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HomeMy WebLinkAboutRailbelt Intertie Proposal Preliminary Economic Assessment 19874 043 Alaska Power Authority LIBRARY COPY Alaska Power Authority Railbelt Intertie Proposal Preliminary Economic Assessment March 1987 RAILBELT INTERTIE PROPOSAL PRELIMINARY ECONOMIC ASSESSMENT Summary and Conclusions A contract for $25,000 was issued by the Alaska Power Authority to Lotus Consulting Group, an electric utility consulting firm based in California, for a preliminary assessment of economic benefits associated with two proposed transmission projects: upgrade of the existing Anchorage/Fairbanks intertie and eee of a new Anchorage/Kenai Peninsula intertie. Presented below is an overview of the issue, a summary of the benefit assessment undertaken by Lotus Consulting Group, discussion of other associated benefits that are not captured in that assessment, and a comparison of benefits with estimated project costs. The report prepared by Lotus Consulting Group is attached. On the basis of the analysis performed, it is concluded that the proposed transmission projects are capable of delivering economic benefits in excess of their costs, and consequently warrant further consideration. The primary benefit categories that are quantified in the analysis are economy interchange, reserve sharing, system 8549/723 efficiency and, to a partial extent, siting flexibility for new generating plants. Other benefits that are not quantified include improved system reliability, increased utility coordination, distribution of Bradley Lake benefits, and enhanced competition among fuel suppliers. The sum of the benefits identified in the system modeling performed by Lotus Consulting Group is approximately $150 million higher (in 1986 dollars) than the sum of the estimated costs. However, because most of the costs are incurred before most of the identified benefits are realized, the present value of costs and identified benefits are approximately the same. If the benefits not captured in the system modeling were brought into the comparison, then the present value of benefits would exceed the present value of costs. Background and Purpose of the Study A Request for Proposal (RFP) was issued by the Power Authority for a feasibility study of the Anchorage/Kenai Peninsula intertie in August 1986. The anticipated cost of that study is approximately $300,000, with the State contributing half of the funding and the Railbelt utilities contributing the other half. The firm that won the contract included $10,000 within its proposed budget to perform the economic cost/benefit part of the evaluation. However, despite 8549/723 its superior qualifications to perform other elements of the analysis such as engineering, design, and cost estimation, that firm failed to demonstrate adequate ability regarding the estimation of economic benefits. As a result, that component of the project was deleted from the scope of work, and a decision was made by the Power Authority to pursue that analysis separately. During the same period of time, the Railbelt Energy Council was formulating its proposal for the State to upgrade the existing Anchorage/Fairbanks intertie as well as construct a new Anchorage/Kenai Peninsula line. It became apparent that the economic merits of both transmission proposals would become a subject of interest during the 1987 legislative session. Consequently, the Power Authority decided to consolidate the economic assessment of both proposals within a single contract, and to aim for completion of that assessment as early as possible in the 1987 session. State funding in the amount of $25,000 was identified for the effort, an RFP was developed in November 1986, and a contract was awarded to Lotus Consulting Group on December 31, 1986. A highly detailed analysis of each alternative is not possible within the funding and time constraints that characterized this effort. The goal of the study, explicitly stated in the RFP, was to produce an understanding of the benefits of both transmission 8549/723 proposals sufficient to judge whether they are promising with regard to economic feasibility criteria. Existing Generation and Transmission System For the following discussion, it may be helpful to refer to the simplified Railbelt transmission map shown in Figure l. On the Kenai Peninsula, existing generating capacity consists primarily of natural gas units at Bernice Lake and Soldotna totaling about 120 MW, and a hydroelectric facility at Cooper Lake of about 17 MW. The natural gas units are currently used primarily for reserve capacity and winter peaking requirements. Most of the electric energy currently consumed on the Kenai Peninsula is generated at the Beluga station and brought south over the existing transmission line. For the intertie economic study, it is assumed that the Bradley Lake project is operational throughout the period of analysis. The existing transmission line between Anchorage and the Kenai Peninsula is owned by Chugach Electric Association, is constructed for operation at 115 KV and has a rated transfer capability of 55 MW. However, due to the demand of customers along the route and also due to significant line losses, it is estimated that only 8549/723 40 MW can be assumed for delivery in Soldotna given a 55 MW input on the Anchorage end of the line. In addition, the line is subject to avalanche and weather induced outages, and as a result its reliability is a continuing concern. It is primarily for that reason that generating capacity has been installed on the Kenai Peninsula sufficient to meet its own peak requirements even though most of the annual energy is imported from the north. The existing transmission line should not be considered an adequate interconnection for purposes of future generation capacity expansion. In the Anchorage/Beluga area, installed generating capacity totals about 768 MW, all of which consists of natural gas-fired units except for the 30 MW hydroelectric facility at Eklutna. Of the total gas-fired capacity, approximately 360 MW is located at the Beluga station on the west side of Cook Inlet. Sufficient transmission capability currently exists between the Beluga station and the Anchorage load center to permit moderate expansion of generating capacity at Beluga without encountering transmission constraints. The transmission system of Chugach Electric Association extends north to the Teeland substation, which is identified at the northern end of Knik Arm in Figure l. The intertie between Teeland substation and Fairbanks consists of three segments: approximately 25 miles of line between Teeland and Willow owned by Matanuska Electric Association, approximately 170 8549/723 miles of line between Willow and Healy owned by the Alaska Power Authority, and approximately 100 miles of line between Healy and Fairbanks owned by Golden Valley Electric Association. The entire circuit from Teeland to Fairbanks is currently operated at 138 KV and has a transfer capability of 70 MW. In the Fairbanks area, installed capacity currently operated by the local utilities consists primarily of oil-fired units totaling about 200 MW and coal-fired units totaling about 45 MW. Of the total coal-fired capacity, 25 MW is located at Healy. Because the transmission line owned by Golden Valley Electric Association between Healy and Fairbanks can accommodate power transfers up to 95 MW, the coal-fired unit at Healy can operate at full capacity and still allow transfers between Anchorage and Fairbanks of up to 70 MW. Railbelt Intertie Proposal There are two components of the Railbelt Intertie proposal put forward by the Railbelt Energy Council: 1) Upgrade of the existing Anchorage/Fairbanks intertie; 2) Construction of a new Anchorage/Kenai Peninsula intertie. 8549/723 The portion of the Anchorage/Fairbanks intertie built by the Power Authority is constructed for operation at 345 KV. However, the line is currently operated at 138 KV due to transmission constraints at both ends of the Power Authority line, i.e. south of Willow and north of Healy. By upgrading the circuit where these constraints exist, the intertie could be operated at a full 345 KV which would increase the power transfer capability between Anchorage and Fairbanks from 70 MW to approximately 350 MW. For purposes of the economic analysis, it was assumed that upgrade of the Anchorage/Fairbanks intertie would allow a full 350 MW to be transferred over the line. It is expected that a new Anchorage/Kenai Peninsula intertie would be constructed for operation at 230 KV, and that the full power transfer capability of that line would be approximately 250 MW. For purposes of the economic analysis, it was assumed that a new line would provide a reliable interconnection that would permit transfers up to 250 MW. Categories of Benefit There are several types of benefits that would be associated with the proposed Railbelt Intertie project: * Economy Interchange: These are the savings that are produced 8549/723 when a transmission project allows lower cost generation produced in one area to displace higher cost generation produced in another area. Examples of this would occur when the cost of oil-fired generation in Fairbanks exceeds the cost of natural gas-fired generation in the Cook Inlet area, or when the cost of gas-fired generation in Anchorage exceeds the cost of gas-fired generation on the Kenai Peninsula. Another example would occur if the cost of coal-fired generation in the Interior fell below the cost of generation in the Southcentral area. * Reserve Sharing: These are the savings that are produced when a transmission project allows one or more utilities to forego building or maintaining a certain amount of reserve capacity by relying instead on reserves available elsewhere in the interconnected system. An example of this would occur if a reliable interconnection were built between Anchorage and the Kenai Peninsula. The total installed capacity needed to meet reserve requirements for both areas would be reduced as a result. * Siting Flexibility for New Generating Plants: Improved transmission allows greater flexibility in siting new plants wherever the costs of operation, including the costs of fuel, are lowest. For example, if natural gas is available on the Kenai Peninsula at a significant savings relative to the price 8549/723 of natural gas delivered to Anchorage, then siting new plants on the Kenai Peninsula rather than the Anchorage area would reduce system costs. A firm interconnection would allow that to occur. Other examples would be the possible future construction of a major coal-fired power plant or hydro project in the Railbelt. Improved transmission would allow such a plant to be built anywhere near the grid (e.g. Beluga, Matanuska Valley, Healy, Nenana) and still serve all of the major Railbelt load centers. * System Reliability: An improved transmission system can substantially reduce the number and extent of power outages. For example, the existing Anchorage/Fairbanks intertie made it possible for electricity demand in the Mat-Su Valley to be served from the Fairbanks area when service from Anchorage was interrupted during a recent incident. A new intertie between Anchorage and the Kenai Peninsula would produce a far more reliable connection between these two areas than currently exists, and would result in a reduction in the number and extent of power outages, particularly on the Kenai Peninsula. * System Efficiency: Transmission losses are reduced in higher voltage circuits. Power transfers between Anchorage and Fairbanks presently suffer losses on the order of 10% at 138 KV. For the economic study, it is assumed that such losses would be reduced to 4% at 345 KV (i.e. a reduction in 8549/723 -10- losses of 60%). Similarly, it is assumed in the economic study that losses over the existing Anchorage/Kenai Peninsula line are 10%, but that losses over a new 230 KV line would be reduced to 2% (i.e. a reduction in losses of 80%). * Increased Utility Coordination: It is generally agreed that the interests of Railbelt consumers would be served through increased integration of planning and operations among the seven Railbelt utilities. Strengthening the transmission network that links these utilities together would enhance the evolution of a more coordinated utility structure. Further, such improved linkage would facilitate the sharing of costs among all the utilities for future generation projects that may be economically attractive but which exceed the financial resources of any single utility or community. * Distribution of Bradley Lake Benefits: The Railbelt Intertie project would facilitate the distribution of Bradley Lake benefits throughout the Railbelt by providing each of the seven utilities with direct access to project output over reliable transmission facilities. * Enhanced Competition Among Fuel Suppliers: By improving the access of all seven utilities to energy sources throughout the Railbelt, the competition among those sources to supply utility requirements would be enhanced. Because each utility 8549/723 = 4) would have a broader range of energy supply alternatives, the bargaining position of each utility with respect to potential fuel suppliers would be strengthened. The interests of consumers would be served by this improved position. Study Methodology and Limitations Lotus Consulting Group was directed to estimate the production costs of the Railbelt system for the period 1991 - 2020 with and without the proposed Railbelt Intertie. A computerized production cost simulation model was used for the analysis. Because the costs of construction and maintenance of the Intertie project were not defined at the time the economic analysis was undertaken, no estimate of those costs was included. The work performed by Lotus Consulting Group therefore sheds light only on the benefit side of the ledger. It is necessary to go beyond the Lotus study in order to compare total benefits with estimated costs. Of the various benefit categories noted above, there are several that are not accounted for in any way within the Lotus study, specifically the benefits of improved system reliability, increased utility coordination, distribution of Bradley Lake benefits, and enhanced competition among fuel suppliers. The benefit of siting flexibility for new generating plants is partially accounted for in 8549/723 = 10 = that the analysis assumes more advantageous siting of some new gas-fired capacity with the Intertie project in place. However, study constraints did not allow consideration of other possible siting benefits such as the impact of the Intertie on the viability of coal-fired generation or other large-scale projects. The primary benefit categories that are quantified in the system modeling effort are economy interchange, reserve sharing, and system efficiency. All major assumptions and parameters for the study were provided to Lotus Consulting Group by the Power Authority. Major Assumptions and Parameters There are many assumptions that enter in to such an assessment, such as electricity demand forecasts and fuel price forecasts. For most of these assumptions, there are numerous values and trends that could be defined that fall within a range of reasonable possibilities. Yet single point estimates had to be selected for each of these assumptions because the time and dollar constraints did not permit review of multiple scenarios. The approach adopted for the study was to select values that were either suggested or agreed to by Railbelt utility representatives and that were judged by the Power Authority to be reasonable. These major assumptions and parameters are discussed below: 8549/723 | ay a Time Frame for the Analysis: System costs were modeled for the 30 year period from 1991 through 2020. Thirty years was selected as a conservative estimate of the economic life of the Intertie project. Although steel towers would be expected to last longer than 30 years, less durable elements of the Intertie project such as submarine cable may require renovation or replacement by that time. The initial year was set at 1991 because it would be difficult to complete the Intertie project prior to that time and because 1991 is expected to be the first full year of commercial operation for the Bradley Lake project. * Fuel Price Forecasts: For an analysis of this type, the critical issue with regard to fossil fuel prices is not whether the absolute level of such prices is likely to increase, decrease, or remain the same, but rather what the price differentials are likely to be between different fuels delivered to different locations. For example, the economy interchange benefit of transmission capacity between Anchorage and Fairbanks is primarily based on the assumed differential between the price of natural gas in the Cook Inlet area and the price of fuel oil in the Fairbanks area. If the prices of those two fuels are competitive, there is little benefit in importing energy from one area to displace generation in the other area, whether or not the absolute level of prices is high or low. Conversely, a significant differential in price 8549/723 aly ae can lead to a substantial benefit from economy interchange. Because the absolute level of fossil fuel prices is not central to the analysis, the approach adopted was to assume that the absolute level remains essentially constant in real terms (i.e. tracks the rate of inflation, no more and no less). This assumption was adopted for simplicity, and does not reflect any consideration by the State, the Power Authority, or the Railbelt utilities regarding the expected long-term outlook for fossil fuel prices in general. Cook Inlet Natural Gas: Substantial gas-fired generating capacity exists in three distinct locations within the Cook Inlet area: the Beluga station on the west side of Cook Inlet, the Kenai Peninsula, and the Anchorage area itself. Because part of the Railbelt Intertie proposal consists of a new line between Anchorage and the Kenai Peninsula, and because reliable transmission already exists between Beluga and the Anchorage area, it is necessary to estimate the extent of any price differential for natural gas delivered to power plants in these three distinct eenasiews, If a price differential exists, then the transmission proposal will produce benefit if it allows lower priced gas to be used to a greater extent. The first step in estimating delivered price is to estimate the wellhead value. It is assumed for this analysis that the 8549/723 wellhead value of natural gas is the same everywhere in the Cook Inlet area. A natural gas pipeline network is currently in place that extends from the Beluga field around Knik Arm to Anchorage, down to the Kenai Peninsula and then back across Cook Inlet to the vicinity of the Trading Bay field about 13 miles south of the Beluga station. In other words, with the exception of a short segment between Beluga and Trading Bay on the west side of the Inlet, a pipeline loop extends around the area linking the various major fields in the Cook Inlet region. The existence of this linkage supports the idea that the wellhead value of gas in one field is likely to be very much the same as the wellhead value of gas in another. Natural gas for the Beluga generating station is obtained at the wellhead from the Beluga field through direct purchase from gas producers. Therefore, there is no charge for transporting the gas from the field to the plant. Natural gas for both Kenai Peninsula and Anchorage area plants is presently purchased from Enstar Natural Gas Company, which delivers gas to the plants through its pipeline system at a price that includes Enstar's gas acquisition cost and the cost of pipeline transportation. Based on discussion with an Enstar representative, it is estimated that the transportation cost component of the delivered price is currently $ .60 per MMBTU. 8549/723 = {§ = The utilities that currently operate gas-fired capacity on the Kenai Peninsula have expressed the expectation that gas in the future will be obtainable for their plants on the Kenai Peninsula at its wellhead value from suppliers other than Enstar. Consequently, it was assumed for this analysis that natural gas available to generating plants on the Kenai Peninsula will be priced at the assumed wellhead value (i.e. without a $ .60 per MMBIU transportation charge). In support of this assumption, it can be noted that the review of Bradley Lake economics issued by the State Office of Management and Budget (dated February 25, 1987) incorporates the same assumption that such gas will be available at its wellhead value. For generating plants in the Anchorage area, it is assumed that future supplies of natural gas must still be delivered by pipeline at a price that includes a $ .60 per MMBTU transportation cost. Therefore, the approach adopted for the analysis was to assume the availability of natural gas both at Beluga and on the Kenai Peninsula at the wellhead value, but to assume that the price delivered to Anchorage area plants would equal the wellhead value plus $ .60 per MMBTU. Based on discussions with area utilities, it was assumed that the wellhead value is $1.60 per MMBTU (implying a delivered price to Anchorage area plants of $2.20 per MMBTU). These values were held constant in real terms throughout the period of 8549/723 a7! analysis. (1) Fuel Oil in Fairbanks: It is necessary to estimate a fuel oil price in Fairbanks that is reasonably consistent with an assumed Cook Inlet natural gas price of $1.60 at the wellhead. The judgment adopted for this analysis was that a Cook Inlet gas price of $1.60 is roughly consistent with a long-run world oil price in the vicinity of $20/barrel (in 1986 dollars). These magnitudes are supported in general by the observation that Cook Inlet wellhead values for natural gas were about $2.30/MMBTU four years ago when the world oil price was approximately $30/barrel. Since $1.60 represents a reduction of about one-third, the oil price assumed to be consistent was reduced by about one-third. Based on discussion with Fairbanks utility representatives, the assumed crude oil price of $20/barrel was translated into an estimated fuel oil price of $ .48/gallon. That price, in turn, is equivalent to $3.40/MMBTU. The analysis therefore assumes a long-run price differential between Cook Inlet natural gas at the wellhead and fuel oil available in Fairbanks of $1.80/MMBTU (i.e. $3.40 for fuel oil vs. $1.60 for natural gas). It is interesting to note that the feasibility study for the 8549/723 - 18 - existing Anchorage/Fairbanks intertie performed for the State in 1981 incorporated the assumption of a far greater differential between these two prices. Given a natural gas price of about $1.60/MMBTU, the estimated fuel oil price assumed within that analysis was approximately $9.00/MMBTU, a differential of $7.40. This suggests that the estimated long-run price differential adopted for the current analysis may be conservative, as it is approximately one-fourth of the long-run differential previously estimated. Coal in Fairbanks: As discussed below under the heading of “Expansion Plan," the scenario examined for this study involved a reduction in existing coal-fired capacity in the Fairbanks area from 45 MW today to a single 25 MW plant. The existing capacity consists of a 20 MW plant in Fairbanks that is scheduled for retirement in 2005 and a 25 MW minemouth plant at Healy that is assumed to be replaced in kind in 2002. The current delivered price of coal to the 20 MW plant in Fairbanks is $44.48/ton, or about $2.85/MMBTU. The current minemouth price available to the Healy plant on long-term contract is $1.30/MMBTU. The existing contract runs through 1994, For this analysis, it is assumed that a marginal price reduction will be negotiated for the Fairbanks plant yielding a delivered price of $2.50/MMBTU until the plant is retired. For the Healy plant, it is assumed that the 8549/723 - 19 - price will remain at $1.30/MMBTU (in 1986 dollars) through 1994, but will then increase to $1.60/MMBTU in 1995 and remain constant in real terms thereafter. (2) * Electricity Demand Forecast: Between 1965 and 1985, the average annual rate of increase in electricity demand in the Railbelt was 10.3%. Historical demand growth is shown in the table below: Railbelt Utility Electric Energy Generation (millions of kwh) Southcentral Fairbanks Total Year Area Area Railbelt 1965 367 120 487 1970 700 222 922 1975 1353 452 1805 1980 2112 440 2552 1985 2939 509 3448 During 1986, electric energy demand in the Railbelt was flat to declining. The most recent electricity demand forecasts 8549/723 - 20 - produced by the Railbelt utilities as of December 1986 reflect an expected average annual rate of demand growth of 1.5% over the long run. These utility forecasts were used for the present analysis, with the following three adjustments: 8549/723 1) 2) The utility forecasts cover the period 1987 - 2001. These forecasts were extended through the year 2020 by applying the average annual rate of increase indicated for the entire Railbelt through 2001. Because that average annual rate of increase was equal to 1.5%, the demand forecast used for this analysis reflects an average annual rate of increase of 1.5% for the entire period between 1987 and 2020. The forecasts provided by Chugach Electric and its wholesale customers showed an anticipated dip in demand during the mid-1990s. This was based on an earlier assumption that rate shock would occur at that time due to the expiration of old Beluga gas contracts and en that new gas prices would suddenly be encountered. Now, however, Chugach believes that rate shock can be avoided at that time by negotiating a gradual ramping in of the new price level. Consequently, the anticipated dip in demand has been leveled out for purposes of this analysis. 