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HomeMy WebLinkAboutAPA2346I J ~i l) '""'"' ""' ,,. __.., -.---_,_ . fXJ&fm~&c§®&@©@ SusJtna Joint Venture Document Number Please Return To - DOCUMENT CONTROL I I ooi· ~- SUSITNA HYDROELECTRIC PROJECT ECONOMIC ANALYSIS PACKAGE MEETING JANUARY 14 AND 15~ 1982 BELLEVUE4 WASHINGTON Acres American Incorporated Suite 329 The C.larl< Building Columbia, Maryland 21044 Teiephone (301) 992-5300 ~j ---· _,..~ .. "'. : .., . "'~ I I; . ~ ',j ' , ' • I ,. ~ • ~ ' ;.. ... ~ \ • 'i / f "" I • \I . I ' 0 .. • • , VIe / · t ' .. '. ~;,·I . ' -I I •• ~ 4 • • • r 1 , ' I . . . I I I I I I I I I -1 I I Mr. Dennis Rohan SRI International 333 Ravenwood Avenue Merlo Park, CA 94205 Dear Mr. Rohan: December 29, 1981 P5700.00 Susitna Hydroelectric Project T~= purpose of this letter is to transmit information in preparation for your briefing on the subject, January 14 and January 15 in Bellevue, Washington. Mro Robert Mohn of APA has previously outlined the meeting topics in his letter of December 7, to you. These materials are related to the Susitna study, Economic Analysis Methodology and Preliminary Results and the Risk A-n-a~1y-s~i~s-.--s~·a-c~k_g_r_ound material for Acres' third area of briefing responsibility, Financial Analysis, are being sent under separate cover. Enclosed are separate briefing packages for the economics and risk analysis topics. As you will note, at this time, we are getting into the middle of each task's scope of work. As a result, the information presented here is oriented towards methodology rather than results. We hope to have more on the results side to present at the meetings. The Economic Analysis package includes six sections: 1 -A Scope of Work for the generation planning update work. This work builds on the work done about one year ago for the Development Selection Report. 2 - A draft memorandum of a coordination meeting held between Acres and Battelle to review the respective studies and identify and resolve conflicts where possible. 3 -An explanation of the economic analysis methodology which uses the generation model production costs as a basis. The end product of the economic analysis is a benefit-to-cost ratio. 4 -Preliminary results of tne 11 With" and nwithout" Susitna, Railbelt p 1 ans. 5 -Load Projections as supplied by Battelle, December 21, 1981. ACRES AMERICAN INCORPORATED C-:.l··~ .... ! r-; Et-<l ~ ... ,.,, ~-• ••· ;:~ lt•.} C ~r,: & ... ~ 1 r 7 .... t.!~' f• r :: •.•d,t, .. ~" ~ :: .... .!4. ~c.e- I fl I I I I I I I I I ' . l (l ri ' Mr. Dennis Rohan -2-December 29, 1981 6 - A summary of the Generation Planning Model, OGP, written and published by General Electric, Schenectady, New York. The Risk Analysis package contains the following: 1 -The scope of work for the Risk Analysis 2 - A list of risk and construction activities 3 -Risk analysis 4 -Progress status of work scope We hope that these packages provide you with sufficient background for our briefings. If you have any questions on this material, please contact me or Phil Hoover in Columbia (301-992-5300). JL/pb Enclosures ACRES AMERICAN INCORPORATED Very truly yours, ,......-: ... . /~-.· / .. '1 ·~~~"' <. ~,_ ........ ~ v·vv: ~-... C..· John Lawrence Project Manager . I I . I ~ I I I I I I I I I I . ~ ·~ ' ! ' ' ( ITEM 1 -SCOPE OF WORK (j I I I I I ·.~ r ' ,. l . Item 1 DETAILED WORK PLAN -SUBTASK 6.37/6.38 -UPDATE GENERATION PLAN 11/10/81 Objective: Update results of the generation planning studies based on detailed information available to the study from the Battelle Power Alternatives Study and the latest information on the Susitna Hydroelectric Project. The primary tool to be used in this analysis is the General Electric Optimized Generation Planning model. Methodology: The generation planning portion of the study Subtasks 04, 05, 06 and 07 will follow this general methodology: 1. Pre-Susitna base system under economic parameters (low, medium and high load forecasts). 2. Study period (1993-2010) without Susitna case with economic parameters, medium load forecast. 3. Study period with Susitna case with economic parameters, medium load forecast. 4. Repeat for high and low load forecasts. 5. Test medium load forecast case using financial parameters. 6. Conduct sensitivity analysis on medium load case with the Susitna project. See Figure 1 for diagram of analysis. Schedule: This outline assumes an initial target start date of November 9 and a completion date of January 22 based on the availability of information for each of the Subtasks listed below. See Table 1 for a summary and schedule. Subtask.01: Update Load Models Based on information provided by Battelle/ISER and WCC derived load shapes (Task 2) regarding load forecasts; medium, high and low forecasts for energy (GWh) and peak (MW) for net generation demand (not just utility sales) will be revised in the OGP-5 Load Mode1 program routine. ISER has, in the past, presented projections for load in terms of utility sales. Generation plans are developed based on sales plus transmission and distribution losses or net generation. Also, since Battelle is using an probabilistic ~odel without a high, medium or low forecast per se, it may be necessary to revise information from Battelle/ISER to conform with our high, medium and low load forecast format, concentrating on the medium case. This subtask is completed. -1- . 