS a5 P29) * Natural Setting LUD’s =WWo's that ba ‘mamntain okd-growth habitat Wilderness. National Monuments, Congressionaly Designated Unroaded Areas, Old-growth Recreation, Municipal Watersheds, Special Interest Areas, Wild. Scenic & Recreational Sirus. oud Ronaech Hotere * Developmental LUD’s = Timber Production Moditied Landscape, end Scenic Viewshed flosa than 25% of these lands are suitable for timber harvest) aa * Non National Forest System Lends = ‘Suma, Native, and Private lands. SR EXISTING TRANSMISSION LINE* ===" PROPOSED TRANSMISSION ule * Approximate voltage ingicated. SCALE bb} o 38 76 114 MILES o CH2MIHILL EGEIVE|)) JUN 1 & 1999 Le) Alaska Industrial Development fener’, tae and Exeort Authority 117526.B1.01 Mr. Dennis McCrohan Alaska Industrial Development and Export Authority 480 West Tudor Road Anchorage, Alaska 99503-6690 Subject: Budget Increase Request Dear Dennis: CH2M HILL 777 108th Avenue NE Bellevue, WA 98004-5118 P.O. Box 91500 Bellevue, WA 98009-2050 Tel 425.453.5000 Fax 425.462.5957 Proud Sponsor of National Engineers Week 2000 This letter is to request a budget increase to NPT No. 5, Multi-Discipline Architectural and Engineering Services, Agreement No. AIDEA 97-002, in the amount of $15,000. This increase would bring our contract total to $35,000.00. The budget increase is to cover additional scenario analysis and alternative review, and the anticipated analysis in response to critical comments that may result from public review of the report. Please call Dave Gray with any questions at 425/453-5005, extension 5136. Sincerely, CH2M HILL William J. Winter, Ph.D., P.E. Vice President ergy Economits JUN-03-99 THU 03:54 PM FAX NO. P, Ol DRAFT DRAFT DRAFT RAFT DRAFT DRAFT, ,, LAL Feur Dam Peo! Response to 2 of : AIDEA's Southeast intertie Review LIVAM Introduction AIDEA racently released thelr report entitled "Sputheaet Iniartie Review" dated April 12, 1099 analyzing the feasibility of lseuing bonds to finance the Swen-Tyse Inierlie, and comparing the imtertie to other proposed Ketchikan area energy projects. While the Project Menagament Committes ("PMC") of the Four Dam Poo! appreciates AIDEA's review of the interiia, the PMC balieves the repori focusas on the ahort-term economics of the project Inataad of he overall long-term benafite io Ketchikan, 8.E. Alaska, and the communities In the Four Dam Peal, Contrary to the conclusions drawn In AIDEA's report, the following facts support buliding the Interiia; . The Interthe wil beneft the communities of Kelchikan, Kaciek, Petersburg, Wrangell, Valdez, Glenailen, Keke, Metlakatia, Craig, Mydaburg end Sika (?); , The project is self aufficien!; wih anlicigated federal grants, incraased sales of Tyee power can finance the remaining debi; . The intertie wif Uviize power at Tyee that is currently being wasted as water spifing over the dam, therefore, taking ecvaniage of, and maximizing retum on, 6n exlating Stale investinent; » = Environmental impect Study is completa and af pennits have been sued. Nconomice The Four Dam Pool purchasing utllites have consistently stated that justificalion for prooseding with the interlie extende beyond shorl term economics, Furthermore, Ketchikan: Publle Utities (KPU) and the PMC have long acknowledged (hal at full cost (he Intertia is not the most cost sMacthe energy resource for KPU (as the primary recipient ef power ever the Interta) mt leant in the near term, However, few major public works projecis penell out intially uniess intangible benefits are Included in the econamis analysis. ile no surprise thal the economic analyala shows that clher resources are more cos! effactlve, given the reviews primary essumptions of continued low diesel prices and no additional prant money for construction, However, assuming the reeelpt of additional feceral grants (which at thie point is © very real poselbillty) and @ more reallatic forecast 19@IENAAMO/0823 84-0009 JUN-03-99 THU 03:54 PK FAX NO. P, 02 of future divse! pricas based on current trenda, Ihe Interiie is the most economically viable power aupply for KPU.' The econemic analysis ln the AOEA review assumes that the interts (¢ funded from the following sourcau: Funding Available: State Granis Authorized/Recalved $11,200,000 Federal Grants Authorized/Received 9,800,000 Timber Sele Credit — 4.900.000 $26,100,000 Additional Funding Proposed: Additonal Proposed Federal Grants $ 7,800,000 Proposed Qlate Bond Proceeds 44,800,000 $77,200,000 However, (he AIDEA review neglects one additional grant fund and underetates ancther, KPU und the other Four Darn Pool parlicipanis have requested $20 million in addkionel federal granty, not $7.8 million a¢ atated In their report. In addition, KPU will receive an additional $4.4 milion this year from the Sovtheas| Energy Fund, These two grant sources decrease the required bond proceeds (o $27,700,000. Using assumptions ulmitar to those used by AIDEA, nel debt service on bonda wilh thia amount of proceeds would be approximately $2.8 milion annually, compared {o (rest loat on fax from Alan D and he ia doing additional analyiels). In addition to revenue darived from sales of energy ovar tha Intertle, KP ls expected to receive addtional payments @ach year from the Southeaet Energy Fund. These revenue sources should total over $6 million annually und be sufficient to amortize the bonds In s timely manner, Benefita to Ketchikan Tha Intartio has substantial benefits over other generation sources thal KPU has conaldered. Although soma may be cheaper in the short-lerm, they ore all nedequate to mest current, rict lo mentian forecast, loads and will have to be augmenlied by dieval generation in the near ierm. ‘The larguat allernative energy source baing considered is the Mahonay Lake project that has @ theoretical capacty of approximately $0 million kWH. This, however, pales in comparison lo the surplua avallabie at Tyee which is around @9 mitton kwh. AIDBA's reper pointe oul that as the populations in Petersburg and Wrangell grow, teas power wil be avaiimble to KPU, However, the population In Petersburg and Wrangall have, at best, stagnated in the past couple years and have probably deciined, eitatmane, ‘ AIDBA‘@ report assumes a6 a bays onne disygl prtoes of BB canta per gelion In 1009 {0 64 cants in 2015 ter upeed It rea! dolart, KPU purchased dietal fuel earias this month al & cost of @3 canis pet gallon, and tha — Cont of #2 digye! fuel Ini the Slale of Amshe ever the peat twenty years hes been abou! GB cents per gation, 1963/1 RAMDANS72394-0000 JUN-03-98 THU 03:54 PM FAX NO. P, 03 Another raeaon fo pursue the intertie instead of an addilione) hydro project in the Keichikan area is the consideration that af the proposed, a8 well as exiating, hydro projects are fow elevation projects mainly dependent on regular rainfall to replenish the reservoira. All of theae are in he same meteorological zone and when it dosan't rain in one, ¢ probably won't rein In eny of them. Tyee, onthe other hand, ta a high elevation project in w distinet mateorological ares. {¢ 6 slso » project thal la fed from a large Walershed with a large tnow pack, The Inertie will allow optimization and coordination of these indapendent watersheds. Benefiia te Southeast Alasks Tha long-tern banefite to Southeast Alaska in completing the first leg of the Southeast Electical intertls Syatem are significent. The project has {he brosd support af almost every community In Boutheasl Alaska an wal) as the Southeast Conference, The Swan- Tyee Intertte wit interconnect the communtiies of Ketchikan, Wrangell, and Petersburg, which will improve retisbilty and provide for additional reserve potential fer thoee , communtias. The intertie wil ay the groundwork for the cansiruetion of additional links fe smaller communities euch es Kake and Metlekatia end evantuaily tranemisaion lines connecting GRkw and Juneau. Several small hydro generation sources have been Kentiiad in the proximity af the Intettis and could be inexpensively brought on line ae the eurptus from the Tyse diminishes over time. Affordable, reliable power le the “lifsblead" thet ruts the economle angines in almost all of the Southeast Alaska communities. With the vidual demise of the timber Industry in $.8. Alaeka and the changes taking placa in the salmon fahing industry, attracting new business wit In large part depend on the avellablity of euffieiant power. The Intertie will significantly avale( in this endeavor, Banefits to the Four Dam Pool Construction of the Swan-Tyee Intartia te of Interest lo all the Four Dam Poo! Purchasing \tities, These utliliss serve consumers in Kodiak, Vader, Glanalien, Ketchikan, Petersburg, and Wrangell in addition to several emelier communities. The Interile will lap the huge surplus (and lis only surplus avelable among the 4 hydro projects that make up the Four Dam Pool) theraby significantly lowering tie Wholesale Power Rate for power purchased by the utilities, AIDEA's report identifies this saving to ba in exceas of .5 cents/kwH when the Tyee project Is fully utilized, however, thay fail to factor this savings into their ecanamic analysia. The total ssvings (o all the consumers in the Four Dam Poel will amount to atound 82 millon each year # the Intertle ie constructed and the Tyee surplus le lapped. in addition, beosuse both the Swen and Tyee projecis are Four Dam Pool projects, the Inierte wil enable the affective management of watersheds in both projects thereby optimizing cutput. Summary It the intertie Is ever to be bullt, this Is the time. KPU hes a demand for power and Tyee has the surplus avatable. KPU'y willingness to purchase power over the Intertie 196301 MAMD06ZI H4 O00 JUN-03-99 THU 03:55 PK FAX NO, P, 04 Preasnts an opportunity for the Btete to inveat In the long term econamic development of Bautheset Alaska. Hf KPU elects to pursue other akernatives, the opportunity to build the Intertie la lost, H KPU chooses to proceed with other generation aplions in Ketchikan, the benefits lo Petersburg, Wrangell, tha real of 6.E. Alana, and the Four Dam Pool ratepayvre wil be lost. The choice ls eintple; KPU can proceed with local Options and purchase pewer for around 6.6 cents/nwH, For about the seme price, KPU can purchasy powsr end the Intertis can be built hereby benefitting ali ef Gouthenat Alseka and the Four Oem Poel. : Dennis Lewte Chairman Project Management Commitise Four Dam Pool 1980/1 MMODEZ 394-0000 RESOLUTION NO. A RESOLUTION of the Project Management Committee (PMC) of the Four Dam Pool Supporting the Swan - Tyee Intertie. WHEREAS, the City of Ketchikan, the City of Wrangell, the City of Petersburg, the Copper Valley Electric Association Inc., and the Kodiak Electric Association, Inc. are the Purchasing Utilities of the Four Dam Pool; and WHEREAS, these utilities serve approximately 60,000 Alaskans providing reliable, low-cost energy; and WHEREAS, the Swan Lake Project, which serves the City of Ketchikan, is operating at full capacity and Ketchikan is presently running diesels to meet load requirements; and WHEREAS, the Tyee Project has surplus generating capacity available to supply Ketchikan’s additional energy needs well into the future; and WHEREAS, the proposed Swan-Tyee Intertie is the first portion of the S.E. Alaska Electrical Intertie system and construction of this Intertie will interconnect the communities of Ketchikan, Wrangell and Petersburg; and WHEREAS, additional sales from the Tyee Project will lower the power costs for ALL ratepayers in the Four Dam Pool including the communities of Ketchikan, Wrangell, Petersburg, Kodiak, Port Lions, Glenallen, Copper Center and Valdez; and WHEREAS, construction of the Swan-Tyee Intertie will allow smaller hydroelectric projects in the vicinity of the Intertie to come on as load demand grows in the communities of Ketchikan, Wrangell, and Petersburg; and WHEREAS, the Swan-Tyee Intertie has been engineered, necessary permits are in place, and the project is ready to bid; and WHEREAS, the Swan-Tyee Intertie has strong support from Senator Stevens, Senator Murkowski, and Representative Young, as well as from all the communities in Southeast Alaska; and WHEREAS, Ketchikan Electric Corporation, a joint venture of Cape Fox Native Corporation and Alaska Power & Telephone, is actively pursuing Ketchikan to purchase power from the proposed Mahoney Lake Hydroelectric Project in lieu of building the Swan-Tyee Intertie; and WHEREAS, the