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HomeMy WebLinkAboutS Intertie EIS 1997ALDEr CHUGACH ELECTRIC ASSOCIATION, INC. Dog Renns was Cok 2) ¥ OZ Dd 3) Shee < September 5, 1997 Alaska Electric Generation & Alaska Transmission Cooperative, Inc. 1018 Galena Street Fairbanks, Alaska 99709 Attention: Mr. Robert Hufman, Executive Manager Subject: Southern Intertie - EIS Process DFI Economic Feasibility Study Update Dear Mr. Hufman: Enclosed is the final report "Review and Update of Economic Feasibility of Southern Intertie Projects", dated August 1997 and prepared by Decision Focus, Inc., (DFI). Comments provided during the review period of the draft have been incorporated. We have also asked PEI/DFI to prepare a scope of work and estimate of the costs for adding updates on planned system improvements, such as BESS and SMES, as well as actual system operations with the Bradley Hydro Project on Line. Their proposal for $89,487 is included for your review and comment. We would like to discuss DFI's added work at the September 22, 1997 IPG meeting and will ask for approval to add this work to the present agreement. If you have any questions, please call me or our Project Manager, Dora Gropp, at (907) 762-4626. Sincerely, General Manager ENG/dlg:ahw Enclosure: "Review and Update to Economic Feasibility of Southern Intertie Project". c Lee Thibert Joe Griffith Mike Massin Jim Borden ij IPG Technical Committee W.0.#£959008 1, Sec., 2.1.2.1 RF 5601 Minnesota Drive » P.O. Box 196300 »* Anchorage, Alaska 99519-6300 Phone 907-563-7494 * FAX 907-562-0027 Southern Intertie Route Selection Study - Phase 1B W.0.#E9590081 Subject: DFI Economic Feasibility Study Update Preceding letter from Chugach sent to IPG Utility General Managers and to AIDEA as follows: Alaska Electric Generation & Transmission Cooperative, Inc. Attention: Mr. Robert Hufman 1018 Galena Street Fairbanks, Alaska 99709 c: Mike Yerkes Alaska Industrial Development & Export Authority Attention: Mr. Randy Simmons, Executive Director 480 West Tudor Road Anchorage, Alaska 99503 Ce Dennis McCrohan Anchorage Municipal Light and Power Attention: Mr. Hank Nikkels, Acting General Manager 1200 East First Avenue Anchorage, Alaska 99501 Cc: Tim McConnell City of Seward, Light and Power Division Attention: Mr. Dave Calvert, Utility Manager P.O. Box 167 Seward, Alaska 99664 Fairbanks Municipal Utilities System Attention: Mr. Frank Biondi, General Manager P.O. Box 72215 Fairbanks, Alaska 99707 Golden Valley Electric Association, Inc. Attention: Mr. Michael Kelly, General Manager P.O. Box 71249 Fairbanks, Alaska 99707 ce Mr. Steve Haagenson Homer Electric Association, Inc. Attention: Mr. Norm Story, General Manager 3977 Lake Street Homer, Alaska 99603 Cs Mr. Don Stead Matanuska Electric Association, Inc. Attention: Mr. Wayne Carmony, General Manager P.O. Box 2929 Palmer, Alaska 99645 Cc: Jim Hall HADATAUNNALISAWEDOCSE999008 MAILTECH.GM Setpember 5, 1997 Review and Update of _ Economic Feasibility of Southern Intertie Project Prepared by: Stephen Haas Annette Hulse Decision Focus Incorporated 650 Castro Street, Suite 300 Mountain View, California 94041-2055 (415) 960-3450 Prepared for: Power Engineers Incorporated 3940 Glenbrook Drive Hailey, ID 83333 August 1997 7 . e 1.0 2.0 3.0 | 1.4 Additional Analysis ....cmscmenenesees TABLE OF CONTENTS Page Introduction and Summary ...ssssosseseesennesesssessnecsnnsessersesssseessnnereesenssssseneesenneecens L 1.1 Backgrounnd......s.sesececsesssseessensesesenssssssneessssssessssnseeessnncssanecssnecsensecennesnsseessavecceneees L 1.2 Updated Benefits Estimates ..nwmsennnnnnsnsnnetnnnsennseeenen a1 1.3 Benefits Estimation Methodology .wwsssesesemennenenmssetetetetetntntntnesentntnteeens 2.1 Capacity Sharing...........sssecsssssssssnssessssessssnsseecesnseessnnesenscssensescnsecenessanessessnseseans 2.2 Economy Energy Tramsfer..........cccsvessccseesssseseee Updates of Key Data Items.........sssssssssssssnssscesaseessrsnsssennesseneessenssenssesencnanesessnsseenness 6 3.2 Discount Rate..........ssscssssessssossnseesssennsesssnssenssssssenensnesssenunesessaneccesenecsssaneessccssesees 7 3.3 3.4 Generating Capacity: Planned Additions and Retirements......-....-s-ss+ 9 3.5 Cost of New Combustion Turbinne..........csssssccsesssssversseesssssecsenecsavercesnecsrnnesene D 3.6 Fuel Prices .....sssssscsonnesesnsseeccennsseeessnnsesecsnnsnnnecsessnnueessenssssscsncsssennnsssnssacssessssneeese 9 3.7 ——_ Level of Customer Outages.........svesessmsssssneseesnssescnnsesnnsecssscceneseenseccensnsstee otk d 3.8 Value of a Customer Outtage.......ccosessssesessssseesssnecssneesnsseesnseessnecsnnsessssneesenee 11 Decision Focus Incorporated - Confidential i R2947— LIST OF TABLES Table Page 1 Net Present Value of Benefits of Proposed SIP she ee ie aoe 2 2 Comparison of Peak Demand Forecasts for 2010 (MW)).......scssssscssvssssesenssseessssnsosesessee 8 3 Comparison of 1997 Fuel Price Forecast with Actual Prices ccsscssssssseeseeseenes 10 4 Comparison of Fuel Price Forecasts for 2010 Made in 1989 with those Made in 1997 ..