3) » 21 = Though the military has historically generated its own power in the Fairbanks area, consideration is being given to the purchase of power from a local utility, which would result in substantial savings to the military according to the utility's estimates. The Fairbanks utility forecast has been adjusted upward to account for this alternative. Anticipated peak requirements have been increased by 30 MW as a result. For major Railbelt studies in the past, specifically the Susitna and Bradley Lake feasibility studies, the Power Authority has produced its own electricity demand forecast in a two step process: 8549/723 1) 2) A forecast of employment, population, and households was generated by the Institute of Social and Economic Research (ISER) using their MAP econometric model. Assumptions provided to ISER by the Power Authority included oil price and State revenue scenarios. These demographic forecasts were provided as inputs to the Railbelt Electricity Demand (RED) model maintained and operated by Battelle Pacific Northwest Laboratories in Richland, Washington. The demand forecast was an output of the RED model. This modeling sequence was most recently authorized and funded by the Power Authority in 1985 in preparing a revision to the FERC license application for the Susitna project. The lowest oil price scenario specified as input to the modeling sequence was the forecast from Wharton Econometrics, which anticipated oil prices in 1985 dollars rising from $24.80 in 1990 to $31.30 in 2000, and then to $40.70 in 2010. The average annual rate of electricity demand growth for the Railbelt that emerged from this scenario was 1.7%, a factor that reflected a substantial measure of anticipated, price-induced conservation. Higher oil price inputs resulted in similar long-term demand forecasts because the economic stimulus of higher prices was, in general, compensated by the effect of higher power costs in encouraging electric energy conservation through the price elasticity mechanism. Implementation of the modeling sequence described above is time-consuming and costly, and could not have been accomplished within the constraints of the present analysis. Given the results of the modeling reported above from 1985 and the fact that electricity demand has grown at a far higher rate in the Railbelt during most of the last 25 years, an average annual rate of demand growth of 1.5% was judged to be reasonable. 8549/723 * Expansion Plan: In order to model the costs of producing electricity for a future 30 year period, it is necessary to make assumptions regarding the retirement of existing generating units and the addition of new units both for replacement and for meeting anticipated load growth. A schedule of planned retirements was obtained from earlier Railbelt studies and reconfirmed with Railbelt utility representatives. The amount of new generating capacity that was assumed to be added to the system was based on the premise that a planning reserve margin of approximately 40% would be maintained in each of the three supply centers (i.e. Kenai Peninsula, Fairbanks, and Anchorage/Beluga) in the absence of any change in the existing transmission system. A planning reserve margin of 40% means that the amount of installed capacity exceeds the annual peak demand by 40%. For most utilities in the lower 48 states, a planning reserve margin of 40% would be considered high. However, reserve margins in the Railbelt today are considerably higher than that, approximating 70% for the Railbelt as a whole. (3) Though Railbelt conditions warrant a relatively high level of reserves, it is generally agreed that evolution of the existing system has produced reserve margins today that are higher than necessary. Reserve margins for purposes of the analysis are therefore allowed to decline to a 40% level given the existing transmission system. 8549/723 Sy Transmission improvements can sometimes allow for additional sharing of reserves among regions and utilities, and consequently result in a reduction in the total amount of installed capacity required. For the present analysis, it is assumed that a new Anchorage/Kenai Peninsula line would have this effect but that an upgrade of the Anchorage/Fairbanks line would not. For purposes of reserve planning, a given load center may rely on a transmission line from another area for a certain proportion of its reserves, but typically would not rely on the line for reserves that exceed the capacity of the largest installed unit operated within that load center. The existing Anchorage/Fairbanks intertie can now provide reliable access to 70 MW of capacity, an amount that approximates the size of the largest unit in the Fairbanks area. If the transfer capability of the line were increased to a full 350 MW, the line could be relied upon for significantly greater reserve capacity only if the size of the largest generating units in the Fairbanks area were significantly larger in the future. In contrast, the proposed new line between Anchorage and the Kenai Peninsula would produce a far more reliable connection between these two areas than presently exists. As discussed in the report from Lotus Consulting Group, it was estimated 8549/723 - 25 - that the new Anchorage/Kenai Peninsula line would allow a reduction of installed reserves in the Anchorage/Beluga area from a 40% level to a 25% level, resulting in a reduction of installed capacity of approximately 100 MW relative to installed capacity required with the existing transmission system. The capacity expansion plan assumed for scenarios that include the new Anchorage/Kenai Peninsula line reflect this reduction in required installed capacity. (4) Finally, the type and location of capacity additions had to be specified for the analysis. That specification was based primarily on the following three assumptions or principles: 1) The Bradley Lake project would be complete and operational throughout the analysis period. 2) The type of capacity additions should be consistent with the fuel price forecasts adopted for the analysis. 3) Within the constraints of reserve requirements and transmission capacity, new units should be located at sites that offer the lowest costs of operation. The price level for natural gas adopted for this analysis is too low to permit effective penetration of the market by 8549/723 - 26 - coal-fired generation. As noted earlier, this does not constitute a conclusion by the Power Authority that expanded coal-fired generation in the Railbelt is implausible, but only that such expansion would be inconsistent with the fuel price scenario adopted for this specific analysis. The capacity “expansion plan" therefore entails a reduction of existing coal-fired capacity in the Fairbanks area from the current 45 MW to a single 25 MW plant at Healy. It is assumed that the Healy plant is replaced by a more efficient 25 MW coal-fired plant in the year 2002, which is the scheduled retirement date of the existing unit. All other capacity additions besides Bradley Lake are assumed to consist of oil-fired combustion turbines in the Fairbanks area and natural gas-fired combustion turbines and combined cycle units in the southcentral area. Because the price of natural gas delivered to the power plant is assumed to be lower on the Kenai Peninsula than in the Anchorage area, it was further assumed for this analysis that the existing combined cycle capacity in the Anchorage area would be replaced by new combined cycle units on the Kenai Peninsula when the existing units are retired in scenarios that include the new Anchorage/Kenai Peninsula line. Those resulting production cost savings could not be realized in the “base case" because the existing transmission limitation would not allow that relocation of plant capacity to occur. 8549/723 =~ 37 = * Transmission Limitations As noted earlier, the existing transmission line between Anchorage and the Kenai Peninsula can typically deliver about 40 MW in Soldotna given a 55 MW input on the Anchorage end of the line, due to the demands of customers along the route (e.g. Seward, Girdwood, and others) and due to transmission losses. An additional demand of approximately 5 MW is presently anticipated to occur in Seward over the next 5 years as a result of the new maximum security prison and other industrial development. Consequently, the delivery capability of 40 MW is expected to decline to about 35 MW by 1991, and to decline further thereafter to the extent that demand continues to grow along that route. Consequently, it is assumed for this analysis that the actual transfer capability of the existing line in 1991 will be 35 MW, and that such capacity will decline to 24 MW by the year 2020. In addition, the cost of energy imported over the specified transmission lines has been increased to reflect the cost of transmission losses. For example, if the transmission loss over a particular line were 5%, the effect of that loss would be to increase the cost of the delivered energy by 5%. Transmission losses for both the existing Anchorage/Fairbanks and Anchorage/Kenai Peninsula interties have been assumed to be 10%, Transmission loss between the Beluga station and 8549/723 - 28 - Anchorage has been assumed at 2%. Transmission losses for the upgraded Anchorage/Fairbanks intertie have been assumed at 4%, while 2% losses were assumed for the new Anchorage/Kenai Peninsula intertie. * Inflation and Discount Rate: A zero inflation rate is assumed for the economic analysis, and all costs are consequently expressed in terms of constant 1986 dollars. The real discount rate used for the calculation of net present value is 3.5%. Both of these are consistent with analysis parameters previously adopted by the Power Authority. Results of System Modeling Four distinct scenarios were modeled by Lotus Consulting Group: 1) Base Case: No change in existing transmission system. 2) Anchorage/Kenai Peninsula Only: A new intertie between Anchorage and the Kenai Peninsula is assumed that can transfer up to 250 MW on a reliable basis. No other change in the transmission system is assumed. 3) Anchorage/Fairbanks Upgrade Only: The existing intertie between Anchorage and Fairbanks is upgraded from its 8549/723 | present transfer capability of 70 MW to a full capability of 350 MW. No other change in the transmission system is assumed. 4) Full Railbelt Intertie Proposal: Both of the transmission improvements described above are assumed: the Anchorage/Kenai Peninsula Intertie and the Anchorage/Fairbanks upgrade. The benefits that were quantified in this analysis are defined as the reduction in system cost that occurs as a result of a given transmission improvement. For example, the quantified benefit of the full Railbelt Intertie proposal is defined as the difference in system cost between scenario #1 and scenario #4, i.e. the base case cost minus the system cost given the full Intertie proposal. As discussed in greater detail in the report from Lotus Consulting Group, the value of the benefits identified in the system modeling exercise are as follows: Sum of Benefits Net Present Value in 1986 Dollars of Benefits* _ (millions) (millions) Full Intertie Proposal $423.2 $204.6 Anchorage/Kenai Only 209.4 102.2 Anchorage/Fairbanks Only 210.6 101.2 * The base year for the net present value calculation is 1987. 8549/723 - 30 - Approximately 25% of the identified value of the Anchorage/Kenai Peninsula intertie is attributable to an estimated 100 MW of capacity cost savings made possible by reserve sharing. The other 75% of value is due primarily to siting flexibility for new plant capacity and economy interchange. It should be noted that the entire output of the Bradley Lake project is absorbed by the system in every scenario, including the base case. The effect of the intertie project on Bradley Lake would be to increase the distribution, not the amount, of Bradley Lake power sales. The identified value of the Anchorage/Fairbanks upgrade is due primarily to the increased displacement of oil-fired generation in the Fairbanks area by natural gas-fired generation from the southcentral area. The key factors that contribute to this estimate are the assumed differential between the natural gas price and the fuel oil price, and the assumed electricity demand forecast over the long run for the Fairbanks area. Other Benefits * System Reliability: Strengthening the transmission links between load centers creates a more resilient interconnected system that is better able to recover from disturbances such as the loss of a major generating unit. The existing transmission links between Anchorage and the Kenai Peninsula 8549/723 - 31 - and between Anchorage and Fairbanks will result in a separation of the three areas from one another if a significant disturbance occurs. This will usually result in the loss of load in at least two of the three areas. This separation occurs precisely at the time when it is most important to maintain the connection between areas to enable generating reserves to be transported to the area where the disturbance has occurred. A stronger interconnection between the three load centers would reduce the probability of islanding (where one area loses its interconnection with another area), and consequently reduce the probability or magnitude of an outage. * Enhanced Competition Among Fuel Suppliers: Though the magnitude of this benefit to Railbelt consumers is particularly difficult to assess, it could be one of the most significant aspects of the Intertie project. An example might help to illustrate the potential. A conservative estimate of natural gas cenwump idan For electric generation during the early years of the study period is 30 BCF per year. At $1.60 per MMBTU, the cost of that gas in 1986 dollars would be $48 million per year. If enhanced competition resulted in a reduction in the wellhead price of 5 cents per MMBTU, the annual savings in fuel cost would amount to about $1.5 million per year. Extending that benefit over the 30 year study 8549/723 =<.) = period from 1991 through 2020, the total saving achieved in this manner would be $45 million, with a present value of about $24 million. Oil and coal suppliers would be faced with similar competitive pressures. Comparison of Costs and Benefits There are two routes that are presently under consideration for a new Anchorage/Kenai Peninsula intertie. The best construction cost estimates currently available are about $76 million for one route and about $96 million for the other route. Because the construction cost is not the only consideration in route selection, a decision on a preferred route has not yet been made. For purposes of this preliminary comparison of costs and benefits, a construction cost of $86 million is assumed based on the average cost of the two routes. A study aimed at careful development of a cost estimate for the Anchorage/Fairbanks upgrade is scheduled to take place during the month of April, 1987. Until that study is complete, the best figure available continues to be a rough estimate of $100 million. Therefore, the construction cost of the full Railbelt Intertie proposal is assumed to be $186 million (in 1986 dollars) for purposes of this comparison. Further, it is assumed that these costs would be spread over a two year construction period, 8549/723 - 33 = specifically that half of the cost would be incurred in 1989 and the other half in 1990. The annual operations and maintenance (0&M) cost of a new Anchorage/Kenai Peninsula line has been estimated at 1.5% of the construction cost by the firm that performed the preliminary engineering and design of those alternatives. Applying that 1.5% factor to the estimated construction cost of the full Railbelt Intertie proposal yields an estimated annual O&M cost of about $2.8 million (in 1986 dollars). For this comparison, it is therefore assumed that a $2.8 million 0&M cost is incurred for the full project for each year between 1991 and 2020. The sum of the construction and O&M costs described above for the full Railbelt Intertie proposal is approximately $270 million (in 1986 dollars) over the period 1989 through 2020. The present value of those costs is approximately $210 million. (5) The sum of the benefits identified in the modeling exercise is therefore approximately $150 million higher (in 1986 dollars) than the sum of the estimated costs (i.e. $423 million in benefits vs. $270 million in costs). However, because most of the costs are incurred before most of the identified benefits are realized, the present value of costs and identified benefits are approximately the same. If the benefits not captured in the modeling exercise 8549/723 = 34 - were brought into this comparison, then the present value of benefits would exceed the present value of costs. As stated earlier, the goal of this study was to produce an understanding of the benefits of both transmission proposals sufficient to judge whether they are promising with regard to economic feasibility criteria. On the basis of the analysis performed, it is concluded that the proposed transmission projects are capable of delivering economic benefits in excess of their costs, and consequently warrant further consideration. 8549/723 =5/135| = FOOTNOTES (1) It is recognized that Chugach Electric Association, which operates the Beluga generating station, still has access to significant quantities of old gas at Beluga at prices in the vicinity of $ .30 per MMBTU. In the initial modeling runs performed for this study, the Beluga gas price (in 1986 dollars) was assumed to ramp up from $1.04/MMBTU in 1991 to $1.60/MMBTU in 2003, remaining constant at $1.60 thereafter. The price prior to 2003 represented a blend of old and new gas with a declining proportion of old. It was assumed that gas at the blended price was available to generate power for economy sales to other utilities, though such sales to Anchorage Municipal Light and Power (AML&P) were limited by forcing the AML&P units to run. (AML&P operates most of the “Anchorage area" generating capacity.) The basis for this constraint was the Chugach policy of reserving its limited supply of old gas for the benefit of its own customers. In the final modeling runs, however, the Beluga gas price (in 1986 dollars) was assumed to be $1.60 in 1991 and to remain constant in real terms thereafter. By ignoring the declining quantities of old gas, production costs are overestimated for the early years of the study, but are 8549/723 = 365 overestimated equally in the base case (with the existing transmission system) and in the alternate case (with the improved transmission system). The benefit of ignoring the old gas for purposes of the modeling is that the price of energy for economy sales from Beluga will always reflect the price of new gas at $1.60, which is more realistic than the assumption used initially. By assuring that economy sales from Beluga will be based only on the new gas price, it became possible to remove the “must run" requirement for the AML&P units. Further, the analysis incorporates the assumption that natural gas will be available in sufficient quantities at wellhead prices at Beluga and on the Kenai Peninsula, and at wellhead plus transportation in Anchorage, to meet all estimated demands at these locations through the year 2020. Variations regarding the natural gas supply assumption could produce alternative patterns of use for the proposed transmission projects. (2) The estimated increase in the minemouth price to $1.60/MMBTU for the Healy plant in 1995 is based on the following observations: 1) The current minemouth price for coal paid by 8549/723 2) 3) - 37 - Fairbanks Municipal Utility System is $34.48 per ton, which is approximately $2.20/MMBTU. The current minemouth price for coal paid by the U.S. military at Fort Wainwright is $31.79 per ton, which is approximately $2.05/MMBTU. The prices noted above were recently negotiated, and suggest that the price of coal for the Healy power plant will be subject to upward pressure when the current contract expires. However, particularly as a result of the Anchorage/Fairbanks intertie, the extent of such increase will be limited by competition. The assumption of a moderate increase was therefore adopted in balancing these considerations. (3) The high existing reserve margins in the Railbelt are, in large part, due to the more hostile operating environment, the relatively large size of certain generating resources with respect to the loads of the individual systems, and the limited extent of interconnection among the utilities. Most of the existing generating capacity was installed prior to the construction of the Anchorage/Fairbanks intertie and also before the establishment of a high capacity interconnection 8549/723 (4) (5) oa Mo in Anchorage between Chugach Electric and Municipal Light and Power. Mild winters in recent years have also contributed to the appearance of high reserve margins. Although the reserve margins used in this analysis are considered reasonable for modeling purposes, actual reserve requirements may well depart from these general estimates according to the specific determinations and judgments of the utilities. For clarification, costs of the Intertie proposal were estimated as follows: cost YEAR (Millions of 1986 Dollars) 1989 $ 93.0 Construction 1990 93.0 Cost = $186 million 1991 2.8 1992 200 O&M Cost = ‘ $2.8 million / year . for 30 years 2020 2.8 (Net Present Value = TOTAL $ 270.0 $209.8 million) 8549/723 Figure 1. (A) BELUGA PLANT BERNICE LAKE AND SOLDOTNA PLANTS © BRADLEY LAKE PROJECT (D) TEELAND SUBSTATION =—~ Proposed Alternate Routes for Anchorage/Kenai Peninsula Intertie ===-= New line to be built by Homer Electric Assoc. Palmer Anchorage Railbelt Transmission Alternatives Assessment Final Report March 31, 1987 Prepared For The Alaska Power Authority Anchorage, Alaska Prepared By Lotus Consulting Group 4962 El Camino Real, Suite 112 Los Altos, CA 94022 Richard Albert Jon Fatula Executive Summary The Alaska Power Authority (APA) contracted with Lotus Consulting Group to evaluate the benefits of alternative transmission configurations within the Alaska Railbelt region. The multi-area study was conducted using Lotus Consulting Group’s proprietry software progam UPLAN. Based on data supplied by APA, the model determined the savings in production costs and capacity deferrals associated with the specified improvements to the transmission network. The sum of the benefits identified over the 30 year planning horizon is $423 million (expressed in 1986 dollars), with a net present value of $205 million dollars. This result was based on increasing the interconnection between the Kenai Peninsula and Anchorage from 35 MW to 250 MW, and between Anchorage and Fairbanks from 70 MW to 350 Mw. These improvements allow for increased purchase of economy energy and the relocation of future generating resources to the Kenai Peninsula to take advantage of favorably priced natural gas. In addition, by creating an opportunity for reserve sharing between the Kenai Peninsula and Anchorage, the improvements allow deferral of 100 MW of new installed capacity in the Anchorage area. The system modeling further indicates that the identified benefits are attributable to each of the two transmission proposals in nearly equal proportions. Construction of only the new intertie between the Kenai Peninsula and Anchorage produced benefits with a net present value of $102 million dollars, while the net present value of benefits identified for the Anchorage/Fairbanks upgrade considered separately were $101 million dollars. Railbelt Transmission Alternatives Lotus Consulting Group Contents Ve ntact en ayia Se arias talc ool ria ete esi her's! bie on be eee ies wide e 1 2. Overview of Methodology... 