Four Dam Pool purchasing utilities will not receive any benefits if Mahoney Lake power is sold to Ketchikan; and WHEREAS, the surplus power available from the Tyee Project is twice that amount available from the Mahoney Project; and WHEREAS, the Swan and Tyee projects are in separate and distinct meteorological areas/watersheds and the construction of the Intertie will lessen the impact caused by periods of low precipitation by utilizing water management procedures between the two projects; and WHEREAS, construction of the Mahoney Lake Hydroelectric Project prior to construction of the Swan-Tyee Intertie will not either benefit the purchasing utilities of the Four Dam Pool or satisfy the long term power needs of the greater Ketchikan community; NOW, THEREFORE, BE IT RESOLVED by the Power Management Committee of the Four Dam Pool that it supports the immediate funding and construction of the Swan-Tyee Intertie both for the benefit of the 60,000 Alaskan residents served by the Four Dam Pool and to satisfy the long-term power needs of the “ay Ketchikan me ee (AEA). \X\ am ° @ £/12/4F SN a ADP BC we SMe (Show eho/s4 Fie ® ALASKA INDUSTRIAL DEVELOPMENT =, » ¢ AND EXPORT AUTHORITY => ALASKA @@E— =ENERGY AUTHORITY 480 WEST TUDOR ANCHORAGE, ALASKA 99503 907 / 269-3000 FAX 907 / 269-3044 Il. Introduction and Executive Summary The Alaska Industrial Development and Export Authority (AIDEA) was asked to perform a review of the proposal being advanced by Ketchikan Public Utilities (KPU) for funding and construction of the proposed Southeast Intertie (the “Intertie”). The review has two primary aspects. The first provides an economic analysis and comparison of the Southeast Intertie (using the KPU proposal) to other alternative projects that could serve Ketchikan’s needs. The second aspect examines the financing issues surrounding the KPU proposal. AIDEA engaged CH2M Hill to perform the economic analysis and comparison aspect of the review. CH2M Hill performed two analyses for this purpose. The Economic/ Resource Analysis compares the actual cost to build and operate the Intertie, irrespective of who pays for those costs, to costs for other alternatives such as the Mahoney Lake project, other small hydroelectric projects and additional diesel generation. The Rate Impact Analysis examines the rate impacts to the Ketchikan energy consumers of the various alternatives. CH2M Hill also performed sensitivity analyses with respect to various assumptions. These analyses include considering the impact of significantly increased diesel fuel costs. CH2M Hill’s Economic/Resource Analysis indicates that, in almost all cases, the Intertie is not the best economic choice to meet Ketchikan’s future load requirements. Under certain growth conditions, however, if high diesel fuel prices are assumed, the Intertie has a resource cost comparable to the other alternatives. From a rate impact perspective, CH2M Hill’s analysis indicates that the Intertie would increase power rates in the Ketchikan area relative to the other power options available. AIDEA engaged its financial advisor, Pat Clancy of Clancy Gardiner and Pierce, to analyze the various financing issues related to KPU’s proposal. Mr. Clancy’s analysis indicates that the KPU financing proposal, as currently envisioned, would not provide a sufficient structure for the issuance of revenue bonds. If several structural changes are made, however, Mr. Clancy concludes that it may be possible to structure an investment grade bond issue. Among the required changes is the need for a credit- worthy entity to guarantee bond debt service. The economic and financial analyses performed by AIDEA’s consultants do not completely resolve the question of whether the KPU proposal has merit. Instead, these analyses provide a framework for consideration of the various public policy issues surrounding the Intertie. There are a number of additional factors (both positive and negative) that must be considered from a policy perspective in making a determination if the Intertie should proceed. These include the Intertie’s integration with the Southeast Alaska Electrical Intertie System Plan, currently available federal funding opportunities for the Intertie, watershed considerations, and policy considerations related to public versus private sector funding of energy projects. If a decision is made to proceed with the Intertie, AIDEA has identified certain basic elements that would be required. These include appropriate legislation, financial guarantees, and contractual agreements. Il. Background A. Southeast Intertie The proposed Southeast Intertie would connect the Tyee Hydroelectric Project (a part of the Four Dam Pool projects) with the Ketchikan area. Unused surplus power from the Tyee project (now serving only Petersburg and Wrangell) would be transmitted via the Intertie to Ketchikan.’ Currently, Ketchikan’s primary source of power is the Swan Lake Hydroelectric Project (also a part of the Four Dam Pool) and other local hydroelectric projects. These projects do not supply sufficient power to cover all of Ketchikan’s needs and therefore KPU supplements these local hydroelectric resources with diesel generation. The following table depicts KPU’s existing generation resources: Existing KPU Generation Resources Resource 1998 Actual(MWh) Average Annual Capability (MWh Swan Lake 71,078 80,700 Other KPU Hydro 66,251 64,600 Diesel 26,798 141,220 TOTAL 164,127 286,520 In 1998, KPU’s average retail rate for power was approximately 9.2 cents per KWh. This rate compares favorably with energy rates in Southcentral Alaska and is below statewide averages. The proposed Intertie would allow for load growth in Ketchikan and reduce the need for diesel generation. The Southeast Intertie would, for the first time, link two of the Four ' As energy loads grow in Petersburg and Wrangell less surplus energy would be available for transmission to Ketchikan over the Intertie. While the Tyee Project has the capability of adding an additional turbine, because of water constraints, an additional turbine would not increase the overall energy producing capability of the Tyee project. Southeast Intertie Review April 12, 1999 Page 2 Dam Pool projects. Because operating costs for all of the Four Dam Pool projects are pooled, depending on the rate at which power was purchased, sale of power to Ketchikan from the Tyee project would somewhat lower the operating costs of the Four Dam Pool on a per kilowatt hour basis. This reduction would reduce power costs for all of the Four Dam Pool communities. Gross state revenues from the Four Dam Pool projects would also increase. In addition, the Intertie could open the possibility of future generation projects in proximity to the Intertie. The Southeast Intertie is part of the first phase of a proposed $436 million Southeast Alaska Electrical Intertie System Plan developed for the Southeast Conference. This System Plan was developed to integrate development of proposed intertie segments with new hydroelectric generation capacity for the region. To date, funding proposals for the remainder of the System Plan have not been developed. B. Alternatives In addition to the Southeast Intertie, other projects have been proposed which could serve Ketchikan’s energy needs for the foreseeable future. The Mahoney Lake project is a 10 MW hydroelectric project being promoted by Ketchikan Electric Company (KEC). KEC holds a Federal Energy Regulatory Commission license for the project. KEC is a joint venture between Alaska Power and Telephone (APT) and the Cape Fox Corporation. Other proposed hydroelectric projects that could be developed by KPU include the 5.3 MW Whitman Lake project, the 1.9 MW Lake Connell project, and the 1.2 MW Carlanna Lake project. KPU currently uses diesel generation to supplement its Swan Lake power. Subject to air permitting requirements, KPU could add new diesel facilities to increase its generation capacity.2 Even if the Intertie or other hydroelectric alternatives were chosen to meet Ketchikan’s energy requirements, under certain scenarios, additional diesel backup reserve generation would nonetheless be required. The following table compares Ketchikan’s various energy resource alternatives along with their estimated cost and projected generating capability.° ? Under high energy growth conditions, increased diesel generation in Ketchikan could be limited by air emission regulatory and permitting requirements. > R.W. Beck’s 1998 update to KPU’s Power Planning Study indicates that approximately 10,200 MWh of hydroelectric energy and as much as 37,600 MWh of diesel energy might be available through an interconnection of Ketchikan with the Metlakatla Power & Light (MPL) system. In addition, the interconnection could also provide reserve capacity to KPU and additional hydroelectric power generation with upgrades to the MPL system. Assuming that KPU would pay for the interconnection and the upgrades, R.W. Beck found that, from a cost standpoint, the MPL interconnection was similar to KPU adding the small hydro projects to its system. CH2M Hill did not analyze the MPL interconnection alternative. Southeast Intertie Review April 12, 1999 Page 3 Ketchikan Energy Resource Alternatives 1998 Estimated Project Cost ($ millions Capacity (MW) Energy Available (MWh) Intertie $77.2 ° 20.0 ° 88,769 ° Mahoney Lake SA75° 10.0 41,740 Whitman Lake $ 7.1 53 19,880 Lake Connell $ 5.4 1.9 12,200 Carlanna Lake $ 4.2 1.2 6,665 New Diesel (low speed): Without power house $ 8.3 6.4 53,260 ° With power house $17.3 6.4 53,260 ° Notes to table: Represents full estimated construction cost before timber sale credit. Represents Tyee capability; actual availability will vary annually based on water conditions and Wrangell and Petersburg loads. Represents average Tyee capability reduced by FY1998 Wrangell and Petersburg loads actually serviced by Tyee. Actual availability will vary annually based on water conditions and actual Petersburg and Wrangell loads. Per KEC estimate. A 1998 R.W. Beck study used a capital cost of $28.8 million for Mahoney Lake. Assumes 95% availability. ll. Original Financing Proposal In 1993, legislation was enacted that formed the basis for the original financing proposal for the Southeast Intertie. Under the legislation, KPU was to own the Intertie for the benefit of the utilities participating. The legislation created three potential funding sources. First, $20 million was appropriated to the Department of Community and Regional Affairs to be used as a loan to the participating utilities for the Intertie. This loan was to have a term of 15 years and bear interest at 3%. Second, subject to appropriation each year, the legislation allocated 40% of the State’s Four Dam Pool revenue stream to the Southeast Energy Fund.* To date, $11.3 million in grants from ‘ Under the Power Sales Agreement (PSA) for the Four Dam Pool, the Alaska Energy Authority (AEA) sells power from the projects to the five local utilities serving the Ketchikan, Wrangell, Petersburg, Kodiak, Glennallen, and Valdez areas. Power from the projects is sold to the utilities at a rate determined under the PSA. The rate has two components. The power cost production component covers the actual operation and maintenance costs for the projects. This component also includes a fixed $500,000 per year contribution to a project renewal and replacement fund to be used for renewals and replacements of project facilities and equipment. The debt service component provides for payments to the State based upon a schedule contained in the agreement. Under the PSA, the State is responsible for certain significant project liabilities. These include uninsured facility failures, substandard performance and deficiencies in the renewal and replacement fund. The PSA provides that the utilities may withhold the debt service component payments to the State if AEA is unable to otherwise obtain funds to meet its obligations under the PSA. This right is generally referred to as the utilities’ self-help right. In FY 1999, the uniform Four Dam Pool rate is 6.8 cents per kWh. As part of legislation passed in 1993 that reorganized the AEA (see footnote 5), subject to annual appropriation, the Legislature pre-allocated the debt service component payments received by the State as follows: 40% to the Power Cost Equalization and Rural Electric Capitalization Fund, 40% to the Southeast Energy Fund, and 20% to Southeast Intertie Review April 12, 1999 Page 4 the Southeast Energy Fund have been made or committed to KPU for Southeast Intertie related activities. Finally, the legislation authorized AIDEA to issue up to $40 million in revenue bonds to finance the Intertie.