-svvsssecsessssssecsecsssesseesessessesssssseseeerseoreennensnenscene 10) Decision Focus Incorporated - Corifidential ii 1.0 Introduction and Summary 1.1 Background In 1989 Decision Focus Incorporated (DF) carried out an economic analysis of the benefits of several proposed transmission line upgrades or additions in the Railbelt area of Alaska. The results of the analysis were documented in a December 1989 report entitled “Economic Feasibility of the Proposed 138 KV Transmission Lines in the Railbelt”. One of the lines studied in the 1989 analysis, the Southern Intertie Project (SIP) between Anchorage and Kenai, is currently under serious consideration, and an environmental impact statement (EIS) is being prepared for the proposed project. Because DFI’s 1989 analysis helped to justify the project, it is desirable to review that analysis to determine whether any changes have occurred in the years since 1989 that would alter the conclusions of the analysis. The December 1989 report estimated benefits of new transmission lines in six different categories: capacity sharing economy energy transfer transmission losses operating reserve sharing state revenue from gas royalty and severance taxes A PEVe The current review and update, described in this report, concentrates on the first three categories, which accounted for about 90 per cent of the total benefits in the 1989 study. The update focused on the key data values underlying the estimates, determined how these data values have changed, and calculated the impacts on the benefits estimates. In addition, all benefit estimates were converted to 1997 dollars for easy comparison to current cost estimates of the proposed line. 1.2 Updated Benefits Estimates | Table 1 summarizes the conclusions of the update. The dollar values shown are the net present value of benefits in each category over the expected 40-year life of the new transmission line. In 1989 the line was expected to come into operation in 1994, so the 1989 benefits values are for the period 1994-2033; the line is now planned to come into operation January 1, 2004, so the benefits values are for the period 2004-2043. The 1989 study calculated all present values in 1994, the year the line was expected to come into operation. Here we display the present values for 2004, the year the line is now expected to come into operation. Decision Focus Incorporated - Corifidential —_—————_@____—__o———_; Table 1 Net Present Value of Benefits of Proposed SIP * in 1994 for 1989 study, and in 2004 for current update. The new total benefits estimate is substantial, but is lower than for the 1989 study, when expressed in the same year dollars, due primarily to lower forecasts of fuel prices and a lower cost of new generating capacity. The changes in benefits and the reasons for them are explained in Sections 2 and 3. The biggest change is for the capacity sharing and economy energy transfer benefits, which are significantly lower, primarily as a result of lower cost of new generating capacity and lower fuel price projections. Benefits of improved reliability are the same as the 1989 study, except for the conversion to 1997 dollars, because complete updating of the reliability numbers was beyond the scope of this update; it would require significant data analysis and review of a number of subjective assumptions. Benefits in the other categories are the same as the 1989 study, except for the conversion to 1997 dollars; they were significantly smaller than the first three categories, so we did not attempt to update them. To put the benefits of the proposed SIP in context, it is helpful to compare them to the current level of expenditures (total paid by retail customers) on electricity in the Railbelt. These are roughly $450 million per year. If we assume these will grow at 2 per cent per year, then the net present value of these expenditures over the period 2004- 2043, for which we have estimated the benefits of the proposed Kenai-Anchorage line, is about $9 billion. 1.3 Range of Benefits Estimating the future benefits of a project like the SIP is difficult because it depends on numerous factors that can not be predicted or measured with precision, ranging from Decision Focus Incorporated - Confidential @ ® 3 future fuel prices to how much consumers would pay to avoid an outage to how the Railbelt utilities will choose to operate their interconnected systems in the future. Asa result, there is necessarily a great deal of uncertainty and imprecision in the benefits estimates presented here. The December 1989 study showed a range of values within which the benefits were expected to lie. This review takes the midpoint of that range as a starting point, but does not try to update the range. This should not be interpreted as a failure to recognize the uncertainty and lack of precision; if anything, the range of Boe a ate cel ier tee aay eran emg em ney (See page 6-1 of the Rai 2 i eport, prepared by the Alaska Energy Authority, March 1991 for further discussion i this point.) 