1.0... . 0. ce eee eee eee eee 2 3: Data Overview wo ie sie 6 is. ol ie f6 colt 6 (8 coite io. ain a lorie) oi wllal at ice lai ol tol 7 3.1. Supply Side Representation. ......... cc cee scseeee 7 3.2. Demand Side Representation... ....... 0. cece eee eee 8 3.3. Interconnection Representation. .......... 0.0 e ee eae 10 4. Base Case Development and Benchmarking...............000- 11 S: Reserve: Sharing: 5) ote Jot ce fatoer ola: ta lal trtat fol tte 16) tilis o b ello lief fl dar ot 12 6. Alternative Scenerio Simulation Results. ............ 002 eee 13 7. summary and’ Conclusions 4.5/4 ie. s ie spss 06 tol ol wo tel lei ww total oe te tens 16 8. Appendices 8.1. Description of the UPLAN Model 8.2. Supply Input Data Sets 8.3. Load Data Sets 8.4. Production Cost Results Railbelt Transmission Alternatives Lotus Consulting Group 1, Introduction In this report, we describe the data and methodology used to estimate the economic benefits associated with an increase in the transfer capability of the intertie connecting the Anchorage, Fairbanks and Kenai Peninsula regions of the Alaska Railbelt. A 30-year base case and alternative cases with expanded transmission capacities were analyzed. The Alaska Power Authority has identified the goal of the study as the assessment of the benefits from improving the transmission network to provide for the increased integration of the Railbelt region. The benefits captured in the system | modeling described in this report accrue from the increased opportunity for economy interchange, reduced capacity requirements through reserve sharing and increased system efficiency due to reduced transmission losses. This report consists of three major sections. The first section describes the methodological foundations of the study and the data and assumptions from which the base case simulations for the region were developed. This first section includes Chapters 1 through 4. Chapters 5 and 6 make up the second major division of the report. These chapters describe the three alternative scenarios which were evaluated. For each scenario, the major assumptions made and results obtained are presented. Chapter 7 presents the overall results of the Railbelt Transmission assessment and our conclusions concerning the results. The report concludes with a set of appendices, in which listings of the major input and output data sets from the simulations are provided for reference, along with a description of the UPLAN planning model. Railbelt Transmission Alternatives -1- Lotus Consulting Group 2. Overview of Methodology The basic outline of the existing Railbelt system is shown schematically in Figure 1. The system as modeled consists of 3 supply/demand nodes connected by bidirectional interties with known transfer capacity. Within the area covered by each node, no transmission limitations exist. Each node is modeled to serve its own local demand from its own generating resources with first priority, and will supply economy energy to the network only from excess energy available after satisfying local demand. Figure 2 shows a typical three system network. In this network, a terminal node is a node tied to exactly one other node: nodes A and C are terminal nodes. An interior node is a node connected to two other nodes: system B is the only interior node in this network. For each node, we need the supply, financial, and load shape data normally required to model the node as an isolated system. For each scenario, we analyze the network iteratively, beginning each solution from an opposite terminal node. The method consists of the following steps: 1) Starting with a terminal node, estimate its potential economy energy exports to its connecting node, given the intertie capacity and the export demand shape as seen through the intertie. The net profile for sales demand is the minimum of either the intertie capacity limit or the load shape of the connected node. 2) Transform the resulting potential energy export to one or more equivalent, capacity-factor limited purchase resource units, and add the unit(s) to the supply resources of the interconnected interior node. Lotus Consulting Group -2- Railbelt Transmission Alternatives Figure 1. Existing Transmission Capacity Fairbanks 70 mW capacity 138 kV High reliability Anchorage 55 mW capacity 115 KV Low reliability Kenal Peninsula Railbelt Transmission Alternatives -3- Lotus Consulting Group Figure 2. Simplified Network Topology Load/Supply Center C Load/Supply Center B Load/Supply Center A Lotus Consulting Group -4- Railbelt Transmission Alternatives 3) For the interior node, estimate its own production costs and potential exports to the next node, using its own generation and the purchase resources of the previous node. The potential exports will include any wheeled energy, ie. energy available from the previous node, not dispatched against the current node’s native demand, and available for dispatch against the next node’s net profile for sales demand. 4) Repeat step 3 for each interior node until the terminal node in the series is reached. For the terminal node, no potential export energy is estimated: its own production costs are estimated using the economy purchase units from the previous node. 5) Redo the analysis in the reverse direction, this time starting with final terminal node examined in the previous step. The final simulation in this series will estimate the own production costs of the original starting node analyzed in step 1, using available purchase resources from the other direction. 6) Compare the forward and the reverse solutions, and resolve any conflicts in intertie usage, either by repeating the process with the previous round of economy interchange data or revising the size and cost of the equivalent purchase economy units in the appropriate node. For the network of Figure 2, the process would involve six production cost simulations. The following table shows the demands, supply systems, and results obtained from each of the six: Railbelt Transmission Alternatives -5- Lotus Consulting Group Native 2nd Area Supply Case Load Load Resources Result 1 A B A Potential exports from A (A*) 2 B Cc B+A* 1. Bcosts with A* purchases 2. Potential exports to C from A and B (B*) 3 Cc none C+B* Ccosts with B* purchases 4 Cc B Gc Potential exports from C (C*) 5 B A B+C* 1. Bcosts with C* purchases 2. Potential exports to A from B and C (B#) 6 A none A+B# Acosts with B# purchases In general, another run for area B with potential purchase from both A and C may be necessary. In this study the operating costs of Fairbanks, which will be modeled as area C, are higher than anything in Anchorage and no sales will occur from Fairbanks to Anchorage. The application of the methodology can be readily automated using the simulation capabilities of UPLAN. From the end-use demand model the net hourly load profile of the sales demand for the connecting node is constructed on a chronological basis. This profile is used in a two area monthly production simulation and UPLAN automatically determines the surplus energy and associated costs available for interchange. This information is converted into equivalent monthly constrained availabilities for economy purchase units in the connecting node to determine the area absorption. Lotus Consulting Group -6- Railbelt Transmission Alternatives 3. DATA OVERVIEW 3.1 Supply Side Representation General Basic technical and operating data for all generating units was obtained from the Alaska Power Authority and is shown in the Appendix, Section 8.2. Unit level cost data reported in 1985 dollars was escalated by 2% to yield 1986 base year dollars for study purposes. Maintenance outages were modeled using the APA values for planned outage rates, and the timing of unit maintenance followed that reported in earlier Alaska Power Authority studies. The Anchorage supply center consists of all generating units operated by Anchorage Municipal Light and Power (AMLP), the Beluga and International units of Chugach Electric Association, and the Eklutna Hydro project of the Alaska Power Administration. For this study, all units were coordinated with the area requirements and dispatched on strictly economic ordering. The Kenai Peninsula supply center includes the Bradley Lake and Cooper Lake hydro projects, and the thermal units at Soldotna, Seldovia, and Seward. It is assumed that the Bradley Lake unit will be available and on-line in 1991, and that it will operate at $0 variable 08&M costs. The Fairbanks supply center includes all ‘capacity owned by the Fairbanks Municipal Utility System and Golden Valley Electric Association. These units include Chena Units 5 and 6, FMUS IC units 1-3, Healy steam and IC units, and the North Pole, Zendher, and Diesel IC units operated by Golden Valley. It is assumed that the Chena units 1 through 4 will not be operated over the study period due to environmental constraints. Railbelt Transmission Alternatives -7- Lotus Consulting Group For the base case, planning reserve margin for all regions was established 40%. The Kenai center was modeled with committment levels for fossil units to provide frequency control. This amounts to an operating reserve require of approximately 25 MW. Fuel Prices All prices, costs and revenues in the study are reported in 1986 constant dollars. Wellhead gas prices are assumed identical throughout the Cook inlet area. A wellhead gas price of $1.60/MMBTU is assumed, with no real escalation over the study period. Delivered prices of gas are assumed to vary across the region. Gas delivered to Anchorage is priced at wellhead plus 60 centssMMBTU for pipeline transportation. On the Kenai Peninsula and at Beluga, gas is priced wellhead. Coal delivered to the Healy Station of GVEA is priced at $1.30/MMBTU through 1994, and at $1.60/MMBTU thereafter. Coal delivered to Fairbanks MUS is priced at $2.50/MMBTU. Fuel oil prices are chosen to be consistent with a crude oil price of $20 per barrel. #4 Fuel oil is priced at $3.40/MMBTU, and diesel fuel is priced at $5.00/MMBTU for all sites except Seldovia, where diesel is priced at $7.00/MMBTU. 3.2. Demand Side Representation Fairbanks load center is modeled as the combined loads of Fairbanks Municipal Utility System and Golden Valley Electric Association. In addition, 30 MW was added to the Fairbanks peak load over the complete study period, 1991- Lotus Consulting Group -8- Railbelt Transmission Alternatives 2020, with no change in Fairbanks load factor to accommodate the assumption that military loads in the future will be served by Fairbanks utilities. Anchorage load center is modeled as the combined loads of Anchorage Municipal Light and Power, Chugach retail demand, and Matanuska demand. The Kenai Peninsula load center is modeled as the combined loads of the City of Seward and the Homer Electric Association. To this is added an 8 MW incremental demand, representing northern Kenai Peninsula customers with demand characteristics identical to Anchorage demand. This increment is escalated at the same rate as AMLP demand. Hourly load shapes were developed for two regions: Anchorage and Fairbanks. It is assumed that the hourly load shape of the Anchorage and Kenai Peninsula regions will be the same. Hourly loads were developed from information provided by APA for the years 1982 and 1983. Three distinct representative seasonal weekly load shapes were developed for each region: a winter shape, a summer shape, and a transitional Spring/Fall shape. These representative shapes were assigned to individual months, and adjusted to match the month-by-month peak and energy fractions reported in Table 8.3.1, Statement of Power Needs and Utilization, provided by the Power Authority. For the 1991-2010 period, three separate annual load shapes were employed for each region. The first was used for the 1990-95 period, the second for 1996-2000 period, and the final for the 2001-2020 period. Annual peak load and energy forecasts were based on Table 8.3.2 Total Railbelt Energy Requirements, which summarizes the load forecasts prepared by the Railbelt utilities. To estimate total busbar energy requirements, the system losses reported separately for Chugach Electric Association were rolled back into their reported sources on the basis of a 2.9% transmission loss associated with sales to Homer, Seward, and Matanuska, and 13.88% loss associated with retail sales. Railbelt Transmission Alternatives -9- Lotus Consulting Group Peak demand and energy estimates for the 1993 to 2000 period were adjusted from their tabulated values for Homer, Matanuska, and Chugach to reflect an unchanging year-to-year energy and peak demand forecast, rather than the sharp 1994-95 decline in peak and energy reported in Table 8.3.2. For the period from 2002 to 2020, peak demand and energy are assumed to grow at the rate of 1.5% per year for all regions. The annual peak demand and energy forecast used in the analysis for all three regions are shown in Table 8.3.3 in the Appendix, Section 8.3. 3.3. Interconnection Representation: Base Case As shown in Figure 1, the current capacity of the connection between Anchorage and the Kenai Peninsula is 55 MW. However, due primarily to the demands of customers along the route, the assumed transfer capability of the line from one end to the other is set at 35 MW in 1991. This capacity is assumed to decline from 35 MW to 24 MW over the 30 year study period due to the increasing requirement of the Seward area. The existing line from Anchorage to Fairbanks has a transfer capacity of 70 MW. In addition to the capacity limitations, transmission losses were included. The transmission loss factors between the Kenai Peninsula and Anchorage and between Anchorage and Fairbanks are assumed to be 10% in the base: case. Also, average transmission losses of 2% were assumed between Beluga and the Anchorage load center. These factors were used to increase the perceived cost of the purchase energy and factored into the valuation of the economic absorption of sales. Lotus Consulting Group - 10- Railbelt Transmission Alternatives 4, Base Case Development and Benchmarking Generation capacity plans were developed for each supply center. It was assumed that the Anchorage area stations will retire their current capacities over the study period and expand the resources in keeping with the needs of the Anchorage area. For the Anchorage and Kenai Peninsula Regions, all new capacity consisted of gas-fired CTs and combined cycle units at $400/KW and $650/KW, respectively. In Fairbanks it was assumed the current Healy unit will be replaced with a new coal-fired unit. All other new capacity for Fairbanks consisted of oil-fired CTs at $400/KW. For the period 1991-2020, the base case capacity was expanded to meet a reserve margin requirement of 40%. Table 1 shows the supply resources used in the UPLAN simulations for the Kenai Peninsula. Table 2 shows the associated reserve margins over the planning horizon. Tables 3 and 4 show the same for Fairbanks and Tables 5 and 6 for Anchorage. UPLAN was run for the 30 year planning period of 1991 to 2020 following the methodology of Chapter 2. The total production costs for each area and the region as a whole are shown in Table 7. Detailed results for four selected years from these simulations are shown in Tables 8 through 19. Tables 8 to 11 present the annual total and unit operations in the Fairbanks area for 1991, 1996, 2006 and 2015. Tables 12 to 15 show the same results for the Kenai Peninsula and Tables 16 to 19 for Anchorage. The simulation results were nominally compared to previous simulations produced by other APA consultants, and are consistent within the differences in load and resource assumptions between the two runs. In the base case results, Fairbanks is basically the main importer of energy. There is some interchange being conducted within the Anchorage area with Railbelt Transmission Alternatives -ll- Lotus Consulting Group generation from Beluga serving some of the load belonging to AMLP thereby displacing the output of the AMLP units, but this interaction has not been quantified for this study. 5. Reserve Sharing Prior to performing the final simulations for the complete 30 year planning study, a series of single year studies was done to evaluate the characteristics of the region. The main outcome of these studies was the setting of the reserve sharing level in the Anchorage-Kenai Peninsula region. The Anchorage expansion for the alternate case was revised to reflect reserve sharing between the Anchorage and the Kenai Peninsula regions. . The estimation methodology was to calculate the index of reliability for Anchorage and the Kenai Peninsula as isolated areas. The index of reliability used in UPLAN is Loss of Load Probability (LOLP) as reported in days/year. This statistic is calculated by determining the probability of the load exceeding the capacity during any hour of the simulation period. For this study, only a single year was evaluated: the year chosen was 2016. Tables 20 and 21 present the reliability simulation of these areas as isolated systems. The Anchorage area shows an index of reliabiliy of 0.056 days per year. The Kenai.Peninsula area has an index of reliability of 0.088 days per year. The joint reliability of the two isolated systems is therefore 0.144 days per year. Table 22 shows Anchorage/Kenai Peninsuls as an interconnected area sharing reserves. By removing 110 MW of installed capacity from this combined system, the reliability index rises from 0.002 to 0.115 as shown in Table 23. This level is considered equivalent to the combination of the two isolated systems and no further capacity was removed. Note that all capacity removed from the expansion Lotus Consulting Group -12- Railbelt Transmission Alternatives plan was associated with the Anchorage area. This build-down corresponds to a 25% planning reserve margin in Anchorage. 6. Alternate Scenario Simulation Results For the alternate cases, the intertie transfer capacities are set to 250 MW for the Anchorage/Kenai Peninsula line, and 350 MW for the Anchorage/Fairbanks line. The transmission loss factors were reduced from 10% to 2% for the Anchorage/Kenai Peninsula intertie and from 10% to 4% for the Anchorage/Fairbanks intertie. This is reflected in lower costs for the economy energy interchange and represents an additional potential benefit to the region. In the alternate case, planning reserve margin for the Kenai Peninsula and Fairbanks areas are still modeled at 40%. However, the alternate case planning reserve margin for Anchorage was reduced to 25%, as discussed in the previous section. Table 24 shows the revised Anchorage supply resources for the alternate case. Table 25 presents the associated reserve margins. Unit committment for frequency control was discontinued on the Kenai Peninsula. It is assumed for purposes of this analysis that the replacement unit for Anchorage combined cycle capacity retired in 1999 is located on the Kenai Peninsula, where access is gained to natural gas priced at the assumed wellhead value. The Kenai Peninsula and Anchorage are modeled as a single, jointly dispatched supply/demand area with no effective transmission limitations in scenarios that include the new Anchorage/Kenai Peninsula line. (The single year run described earlier indicated that no significant transmission constraint existed in these alternative intertie cases and no change in the methodology described in Chapter 2 is necessary to achieve the same results. This results in a significant savings in computational requirements without any loss of accuracy. Although the installation of an additional Railbelt Transmission Alternatives - 13- Lotus Consulting Group 180 MW of combined cycle capacity on the Kenai Peninsula appears to create a surplus capacity of more than 250 MW during off-peak hours in the off-peak season, the capacity of the Kenai Peninsula hydro projects will be significantly discounted because of limited water availability at the same time. As a result, sufficient line capacity will be open during these time periods.) , UPLAN runs were made of the alternate case with increased tie lines and revised resources following the same procedure as the base case. Tables 26 through 33 show the detailed results for the four same years as are shown for the base case. Tables 26 to 29 present the production simulations for Fairbanks for 1991, 1996, 2006 and 2015. Tables 30 to 33 show the results for the Anchorage-Kenai areas as operated under the joint dispatch assumption for the same years. By way of comparison, Table 34 shows the production simulation in the Fairbanks area for the year 2006 for the base case and the alternate case. In this year there is an operating savings of around 8.6 million dollars. This savings is achieved because of the increased availability of economy energy and the lower cost of the purchase power. Around 1 million dollars is gained from the lower average cost of purchase power and from the increased reliability provided by the larger intertie. However, the bulk of the savings (7.6 million) comes from the ability to import an additional 430 GWH at an incremental savings of about 18 $/mwh. The savings in the Anchorage-Kenai production costs are around 5.5 million dollars for the same year, 2006. Table 35 repeats the base case results for Anchorage and Kenai in 2006 for comparison to Table 32. The components of the savings are slightly more complicated to see. The dominant effect in the region is the availability of low cost energy out of the combined cycle unit located on the Kenai Peninsula and using wellhead gas for fuel. There is a savings of around 1 million dollars from relaxing the operating reserve requirement for frequency control and from the serving of some Kenai Peninsula load out of the new combined cycle unit at an incremental Lotus Consulting Group - 14- Railbelt Transmission Alternatives savings of 3.5 $/mwh. The remaining 4.5 million dollars savings occurs in the Anchorage area by having available an additional 1200 GWH of energy from the new combined cyle unit at an average production savings of around 3.8 $/mwh. Using the same assumptions of the alternate case, two additional studies were performed using UPLAN to evaluate the incremental benefits of the upgrading of each intertie separately. The results of these runs are similar to the alternate case and are contained in the Appendix. Railbelt Transmission Alternatives -15- Lotus Consulting Group 7. Summary and Conclusions Tables 36 through 38 show the complete comparisons of the various scenarios. Table 36 presents the production operating savings and capacity deferral savings between the base case and the alternate case. The capacity benefit is calculated by crediting the savings with the amortized capital costs of the deleted units over a 20 year period at a real interest rate of 3.5%. The units removed from the resource plan in the alternate case are the new 50 MW Beluga CT unit scheduled to be installed in 1994 and the new 50 MW AMLP CT unit scheduled for installation in 2007. This amounts to a savings of over 50 million dollars over the 30 year planning horizon. The savings in operating costs are 372.5 million dollars giving a total savings of 423 million dollars. The net present value of this savings discounted back to 1987 at a discount rate of 3.5% is 205 million dollars. Because no inflation was used in the study, these values are in 1986 dollars. Table 37 shows the same comparative information for the savings achieved by upgrading only the Kenai Peninsula to Anchorage tie. The net present value of savings is 102 million dollars. Finally, Table 38 presents the savings from upgrading only the Anchorage to Fairbanks intertie. In this case, the net present value is 101 million dollars. Lotus Consulting Group - 16- Railbelt Transmission Alternatives Table 1 - Kenai Supply Model RNM fi le:c:KENAALL .RNM-kenad load 1991-2020 Supply file:c:kenairsa.SPM-Kenai Supply Model Onis: Lio. Unit Unit Size Number Date Unit Lb Name (MW) of Installed Life Units CYeEs. 