° In addition to the funding sources for the Intertie identified in the 1993 legislation, KPU has actively sought federal funding for the Intertie. To date, $9,900,000 in federal grants has been made available for the Intertie and additional federal funds have been requested. Based upon the various funding sources identified, KPU developed its original financing proposal. Recognizing that the cost of power from the Intertie would be unacceptable if KPU were required to pay the uniform Four Dam Pool rate for power, pay the operating costs for the Intertie and also make the debt service payments contemplated in the 1993 legislation, KPU proposed that it pay a reduced rate for the Tyee power. KPU proposed that the rate for Tyee power be at a level that when added to its other Intertie related costs (debt service, operation, maintenance, etc.), resulted in a total cost of power in Ketchikan equal to the uniform Four Dam Pool rate of 6.8 cents per kilowatt hour. Put another way, KPU proposed reducing the uniform Four Dam Pool rate by an amount sufficient to cover its entire Intertie related costs. KPU’s analysis indicated that, initially, no payments could be made for the Tyee power. Moreover, to ensure no increase to the Ketchikan ratepayers in the early years of operation, KPU indicated it might require access to a working capital loan. KPU proposed that it obtain such a loan from AIDEA for this purpose. After significant analysis and discussions with its financial advisor, KPU determined that it would not be prudent for the Ketchikan community to incur the level of debt required by the original financing plan. The KPU debt contemplated in the original proposal would have severely impacted Ketchikan’s future borrowing ability. Accordingly, KPU abandoned the original financing proposal. the Power Project Fund. No portion of the debt service payment was allocated to AEA to fulfill any of its obligations under the PSA. ° The 1993 legislation was part of an overall reorganization of AEA. Previously, AEA’s primary mission was to construct, own and operate energy infrastructure projects for the benefit of local utilities and consumers. The 1993 legislation signaled a change in policy with respect to State ownership of energy projects. The legislation eliminated AEA’s ability to acquire and construct new projects. Wherever possible, AEA was to contract with local utilities for the operation of the existing facilities. These policy changes are reflected in the legislative treatment of the Southeast Intertie. Despite the fact that the Southeast Intertie was to link two AEA owned Four Dam Pool facilities, the legislation called for KPU ownership of the Intertie. Moreover, the Intertie was to be financed by loans and bonds to be repaid directly from payments made by KPU and the other participating utilities. Southeast Intertie Review April 12, 1999 Page 5 IV. Current KPU Proposal In the fall of 1998, KPU formulated a new financing plan for the Southeast Intertie. Under the KPU proposal the State would own the Intertie.° The State, presumably through AEA, would issue revenue bonds in an amount sufficient to provide proceeds to fund the remaining costs of the Intertie. Debt service for these bonds would be paid from the 40% share of the State’s Four Dam Pool revenues currently allocated to the Southeast Energy Fund. Under KPU’s proposal, the $20,000,000 DCRA loan contemplated in the 1993 legislation would not be utilized and could be immediately released for other purposes. KPU would enter into an interruptible power sales agreement for power received over the Intertie from the Tyee facility. While KPU has indicated that an acceptable interruptible power sales agreement will need to be negotiated, KPU has assumed that Tyee power would be sold to KPU at or near the current Four Dam Pool rate. The following table depicts the current KPU funding proposal. Funding Available: State Grants Authorized/Received $11,200,000" Fed. Grants Authorized/Received 9,900,000 Timber Sale Credit 4,000,000 25,100,000 Additional Funding Proposed: Additional Proposed Federal Grants 7,500,000° Proposed State Bond Proceeds 44,600,000° 52,100,000 Total Estimated Intertie Cost (As of 9/98 in 1997 dollars) $77,200,000 V. Economic Analysis AIDEA engaged CH2M Hill to perform an economic analysis for the Southeast Intertie. CH2M Hill's report is attached as Exhibit “1” to this memorandum. CH2M Hill evaluated both the economics and rate impacts of the Intertie and the various power resource alternatives. The CH2M Hill report describes in detail the assumptions utilized and the © As the Southeast Intertie would connect two AEA owned Four Dam Pool projects, AEA is the logical choice for State ownership. ? The Department of Community and Regional Affairs, Division of Energy, recently notified KPU that an additional $4.4 million in State grant funds are available for the Intertie from the Southeast Energy Fund. Disbursement of these funds is contingent, however, on a number of conditions including development and approval of a financing plan for the Intertie and the execution of appropriate agreements. Because KPU’s proposal did not include these additional State grant funds, these funds have not been included in this analysis. Obviously, any additional State grant funds actually received would reduce the remaining funding required. ® KPU is seeking more than the $7,500,000 in additional federal grants for the project. Any increase in federal grants would reduce the amount of State bond proceeds required. We understand that the Clinton Administration recently introduced energy legislation that includes authorization language to provide up to $20,000,000 for the Intertie. To date, however, no federal appropriation for the Intertie has been introduced. Southeast Intertie Review April 12, 1999 Page 6 conclusions reached. CH2M Hill's assumptions were shared with KPU. CH2M Hill considered KPU’s comments and modified certain assumptions. In addition, CH2M Hill performed sensitivity analyses with respect to various assumptions. The following sections briefly describe key elements of the report. A. Load Forecasts In performing its analysis, CH2M Hill was not tasked with developing new energy load forecasts for the Ketchikan area. Rather, CH2M Hill utilized the June 1998 load forecasts prepared for KPU by the Institute of Social and Economic Research (ISER). ISER had developed three load forecasts utilizing high, medium, and low growth assumptions for the Ketchikan area. CH2M Hill examined these forecasts and made adjustments based upon discussions with KPU staff. The result of these adjustments was to increase the ISER forecast loads in the medium and high growth scenarios. These adjusted load forecasts were then used by CH2M Hill in performing its analysis. B. Alternatives Reviewed Based on available information, in performing its economic analysis, CH2M Hill examined the following alternative cases: All Diesel — This case assumes that no other alternative is chosen and therefore Ketchikan’s future energy demands are satisfied entirely by adding additional diesel generation. This case assumes fuel costs of 63 cents per gallon in 1998 and 58 cents per gallon in 1999 then escalating to 66 cents per gallon in 2018. CH2M Hill also performed a sensitivity analysis assuming fuel prices of 85 cents per gallon. Southeast Intertie - This case assumes construction of the Southeast Intertie. The option also assumes additional replacement (reserve) diesel generation will be required in the future. The timing of the diesel reserve requirement is dependent on the particular load forecast utilized. Mahoney Lake — This case assumes development of the Mahoney Lake project based upon proposals advanced by KEC. Depending on the load forecast utilized, replacement diesel reserve generation is also included. The high load forecast case assumes that the small hydro plants are developed instead of the addition of new diesel units. Mahoney Lake & Intertie — In the medium and high load growth scenarios, this case assumes that both the Mahoney Lake and Southeast Intertie projects are constructed. In the medium growth scenario the Mahoney Lake project is constructed first followed by the Intertie. In the high growth scenario both projects are constructed at the same time. Southeast Intertie Review April 12, 1999 Page 7 Small Hydro — This case assumes development of the Whitman Lake hydroelectric project and, depending on the load forecast, subsequent development of the Lake Connell hydroelectric project.2 Replacement diesel reserve units are included in the high load forecast case. CG: Economic/Resource Analysis 1. Purpose and Assumptions CH2M Hill's Economic/Resource Analysis compares the present value of the alternative energy projects based upon the various load forecasts. This analysis ignores the funding sources for the various projects and instead compares the total capital and operational costs of the projects over a 50-year period. This methodology had been used by AEA and continues to be used by the Division of Energy in examining proposed energy projects. The methodology is designed to examine the total societal cost of choosing one energy resource over another. The Economic Resource analysis requires consideration of the capital costs of the projects being compared. Because existing funds have already been devoted to the Intertie and a substantial amount of additional federal funding is proposed, CH2M Hill developed three cases for examination of the Southeast Intertie that modify the methodology that is normally used in this type of analysis: Incremental State Cost — This case utilizes as capital costs only those additional costs required to complete the project which are to be funded with State dollars. The analysis excludes both the funds expended to date (the “sunk costs”) and future costs to be funded with federal grant dollars. Accordingly, under this case the capital cost of the Intertie is reduced by the $17.4 million dollars in federal grant funds proposed by KPU and $8.1 in funds already expended for Intertie development. Incremental Cost — This case utilizes as capital costs only those additional costs required to complete the project. It excludes all sunk costs but does not make any adjustments for proposed federal funding. This case is the most helpful for comparing the Intertie versus the other alternatives without federal grant assumptions affecting the result. Full Cost — This case utilizes the full capital cost of the Intertie including all costs expended to date (the sunk costs) and all additional costs required to complete the project. ° KPU’s analysis indicates that the Carlanna Lake project could be substituted for the Lake Connell project. CH2M Hill utilized the Lake Connell project in its analysis because a preliminary FERC license has been obtained for that project and that project is capable of displacing more high-cost diesel generation thereby reducing overall costs. Southeast Intertie Review April 12, 1999 Page 8 Two separate construction cost estimates were utilized in examining the Mahoney Lake project. KEC estimates the cost of Mahoney at approximately $17.5 million. A 1998 R.W. Beck study prepared for KPU used a capital cost of $28.8 million for the Mahoney Lake project. CH2M developed two Mahoney cases, a high and low capital case, utilizing the differing construction cost estimates 2. Findings CH2M Hill draws several conclusions from the Economic Resource analysis. Among the most significant are: e In amedium growth scenario, the low capital cost Mahoney case is the least costly, closely followed by the Small Hydro alternative. If the high capital cost Mahoney case is considered, under a medium growth scenario, the Small Hydro alternative is the least costly followed by Mahoney Lake. e Even when considered at the incremental state costs (excluding all federal grants and sunk costs), under a medium growth scenario, the Intertie is significantly more costly than the Mahoney Lake or Small Hydro alternatives. e In a high growth scenario, the low capital cost