1.4 Additional Analysis Time and budget constraints limited the extent of this review. In particular, we have not revisited operating scenarios for the Railbelt system, i.e., how the overall system is likely to be operated with and without the proposed line. Conditions and expectations have changed since the 1989 study. For example, at that time Bradley Lake was not yet on line, but was expected to provide spinning reserve; now it is on line, but is not providing spinning reserve. As another example, consideration is now being given to adding battery energy storage (BESS) or superconducting magnetic energy storage (SMES) to the Railbelt system; the value of the proposed transmission line could vary significantly if storage is added. If additional analysis of the benefits of the SIP is considered warranted, it should focus on the following areas: = Economy energy benefits: projections of how the entire Railbelt system would be operated, with and without the new line, should be developed, instead of simply adjusting the 1989 estimates in proportion to the change in projected fuel prices. a Spinning reserve benefits: projections of how the entire Railbelt system would be operated, with and without the new line, will impact spinning reserve costs as well. a Impacts of adding BESS or SMES in addition to the SIP to the Railbelt system; Anchorage Municipal Light and Power (AMLP) has estimated that the savings in spinning reserve costs from adding storage would be $1 million per year for AMLP alone, but only if there is adequate transmission capacity. a Reliability benefits: the assumptions about the extent to which unserved energy would be reduced by constructing the proposed line, and about the value of each unit of unserved energy, should be reviewed. Decision Focus Incorporated - Confidential a Other potential benefits not included in either study, such as transmission system stability and economies of scale i in installing new generating capacity. a Uncertainty in projections of fuel prices and load growth. Specifically, we recommend a re-examination of how the overall generating system is likely to be operated without the proposed line, with the proposed line, and with both the proposed line and BESS and/or SMES. Such a re-examination would require considerable interaction with staff of the IPG members, and would include factors such as unit commitment and dispatch policies, hydro-thermal coordination, spinning reserve, and transmission line loading policies. The re-examination would provide more credible values for the economy energy and spinning reserve benefits of the proposed transmission line. 2.0 Benefits Estimation Methodology This section outlines the methodology used for calculating the numerical estimates in each of the three major categories, summarizing the key assumptions and listing the major data items affecting the estimates. 2.1 Capacity Sharing Capacity sharing benefits occur when: e one region has a capacity shortfall (i.e., demand plus the required reserve margin exceeds the capacity available) another region has a capacity surplus transmission links allow the first region to rely on excess capacity in the second region, even if only for a limited time Increased transmission capacity allows one region to rely more heavily on generation capacity in another region, for capacity as well as for energy. For the Railbelt, the SIP would allow Anchorage to rely on a greater portion of the Kenai Peninsula generation capacity surplus for meeting the Anchorage capacity part, thus deferring the need to build new ——_ capacity in Anchorage. There are two types of capacity sharing benefits: 1. _As load grows ina region, enough capacity must be available to meet the peak load in that region plus a required reserve margin. Increased transmission capacity increases access to generation capacity in regions with surplus capacity, thus making it possible to defer adding generation capacity in the first region Decision Focus Incorporated - Confidential 2. The larger and more interconnected a system, the lower the reserve margin required to provide the same level of reliability. Increasing transmission capacity increases the level of interconnectedness for the Railbelt, allowing utilities to permanently avoid building some of the capacity that would have been constructed to maintain the desired reserve margin. Construction of the SIP would produce both types of capacity sharing benefits. Demand growth, taken together with available capacity, determines the timing of any capacity sharing