2 (Yrs.) bern bernice2 18 1 1971 26 bern bernice3 27 1 1978 26 bern bernice4 27 1 1981 23 brad bradleyH 90 1 1990 65 coop cooper H 18 1 1975 39 gtk soldatcT 38 1 1985 25) sldi seldic2 A i 1964 99) sldi seldic34 1 1 1970 99 ses seward3s 2 1 1965 9S ses seward4 a 1 1985 99 ses sewards 3 1 1986 99 ses sewardé 3 2 1990 99 new new ctl 40 1 2004 20 new new ct2 40 1 2010 20 new new ct3 25 1 2014 25 Railbelt Transmission Alternatives -17- Lotus Consulting Group Year 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Lotus Consulting Group Peak (MW ) 116 117, LS) 119 LD 11g 119 120 120 120 121 123 ld) 126 Table 2 - Kenai Reserve Margins Capacity and Reserve Margin Reserve Reserve Margin System Load Capacity Margin Exc.Pur Exc. Pur (MW ) (%) 230 98.962 230 96.749 230 93.766 230 935.115 230 92.953 230 92.791 212. 77.554 212 Ti 3258 eli2) 76.962 212 76.667 ie, 75.497 212 72.920 212 70.281 198 56.770 198 54.446 128 Inc. Pur (%) 98: 96. 93. 93. 295s 92; -554 Wis 76. 76. 75 Te. -281 sé. S54. 92 Ue 70 962 749 766 TIS 791 258 962 667 497 920 770 446 -18- Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Peak System Reserve load Capacity Margin Exe.Pur Exc. Pur (MW) 130 132 135 136 138 140 142 144 147 149 151 153 156 158 160 (MW) 198 198 198 198 200 200 200 200 225 225 225 225 225 225 225 (%) SZ 4198 49.886 47.103 45.588 44.823 42.653 40.548 38.504 53.479 Siz210) 49.007 46.771 44.602 42.495 40.362 Reserve Margin Inc. Pur (%) S221 911 49.886 47.103 45.588 44.823 42.653 40.548 38.504 53479 Si i210 49.007 46.771 44.602 42.495 40.362 Railbelt Transmission Alternatives Table 3 - Fairbanks Supply Model RNM file:c:FATRAL | RNM-fairbanks native demand 1991-2020: +30 MW Supply file:e:fairrsa.SPM-Fairbanks Supply Model Units 1-15 Unit Unit Size Number Date Unit [> Name (MW) of Installed Life Unite (Yrs ) (Yrs) chen ChenaSsTs 20 1 1970 35 Chen ChenaSTé 26 iE 1976 30 Fmus Fmusic 1 3 l L967 25 Fmus Fmusic 2 3 1 1967 ZS. Fmus Fmusic 3 3 a 1967 25 Heal HealySTl 25 1 1967 35) Heal HealyIC2 3 1 1967 30 Nopo NoPolCTl 61 1 1976 30 Nopo NoPolCT2 61 1 LOT? 30 Zen Zender 1 18 iL 1971 30 Zen Zender 2 18 1 1972 30 Dsll DslIC 1 2 if 1961 30 DslI DslIC 2 2 i 1961 30 DslI DslIC 3 2 1 1961 30 Osll DslIc 5 3 1 1970 30 RNM file:c:FAIRALL .RNM-fairbanks native demand 1991-2020: +30 MW Supply file:c:fairrsa.SPM-Fairbanks Supply Model Units 16-30 Unit Unit Size Number Date Unit ID Name (MW) of Installed Life Units CY¥ES=) CY¥rs=) Ds1I DslIC 6 3 1 1970 30 UAFI UAFIC 7 3 1 1970 26 UAFI UAFIC 8 3 1 1970 26 NewH NewHeST1 ZS) 1 2002 35S NewF NEWFCT A 25 1 1992 30 NewF NEWFCT B 25 i 2002 30 NewF NEWFCT 1 2S a 1996 30 NewF NEWFCT 2 25 1 1999 30 NewF NEWFCT 3 ZS. 1 2001 30 NewF NEWFCT 4 50 1 2005 30 NewF NEWFCT S 70 1 2006 30 NewF NEWFCT 6 70 1 2007 30 NewF NEWFCT 7 30 1 2010 30 NewF NEWFCT 8 30 1 2016 30 Railbelt Transmission Alternatives -19- Lotus Consulting Group Year 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005S Peak System Table 4 - Fairbanks Reserve Margins Capacity and Reserve Margin Reserve Load Capacity Margin Exc. Pur Exe. Pur (MW) 176 180 184 189 193 197, 202 207 212 2A, 222 ees 228 231 234 (MW) 255 269 269 269 269 288 285 285 310 304 311 318 318 318 348 Lotus Consulting Group (%) 43.587 do279 45.958 42.630 39.378 45.897. 412019 37.814 46.503 40.286 40.216 41.522 eo 719 37.901 48.973 Reserve Margin Inc. Pur (%) 43.587 ao 279 45.958 42.630 39.378 45.897 41.019 37.814 46.503 40.286 40.216 42.522 SIatl9 37 590K 48.973 -20- Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Peak load Capacity (MW) 237 240 243 246 249 253 256 259 263 266 270 273 ar? 281 285 System Reserve Margin Exc.Pur Exec. Pur (MW) (%) 331 39.899: 340 41.844 340 39.975 340 38.155 370 48.416 370 46.477 370 44.588 370 42.692 370 40.791 370 38.941 400 48.258 400 46.306 400 44.404 400 42.501 400 40.598 Reserve Mar Inc ( So: 41; aos 38. 48. 46. 44 42. 40. 38. 48. 46. 44. 42. 40. Railbelt Transmission Alternatives gin 2 Pur %) 899 B44 975 155 416 477 - 588 692 oA 941 258 306 404 sol 598 Table 5 - Anchorage Supply Model RNM file:c:ANCHALL .RNM-anchoraage load 1991-2020 Supply file:c:anchrsa.SPM-Anchorage Supply Model Units t=i5 Unit Unit Size Number Date Unit ID Name (MW) of Installed Life Units (Yrs) CYS) EKLU EklutnaH 30 1 FOSS 99 AML P Anc CT 1 16 1 1962 Ze) AMLP Anc CT 2 16 1 1964 25 AMLP Anc CT 3 20 at 1968 23 AMLP Anc CT 4 34 1 1972 20 AM C Anc CCS6 48 ak 1979 20 AM C Anc CC76 109 if LOTS 20 AML P Anc CT 8 87 1: 1984 25 AMLP Anc CT 9 87 a 2050 38 Bel BelugCT1 16 1 1968 26 Bel BelugCT2 16 1 1968 26 Bel BelugCT3 50 i 1972 27, Bel BelugCT4 10 i 1976 20 Bel BelugCTS 67 1 1975 24 Belc BelgCCé6é8 101 a 1976 31 RNM file:c:ANCHALL .~.RNM-anchorage load 1991-2020 Supply file:c:anchrsa.SPM-Anchorage Supply Model Units 16-30 Unit Unit Size Number Date Unit ID Name CMW) of Installed Life Units (Yrs.) CESS) belg BelgCC78 101 iz 1976 31 Int IntncT1 14 1 1965 31 Int IntncT2 14 1 1968 28 Int IntncT3 20 2 1970 26 NewC New CC76 180 1 1999 2S New8 NewBCT 3 sO 1 1994 27 NewB NewBCT 4 so 1 1996 20 NewB New8CT 5S 67 1 1999 25 NewB New8CT 6 50 1 1999 25 New8 New8CC68 101 1 2007 Si. NewB New8CC78 101 iL 2007 ot NewC New CT10 so | 2007 25 NewC New CT11 87 1 2009 2s NewC New CT12 50 1 2015 25 NewC New CT13 50 1 2018 25 NwBC New8CT14 50 1 2002 25 Nw8C New8CT15 so 1 Zot, 2s Railbelt Transmission Alternatives -21- Lotus Consulting Group Year 1997, 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005S Peak System Table 6 - Anchorage Reserve Margins Capacity and Reserve Margin Reserve Load Capacity Margin Exc.Pur Exc. Pur (MW) 459 464 474 484 486 488 490 494 499 506 515 523 531 539 547 (MW) TAZ 683 683 701 701 693 693 693 716 716 716 766 766 766 766 Lotus Consulting Group (%) 56.209 47.325 44.245 44.835 44.209 42.037 41.313 40.312 43.631 41.502 39.002 46.519 44.338 42.221 40.113 Reserve Margin Inc. Pur (%) 56. 209 47.325 44.245 44.835 44.209 42.037 41.313 40.312 43.631 41.502 39.002 46.519 44.338 G@2-221. 40.113 -22- Year Peak load (MW) 2006 SSS 2007 563 2008 S72 2009 sso 2010 S89 2011 598 2012 607 2013 616 2014 625 2015 635 2016 644 2017 654 2018 673 2019 684 2020 694 System Reserve Capacity Margin Exc.Pur Exc.Pur CMW ) 766 816 816 816 816 866 866 B66 866 916 916 916 966 966 966 (%) 38.043 44.886 42.732 40.617 38.540 44.865 42.716 40.607 38.538 44.366 42.236 40.125 43.451 41.331 39.233 Reserve Margin Inc. Pur (%) 38.043 44.886 42.732 40.617 38.540 44.865 42.716 40.607 38.538 44.366 42.236 40.125 43.451 4tesst SIE2SS Railbelt Transmission Alternatives Table 7 Base Case Production Costs (Mill Year L991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Kenai 8.46 8.61 8.82 8.86 8.87 8.88 S77 8.79 S-75 8.78 8.88 8.84 9209 8.34 6255 8.76 8.98 9226 9.42 Seal 952 DTS S95 10.41 10.64 10.86 Alia} 11.33 11.56 11.80 Railbelt Transmission Alternatives Anchor 58.70 58.98 60.35 60.67 60.94 59°87. 60.18 60.62 59.45 60.31 62-77. 63.79 64.71 65.63 66.59 67 7S6 67.96 68.97 69.65 70.65 71.84 72.90 73.98 75.06 76.60 Vid he, 78.88 81.68 82.91 84.16 -23- Fairbnk 32.47 33.60 34.56 34.88 35-79 36.21 S7e19 38.19 37-75 38.87 39.78 38.87 39-50 40.14 39-93 40.36 41.44 42.20 42.93 43.84 44.14 44.92 45.72 46.51 47.33 48.43 49.30 50.24 51.14 52.09 $) Total 99.63 101.19 103.73 104.41 105.60 104.96 106.14 107.60 108-95 107.96 111.43 111.50 113.30 Lug EUS 07 116.68 118.38 120.43 122.00 123.80 125.50 L27.55 129565 131.98 134.57 137.01 139.28 143.25 145.61 148.05 Lotus Consulting Group Table 8 - 1991 Base Case Production Operation in Fairbanks Detail report:a:FRASFAOL .OTL 3-17-1987 Page 1 RNM file:c:FAIRALL .RNM-fairbanks native demand 1991-2020: +30 MW Supply file:c:FBASFE4OL .SPM-fairbanks basea case supply 40% prm 25 mw healy e97 SYSTEM REPORT FOR YEAR 1991 ENERGY (GWH) RELIABILITY COSTS(M$ ) Demand 937266 PK Load (MW) T7620 Fix O&M 4.78 Unserve O=5it Variable Lée 7S Net. Gen. 937-15) Unserved G205 Storage 0.00 Fuel LOEI2 Total Gen DS7ealS LOLP (Dys/Yr) 0.000 Total 32.47 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor ( GWH ) Variable Fuel Cost Total $/(MWH) HealyST1 Sits10 19952. 835.97 Soo2-79 4168.76 20.89 ChenaSTS $6.92 99572 65-12 3747.25) SOl2ZcS7 38.23 TIEPURSIL 89.74 550.28 15697.81 0.00 15697 .81 20.55) NoPolCTl 15.95 85.23 124.18 3730.70 3854.88 45.23 NoPolCT2 0.44 2eoS) S259 101.87 105.26 45.23 ChenaSTé6 0.03 0.06 0.04 3.59 3.62 Sieet Zender 1 0.01 OzZO1 0.01 0.67 0.68 S7al6 Zender 2 0.00 0.00 0.00 0.18 0.18 S726 HealyIC2 0.00 0.00 0.00 0.01 OZor 67.26 UAFIC 7 0.00 0.00 0.00 0.01 0.01 67.26 DslIc 5S 0.00 0.00 0.00 0.01 OR.03 67.26 DslIC 6 0.00 0.00 0.00 0.00 0.01 67.26 UAFIC 8 0.00 0.00 0.00 0.00 0.00 67.26 Fmusic 1 0.00 0.00 0.00 0.00 0.00 89.69 Fmusic 2 0.00 0.00 0.00 0.00 0.00 89.69 Fmusic 3 0.00 0.00 0.00 0.00 0.00 89.69 Lotus Consulting Group - 24- Railbelt Transmission Alternatives Table 9 - 1996 Base Case Production Operation in Fairbanks Detail report:a:FBASE4OL .PTL 03-17-1987 Page 2 RNM file:c:FAIJRALL .RNM-fairbanks native demand 1991-2020: +30 MW Supply file:c:FBASE4OL.SPM-fairbanks basea case supply 40% prm 25 mw healy e97 SYSTEM REPORT FOR YEAR 1996 ENERGY (GWH) RELTABILITY COSTS( M$) Demand 1038.89 PK Load (MW) 197.40 Fix O&M S271) Unserve O222 Variable 1657S Net Gen. 1038.67 Unserved 0.02 Storage 0.00 Fuel 14.84 Total Gen 1038.67 LOLP (Dys/Yr) 0.000 Total 36.21 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/(MWH) HealyST1 91.10 1991552 835.98 4102.72 4938.70 24.75 ChenaST5 67579 118.76 77155) 4428.44 450S,..99 37.94 TIEPUR96 93.45 $73.06 15021 212) 0.00 15024 212 26.524 NoPolCT1l 26.48 141.48 206.13 6050.55 6256.68 44.22 NoPolCT2 1.08 Size 8.40 252)..25 260.65 45.23 NEWFCT A 0.03 0.06 0.03 2347 2.51 41.70 NEWFCT 1 0.01 0103S 0.02 1.08 1.10 41.70 ChenaSTé6 0.00 0.00 0.00 0.17 O17 Sieet Zender 1 0.00 0.00 0.00 0.03 0.03 57516 Zender 2 0.00 0.00 0.00 O01, 0.01 57516 HealyICc2 0.00 0.00 0.00 0.00 0.00 67.26 DslIc § 0.00 0.00 0.00 0.00 0.00 67.26 DslIC 6 0.00 0.00 0.00 0.00 ea OOO) 67.26 Railbelt Transmission Alternatives -25- Lotus Consulting Group Table 10 - 2006 Base Case Production Operation in Fairbanks Detail report:a:FRASE4OL .MTl. 03-17-1987 Page 3 RNM file:c:FAIRALI .RNM-fairbanks native demand 1991-2020: +30 MW Supply f1le:c:FRASE40l .SPM-fairbanks basea case supply 40% prm 25 mw healy @97 SYSTEM REPORT FOR YEAR 2006 ENERGY (GWH) RELIABILITY COSTS(M$ ) Demand 1230.86 PK Load (MW) 236.60 Fix O&M 4.14 Unserve a 29 Variable tS _ 58) Net Gen. 122720 Unserved On37 Storage 0.00 Fuel 20.26 Total Gen 227 LOLP (Dys/Yr) OLONt Total 40.36 Unit Capacity Energy Cost 1n $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/ (MWH) NewHeST 1 87.48 LO aS 7. 823.76 3024.46 3848.21 20.09 TIEPUROS6 97.88 600.21 14231 .92 0.00 14231 .02 23e7% NoPolCT2 S7a75) 308.58 449.60 12027 21S 12476.74 40.43 NEWFCT A 153599 35.03 20.32 1440.44 1460.75 41.70 NEWFCT B Oro) 20.157. TIS 846.06 858.00 41.70 NEWFCT 1 6.25 13.69 TaI4 563.05 570.99 41.70 NEWFCT 2 5.04 11204 6.41 454.15 460.55 41770 NEWFCT 3 4.38 3.59 5.56 394.30 399.86 41.70 NEWFCT 4 3.84 16.83 O16 692.28 702.04 41.70 NEWFCT S Si. 26 19.99 11.60 82221 833.81 41.70 Lotus Consulting Group - 26- Railbelt Transmission Alternatives Table 11 - 2015 Base Case Production Operation in Fairbanks Detail report:a:FBASE4OL .DTL RNM file: ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name NewHeST1 TIEPURIS NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NOQWUSLWNY OD >: FATRALL Supply file:c:FRASE4OL -RNM-fairbanks -SPM-fairbanks basea case suppl (GWH ) 1385.87 oO native OS=17=1987 demand 1991- SYSTEM REPORT FOR YEAR 2015 RELIABILITY R2 1384.55 0 00 1384.55 Capacity Factor er 98. 510 S4 46. S2: 26. 18. 12. 10. Si 8. 49 7 os 88 SS 60 66 es 12) 74 PK Load (MW ) LOLP (Dys/Yr) Energy (GWH 191 605 LTS, 100 Tees Did 40 5S. 62. S55 22. Railbelt Transmission Alternatives ) -60 750 -78 65 ol -66 a7 44 06 90 97 Variable 823. 14347. 69. s8. etd 33. 23. 32. 35. Sas 13. 41 B86 s4 47 49 44 62 1é 99 42 32 -27- 266.350 0.028 Cost in $1,0 Fuel Cost 3024.80 0.00 4925.81 4147.15 2961.43 2371.00 1674.85 2279.93 2551.90 2298.89 944.43 Page 4 2020: +30 MW y 40% prm 25 mw healy e97 COSTSCMS,) Fix O&M 4.56 Variable LSS St Unserved 0.08 Fuel 27. Le Total 47-35 oO Total Cost. Total $/(MWH) 3848.66 20.09 14347 .54 23.69 4995.28 41.570 4205.64 41.70 3003.20 41.70 2404.44 41.70 1698.47 41.70 2512.09 41.70 2587.89 41.70 2331.31 41.70 957 1G ai 70 Lotus Consulting Group Table 12 - 1991 Base Case Production Operation in Kenai Petail repert.:a:KBAS3SI_S.DTL OSI 71987 Page 1 RNM file:c:KENAALL .RNM-kenai load 1991-2020 Supply file:c:kbas351Ss.SPM-kenai with anc 35mw purch 10% prm loss penalty SYSTEM REPORT FOR YEAR 1991 ENERGY (GWH) RELIABILITY COSTS(M$ ) Demand 596.29 PK Load (MW) P1S60 Fix O&M 3.70 Unserve Ons Variable 0.28 Net Gen. 596.10 Unserved 0.02 Storage 0.00 Fuel A.46 Total Gen s9¢é.10 LOLP (Dys/Yr) 0.000 Total 8.46 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/ (MWH) soldatcT 51.90 172.76 247.05 4138.16 4385.20 25.38 bernice3 4.36 TOAST 23.00 252-18 2715.17 26.68 bernice4 122s 2s: 6.50 7A 235 TT oS 26.68 bernice2 0.00 0.00 0.00 0.00 0.00 Zt ask: ANCPURS1 0.00 0.00 0.00 0.00 0.00 28.08 seward3 0.00 0.00 0.00 0.00 0.00 0.00 seward4 0.00 0.00 0.00 0.00 0.00 0.00 sewardsS 0.00 0.00 0.00 0.00 0.00 0.00 seward6é 0.00 0.00 0.00 0.00 0.00 0.00 seldic2 0.00 0.00 0.00 0.00 0.00 0.00 seldic34 0.00 0.00 0.00 0.00 0.00 0.00 bradleyH 46.82 369.13 0.00 0.00 0.00 0.00 cooper H 25399 40.98 0.00 0.00 0.00 0.00 Lotus Consulting Group - 28- Railbelt Transmission Alternatives Table 13 - 1996 Base Case Production Operation in Kenai betail report:a:KBAS3SLS.DTL O3=—17=1987 Page 2 RNM file:c:KENAALL .RNM-kenal load 1991-2020 Supply file:c:kbas351ls.SPM-kenai with anc 35mw purch 40% prm loss penalty SYSTEM REPORT FOR YEAR 1996 ENERGY (GWH) RELIABILITY COSTS(M$) Demand 615.353 PK Load (MW) 119.30 Fix O&M 3.720) Unserve Ore Variable OnS1 Net Gen. 6tSe22 Unserved O.0r Storage 0.00 Fuel 4.86 Total Gen oS: 22 LOLP (Dys/Yr) 0.000 Total 8.88 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total -$/ (MWH ) soldatCT 56.67 188.64 269.76 4460.38 4730.14 25:07 bernice3S Sing 12326 Zi o> 299.91 327.26 26.68 bernice4 177 4.19 9.33 LOZ ESS 111.68 26.68 ANCPUR9S6 0.00 0.00 0.00 0.00 0.00 25558 bernice2 0.00 0.00 0.00 0.00 0.00 0.00 sewards 0.00 0.00 0.00 0.00 0.00 0.00 seward4 0.00 0.00 0.00 0.00 0.00 0.00 sewardsS 0.00 0.00 0.00 0.00 0.00 0.00 sewardé 0.00 0.00 0.00 0.00 0.00 0.00 seldic2 0.00 0.00 0.00 0.00 0.00 0.00 seldic34 0.00 0.00 0.00 0.00 0.00 0.00 bradleyH 46.82 369.14 0.00 0.00 0.00 0.00 cooper H 25507 40.98 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives - 29- Lotus Consulting Group Table 14 - 2006 Base Case Production Operation in Kenai bet.ail report:a:KBAS3SI_S_D0T RNM f1le:sc: KE Supply file:e:kbas351s ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name new ctl soldatcT ANC PUROE seward3 seward4 sewards seward6é seldic2 seldic34 bradleyH cooper H Lotus Consulting NAALL LR NM -SPM-kenal sn? ie ena. load 1991-2020 with ane 35inw purch 40% prim SYSTEM REPORT FOR YEAR 2006 (GWH) ©70,. Oo. 669. 0 669. Capacity Factor 65.89 206 ON -00 -00 -00 -90 -00 -00 46.79 25.98 oo0000000 Group 56 o4 92 .00 92 PK Load LOLP (Dys/Yr) Energy ( GWH ) 230. ete <O2 -00 -00 -00 .00 -00 -00 -90 -96 nN e0o00000 0 88 Variable 133. 41. O10: 010'O O10 OO -30- ot 71 OL -00 -00 -00 -00 -00 -00 -00 -00 RELIABILITY (MW) 150. 10 0.9000 Cost in $1,000 Fuel Cost 4468.02 735.80 -00 -00 -00 .00 .00 -00 .00 00 -0O0 eo00000000 Page s loss penalty COSTS( MS) Fix O&M Sea Variable 9.18 Unserved 0.06 Fuel S220) Total 8.76 Total Cost Total $/(MWH ) 4601.94 Taos) UT SO 26.66 Oo Si 23.78 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives Table 15 - 2015 Base Case Production Operation in Kenai Cetai1) report:4:KBASSSLS.LTL O3- 17-1987 Page 4 RNM file:c:KENAALL .RNM-kenal load 1991-2020 Supply file:c:kbas351s.S$PM-kenai with anc 35mw purch 40% prm loss penalty SYSTEM REPORT FOR YEAR 2015 ENERGY (GWH) RELIABILITY COSTS(M$) Demand 766.95 PK Load (MW) 148.80 Fix O&M 3.46 Unserve O76 Variable Oe) Net Gen. 766.18 Unserved 0.08 Storage 0.00 Fuel 6.89 Total Gen 766.18 LOLP (Dys/Yr) 0.9001 Total 10.64 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor ( GWH ) Variable Fuel Cost Total $/(MWH ) new ctl 73.63 257.99 149.63 4992.65 $142.28 19.393 new ct2 22.908 72512 45.89 1531.18 1577.07 19.93 new ct3 8.74 1951S 11510 370.20 381.30 19.93 ANCPURLS 0.01 0.02 0.53 0.00 0.53 2351.79 sewards 0.00 0.00 0.00 0.00 0.00 0.00 seward4 0.00 0.00 0.00 0.00 0.00 0.00 sewardsS 0.00 0.00 0.00 0.00 0.00 0.00 seward6é 0.00 0.00 0.00 0.00 0.00 0.00 seldic2 0.00 0.00 0.00 0.00 0.00 0.00 seldic34 0.00 0.00 0.00 0.00 0.00 0.00 bradleyH 46.80 368.96 0.00 0.00 0.00 0.00 cooper H 25.98 40.96 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives -31- Lotus Consulting Group Table 16 - 1991 Base Case Production Operation in Anchorage Deta))] report:a:AK3540LS.DTL 03-17-1987 Page } RNM fi1le:c:ANCHALL .RNM-anchorage load 1991-2020 Supply file:c:AK35LAST.SPM-anc w/ 35mw ken pur 10% penalty prm 40% 2% beluga Pp SYSTEM REPORT FOR YEAR 1991 ENERGY (GWH) RELIABILITY COSTS(M$ ) Demand 2516/97 PK Load (MW) 459.00 Fix O&M 113.60 Unserve Orla Variable 4.93 Net Gen. 2516383 Unserved 0.01 Storage 0.00 Fuel 42.16 Total Gen 2516.83 LOLP (Dys/Yr) 0.003 Total 58.70 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/ (MWH ) BelgCC78 78.70 696.27 995.66 10906.26 11901 .93 17.09 BelgCCé8 78.48 694.38 990.88 11145.99 12136.87 17.48 BelugCT3 US 02 331.65 473.26 6417.66 6890.93 20.78 BelugCTS 63.01 369.80 527. 70 8386.41 8914.11 24.11 Anc CC76 24.98 238.48 1380.30 4914.37 6294.67 26.40 KENPURO1 6.45 19577, 524.49 0.00 524.49 26.53 BelugCT2 3.18 4.46 6.36 124.50 130.86 29) 2Si7 BelugCT1 224 3.14 4.49 87.64 9213) 29 337 BelugCT4 1365) 1.44 2.06 47.35 49.41 S425 Anc CCSé 0.83 S rol: 20.32 92.97 113.29) S2.i27: Anc CT 8 0.13 0.99 S74 30.59 36.52 36.65 Anc CT 4 O-01 0.04 0.26 A, 181, 2.06 46.43 IntncT1 0).01 0.01 0.09 0.32 0.41 61752 IntncT2 0.00 0.00 0.05 0.18 0.23 61,52 IntncT3 0.00 0.00 0.03 0.12 0.16 61.43 EklutnaH 58.18 1S2)169) 0.00 0.00 0.00 0.00 Lotus Consulting Group -32- Railbelt Transmission Alternatives Table 17 - 1996 Base Case Production Operation in Anchorage Detail report:a:AK35401.S.DTL 03-17-1987 Page 2 RNM f1le:c:ANCHALL .RNM-anchorage load 1991-2020 Supply file:c:AK3SLAST.SPM-anc w/ 35mw ken pur 10% penalty prm 40% 2% beluga p SYSTEM REPORT FOR YEAR 1996 ENERGY (GWH) RELIABILITY COSTS(M$) Demand 2684.08 PK Load (MW) 487.90 Fix O&M 10.69 Unserve 0222 Variable 335? Net Gen. 2683.86 Unserved 0.02 Storage 0.00 Fuel 45.56 Total Gen 2683.86 LOLP (Dys/Yr) 0.045 Total $9.87 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH) Variable Fuel Cost Total $/(MWH ) BelgCC78 78.68 696.11 995.44 10904.17 11899.61 17.09 BelgCCé6é8 78.61 698.53 992.53 11160.82 12153.35 7 47 NewBCT 3 73.44 321.68 186.57 6349.66 6536.23 20.32 NewBCT 4 67.88 297.32 172.45. 5868.87 6041.31 20.32 BelugCTS 54.94 240.62 343.36 4891.75 5235.11 21.76 BelugCTS 32.27 189.39 270.27 4610.94 4881.20 255 7a Anc CC76 8.65 82.61 . 478.15 1702.39 2180.54 26.40 KENPURS6 1.61 4.95 131.56 0.00 131.56 26.60 Anc CCS6é 0.52 232) 12.78 58.46 Ch 325 32.27 Anc CT 8 0.08 0.58 $.395 AT .77 21.10 36.65 EklutnaH See i7, 152.86 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives - °33- Lotus Consulting Group Table 18 - 2006 Base Case Production Operation in Anchorage Detail report:a:AK3S540LS.DTL 03-17-1987 Page 3 RNM file:c:ANGHALL .RNM-anchorage load 1991-2020 Supply f1ile:c:AKSSILAST.SPM-anc w/ 35mw ken pur 10% penalty prm 40% 2% beluga p SYSTEM REPORT FOR YEAR 2006 ENERGY (GWH) REL TARILITY COSTS( M$) Demand 3124.08 PK Load (MW) 554.90 Fix O&M 11.16 Unserve 1.38 Variable 3.00 Net Gen. 3122.70 Unserved 0.14 Storage 0.00 . Fuel 83.27 Total Gen 3122.70 LOLP (Dys/Yr) O..225 Total 67.56 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/ (MWH ) BelgCC78 78.71, 696.35 995.78 10907 .50 11903.29 L709 BelgCCé8& 78.70 696.31 993.64 11171.03 12164 .67 17.47 NewBCT14 77.90 341.22 197 «91 6603.28 6801.18 19.93 NewBCT 3 73.51 321.97 186.74 6355.46 6542.20 20.32 NewBCT 4 66.88 292.92 169.89 5781.94 5951.84 20.32 NewBCT 5 55.55 324.87 188.43 6412.72 6601.14 20.32 NewBCT 6 37.99 166.39 96.51 3284.40 3380.90 20.32 New CC56 12.67 53.28 30.90 11:52 555 1183.25 22.21 New CC76 6.15 11.09. 41.23 1537 251 1578.74 22.21 KENPUROG 1.12 3.43 84.45 0.00 84.45 24.61 Anc CT 8 0..25 1.94 11.24 59.92 7A515 36.65 EklutnaH $8.19 152.92 0.00 0.00 0.00 0.00 Lotus Consulting Group -34- Railbelt Transmission Alternatives Table 19 - 2015 Base Case Production Operation in Anchorage Detail report:a:AK3S540L.5.DTL O31 7 -1987 Page 4 RNM f1ile:c:ANCHALL .RNM-anchorage load 1991-2020 Supply file:c:AK3SLAST.SPM-ane w/ 35mw ken pur 10% penalty prm 40% 2% beluga p SYSTEM REPORT FOR YEAR 2015 ENERGY (GWH) RELIABILITY COSTS(M¢ ) Demand 3572.25 PK Load (MW) 634.50 Fix O&M 12.46 Unserve Lee Variable S288 Net Gen. 3570.45 Unser ved 0.18 Storage 0.00 Fuel 60.08 Total Gen 39:70:45) LOLP (Dys/Yr) 0.039 Total 76.60 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH) Variable Fuel Cost Total $/(MWH) NewBCC68 78.70 696.34 459).58 10907.41 11367 .00 16.32 NewB8CC78 78.71 696.36 459.60 10907 .62 11367 .22 16.32 NewBCT14 78215 342.28 198 -'52 6623.71 6822.23 19:98 NewBCT15 772/50. 339.45 196.88 6569.07 6765.96 19.93 NewBCT 3 T3535 S21.17 186.28 6339.52 6525.80 20 82 NewBCT 4 68.44 299.76 173.86 5917.05) 6090.92 20 3352 NewBCT 5S 58.44 343.00 198.94 6770.43 6969.37 20.52 NewBCT 6 44.41 194.53 112.83 3839.90 3952.73 20.32 KENPURLS Zi 34 83.84 1838.16 0.00 1838.16 22592 New CC56 S595 41.85 24-27 905.14 929.41 22.21 New CC76 4.75 54.93 31.86 1188.06 1:21 9'92 22.28 New CT10 0.46 2501 ely, 53.46 54.62 27.19 New CTl1 0.20 noe 0.88 40.32 41.19 272 to New CT12 O.11 0.50 0.29 13.40 13.69 2719 EklutnaH Seed 1S2/92 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives -35- Lotus Consulting Group Table 20 - 2016 Production Operation in Kenai as an Isolated Area with 40% Reserves betall report:c:KENATIJe6 RNM file:c:kenailé.RNM-kena) Supply file:c ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name new ctl new ct2 new ct3 bradleyH cooper H :KENAT ( GWH ) 778 OF Td 0 W7a: Capacity Factor 81.26 ol. 7S 9.64 46.82 ZoLo9 Lotus Consulting Group OTL 2016 03-18-1987 Page 1 -SPM-kenai supply 49% planning reserve margin SYSTEM REPORT FOR YEAR 2016 eee 76 52 -00 S2 RELTABILT PK Load (MW) LOLP (Dys/yYr) Energy (GWH) 213.55 116.735 S7 aii 7 369.10 40.98 Variable 123.86 67.70 2256 0.00 0.00 - 36- TY COSTS( M$) 1Si1-00 Fix O&M Variable Unserved Fuel 0.088 Total 1 Cost in $1,000 ae OE Gr 7 oO Sa a or 05 -89) Total Cost Fuel Cost Total $/ (MWH ) 4100.22 4224.08 1978 2241.14 2308.85 19.78 7i3\-58 735.14 19578 0.00 0.00 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives Table 21 - 2016 Production Detail report:c:ANCH16é RNM file:c:anchlé.RNM-anchorage 2016 Supply file:c:ANCH ENERGY Demand Unserve Net Gen. Storage Total Gen Unit” Name New8CC6é8 New8CC78 NewBCT 3 NewBCT 5 NewBCT14 NewBCT15S NewBCT16 New New New New New New Anc Anc CCSé CcC76 cT10 cT11 cT12 CT17 cT 8 ct 9 EklutnaH ( GWH) 3625. 3625. S625 5 Capacity Factor 78.71 78371 7Oo47 At oe: 72495 73.44 71.05 69.94 40.04 15h 75) 8.24 3.85 dS 0. 71) 0.07 58.19 -OTL Operation in Anchorage as an Isolated Area with 40% Reserves 03-18-1987 Page 1 .SPM-ancho with 35 mw ken purchase units prm=40% SYSTEM REPORT FOR YEAR 2016 RELIABILITY wa aliz| 54 -00 54 Energ ( GWH ) 696. 696. 342. 453. LOT, 160 124. 294. 382. 68. 28. 