Mahoney Lake project augmented by development of Small Hydro is the least costly alternative closely followed by the Mahoney Lake & Intertie alternative. e In alow growth scenario, the Small Hydro alternative is the least costly by a substantial margin followed by the All Diesel alternative. e Under medium growth conditions, if higher diesel prices are assumed, the Intertie (considered at incremental state (lowest) cost), Mahoney Lake, and Mahoney Lake augmented by future Intertie development all have comparable costs. e Under high growth conditions, if higher diesel prices are assumed, Mahoney Lake augmented with future Intertie development is the least costly alternative followed by the Intertie (considered at incremental state (lowest) cost) and Mahoney Lake/Small Hydro alternatives. The CH2M Hill Economic Resource analysis demonstrates that, under most growth scenarios, the Intertie is substantially more costly than the other alternatives. Southeast Intertie Review April 12, 1999 Page 9 D. Rate Impact Analysis it Purpose and Assumptions CH2M Hill performed a Rate Impact Analysis. The purpose of this analysis is to compare the actual power rate impact to the Ketchikan consumer of the Intertie and the other alternative power resources. The analysis uses as a base case the All Diesel alternative and compares the rate implications of undertaking each of the other alternatives. The assumptions utilized in the analysis are described in the CH2M Hill report. The following highlights a few of the more significant assumptions: All Diesel — As KPU would be the owner of the facilities, this case utilizes the projected capital financing and operation costs for the diesel facilities. This case assumes fuel costs of 63 cents per gallon in 1998 and 58 cents per gallon in 1999 then escalating to 66 cents per gallon in 2018. Southeast Intertie —- This case assumes that KPU purchases power generated from the Tyee project at 6.8 cents per kWh, the current uniform Four Dam Pool rate plus a component for renewals and replacements. This is the same assumption provided by KPU in the information forwarded to AIDEA."° Any changes in the actual rate would require that the Rate Impact Analysis be adjusted to reflect that rate. Mahoney Lake — This case assumes that KPU would purchase power generated from the Mahoney Lake project at 6.5 cents per kWh and that the power would be subordinate to KPU’s Swan Lake power. KEC has indicated its willingness to enter into a long-term power sales agreement for Mahoney power at this rate. KEC has indicated that this rate could be lowered if federal grant funding were made available for the Mahoney Lake project. Because no grant funds have been identified the analysis does not consider this possibility. Additionally, KEC has stated it will not pursue State grant funding for the project. Small Hydro — This case utilizes the project capital financing and operation costs for the Whitman Lake and Lake Connell projects assuming KPU ownership and tax exempt financing. '° This assumption is also consistent with the notion that if the State is to provide a significant portion of the capital for the Intertie (through Southeast Energy Fund grants and use of State revenues to pay debt service) the State should reasonably require that KPU pay the full Four Dam Pool rate for Tyee power. Even at this rate, CH2M Hill’s analysis indicates that the additional State revenues generated by the sale of Tyee power over the Intertie are not sufficient to pay the cost of the Intertie. Because utilization of the full Four Dam Pool rate would minimize the State subsidy for the project we believe the assumption is reasonable. Southeast Intertie Review April 12, 1999 Page 10 2s Findings Among the most significant findings from the CH2M Hill Rate Impact Analysis are: e In all but the high growth scenario, the Southeast Intertie would increase KPU rates relative to the other alternatives examined including All Diesel. e In the high growth scenario, the Southeast Intertie would result in lower rates to the KPU ratepayers than the All Diesel case, but higher rates than for the other alternatives. e In all but the high growth scenario, the Small Hydro alternative would result in the lowest cost to KPU ratepayers. e Ina high growth scenario, Mahoney Lake augmented by Small Hydro would result in the lowest ratepayer cost. Vi. Financing Issues KPU has proposed that the State issue bonds to finance the remaining costs of the Intertie. KPU has indicated that it expects to receive an additional $7,500,000 in federal funding for the Intertie. If KPU were successful in obtaining these funds, under KPU’s proposal, bond proceeds of $44,600,000 would be required to fund the project."' KPU has proposed that the debt service on these bonds be paid from the 40% share of the State’s Four Dam Pool revenues currently allocated to the Southeast Energy Fund. AIDEA asked its financial advisor, Pat Clancy of Clancy Gardiner and Pierce to review KPU’s financing proposal and analyze the various bond-financing issues. A copy of Mr. Clancy’s report is attached as Exhibit “2.” In order to obtain $44.6 million in bond proceeds, Mr. Clancy estimates that approximately $51.3 million in bonds would need to be issued. This amount includes estimated issuance costs and the amount necessary to fund a debt service reserve fund. Mr. Clancy estimates the net annual debt service on the bonds would be approximately $4.13 million after taking into account earnings on the debt service reserve fund. This amount assumes a level 25-year amortization of the bonds at a taxable rate of approximately 7%." 1 KPU has indicated that it may actually be able to obtain federal funds substantially in excess of the projected $7,500,000. Any additional federal grant amounts received would reduce the amount of bond proceeds that would be required. 12 It appears that under Internal Revenue Code rules, the Intertie would serve more than two contiguous “counties” and would therefore not qualify for tax exempt financing. Southeast Intertie Review April 12, 1999 Page 11 In order to issue bonds, Mr. Clancy has indicated that a stable revenue stream earmarked for payment of the debt service must be identified. The Four Dam Pool revenue stream is currently subject to annual appropriation and accordingly, as currently structured, would not provide an earmarked source of payment sufficient to issue the bonds. Presumably, this problem could be remedied with appropriate statutory changes. More importantly, however, Mr. Clancy has indicated that the Four Dam Pool revenue stream is not sufficiently stable under the Power Sales Agreement (PSA) for the projects. Under the terms of the PSA, the revenues received by the State vary with production. Because the contract is not “take or pay,” a reduction or interruption in energy generation and sales from the Four Dam Pool projects reduces payments to the State. In addition, the purchasing utilities’ “self-help” right can interrupt the State’s revenue stream if funds are needed to fulfill State obligations under the PSA. Self-help has been utilized on several occasions over the last few years to cover major repairs to the projects. Mr. Clancy also notes that 40% of the State’s revenue stream in the fiscal year 1999 would have been only $4.32 million, an amount marginally sufficient to cover estimated net debt service for the bonds of $4.13 million. Investment grade bonds typically require revenues significantly in excess of the required debt service requirement. While future growth projections indicate that the 40% revenue stream will likely grow, Mr. Clancy believes it is unlikely that 40% of Four Dam Pool revenue stream would be sufficient to provide the level of coverage necessary to support investment grade bonds. Mr. Clancy has identified a number of structural changes that could be made to address the issues identified. First, Mr. Clancy suggests that the entire debt service payment from the Four Dam Pool could first be pledged to the bond debt service. Any amounts not needed for debt service would then flow to the other allocated uses. This would provide sufficient coverage and alleviate concerns related to annual revenue changes from energy generation changes. This approach, however, would make the Intertie debt service the first priority and could limit the amount of funds available for the State to allocate for other uses such as power cost equalization. In order to eliminate the possibility that exercise of self-help could interrupt bond payments, Mr. Clancy suggests that the PSA could be amended to limit the utilities exercise of self-help. Even if such an amendment were possible, limitation of self-help might pose other problems. In recent years, self-help funds have been the only source of funds available to make major repairs to the Four Dam Pool projects. Restrictions on the availability of self-help funds could impede AEA’s ability to fulfill its obligations, potentially jeopardizing the reliability of the projects and the State’s Four Dam Pool revenues. More importantly, limitation of self-help in order to provide sufficient funds to make bond payments merely postpones self-help and ultimately reduces the State revenues available to allocate for other uses. Southeast Intertie Review April 12, 1999 Page 12 Mr. Clancy has suggested another approach that does not require modifications to the Four Dam Pool PSA or pledging of the entire State Four Dam Pool revenue stream. Mr. Clancy suggests that the 40% revenue stream could be backed by a guarantee by some sufficiently credit-worthy entity or entities. It is unclear if KPU or the other Four Dam Pool utilities have the willingness or financial strength to provide such a guarantee. Finally, Mr. Clancy notes that, under whatever structure is utilized, a plan would need to be developed that ensures the bondholders that sufficient funds from some source are available to pay the projected operation, maintenance, repair and replacement costs of the Intertie. In summary, Mr. Clancy’s analysis indicates that the KPU financing proposal, as currently envisioned, would not provide a sufficient structure for the issuance of revenue bonds. The following structural changes would be required to allow financing utilizing the 40% Four Dam Pool revenue stream: e Statutory changes necessary to pledge 40% of the State Four Dam Pool revenue stream toward debt service for the bonds. e Debt service guaranteed by a sufficiently creditworthy entity or entities. e Development of an acceptable funding plan for operation, maintenance, repair and replacement costs for the Intertie. Vil. Additional Factors The economic and financial analyses discussed above do not completely resolve the question of whether the KPU proposal has merit. Instead, these analyses provide a framework for consideration of the various public policy issues surrounding the Intertie. This section will highlight some additional factors that should be considered in making a determination whether or not to proceed. A. Factors favoring the Intertie The following are some factors favoring the Intertie that should be considered. e Assuming there is support for the Southeast Alaska Electrical Intertie System Plan, the Southeast Intertie is a part of the first phase of this comprehensive plan, which could ultimately provide benefits to a large portion of Southeast Alaska. However, the other major segments are distant prospects with respect to economic and financial feasibility at the present time. Southeast Intertie Review April 12, 1999 Page 13 B. The leadership positions of our congressional delegation provide an opportunity to receive federal funding for the Intertie now. It is unlikely that such an opportunity will arise again. Moreover, it is not clear that federal funding will be available for any of the other alternatives considered. Tyee Lake and Swan Lake are supplied by independent watersheds. Therefore, the Intertie allows for optimization of water resources. On the other hand, Mahoney Lake and Swan Lake are in close proximity and utilize the same watershed. Therefore, under critical water conditions, the Intertie could provide greater flexibility. For an additional capital cost, Tyee Lake has the capacity to create additional peak generation by adding another turbine. Because of water constraints, however, the total annual generating capability of the