'J~~-,~~-~-~~---~--~----~---r·-·~=e·-·e--· I I I I I Subtask.02: Update Generation Model According to March 1981 (Task 4) Report by Battelle, check existing generation system planned additions and retirements for consistency, revise if necessary. Subtask.03: Update Alternatives Data Review results of alternatives• cost and availabilities, as well as other parameters, outages (forced and planned) and O&M costs. Data on fuel costs and escalation patterns is also necessary from Battelle Task 1 fuel reports. Update OGP-5 model and check initial data preparation output. At this point a second coordination meeting with Battelle will be necessary. Some additional points discussed: -escalation from 1980 -Jan. 1982 price level -utility sales conversion to generation demand assumptions (note; Battelle+ 8 percent) -intertie cost assumptions with respect to thermal and Susitna development plans -consistency of capital cost assumptions -preliminary reserve margin figures from Battelle -clarification of other points which may arise during the review of alternatives data -planning parameters. The alternatives selected by Battelle for use in the Susitna study generation planning update are: -coal-fired steam electric at Nenana and Beluga -gas-fired combined cycle .Plants at Anchorage or Fairbanks -gas-fired combustion turbines at Anchorage or Fairbanks -Chackachamna Hydro project Subtask.04: Generation Plan Without Susitna (Econornic Parameters) Based on system reliability criteria or reserve margins (if available) from Battelle, a "without 11 case, medium load forecast will be run, allowing the program to optimize new generation production costs using economic parameters. The followin3 assumptions will be made provided they are consistent with Battelle and Acres transmission team assumptions. -No limit in natural gas use. -Economic parameters as specified by APA (0% escalation; 3% interest) 2 I I I jl, '~:\\ I ' l ' I ' I I ~~ [. ' ' [ ' -Costs of transmission for initial Beluga and Nenena plants will be added in. -Alternatives available under Battelle's Plans I & II will be available to the system and staged as necessary~ -Fuel escalation as specified by Battelle will be used. Simi 1 ar OGP-5 runs wi 11 be made for the high and 1 ow forecasts., These runs will be comparable with Battelle Plans I and potentially IV and V. Subtask.05: Generation Plan With Susitna (Economic) Parameters A number of OGP-5 runs wi 11 be made under this task to confi r·m a 11 with 11 Susitna plan under the medium, high and luw load forecasts for comparison with Battelle Plan II results. Three key points are: -Economic parameters will be used as specified by APA (10/29/81) -The only Susitna plan is Watana/Devil Canyon (in that order) -Susitna data (energy and cost) used in this task identical to that provided to Battelle For the medium load forecast, staging will be optimized using economic parameters. Definition of a plan under the high load forecast similar to the medium case including later unit additions of Susitna. The low forecast plan will also resemble the base case, utilizing cheaper alternatives for peak during intermediate years. The first coal units will be assessed for transmission cost to the existing Willow to Healy 345 kV line provided this is consistent with assumptions in Subtask 04. Subtask 06: Financial Analysis Based on the plans for the middle load forecast defined in the Subtask 04 and 05 work; the systems for the with and without cases will be run under the financial parameters. Subtask.07: Sensitivity Analysis The methdology for sensitivity analysis is as follows: -Identify areas of uncertainty -For each topic identify the range of variability -Test sensitivity -Discuss the variability. Several topics have already been identified and tested in the 6.36 work: 3 I I I I ;I• 1 ·.,~ I I 1 l [ [ ' . r Lt Loads -As part of both Tasks 04 05 and 05, high, medium and low loads will be addressed. Intrinsic to these loads are assumptions of economic activity, state spending, per capita use in each consumptive sector. The variability of the with and without plan within the range of load forecasts has been treated before and will be updated. Economic/Financial Inflation/Discount Rates -Under this revised scope of work economic (0% inflation, 3% cost of money) and financial (to be identified by APA) parameters are to be tested in Subtasks 04, 05 and 06. Similarly, the conclusions .. drawn in the Task 6.36 (DSR) work would be extended in this phase. At this time, we propose to wait until the results of the previous tasks are completed to define a range of variability of discount rate. However, assuming that Susitna is still economics the approach would be to seek the case where Susitna becomes unacceptable in economic terms, rather than review the entire range of greater economic feasibility; i.e., higher rather than lower real interest rates will be used. Period of Analysis -The planning period for modeling purposes extends to 2010. This is considered to be the outer limit for load forecasting and economic cost projections. However, the Susitna project is entered into the system in the 1993-2005 timeframe (Watana/Devil Canyon separate stages). Thus, the production cost model will assess the value of the Susitna stages from a maximum of 17 years, to as little as 5 years. Given that the life of the Susitna project is approximated as 50 years, several assumptions must be made to extend the period of analysis. In order to assess the economics of the project, the last year of pro- duction cost modeling will be assumed to re-occur annually for a period of time equal to 50 years after the last Susitna installation. This assumes no load growth and no actual escalation of any costs. It is believed that this approach provides a slightly conservative edge to the non-Susitna plan. This approach is discussed in more detail in the B/C methodology section. Sensitivity of this approach could be performed only if the economics of Susitna are not within the acceptable range. The sensitivity would be to find the period of analysis where Susitna is feasibile/unfeasibile. Project life for the generation alternatives have been mutually agreed upon by Acres and Battelle and are within accepted ranges for the industry. Results of the study are not highly sensitive to a + change of 5 years or 1 ess to these va 1 ues. - Capital Costs - A considerable amount of analysis and reiteration of capital costs of thermal alternatives has been already completed in th~ 1981 sensitivity analysis. Additionally, Battelle/Ebasco has devoted a significant level of effort into estimating capital costs of alternatives. Nonetheless, there is concern that the estimates produced (particularly for the coal-fired steam alternative) and a level of confidence lower than the Susitna project. The sensitivity of the capital costs will be approached