16 Ss Sy O 1S2; Railbelt Transmission Alternatives PK Load (MW ) LOLP (Dys/Yr) y 37 36 40 76 -96 -83 48 08 32 89 88 -86 47 42 -56 92 Variable 489. 459.5 198. 263. 114. 93. We 170. 221. -96 16= -78 -O1 31. Se OF 39 9 2 60 59 So 18 82 28 20 sé 75 75) 39 22) oo E375 644 -00 0.056 costs Fix O&M Variable Unserved Fuel Total Cost in $1,000 Fuel Cost 10952 10952 2481 8188. 12036. 2126. 891 S20. 107). 167 17 ° -68 ae 6729 8929. 3906. 3187. 76 61 s9 $2 -31 We 34 eu ore, 22 LS -41 Be ly/ -00 Total 1I412729, 11482.11 6928.35 ChIC pe) 4021.41 3280.80 2555-91 8359.29 12258.09 2166.23 907.96 530.00 109.16 198.80 20.39 0.00 (M$ ) Total $/( 16. 16. 20. 20). 205 20; 20. 28. 32. 31. 31. 31. 31. 36. 36. oO. 15310 2216 O02 Pial? 86.47 cost MWH ) 39 39 23 26 31 40 Si 43 06 44 44 44 44 6s 65 oo Lotus Consulting Group vetail Table 22 - 2016 Production reportiasnikle RNM file:c:aklo.RNM-anchor and k Supply f11le:c:ANCH ENERGY (GWH) Demand Unserve Net Gen. Storage Total Gen Unit Name NewBCC68 NewBCC78 new new new etl ct2 ct3 NewBCT 3 New8CT 5 NewBCT14 NewBCT15S NewBCT16 New New New New New New Anc Anc CCS6é CC76 cT10 cqgll cT12 CcT17 cT 8 ct 9 EklutnaH bradleyH cooper H 4475. QO. 4475S. 0. 4475S. Capacity Factor 78.70 78.70 83.81 83.81 63.77 77336 Wait 73 .82 72265 66.15 54.53 L727 3.18 1.S¥ O54 (0) 74=) 0.08 0.00 58.18 46.82 25.99 Lotus Consulting Group B4 04 8a 00 80 DT enai 2016 US-1E-1987 Operation in Anchorage/Kenai as a Joint Dispatch Area with 40% Reserves Page 1 SPM-ancho with 35 mw ken purchase units prm=40% SYSTEM REPORT FOR YEAR 2016 PK L LOLP Energy (GWH ) 696.34 696.32 220). 25 308.35 322.87 338.82 446.69 194.01 156.92. 11S), 90) 229.529, 164.88 13.92 a7 oD, 2 nee 0.44 0.s9 0.04 152 91 369.13 40.98 RELIABILTI oad (MW) (Dys/Yr) Variable 459.58 459). S17 a7 75) 178.84 187.26 196-51 259.08 112.53 9LsOL 67 322 132.99 98.63 8.08 2578) Las? 0.25 3.40 0.22 0.00 0.00 0.00 -38- TY 795. oo 0.002 Cost in $1,000 Fuel Cost 10952). 109582. 4228. s920. 6199 6667. 8805. 3843. 3123. 2338. 6678. S424. 429. 147. 73. 29) Ol 89 27 -03 39 16 91 90 28 To 55 PACs 80 us) aS ies aA z -00 -00 -00 COSTS(M$) Fix O&M Variable Unserved Fuel Total Total 11411.88 11411,557 4356.64 6099.12 6386.29 6863.91 9064.24 3956.43 3214.91 2405.50 6811.74 5520.18 437.80 150758) 74.53 13.78 21352 Lo? 0.00 0.00 0.00 16.64 2.38 0.00 75, 82) 94°.85 Total Cost. $/(MWH ) 16. 16. 19 Lo. 19) ZO: 20 20. 20. 20). aaa 33. 31. Sie Si 31. 36. 36. oO. oO. Oo. 39 39 -78 78 -78 26 eae, 39 49 wS Zh 48 44 44 44 44 65 6s oo oo 00 Railbelt Transmission Alternatives Detail report:c:AK2S0 RNM file:c:ak Supply file:c ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name NewBCC68 NewBCC78 new ctl new ct2 new ct3 NewBCT 3 NewBCT 5S NewBCT14 NewBCT15 NewBCT16 New CCS6é New CC76 New CT12 Anc CT 8 Anc CT 9 EklutnaH bradleyH cooper H Table 23 - 2016 Production Operation in Anchorage/Kenai as a Joint Dispatch Area with 110MW Reduction in Reserves =Dmt 16.RNM-anchor and kenai 2016 -SPM-reduced anchor reserve SYSTEM REPORT FOR YEAR 2016 :AK250 (GWH ) 4475. Ow 4475. Oy 4475S. Capacity Factor 78.70 78.70 83.81 83.80 83.76 Vt 339, 76.10 73.82 L365 66.16 54.56 17-28 3.18 0.96 OL 12 58.18 46.82 25\.99) 84 08 76 oo 76 REL IABILI PK Load (MW) LOLP (Dys/Yr) Energy ( GWH ) 696. 696. 220. 308. 322. 338. 446. 194. 156. 1Ed.S 2297. 164. iS nS [5 1525 369. 40. Railbelt Transmission Alternatives 30 27 24 33 8s 80 67 oo 91 91 40 96 92 30 92 90 a 98 Variable 459.56 459.54 127.74 178.83 187 25 196.50 259.07 112.52 91-01 67223) 133.05 95.68 8.08 42.23 Ca) 0.00 0.00 0.00 -39- 03- 18-198 z Page d TY COSTS(M¢) 795.00 Fix O&M 135):68 Variable 2.142 Unserved 0.01 Fuel 735.82 OL LIS Total 93.93 Cost in $1,000 Total Cost Fuel Cost Total $/ ( MWH ) 10951 .81 11411.37 L6G 359 10951.45 11410.99 16.39 4228.63 4356.37 19578 5919.92 6098.75 1O.78 6198.67 6385.92 19-78 6667.02 6863.52 20.26 8804.73 9063.80 20.29 3843.72 3956.24 2039 SL23\-74 S2l4c7s 20.49 2338.43 2405.65 20.76 6682.28 6815.33 29,72 5427.40 5523.08 33.48 429.70 437.78 31.44 225.19, 267.42 36.65 28.44 33.77 36.65 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Lotus Consulting Group Table 24 - Anchorage Supply Model with Reduced Reserves RNM file:c:ANCHALL .RNM-anchorage load 1991-2020 Supply file:c:anchrsa.SPM-Anchorage Supply Model Units 1-15 Unit Unit Size Number Date Unit ID Name (MW) of Installed Life Units Yrs) C¥FSa) EKLU EklutnaH 30 1 1955 9S AMLP Anc CT lL 16 3 1962 25) AMLP Anc CT 2 16 1 1964 25 AMLP Anc CT 3 20 uy 1968 23 AMLP Anc CT 4 34 1 TI. 20 AM C Anc CCS6 48 1 1979 20 AM C Anc CC76 109 1 1979 20 AMLP Anc CT 8 87 L 1984 25 AMLP Anc CT 9 87 1 2050 38 Bel BelugCT1l 16 1 1968 26 Bel BelugCT2 16 x 1968 26 Bel BelugCTS 50 z 1972 27 Bel BelugCT4 10 r 1976 20 Bel BelugCTS 67 1 1975 24 Belc BelgCCé8 101 1 1976 31 RNM file:c:ANCHALL. .RNM-anchorage load 1991-2020 Supply file:c:anchrsa.SPM-Anchorage Supply Model Units 16-30 Unit Unit Size Number Date Unit ID Name (MW) of Installed Life Units (Yrs.) (Yess) belg BelgCC78 101 1 1976 31 Int IntncTl 14 a 1965 31 Int IntncT2 14 1 1968 28 Int IntncT3 20 ab 1970 26 NewC New CC76 180 a 1999 25 *NewB NewBCT 3 so 1 2999 ae NewB NewBCT 4 so 1 1996 ae NewB NewBCT 5 67 1 {939 25) NewB NewBCT 6 50 I 1999 25 New8 NewBCC68 101 1 2007 “31 New8 New8CC78 101 1 2007 31 *NewC New CT10 50 i 2999 Zo) NewC New CT1ll 87 1 2009 25 NewC New CT12 sO 1 2015 2s NewC New CT13 50 1 2018 25 NwB6C NewBCT14 so 1 2002 Zo) NwBC NewBCT15S 50 1 2011 25 Lotus Consulting Group -40- Railbelt Transmission Alternatives Year 1991 LIF2 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Peak: Table 25 - Anchorage Reserve Margins with Reduced Reserves Svetem Capacity and Reserve Margin Reserve Load Capacity Margin Exe. Pur Exe. Pur (MW) 459 464 474 484 486 488 490 494 499 506 515 523 531 539 547 (MW) Zils? 683 683 651 651 643 643 643 666 666 666 716 716 716 716 (%) 56.209 47-325 44.245 34.504 33.923 S789 Slit Le 30.188 33.601 31.621 20 295 36.955 34.916 32.937 30.968 Railbelt Transmission Alternatives Reserve Margin Ine. Pur (%) 56.209 472025 44.245 34.504 33.923 31.789 SAG LZ 30.188 33.601 Si621 29 295) 36-955 34.916 32.937 30.968 SAL = Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015S 2016 2017 2018 2019 2020 Peak Load Capacity (MW) 555 S63 S72 S80 589 598 607 616 625) 635 644 654 673 684 694 System Reserve Margin Exe-Pur Exe=Pur (MW) 716 716 716 TAG 716 766 766 766 766 816 816 816 866 866 B66 (%) 29/0352 27.131 CASE CX | 23.384 21.562 28.137 26.236 24.371 22.540 28.605 26.708 24.828 28.601 26.701 24.820 Reserve Margin Tne. Pur (%) 29032 Aratst 25.241 23.384 21.562 28.137 26.236 24.371 22.540 28.605 26.708 24.828 28.601 26.701 24.820 Lotus Consulting Group Table 26 - 1991 Alternate Case Production Operation in Fairbanks Petal! report:a:FBAS250xX PTL RNM file:c:FATRALL 03-17-1987 Supply file:c:FRBASE250.SPM-rsa model of fairbanks SYSTEM REPORT FOR YEAR 1991 ENERGY (GWH) Demand Unserve Net Gen. Storage Total Gen Unit Name HealySTl ChenaSTS TIEPURS1 TibPUR91 NoPolCT1 NoPolCT2 ChenaSTé Zender 1 Zender 2 HealyIC2 UAFIC 7 DslIc 5 DslIC 6 UAFIC 8 Fmusic 1 Fmusic 2 Fmusic 3 S37: Oy 936. Oe 936" Capacity Factor 85.70 27.54 84.47 5.87 S28 1.49 0.44 0.41 0227 O. 21 0220 0.235 O525 0.26 “O26 0.26 0225 Lotus Consulting Group 66 94 Ze 90 V2 RELIABILI PK Load (MW) LOLP (Dys/Yr) Energy (GWH ) 187.68 48.25 Si ooo 144.07 28.22 7298 AO 0.65 0.43 0.06 0.05 0.06 0.07 0.07 0.07 0.07 0.07 Variable 786.40 SiO 12922.94 4130.56 41 312 11,258 0.60 0.39 0.26 0.33 OLSst 0.36 0.38 0.40 1260 1308 L-04 =42- TY 176%: 20 1.062 Cost in $1,000 Fuel Cost 3153.41 1883.32 0.00 0.00 1235.38 347.89 $7 03 36.92 24215 3.43 S22 3.74 4.04 4.19 4.56 4551 4.41 Page 1 -RNM-fairbanks native demand 1991-2020: +30 MW COSTS(MS ) Fix O&M 4.78 Variable L795 Unserved 0.09 Fuel 6.77 Total 29558 Total Cost Total $/ (MWH ) 3939.81 20399) 1914.83 39.69 12922.94 24395 4130.56 28.67 1276.50 45.525 359.47 45.23 S77 165 S721 37.31 S726 24.41 S716 3.76 67.26 S255) 67.26 4.09 67.26 4.43 67.26 4°59) 67.26 6.16 89.69 6.09 89.69 5295 89.69 Railbelt Transmission Alternatives Table 27 - 1996 Alternate Case Production Operation in Fairbanks Deta1] report:a:FBAS250X.DTL OS—1 7-1 eo? Page 2 RNM file:c:FAIRALL .RNM-fairbanks native demand 1991-2020: +30 MW Supply file:c:FBASE250.SPM-rsa model of fairbanks SYSTEM REPORT FOR YEAR 1996 ENERGY (GWH) RELIABILITY CcOSTS(M$) Demand 1038.89 PK Load (MW) 197.40 Fix O&M 5.21 Unserve 0.24 Variable 21745 Net Gen. 1038.66 Unserved 0.02 Storage 0.00 Fuel 7.08 Total Gen 1038.66 LOLP (Dys/Yr) 0.295 Total 33.76 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/ (MWH) HealyST1l 86.97 190.46 798.05 3932.84 4730.89 24.84 ChenasTS 26.50 46.42 30.32 1812.07 1842.39 39.69 TIEPUR96 89.41 548.24 14369.38 0.00 14369.38 26.21 TibPURS6 9.10 223.10 6208.87 0.00 6208.87 27.83 NoPolCTl 4.0S 21.66 31.56 948.14 9719570) 45.23 NoPolCT2 1.14 6511 8.90 267.47 216.37. 45.25 NEWFCT A 0.49 1207 0.62 44.04 44.66 41.70 NEWFCT 1 O#733 O-72 0.42 29.49 29.90 41.70 ChenaSTé 0.20 0745 0.26 25-22 25.48 Si aed Zender 1 0.14 0.23 0.14 12.82 12595 S706 Zender 2 0.09 0.14 0.09 8.16 e-25 57516 HealyIC2 0.07 0.02 0.11 1.13 1.24 67.26 DslIc S 0.06 0.02 0.10 1.05) iS 67.26 DslIC 6 0.07 0.02 0.10 1.09 220 67.26 Railbelt Transmission Alternatives - 43- Lotus Consulting Group Table 28 - 2006 Alternate Case Production Operation in Fairbanks Detail report:a:FBAS250xX .DTL RNM file:c:FATRALL OS=17=1987 Supply file:c:FBASE250.SPM-rsa model of fairbanks SYSTEM REPORT FOR YEAR 2006 ENERGY (GWH) Demand Unserve Net Gen. Storage Total Gen Unit Name NewHeST1 TIEPURO6 TibPUROS NoPolCT2 NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT UAWNY OD 1230. oO. 1230. oO. 1230. Capacity Factor 86.38 96.75 17.80 136) 0.46 O37, 0.30 0223 0.18 Ons 0.09 Lotus Consulting Group Bé 02 84 oo B4 RELTIABILTI PK Load (MW) LOLP (Dys/Yr) Energy ( GWH ) 189217 593.30 436.56 Ts2e 1.02 0.82 O265 O5S1 0.40 OES? 0-57 Variable 813.42 12993 .31 10350.95 10.58 0.59 0.48 0.38 0.29 O525 0.34 0.33 4ae TY 236.60 0.030 Cost in $1,000 Fuel Cost 2989.27 0.00 0.00 S17 S877. 41.82 SS 275 26.60 20.87 16.45 24.06 23.34 Page 3 .RNM-fairbanks native demand 1991-2020: +30 MW COSTS(M$) Fix O&M Variable Unserved Fuel Total Total Total $/ ( 3802.69 20 12993 .30 21, 10350.95 25h 328.45 45: 42.41 ai. 34.23 41. 26.98 ay. 21.16 41 16.68 41. 24.40 a1 2567 c, 4.14 24.17 0.00 3349 Ss) Cost MWH ) LO 90 al 23 70 70 70 70 70 70 70 Railbelt Transmission Alternatives Detail repert:a:FBAS2S50x.DTL RNM file:c:FATRALI Table 29 - 2015 Alternate Case Production Operation in Fairbanks .RNM-fairbanks native demand Supply f1le:c:FBASE250.SPM-rsa model of fairbanks SYSTEM REPORT FOR YEAR 2015 ENERGY (GWH) Demand Unserve Net Gen. Storage Total Gen Unit Name NewHeST1 TIEPURIS TibPURILS NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NQWUSLAWNY OD Railbelt Transmission Alternatives 1385. Os 1385. Os 1385S. Capacity Factor 87.49 98.76 23.98 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 37 00 37 00 37 RELIABILI PK Load (MW) LOLP (Dys/Yr) Energy (GWH ) -60 60s. S88. -00 -00 -00 -00 -00 -00 -00 -00 -00 19% ooooo00 0° 58 Lg Variable 823.89 12959.42 13934 .18 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -45- O3=17-19387 Page 4 1991-2020; +30 MW TY COSTS(M$ ) 266.30 Fix O&M 4 Variable 27 Unserved Oo Fuel 3 0.000 Total 35 Cost in $1,000 Total Co Fuel Cost Total $/ (MWH 3024.89 3848.78 20.09 0.00 12959.42 21.40 0.00 13924.18 23.69 0.00 0.00 41.70 0.00 0.00 41;. 70 0.00 0.00 41.70 0.00 0.00 41.70 0.00 0.00 41.70 0.00 0.00 41.70 0.00 0.00 41.70 0.00 0.00 41.70 0.00 0.00 41.70 Lotus Consulting Group -26 wa -900 J02 500 Sy ) Table 30 - 1991 Alternate Case Production Operation in Anchorage/Kenai Joint Area hetail report:a:AKJOINTL .OTL RNM file:c:JOINTALL .RNM-anchorage/kenai Supply file:c:AKJOINT ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name BelgCC78 BelgCCé68 BelugCT3 BelugCTS soldatcT bernice3S bernice4 bernice2 Anc CC76 BelugCT2 BelugCTl1 BelugCT4 Anc CCS6 Anc CT 8 Anc CT 4 IntncT1 IntncT2 IntncT3 seward3 seward4 sewards sewardé seldic2 seldic34 EklutnaH bradleyH cooper H Os= 7-1 987 SYSTEM REPORT FOR YEAR (GWH ) Sits. 0. Sii2. Oz S112) Capacity Factor 7On0 1 78.70 80.71 VARI AT/ 56.22 32. 77 T2252 10.86 2917 0.42 0.26 0-18 0.08 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 5819 46.82 25.99 18 30 88 00 88 Lotus Consulting Group REL [ABILITY PK Load (MW) LOLP (Dys/Yr) Energy (GWH ) 696.38 696.30 S55 52 450.57 187.14 71.80 41.43 Lifere. 28.35 0.58 0.37 O225 0232 0.06 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11S2292 369.16 40.98 Cost in $1,000 Variable 995.82 993.63 504.47 642.96 267.61 172.82 92.40 38.19 164.11 0.83 0.55 0.22 1.86 0.37 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -46- joint Joad .-SPM- Joint ane/kena1 dispatch newec76 1991 574.62 0.000 Fuel Cost 10907 .93 L170. 91 6781.42 9962.72 4226.11 1820.14 1001.00 436.87 686.42 16.33 10527 5.06 10.56 1.98 0.07 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Page 1 in kenai 40% prm COSTS(M$) Fix O&M 15.30 Variable 3.88 Unserved 0.03 Fuel 47.04 Total 66.24 Total Cost Total $/(MWH ) 11903.75 1709 12164.53 17s 47 7285.89 20.61 10605.68 23.54 4493.72 24.01 1992.96 25 g2 1093.40 26.39 475.08 Zar 850.53 30.00 L75v6 22287 10.79 29.37 Si2e 34.25 12542 38.69 2.35 36.65 0.08 46.43 0.01 61.52 0.01 61-52 0.00 61.43 0.00 116.76 0.00 116.76 0.00 116.76 0.00 116.76 0.00 135.24 0.00 135.24 0.00 0.00 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives 5 Table 31 - 1996 Alternate Case Production Operation in Anchorage/Kenai Joint Area Detail report:a:AKJOINTL .MT RNM file:c:JOINTALL .RNM-anchorage/kenal j01 Supply f1le:c:AKJOINTL .SPM- joint SYSTEM REPORT FOR YEAR ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name BelgCC78 BelgCCé8 NewBCT 4 BelugCT3 BelugCTS soldatcT bernice3 bernice4 bernice2 Anc CC76 Anc CCS6 Anc CT 8 seward3 seward4 sewards seward6é seldic2 seldic34 EklutnaH bradleyH cooper H (GWH ) S299 75 Os 3299: OF 3299 Capacity Factor 7S, 71 78.70 T7567 77.80 69.99 42.49 21.06 13.48 6c19 1787, OF19) 0.03 0.00 0.00 0.00 0.00 0.00 0.00 58.19 46.82 25.99 46 20 26 00 Pu) 03-17-1987 anc/kena) RELIABILITY PK Load (MW) LOLP Energy ( GWH) 696.37 696.35 340.21 340.76 410.79 141.44 49.80 Si 787 975 17.84 0.82 O19 0.00 0.00 0.00 0.00 0.00 0.00 LS2e92) 369.15 40.98 Railbelt Transmission Alternatives (Dys/Yr) Cost in $1,000 Variable 995.80 993.69 197 S82 486.27 $86.20 202.26 111.06 71.08 21575 103.28 4.74 Doli 0.00 0.00 O..01 0.00 0.01 Oj; OF! 0.00 0.00 0.00 -47- nt load dispatch neweo7é 1996 607. zy, 0.008 Fuel Cost 10907. Lae 67S. 6568. 9236. 3276. 1196. Tk 250% 431. 26. 295) O07 -O7 -10 -09 -02 -02 -00 O. oO. eo000000oNn a2 43 43 53 S2 18 76 S57 Ey] 99 93 oo oo Page 2 costs Fix O&M Variable Unserved Fuel Total 1n kenai 40% prm (M$) 13.96 3.77 0.02 50.56 68.32 Total Cost Total $/ (I4WH ) 11903.52 17.09 12165.12 17.47 6912.75 20.32 7054.80 20.70 9822.72 23.91 3478.45 24.59 1307.83 26.26 847.64 26.59 272.26 27.91 $35.27 30.00 31.67 38.69 7.06 36.65 0.08 116.76 0.08 116.76 0.10 116.76 0.09 116.76 0.03 135.24 0.03 135.24 0.00 0.00 0.00 0.00 0.00 0.00 Lotus Consulting Group Ss Table 32 - 2006 Alternate Case Production Operation in Anchorage/Kenai Joint Area Detail report:a:AKIJOINTL.DTL RNM file:c:JOINTALL.RNM-anchorage/kenal J Supply file:c:AKJOINTL.SPM-joint anc/kenal dispatch newec7é ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name New CC76 BelgCC78 BelgCCé8 NewBCT14 newKetl NewBCT 4 NewBCT 5S NewBCT 6 soldatcCT Anc CT 8 sewards seward4 sewardS sewardé seldic2 seldic34 EklutnaH bradleyH cooper H 03-17-1987 oint load SYSTEM REPORT FOR YEAR 2006 (GWH) 3794. 2. S792 5 OF S792 s Capacity Factor 81.76 78.60 75.04 GlaLt 46.76 13.98 8.77 5.62 L294 0.70 O225 O225 0.24 0.23 OzZ2, Oa2t 58.18 46.82 25.99 Lotus Consulting Group 58 i 48 00 48 RELTABILT PK Load (MW) LOLP (Dys/Yr) Energy (GWH ) 1289.27 695.38 663.92 267.65 163.86 61.24 51.48 24.64 6.46 5.34 0.04 0.04 0.06 0.06 0.02 0.02 15290 S695 11 40.98 Variable 747.78 994 39 947.42 LSS .24 95.04 35.52 29.86 £4.29 9.24 30.92 0.26 0225 0.37 0.35 O75) 0.73 0.00 0.00 0.00 - 48 - TY 685.00 0.787 Cost in $1,000 Fuel Cost 20386 .06 10894.95 10741 .97 5179).50 3171.02 1208.87 1016.21 486.27 163.09 164.88 4.90 4.83 6.96 6.56 i On 1.76 0.00 0.00 0.00 Page 3 in kenai 40% prm 2 COSTS(MS ) Fix O&M 14.03 Variable 3.06 Unserved OG21 Fuel 53.44 Total 70.74 Total Cost Total $/(MWH) 21133.83 16.39 11889.34 17,10 11689.39 Wary 3) 5334.73 19.93 ~ 3266.06 19295 1244.39 20.32 1046.07 20.32 500.56 20.52 172.33 26.66 195.80 36.65 5. Lie 116 376 S09) 116.76 72s) T1627 6: 91 116.76 21. 56) L351. 24 2549 135.24 0.00 0.00 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives Table 33 - 2015 Alternate Case Production Operation in Anchorage/Kenai Joint Area Kerax 1 ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name NewBCC68 NewBCC78 New CC76 NewBCT14 NewBCT15 newKetl newkKet2 newKet3 NewBCT 4 NewBCT 5S NewBCT 6 New CT11 New CT12 seward3s seward4 sewards seward6é seldic2 seldic34 EklutnaH bradleyH cooper H Railbelt Transmission Alternatives repurt:a:AKJOINTL PTL RNM file:c:JOINTALL .RNM-anchorage/kenal Supply f1le:c:AKJOINTL .SPM-joint J ane/kena OS= 7-1 3987 oeint load 1 dispatch newec76 1m kenal SYSTEM REPORT FOR YEAR 2015 (GWH ) REL TABILITY 4339.12 PK Load (MW) 783.30 0.78 4338.34 0.00 4338.34 LOLP (Dys/Yr) 0.435 Capacity Energy Cost in $1,000 Factor ( GWH ) Variable Fuel Cost 78.69 696.21 459.50 10905.68 78.69 696.22 @59 251 10908.78 81.38 1283.20 744.26 20307 .02 72.48 317.44 184.12 6143.15 69.06 302.50 L7Sn45 5854.06 SS 742 194.18 112.63 S757 3195 37.86 132.66 76.94 2567.30 26.32 57.64 33.43 LETS 758 9.02 SI. 52 22.92. 780.08 S62 32.99 1915 1:4 651.26 3.517 15.64 9207 308.72 On71 5.44 Sisk) 144.68 0.36 1.60 0.93 42.45 OO. US 0.03 0.15 2.86 0.14 0.02 Gus Zaat 0.14 0.04 o.21 3.95 0.13 0.03 0.19 3.70 O212 0.01 0.42 1.01 Oeh2 0.01 0.41 0.98 58.18 152.89 0.00 0.00 46.81 369.08 0.00 0.00 2599 40.97 0.00 0.00 - 49- Page 4 40% prm 2 CcOSTS(M$) Fix O&M 15205) Variable 2250 Unserved 0.08 Fuel 63.50 Total 80.92 Total Cost Total $/(MWH) 11365.18 16252 11.365 =29 16.32 21051.28 16.41 6327.27 191.93 6029.51 19.93 3870.48 19.93 2644.24 19.95 1148.81 19 95) 803.01 20.32 670.39 20.32 SIT 79 20.32 147.83 Ziad? 43.38 Zl 3.01 116.76 2.92 116.76 4.16 116.76 3.89 116.76 1.43 135.24 Loe. 135.24 0.00 0.00 0.00 0.00 0.00 0.00 Lotus Consulting Group Table 34 - Comparison of 2006 Results in Fairbanks Detail report:a:FRASE4OL .DTL 3-17-1987 Page 3 RNM file:c:FAIRALI. .RNM-fairbanks native demand 1991-27020: +30 MW Supply f1le:c:FRASE4O0l..SPM-fairbanks basea case supply 40% prm 25 mw healy @97 SYSTEM REPORT FOR YEAR 2006 ENERGY (GWH) RELIABILITY COSTS( M$) Demand 1230.86 PK Load (MW) 236.60 Fix O&M 4.14 Unserve S.75 Variable Loe oo) Net Gen. 1227 501 Unserved O.s7 Storage 0.00 . Fuel 20.26 Total Gen M227 501 LOLP (Dys/Yr) 9 Oll Total 40.36 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/(MWH ) NewHeST1 87.48 191.57 823.76 3024.46 3848.21 20.09 TIEPURO6 97.88 600.21 14231 .02 0.00 14231 .02 235i. 71 NoPolCT2 $7575 308.58 449.60 12027.15 12476.74 40.43 NEWFCT A ts.99 35.03 20.52 1440.44 1460.75 41.70 NEWFCT 8 9.39, 20.57 L193 846.06 858.00 41.70 NEWFCT 1 Ga25) 13.69 7.94 563.05 570.99 41.70 NEWFCT 2 5.04 11.04 6.41 454.15 460.55 41.70 NEWFCT 3 4.38 9.89 S356 394.30 399.86 41.70 NEWFCT 4 3.84 16.83 9276 692.28 702.04 41.70 NEWFCT S 3 SieO 19599 11.60 822.21 833.81 41.70 Detail report:a:FBAS250X.DTL 03-17-1987 Page 3 RNM file:c:FAIRALL .RNM-fairbanks native demand 1991-2020: +30 MW Supply file:c:FBASE250.SPM-rsa model of fairbanks SYSTEM REPORT FOR YEAR 2006 ENERGY (GWH) RELIABILITY COSTS(M$) Demand 1230.86 PK Load (MW) 236.60 Fix O&M 4.14 Unserve 0.02 Variable 24.17 Net Gen. 1230.84 . Unserved 0.00 Storage 0.00 Fuel 3.49 Total Gen 1230.84 LOLP (Dys/Yr) 0.030 Total 31.81 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/ (MWH) NewHeST 1 86.38 189.17 813.42 2989.27 3802.69 20.10 TIEPUROG 96.75 593.30 12993.31 - 0.00 12993 .30 21-90 TibPUROS 17.80 436.56 10350.95 0.00 10350.95 235.71 NoPolCT2 1.36 7.26 10.58 317.87 328.45 43525 NEWFCT A 0.46 1.02 O7S9) 41.82 42.41 41.70 NEWFCT B 0.37 0.82 0.48 SoS 34.23 41.70 NEWFCT 1 0.30 0.65 0.38 26.60 26.98 41.70 NEWFCT 2 0.23 O-S! 0.29 20.87 ZiAciG 41.70 NEWFCT 3 0.18 0.40 0.23 16.45 16.68 41.70 NEWFCT 4 Oris 0.89 0.34 24.06 24.40 41.70 NEWFCT 5S 0.09 0. 57) 0.33 23.34 23.67 41.70 Lotus Consulting Group - 50- Railbelt Transmission Alternatives Table 35 - Comparison of 2006 Results in Anchorage and Kenai Detail report:a:AK3SSA0OLS.DTL HS—l7=1987 Page 35 RNM file:c:ANCHALL .RNM-anchorage Joad 1991-2020 Supply file:c:AK3SLAST.SPM-anc w/ 35mw ken pur 1O% penalty prm 40% 2% beluga pe SYSTEM REPORT FOR YEAR 200¢ ENERGY (GWH) REL IABIL ITY COSTS( M$) Demand 3124.08 PK Load (MW) 954.90 Fix O&M 11.16 Unserve 1,38 Variable B Oud Net Gen. 3122.70 Unser ved 0.14 Storage 0.00 Fuel Sena? Total Gen 3122.70 LOLP (Dys/Yr) 02225 Total 67.56 Unit Capacity Energy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost Total $/ (MWH ) BelgCC78 48 71. 696.35 995.78 10907 .50 11903.29 1,7.09 BelgCCé68 78.70 696.31 993.64 11171038 12164.67 17.47 NewBCT14 77.90 341.22 197 791 6603.28 6801.18 19.95 NewBCT 3 73.51 321.97 186.74 6355.46 6542.20 20.32 NewBCT 4 66.88 292.92 169.89 5781.94 5951.84 20.32 NewBCT 5S SS sS> 324.87 188.43 6412.72 6601.14 20.32 NewBCT 6 37.99 166.39 96.51 3284.40 3380.90 20.32 New CCS6 12.67 53.28 30.90 P1S2Z-55 1183.25 22 rad New CC76 Garis TOF 41.23 1837.51 1578.74 ee el. KENPURO6 L5t2 3.43 84.45 0.00 84.45 24.61 Anc CT 8 0.25 1.94 11.24 SIEO2) 7IeS 36.65 EklutnaH Sea19 152.92 0.00 0.00 0.00 0.00 Detail report:a:KBASSSLS.DTL 03-17-1987 Page 3 RNM file:c:KENAALL_.RNM-kenai load 1991-2020 Supply file:c:kbas351s.SPM-kenai with anc 35mw purch 40% prm loss penalty SYSTEM REPORT FOR YEAR 2006 ENERGY (GWH) RELIABILITY COSTS(M$) Demand 670.56 PK Load (MW) 130.10 Fix O&M S552 Unserve 0.64 Variable 0.18 Net Gen. 669.92 Unserved 0.06 Storage 0.00 Fuel >i. 20 Total Gen 669.92 LOLP (Dys/Yr) 0.000 Total 8.76 Unit Capacit Energy Cost in $1,000 Total Cost Name Poa (GWH) Variable Fuel Cost Total $/( MWH) new ctl 65.89 230.88 1353.91 4468.02 4601.94 19593 soldatcT 8.76 29.17 41.71 735.80 T1250 26.66 ANCPURO6 0.01 0.02 O-S1 0.00 Oo. 51 23.78 seward3 0.00 0.00 0.00 0.00 0.00 0.00 seward4 0.00 0.00 0.00 0.00 0.00 0.00 sewardsS 0.00 0.00 0.00 0.00 0.00 0.00 sewardé 0.00 0.00 0.00 0.00 0.00 0.00 seldic2 0.00 0.00 0.00 0.00 0.00 0.00 seldic34 0.00 0.00 0.00 0.00 0.00 0.00 bradleyH 46.79 368.90 0.00 0.00 0.0@ 0.00 cooper H 25.98 40.96 0.00 0.00 0.00 0.00 Railbelt Transmission Alternatives -51- Lotus Consulting Group LL 99/104 STUSUDA, uDusaly uots: SOA: -2S- dnosn 8uyjnsuoD snoTJ Year 1991 1992 1993 1994 1995 1996 1997 19398 1399 2000 2001 2002 2003 2004 2005 2006 2007 2008 2003 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Total Kenai 8.46 8.61 8.82 8.86 8.87 8.88 8.77 S09 8.75 8.78 8.88 8.84 3.09 8.34 8.55 8.76 8.98 9.26 ac 9.31 3.52 9.73 9.95 10.41 10.64 10.86 11.10 11.33 11.56 11.80 NPU 1987 Base Case vs. Anchor 58.70 58.98 60.35 60.67 60.94 59.87 60.18 60.62 59.45 60.31 62.77 6s. 72 64.71 65.63 66.59 67.56 67.36 68.97 69.65 70.65 71.84 72.30 735.38 75.06 76.60 77.72 78.88 81.68 62.91 84.16 Fairbnk 32.47 33.60 34.56 34.88 35.793 36.21 37.193 38.19 S0ate 38.87 39.78 38.87 393.50 40.14 39.93 40.36 41.44 42.20 42.93 43.84 44.14 44.92 45.72 46.51 47.33 48.43 43.30 50.24 51.14 52.09 Total 939.63 101.19 103.73 104.41 105.60 104.96 106.14 107.60 105.95 107.96 111.435 111.50 113.30 114.11 115.07 116.68 118.38 120.43 122.00 123.80 125.50 127.55 129.65 131.98 134.57 137.01 139.28 143.25 145.61 148.05 Alternate Case —- Savings in Production Cost & Capacity be Alternate Case---~I Ken/Anch Fairbnk 66.24 66.67 68.24 63.36 63.68 68.32 68.55 69.04 62.48 63.28 65.56 66.71 67.77 68.51 63.61 70.74 70.79 72.06 72.81 73.86 75.32 76.58 77.85 73.25 80.92 82.24 83.59 86.48 87.89 89.35 29.58 30.493 31.34 33.02 33.77 33.76 34.80 35.21 31.39 32.14 33.13 Si .7s 32.09 32.14 31.51 31.81 32.54 33.60 33.60 34.00 33.44 34.39 34.74 34.54 35.30 36.31 37.33 37.89 38.63 39.85 Total 95.82 97.16 39.58 102.38 103.45 102.08 103.35 104.25 93.87 95.42 38.69 38.44 99.86 100.65 101.12 102.55 103.33 105.66 106. 41 107.86 108. 