Tyee project would not increase. The Intertie opens up the possibility of development of other generation sources in proximity to the Intertie route. Under certain circumstances the Intertie could provide additional reliability and reserve potential in Petersburg and Wrangell by permitting the transfer of Swan Lake or other power generated in the Ketchikan area to be transmitted to those areas. Factors opposing the Intertie The following are some factors opposing the Intertie that should be considered. The KPU proposal requires significant State investment (40% of State Four Dam Pool revenues for 25 years) to support a region that already has some of the lowest power rates in the State. The Mahoney Lake project, a private sector project, requires no State funding or bonds yet results in lower energy rates than the Intertie under most scenarios. The funding and federal license are: already in place for the Mahoney Lake project. Following execution of a power sales agreement with KPU, KEC estimates Mahoney could be operational in 14 months. The Intertie requires additional federal funds, enactment of State legislation and the issuance of revenue bonds. In addition, the Intertie requires two constructions seasons to complete. Given these requirements, it will likely be several years before the Intertie could be operational. Southeast Intertie Review April 12, 1999 Page 14 e The State retains substantial risks related to the Four Dam Pool. Moreover, the purchasing utilities have recently asserted that the State is responsible for certain outage and other indirect costs. In this environment, additional State ownership and financing for the Intertie may be unwise. e Divestiture of the Four Dam Pool projects has been pursued for the last few years. Issuance of revenue bonds tied to the Four Dam Pool Revenue stream creates complications that would make divestiture much more difficult. Vill. Conclusion The Economic Resource Analysis performed by CH2M Hill indicates that, in almost all cases, the Intertie is not the best economic choice to meet Ketchikan’s future load requirements. Under certain growth conditions, however, if high diesel prices are assumed, the Intertie has a cost comparable to other alternatives. CH2M Hill's rate impact analysis indicates that the Intertie would increase power rates in the Ketchikan area relative to the other power options available. As noted above, however, there are a number of other factors that could be considered in addition to a strict economic analysis. If a decision were made to proceed with the Intertie, we believe the following basic elements would be required: e Legislation authorizing the project, AEA ownership and the issuance of AEA revenue bonds to finance the remaining construction costs and devoting 40% of the Four Dam Pool revenue stream to the payment of debt service for the bonds. e Cost overruns and debt service on the bonds would need to be guaranteed by some credit worthy entity or entities, presumably KPU and/or the other Four Dam Pool purchasing utilities. e Appropriate contractual arrangements would be required to ensure that the State has no financial responsibility for operation and maintenance, reserve and replacement, or other costs related to the Intertie. Additionally, we would recommend that appropriate contractual arrangements be in place to assure that KPU purchases all of its excess power needs from the Tyee project so long as power is available from the project. This will ensure the State obtains the maximum possible recovery of its Intertie investment. Southeast Intertie Review April 12, 1999 Page 15 CH2M HILL 301 West Northern Lights Boulevard Suite 601 EXHIBIT 1 Anchorage, AK CH2NME H I LE 99503-2648 MaRS Tel 907.278.2551 Fax 907.277.9736 April 16, 1999 Mr. Dennis McCrohan Alaska Industrial Development and Export Authority 480 West Tudor Anchorage, Alaska 99503 Dear Dennis: At your request, we have evaluated the economics and potential rate impacts of power resource options for Ketchikan, Alaska. The study has particular focus on the Swan Lake- Tyee Intertie (the “Intertie”). Our analysis was conducted using KPU’s power supply planning model, developed by R.W. Beck and used in KPU’s Power Supply Planning Study (1996) and the 1998 Update. Our findings are summarized in the four attachments to this letter. Attachment A, Economic/Resource Analysis, provides economic analysis of the resource options; Attachment B, Rate Impact Analysis, provides projected rate impacts of the same options; Attachment C, Sensitivity Analysis, provides results from changes in key assumptions and projections; and Attachment D summarizes the sources of information used in the analysis. In performing this analysis, we relied on information and projections from various sources (see Attachment D) and did not conduct new, independent research as the basis for our assumptions and input data. Major findings of our study are as follow (tables supporting each finding are identified in brackets): 1. For the base-case analysis (medium load forecast) the lowest resource costs are for either Mahoney Lake or Small Hydro (Whitman and Connell Lakes) development. Even with $17.4 million in Federal funding, the Intertie is $27.3 to $28.8 million more expensive than the Small Hydro and Mahoney alternatives, respectively. [Table A-1] 2. Under high load forecast conditions, Mahoney Lake augmented with small hydro when needed, is the least-cost option. However, under these forecast conditions, construction of Mahoney Lake in conjunction with the Intertie, is almost as inexpensive. [Table A-1] 3. The Mahoney Lake and Small Hydro alternatives present much less economic risk than does the Intertie. [Table A-1] Mr. Dennis McCrohi April 16, 1999 Page 2 4. The Intertie would increase Ketchikan Public Utilities’ rates relative to the All-Diesel alternative except under high load forecast conditions. Compared with other power supply alternatives, the Intertie would increase rates under all load forecast conditions evaluated. Under medium load forecast conditions, KPU rates with the Intertie would exceed those for Small Hydro and Mahoney Lake alternatives by 0.9 to 1.2 cents per kWh, respectively. [Table B-1] 5. Under all load forecast evaluations, net revenues to the State of Alaska from Tyee Lake sales over the Intertie would be negative. This is because the state would not make enough revenues from these sales to fully offset its annual debt service on the Intertie of $4.13 million. [Table C-3] Please call me if you have any questions about these findings or the attached materials. Sincerely, CH2M HILL David A. Gray Director of Energy Economics ANCILKB544.doc/ 991060004 Attachment A Economic/Resource Analysis of Power Supply Resource Alternatives at Ketchikan, Alaska’ 1. Under medium load forecast conditions: The least cost alternative is Mahoney Lake, if it can be built for $17.5 million. The cost of the Small Hydro (Whitman and Connell Lakes) alternative is nearly as low. Even with $17.4 million in Federal funding, the Intertie is $28.8 million more expensive than the Mahoney Lake estimate and $27.3 million more expensive than the Small Hydro alternative. Even if it were to take $28.8 million to build Mahoney Lake, the Intertie would be $18.2 million more expensive. The cost of the building Mahoney Lake and then the Intertie, when new generation is needed in 2011, is estimated to be $18.4 million higher than not adding new generation after Mahoney is complete. The Intertie with Federal funding is $15.6 million less expensive than the All Diesel alternative. One reason that the Mahoney Lake and Small Hydro alternatives are less expensive than the Intertie is that they do not require new diesel plants for reserve capacity. This is because they are not dependent upon the transmission line between Swan Lake and Ketchikan. The Intertie connects to this line at Swan Lake and as a result requires new diesel plants for reserve capacity. 2. Under the high load forecast, Mahoney Lake, augmented by small hydro when new resources are needed, is the least cost alternative. However, construction of Mahoney Lake followed by the Intertie is almost as inexpensive under this forecast. 3. Under the low load forecast, Small Hydro is the least cost alternative by a substantial margin. 4. Small Hydro provides staging opportunities that substantially reduce risk associated with uncertain future loads. 5. These conclusions are based on economic analysis of the resource costs associated with new generation for service to Ketchikan. They are supported by Table A-1 and Figures A-1 and A-2. These documents show the present value of new resources required” for each power supply alternative. ' This economic/resource analysis is based on the cost of resources for 2001 through 2027. ? Exceptions to this are shown for the Swan Lake transmission line. The new resource cost is the option entitled “Intertie (incremental)”. The Intertie (full cost) option includes costs that are already sunk in the project ($8.1 million). It therefore overstates new resource costs associated with the Intertie. The Intertie (incremental state cost) option is reduced by the amount of grant funds from the Federal government. As such, it considers resource costs only from the perspective of the State of Alaska. A-1 6. The medium, high, and low load forecasts that underlie this analysis are shown in Figure A-3 as the “Revised” forecasts. Also shown in this figure are load forecasts prepared by the Institute of Social and Economic Research (ISER) in 1998. The ISER forecasts serve as the foundation for the Revised forecasts. 7. Assumptions for this analysis are documented for the medium, high, and low load forecast cases in the pages that follow Table A-1 and Figures A-1 through A-3. High and low load forecast assumptions that vary from the medium forecast case assumptions are printed in bold. A-2 Assumptions (Medium Load Forecast) Load Forecast Based on ISER base (medium) load forecast for KPU (1998). Adjusted to include KPC sawmill load and marine layups (2 per year); adjustment adds 2.8 MW and 17,050 MWh/year. Resource Alternatives All Diesel: Assumes fuel cost of $.63/gal in 1998, $.58/gal in 1999, then increasing to $.66/gal in 2018. Replacement diesel (reserve) unit required in 2005; includes new powerhouse ($9 million in $1998). Intertie (full cost, including sunk costs): $73.2 million capital cost (total cost of $77.2 million less assumed revenue from timber sales of $4.0 million). Replacement diesel (reserve) unit required in 2005; includes new powerhouse ($9 million in $1998) to meet reserve requirements for the Swan Lake transmission line. Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. Zero incremental cost of Tyee output. Intertie (incremental cost): $73.2 million capital cost less $8.1 million expended (versus $11.2 million that has been appropriated) = $65.1 million. Replacement diesel (reserve) unit required in 2005; includes new powerhouse ($9 million in $1998) to meet reserve requirements for the Swan Lake transmission line. Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. Zero incremental cost of Tyee output. Intertie (incremental state cost): $65.1 million capital cost less $17.4 million federal grants = $47.7 million. Replacement diesel (reserve) unit required in 2005; includes new powerhouse ($9 million in $1998) to meet reserve requirements for the Swan Lake transmission line. Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. Zero incremental cost of Tyee output. A-3 ASSUMPTIONS — Medium Load Forecast (continued): Mahoney Lake: e $28.8 million (per 1998 Beck analysis) and $17.5 million (per KEC/HDR). e Capacity credit since connection is at Beaver Falls; no new diesel required. Mahoney Lake and Intertie: e Assumes Mahoney Lake constructed in 2001 and Intertie constructed in 2011. e Assumes $17.5 million capital cost. Small Hydro: e Assumes Whitman Lake (added in 2002) and Lake Connell (added in 2012). [Analysis indicates that Carlanna Lake could be substituted for Lake Connell; however, Lake Connell was used because a preliminary FERC license has been obtained for this project. Also, Lake Connell is capable of producing more energy than Carlanna Lake, which results in the displacement of more high-cost diesel generation, thereby reducing the overall cost of this scenario.] e Scenario involves continued reliance on diesel generation for a significant portion of KPU energy needs. e No new diesel required. Real Discount Rate: 3.0 percent Rate Impact Analysis e Capital financed at 5.5% over 30 years. e Mahoney Lake energy at proposed KEC rate of 6.5 cents/kWh; project would be subordinate to Swan Lake. e Existing KPU hydro and non-power supply costs escalate with inflation (3% per year). Assumptions (High Load Forecast) Load Forecast Based on ISER high load forecast for KPU (1998). Adjusted to include KPC sawmill and veneer plant loads plus marine layups (4 per year); adjustment adds 5.4 MW and 47,360 MWh/year. Resource Alternatives All Diesel: Assumes fuel cost of $.63/gal in 1998, $.58/gal in 1999, then increasing to $.66/gal in 2018. Replacement diesel (reserve) units required in 2002, 2006, and 2015; includes new powerhouse ($9 million in $1998). Diesel generation air emission regulatory and permitting requirements would increase the costs of this alternative beyond the level shown. Additional costs associated with increasing permitted operations would include professional services, capital improvements, and emissions monitoring. Diesel generation exceeds permitted levels in 2002. Intertie (full cost, including sunk costs): $73.2 million capital cost (total cost of $77.2 million less assumed revenue from timber sales of $4.0 million). Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. Zero incremental cost of Tyee output. Scenario involves continued reliance on diesel generation for a significant portion of KPU energy needs. Diesel generation air emission regulatory and permitting requirements would increase the costs of this alternative beyond the level shown. Additional costs associated with increasing permitted operations would include professional services, capital improvements, and emissions monitoring. Diesel generation exceeds permitted levels in 2017. Replacement diesel (reserve) units required in 2002, 2006, and 2015; includes new powerhouse ($9 million in $1998) to meet reserve requirements for the Swan Lake transmission line. Intertie (incremental cost): $73.2 million capital cost less $8.1 million expended (versus $11.2 million that has been appropriated) = $65.1 million. Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. Zero incremental cost of Tyee output. Scenario involves continued reliance on diesel generation for a significant portion of KPU energy needs. A-5 ASSUMPTIONS - High Load Forecast (continued): Diesel generation air emission regulatory and permitting requirements would increase the costs of this alternative beyond the level shown. Additional costs associated with increasing permitted operations would include professional services, capital improvements, and emissions monitoring. Diesel generation exceeds permitted levels in 2017. Replacement diesel (reserve) units required in 2002, 2006, and 2015; includes new powerhouse ($9 million in $1998) to meet reserve requirements for the Swan Lake transmission line. Intertie (incremental state cost): $65.1 million capital cost less $17.4 million federal grants = $47.7 million. Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. Zero incremental cost of Tyee output. Scenario involves continued reliance on diesel generation for a significant portion of KPU energy needs. Replacement diesel (reserve) units required in 2002, 2006, and 2015; includes new powerhouse ($9 million in $1998) to meet reserve requirements for the Swan Lake transmission line. Diesel generation air emission regulatory and permitting requirements would increase the costs of this alternative beyond the level shown. Additional costs associated with increasing permitted operations would include professional services, capital improvements, and emissions monitoring. Diesel generation exceeds permitted levels in 2017. Mahoney Lake: $28.8 million (per 1998 Beck analysis) and $17.5 million (per KEC/HDR). Capacity credit since connection is at Beaver Falls. Scenario involves continued reliance on diesel generation for a significant portion of KPU energy needs. Assumes small hydro (Whitman Lake, added in 2005, and Lake Connell, added in 2006), which results in a lower total cost than if diesel units were added. Diesel generation air emission regulatory and permitting requirements would increase the costs of this alternative beyond the level shown. Additional costs associated with increasing permitted operations would include professional services, capital improvements, and emissions monitoring. Diesel generation exceeds permitted levels in 2016. Mahoney Lake and Intertie: Assumes both Mahoney Lake and Intertie constructed in 2001. Assumes $17.5 million capital cost. A-6 ASSUMPTIONS - High Load Forecast (continued): Small Hydro: Assumes Whitman Lake (added in 2002) and Lake Connell (added in 2005). [Analysis indicates that Carlanna Lake could be substituted for Lake Connell; however, Lake Connell was used because a preliminary FERC license has been obtained for this project. Also, Lake Connell is capable of producing more energy than Carlanna Lake, which results in the displacement of more high-cost diesel generation, thereby reducing the overall cost of this scenario.] Scenario involves continued reliance on diesel generation for a significant portion of KPU energy needs. Replacement diesel (reserve) unit required in 2011; includes new power plant ($9 million in $1998). Diesel generation air emission regulatory and permitting requirements would increase the costs of this alternative beyond the level shown. Additional costs associated with increasing permitted operations would include professional services, capital improvements, and emissions monitoring. Diesel generation exceeds permitted levels in 2008. Real Discount Rate: 3.0 percent Rate Impact Analysis Capital financed at 5.5% over 30 years. Mahoney Lake energy at proposed KEC rate of 6.5 cents/kWh; project would be subordinate to Swan Lake. Existing KPU hydro and non-power supply costs escalate with inflation (3% per year). A-7 Assumptions (Low Load Forecast) Load Forecast e Based on ISER low load forecast for KPU (1998); no adjustments. Resource Alternatives All Diesel: e Assumes fuel cost of $.63/gal in 1998, $.58/gal in 1999, then increasing to $.66/gal in 2018. e No replacement diesel (reserve) units required. Intertie (full cost, including sunk costs): ¢ $73.2 million capital cost (total cost of $77.2 million less assumed revenue from timber sales of $4.0 million). e Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. e Zero incremental cost of Tyee output. e No replacement diesel (reserve) units required. Intertie (incremental cost): e $73.2 million capital cost less $8.1 million expended (versus $11.2 million that has been appropriated) = $65.1 million. e Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. e Zero incremental cost of Tyee output. e¢ No replacement diesel (reserve) units required. Intertie (incremental state cost): e $65.1 million capital cost less $17.4 million federal grants = $47.7 million. e Assumes Tyee energy availability equal to project capability of 134,400 MWh per year plus capability of Petersburg municipal hydro system (10,000 MWh per year), less projected energy requirements for Petersburg and Wrangell. e Zero incremental cost of Tyee output. e No replacement diesel (reserve) units required. Mahoney Lake: e $28.8 million (per 1998 Beck analysis) and $17.5 million (per KEC/HDR). e Capacity credit since connection is at Beaver Falls. e No replacement diesel (reserve) units required. Small Hydro: e Assumes Whitman Lake (added in 2002). e Noreplacement diesel (reserve) units required. Real Discount Rate: 3.0 percent A-8 ASSUMPTIONS - Low Load Forecast (continued): Rate Impact Analysis e Capital financed at 5.5% over 30 years. e Mahoney Lake energy at proposed KEC rate of 6.5 cents/kWh; project would be subordinate to Swan Lake. Existing KPU hydro and non-power supply costs escalate with inflation (3% per year). A-9 Attachment B Rate Impact Analysis of Power Supply Resource Options At Ketchikan, Alaska Under medium load forecast conditions: e The Intertie would increase Ketchikan Public Utilities (KPU) rates relative to other new power supply alternatives, including diesel generation, Mahoney Lake, and Small Hydro (Whitman Lake and Lake Connell). [Rate impacts of the Intertie were adjusted to reflect reductions in the Four Dam Pool wholesale power rate due to increased sales from Tyee Lake (affects both purchases from Tyee Lake and Swan Lake).] e The Small Hydro alternative would result in the lowest cost to KPU ratepayers. Under high load forecast conditions: e The Intertie would reduce KPU rates relative to diesel generation but increase rates relative to the Mahoney Lake and Small Hydro alternatives. e Mahoney Lake would result in the lowest cost to KPU ratepayers. Under low load forecast conditions: e The Intertie and Mahoney Lake alternatives would all increase rates relative to the All Diesel alternative. e The Small Hydro and All Diesel alternatives would result in about the same rates for KPU customers over the long term. These findings are based on the following key assumptions: e KPU would pay 6.8 cents per kWh (the Four Dam Pool wholesale power rate), plus full contributions to an Intertie R&R Fund , for power delivered over the Intertie. O&M associated with the Intertie would be paid for through the Four Dam Pool wholesale power rate as an additional O&M budget item. e Mahoney Lake power to meet requirements beyond those met by Swan Lake and existing KPU hydro would be available to KPU for 6.5 cents per kWh. e Small hydro would be built with tax-exempt financing. Rate projections (in nominal, or current year, prices) are shown in Tables B-1 through B-3. These table are based on medium, high, and low load forecasts, respectively. B-1 Attachment C Sensitivity Analysis of Power Supply Resource Options At Ketchikan, Alaska 1. How would the results of the economic/resource and rate impact analyses change with higher diesel fuel costs? A higher fuel price assumption benefits cases that do not rely on significant amounts of diesel generation, such as the Intertie and Mahoney Lake resource scenarios. The analyses summarized in Attachments A and B are based on an initial diesel fuel price of 63 cents per gallon (the average fuel price paid by KPU over the past 3 years). Results of an analysis based on a fuel price of 85 cents per gallon are shown in Table C-1. Under medium load forecast conditions, with the high fuel price assumption, the Intertie, Mahoney Lake, and Mahoney Lake/Intertie alternatives are the lowest cost resource plans. Under high load forecast conditions, with the high fuel price assumption, the Mahoney Lake/Intertie case is clearly the least cost alternative, followed by the Intertie and Mahoney Lake alternatives. Under low load forecast conditions, with the high fuel price assumption, Small Hydro/Diesel remains the least cost resource plan, followed by the Mahoney Lake and Intertie cases. With the high fuel price assumption, results of the rate impact analysis would show an increased benefit (in terms of reduced KPU rates relative to the All Diesel scenario) for all alternatives examined. However, the relative differences in rate impacts among the alternatives (Intertie, Mahoney Lake, and Small Hydro) would be unchanged; i.e., each case would be reduced by approximately the same amount (0.3 to 0.5 cents per kWh under medium load forecast conditions). 2. What is the impact of the sale of Tyee power over the Intertie on the Four Dam Pool wholesale power rate? This analysis assumed that Tyee sales to KPU would be based on the existing debt service component (4 cents per kWh) of the Four Dam Pool wholesale power rate®. 3 The Four Dam Pool Power Sales Agreement provides for a reduced debt service component (3 cents per kWh) on all sales above the contracted forecast amounts. For this analysis, however, the existing debt service component of 4 cents per kWh was used to allow the State to more fully recover debt service costs associated with the Intertie. C-1 With increased sales of Tyee power, however, the O&M component of the Four Dam Pool wholesale power rate would change. On the one hand, the overall O&M amount to be paid would increase with the added O&M cost for the Intertie*. On the other hand, this increase would be more than offset by the effect of increased sales of Tyee power over the Intertie. Total O&M costs (including those for the Intertie) would be divided by a greater number of kilowatt-hours than would be the case without the Intertie. This would result in a net decrease in the overall O&M rate for Four Dam Pool power as shown in Table C-2. This shows the change in the projected Four Dam Pool wholesale power rates under medium and high load forecast conditions. The first 10 years of Intertie operation would result in reductions of the Four Dam Pool rate ranging from 0.2 to 0.4 cents per kWh. These reductions were incorporated into the rate impact analysis shown in Tables B-1 through B-3. 