in t\'IO ways • -4- - I I I I I I ~' I i [ ! l I i [ ~. ' l t ...... L I ~ . f First, the alternative capital costs will be checked against the Susitna base plan using 90 percent and 120 percent of the Ebasco estimate. The selected alternative plan (units and staging) will remain constant. These percentages will be varied somewhat in an effort to determine the 11 breakeven point 11 for· the Susitna project. Second, using the medium forecast plans, rea1 escalation of construction and operation costs will be entered. These escalation values will be adopted from those included by Ebasco in their Railbelt capital cost studies. These values are not being used in the base plans at this time. Construction Period -An upward variance (longer) in the construction period will be considered. It is expected that this possibility will not have a major impact on results since 3 percent, interest during construction is minimal. Fuel Cost and Escalation -As defined in the DSR senstivity analysis, fuel cost and fuel cost escalation plays an extremely important role in the planning procedure. Sensitivity should be geared towards defining the fuel/cost escalation rate combination for alternatives at which Susitna b€comes unattractive. In the financ1al analysis of the Susitna study, exception has been taken to the coal escalation rates. One case will be analyzed using the base plans and the Acres' escalation estimates. Construction Period and Online Dates -This sensitivity is essentially accomplished under the definition of the plans under financial parameters. Constraints on construction period are factored into the earliest possiole online date and the high contingency values. 0 & M Costs -Although a factor in the production cost model it would appear that due to the lack of historic data and the consistency of application, it is doubtful that the sensitivity of this parameter would result in different recommendations and will not be further addressed. System Reliability -A system loss of load probability of one day in ten years has been used in system modeling. Variance of this factor would cause the system to add more or less capacity, thus potentially changing the staging of alternatives. Additionally, the Battelle study in using a probabilistic approach to the load forecast may result in a reserve margin higher than that planned with a single forecast input. For sensitivity we would propose to conduct our study planning Subtasks 04, 05, and 06 using Battelles' reserve margins (if available) and then checking sensitivity with LOLP. Thus further model runs should not be needed. These represent a most of the potential sensitivity runs that can be accomplished. Given the results of the sensitivity checks, combinations of parameter variance will be checked, if they appear critical. Figure 2 outlines assumptions and potential sensitivity tests. -5- - 11 I I I I I I I r: ~~ [ ' ' . ~ . . L [ Subtask.08: Document Results Document results of the above tasks in a format consistent with the proposed outline of the Feasibility Report {dated October 12, 1981) It is our understanding at this time that Section 8.8 wil.l document the DSR Task 6.36 studies and remain intact. The 6.37/6.38 Tasks will provide a portion of the financial and economic evaluation of new Section 16. OGP-5 data will be summaraized in Appendix (Al). -6- - ,c I •" " ~ ; ' ; -~ -~ ~ ~---" .-~ ~ --.-~ w~·~ · · _., ;c.~~~--::A~ W!.-~--~-·--"''1 1.?:~:. k1 Low Load Model (Update) 1981-1993 1993--2010 Without l Economic** ~S~sitnaJ Plan r-~ ----~ _l ~-~ __ ,..,-1 ~-;..§ L __ § ~ a;' With Susitna EXISTING GENERATION SYSTEM 1981 (Update) Medium Load Mode 1 (Update) 1981-1993 199l-2010 I Without J Economic** I With' Susitna Plan Susitna W/0 I Financial* I W Plan Sensitiv·ity ~------~ SYSTEM PLANNING METHODOLOGY * Using parameters defined by APA ( 10/2 9/81) . ** Using 0%, 3% parameters. l-"1 ~ Without Susitna ', ~ ~ ~ ~ lf!il I High Load Mode 1 (Update) I 1983-1990 1993"-2010 Economic Plan With Susitna FIGURE 1 ;§Jil ri:iiit iiiil I I .·, ~,·,- '' J ~ a ~ ' ~ ~ - 0 . ~ ~ .... ~ ~ :f~.· .:.~:· f.! . -1 ASSUMPTIONS Appliance Saturation Turnover of Housing I -, r.-~·-~--J ~ ~ k~::l L~ Residential Commercial lndustri al 1982 Cost Fuel Char. Esc. Rate Alaskan Factor !WIIIIIJ ......... _. ___ _ l!;_§§ ~ Economic Activity State Spending Per Capita Use Analysis Period D'i scount Rate Inflation Rate Construction Cost Escalation Kate us I Fue 1 Cost/Esc a 1 at ion ] Construction Period O&M Costs Env. Protection I Capital Costs I Base Costs Contingencies Risk Cost O&M Costs Construction Period I Capital Costs I Potential Sensitivity Tests. ~ [11M ~ nr11.·· -~--MIJ SENSITIVITY LOAD FORECASTS ECONOMIC ANALYSIS PARAMETERS COST OF THEKMAL GENERATION COST OF SUSITNA GENERATION &EJ . FIGURE 2 . f2i!iit &Ji I ,,p il I I I ' .l I ·' ;,j I I I ~ ITEM 2 -MEMORANDUM OF BATTELLE/ACRES MEETING I _.,~ I I ' ' -l I 1: ll ~~ I' l l ~toj L l - I (I ~·~ I ' j ! ; \ ' { L .. ,-t Memo of Meeting December 14 and 15, 1981 Battelle PNL Richland, Washington Item 2 December 17, 1981 Subject: Susitna Generation Planning and Railbelt Alternatives Studies Jm Purpose: 1M The purpose of the meeting was to review the study progress to date and identify •1 and reconcile, if possible, differences. ~ Attendance: 11. l J.l r·.: J; r ' ' l l _.,; L ' ' . Jay Jacobson, Battelle; Mary Ann Hosko and Phil Hoover, Acres Agenda 1. Discuss status of progress of the individual studies, including work remaining. 2. Review and compare preliminary input/output of the Rail belt Gener·ation Planning models, OGP (Acres) and EPRI Over/Under-AREEP Version {Battelle). 3. Discuss and resolve specific issues and differences between studies identified. 