benefits. Demand tends to grow over time, while unless new generating units are installed, capacity holds steady or shrinks somewhat due to retirements. Therefore, capacity sharing benefits tend to first grow over time as surplus is eliminated in relatively capacity-poor regions, then fall as surplus also disappears in the relatively capacity-rich regions. The capacity sharing benefit in a year is the amount of capacity avoided or deferred in the year, measured in kilowatt-years, times the cost of a kilowatt-year of capacity. For the latter we use the annualized fixed cost of a new combustion turbine, including both the installed capital cost and the fixed operations and maintenance cost; this is a standard yardstick for measuring the value of capacity. key data items: total generating capacity available peak demand growth required reserve margin fixed cost of new combustion turbine 2.2 Economy Energy Transfers This benefit occurs when high cost energy in one area is displaced by lower cost energy from another area. In the Railbelt all available hydro energy, which uses no fuel and for which the variable cost is essentially zero, will be used with or without the proposed new transmission line. Thus the benefits in this category result from displacing electricity generated from thermal units (gas-fired or oil-fired) with electricity from other thermal units with lower variable costs. These lower costs may result from access to less expensive fuel or from some units being more efficient (converting a greater fraction of the energy content of the fuel to electricity) than others. The economy energy benefit is equal to the increased amount transferred between Kenai and Anchorage (as a result of the new line) times the difference in marginal variable operating costs between the two regions. Secondary impacts result from being able to better operate units at or near their optimal loading levels, and improved hydro-thermal coordination. Decision Focus Incorporated - Coinfidential The variable costs of producing electricity, i.e., costs of economy energy, are roughly proportional to fuel prices. This means that higher fuel prices translate directly to a higher level of economy energy transfer benefits; a percentage increase in fuel prices translates to roughly the same percentage increase in economy energy benefits if all fuel prices in both regions are increased by the same percentage. Similarly, a reduction in ptice forecasts for all fuels translates directly to reductions in economy energy transfer benefits. Changes in load growth forecasts since 1989 may impact economy energy amounts ice 3 NNN NTE TNTA TIORRG but this is a smaller effect and has not been estimated. key data items: a fuel price projections 2 load growth projections 2.3 Reliability Reliability is determined by the number, magnitude, and duration of customer outages. Reliability benefits occur if customer outages are reduced as a direct consequence of constructing a new transmission line. The proposed SIP is expected to reduce both the frequency and duration of generation- and transmission-related outages, i.e., outages related to unexpected loss of generating units or the existing Anchorage-Kenai transmission line. In the event of an outage, unserved energy is defined as the electricity that would have been consumed if the outage had not occurred. The reliability benefit is equal to the expected reduction in unserved energy as a result of the proposed line times the value of each unit of unserved energy. Several studies have shown that the value per unit of unserved energy depends on the customer class affected and the duration of the outage. key data items: a reduction in unserved energy as result of new line a value of unserved energy 3.0 Updates Of Key Data Items The major factors that go into determining benefits of capacity sharing, economy energy, and reliability include: a discount rate Decision Focus Incorporated - Confidential demand forecasts: a generating capacity: planned additions and retirements cost of new capacity fuel price projections level of customer outages (number, size, duration) and outage causes value of customer outages Each of these is discussed below, followed by a ‘qualitative discussion of the impact on benefits estimates given the new information. 3.1 Converting to 1997 Dollars The first challenge in comparing 1989 estimates with current estimates is to make sure that the numbers are all based on the same year’s dollars; .this eliminates the effects of inflation that make a dollar today not as valuable as a dollar was 7 or 8 years ago. DFI’s 1989 benefits study expressed all values in 1990 dollars. For this update all values are expressed in 1997 dollars. Therefore, before we can compare the data from the previous study to the new information, we have to inflate it so that we can compare old values expressed in 1997 dollars to new values expressed in 1997 dollars. We have assumed an annual average inflation rate over the last 7 years of 3.23 per cent, which is the annual average increase in the Consumer Price Index from 1990 to 1997. With this inflation rate, a value of $1.00 in 1990 dollars corresponds to $1.25 in 1997 dollars. 