3. What are the projected revenues to the State of Alaska for the Intertie and Mahoney Lake/Intertie cases? Gross revenues represent a payment of 4 cents per kWh on all Tyee Lake sales delivered over the Intertie (based on the assumption that Tyee sales to KPU would include the full debt service component of the current Four Dam Pool wholesale power rate). If the State builds the Intertie, net revenues would equal gross revenues minus debt service (assuming levelized $4.13 million in annual debt service costs). Results are shown for the Intertie and Mahoney Lake/Intertie cases in Tables C-3 and C-4, respectively. For the Intertie scenario, net revenues to the state would be negative for the 25 years during which the state is paying debt service on the Intertie. Similarly, for the Mahoney Lake/Intertie scenario, net revenues to the state would be negative for the 25 year repayment period. However, since less Tyee energy would be required under this scenario due to the availability of output from the Mahoney Lake project, the net loss to the state during the first 25 years would be higher than if only the Intertie were built. Under low load forecast conditions, all of KPU’s energy requirements during the forecast period would be met by existing hydro, Swan Lake, and the Mahoney Lake project. Since no Tyee energy would be utilized, the Intertie would not be needed. 4. What if the Metlakatla Interconnection were constructed? Estimates contained in the 1998 update to KPU’s Power Supply Planning Study (prepared by R.W. Beck) indicate that about 10,200 MWh of hydroelectric energy and as much as 37,600 MWh of diesel energy could be made available annually via interconnection with Metlakatla Power & Light (MP&L). MP&L’s diesel units could ‘ The analysis assumes that the incremental cost of Tyee Lake output is zero. C-2 also provide reserve capacity to KPU. An additional 3 MW of capacity (14,8300 MWh per year) could be installed at the Chester Lake hydro project’. The Beck analysis found that the Metlakatla interconnection was similar to that of the Small Hydro alternative, assuming that KPU would pay costs associated with the interconnection with MP&L and the upgrade to the Chester Lake powerhouse plus 2 cents per kWh for power purchased from MP&L’s existing hydro resources. The MP&L interconnection would therefore be one of the lowest cost resource alternatives under all three load growth scenarios. > Other hydroelectric projects, such as Tamgas Lake and Triangle Lake, would increase the amount of energy available from MP&L. These projects were not considered in the 1998 update to the Power Supply Planning Study. C-3 Attachment D Sources of Information 1. Load Forecasts: KPU: Base Adjustments (see “Assumptions”) Other Four Dam Pool participants: 2. Diesel Fuel Cost ($.63/gallon): 3. Generation Resource Alternatives: Diesel unit costs and operating assumptions Small hydro unit costs and operating assumptions Mahoney Lake capital cost ($28.8 million), O&M, and operating assumptions Alternative Mahoney Lake project capital cost ($17.5 million) Electric Load Growth Study (prepared for KPU by ISER, June 1998). Per discussions and correspondence with KPU staff (R. Trimble). Electric Load Forecast for Ketchikan, Metlakatla, Petersburg, and Wrangell, Alaska: 1990-2010 (prepared for AEA by ISER, June 1990). KPU 1998 Avoided Cost Documentation (prepared by R.W. Beck, November 1998); represents average of Bailey fuel purchases (1997-1999) per KPU records. 1998 Update to the Power Supply Planning Study (prepared for KPU by R.W. Beck, February 1998). 1998 Update to the Power Supply Planning Study (prepared for KPU by R.W. Beck, February 1998). 1998 Update to the Power Supply Planning Study (prepared for KPU by R.W. Beck, February 1998). Per KEC (attachment to memo from John Magyar to the Ketchikan City Council, March 4, 1998). D-1 4. Intertie Cost and Operating Data: Total cost ($77.2 million) Net cost ($73.2 million) “Sunk” costs ($8.1 million) Federal funds ($17.4 million) Four Dam Pool wholesale power rate (before Tyee sales to KPU) Tyee capability (134,400 MWh) Petersburg municipal hydro capability (10,000 MWh) Projected Tyee sales to KPU Memo from Pat Clancy to AIDEA, March 11, 1999. Draft SE Intertie Review, March 23, 1999. Memo from Rich Trimble (KPU) to AIDEA, September 18, 1998. Memo from John Magyar (KPU) to Ketchikan City Council, September 25, 1998. Historical data per KPU; projected data based on the methodology outlined in the Four Dam Pool Power Sales Agreement. 1998 Update to the Power Supply Planning Study (prepared for KPU by R.W. Beck, February 1998). 1998 Update to the Power Supply Planning Study (prepared for KPU by R.W. Beck, February 1998). Developed using R.W. Beck resource model. D-2 Table A-1 Swan/Tyee Intertie Analysis Summary of Results (Incremental Analysis) 7 Present Value of Costs ($ millions) Medium High Low Forecast Forecast Forecast Resource: All Diesel 84.7 207.3 17.6 Intertie (full cost) 91.1 176.8 67.8 Intertie (incremental cost) 84.6 170.3 61.3 Intertie (incremental state cost) 69.1 154.8 45.8 Mahoney Lake ($17.5 million)” 40.3 116.9 29.1 Mahoney Lake ($28.8 million) 50.9 129.2 39.7 Mahoney Lake ($17.5 million) and Intertie (state) 58.7 119.4 NA Small Hydro 41.8 170.4 9.7 Index (All Diesel = 100) Medium High Low Forecast Forecast Forecast Resource: All Diesel 100 100 100 Intertie (full cost) 108 85 385 Intertie (incremental cost) 100 82 348 Intertie (incremental state cost) 82 a5 260 Mahoney Lake ($17.5 million)” 48 56 166 Mahoney Lake ($28.8 million) 60 62 225 Mahoney Lake ($17.5 million) and Intertie (state)° 69 58 NA Small Hydro 49 82 55 Notes: 1 Costs evaluated are for years 2001 through 2027. These costs exclude those associated with Swan Lake, existing diesel units, and existing KPU hydro. 2 For high forecast ONLY, includes small hydro (Whitman and Connell Lakes) instead of new diesel units when new resources are required. 3 Under medium load forecast, construction of the Intertie is delayed until 2011. Under the high forecast, both Mahoney lake and the Intertie are constructed in 2001. Under the low forecast, the Intertie is not needed. 180 160 ) — aS oO 120 Present Value ($ Millions Figure A-1 Mahoney Lake vs. Intertie Low Medium High © Mahoney Lake ($17.5 Million) 3 Intertie ($47.7 Million) Present Value ($ Millions) Figure A-2 Small Hydro vs. Intertie 180 160 sil aS oO — So Oo © So | a oO i oO | 20 + Medium High [Small Hydro i Intertie ($47.7 Million) Figure A-3 KPU Load Forecasts t L107 r SIOZ r £107 r [107 6007 TTT L007 r S007 t £007 f 1007 r 6661 r LO6T | S661 f £661 r [661 | 6861 5 T S Wy N + T T S S S S wo So N — — YAY JO SUOTTETAL 50 5 Revised - = = Original Table B-1 Rate Impact Analysis Medium Load Forecast Average — Power Supply Retail Rate Cost Under Under Do-Nothing Do-Nothing Alternative Alternative Estimated Rate Impacts (cents/kWh) 4 Year (cents/kWh) : (cents/kWh) Intertie * Mahoney 4 small Hydro 1998 9.2 4.7 - - - 1999 9.4 4.8 - - - 2000 9.6 4.8 - = : 2001 9.8 4.9 0.1 0.1 - 2002 10.0 5.0 0.1 0.1 (0.2) 2003 10.2 5.0 0.1 0.1 (0.2) 2004 10.4 Sel 0.1 0.1 (0.2) 2005 11.6 6.1 0.1 (0.9) (1:2) 2006 11.8 6.2 0.1 (0.9) (1.2) 2007 12.0 6.2 0.1 (0.9) (1.2) 2008 12.3 6.3 0.1 (0.9) (1.2) 2009 12.5 6.3 0.2 (0.9) (1.2) 2010 12.7 6.4 0.2 (0.9) (1-2) 2011 13.0 6.4 0.2 (0.9) (1.2) 2012 13.2 6.5 0.2 (0.9) (1.2) 2017 14.6 6.8 0.3 (1.0) (1.2) 2022 15.9 6.8 (0.0) (1.2) (1.2) 2027 17.4 6.8 (0.0) (1.2) (1.2) Levelized 12.8 6.1 0.1 (0.8) (1.1) Notes: 1 Represents All-Diesel case; capital financed at 5.5% over 20 years. Assumes 3 percent general inflation rate. Relative to All-Diesel case. At Four Dam Pool rate plus renewals and replacements. KEC proposal (6.5 cents/kWh), subordinate to Swan Lake. Assumes capital cost financed at 5.5% over 30 years. nk WN Year 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2017 2022 2027 Levelized Notes: Table B-2 Rate Impact Analysis High Load Forecast Average — Power Supply Retail Rate Under Cost Under Do-Nothing Do-Nothing Alternative Alternative Estimated Rate Impacts (cents/kWh) (cents/kWh) : (cents/kWh) Intertie ° Mahoney * small Hydro 3 9.2 4.7 - - - 9.4 4.8 - - - 9.6 4.9 - - - 9.8 4.9 (0.2) (0.0) - 10.7 537 (0.4) (1.1) (1.0) 10.9 5.7 (0.4) (1.1) (0.9) 11.1 5.8 (0.2) (1.1) (0.9) 11.3 5.8 (0.2) (1.1) (1.0) 11.8 6.1 (0.3) (1.4) (1.3) 12.0 6.2 (0.3) (1.4) (0.6) 12.2 6.2 (0.2) (1.4) (0.6) 12.4 6.2 (0.2) (1.4) (0.6) 12.6 6.3 (0.2) (1.3) (0.6) 12.8 6.3 (0.1) (1.3) (0.6) 13.1 6.3 (0.1) (1.3) (0.6) 14.5 6.7 (0.0) (1.5) (0.5) 15.8 6.7 (0.3) (1.7) (0.5) 17.3 6.7 (0.3) (1.7) (0.5) 13.0 6.1 (0.2) (1.4) (0.6) Represents All-Diesel case; capital financed at 5.5% over 20 years. Assumes 3 percent general inflation rate. Relative to All-Diesel case. At Four Dam Pool rate plus renewals and replacements. KEC proposal (6.5 cents/kWh), subordinate to Swan Lake, plus costs associated with small hydro. Assumes capital cost financed at 5.5% over 30 years. Table B-3 Rate Impact Analysis Low Load Forecast Average — Power Supply Retail Rate Cost Under Under Do-Nothing Do-Nothing Alternative Alternative Estimated Rate Impacts (cents/kWh) 2 Year (cents/kWh) ; (cents/kWh) Intertie * Mahoney * small Hydro 7 1998 9.2 4.7 - - - 1999 9.3 4.7 - - - 2000 9.5 4.8 - - - 2001 9.7 49 0.0 0.0 - 2002 10.0 49 0.0 0.0 0.3 2003 10.2 5.0 0.0 0.0 0.3 2004 10.4 5.1 0.1 0.0 0.3 2005 10.6 5:1 0.1 0.0 0.2 2006 10.9 5.2 0.1 0.0 0.2 2007 11.1 5.3 0.1 0.0 0.1 2008 11.4 5.4 0.1 0.0 0.1 2009 LT 55 0.2 0.0 0.0 2010 11.9 5.6 0.2 0.0 0.0 2011 12.2 5.7 0.2 0.0 (0.0) 2012 12.5 5.8 0.2 0.0 (0.1) 2017 14.3 6.5 0.4 0.0 (0.2) 2022 15.6 6.6 0.3 (0.1) (0.3) 2027 17.1 6.6 0.3 (0.1) (0.3) Levelized 12.3 5.7 0.2 (0.0) (0.0) Notes: 1 Represents All-Diesel case; capital financed at 5.5% over 20 years. Assumes 3 percent general inflation rate. 2 Relative to All-Diesel case. 3 At Four Dam Pool rate plus renewals and replacements. + KEC proposal (6.5 cents/kWh), subordinate to Swan Lake, plus costs associated 5 Assumes capital cost financed at 5.5% over 30 years. Table C-1 Results of Fuel Price Sensitivity Analysis Present Value of Change in PV Revised Cost Assuming Due to Incremental Revised Load Base Fuel Prices Index High Fuel Costs Present Value Index Forecast Resource Scenario ($millions) (All-Diesel=100) —($millions) ($millions) (All-Diesel=100) Medium: Base (All-Diesel) 84.7 100 179.3 264.0 100 Intertie | 69.1 82 12.2 81.3 31 Mahoney Lake ” 40.3 48 40.5 80.8 31 Small Hydro ? 41.8 49 95.8 137.6 52 Mahoney + Intertie 58.7 69 12:2 70.9 2p High: Base (All-Diesel) 207.3 100 463.2 670.5 100 Intertie | 154.8 75 189.0 343.8 51 Mahoney Lake * 116.9 56 233.4 350.3 52 Small Hydro 7 170.4 82 373.9 544.3 81 Mahoney + Intertie 119.4 58 89.4 208.8 31 Low: Base (All-Diesel) 17.6 100 53.9 71.5 100 Intertie | 45.8 260 5.4 51.2 72 Mahoney Lake 7 29.1 166 5.4 34.5 48 Small Hydro ° 9.7 55 6.1 15.8 22 Notes: 1 Incremental state cost. 2 $17.5 million capital cost. 3 Whitman and Connell Lake projects. 4 Mahoney Lake augmented by small hydro when needed. 