4. Unresolved issues Meeting Notes 1~ Phil Hoover reviewed the Acres' scope of work for the 6a37/.38 efforts and provided a copy of the work scope. This scope provides for a breakout of the effort into eight subtasks: -Update Load Models (input) -Generation Plan with Susitna -Update Generation Model (input) -Alternatives Data -Financial Analysis -Sensitivity Analysis -Generation Plan without Susitna -Documentation Jay Jacobson reviewed Battelle's effort which consists of essentially five tasks: (a) Fuel cost estimating: (Lead-Tom Sechrest) This task is essentially complete. One area which is being reviewed is the availability of North Slope Gas in Fairbanks given recent developments in the gas pipeline. {b) Demand Forecasting: (Lead -Mike Scott) The forecast provided 12/9 has been invalidated due to an internal error in program data. New forecasts were being developed during the meeting. Anchorage and Fairbanks are assuned to have a 97 percent coincident peak. - I I ' I I 'I' I , I,_ r; I f ' I I . " I ,. ,-: .' ... fr : 1.,. \' ..........,_, ..... , Memo of Meetings -2-December 17, 1981 It appears that the medium load forecast, when completed, will be fail.,ly close to the forecast used in previous DSR Acres• studies. All three forecast~ will probably be available during the December 16-18 time period. The forecasting team is confident that the errors are ironed out of the forecast. (c) Evaluation of Generation and Conservation Alternative: (Lead - Jeff King) This task is also nearly complete. From the initial exhaustive list of alternatives, there remains 17; eight or nine are hydro and the rest are coal and natural gas. The plans to be developed in Battalle Plans lA and lB will use coal-firtd steam, combined cycle and gas turbine plants, located in both Anchorage and Fairbanks. -{d) System Integration: {Lead -Jay Jacobson) The primary tool to be used in this task is the EPRI Over/Under Model, AREEP Version. Using this model, Battelle will develop plans with scheduled plant additions and cost. Also to be done is a sensitivity analysis consisting of: -Higher and lower fuel costs~ The base case is set with world markets forcing real escalation of 2 percent on oil prices. Sensitivity will be done on price forecasts with world oil escalating at 1 and 3 percent. -Capital costs will be varied on a+ 20% basis. Variance will be 1 imited to one alternative at a time. All capital costs wi 11 be recovered in the generation planning study. -Effect on demand of SB25.,.''capital cost grant" interpretation. For example, if consumers d:id not have to repay the costs of Susitna in their rates, what effect would the low cost energy have on demand. (e) Implementation Strategy-This will be defined for each Generation Plan identified. This task will address the possibilities for finnncing, strategy and institutional arrangements needed for plan implementation, including cautionary notes on assumptions. The actual completion date for the draft report in January 30. This will include plans, cost of plans, environmental impacts, other precautions. No recommendations are anticipated. 2. Mary Ann Hosko reviewed in detail a printout of a preliminary OGP output. The input data was discussed in detail. In general, there is a high degree of consistency between Acres and Battelle's basic data. The load model used by OGP will be annually matched to the Battelle forecast; ho\'tever, the monthly/daily characteristics will rema.in based on the.l980 Woodward-Clyde studies. The load model is a significant difference between AREEP and OGP as the former operates on a yearly load duration curve l!Jhile the latter varys by month and day. AREEP will use a constant shape of load duration curve throughout the 30-year period of analysis. I • 11 '1.: .. ' ·' •"-;.., 'I ' .J J, I J·. ' I, '~ 1 .. J~ ' ... -• • :~. ' 7 ~ ,- ' ~ ·, ' -i\ ',, Memo of Meetings -3-December 17, 1981 Acres has adopted the most recent Battelle information on existing and committed units. We will include the Copper Valley/Glennallen resources and load in the study, as Battelle has been directed to do so. In the OGP model, heat rates are specified to units, thus the existing units have a much higher heat rate than the avail able ne\'J alternatives.. AREEP allows only a single heat rate for each type unit. Therefore, the OGP model will have higher fuel costs associated with use of existing generation units. It was noted that Battelle is assuming no interactive energy flows between Anchorage and Fairbanks can take place prior to 1984o In 1985-89, energy transfer is limited to the pla,_nned intertie, 260 GHW annually. In the post-1990 period, energy transfers are unlimited. Acres, in focusing ·in the post Susitna period (1993-2010) has full exchange potential but also in costs to account for the more intertie capability. Acres is currently using one cost level each for coal, gas and oil. Battelle is differentiating between coal in Anchorage (Beluga) and Fairbanks (Nenana), and old and new gas in CEA and AML&PD., It was decided that Acres would make the necessary changes in their Railbelt model to enact the cost difference. This change will probably have a small impac,:: on results. Battelle is reviewing cost projections of North Slope gas available to Fairbanks. This is consistent with the economic scenario assumption of the completion of the TAPS gasline. It is interesting that this gas decreases in real price through time, due to the back out price from the lower 48 sales. Battelle is using two coal plants at the separate prices at Beluga and Nenana, as compared to the Acres• all Beluga development. Since the cost~ developed by Ebasco are nearly equal for the two sites, the prior decision that it would be much less expensive to upgrade the intert·ie and keep development at Beluga may be remiss. Acres will give consideration to the shifting of some of the Beluga units to the Nenanna fields. This could enact savings to the all-thermal plan, as it would have lower transmission costs (currently $500 million). At this time, 200 ~1W units are the standard size being used by Battelle for coal and combined cycle units. Acres will adopt this size. The retirement policies on the units will be from published Battelle work paper· 4~1. The AREEP model calculates interest during construction on capital costs, given a constant annual cash flow during the construction period. The OGP model does not calculate IDC so it is input as part of the capital costs. Acres is using an "5" curve formula for this calculation. These