3.2 Discount Rate In order to make simple comparisons between two or more multi-year streams of costs or benefits, the multi-year streams are usually converted to a net present value by discounting costs and benefits that occur in future years back to an initial year, and summing over all years. This means that costs or benefits that occur in the future carry less weight than those occurring now. For example, at a discount rate of 6 per cent, $1 of benefits in 1998 is worth $0.94 now, while $1 of benefits in 2010 is worth only $0.47 now. The choice of discount rate can make a significant difference to the net present value of a benefits stream if many of the benefits occur in the future. A lower discount rate gives relatively more weight to future benefits than'a higher discount rate. Which discount rate to use for evaluating projects such as the SIP is not obvious. The discount rate is supposed to reflect the time preference of the party or parties making the decisions. If multiple parties with different preferences are involved, what rate Decision Focus Incorporated - Confidential We believe that for the SIP the appropriate discount rate should reflect the cost (or value) to the ratepayer of investing money today to capture future benefits. The cost of capital for the investing organization is a good measure of the cost to the ratepayer. For instance, Chugach Electric Association has an average historic cost of debt of about 8.6 per cent. This means that, on average, when Chugach has borrowed money in the past, it has paid a nominal interest rate of 8.6 per cent on the debt. The nominal interest rate includes inflation; to get the equivalent real interest rate we take out the effects of inflation. Fuel prices provided by Golden Valley Electric Association indicate a projected forward-looking inflation rate of 2 per cent, and historical inflation has been 2.5 to 3 per cent over the last 5 years. For this update of the 1989 study, we have used a discount rate of 6 per cent as representative of the real cost of capital for the Railbelt area (8.6 per cent nominal = 6 per cent real + 2.6 per cent inflation). Present values of benefits are shown in Table 1 using both 6 per cent and 4.5 per cent discount rates. Using a 6 per cent discount rate instead of 4.5 per cent, as was used in the 1989 study, with no other changes in assumptions lowers the present value of benefits by 15 to 20 per cent, depending on the pattern of benefits over time. For rates between 4.5 and 6 per cent, the present value of benefits would lie between those calculated using these two rates. Note that both the 4.5 per cent rate used in 1989 and the 6 per cent rate suggested here are real discount rates, i.e., tates excluding inflation. The switch from 4.5 to 6 per cent does not reflect any changes in underlying conditions, but rather a change in assumptions away from a rate mandated by a government agency to a rate more appropriate for a utility and its ratepayers. 3.3 Demand Forecasts Table 2 compares the demand forecast used in the 1989 study with current demand forecasts, by looking at the forecast for the year 2010. Table 2 COMPARISON oF PEAK DEMAND FORECASTS FOR 2010 Decision Focus Incorporated - Confidential (Fairbanks forecast is preliminary.) For Anchorage and the Kenai Peninsula, the new forecasts for 2010 are not too different from the 1989 forecasts. However, the newer projection for Golden Valley /Fairbanks is substantially higher. 3.4 Generating Capacity: Planned Additions and Retirements There have been some changes since the 1989 study. Life extensions and postponing the retirement of several units, particularly Beluga, result in a substantially higher projection of available capacity, pushing capacity sharing benefits further into the future. 3.5 Cost of New Combustion Turbine A new combustion turbine is assumed to cost $600 per kilowatt installed, with fixed operations and maintenance cost of $8 per kilowatt per year (per discussion with Power Engineers Incorporated, for a unit in the 50 megawatt size range, at an unspecified site; a larger unit at an established site would cost less). Levelizing the capital cost over 25 years at 6 per cent and adding the fixed operations and maintenance cost yields a value of $55 per kilowatt per year, in 1997 dollars. The 1989 study used a value of $51 per kilowatt per year, in 1990 dollars. When both are expressed in the same year dollars, the new value is about 15 per cent lower. 