76 110.97 112.59 113.79 116.22 118.55 120.92 124.37 126.52 129.20 Operating Savings 3.81 4.03 4.15 2.03 2.15 2.88 2.79 3.35 12.08 12.54 12.74 13.06 13.44 13.46 13.95 14.13 15.05 14.77 15.59 15.94 16.74 16.58 17.06 18.19 18.35 18.46 18.36 18.88 19.09 18.85 372.50 178.53 Capital Savings 0 ° 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 2.81 2.81 2.61 2.61 2.81 2.81 2.81 2.81 1.41 1.41 1.41 1.41 1.41 1.41 1.41 50.66 26.14 Total Savings 3.81 4.03 5.56 3.44 3.56 4.29 4.20 4.76 13.49 13.95 14.15 14.47 14.85 14.87 15.36 16.94 17.86 17.58 18.40 18.75 19.55 19.39 19.87 19.60 19.76 19.87 19.77 20.29 20.50 20.26 423.16 204.67 SyNSoY Two Aq OX - OF BGR dnosy 8unyjnsuoD snio7J -€G- SAANDULIIY UOISSNUSUDL 1aqiIDy Hase Case vs. Year Kenai 1s3t 8.46 iss2 8.61 1i9ss 8.82 1994 8.86 1995 8.87 1996 8.838 19972 Bae 13998 Sacd 13999 8.75 2000 8.73 2001 8.88 2002 8.84 2003 3.09) 2004 a. 34 2005 8.55 2006 8.76 2007 8.93 2008 S226 2003 9.42 2010 S251 2011 S252 2012 S273 2013 9.95 2014 10.41 2015 10.64 2016 10.86 2017 LIS 10 2018 L1S533 2019 11.56 2020 LIZ3S0 Total NPY 1987 Anchor 58.70 58.38 60.35 60.67 60.94 59.87 60.18 60.62 59.45 60.31 62.77 63.579) 64.71 65.63 66.59 67.56 67.96 68.97 69.65 70.65 71.84 72.90 Ca028 75.06 76.60 Cie 78.88 81.68 82.91 84.16 Fairbnk 32.47 33.60 34.56 34.88 35.79 36.21 37.19 38.19 37.75 39.87 33.78 38.87 33.50 40.14 39.93 40. 36 41.44 42.20 42.93 43.84 44.14 44.92 45.72 46.51 47.33 48.43 49.30 50.24 51.14 52.09 Total 99.63 101.19 103.73 104.41 105.60 104.96 106.14 107.60 105.95 107.96 111.43 111.50 113.30 114.11 115.07 116.68 118.38 120.43 122.00 123.80 125.50 127.55 129.65 131.98 134.57 137.01 139.28 143.25 145.61 148.05 I-~-Ken-Anc Only Case--~-I Ken/Anch Fairbnk 66.24 66.67 68.24 69.36 69.67 68.32 68.54 69.03 62.47 63.27 65.57 66.72 67.76 68.51 69.61 70.75 70379 72.06 72.81 73.86 75.32 76.58 77.85 739.25 80.92 82.24 83.59 86.48 87.30 89.35 31.76 32.85 33.¢73 34.89 35.79 36.58 Siicoo 38.57 37.00 38.10 38.90 38.23 38.86 39.34 39.13 39.52 40.62 41.36 42.03 42.87 43.42 44.16 44.93 45.60 46.37 47.42 48.24 439.10 49.96 50.85 Total 38.00 99.52 102.03 104.25 105.46 104.90 106.13 107.60 99.47 101.37 104.47 104.95 106.62 107.85 108.74 110.27 111.41 113.42 114.84 116.73 118.74 120.74 122.78 124.85 127-293 129.66 131.83 135.58 137.86 140.20 Operating Savings Loos 1.67 1.70 0.16 0.14 0.06 0.01 0.00 6.48 6.593 6.396 6.55 6.68 6.26 6.33 6.41 6.97 7.01 7.16 7.07 6.76 6.81 6.87 7-13 7.28 7.35 7.45 7.67 7.75 7.85 158.75 76.10 Kenai-Anchor Tie Only Case - Savings in Production Cost & Capacity Capital Savings oO Oo 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 1.41 2.81 2.81 2.61 2.81 2.81 2.81 2.81 2.81 1.41 1.41 1.41 1.41 1.41 1.41 1.41 50.66 26.14 Total Savings 1.63 1.67 3.11 1.57 1.55 1.47 1.42 1.41 7.89 8.00 8.37 7.396 8.09 7.67 7.74 9.22 93.78 93.82 3.97 3.88 3.57 3.62 9.68 8.54 8.69 8.76 8.86 3.08 Sal6 9.26 209.41 102.24 SyINsoy e2X Aq TeX - LE B19RL LL 39Q]104 UOISSTUSUDAL saaupusaiy ->S- dnosn 8unjnsuod sno7J Year 1991 igs2 1993 1994 1995 1996, 1997 1996 1332) 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Trotal NPV 1 Base Case vs. Anchorage-Fairbanks Tie Only Case - Savings in Production Cost & Capacity Kenai 8.46 8.61 8.82 8.86 8.87 3.88 B.77 Soe2 8.75 8.78 3.88 8.84 3, 09) 8.34 8.55 8.76 3.98 3.26 3.42 Soo. Booe Waco) 3.95 10.41 10.64 10.86 11.10 Li. S35 11.56 11.80 987 Anchor 58.70 58.98 60.35 60.67 60.94 59.87 60.18 60.62 59.45 60.31 G2577 63.79 64.71 65.63 66.59 67.56 67.96 68.37 69.65 70.65 71.84 72.90 73.98 75.06 76.60 Ciace 78.88 61.68 62.91 84.16 Fairbnk 32.47 33.60 34.56 34.88 35.79 36.21 37-19 38.19 37.75 38.87 39-75 38.87 33.50 40.14 39.93 40.36 41.44 42.20 42.93 43.84 44.14 44.92 45.72 46.51 47.33 48.43 43.30 50.24 51.14 52.09 Total 99.63 101.19 103.73 104.41 105.60 104.96 106.14 107.60 105.35 107.96 111.43 111.50 113.30 114.11 115.07 116.68 118.38 120.43 122.00 123.80 125.50 127.55 129.65 LSl 590 134.57 137.01 139.28 143.25 145.61 148.05 I------Anchor-Fairbanks Case----I Operating Cap Kenai Anchor Fairbnk Total Savings Sav 8.46 58.70 30.53 937.69 1.94 o 8.61 58.98 31.49 93.08 elt ° 8.82 60.35 32.31 101.48 2.25 0 8.86 60.66 32.40 101.92 2.49 0 8.87 60.93 33.16 102.96 2.64 o 8.88 59.87 33-01 101.76 3.20 o 8.77 60.17 33.76 102.70 3.44 o So. 79 60.62 34.53 103.94 3.66 °o 8.75 59.45 32.60 100.80 5.15 0 8.78 60.31 33.44 102.53 5.43 ° 8.88 62.77 34.33 105.38 5.45 ° 8.84 63.79 32. 7k 105.34 6.16 oO 3.09) 64.72 33.18 106.939 Gost Q 8.34 65.63 33.593 107.56 6.55 ° 8.55 66.58 32.42 107.55 7.32 oO 8.76 67.55 32.85 109.16 7.52 o 8.98 67.96 33.41 110.35 8.03 oO 9.26 68.97 335297 112.20 8.23 oO 9.42 69.64 34.38 113.44 8.56 Oo 9.31 70.65 35.08 115.04 8.76 Oo 9552 71.84 34.66 116.02 3.48 ° S275 72.90 35.18 117.81 9.74 Qo 3295 (3-97 Joe 119.65 10.00 Oo 10.41 75.06 36.26 121.73 10.25 o 10.64 76.60 36.87 124.11 10.46 oO 10.86 Coate 37-72 126.30 10.71 ° 11.10 78.88 38.51 128.49 10.79 oO 11.33 81.68 39.21 132.22 11-035 ° 11.56 82.91 39.87 134.34 Mcee ° 11.90 84.17 40.62 136.59 11.46 ° 210.59 o 101.17 ° Total Savings 1.94 2.01 2.25 2.49 2.64 3.20 3. 44 3.66 5.15 5.43 5.45 6.16 6.31 6.55 7.52 ace 8.03 8.23 8.56 8.76 9.48 3.74 10.00 10.25 10.46 10.71 10.79 11.03 11527 11.46 210.59 101.17 SyNsoy reoA Aq eX - gE oIqQUL 8. Appendices: 8.1. Description of the UPLAN Model UPLAN The Electric Utility Planning System An Integrated Utility Planning Model Major Features: ¢ Supply-Side Planning ¢ Demand-Side Management ¢ Financial Planning ¢ Uncertainty Simulation F1 £08 F2New MontvSave F3 Prev. F4 Next AR-A-Auto Mode | IBM PC/XT/AT/3270- or compatibles. F6 Restore F7 Help F8Overiay original F10Exit Al-Z-Annual Load Factor USAM CENTER Utility Software And Modeling Center 4962 El Camino Real, Suite 112, Los Altos, CA 94022 PADOCHSE (415) 962-9670 -8.1.1- The Electric Utility Planning System + INTEGRATED PLANNING + EXPLICIT UNCERTAINTY ANALYSIS + UNIFIED OPERATING ENVIRONMENT SUPPLY-SIDE PLANNING * Production Cost + Marginal Cost ¢ Optimal Generation Plan * Reliability Analysis DEMAND-SIDE MANAGEMENT ¢ End-use Model ¢ Load Management ¢ DSM Programs ¢ Marketing Programs FINANCIAL PLANNING ¢ Economic Analysis ¢ Financial Projections * Cost of Service Features: + State-of-the-art utility planning system ¢ Fast, accurate and flexible + Window-based, menu-driven environment + Integrated work station (IBM PC/ XT/AT/3270PC/ AT) * Powerful batch © interactive pro- cessing The Electric Utility Planning System The Electric Utility Planning System (UPLAN) is a powerful simulation tool designed to facilitate the analysis and evaluation of demand, supply and financial options facing utilities. This sophisticated, yet easy to use, system ex- pands the decision-making process by combin- ing demand-side management (DSM), optimal generation planning, production costing, reli- ability analysis, economic analysis and financial planning in a unified operating environment. UPLAN INTRODUCTION Comprehensive Modeling System UPLAN offers advanced modeling capabilities for: + Multl-area Production Costing + Chronological Dispatch of Time- Dependent Resources + Hourly Marginal Costing + Optimal Generation Planning + Reliability Analysis + Revenue Requirements and Economic Analysis + DSM Benefit Analysis * Integrated Demand/Supply and Financial Planning * Uncertainty Simulation * Cost of Service Determination UPLAN in Action Since the systems’ first commercial introduc- tion in 1984, UPLAN electric utility planning systms have found broad service in utility and research studies. UPLAN has demon- strated the accuracy, speed, ease of use, and dependability needed to support critical testimony. The range of applications which UPLAN can address is very wide. Some UPLAN studies already completed include: + Demand-side management evaluation in California * Resource planning and marginal cost analysis for West Coast utilities + Estimation of region-wide benefits of demand-side management programs for EPRI regional system -8.1.3- + Merger analysis and testimony in the Northeast + Long-term avoided cost analysis of cogeneration in Maine + Risk and financial analysis in Texas * Strategic planning, fuel plann- ing, and short-term avoided cost analysis in the Northeast + Least-cost resource planning in Nevada « Regional resource adequacy assessment by the U.S. Con- gressional Office of Technology Assessment * Optimal resource mix identifi- cation and service area benefits assessment in the Northwest + Minimum-load studies fora West Coast utility UPLAN INTERFACE UPLAN is an easy-to-run interactive software package consisting of a series of interrelated modules that simulate the planning process. The system uses multiple windows, function keys, on-screen help, and dedicated data entry editors to provide a user-friendly environment for entering, viewing, and on-screen editing tables and graphs. Window Based System UPLAN communicates with the user through ex- tensive use of windows. These windows help organize and present related data in a logical and easy-to-follow way. The system uses several types of windows, such as: + Command menu windows + File choice windows + Report windows + Status and help windows Command menus are used to choose and ex- ecute modules in UPLAN. These menus are organized hierarchically: if a command has a series of subcommands, secondary or sub- menus are displayed on the screen. Function Keys Predefined function keys, displayed on the appropriate menu, allow the user to ins- truct the system to perform § transactions such as help, show, save, delete and print. On-line Help The on-line help facility provides detailed information about individual modules, as well as a system diagram that explains sche- matically the data and logic flow typical of any UPLAN study. Data Entry Editors To create and edit data, UPLAN provides customized screen editors. Each class of input data; supply, financial, and load, has its own individually tailored screen-editor. UPLAN Unified Operating Environment UPLAN's window based batch-inter- active operating system manages both the system of models and the data base. “vor ESC wb quit End Create or modify financial input data tables -8.1.4- UPLAN has supply-side modules for: + Production Costing + Chronological Production Costing + Marginal Costing +» Optimal Generation Planning + Reliability Analysis + Economic Analysis + Interactive Capacity Planning « Uncertainty Simulation PRODUCTION COSTING UPLAN incorporates a two-area probabilistic costing simulation algorithm to provide fast and accurate month-by-month unit-by-unit produc- tion costing for up to 30 years. Each generating unit can be specified to be primarily dedicated to either the native area ora UPLAN SUPPLY-SIDE MODELS secondary service area. For the native service area, UPLAN uses the Mixture of Normal Approximation (MONA) algorithm. The MONA technique has proved superior to conventional production costing methods because the load is represented by a combination of distributions rather than by the single distribution common to traditional methods. Production costing features include: « Hydro optimization + Pumped storage dispatch ° Power purchase modeling + Multiple-block treatment of units « Non-economic dispatch capability ¢ Unit commitment algorithm * Chronological dispatch of time- dependent units Production Cost 7 Report: — Main Menu = ——— Deut 5 my Annual Detail c’upindata\SAMPLE1 .OTL Screen 1 RNM file:c NEWDEMO2.RNM-Change case sample run ‘Supply file:c:- NEWDEMO2.SPM-Base case sample run UPLAN produces SYSTEM REPORT FOR YEAR 1985 several production ENERGY (G' RELIABILITY COSTS(M$) . Demand “Seide17 PK Load (MW) 3215.30 Fx oan 32.50 cost reports with Unserve 49.95 Capacity (MW) 4080.00 Var O&M 17.45 varying degree of Net Gen. 16352.22 Reserve (%) 2689 Consum. 4.73 detail. The reports Storage 96.01 LOEP (%) 0.303 Fuel 202.06 ave TotalGen 16448.23. LOL (Dys/Yr) 7.410 Total 256.74 . Unit Capacity Energy a oe i a Cost + Unit-by-unit Name factor «= (GWH) «=: Var O&M otal MWH) NUCO8CO —«71.23.««4001.55 8485.63 4462087 53106.50 10.64 monthly report COLSSUB «75.14 © 3949.57 3049.57 62156.42 66105.99 116.74 + Unit-by-unit COL6SPRF 64.34 3381.80 7778.15 53153.32 6003147 18.02 annual report COL25SUB 42.05 920.84 «= 920.84 16322.39 17243.22 18.73 + Aggregate fuel COL2SSUB 23.85 522.35 522.35 10157.07 10679.42 20.44 ort COAL100 13.10 114.72 114.72 2801.75 2916.47 25.42 rep' COAL100 9.77 85.62 85.62 2206.06 229168 26.77 + Summary report COAL100 6.85 60.05 60.05 1620.30 1680.35 27.98 + 2nd area ALIOON 5.44 47.63 4763 1298.55 1346.18 28.26 . F2 Select screen, F3 Prev, F4 Next, FO tomain menu, Esc to quit, *.,PgUp, PgOn dispatch report Dae eae AN-P to print fle A Ls -2 1 &. UPLAN SUPPLY-SIDE MODELS CHRONOLOGICAL PRODUCTION SUBMODEL Using this module, generating units with capa- city which varies from hour to hour can be modeled directly. Planning applications for which this submodel is particularly well-suited include: + studies of minimum loading conditions due to unit commit- ment requirements, qualified facilities, and other restrictions * modeling time-varying power purchases Under this approach, an hour-by-hour capability shape is entered for each time-varying unit, and two-pass chronological dispatch simulation is performed. MARGINAL COSTING UPLAN determines the marginal cost of electri- city by computing the probability of a unit being at a margin for a given load level. The system reports marginal costs on an hourly, monthly percent of peak load, and percent of time basis. Marginal costs aid in the analysis of potential transactions, and can be used for rate- making. UNCERTAINTY SIMULATION UPLAN's uncertainty simulation is the first of its kind for the utility industry. This option allows systematic evaluation of uncertainty and risk factors associated with alternative planning op- tions using the Monte Carlo analysis technique. The user may define a number of critical variables as uncertain, such as load growth, capital costs and fuel prices, and specify low, high, most- likely values for them. Based on these uncer- tainty variables, UPLAN processes production costing simulations and produces distributions of variable and fixed production costs and financial projections. Defining an \ Uncertainty Distribution pores The range of the uncertainty variables such as load growth, capital costs and a fuel prices is ' ENTRIES CHOSEN LOW MOST LIKELY HIGH specified by Noot NUCO800 1977. 1970 1980 1990 choosing low, 001 COLESPRF 1974 1975 1985 1990 high and most likely values at run time. ESC to Exit S/S -8.1.6- OPTIMAL GENERATION EXPANSION (OGE) The OGE module determines the plant invest- ment program that minimizes total present value of capital and operating cost over a planning horizon. This option can be used in conjunction with the price elasticity option and uncertainty simulation option. INTERACTIVE CAPACITY PLANNER The interactive capacity planner can be used to quickly examine the major features of a capacity expansion plan. This module allows the user to modify the installation and retirement dates, and allows treatment of constraints which cannot be modeled with an optimization model. Input Data UPLAN's requirements for supply data are ex- tremely flexible to allow a wide-range level of detail. UPLAN SUPPLY-SIDE MODELS To generate unit information for screening studies, data can be entered for the first year of the simulation period and remain constant Seige he ly lite cycle of the study. For detailed analvsis, unit data can be up- dated every study year. Supply data includes the following: * Capacity, installation date, and tax depreciation schedule * Outage rates (forced and daily un- availability) « Heat rates (four load levels and average) « Fixed and variable O&M, consumables, and fuel costs + Monthly energy and capacity limitation « SOx, NOx, and particulate emissions ¢ Construction time and cost + Multiple block loading + Monthly planned maintenance schedule + Variable cost data for second area dispatch and parameters for unit commitment algorithm. Supply fr > Data Editor File Name: c:BASECASE.SPM Description: Base Case Tutorial Run * ‘Séreen One :General Unit information Unite 1-15 With the Supply oo Unit Size Number Flue gas Super- Date Book ACRS Data editor, ! Name (MW) of + Scrubber Critical Installed Lite Type users enter all Units (yes/no) (yes/no) (Yq 1-3 ie syatemi Noo! NUCOB00 oe 1 NO NO 1977 30 1 supply system C001 COLSSPRF 1 YES YES 1974 40 2 cost,engineering, on COLESUB 600 1 NO NO 1967 40 2 and transaction _ coL2ssuB 250 2 NO NO 1965 40 2 . ‘ C004 GOAL100 100 3 NO NO 192 40 2 information. (00S COALIOON 100 2 NO NO 198 40 2 The general unit CTO1 CTIOOA 50 3 NO NO 1972 30 1 information is CTo2 CT100B 5 2 NO NO 1970 30 1 i CTo3 CT100C 50 2 NO NO 1975 30 1 ee i a ae HOO1 HYDRO 60 NO NO 1975 45 2 ta entry PSO1PUMPSTOR 100 1 NO NO 1975 30 1 screens. CTo4 NEWCT 200 «1 NO NO 1989 30 1 F1:Save F3:Prev F4Next F5:Left F6:Right F10:Quit Alt-A:insert/Delete line XN v4 -8.1.7- UPLAN DEMAND-SIDE MODELS UPLAN integrates powerful demand-side ca- pabilities with supply and financial mo- dules. The system offers tools to: + Manage load-side data + Build daily load shapes libraries + Combine daily loads to form monthly end-use loads ¢ Build hourly system loads + Display graphically and modify load shapes at all levels of aggregation. With UPLAN, a user can create an annual lad shape for a group of customers or appliances. This end-use annual shape can be represented by seven hourly typical shapes for each month. In this manner, demand-side programs, which have been targeted for a particular customer class, can be analyzed individually. GRAPHICAL MODIFICATION OF LOAD SHAPES UPLAN can automatically modify load shapes to accommodate specified user requirements. Modify Annual Load Shapes The Annual Load Shape Graphics Editor graphically displays typical monthly load shapes and energies, and allows modifications to be made to these curves by directly working with graphs of the curves rather than with tables of data values. Modify Typical Day Type The Typical Day Graphics editor displays a 24 hour shape created in the day type editor. Changes can be made directly on the curve: as changes are made, the underlying data base is automatically updated. Load Shape Editor Modify Loads and Overlay Changes 3 5 :¢:SAMPLE1 .EHM of The graphic load shape editor allows on-screen load modification using the cursor keys. ° Sun F r a c t i ° n ° f Pp e a k 1 Value: 0.627 Load Factor: 0.7897 Month:January Monthly Peak: 268832 GW Original Load Factor: 0.7450 F1:Edit F2New Month/Save F3:Prev. F4:Next Alt-A:Auto Mode F5:Restore F7:Heip F8:Overiay original F10:Exit Alt-z: Annual Load Factor -8.1.8- AGGREGATE LOAD SHAPES Aggregation of Day Type into End-Use Loads In this module, month-by-month load shapes for end uses are created. The building blocks of an end-use shape are typical daily load shapes and energy forecasts for each day. Aggregation of End-Use into Annual Loads This module enables the user to group monthly end-use files into monthly system load files. The module is also used to add end-uses to, or subtract end-uses from, existing system load shapes. Compare Two Annual Loads This module computes and graphically displays differences between monthly system-wide load shapes. Differences can be used as residual load shapes. UPLAN DEMAND-SIDE MODELS DEMAND-SIDE MANAGEMENT UPLAN offers two complementary models for simulating demand-side management options. STRATEGIC LOAD MANAGEMENT (SLM) MODEL The SLM model handles changes at the stra- tegic level to the load shape. Using an on- screen graphics editor, the following changes can be performed on hourly loads: + Peak shaving + Valley filling * Load shifting and * Load factor modification. TOTAL STSTEM LOAD 30-0487 5 =o xeponv -8.1.9- Aggregate Load Shapes Up to 40 end- use load shapes can be aggregated using load aggre- gation models. UPLAN DEMAND-SIDE MODELS PROGRAMMATIC LOAD MANAGEMENT (PLM) + Shifts energy from a particular MODEL hour or block of hours to other hours The PLM model handles detailed changes to the load shape. Using a spread-sheet-like + Shifts energy from classes of interface, specific amounts of energy may be days to other classes added to, subtracted from, or shifted among hours or block of hours. « Substitutes one day type for another day type. Useful in In this way, utility load data can be used in other modeling DSM programs (DLC, models. appliance, AC cycling, etc.) Load Management r Select months for demand management ii; Programmatic Load Changes 2.95043 2.84507 2.63435. 2.52899 2.70459 3.19627 PLM module allows implementation of load management 3.16115 option interactively Sone by specifying one of 2.73071 the three types of 2.91531 changes. 3.00056 -8.1.10- MARKET PENETRATION MODEL The market penetration model enables the user to estimate the load shape impact and program- by-program market shares of up to twelve demand-side management (DSM) or energy marketing programs. The penetration level is calculated using a diffusion theory approach, and market shares are estimated by means of a logit-type model. The model evaluates energy changes on an hourly basis, and develops benefit-cost ratios based on levelized program cost and marginal production costs. Estimating Market Penetration and Program Market Shares UPLAN uses diffusion theory to estimate the number of customers expected to adopt the program. The user specifies the starting date of UPLAN DEMAND-SIDE MODELS the program and its duration as well as the expected number of participants. UPLAN will generate an S-curve which graphically displays the level of customer participation. DSM Program Energy Savings When the participation levels have been determined, the user enters the seasonal energy savings by time-of-use periods. When more than one program is specified, a cost- effectiveness measure is used to determine Program market shares. UPLAN uses an iterative Procedure to estimate a stable level of market penetration among programs. Hourly marginal costs for the specific customer classes are required for this calculation. PF Number Participants Penetration Rates Elapsed Time From Program Start (Months) -8.1.11- UPLAN DEMAND-SIDE MODELS BENEFIT-COST ANALYSIS FOR DEMAND-SIDE MANAGEMENT (DSM) PROGRAMS The UPLAN benefit-cost model uses avoided costs from production cost simulation to estimate benefit-cost ratios, net present value, and rate impacts for demand-side management (DSM) programs. These estimates are developed and reported on a class-by-class basis for each customer class, and for the utility. Benefit-Cost Calculations The benefit calculation for a DSM program is based on the avoided costs associated with the program for each class of customer. The energy component of avoided cost is allocated among the customer classes on an hourly basis. Capacity savings are allocated across classes using a coincident peak rate design method. Rate impacts are calculated, and using the rate impact measure information, benefit-cost ratios and net present program value are calculated for each customer class. ‘ UPLAN Benefit- ie 5 Cost ciupindatalSAMPLE .CBO Model Output UPLAN Benefit-Cost Report PV Rate impact B/C per NPV Class 1986 mills/kWh Customer | ($/customer) Participants: Class 2 -35.420 19.19 562.54 Non-Participants . Class 1 0.714 0.00 -166. 70 Class 3 0.863 0.00 -140. 76 Class 4 0.536 0.00 -160. 95 Utility: 0.006 0.00 45.05 Esc: Return to Main Menu. Altt-P: Print Screen. = -8.1.12- Financial Simulation UPLAN has three financial models: + Strategic Model + Long Range Model + Short-term Tactical Model The Strategic Financial Model determines the net income, retained earings, income taxes and required revenue on an annual basis. The other two models are written in IFPS, the fourth gene- UPLAN FINANCIAL MODELS ration financial language. These two models can be used where greater detail is required. Additionally, the users can modify the codes to meet their individual nees. The Strategic Model produces: + Annual balance sheets + Income statements + Flow of funds statements + Financial report summaries Strategic Financial lodel -8.1.13- UPLAN FINANCIAL MODELS COST OF SERVICE The Cost of Service module uses the time-of- day rate structure. This module is used to com- pute both time-differentiated and nontime-differ- entiated rates for up to twelve customer rates. The standard module allocates energy-related costs using the time-differentiated marginal cost method, while the fixed cost is distributed by non-coincident peak responsibility. If necessary, USAM Center can customize the Cost-of- Service module for other rate-making metho- dologies. 