differences should not be significant. Start up time as defined on Battelle's information sheets is not consistent with the Acres• definition of irrmature unit time. The Battelle definition is time which would be added on to the construction period for unit corrmissioning. The Acres' definition is that time that the unit suffers a I ' ' ' ··1·1. : I r1::mo of M=et i ngs -4-December 17, 1981 higher forced and planned outage rate, due to "bugs:' in the plant which must be worked out. Acres will revert to using the previous immature time periods instead of the new Battelle start-up times. Battelle does not have the capability for expressing immature outage rates. Battelle is using ssveral factors in AREEP, not used in the Acres• model. These include a rate base for plants in service, and a cost for distibution and overhead. Battelle is using 8.13 mills/kWh for general administration and overhead. The rate base was supplied by the Alaska-PUC. A copy was given to Acres. It is depreciated by Battelle on a declining balance method at 10 percent per year. The AREEP model develops a generation plan based on a desired long term mix goal and an upper limit on capacities specified by the operator. Thus, the mix is controlled somewhat by the operator. The program, ~hen capacity is needed, reviews the existing system mix and compares it to the long term desired plan. Units are then selected to make the existing balance as close as possible with the plan. Currently, the all-thermal long term mix is approximately 40% Beluga coal units, 18% combined cycle, 8% gas turbines, 14% Fairabnks (Nenana) coal and 20% hydro. Spinning reserve requirements are not addressed by the AREEP model. The OGP model operates plants as necessary on a hot spinning reserve mode. Thus, the fuel costs in the Acres model will be higher for the same amount of generation. The output of the AREEP model are in three categories of price Jan. 1981, mills/kWh: total, electrical re~uirements, delivered energy, and conservation. The latter is calculated by Battelle's RED (Railbelt Electric Demand) model. The delivered category corresponds to the Acres' planning since conservation is taken into account by the forecasts provided by Battelle. It was concluded from the close comparison of the two models that the outputs will not be directly comparable on an absolute number basis. The generation plans are expected to be similiar with the relative merits of each plan shown to be the same. The following are major differences in methodology/model capability: (a) (b) Dispatch: The daily unit dispatch modeling in the OGP model results in greater use of more expensive units than the AREEP model, which dispatches units on an annual basis. This will result in higher fuel costs in the OGP model. Heat Rates: The AREEP r.rodel uses only one heat rate per unit type. The Acres• model was specific rates for each existing unit. This fuel costs for operating existing units will be significantly higher in the Acres • model. - I I I I I I I I I I l . ' . ~· M2mo of fv\= et i ng -5-December 17, 1981 (c) Overhead and Sunk Costs: The Battelle AREEP model has included cost for distribution systems and utility overhead. These have not been included in the Acres• model since relative costs between plans is desired rather than an absolute customer cost.. Thus, the production cost value from the OGP model is not equivalent to the AREEP consumer cost. The AREEP model also includes an annual cost for existing plant in service which is depreciated over time. 3~ Other issues discussed: (a) (b) (c) {d) (e) (f) (g) Hydro alternative: Battelle has cost and energy information from both Bechtel and Ebasco on the Chackachamna project. It was agreed that the primary Chackachamna alternative would be Case B from the Bechtel Study. Battelle will check the Ebasco costs and project in sensitivity analyses. Other hydro alternatives to be used are Grant Lake (7 MW in 1988) and Allison Creek (7MW in 1992) based on Acres-DSR costs (escalated to January 1982 level by 7 percent) and energies. Socio-economic data which is the basis of ISER's forecast was provided to Acres in report form. The revised medium forecast, as well as the high and low forecast, will be available by December 18. The high and low will bracket the range of reasonable economic futures. No analysis of a resultant reserve margin which would be dependent on forecast uncertainty has been completed. At this time Battelle is doing their analysis on a 40 percent reserve goal. Acres is planning to a loss of load probability of one day. in ten years. A copy of Acres• final report on Cook Inlet Tidal Power will be sent to Battelle. Acres will adjust its model to differentiate between fuel costs in the different load centers. This will be consistant with the AREEP model. Additionally, to be consistent with Battelle's findings~ a limited number of coal plants will be sited in Nenana to balance demand and generating resources. The period of analysis for the study was discussed. Acres is making the assumption of a 40-year extension of the last year (2010) of modeling in order to make some measure of the long term relative benefits of the with and without Susitna plans. While Battelle has no specific objections to the methods, they will not be doing the same, unless directed. -... G I I I f1Jemo of r.-eeting -6-December 17, 1981 (h) Susitna development was discussed, and it was pointd out that the development could be formulated as follows: Watana 1 4 170 MW units = 680 ~ 2 170 MW units = 340 1020 MW Devil Canyon 1 3 150 MW units = 450 ' 1 150 MW units = 150 600 MW Energy 3385 GWh 0 GWh 3264 GWh 0 6649 GWh I Addition of second stage at Watana delays $41 million expenditure. 