3.6 Fuel Prices Table 3 shows the fuel prices projected for 2010 in the 1989 analysis, converts them to 1997 dollars, and compares the forecasts to today’s actual prices. The actual prices today are about 40 to 70 per cent lower than the forecast, when both are expressed in 1997 dollars. Decision Focus Incorporated - Confidential R2947— 10 Table 3 Comparison of 1997 Fuel Price Forecast with Actual Prices [$/million Btu] Table 4 compares the 1989 fuel price forecasts for 2010 with current fuel price forecasts for 2010. As in Table 3, all numbers are converted to 1997 dollars. We see a similar pattern, in that the prices forecast today for 2010 are 25 to 50 per cent lower than the prices that were forecast for 2010 in 1989. Table 4 Comparison of Fuel Price Forecasts for 2010 Made in 1989 With Those Made in 1997 [$/million Btu] Decision Focus Incorporated - Confidential R2947a Lower fuel prices reduce the value of the benefits from economy energy. Without detailed system modeling (i.e.,.how each generating unit would be operated over the 40-year time horizon, with and without the proposed new transmission line), it is impossible to say precisely how much the benefits are reduced (see recommendation in Section 1.4). . However, in aggregate, we would expect that if all fuel prices are lower by some percentage, then the SE : 3.7 Level of Gintomer Outages Two key assumptions about the impact of the new. Kenai-Anchorage line were made in the 1989 study: . - = the new line would reduce outages (unserved energy) in the Kenai by ‘ about 55 per cent from historical levels (1986-1987); this assumption took into account the fraction of time that energy was flowing in each direction, and the likely impact of an outage for each direction of flow. a the new line would reduce outages in the Anchorage area by 30 to 60 megawatthours; this is based on avoiding 1 to 2 outages of 30 MW and one hour duration per year. The current update uses these same assumptions. New outage data has been provided, but it is incomplete, and completely redoing the reliability benefits component was beyond the scope of this update (see recommendation in Section 1.4). 3.8 Value of a Customer Outage Secepé:kor compacting t0/1097 clings, we'nsed tile eitas uapame ore ins the 1089 study, About 88 per cent of outages are industrial or commercial, with the remainder residential. The outages that would be impacted by the proposed line range from a few minutes to a few hours in duration. Based on the distribution by customer class and duration, the average value of each kilowatthour of unserved energy avoided is about $22 (1997 dollars). Decision Focus incorporated - Confidential R2947 _ SENT.BY: &4 © 5-87 +11:30AM ; POWER ENG D™” =R> 907 562 0027;# 2/ 6 a) omer September 5, 1997 Dora Gropp Project Manager Chugach Electric Association 560] Minnesota Drive Anchorage, AK 99519-6300 Subject: 120376-05: Southern Intertie Project - Decision Focus Benefits Study Extension Dear Dora, © As we have discussed, an extension to Decision Focus’ work scope to include a more detailed ‘investigation and update of the benefits attributable to economy energy transfers and spinning reserve sharing appears to be warranted. As you directed, we requested and have received the attached proposal from DF1 to conduct meetings with Railbelt staff and additional analysis to further update and assess the value of the benefits from the Project. DI'l’s approach to the additional analysis and the deliverables that would be received are outlined in their proposal. The total estimated cost for DF1 to complete the proposed scope of work is estimated to he between $50,000 and $70,000, According to DFI, the final cost is dependent on the methodology and the level of detail of modeling that is required. Determination of these - parameters requires discussion with you and other Railbelt staff. - To support the effort by DFI and to provide for review of the work, it is proposed that Randy Pollock accompany DFT on the initial data gathering trip to Alaska, and to also attend a subsequent presentation at the conclusion of the study, should that prove desirable to the IPG. DEN 26-1314 POWER Engineers, Incorporated ‘5900 South Wadsworth Boulevard, Suite 700 ae Phone (303) 716-8900 Lakewoud, CO 80235 : : Max (303) 716-8980 09/05/97 FRI 09:32 [TX/RX NO 62801 SENT BY: Y 5-87 511:31AM ; POWER ENG VER> 907 562 0027;# 3/ 6 * Chugach Blectric Association September 5, 1997 Page 2 On this basis we propose the following budget for the work: ie i ay eames cee eats Fo pose as een Thank me for your consideration of this matter. Sincerely, POWER Engineers, Inc. Randy Pollock, PF. ; Project Manager Enclosure 1p/RP | . cc: Mike Walbert - Power File DEN 261314 nasnk/a7 = FPT no-29 ry mv ain coond . SENT-BY-: *- 5-87 311:31AM ; POWER ENG D = =R> 907 562 0027;# 4/ 6 Proposal to Extend the Current Review and Update of the 1989 Study on the Benefits and Costs of the Proposed Southern Intertie Project