7 Rate Report: Main Menu 5 [Rete Reports 5 ) Peak-Period CAupindata\SAMPLE1 COS Changes Distribution of Rates Prior to Adjustment Peak Period Year 1990 Customer Class (Mills/KWH) Class 1 Class 2 Class 3 Average Rate report produces rates Energy 16.70 20.04 15.18 17.33 by customer Customer 0.00 0.00 0.00 0.00 classes for peak Demand 3.95 4.74 3.59 4.10 period, off-peak Po 0.00 0.00 0.00 0.00 period and aver- Customer 0.00 0.00 0.00 0.00 age base. Up to Demand 4.70 5.36 6.26 5.42 12 customer Distribution Energy 0.43 0.51 0.39 0.44 classes ican = Customer 7.21 4.88 0.38 4.25 specified. Demand 1.50 1.80 1.37 1.56 Total 34.49 37.33 27.17 33.09 F2 Select screen, F3 Prev, F4 Next, F9 to main menu, Esc to quit, *, v, PgUp, PgOn AI-P to print fle S -8.1.14- LONG-RANGE FINANCIAL MODEL The UPLAN Long-Range Financial Model simulates utility financial operations on an annual basis in full detail. While the Long-Range Model is completely integrated with the UPLAN system, i can also be customized by the user to meet the particular modeling needs and reporting requirements of the individual utility. The LRFM simulates utility financial operatons to determine annual extemal financing requirements and rate adjustments. it also simulates revenue and revenue requirements, and calculates the effects of regulatory lag. The principal driver of the model can either be rate of return or rates. The long-range model's major features include: * fuel inventory modeling * project construction analysis * detailed tax modeling * explicit regulatory lag simulation * project-level accounting * extended extemal finance options Sk& standard reports are produced by the model. These reports include income statements, O&M breakdown, sources and uses of funds, balance sheet, financial performance, financial UPLAN FINANCIAL MODELS Statistics, coverage ratios, electric rates, and sources of contributions to revenue. The long-range mode! makes use of the IFPS Interactive Financial Planning System. IFPS is a fourth-generation interactive financial modeling language. IFPS includes facilities which enable the financial planner to easily modify the default model to customize the content and layout of reports. SHORT-TERM TACTICAL MODEL The Short-Term Tactical Model offers highly detailed, month-by-month financial simulation and reporting. The model's design support the tracking of short-term flows and budgeting. It includes disaggregate monthly reporting of revenues, broken out by major customer class, current and deferred tax status, operating revenues and expenses, interest expenses by call of investment, and full financial and operating Statistics, Including Moody's ratios, key financial indicators, and rates. The model allows customization of plant accounting, rate calculations, revenue calculations, and fuel Clause adjustment mechanisms. Like the Long Range Financial Model, the Short- Term Tactical Model makes use of the IFPS Inter- active Financial System. e@11c UPLAN REPORT WRITERS REPORTING UPLAN produces a wide range of reports. | canbe controlled bythe users. These reports summarize the results of supply, demand and financial models. The number of | UPLAN command menus are used to select, reports and the level of detail in these reports aa and print all reports produced by Detail Finance ( \ Report: [Main Menu = [7 Detal Finance + . cAupindatasSAMPLET FDG con Financial and RNM fiexc‘NEWDEMO .RNM-DEMO i . Sen Supply fie :C:DEMO.SPM-Demonstration supply data fle rma! ystem and Financial Report al ae i 19980 1901 1992 1993 pci oat (Billion ii 18.23 18.43 18.68 18.79 . (Megawatts 3562.00 3600.00 3660.00 3670.00 Financial Model Capacity Margin(%) 19.05 2258 21.51 21.08 reports include: Reserve Margin (%) 23.53 29.17 27.40 26.70 Ful Price ($/MWH) 17.72 18.92 20.77 22.63 Price ($MWH) 46.89 53.91 54.92 62.16 + Balance Sheet Total Price (S/MWH) 64.61 72.84 75.69 84.70 * Income State- Base Price increase (M$) 635.97 120.41 18.85 136.06 ment Retum on Eauty ~ 10.00 10.00 : 10.00 : 10.00 . Eamings Per Share $ 106 8 8$ 1.76 1.76 1 Flow of Funds # of Shares Outstanding 53.55 56.78 58.57 75.83 + Supplemental Market Price-Common Stock$ 20.00 18.93 20.77 2.7 Reports Book Value/Share-Common $ 17.21 18.80 20.70 22.92 interest Coverage Ratio 1.258 1.396 1.373 1.236 Ext. Fina. as % of Construc. 4531.23 86.16 40.44 81.29 PV of Revenue Rea. (MS) 1,177.63 2,471.49 3,784.75 5,251.30 Smoothed Elec. Cost($) 64.61 68.67 70.96 74.34 F2 Select screen, F3 Prev, F4 Next, F9 fo main menu, Esc to quit, “, v, PgUp, PgOn Cs ARP to print fe Bec TIT S Uncertainty Outcome: Frequency Plots The results of the UPLAN Uncertainty Model are shown as frequency charts as well as in tables and sample statistics. -8.1.16- Name of Report Aggregate Monthly Marginal Cost Time of Day Percent of Time Detail Finance 2nd Area Detail 2nd Area Monthly Opt Exp Report Cost of Service UPLAN REPORT WRITERS UPLAN Report Types Description System-wide summary production cost reports, to both deterministic and uncertainty cases. Aggregate annual production cost reports, with generating units grouped by fuel type. Annual unit-by-unit production cost reports for standard production cost and second area dispatch cases. Month-by-month, unit-by-unit production cost reports for standard production cost and second area dispatch cases. Annual and monthly marginal costs at percentages of peak load. Hour-by-hour marginal costs. Expected marginal costs along the time axis of the load duration curve. Summary financial indicators for the full study period. Detailed annual financial reports. Annual detailed production reports from the second area dispatch model. Monthly detailed dispatch reports from the second area dispatch model. Optimal generation expansion plan report. Cost per KWH for residential, commercial and industrial customers (selected customer classes) for generation, transmission and distribution. These reports can also be transferred to Lotus Se met ss oeeeal (areas 1-2-3 or Symphony spread sheet/graphic pack- | sheets erfaces age. in this way the user candevelop custom- Package are available from the USAM Center. ized reports and charts. Customized spread -8.1.17- About USAM Center The Utility Software and Modeling Center offers a full range of software products and consulting services in support of electric utility system analysis. Since 1982, we have served the utility industry with: + basic research in utility modeling methods + software development of utility planning tools * consulting, study design and execution for supply-side and demand-side studies + training and customer support In utility planning methods and in the use of our software systems * expert witness testimony Our commitment to complete client support is indicated by the range of our services. Training and Seminars USAM Center offers both specific training in the use of UPLAN and special topic seminars on techniques for strategic planning. Training in the use of our models is provided either at our facility in Los Altos or at a client's home site. Users Group Active UPLAN Users’ Groups exist throughout the United States. The groups teleconference and meet periodically to exchange ideas and techniques about the use of UPLAN in modeling different utility problems. Advisory Council The UPLAN Advisory Council offers high level, independent evaluation and recommendations for UPLAN system extensions and enhance- ments. For a list of current members, please contact USAM Center Support Services USAM Center provides complete client support for our utility modeling systems. These are available through: + Telephone hotline service: Ourtechnical analysts are available to respond to inquires conceming UPLAN software, and responses are provided within a single working day. ¢ On-site visits: Our client service staff is available for support to review and recommend UPLAN applications and trouble-shoot problem areas. « Consulting services: Our consulting staff has the experi- ence and capabilities to support our clients needing assistance to meet strict deadlines and special project requirements including: - Least-Cost Resource Planning Studies - Regulatory Analysis and Expert Testimony - Strategic Planning and Scenario Analysis - Custom Utility Model Development - Litigation Support « USAM Center Newsletter. The Newsletter is published quarterly. It provides a forum for users and other interested parties to exchange ideas and methods about the use of our planning system. The Newsletter includes correspondence from users, new product and update information, and general and technical planning articles, and ways to tame Julie. -8.1.18- Least-Cost Utility Planning + UPLAN integrates Demand-Side and Supply-Side options to develop the least-cost resource plan which satisfies economic, reliability, and financial criteria. * UPLAN includes a comprehensive financial model for evaluating the impact of the least-cost plan on the utility's financial integrity. * UPLAN Includes optional operation planning, production costing, reliability analysis, and uncertainty models to facilitate development of a least-cost plan that is flexible in coping with risk, considering uncertainties such as load growth, capital costs, and fuel costs. -8.1.19- HARDWARE REQUIREMENTS Computer: IBM PC/XT/AT, 3270-PC/AT or compatibles Minimum 640KB (Optional: 4MB RAM Disk) Required (code: 1.75MB, data: 1.5MB) 8087/80287 math coprocessor required IBM color graphics adapter, enhanced graphics adapter, or compatibles USAM CENTER Utility Software and Modeling Center 4962 El Camino Real Los Altos, CA 94022 (415) 962-9670 -8.1.20- 8.2. Supply Input Data Sets -1°2"8- Table 8.2.1 ANCHORAGE-OOOK INLET AREA EXISTING PLANT DATA, DEC. 1984 (Page 1 of 3) Operation Period Generating Heat Rate Outage Rates Unit Settee Retire Capacity @ Gen. O&M Costs (1985 $) Planned Forced Name Date Date 30°F Capacity Fixed Variable Outage Outage (Mw) (Btu/kWh) ($/kW/yr) ($/MWh) (Ztime) (Ztime) Alaska Power Administration Eklutna 1955 2055 30.0 — = 19.0 - - Anchorage Municipal Light and Power AMLPCT#1 1962 1990 16.2 15,329 10.12 5.67 12.0 5.0 AMLPCT#2 1964 1990 16.2 15,329 10.12 5.67 9.7 5.0 AMLPCT#3 =—1968 1991 19.9 14 ,089 10.12 5.67 12.3 5.0 AMLPCT#4 =: 972 1992 33.8 13,901 ~ 10.12 5.67 13.5 5.0 AM CC#56 8611979 1999 47.5 10,570 12.79 0.92 11.0 5.0 AM CC#76 =—:11979 1999 109.3 9,365 12.79 0.92 11.0 5.0 AMLPCT#8 1984 2009 87.0 12,000 12.79 0.92 14.8 5.0 nnn 0 EE Total AMLP Capacity 329.9 ee LEE . -7°7°8- (Page 2 of 3) Table g.2.1 . Operation Period Generating Heat Rate Outage Rates Unit Onl ine Retire Capacity @ Gen. O&M Costs (1985 $) Blanned® Forced Name Date Date 30°F Capacity Fixed Variable Outage Outage (uw) (Btu/kWh) ($/kW/yr) ($/MWh) (Ztime) (2c ime ) Chugach Electric Association BEL CT#1 1968 1994 16.1 16,100 11,21 1.40 10.3 5.0 BEL CT#2 1968 1994 16.1 16,100 11.21 1.40 9.0 5.0 BEL CT#3 =:1972 1999 49.5 12, 800 11.21 1.40 12.8 5.0 BEL CT#& 1976 1996 10.0 17, 500 11,21 1.40 11.5 5.0 BEL CT#S5 1975 1999 67.3 12, 400 11.21 1.40 12.8 5.0 BEL CC#68 1976 2007 100 .6 9,600 11.21 1.40 11.5 6.0 BEL CC#78 1976 2007 100 .6 9,600 11.21 1.40 11.5 6.0 BERNCT#1 1963 1988 8.9 17,300 10.03 2.19 9.0 5.0 BERNCT#2 1971 * 1997 18.4 14,500 10.03 2.19 9.0 5.0 BERNCT#3 1978 2004 27.2 13,700 10.03 2.19 10.3 5.0 BERNCT# = =1981 2004 27.2 13, 700 10.03 2.19 12.8 5.0 INT cT#l 1965 1996 14.3 18,000 19 .39 13.47 7.7 5.0 INT CT#2 1968 1996 14.3 18 ,000 19.39 13.47 7.7 5.0 INT CT#3 1970 1996 19.9 14,500 19.39 13.47 15.4 5.0 OOO PER 1960 2055 17.4 - - 7.4 - = Total CEA Capacity 507.8 -€°2°8- Table 3.2.1 (Page 3 of 3) . Operation Period Generating Heat Rate Outage Rates Unit OAT ine Retire Capacity @ Gen. O&M Costs (1985 $) ¥igaael Forced Name Date Date @ 30°F Capacity Fixed __- Variable Outage Outage (mw) (Btu/kWh) = ($/kW/yr) ($/MWh) (Zeime) (Ztime) Homer Electric Association SELDIC#l 1952 1990 0.3 14,998 2.81 38.80 4.0 5.0 SELDIC#2 1964 1994 0.6 12,006 2.81 38 80 4.0 5.0 SELDIC#3 1970 2000 0.6 12,006 2.81 38.80 4.0 5.0 SELDIC#4 1982 2012 0.6 12,006 2.81 38.80 4.0 5.0 Total HEA Capacity 2.1 Seward Electric System SES IC#l 1965 . 1990 1.5 15,000 0.59 5.72 1.0 5.0 SES IC#2 1965 1990 1.5 15 ,000 0.59 5.72 1.0 5.0 SES IC#3 1965 1995 2.5 15,000 0.59 5.72 1.0 5.0 Total SES Capacity 5.5 -°Z"8- Table 3.2.2 FAIRBANKS-TANANA VALLEY AREA EXISTING PLANT DATA, DEC. 1984 ; Operation Period Generating Heat Rate Outage Rates Unit Online Retire Capacity @ Gen, O&M Costs (1985 $) Planned Forced Fixed Variabl Name Date Date @ 30°F Capacity fariable Outage Outage (mw) (Btu/kWh) ($/kW/yr) ($/MWh) (Xtime) (time) Fairbanks Municipal Utility System CHENST#1 1954 2000 5.1 15,968 51.12 1.22 6.0 6.0 CHENST#2 1952 2000 2.0 18,049 51.12 1.22 6.0 6.0 CHENST#3 1952 2000 1.5 18,091 51.12 1,22 6.0 6.0 CHENST#4 ©1963 1985 6.1 12,894 8.761/ 0.58l/ = 3.0 8.0 CHENST#5 1970 2005 20.0 14,2% 73.57 0.64 6.0 6.0 CHENST#6 1976 2006 26.1 42,733 8.761/ 0.58l/ 3.0 8.0 FMUSIC#1 1967 1992 2.8 12,128 0.87 22.82 2.0 5.0 FMUSIC#2 1968 1992 2.8 12,128 0.87 22.82 2.0 5.0 FMUSIC#3 1969 1992 2.8 12,128 0.87 22.82 2.0 5.0 Total FMUS Capacity s . ny Golden Valley Electric Association HEALST#1 1967 2002 25.0 12,750 69.96 4.11 7.0 1.8 HEALIC#2 1967 - 1997 2.6 11,210 0.59 5.72 20 .0 1.0 NOPOCT#1 1976 2006 60.9 9,500 7.42 1.43 15.0 1.0 NOPOCT#2 81977 2007 60.9 9,500 7.42 1.43 15.0 1.0 ZEN CT#1 1971 2001 18.0. 14,869 8.79 0.59 15.0 1.0 ZEN CT#2 = =:1972 2002 18.0 14,869 8.79 0.59 15.0 1.0 DSL IC#l 1961 1991 1.9 11,209 0.59 5.72 20.0 5.0 DSL IC#2 1961 1991 1.9 11,209 0.59 5.72 20.0 5.0 DSL Ic#3 1961 1991 1) 11,209 0.59 5.72 20.0 5.0 DSL Ic#5 1970 2000 2.6 11,210 0.59 5.72 20 .0 5.0 DSL IC#6 1970 2000 2.6 11,210 0.59 5.72 20.0 5.0 UAF IC#7 =1970 1996 1.9 11,209 0.59 5.72 20.0 5.0 UAF IC#8 =1970 1996 1.9 11,209 0.59 5.72 20.0 5.0 Total GVEA Capacity 200.1 1J/ applicant's estimate of O&M costs used. O3-22-1987 13:06:54 File Name: b:KENAIRSA.SFM Description :Kenai Supply Model Unit Unit Size Number Flue gas Super- Date Book ACRS ID Name (MW) of Scrubber Critical Installed Life Type Units (yes/no) (yes/no) (Yr) 1-3 bernct2 bernice2 18.0 1 no no 1971 26 1 bernct3 bernices 27.0 1 no no 1978 26 1 bernct4 bernice4 27.0 1 no no 1981 23 1 bradley bradleyH 90.0 1 no no 1990 65 1 cooperl cooper H 18.0 1 no no 1975 99: 1 gtk ctl soldatCT 38.0 1 no no 1985 25 1 sldic2 seldic2 1.0 al no no 1964 99 1 sldic34 seldic34 1.0 1 no no 19790 99 2 ses ic3 seward3 2.0 1 no no 1965 99 1 ses ic4 seward4 2.0 1 no no 1985 99 1 ses icS sewardS 3.0 1 no no 1986 99 1 ses ic&é sewardé 3.0 1 no no 1990 99 1 new cti new ctl 40.0 1 no no 2004 20 1 new ct2 new ct2 40.0 1 no no 2010 20 1 new ct3 new ct3 235.0 1 no no 2014 25 1 -8.2.5- Unit Ip Description bernct2 bernctsS bernct4 bradley cooper 1 gtk ctl sldic2 sldics4 ses ses ses ses new new new ics ic4 ic ic6é ett etrZ cts Unit Name bernice2 bernicesS bernice4 bradleyH cooper H soldatCT seldic2 seldici4 sewards seward4 sewardsS sewardé new ctl new ct2 new ct Description :Ken Unit ID bernct2 bernctS bernct4 bradley cooper! gtk cti sldic2 sldic34 ses ic3 ses ic4 ses icS ses icé new ctl new ct2 new cts Unit Name bernice2 bernicesS bernice4 bradleyH cooper H soldatCT seldic2 seldic34 sewards seward4 sewardS seward6 new new new ctl ct2 ets zkKen File Name: Supply Model al Size (MW) 18.0 Nb NOOUWUWNNKe eceoooo0ooco File Name: ai Supply Model Size Unsche. (MW) Outage Rate (Z) 18.0 5.0 LiiiO 5.0 Ziel 5.0 90.0 0.0 18.0 0.0 38.0 5.0 1.0 5.0 1.0 5.0 2. 5.0 ZO) 5.0 3.0 5.0 3.0 5.0 40.0 8.0 40.0 8.0 25.0 8.0 HEAT RATES 100% 735% 14500 14805 13700 14082 13700 14082 12785 13763 12006 12262 12006 12362 15000 15451 15000 15451 15000 15451 15000 15451 -8.2.6- b:KENAIRSA. SFM Daily Unavail. (7%) o.0 0.0 ccoococoocce ecoooo00co0o0od b: KENAIRSA. SPM (EBTU/KWH AT SOx 16050 15284 15284 15768 13667 13667 17064 17064 17064 17064 25% % OUTPUT) AVERAGE 14805 14082 14082 13763 12362 12362 15451 15451 15451 15451 12095 12095 12095 File Name: b:KENAIRSA.SFM Description :Kenai Supply Model Unit Unit Size Maximum Capacity Factor ID Name (MW) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec CL) (hd C4 COZY OLY OLY CKD 6%) 0%) OK) OK CK) bernct2 bernice2 18.0 bernctS bernices 27.0 bernct4 bernice4 27.9 bradley bradleyH 90.0 62.459. 447.239. 630.419.925. 941.154.859.459. 462.4 cooperl cooper H 18.0 4S. 730.422.830.411.411.4 7.615.215.2350. 445.745.7 gtk ctl soldatCT sldic2 seldic2 sldict4 seldic34 ses ic3 seward3 ses ic4 seward4 ses icS sewardS ses icé sewardd new ctl new ctl new ct2 new ct2 new ct3 new ct3 uw oO ° . NUOOUUNNK eK eo00o00coodcsdg Nps File Name: b:KENAIRSA. SPM Description :Kenai Supply Model Unit Unit Size Fixed Variable Cost of Fuel Fuel ID Name (MW) O&M Cost O&M Cost Consumables Cost Type ($/KW-YR) ($/MWH) ($/MWH) (#/MBTU) bernct2 bernice2 18.0 10.230 2.23 0.9 1.60 GAS bernct? bernices 210 10.230 2.23 0.0 1.60 GAS bernct4 bernice4 2720 10.230 2.23: Qa.0 1.60 GAS bradley bradleyH 90.0 24.600 0.00 0.0 0.00 WAT cooperl cooper H 18.0 17.360 0.00 0.0 0.00 WaT gtk ctl soldatCT 38.0 11.265 1.43 0.0 1.60 GAS sldic2 seldic2 1.0 2.864 39.357 0.0 7.00 FO2 sldic34 seldic34 1.0 2.864 39.37 0.0 7.00 FO2 ses ic3 seward3 2.0 0.603 5.84 0.0 6.50 FO2 ses ic4 seward4 2.0 0.603 5.84 0.0 6.50 FO2 ses icS sewardS 3.0 0.603 5.84 0.0 6.50 FO2 ses icé seward6é 3.0 0.603 5.84 0.0 6.50 FO2 new ct1 new ctl 40.0 8.760 0.58 0.0 1.60 GAS new ct2 new ct2 40.0 8.760 0.58 0.0 1.60 GAS new ct3 new ct3 25.0 8.760 0.58 0.0 1.60 GAS -8.2.7- File Name: b:KENAIRSA.SPM Description :Kenai Supply Model Unit Unit Size Maintenance Days ID Name (MW) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec bernct2 bernice2 18.0 8 25 bernct3 bernicesS 27.0 20) | 17 bernct4 bernice4 27.0 14 14 18 bradley bradleyH 90.0 cooperl cooper H 18.0 gtk cti soldatCT 38.0 10) tO) | 12 sldic2 seldic2 1.0 8 7 sldic34 seldic34 1.0 8 7 ses ics seward? 2.0 1 3 ses ic4 seward4 2.0 1 3 ses icS sewards 3.0 1 3 ses ic&S sewardé 3.0 1 3 new ctl new ctl 40.0 10 10 12 new ct2 new ct2 40.0 tz) to) | 10 new ct3 new ct3 25.0 12 10) | 10 -8.2.8- 23-23-1987 11:53:48 File Name: c:ANCHRSA .SPM Description :Anchorage Supply Model Unit. Unit Size Number Flue gas Super- Date Book ACRS ID Name (MW) of Scrubber Critical Installed Life Type Units (yes/no) (yes/no) (Yr) 1-3 EKLU EklutnaH 30 1 no no 1955 99 1 AMLPCT1 Anc CT 1 16 1 no no 1962 25 1 AMLPCT2 Ane CT 2 lo 1 no no 1964 2S 1 AML.PCT3 Anc CT 3 20 1 no no 1968 23 1 AMLPCT4 Anc CT 4 34 1 no no 1972 20 1 AM CCSé Anc CCS6 48 1 no no 4979 20 uf AM CC76 Anc CC76 109 L no no L979 20 1 AMLPCT8 Anc CT 8 87 1 no no 1984 25 1 AMLPCTS Anc CT 9 87 it no no 2050 38 1 Bel CT1 BelugCT1 16 1 no no 1968 26 1 Bel CT2 BelugCT2 16 1 no no 1968 26 t Bel CT3 BelugCT3 50 1 no no L972 27 1 Bel CT4 BelugCT4 10 1 no no 1976 20 J, Bel CTS BelugCTS 67 il no no 1975 24 1 BelCCé6é8 BelgCCé8 101 at no no 1976 31 iL belgC78 BelgCC78 101 1 no no 1976 31 1 Int CT1 IntncT1l 14 1 no no 1965 31 1 Int CT2 IntncT2 14 a no no 1968 28 1 Int CT3 IntncT3 20 1 no no 1970 26 1 NewCC76 New CC76 180 1 no no 1999 25 1 NewBCT3 NewBCT 3 so 1 no no 1994 27 1 New8CT4 NewBCT 4 50 1 no no 1996 2 1 NewBCTS New8CT 5S 67 1 no no 1999 25 1 New8CT6 NewB8CT 6 so 1 no no 1999 25 ie NewBCC6é NewBCC6é8 101 1 no no 2007 31 1 NewBCC7 NewBCC78 101 1 no no 2007 ok 1 NewCT10 New CT10 50 1 no no 2007 25 1 NewCT11 New CT11 87 1 no no 2009 25 1 NewCT12 New CT12 so 1 no no 2015S 25 1 NewCT13 New CT13 50 1 no no 2018 25 1 Nw8CT14 NewBCT14 50 1 no no 2002 25 if NwBCT15 New8CT15 50 1 no no 2011 25) r -8.2.9- Description Unit ID EKLU AMLPCT1 AMLPCT2 AMLPCT3 AMLPCT4 AM CCS56 AM CC76 AML PCTS AML PCTS Bel CTl Bel CT2 Bel CT3 Bel CT4 Bel CTS BelCCé8 belgC78 Int CTl Int CT2 Int CTS NewCC76 New8CT3 NewB8CT4 NewBCTS New8CT6 NewBCC6 New8CC7 NewCT10 NewCT11 NewCT12 NewCT13 NwBCT14 NwBCT15 Unit Name EklutnaH Anc Anc Anc Anc Anc Anc Anc Anc ct 1 ct 2 ct 3 cT 4 CCS6 CC76 cT 8 cT 9 BelugCT1l BelugCT2 BelugCTS BelugCT4 BelugCTS BelgCCé8 BelgCC78 IntncT1l IntncT2 IntncT3 New CC76 NewBCT 3 NewBCT 4 NewBCT S NewBCT 6 New8CC68 New8CC78 New New New New cT10 evil cT12 cT13 NewBCT14 NewBCT15 File Name: c:ANCHRSA :Anchorage Supply Model Size (MW ) 30 16 16 20 34 48 109 87 87 16 16 50 10 67 101 101 14 14 20 180 sO sO 67 sO 101 101 sO 87 sO so so 50 Unsche. Outage Rate(%) 0.0 CODDD00000000000000000000000009 DDDMDMDMDAWDAMDAAWDAAAADWDAAAABRANNNNNNNAN -8.2.10- Daily Unavail. %) 0.0 fomomononomonononeononononononononononononeonononononononononene) CODDDDDDDDDDDDDDDODDOOAOCOOCOOGOOCC0OO e -S PM Nescription Unit ID EKLU AMLPCT1 AML PCT2 AMLPCTS AML PCT4 AM CCS6 AM CC76 AMLPCTS AMLPCT9 Bel CTl Bel CT2 Bel CT3 Bel CT4 Bel cTS BelCcé68s belgC78 Int CTl Int CT2 Int CT3 NewCC76 NewBCTS NewBCT4 New8CTS NewBCT6 NewBCC6 New8CC7 NewCT10 NewCT11 NewCT12 NewCT13 NwBCT14 NwBCT1S Unit. Name EklutnmaH Ane Anc Anc Anc Anc Anc Anc Anc cT 1 cT 2 ct 3 cT 4 cCS6 CC76 cT 8 ct 9 BelugCTl BelugCT2 BelugCT3 BelugCT4 BelugCTS BelgCCé8 BelgCC78 IntncTl IntncT2 IntncT3 New CC76 New8CT 3 NewBCT 4 NewBCT 5 NewBCT 6 NewBCC68 New8CC78 New New New New cT10 ceTil cT12 cT13 NewBCT14 NewBCT15 File Name: ¢:ANCHRSA :Anchorage Supply Model Size (MW) 30 1é 16 20 34 48 109 87 87 16 16 so 10 67 101 101 14 14 20 180 so 50 67 sO 101 101 so 87 50 sO sO so HEAT RATES 100% 15329 15329 14089 13901 11209 9017 11810 11810 15314 15314 11344 17500 12963 9391 9391 19371 19371 16627 9391 9391 9391 7S% 16743 16743 15439 14910 12039 9367 12095 1209S 15602 15602 11723 18284 13448 9831 9831 19894 19894 18248 9831 9831 9831 -8.2.11- SPM (BTU/KWH AT 50% 20193 20193 18147 18475 14029 14029 rir 17119 13136 20110 15012 10981 21716 21716 21679 25%; x OUTPUT) AVERAGE 16743 16743 15439 14910 12039 9367 12095 12095 15602 15602 11723 18284 13448 9831 9391 19894 19894 19894 9831 12095 12095 12095 12095 9391 9391 12095 12095 12095 1209S 12095 12095 Description Unit ID EKLU AMLPCT1 AMLPCT2 AMLPCTS AMLPCT4 AM CC56 AM CC76 AMLPCTS AMLPCT9 Bel CT1l Bel CT2 Bel CTS Bel CT4 Bel CTS BelCCé8 belgcC78 Int CT1l Int CT2 Int CT3 NewCC76 NewBCTS New8CT4 New8CTS NewBCT6 NewBCC6 New8CC7 NewCT10 NewCT11 NewCT12 NewCT13 NwBCT14 NwBCT15 Unit Name EklutnaH Anc Anc Anc Anc Anc Anc Anc Anc CT i cT 2 cT 3 cT 4 ccsé CC76 cT 8 ct 9 BelugCT1l BelugCT2 BelugCTS BelugCT4 BelugCTS BelgCCé8 BelgCC78 IntncTl IntncT2 IntncT3 New CC7é6 New8CT 3 NewB8CT 4 NewBCT 5 New8CT 6 NewBCC68 New8CC78 New New New New cT10 cTll cT12 cT13 New8CT14 NewBCT15S :Anchora Size (MW) 3G 16 16 20 34 48 109 87 87 16 16 so 10 67 101 101 14 14 20 180 sO so 67 50 101 101 50 87 sO so so 50 File Name: ¢:ANCHRSA .SPM ge Supply Model Maximum Capacity Factor Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) 63 .954.754.745.754.754.759.459.459.463.965.963.9 -8.2.12- File Name: c:ANCHRSA .SPM Description :Anchorage Supply Model Unit Unit Size Fixed Variable Cost. of Fuel Fuel ID Name (MW) O&M Cost O&M Cost Consumables Cost Type ($/KW-YR) ($/MWH) ($/MWH ) ($/MBTU) EKLU EklutnaH 30 99.484 WAT AMLPCT1 Anc CT } 16 10.320 5. 79) 0.0 22d GAS AMLPCT2 Anc CT 2 16 10.320 5.79 0.0 220 GAS AMLPCT3 Anc CT 3 20 10.320 S79 9.0 2.20 GAS AMLPCT4 Anc CT 4 34 10.320 5.79 0.0 Zuo GAS AM CCS6 Anc CCS5é 48 13.044 a7 0:0 2320 GAS AM CC76 Anc CC76 109 13.044 S279 0.0 2.20 GAS AMLPCT8 Anc CT 8B 87 13.044 Srerzc, 0.0 2.20 GAS AMLPCT9 Anc CT 9 87 13.044 $379 0.0 2.20 GAS Bel CT1 BelugCTl 16 11.436 1.43 0.0 1.63 GAS Bel CT2 BelugCT2 16 11.436 1.43 0.0 1.63 GAS Bel CT3 BelugCT3 so 11.436 1.43 0.0 1.63 GAS Bel CT4 BelugCT4 10 11.436 14S 0.0 1.63 GAS Bel CTS BelugCTS 67 11.436 1.43 0.0 1.63 GAS BelCCé68 BelgCCé8 101 11.436 1.43 0.0 1.63 GAS belgC78 BelgCC78 101 11.436 1.43 0.0 1.63 GAS Int CT1 IntncT1 14 LD TTT 13.74 0.0 2.20 GAS Int CT2 IntncT2 14 LO var: 13.74 0.0 2.20) GAS Int CT3 IntncT3 20 19). 7717. 