4. Unresolved Issues: I I I I (a) The escalation of O&M and capital costs proposed by Ebasco have 41ot been accepted yet by Battelle. They have requested that Ebasco substantiate the figures. At this time the values are not being used. {b) The Acres' concern with regard to coal prices was discussed including: the zero real escalation of Nenana coal, the relationship between the coal and oil prices, and the probability of the opening of the Beluga fields in light of low coal value. This issue will be pursued at a 1 ater date. {c) An additional concern with regard to level of confidence of estimates was discussed. The Susitna estimate, made with detai"~ed studies, takes into account the specific P.roblems of the site. The alternative estimates, on the other hand, may have a lower confidence level and may actually be a center point forecast, subject to a cost increase. Battelle will discuss the level of confidence of the estimates with Ebasco. {d) Transmission line costs for Susitna development have included a reliable assessment of transmission 1 i ne update and capabi 1 ity. A similar assumption and associated costs must be made for the thermal alternative, to be added to the cost of the 11 Without" Susitna case. ~ ·• ..... c', _. ' - I ll I I I I I I I I I _, I flemo of Meeting -6-December 17, 1981 (h) Susitna development was discussed, and it was pointd out that the develoJ)Tlent could be formulated as follows: Watana 1 4 170 MW units = 680 £ 2 170 MW units = 340 1020 MW Devil Canyon 1 3 150 MW units = 450 £ 1 150 MW units = 150 600 MW Energy 3385 GWh 0 GWh 3264 GWh 0 6649 GWh Addition of second stage at Watana delays $41 million expenditure. 4. Unresolved Issues: (a) The escalation of O&M and capital costs proposed by Ebasco have not been accepted yet by Battelle. They have requested that Ebasco substantiate the figures. At this time the values are not being used. (b) The Acres' concern with regard to coal prices was discussed including: the zero real escalation of Nenana. coal, the relationship between the coal and oil prices, and the probability of the opening of the Beluga fields in 1 i ght of low coal value. This issue will be pursued at a 1 ater date, (c) An additional concern with regard to level of confidence of estimates was discussed. The Susitna estimate, made with detailed studies, takes into account the specific groblems of the site. The alternative estimates, on the other hand, may have a lower confidence level and may actually be a center point forecast, subject to a cost increase. Battelle will discuss the level of confidence of the estimates with Ebasco. (d) Transmission line costs for Susitna development have included a reliable assessment of transmission line update and capability. A similar assumption and associated costs must be made for the thermal alternative, to be added to the cost of the "without" Susitna case. - I I I I I I I I I I f I l I I. I,_ IL I[ ·l ITEM 3 -BENEFIT TO COST RATIO METHODOLOGY -(t '. I I I I I I I I I I I I. I. I J Item 3 Susitna Hydroelectric Project Economic Analysis Benefit to Cost Ratio Calculation The primary method of comparing with and without Susitna alternative scenarios is total system costs. The planning model provides output from a computer of the total production costs of these alternative models on a year by year basis. These total costs for the period of modeling include all costs of fuel and operation and maintenance of all generating units included as part of the system. In addition, the production cost include the annualized investment cost5 of any production plants added during the period of study. Factors which contribute to the ultimate cost to the consumer of power which are not included in this model are: all investment cost to plants in service prior to 1993, costs of the transmission and distribution facilities in service and administrative cost of utilities for providing electric service to the public. These costs are common to all scenarios and have been omitted from the study, as having no impact on generation plant decisions. Thus, the production costs modeled are only a portion of ultimate consumer costs and in effect are only a portion, albeit major, of total costs. The sum of the costs is an effective relative indicator of the measure of cost of following one plan compared to another. In order to compare costs, all annual costs from 1993-2010 production simulation have been converted to a present worth to 1982. These present worths for all scenarios considered are shown in tabular form in two amounts. The first is the 1982 PW of the 18 years of model study from 1993-2010. The second value is an estimated long term PW of system costs which will be discussed later. To illustrate this discussion, the with and without Susitna plans of the medium load forecast will be compared. Considering the without Susitna Plan (Case D in Item 4 of this package) the 1982 PW of 1993-2010 production costs is $3141 X 106. This total is the theoretical amount of cash (not including those items noted) needed in 1982 to meet electrical production costs in the Railbelt for the period 1993-2010, given scenario assumptions. The second cumulative PW value is thP long term (2100-2051) PW estimate of production costs.. In considering the value of the addition of a hydropower plant, which has a useful life of approximately 50 years, the study period is inadequately short. A plant which is added in 1993 or 2002 would accrue PW benefits or penalties for only 17 or nine years respectively in the PW measure. It is also true that modeling the system for an additional 50 years, assuming loads and generation alternatives, is well beyond the realm of any prudent projections. For this reason, the final study year (2010) production costs were assumed to reoccur for an additional 41 years, and added to the 18 year PW, to sum a relative measure of long term cost differences between alternative methods of power generation. - 'I: ' ... ,; I I 'I i ~·! I I It should be noted that the long term PW is not by any means an absolute number but is a relative measure of alternative scenarios production costs. For this reason, a benefit-to-cost ratio for a Susitna alternative cannot be calculated by taking one 20 year or long term PW divided by another. What can be estimated is a long term benefit of utilizing one alternative compared to nnother, by examining the difference in PW totals. For example, there would be a production cost savings over the long term of $1022.4 million by pursuing the with Susitna Plan ($8069.8 million), compared to the non-Susitna system ($7047.5 million). Since the costs of these hydro alternatives are built into the production costs, this is a net benefit. In order to compare the Susitna alternatives in terms of both net benefits and costs, it is desirable to estimate a benefit-to-cost ratio for the alternative developments based on system cost estimates. The first impulse would be to divide the total long term PW of one system by another, yielding a system with/without comparison. However, as previously noted, the PW total is not an absolute figure by itself, but does contain some system-common factors. Additionally, both the numerator and denominator contain substantial portions of system costs common to both systems, masking the costs and benefits under scrutiny. The following benefit-to-cost methodology was used. It is readily seen that the net benefits of a plan are defined as the production system cost savings or penalties of the plan as compared to the basis. Additionally, the present worth of the alternatives investment cost would be in the denominator of the ratio. The measure of net benefits is inadequate however, in computing a complete benefit-to-cost ratio. Inherent to the non-Susitna plan is a portion of basic costs of generating which are equal to the cost of the Susitna alternative. These costs must be included with the net benefits to yield a total benefit for an alternative. Figure 1 illustrates this discussion. In that illustration, the ratio would be equal to the PW of gross system benefits divided by the PW of the alternative cost. The basis used for calculating the B/C ratios is the non-Susitna plan. This plan has a long term PW of 7047.5 Since the Susitna plan has a lower production cost, the B/C ratio is 1.2. Should any plan in sensitivity analysis have a higher production cost than the non-Susitna plan, it would then have a B/C less than 1. J! - I I I I I I I I I I I I. I I I. J, I I. il, ~----------------------------------------------------------~ wn-~ wrTI-\OUT PEESENT 'NOE.'T\4 SVSinJA SVSlTUA \OIAL I t P~ODUCTlO~ t ~2. COS-r-5 -------------l-----~.,_ NEf BENEFIT OF ExCESSNE \Q COST=!2. tOr---r--· . Gl<OSSBt:NEFfT-':'--~ ·- B c PW c~·ror· -= 5 EQUIVALENT ~T OF S~ p =3 -.. ·' · ALTEt<-t-..lATIVe ::: 3 7 f--_j_ ~ ··,. 7 "-!---~r---~ ·---. ..--t.L.--__ " -· ~ A 'L o.,..·w = R' ;f"V-·· • ~. S'ISTE"M ~OGTS A , B ALTE12NAT\VE BASIS FOe COM PA g I SOI\J BEt-JEFIT COST ALL COSIS OR GROSS BE~EFITS cosT or= A EQ.UI\(. B+ EXC.ESS B COSTOF A BENEFIT lD COST EATIO METWODOLOG;i FlGU~E I ,· ,' -· I I I" I I I I. I I I I_ I I., ITEM 4 -PRELIMINARY RESULTS I ' I I I I I I I I I I I I I I ~ I I I I .; 'I . Item 4 Preliminary Results -Economic Analysis The following pages present preliminary results of the economic analysis discussed in other items in this package~ The first two pages are calculations based on output from the production cost model using different development plans. The following pages are direct output from the model describing those plans.. To interpret the output, the final item of the package (OGP summary) should be consulted. Five plans have been developed to date: A. Without Susitna, all Thermal Alternatives -using Battelle figures B. Without Susitna, Thermal plus Chackachamna-using Battelle figures C. With Susitna -using Battelle figures D. Without Susitna, all Thermal Alternatives -using Battelle figures except for coal price~, including real escalation on capital costs and O&M. E. With Susitna -using Battelle figures except for coal prices, including real escalation on capital costs and O&M As concluded from the work sheets, in comparing Cases D and E, the Susitna project has a benefit to cost ratio (B/C) of 1.21 to 1. In comparing Case C to Case A, Susitna has a B/C of 1.16 to 1. In comparing Case C to Case B the B/C is 1.11 to 1. Note that these are preliminary results. Several minor adjustments to model input need to be made. These include the estimate on O&M for Susitna and the cal cu 1 at ion of interest during construction in Cases D c.~nd E. These changes may raise the B/C for Susitna to a small degree. 0 -· I 1.·····. " ' I I I I I I I I I Calculations SUBJECT: Lc~~~~~~ ~w (__ \. 0 i;) If\ -\ :; """2. ' ~ (.. (a . ~) ( (, 0 -:,yt' a . 1 CY...:8 ,. ~~ '2o tt-L.o5{ '-'~ ~ "2.-0'"t) rpw C0rsF Q,.)}._) "":::/::~::. lGf~~-2. -o I o ~ w ;\-o~l ~-\t.v._ L/L\'1 d.lfl ~-3 . ~\N \+ho~ ~~~ L IKS c:? 3 <i$7' .3 ~ W ~~ ~vS ;-h.-., I -~ w .~~ -e.~c. I 5jt..~ .-1:\-._ -e. 5 c:. L /o '1 J.../¥7 3\41.\ I I I I; a: ~~ lo z I ~ 0 u. "''\ ' -·: :<• t . \ q~ 2., "2.0\ 0 3G.l.Co . "3 53./ 36'1. 3 JOB NUMBER '):)jo.?,v~ FILE NUMBER -\>51 CD • l'{ o& SHEET I OF ]/ BY f1"~ DATE\ /-g/ APP (ix' a.&) (~to-L.t£{) ~ 3l Ob '3 (p 14'. ~· I J ' I DATE l '1'1:, -'2-.ll.f ( '{p(7b,3 ·evo a r.o9 6"-:;z to, I r -. 2 c=,q, S' 30&5. \0 I 5S ftl7./ l 4~ L 't 4 q 2<3, '6 I % () {,..~ .. 4 3?-<c .. ~ 2>'15L~ 1 /ot.t75 l I I I I I I I I I I I I I I I ~ 'c:: I N 1.0 ,... a z I.~ ,Q ,u. Calculations SUBJECT: ~)c_@·~~ crw N~ ~ .=.. -'7'1 q>zs.'"'..,?< l2:?=J. ·J & 1/ (q • 3 _.. (p oo ~ . 9 ?LJ Go"'st-:::; 9 /t---:J-l.l.fS ,~..Jo 1 - 11 <?:>w ~ ~.:.~ =-'9 :2:5 J ...,.U,llS ~ tot'S 5 QvJ c..::. ~"T ~ 3 <6 G:. C) fl.../ 3't>l.o c + '139. y -::: I. ··f .{ '-YL.. 3Cb(e.o Cc~·~" ~ \.}:.,0 '\ ~ '-~ v-? f." 1 ~,....,_ JOB NUMBER f~7CG 1 0" FILE NUMBER ~5 '700, ft.f, <::>{/ SHEET ~ OF ~ --- BY 'i)1t\)61 DATE ~J/8V APP \ DATE -.§{ I , 1,t.p VV\ = I <.o"/.t..{ . {2. t_.t+C L~6 ,..ro~) r \'04'/ :J:Et."'f'Q .... ~ -:;; Ia 5o-G_..!/Lo,~ -5 S 67. I --;.. '09.Z. '?w 0a"J~ ~ :,~c, o o.. -3 5S&a .,.. &>o9.iL I. t' r-.J {. -~ 't> lh 0 - , V'~ ..----, G EC...,-:, v-l ---;-~.,_ ~ e.~C.. N.e.+ '=>~ ~a to '=\.cr -1 o4 7.5 ~ 16 z.-z... c.~ '\ 'ft.-> 0.'5L rJ J~o,f\ \. ,.,. l ... ··L.fo'7lf J¥1. "' 1. 2\9 )( ·' '2. "-'-\ ~ 3G?o.S q) ~. 4 t U7 ~I 1.+51 .scs,_,, l-3 l t \"'(' )£ -7- J.+9 2.. 