5 Whitman Lake project. Due to Tyee Lake Sales Over Intertie Table C-2 Change in Four Dam Pool Rate Reduction in O&M Component of Wholesale Power Rate (cents/kWh) Medium Load Forecast High Load Forecast Due to Add: Due to Add: Increased Intertie Net Increased Intertie Net Tyee Sales' O&M* Change Tyee Sales' O&M _ Change 1998 - - - - - - 1999 - - - - - - 2000 - - - - - - 2001 -0.21 0.04 -0.17 -0.36 0.03 -0.32 2002 -0.24 0.04 -0.19 -0.38 0.03 -0.35 2003 -0.26 0.05 -0.21 -0.40 0.03 -0.37 2004 -0.27 0.05 -0.23 -0.43 0.03 -0.39 2005 -0.29 0.05 -0.25 -0.44 0.03 -0.40 2006 -0.31 0.05 -0.27 -0.44 0.03 -0.41 2007 -0.33 0.05 -0.28 -0.44 0.04 -0.41 2008 -0.36 0.05 -0.31 -0.44 0.04 -0.41 2009 -0.38 0.05 -0.33 -0.45 0.04 -0.41 2010 -0.40 0.05 -0.35 -0.45 0.04 -0.41 2011 -0.42 0.05 -0.37 -0.45 0.04 -0.41 2012 -0.45 0.05 -0.39 -0.45 0.04 -0.41 2013 -0.48 0.05 -0.42 -0.44 0.04 -0.40 2014 -0.50 0.06 -0.45 -0.44 0.04 -0.40 2015 -0.53 0.06 -0.48 -0.43 0.04 -0.39 2016 -0.56 0.06 -0.51 -0.43 0.04 -0.39 2017 -0.60 0.06 -0.54 -0.42 0.04 -0.38 2022 -0.63 0.07 -0.56 -0.42 0.05 -0.37 2027 -0.63 0.08 -0.55 -0.42 0.06 -0.36 Notes: 1 Four Dam Pool O&M cost assumed to be constant in real terms. Reduction in unit cost results from dividing by larger number of kWh. 2 O&M for the Intertie is estimated to be $126,000 ($1998). Cost is spread over all Four Dam Pool sales, including sales of Tyee power to KPU. Table C-3 Revenues to the State of Alaska From Tyee Sales to KPU (via the Intertie) (Intertie Scenario) t Thousands of Dollars Gross Revenues ” Net Revenues ; Low Medium High Low Medium High Forecast Forecast Forecast Forecast Forecast Forecast 1998 - - - - - - 1999 - - - - - - 2000 - - - - - - 2001 179 1,029 2,578 (3,951) (3,101) (1,552) 2002 190 1,118 2,770 (3,940) (3,012) (1,360) 2003 207 1,180 2,952 (3,923) (2,950) (1,178) 2004 245 1,244 3,125 (3,885) (2,886) (1,005) 2005 282 1,304 3,298 (3,848) (2,826) (832) 2006 324 1,369 3,419 (3,806) (2,761) (711) 2007 374 1,431 3,376 (3,756) (2,699) (754) 2008 405 1,498 3,330 (3,725) (2,632) (800) 2009 433 1,562 3,285 (3,697) (2,568) (845) 2010 464 1,631 3,243 (3,666) (2,499) (887) 2011 496 1,697 3,204 (3,634) (2,433) (926) 2012 527 1,763 3,165 (3,603) (2,367) (965) 2013 556 1,839 3,124 (3,574) (2,291) (1,006) 2014 588 1,920 3,080 (3,542) (2,210) (1,050) 2015 620 2,001 3,035 (3,510) (2,129) (1,095) 2016 653 2,084 2,989 (3,477) (2,046) (1,141) 2017 682 2,168 2,942 (3,448) (1,962) (1,188) 2022 715 2,252 2,894 (3,415) (1,878) (1,236) 2027 715 2,252 2,894 715 2,252 2,894 1998 Present Value: (37,472) (25,132) (10,047) Notes: 1 Assumes Intertie constructed in 2001. 2 Assumes KPU payment to the state of 4 cents per kWh on all purchases from the Tyee Lake project. 3 Gross revenues less levelized debt service cost to the state (assumed to be $4.13 million per year). Represents unrecovered debt service payments. Table C-4 Revenues to the State of Alaska From Tyee Sales to KPU (via the Intertie) (Mahoney Lake/Intertie Scenario) Thousands of Dollars Gross Revenues’ Net Revenues” Medium High Medium High Forecast’ Forecast * Forecast * Forecast * 1998 - - - - 1999 - - - - 2000 - - - - 2001 - 925 - (3,205) 2002 - 1,117 - (3,013) 2003 - 1,299 - (2,831) 2004 - 1,472 - (2,658) 2005 - 1,645 - (2,485) 2006 - 1,822 - (2,308) 2007 - 2,004 - (2,126) 2008 - 2,191 - (1,939) 2009 - 2,382 - (1,748) 2010 - 2,579 - (1,551) 2011 44 2,781 (4,086) (1,349) 2012 110 2,988 (4,020) (1,142) 2013 186 3,124 (3,944) (1,006) 2014 267 3,080 (3,863) (1,050) 2015 348 3,035 (3,782) (1,095) 2016 431 2,989 (3,699) (1,141) 2017 515 2,942 (3,615) (1,188) 2022 599 2,894 (3,531) (1,236) 2027 599 2,894 (36,571) * 2,894 1998 Present Value: (20,785) (19,191) Notes: 1 Assumes KPU payment to the state of 4 cents per kWh on all purchases from the Tyee Lake project. 2 Gross revenues less levelized debt service cost to the state (assumed to be $4.13 million per year). Represents unrecovered debt service payments. 3 Assumes construction of Mahoney Lake in 2001 and the Intertie in 2011. Assumes both Mahoney Lake and the Intertie constructed in 2001. 5 Assumes balloon payment made in 2027 for remaining debt service costs (under medium load forecast only). > EXHIBIT 2 Financial Counsel to Governments, Non-Profits & Public Private Ventures CLANCY, GARDINER, & PIERCE,Lic March 31, 1999 Keith Laufer Alaska Industrial Development and Export Authority 480 West Tudor Anchorage, Alaska 99503 Dear Keith: Pursuant to your request, we have analyzed the various financing issues surrounding a proposal being advanced by Ketchikan Public Utilities (KPU) for the Southeast Intertie (the “Intertie”). KPU has asked the State to consider issuing revenue bonds to fund approximately $45 million of costs relating to construction of the Intertie. KPU’s proposal is to use 40% of the State’s Four Dam Pool income stream to provide a revenue stream with which to pay debt service on the bonds. The Southeast Intertie has been the subject of considerable study and discussion over the past decade. The Intertie would link the Tyee hydroelectric project (a part of the Four Dam Pool) to the Ketchikan area. The proposed funding package is as follows: Funding Available: State Grants Authorized/Received 11,200,000 Fed. Grants Authorized/Received 9,900,000 Timber Sale Credit 4,000,000 25,100,000 Additional Funding Proposed: Additional Proposed Federal Grants 7,500,000 Proposed State Bond Proceeds 44,600,000 52,100,000 Total Estimated Intertie Cost (As of 9/98 in 1997 dollars) $77,200,000 In order to have approximately $44,600,000 in bond proceeds available for Intertie construction costs, we estimate that approximately $51,300,000 in revenue bonds would need to be issued. The increased bond size is needed to provide proceeds for bond issuance costs and to fund a debt service reserve fund. Although the amounts could vary, for this purpose we have assumed that issuance costs will amount to approximately 3% of the principal of the bonds and that a debt service reserve fund equal to approximately 10% of the bond principal would be required. Since, under KPU’s proposal, completion of construction is not required to produce the revenue stream required for payment of the bonds, we have assumed that no provision for capitalized interest would be required. 115 NW First Avenue, Suite 401 Portland, Oregon 97209 Phone: 503.221.1126 Fax: 503.221.1560 SE Intertie Financing Page 2 As you know we believe the State should ordinarily not issue bonds unless those bonds are “investment grade.” If the Intertie bonds could be structured to be investment grade, we assume the interest rates on the bonds would be approximately 7%. These rates assume that the project would not qualify for tax exempt financing. We have also assumed the bonds would be amortized over a 25-year term. Based upon these assumptions, we estimate that the annual debt service on the bonds would be approximately $4.38 million. After taking into account the projected earnings on the debt service reserve fund, we estimate the annual net debt service for the bonds would be approximately $4.13 million. Investment grade revenue bond financing requires a predictable stream of revenue to repay the bonds over time. However, there is currently no revenue stream that has been earmarked to pay debt service on such bonds and the Intertie will not generate significant new revenue. Therefore the first task toward issuing bonds would be to identify a viable revenue stream for debt service payments. The State receives “debt service” payments from the Four Dam Pool participants. Subject to annual appropriation, these State payments are currently allocated: 40% to the Power Cost Equalization and Rural Electric Capitalization Fund, 40% to the Southeast Energy Fund and 20% to the Power Project Fund. KPU has proposed that the 40% of these funds currently being allocated to the Southeast Energy Fund be utilized to pay for the debt service on the proposed bonds. Because the State’s Four Dam Pool revenue stream is subject to annual appropriation, that revenue stream would not be sufficiently predictable and stable for the issuance of bonds. Presumably statutory changes could be made to remedy this deficiency. The total State “debt service payment” (before self help) for fiscal year 1999 was $10.8 million. A diversion of 40% of the current “debt service” payment would result in $4,320,000 per year potentially available for repayment of the proposed bonds. This would provide a baseline payment source for the bonds of 1.05 times the projected bond payments. While the State’s revenue stream is projected to grow over time and potentially increase debt service coverage, this level of base line coverage would probably be insufficient to support investment grade bonds. Additionally, the State’s debt service payments are subject to significant fluctuation based on Four Dam Pool energy production and sales and the payments are subject to interruption under certain conditions described in the Four Dam Pool power sales agreement (commonly referred to as “self help”). Each of these conditions make it more unlikely that the coverage provided by a pledge of 40% of the State’s payment would be sufficient to structure a viable investment grade bond issue. These two difficulties could be remedied by making structural changes to ensure State payments sufficient to pay debt service regardless of energy production and revenue interruptions created by the exercise of self-help. One option for addressing the revenue fluctuation and coverage problems would be to pledge the State’s entire Four Dam Pool revenue stream toward the bonds. Once the bond payment was made the remainder of the State revenues could be released for other purposes. This approach would create the potential of reducing the amount of Four Dam Pool revenues available for the other allocated uses. Using the State’s fiscal year 1999 revenues (before self-help) of $10.8 million would result in bond debt service coverage in excess of 2.6 times. This level of coverage, in normal circumstances and with normal reserves, should lead to an investment grade bond issue. However, the potential of self-help creates a second hurdle. SE Intertie Financing Page 3 Self-help is a unique ability of the Four Dam Pool purchasing utilities to interrupt the State debt service payments to obtain funds for certain State obligations for costs associated with the projects. Over the last several years self-help has been utilized to meet the State’s obligations for major repair of the project. In fiscal year 1999 alone, the State’s $10.8 million debt service payment was reduced by $5.5 million for self-help resulting in a net payment to the State of only $5.3 million. To avoid the possibility of self-help interrupting bond payments, it might be possible to amend the Four Dam Pool power sales agreement to limit the utilities’ ability to invoke self-help. In the last several years, however, self-help funds have been the only source of funds available to make major repairs to the Four Dam Pool projects. Restrictions on the availability of self-help funds could impede AEA’s ability to fulfill its obligations and the State would have to meet those obligations using other unidentified funds. Both of the structural changes described above would need to be designed to contractually guarantee sufficient revenues to the State so that debt service payments could be made. Assuming such changes were made, the State could contractually commit those payments to debt service on the bonds. Another approach to the financing would be to divert only 40% of the revenue stream toward the bonds without modifying the power sales agreement or pledging the entire revenue stream. In this case, any deficiency in the revenues available to pay debt service would need to be guaranteed by a sufficiently creditworthy entity. Ketchikan Public Utilities might be considered the most appropriate entity but may lack the financial strength to make a guarantee on $51.3 million meaningful. Another option might be to back the debt service payments by a “general obligation” pledge of all of the Four Dam Pool participants. The value of any guarantee is dependent on the guarantor’s ability to make good on the guarantee in the event that the revenue stream failed to materialize. In summary, a reliable revenue stream for repayment of the financing needs to be developed. Forty percent of the current debt service paid by the Four Dam Pool is not sufficient to structure an investment grade bond issue. While it might be possible to modify the existing structure to create a sufficient revenue stream by pledging all the debt service payment and limiting self-help provisions, this solution seems unlikely and presents other problems. In the absence of changes to the existing structure the bond debt service would need to be guaranteed by a creditworthy entity. Finally, before issuing bonds, a plan would need to be developed to securely fund the operating, maintenance, and renewal and replacement costs for the Intertie, and to cover any other known Intertie risks. Please feel free to contact me if you have any questions regarding this analysis. , Gardiner & Pierce, LLC Patrick H. Clancy