Background In 1989 Decision Focus Incorporated (DF1) carricd out an cconomic analysis of the bencfits of several proposed transmission linc upgradcs or additions in the Railbelt area of Alaska. The Tesults of the analysis were documented in a December, 1989 report entitled “Economic Feasibility of the Proposed 138 KV Transmission Lines in the Railbelt.” DFI has just complcted a high-Icvcl revicw and update of the bencfits of thc Southern Intcrtic Project (SIP) between Anchorage and Kenai, accounting for changes in such factors as fuel price projections and load growth forecasts, but not reviewing underlying assumptions. During the recent review it became apparent that some of the underlying assumptions have changed and that a more detailed review of how the interconnected Railbelt gencration and transmission system is likely to be operated, both with and without the new linc, would be valuable and could identify benefits previously ovcrlooked. Thc cffort proposed here will focus on two of the benefits catcgorics idcntificd in the carlicr studics: cconomy cncrgy transfers and spinning reserve sharing. Approach Conditions and expectations have changed since the 1989 study. For example, in 1989 Bradlcy Lake was not yet on line, but was expected to provide spinning reserve; now it is on linc, but is not providing spinning rescryc, As anothcr cxamplc, considcration is now being given to adding battery cnergy storage (BESS) and/or superconducting magnetic energy storage (SMES) to the Railbclt systcm, the value of the proposed transmission line could vary significantly if storage is added. To identify the key changes and develop at least a qualitative assessment of how thcy impact the value of the proposed transmission line, we would first revicw all] of the comments on the various studies of the proposed linc carricd out from 1989 to the prcscnt. We would then meet with staff from a number of the Railbelt utilities who are familiar with how system operating decisions arc made now and how they might change in the future, particularly if thc acw transmission linc is built and if energy storage is added to the system. Discussion would focus on such issues as: © unit commitment and dispatch spinning tescrvc hydrothermal coordination allowed transmission loadings impact of BESS and/or SMES on the above impact of the new transmission line on thc above Modeling alternatives To convert the qualitative findings of thesc initial sicps into quantitative benefit estimates will require some level of modeling. Detailed assessment of the economy cnorgy and spinning reyerve 99/08/97 FRI na-29) FTY/DY NN RORAT SENT BY: - 5-97 511:34AM ; POWER ENG 'ER> 807 562 0027;# 6/ 6 Staffing Stephen Haas will Icad the proposed work, Stevc has participatcd in and led a number of DFT’s electricity consulting projccts, including the just-complcted update of the 1989 study and an earlier analysis of battery energy storage in the Alaska Railbelt. Thc second team member is likely to be Ralph Samuelson, who also has many years expcricnce in encrgy consulting, most recently in developing a markct modcling system to determine the likely direction of regional bulk elcctric power prices in a deregulated cnvironment. Schedule DFI can begin work as soon as we receive formal approval. We wil] want to schcdule a trip to mect with staff of several of the Railbelt utilitics as soon as we can after the start. Depending on the Icvel of detail determincd to be desirablc and the amount of modeling rcequircd, the draft report can be completed 6 to 10 weeks after project start. Cost and Billing DFI will bill Power Enginecrs on a time and materials basis. The hourly billing ratcs for the individuals expected to work on thc proposed effort are: Haas $250 Samuelson $215 Support $80 Thc estimated cost is $30,000 to prepare for the initial trip to Alaska, conduct several days of discussion in Alaska, and writc up the qualitative findings of the trip. At that point we would have a much bettcr idea of the additional cost of doing quantitative modcling and analysis and describing the results in a rcport; the additional cost is estimated at $20,000 to $40,000, depending on the Icvel of detail and modeling required. Power Engincers and the Railbclt utility project manager would be involved in the decision on the level of detail and amount of modcling. Travel will be billed at cost, which should not exceed $1,500 per trip. Wc expect that | or 2 trips, with | or 2 DET staff on cach trip, will be necessary. ‘Ihe first trip would be for discussions of how the systcm is now operated and is likely to bc operated in the future, with staff from scveral of the Railbelt utilitics. A second trip may be neccssary for follow-up discussions of model results and analysis. DFI will invoice Power Engineers monthly for work performed in the previous month. AOsne 07 EMT an.2e oem mw un eaoond