13.74 0.0 2.20) GAS NewCC76 New CC76 180 13.260 0.58 0.0 2.20 GAS New8CT3 NewBCT 3 50 8.760 0.58 0.0 1.63 GAS NewBCT4 NewB8CT 4 50 8.760 o.s8 0.0 1.63 GAS New8CTS New8CT 5S 67 8.760 0.58 0.0 1.63 GAS NewBCT6 NewBCT 6 50 8.760 0.58 0.0 1.63 GAS New8CC6 NewBCC68 101 13.260 0.66 0.0 1.63 GAS NewBCC7 New8CC78 101 13.260 0.66 0.0 1.63 GAS NewCT10 New CT10 50 8.760 0.58 0.0 2120) GAS NewCT11 New CT11 87 8.760 0.58 0.0 2.20 GAS NewCT12 New CT12 50 8.760 0.s8 0.0 2.20 GAS NewCT13 New CT13 50 8.760 0.58 0.0 2.20 GAS NwBCT14 New8CT14 sO 8.760 0.58 0.0 1.60 GAS NwBCT15 NewBCT15 50 8.760 0.S8 0.0 1.60 GAS -8.2.13- File Name: c:ANCHRSA .SPM Description :Anchorage Supply Model Unit Unit. Size Maintenance Days ID Name (MW) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Now Dec EKLU EklutnaH 30 AMLPCTL Anc CT 1 1é 10 10 2s AMLPCT2 Anc CT 2 16 é 6 24 AMLPCT3 Anc CT 3 20 Z|) 25) AMLPCT4 Anc CT 4 34 10 ZO}) 19) AM CCS56 Anc CCS6é 48 5 S 5 5 5 S 5 Ss AM CC76 Anc CC76 109 5 5 5 S 5 5 5 5 AMLPCT8 Anc CT 8 87 LOH LSS 9 AMLPCT9 Anc CT 9 87 CS 9) Bel CT1l BelugCT1 16 £4) )) 24) at Bel CT2 BelugCT2 16 16 8 8 Bel CT3 BelugCT3 so 12) || 22) |) 2 | | 20) Bel CT4 BelugCT4 10 8 8 8 8 8 Bel CTS BelugCTS 67 2 9 9) 9 Ly BelCC68 BelgCCé8 101 LS lS) si tS belgC78 BelgCC78 101 13 13 13 13 Int CT1 IntncT1l 14 14 14 Int CT2 IntncT2 14 14° 14 Int CT3 IntncCT3 20 14° 14 #14 #14 NewCC76 New CC76 180 S 5 5 5) 5 5 5 S) NewBCT3 New8CT 3 sO tS |) t5))) 1S 9 NewBCT4 NewBCT 4 so uS |) 2S |) 1S 9 NewBCTS New8CT 5S 67 9)) 1S) tS) is NewBCT6 NewBCT 6 sO SS: 1S) LS NewBCC6 New8CC68 101 US!) | LS) | 2S!) | LS NewBCC7 New8CC78 101 LS) TS) 2S) LS NewCT10 New CT10 so 15) 15) 2S: 9 NewCT11 New CT11 87 LS Sas) 9 NewCT12 New CT12 so 25) | 1:51) 15 Ss NewCT13 New CT13 so S25) 15) 2s NwBCT14 New8CT14 50 9) iS) |) 25) 2S NwBCT15 New8CT15 50 So Loe -8.2.14- Description Unit ID ChenstS Chensté Fmusicl Fmusic2 Fmusic3 HealStl HealIC2 Nopoctl Nopoct2 Zen ctl Zen ct2 DslICl dslICc2 DslICc3 Osl1Ics DslICé UAFIC7 UVAFIC8 NewHeal NewFcta NewFctB NewF ctl NewFot2 NewFot3 NewFct4 NewFctS NewFcté6 NewFct7 NewF cts Unit. Name ChenaSTS ChenaSTé Fmusic 1 Fmusic 2 Fmusic 3 HealySTl HealyIC2 NoPolCT1 NoPolCT2 Zender 1 Zender 2 DslIc DslICc Ds1Ic dsl1IC DslIc UAFIC UAFIC NewHeST NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT ODNAWUUNeE DBrIYKDOWUAWNY ODE File Name: :Fairbanks Size (MW) 20 26 c:FAIRRSA Supply Model Number of Units 1 eee eR eR Flue gas - SPM Super- Serubber Critical Installed 03-23-1987 Date (yes/no) (yes/no) no no no no no no no no no no no no no no no no no no no no no no no no no no no no no e. 1c no no no no no no no no no no no no no no no no no no no no no no no no no no no no no 1970 1976 1967 1967 1967 1967 1967 1976 LOTT Lo74 1972 1961 1961 1961 1970 1970 1970 1970 2002 1992 2002 1996 1999 2001 2008S 2006 2007 2010 2016 112502 Rook Life (Yr) 35 30 2s Zo 25 35 30 30 30 30 30 30 30 30 30 30 26 26 35 30 30 30 30 30 30 30 30 30 30 17 ACRS Type t=S iu t 1 1 i a Z Z 1 1 a 1 is 1 1 z 1 1 1 1 1 1 1 1 1 1 1 1 1 Description Unit ID ChenstS Chensté Fmusicl Fmusic2 Fmusic3 HealStl HealIC2 Nopoctl Nopoct2 Zen ctl Zen ct2 DslIC1 Ds1IC2 DslIC3 DslIcs DslICé UAFIC7 UAFIC8 NewHeal NewFcta NewF cts NewFectl NewFct2 NewFct3 NewFct4 NewFctS NewFcté NewFot7 NewFct8 Unit Name ChenaSTS ChenaSTé Fmusic 1 Fmusic 2 Fmusic 3 HealySTl HealyIC2 NoPolCTl NoPolCT2 Zender 1 Zender 2 Ds1Ic DslIc DslIc DslIC DslIc UAFIC UAFIC NewHeST NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT DNAWWNe DBNAOWNSLWNYODY File Name: c:FAIRRSA :Fairbanks Supply Model size (MW) 20 26 Unsche. Outage Rate(%) 6.0 DODDDDDDDDUNUKNUNNUNNUNUF Kr eee NNnD CO0DDDDDOOOONODOONDONONONOOOOCOOOMDO0O0OG -8.2.16- Daily Unavail. (%) °o ° eo0eoOeoOoOOOOOOOOOOOOOOOCOOOO0O0O00 eP000000O0OCOOCOOOOAOOOOOOOCOOC0O0C”0 “SPM Description Unit ID ChenstS Chenste Fmusicl Fmusic2 Fmusic3 HealStl HealIC2 Nopoctl Nopoct2 Zen ctl Zen ct2 DslIC1l DslIc2 DslIC3 Dsl1ICS Del ICé UAFIC7 UAFIC8 NewHeal NewFctaA NewFctB NewFctl NewFct2 NewFct3 NewFct4 NewFctS NewFcté NewFct7 NewFct8 Unit Name ChenaSTS ChenaSTé Fmusic 1 Fmusic 2 Fmusic 3 HealyST1l HealyIc2 NoPolCT1 NoPolCT2 Zender 1 Zender 2 Dsl1Ic Ds1Ic DslIc DslIc DslIc UAFIC UAFIC NewHeST NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT DNAWNWNe DBNYAUSLWNY DOD File Name: :Fairbanks Size (MW) 20 26 3 3 3 ec: FATRRSA Supply Model HEAT RATES 100% 14236 12733 12128 12128 12128 12750 11210 9500 9500 14869 14869 11210 11210 11210 11210 11210 11210 11210 9750 75% 14693 13574 12425 12425 12425 13012 11486 10781 10781 15218 15218 11486 11486 11486 11486 11486 11486 11486 9950 -8.2.17- SPM (BTU/KWH AT % OUTPUT) SO% 15613 16652 13283 13283 13283 13876 12285 12874 12874 16634 16634 12284 12284 12284 12284 12284 12284 12284 10611 25% AVERAGE 14693 13574 1242S 1242S 12425 12753 11486 10781 10781 15218 18218 11486 11486 11486 11486 11486 11486 11486 9950 12095 12095 12095 12095 12095 1209S 12095 12095 12095 12095 Description Unit ID ChenstS Chensté6 Fmusicl Fmusic2 Fmusic3 HealStl HealIC2 Nopoctl Nopoct2 Zen ctl Zen ct2 DslICl Ds1lIc2 Ds1IC3 Ds1ICcs Ds1lICé UAFIC7 UAFIC8 NewHeal NewFctA NewFctB NewFctl NewFot2 NewFeot3 NewFcot4 NewFctS NewFcoté NewFct7 NewF cts Unit Name ChenaSTS ChenaSTé Fmusic 1 Fmusic 2 Fmusic 3 HealySTl HealyIC2 NoPolCTl NoPolCT2 Zender 1 Zender 2 DslIc Ds1IC DslICc DslIc DslIc UAFIC UAFIC NewHeST NEWFCT NEWFCT NEWFCT NEWF CT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT DNAUWNeK DOBNAUAWNY ODY File Name: :Fairbanks Supply Model Size (MW) 20 26 3 3 Fixed O&M Cost ($/KW-YR) 75.030 8.935 0.887 0.887 0.887 71.349 0.602 7.568 7.568 8.963 8.963 0.602 0.602 0.602 0.602 0.602 0.602 0.602 61.429 8.760 8.760 8.760 8.760 8.760 8.760 8.760 8.760 8.760 8.760 c:FAIRRSA .SPM Variable Cost of O&M Cost Consumables ($/MWH ) ($/MWH ) 0.65 0.0 O89 9.0 2S eu, 0.0 2527 0.0 25.20 0.0 4.19 0.0 5.84 0.0 1.46 0.0 1.46 0.0 0.60 0.0 0.60 0.0 5.84 0.0 5.84 0.0 5.84 0.0 5.84 0.0 5.84 0.0 5.84 0.0 5.84 0.0 4.30 0.0 0.58 0.0 0.58 0.0 0.58 O70 0.58 0.0 0.58 0.0 0.58 0.0 0.58 0.0 0.58 0.0 0.58 0.0 0.58 0.0 -8.2.18- Fuel Cost ($/MBTU) 2550 3.40 5.00 5.00 5.00 1.30 5.00 3.40 3.40 3.40 3.40 S.00 5.00 5.00 5.00 5.00 $.00 5.00 1.30 3.40 3.40 3.40 3.40 3.40 3.40 3.40 3.40 3.40 3.40 Fuel Type col FOe FO? FO2 FOo2 co2 FO2 FO6 FO6 FO6é FO6 Fo2 FO2 FO2 FO2 FO2 FOo2 FO2 co2 FO6 FO6 FO6 FO6 FO6 FO6 FO6 FO6 FO6 FO6 he: Unit [Dd Chensets Chnensté Fmusicl Fmusic? Fmusic3 HealStl HealIc2 Nopoctl Nopoct2 Zen ctl Zen ct2 Osl1IC1 Ds1IC2 OslIC3 DslIcs DslICé6 UAFIC7 UAFIC8 NewHeal NewFcta NewFctB NewFctl NewFct2 NewFct3 NewFct4 NewFctS NewFcté NewFcot7 NewFct8 rieLion Unit Name GhenasTs ChenaSté F:nusic 1 Fmusic 2 Fmusic 3 HealySTl HealyIC2 NoPolCT1 NoPolCT2 Zender 1 Zender 2 DslIc DslICc DslIc Dsl1lIC DslICc UAFIC UAFIC NewHeST NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT ODNOUWNeE DNAUNSLWNY- ODD File Name: :Fairbanke Sa) eo (MW) 1) Supply Medel Jan Feb Mar 10 20 20 20 -8.2.19- Apr 16 5 10 2S 20 20 20 20 20 e:FATRRSA Sem Maintenance May Jun 3 10 10 20 20 20 15 20 iS 25) 25 25°25 2s 25 25 15 20 LS 2 15 18 20 20 LS 201s) Jul 10 LS 235 23 23 20 20 20 20 Dave Aug Sep Oct Nov 12) 20 25 a 25 1S 1S 20 20 745) 25 1S 20 1s 23 23 1S Dec 8.3. Load Data Sets TABLE §.3.1 MONTHLY DISTRIBUTION (Page 1 of 2) OF PEAK POWER DEMAND Anchorage - Cook Inlet Area Average Average 1976-19 82 1982 1983 1982-1983 (2) (2) (%) (2) January 88.5 100.0 100.0 100.0 February 87.4 92.5 88.0 90 .2 March 78.4 82.1 80.5 81.3 April , 69.4 76.5 72.8 74.6 May 60.9 63.5 65.3 64.4 June 58.5 60.5 62.5 61.5 July 58.5 61.4 62.1 61.8 August 59.2 62.9 64.4 63.6 September 66.8 72.9 72.6 72.8 October , 80.1 90.6 81.0 85.8 November 88.0 95.8 84.7 90.2 December 99.2 93.7 93.6 93.6 Fairbanks - Tanana Valley Area Average Average 1976-1982 1982 1983 1982-1983 a &) nC) alam) saunas CG) Su January 92.7 100.0 100.0 100.0 February 91.8 97.2 86 .6 91.9 March 79.1 84.5 Thy 85.6 April 68 .0 76.3 67.9 72.1 May 60.2 69.4 67.1 68.2 June 56.9 68.4 62.9 65.6 July 57.1 64.6 63.4 64.0 August 58.6 66.0 67.6 66.8 September 64.1 69.5 aes 70.4 October 75.4 84 .6 79.8 82.2 November 84.2 99.4 82.6 91.0 December 95.0 94.9 97.2 96.0 Total Railbelt Area Average Average 1976-1982 1982 1983 1982-1983 January 89.8 100.0 100.0 100.0 February 87.7 92.8 87.6 90.2 March 78.9 83.0 80.6 81.8 April 69.2 77.3 1202 74.8 May 60.9 65.1 65.1 65.1 June 58.3 61.2 62.1 61.6 July 57.9 62.4 62.1 62.2 August 59.8 63.0 64.4 63.7 September 66.4 qTaat 72.0 72.4 October 79.5 89.8 81.0 85.4 November 87.7 96.3 84.3 90.3 December 98.9 94.6 93355 94.0 TABLE £§.3.1) (Page 2 of 2) ——[—— Anchorage - Cook Inlet Area Average Average 1976-1982 1982 1983 1982-1983 January 10.0 10.7 10.4 10.6 February 8.9 9.0 8.7 8.8 March 8.9 8.9 8.9 8.9 April 7.8 7.9 7.8 7.8 May 7.2 7.1 es 7.2 June 6.6 6.5 6.7 6.6 July 6.7 6.8 6.9 6.8 August 6.9 6.9 Tiee 7.0 September 7.2 7.2 7.6 7.4 October 8.7 9.0 8.7 8.8 November 9.8 9.6 9.3 9.4 December 11.2 10.2 10.4 10.3 Fairbanks - Tanana Valley Area Average Average 1976-1982 1982 1983 1982-1983 Spenser (ges) nd (2) eee January 10.8 11.0 10.7 10.8 February 9.7 9.2 8.8 9.0 March 9.2 8.9 9.0 9.0 April 7.7 7.8 7.5 7.6 May 6.9 7.3 7.2 ee. June 6.3 6.6 6.7 6.6 July (Joe) 6.8 6.8 6.8 August 6.6 6.9 lise 7.0 September 7.1 7.2 7.7 7.4 October 8.5 8.8 8.5 8.6 November 9.4 9.4 Oat 9.2 December 11.3 10.2 10.6 10.4 Total Railbelt Area Average Average 1976-1982 1982 1983 1982-1983 January 10.2 10.7 10.5 10.6 February 9.1 9.0 8.8 8.9 March 9.0 8.9 8.9 8.9 April 7.8 7.9 7.8 7.8 May 7.1 7.2 7.2 Tice June 6.5 6.5 6.7 6.6 July 6.7 6.8 6.9 6.8 August 6.8 6.9 7.2 7.0 September 7.2 742 7.6 7.4 October 8.7 9.0 8.7 8.8 November 9.7 9.6 9.2 9.4 December 11.2 10.2 10.4 10.3 Source: Data for 1976-1982 are taken from Alaska Electric Power Statistics 1960-1983, Alaska Power Administration (1984). Data for 1982 and 1983 are based on Applicant's evaluation of hourly load data provided by the Railbelt Utilities. AOCHORAGE PUICIPAL LIGHT © POMER CHUGACH ELECTRIC AGGOCIATION (RETAIL) WOPER ELECTRIC SGBOCIATION PATOLGKA ELECTRIC ASSOCIATION CITY OF swe SYSTEN LOSSES ' TOTAL (CEA) FAIRDAOKS MUNICIPAL UTILITY SYSTEM GOLDEN VALLEY ELECTRIC AGGOCIATION WOCHONGE MUNICIPAL LIGHT WO PDE CHUBACH ELECTRIC ASSOCIATION FAIRBANKS FUNICIPAL UTILITY SYSTER GOLDEN WALLEY ELECTRIC ASSICIATIOY HOMER ELECTRIC ASSOCIATION PATARSKA ELECTRIC ASSOCIATION SSwRD TOTAL SYSTER PEAK RESERVE REQUIREMENTS WCHORAGE WEA 2 FAIKBAAKS AREA KENA! PENINSULA TOTAL RESERVE REDUIREMENT TOTAL SYSTEM CAPACITY REDUIREMENT Table 8.3.2 19% 197 we 7 69 -.7 00 OMT ™.1 473.2 ue uo, 13.7 161.8 1997.2 2000.5 16.20 172.9 301.5 = 521.0 420.0 ©= 4.0 mw? OM. 3.3 33 amt 473.2 4m. 473.2 0.0 0.0 9 ue 3,597.9 3,652.3 WA.0 166.7 191.3 198.4 2.3 3.0 © 8.8 7.3 m0 2 (1.0 9.3 “9 7.0 7.0 64.7 670.3 133.7 138.0 60.9 0.9 3.0 3.0 22.6 ya 3 = 07.2 1°91 6.3 7%.0 417.2 43.7 4.0 164.3 205.1 15.3 972.7 473.0 417.2 7.8 406.0 432.7 3.3 46.0 3,051.6 167.1 195.6 B44 112.8 5.0 6.4 12.5 712.8 197.7 0.9 31.0 249.6 TOTA. RAILBELT ENERGY REQUIREMENTS 19819891990 05.7 081.7 O82 $970.2 WS 1,000.1 M170 78. 44.0 4.5 4B 4.20 44 Sb 162.1 1463.7 163,4 2047.2 206.7 (2011.5 14.6 17631799 $1.2 42.2 577.3 4.0 © 430.0 454.3 1.7 7S B30 44.0 © 474.5 479.2 44.0 «4745 425.9 0.0 0.0 © «333 420 434 456 3,082.0 3,720.2 3,701.9 CAPACITY REQUIREMENTS 166.9 16.2 163 17.00«197.4 198.1 W600 2 BR 9.4 © 107.0 109.8 1.5 6.0 © 67.0 %5 93.6 95,5 10.0 1.0124 681.9 © 690.4 701.2 181 :137.2 138.0 0.9 = 90.9 W.0 = B80 «S.0 2.0 Bh 09.9 116.9 = 9264 951.1 Data obtained by APA, Dec 1986 Note: Load Forecast Prepared by Railbelt Utilities 62.4 1992 02.6 1,016.7 471.2 7 4.7 167.5 20.7 107.0 ab 305.0 427.2 7.8 407.0 43.7 S.3 4.7 3,913.0 168.2 198.0 ua 115.8 %.0 97.5 12.7 139.1 0.9 31.0 73.6 m4 1,046.5 “28 a7 172.0 2141.2 192.8 6u.9 310.0 432.2 7.8 %.1 “42.8 S.3 47,7 4,003.4 AS 1,046.6 412.2 42.3 “8 172.3 2190.2 1%,6 1.7 40.60 412.2 7.8 33.6 40.3 3.3 0.8 4,064.1 MS.3 70.3 1.6 1.3 49.2 5.3 2085.7 200.5 3.9 ‘74 1.6 7.8 3.6 411.3 3.3 49.2 4,021.5 4.8 1,009.9 412.2 21 “5 167.3 2110.9 204.5 676.5 0.0 412.2 7.8 3.4 472.1 3.3 4.5 4,077.9 68.0 1,020.4 417.2 47.5 ne At 1%. 208.6 6.6 45.0 417.2 71.8 32.8 47.5 3.3 “9 4,138.5 7.0 1,033.3 417.2 wo. 3.3 171.0 25.9 212.8 113.2 5.0 417.2 7.8 34.4 1 D3 0.3 1,011.6 1,000.7 2.2 4%.2 0.9 173.9 2192.8 217.0 72.3 5300.6 422.2 7.8 WS 4%.2 3.3 0.9 1,037.6 1,068.8 42.2 310, 3.5 17,1 Ad 21.4 732.0 305.0 427.2 7.8 343.7 310.4 3.3 3.5 4,377.0 1,064.1 1,091.2 432.2 327.6 32.2 190.9 720.0 8 ™.1 310.0 432.2 7.8 390.9 32.6 3.3 32.2 4,477.2 142.4 31.0 BAS 1,008.7 14.8 31.0 w.7 1,064.6 Table ¢.3.3 Peak Demand, Energy and Load Factor Forecast | 1986-2020 KONG ee nolo LH laicrereietate Anchorage - - - ---- Wl sieiccaencie Fairbanks Peak Energy Load Peak = Energy Load Peak Energy (mWh) Factor (mW) (mWh) Factor (mW) (mWh) 484.8 58.9% 445.6 2443.6 62.6% 145.1 T7122 495.2 58.9% 460.0 2522.5 62.6% 152.3 810.5 513.2 58.9% 460.4 2524.7 62.6% 160.0 851.4 531.3 58.9% 457.2 2507.2 62.6% 168.2 895.1 554.5 58.9% 459.9 2521.9 626% 171.9 914.8 596.3 58.9% 459.0 2517.0 62.6% 176.2 937.7 603.0 58.9% 463.6 2542.2 62.6% 180.2 958.9 612.2 58.9% 473.5 2596.5 62.6% 184.3 980.8 614.3 58.9% 484.4 2654.0 62.6% 188.6 1003.6 614.8 58.9% 486.1 2665.7 626% 193.0 1027.1 617.4 59.1% 487.9 2684.1 628% 197.4 1039.3 618.2 59.1% 490.4 2697.8 62.8% 202.1 1064.0 619.0 59.1% 493.9 2717.1 62.8% 2068 1088.8 620.0 59.1% 498.5 2742.4 62.8% 211.6 1114.0 621.0 59.1% 506.0 2783.6 62.8% 216.7 1140.9 622.6 58.8% 515.1 2899.9 64.3% 221.8 1153.9 631.9 58.8% 522.8 2943.3 64.3% 224.7 1169.0 641.7 58.8% 530.7 2987.8 64.3% 227.6 1184.1 651.0 58.8% 538.6 3032.2 64.3% 230.6 1199.7 660.8 58.8% 546.7 3077.8 643% 233.6 1215.3 670.6 58.8% 554.9 3124.0 64.3% 236.6 1230.9 680.9 58.8% 563.2 3170.7 643% 239.7 1247.1 693.8 58.8% 571.7 3218.6 64.3% 242.9 1263.7 701.5 58.8% 580.3 3267.0 64.3% 246.1 1280.4 711.8 58.8% 589.0 3316.0 64.3% 249.3 1297.0 722.6 58.8% 597.8 3365.5 643% 252.6 1314.2 733.5 58.8% 606.8 3416.2 643% 255.9 1331.3 744.3 58.8% 615.9 3467.4 64.3% 259.3 1349.0 755.6 58.8% 625.1 3519.2 64.3% 262.8 1367.2 767.0 58.8% 634.5 3572.1 64.3% 266.3 1385.4 778.3 58.8% 644.0 3625.6 64.3% 269.8 1403.7 790.2 58.8% 653.7 3680.2 64.3% 273.4 1422.4 802.0 58.8% 663.5 3735.5 64.3% 277.0 1441.1 813.9 58.8% 673.4 3791.3 64.3% 280.7 1460.4 826.2 58.8% 683.5 3848.1 64.3% 284.5 1480.1 Tables 8.4.1 through 8.4.8 present the detail results for four year as were previously shown for the base case and the alternate case, namely, 1991, 1996, 2006, and 2015. Tables 8.4.1 to 8.4.4 show the annual production operation in the Fairbanks area with only the Anchorage to Kenai Peninsula intertie upgraded. The availability of energy to Fairbanks was determined from the alternate case but constrained by the 70 MW existing tie to Fairbanks. This case is summarized in Table 37 where the Anchorage/Kenai results are the same as the alternate case, but the Fairbanks results are revised to reflect the existing tie. Tables 8.4.5 to 8.4.8 show the annual results for the same four years for Fairbanks with only the Anchorage to Fairbanks line upgraded. In this Case, the availability of energy to Fairbanks was determined from the base case but the intertie is upgraded to 350 MW. This case is summarized in Table 38 where the Anchorage and Kenai Peninsula results are the same as the base case, but the Fairbanks results are revised to reflect the new tie. Vetal tof Sport RNM file:c:FATRALL Table 8.4.1 - 1991 Production Operation in Fairbanks Anchorage/Kenai Peninsula Upgraded Line only PPM ES bt peer Haas } .RNM-fairbanks native demand 1991-2020: +30 MW Supply file:c:FBASE4OL .SPM-fairbankse base case with anchor/kena) SYSTEM REPORT FOR YEAR 1991 ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name HealyST1l ChenaSTS TIEPURS1 NoPolCT1 NoPolCT2 ChenaSTé Zender 1 Zender 2 HealyIC2 UAFIC 7 DslIc § DslIC 6 UAFIC 8 Fmusic 1 Fmusic 2 Fmusic 3 (GWH ) 937.66 Ost 937215 0.00 937.15 Capacity Factor St lt 56.88 90.10 US. 74) 525) =O2 -00 -00 -00 -00 -00 -00 -00 -00 0.00 0.00 oo9g00000000 RELIABILTI PK Load (MW) LOLP (Dys/Yr) Energy (GWH) T9952 99.66 552.49 84.11 1.35 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Variable 6S5;.99 65.08 15082.37 2295 T97 0.01 0.00 0.00 0.00 0.00 0.00 0.00 ar Md 20 o.000 Cost in $1,000 Fuel Cost S332. S745 ° 3681 S23 = oooo0 90 O00 0 0 Bé 24 -00 356 O7 see. E20) -OoS -00 -00 -00 -00 -00 -00 -00 -00 cOSsT Fix O&M Variable Unserved Fuel Total Total 4168.86 3810.32 15082 .37 3804.11 61.04 1.28 0.21 O05 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 upyrad s( M$) Total $/( 20 38. ata 45 45: Sis Cy Sis 67. 67 67 67 6zs 89. 89. 89. e only Wee Nepetet O305 LOnB? Sie 76 Cost MWH ) .89 23 30 -23 23 21 1é 16 26 -26 726. -26 26 69 69 69 Table 8.4.2 - 1996 Production Operation in Fairbanks Anchorage/Kenai Peninsula Upgraded Line only ' aa PShee Ob cel eh OOO. Ore ‘ . . 1 ~ RNM file:c:FAIRALL .RNM-fairbanks native demand 1991-2020: +30 MW Supply file:c:FRASE4OL .SPM-fairbanks base case with anchor/kenai upgrade only SYSTEM REPORT FOR YEAR 1996 ENERGY (GWH) RELIABILITY COSTS(M$ ) Demand 1038.89 PK Load (MW) 197.40 Fix O&M S21 Unserve 0.21 Variable RE Sir Net Gen. 1038.68 Unserved O02 Storage 0.00 Fuel 14.84 Total Gen 1038.68 LOLP (Dys/Yr) 0.000 Total 36.58 Unit Capacity Energy Cost in $) ,000 Total Cost Name Factor ( GWH ) Variable Fuel Cost Total $/(MWH) HealySTl 9310 199) 152. 835.98 4102.71 4938.70 24.575 ChenaSTS 67.79 118.76 77-255 4428.39 4505.94 37.94 TIEPURSE 93.45 573.06 15382.74 0.00 15382.74 26.84 NoPolCTl 26.48 1:40) -5L. 206.18 6052.49 6258.68 44.23 NoPolCT2 1.08 Sa AS) 8.38 281.62 259.99 48.23 NEWFCT A 0.02 0.08 0.03 Zeee a2 41.70 NEWFCT 1 0.01 0.02 0.01 0.97 0.98 41.70 ChenaST6é 0.00 0.00 0.00 0.14 0.14 Siew Zender 1 0.00 0.00 0.00 0.02 0.02 S7 <6 Zender 2 0.00 0.00 0.00 0.00 0.00 57.16 HealyIC2 0.00 0.00 0.00 0.00 o.00 67.26 OslIc 5 0.00 0.00 0.00 0.00 0.00 67.26 DslIC 6 0.00 0.00 0.00 0.00 0.00 67.26 Table 8.4.3 - 2006 Production Operation in Fairbanks Anchorage/Kenai Peninsula Upgraded Line only Cette CROP RCO ARUN tet ae le? Pane 2 RNM file:c:FATRALL .RNM~fairbanks native demand 1991-2020: +30 MW Supply file:c:FRASE4OL .SPM-fairbanks base case with anchor/kenal upgrade only SYSTEM REPORT FOR YEAR 2006 ENERGY (GWH) REL TABILITY COSTS(M$) Demand 1230 .8é PK Load (MW) 236.60 Fix O&M 4.14 Unserve 3.84 Variable l4e75 Net Gen i227), 02 Unserved 0.38 Storage 0.00 Fuel BOG 25) Total Gen 1227.02 LOLP (Dys/Yr) 0.010 Total 39252 Unit Capacity Fnergy Cost in $1,000 Total Cost Name Factor (GWH ) Variable Fuel Cost. Total $/ (MWH ) NewHeST } 87.48 19.t-.S8) 823.80 3024.61 3848.41 20.09 TIEPUROG 9793 600.49 13402.27 0.00 13402.27 22.32 NoPolCT2 57.84 309.07 450.31 12044 .04 12494.35 40.43 NEWFCT A 15.94 34.90 20.24 1435.12 1455.36 415709 NEWFCT 8 9.35 20.44 11.85 840.49 eS2. 35) 41,70 NEWFCT 1 6.20 135° SS 7caw SS8.29 566.17 41.70 NEWFCT 2 4.99 10.92 6.33 449.14 455.48 41.70 NEWFCT 3 4.34 9.51 S51 390299 396.50 41.70 NEWFCT 4 3.81 16.70 9.69 686.94 696.63 41.70 NEWFCT 5 S223 19.84 11.52 815.75: 827.26 41.70 Table 8.4.4 - 2015 Production Opera tion in Fairbanks Anchorage/Kenai Peninsula Upgraded Line only oe . eee Hoey wee aee ste Pee ‘bye RNM file:c:FAIRALL .RNM-fairbanks native demand 1991-2020 3 +30 MW Supply file:c:FBASE40L.SPM-fairbanks base case with anchor/kenai SYSTEM REPORT FOR YEAR 2015 RELIABILITY ENERGY Demand Unserve Net Gen. Storage Tota] Gen Unit Name NewHeST1 TIEPURIS NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NQAWSWUNY OD (GWH ) (385. QO. L384. QO. 1384 S? 76 el 900 iil Capacity Factor 87 99) S4 18 9 -48 -04 Sue 46. 32. 26. Ol 87 Liz a4 12. 10. 2135 8. so 10 74 PK load LOLP (Dys/Yr) Energy (GWH TOY 607 £19) 100 Za Sy 40. S4. 61 S55 22 ) 22 -32 =F" -76 298 21 32 76 ats 25 98 Variable 823. 13466. 69. s8. - 75 33. 235i. 276 2 Ie SZ. 13. 41 31 3s 83 69 49 44 18 39 45 33 (MW) 266. Q Cost in $1,000 Fuel C 3024. O. 4927. 4143. 2960. 2352. 1658. 225i. 2546. 2301 944. 30 022 ost 68 00 25 44 o7 SB 1S: 73 80 05 99 upgrade only COSTS(M¢) Fix O&M 4-56 Variable 14.63 Unserved 0.08 Fuel 27 Ah Total 46.37 Total 3848. 13466. 4996. -88 -82 2385. -54 2283. 2582). 2333. 958. 4201 3001 1681 sO 69 74 76 54 UTS 48 32 Total Cost $,’ (MWH ) 20.09 2o.L7 41.70 41.70 41.70 41.70 41.70 41.70 41.70 41.70 41.70 OS trait 1 Rca te RNM file:c:FATRALL .RNM-fairbanks Table 8.4.5 - 1991 Production Anchorage/Fairbanks Upgraded Line only eset RNRSr\ Supply file:c:FBASEAOL ENERGY Demand Unserve Net Gen. Storage Total Gen Unave Name HealySTl ChenasTsS TIEPURS1 TibPURS1 NoPolCTl NoPolCT2 ChenaSTé Zender 1 Zender 2 HealyIC2 UAFIC 7 DslIC S OslIC 6 UAFIC 8 Fmusic 1 Fmusic 2 Fmusic 3 (GWH ) 937 0 937 0 937 Capacity Factor Si10 22.06 89.74 6.08 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -66 .00 -66 -00 -66 OTe OSes TY native demand 1991-2020: anks base case with fairbanks 176520 9.9000 Cost in $1,000 Fuel Cost SSS2. 1508. -00 -00 00 .00 .00 .00 -00 -0O0 -00 .00 -00 -00 00 -00 SPM-fairo SYSTEM REPORT FOR YEAR 1991 RELTABILT PK Load (MW) LOLP (Dys/Yr) Energy (GWH) Variable v992S1 835.96 38.65 25.24 SSOE 27 1S697-S5 149.23 4347.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 9.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 9e00000000O0COO0O0C00 74 74 ° o Operation in Fairbanks Page QOSTSiMS$ ) Fix O&M 4.78 Variable 20.91 Unserved 9.00 Fuel 4.84 Total SOS) Total Cost Total $/ (MWH ) 4168.69 20.89 1533.98 39.69 1S697 455 28.53 4347.00 29.13 0.00 0.00 0.00 0.00 9.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 L +30 MW wuparade only betari report. RNM file:c:FA Table 8.4.6 - 1996 Production Anchorage/Fairbanks Upgraded Line only :¢ PF OINRSA IRALL .RNM-fairbanks native demand 1991-2020: sts Operation in Fairbanks Us— 23-0987 Page +30 MW Supply f1le:c:FBASE4OL .SPM-fairbanks base case with fairbanks upgrade only SYSTEM REPORT FOR YEAR 1996 ENERGY Demand Unserve Net Gen. Storage Total Gen Unit Name HealySTl ChenasTs TIEPURS6 TibPUR96 NoPolCT1l NoPolCT2 NEWFCT A NEWFCT 1 ChenaSTé Zender 1 Zender 2 HealyIC2 DslIc § DslIC 6 (GWH) 1038. A 103 womo 10 “A Capacity Factor Siratd 22.06 93.46 9.28 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 89 -00 89 -00 .389 RELIABILI PK Load (MW) LOL P Energy (GWH) 199252 38.66 573.08 227.63 -00 -00 -00 -00 -00 -00 -00 0.00 0.00 0.00 oo0o00000 (Dys/Yr) Variable 836.01 25\.24 LSO2Z21..55 6309.34 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 LY: 197.40 9.000 Cost 1n $1,000 Fuel Cost 4102.82 1508.82 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 COSTS(M$) Fix O&M Se2t Variable B2wl SD Unzerved 0.00 Fuel Seo! Tota) Sa.01 Total Cost Total ¢/(MWH) 4938.82 2475 1534.07 S59 7609 LSO21 S55 26.21 6309.34 2 aee 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Cetsii report RNM file:c:FATRALL Table 8.4.7 - 2006 Production Anchorage/Fairbanks Upgraded Line only Jes FrUNRSA -RNM-fairbanks native demand 1991-2020: = hot OS=25=1987 Operation in Fairbanks Page SI +30 MW Supply file:c:FBASE4OL.SPM-fairbanks base case with fairbanks upgrade only SYSTEM REPORT FOR YEAR 2006 ENERGY (GWH) 1230 Demand Unserve Net Gen. Storage Total Gen Unit Name NewHeST1 TIEPUROS6 TibPUROS6 NoPolCT2 NEWFCT NEWF CT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT UAhWNY OD F230. 0. 1230. oO Factor 87. = 7) LZ -00 -00 -00 -00 -00 -00 -00 -00 oT, oo0o000000 49 90 . Bé 00 846 -00 Bée - Capacity PK LL LOLP Energy ( GWH ) NGL 6O) 600.29 438.97 -00 -00 -00 -00 -00 -00 0.00 0.00 oo0o0o0°0 RELTIABILTI oad (MW) (Dys/Yr) Variable 823.88 14232.98 10627.41 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 TY 236. 60 0.000 Cost in $1,000 Fuel Co 3024. oO. Oo. (oe oO Oo o Oo 0 ° ° st 87 oo oo oo -00 -00 -00 -00 -00 00 -00 COSTS( M$) Fix O&M Variable Unserved Fuel Total Total 3846. 14232. 10627. -00 -00 -00 -00 -00 -00 -00 -00 oo oOo 30 5 us 98 41 4.14 25,68) 0.00 Si. 02 iz 2.385 Total Cost $/ (MWH ) 20.09 23.71 24.21 45.23 0.00 0.00 41.790 0.90 0.00 0.00 0.00 Detain’ report: RNM file:c:FATRALL Supply file:c:FBASEAO ENERGY Demand Unserve Net Gen Storaqe Total Gen Unit Name NewHeST1 TIEPURIS TibPURI1S NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NEWFCT NQOWSBAWNY DD Table 8.4.8 - 2015 Production Anchorage/Fairbanks Upgraded Line only .RNM-fairbanks native demand 1 - SPM-fairbankse ( GWH ) 1385 1385. 0 0 1385 Pe IMRSE ~O3L Soe £95 SYSTEM REPORT FOR YEAR 2015S RELIABILITY oad (MW) ud? O00 av 00 sia?) Capacity Factor 87. a) -98 -00 -00 -00 -00 -00 -00 -00 -00 -00 98 23 o900000000 49 PK I. LOL P Energy ( GWH) 191.60 605.58 588.19 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (Pbye/Yr) Varvable 823. 14348. 14114. -00 -00 -00 -00 -00 -00 -00 -00 -00 oo00000000 89 02 17 266. 991-202 base case with fairbanks 30 0.000 Cost in $1,000 Fuel Cost 3024 oo0o000000000 =S) .00 -00 -00 -00 -00 -00 -00 .00 .00 -00 -00 Operation in Fairbanks Page a O: +30 MW uparade only COSTS(ME) Fix O&M 4.56 Variable Sew Unserved 0.00 Fuel 5.02 Total 26.87 Total Cost Total $/( MWH ) 3848.73 20 109 14348.02 23 69 14114.17 24.00 0.00 41.70 0.00 41.70 0.00 41.70 0.00 41.70 0.00 41.70 0.00 41.70 0.00 41.70 0.00 41.70 ‘0.00 41.70