0 - I I I I "' I I I I I I I I I I I ... I . I I ! ' . I . . G l:. ~. E f. A L E L E C 1 h 1 C CD !""iF ?:t~ Y OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT •***********•*********************************** ALASKA HAJLBELT ZERO/. -3/! JOB NUMBER 2ML749 12/30/81 '*************************************** GENERATION SYSTEM TYPE OF'TMZING PCT TRIM NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES 1 2 3 4 5 6 7-10 0 1993 1993 0 0 1993 *** 0 0 0 0 0 0 , 1992 MW ~ 59 452 141 67 317 155. SUM= 1190 *********************************************************************** YR ** 93 94 95 96 97 98 99 0 1 2 3 4 Y E A R L Y H W A D D I T I 0 N S ******* ******* ******* ******* ******* ******* ***** 1X ,200 200* ,.200* 70* lX 70 5 .. 70* TOTAL CAF'AB. + TIES ****** **** 1373 1542 1495 1624 1620 1635 1635 1591 1661 1608 1625 1825 1807 6 70, 1854 7 70* 1924 8 200* 2098 9 2097 10 2097 *********************************************************************** *********************************************************************** MW ADD 0 1000 '490 0 0 0 0 SUM= 1490 MW RET 0 -46 -335 -141 -61 0 0 SUM= -583 ****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 1013 606 0 6 317 155 SUM= 2097 PCT lOT o. 48.3 28.9 O. 0.3 15.1 7.4 SUM~100 PCT ********************************************************t************** AUTO 0 200 70 0 0 0 0 SUM= 270 PCT TOT o. 74.1 25.9 O. O. O. O. SUM=100 PCT * COMMJ TTEI• MW -, I ~ I f . I I I I I I I I I I I I I I I I I I GENERAL ELECTRIC COMPANY OGF'-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ ALASKA RAILBELT ZEHO/. -37. JOB NUMBER 2ML749 12/30/81 **************************************** YEAR **** 1993 1994 ·1995 '' ''. 1996 1997 1998 1999 2000 200i ~002 2003 2004 2005 2006 2007 2008 2009 2010 LOA It ***** 947 965 983 1003 1023 1044 1064 1084 1121 1158 1196 1233 1270 1323 1377 143('- 1484 1537 TOTAL CAPABILITY <INCLUDING TIES) YEAR TIME OF END PEAK ***** ***** 1373 1373 1542 1542 1495 1495 1624 1624 1620 1620 1635 1635 1635 1635 1591 1591 1661 1661 1608 1608 1625 1625 1825 1825 1807 1807 1854 1854 1924 1924 2'098 2098 2097 2097 2097 2097 LOSS OF LOAit PCT. PROBABILITY RES. Il/Y H/Y **** ****** ****** 45.0 0.063 t o. 59.8 0.027 o. 52.0 0.077 o. 61.9 0.059 o. 58.4 0.084 o. 56.6 0.092 o. 53.6 0.055 o. 46.8 0.059 o. 48.2 0.038 o. 38.9 0.062 o. 35.9 0.087 o. 48.0 0.029 o. 42.3 0.062 o. 40.2 0.064 o. 39.7 0.057 o. 46.7 0.033 o. 41·. 3 0.063 o. 36.4 0.060 o. - , COST IN YEARLY COST ******* 141.8 165.1 170.0 203.6 210.7 218.8 222.7 226.7 237.8 242.7 256.1 272.1 287.4 302.3 318.1 337.5 350o3 361.6 MILLION $ CUM. f'W TOTAL ******* 102.4 218.2 334.0 468.6 603.8 740.2 875.0 1008.1 1143.7 1278.1 1415.8 1557.8 1703.4 1852.1 2004.1 2160.5 2318.3 2476.3 I ~· ~ ., I I I I I I I I I . I I I l i 5I GENERAL ELECTRIC COMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT *********************************************~** ALASKA F~AILBEL T ZEROX -3k JOB NUMBER 2ML749 12/30/81 **************************************** YR ** 93 94 95 96 97 98 99 0 1 2 3 4 5 6 7 s 9. 10 . POOL PEAK (MW> ****** 947 965 983 1003 10?3 1044 1064 1084 1121 1158 1196 1233 1270 1323 1377 1430 1484 1537 TOTAL ENERGY < GLJH > ******* 4736 4829 4922 5031 5141 5250 5360 5469 5661 5853 6044 6236 6428 6701 6973 7246 7518 7791 , LOA II FACT Of~ *****~ 57.09 57.12 57.16 57.10 57.37 57 .. 40 57.51 57.44 57.65 57.70 57.69 57.58 57.78 :=7 8? t..J • .... 57.81 57. 69· 57.83 57.86 TOTAL COSTS <MIL.$) ****** 142 165 170 204 211 219 223 227 238 243 256 272 287 302 318 338 350 362 YEAF:L Y $/MWH *****~**************************** INV. FUEL OtM N.I. TOTAL ***** ***** ***** ***** ****** s.o7 21.23 3.64 o. 29.93 12.46 17.96 3.76 o. 34.18 12.22 18.60 3.72 o. 34.55 1 a • 14 1 a·. 3 2 4 • o 2 o • . 4 o • 4 7 18.21 18.81 3.96 o. 40.99 18.29 19.47 3.93 o. 41.69 17.91 19.78 3.85 o. 41.55 17.56 20.17 3.72 o. 41.45 17.38 20e94 3.68 Ot 42.01 16.81 21.10 3.56 o. 41.46 16.68 22.18 3.52 o. 42,38 20.01 19b80 3.82 o. 43.63 19.78 21.21 3.73 o. 44.72 19.33 22.13 3.66 o. 45.12 18.92 23.08 3.62 o. 45.62 21.52 21.21 3.85 o. 46.58 20.74 22.09 3.77 o. 46.60 20.01 22.73 3.67 o. 46.41 . ft . .. ! . : ' : <'-~fJ ?l , ... ; . ": ;;. ~· ~-> > ·."-_ :' ~ . ' :.J ·~) ".o I~.~~::~~ ~N~"~; ~::~L~ST DAT~ ~H~CKING ****** . I GENERAL ELECTRIC COMPANY _ OGP-5 GENERATION PLANNING PROGRAM-SUMM~RY OUTPUT ;I ***************~***********.*************,;;~W*L 7 K£ t \l ALASKA RA I LBEL T 1 · · ZEROX -3X s W/o S"s . . JOB NUMBER ML7K5 12/30/81 . b>t1 ~ cut.tc.k. 1 it**~********* ***~~*****~********* &~~~~c. GENERATION SYSTEM 1Jr> (4c.. h"\. ~~. ~ I· TYPE NUKE COAL NGASGT OIL GT DIESEL COMCYC . TYPES o 5o~ 1 2 l 4 5 6 7-10. GPTMZING 0 . 1993 1993 0 0 . 1993 *** · I PCT TRIM 0 0 0 0 0 0 . . 1992 HW 0 59 · 452 141 67 . 317 155 SUM= 1190 J *~********************************************************************* TOTAL IYR YEARLY H W ADD IT I 0 N S ;A~~~s ** . ******* ******* ******* ******* ******* ******* ***** ****** **** I"~~ 330* ~~~~ .95 1424 1::~ -~00*. ~!~: ·;·98 70* 1495 "99 1495 ~·r ~ 200* ~~;~ -2 70* 1668 . ~ 1· 3 70* 16Eis < [ 4 ',. 1685 5 200* 1797 . ~\ I ' ·6. 1774 ~ z 70* 1844 a . 70* 1888 ~ .9 -.70* . . 1957 11 10 200* 2157 ~ *******************************************~*************************** *********************************************************************** 11 MW ADD 0 800 420 0 0 0 330 SUM= 1550 ~ MW RET 0 -46 -335 -141 -61 0 . 0 SUM= -583 ·****** ****** ****** ****** ****** ****** ****** ***ll*********** . . -· • . I 2010 0 . 813 536 D ~ . ~-7 4~.§_SUM= 2157 ~:... ""PCT TOT 0 • 37 • 7 24 • 9 0 • 0 • 5"" 14 • 7 22 • 5 SUM 1 00 per-···--. - -*********************************************************************** I' AUTO 0 0 0 0 0 0 0 SUH= 0 ll,j PCT TOT 0 • 0 • 0 • 0 • 0 • 0 • 0. SUM= 0 PCT I , I GENERAL ELECTR~C COMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ ALASKA RAILBELT ZEROX -, 3% JOB NUMBER 2ML7K5 12/30/81 **************************************** ) ~ ' - o. o. o. o. SUM= 0 f'CT ·,r·:~iiTTED MW l ; l ~; ' ' . GENERAL ELECTRIC COMPANY I OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ .. (~ RAILBEL T i ·i· • -:-\ 1-'-3% ~ L UJMFER L ~ K5----1: 2/3'07'8t---. ;~:~~=*****~ ~.u******************** I I LOAD ***** 947 965 983 1003 1023 1044 1064 . 1084 1121· 1158 1196 1233 1270 1323 1377 1430 1484 1537 TOTAL CAPABILITY <INCLUDING TIES> YEAR TIME OF END ***** 1503 1472 1424 1354 1480 1495 1495 1651 1651 1668 1685 1685 1797 1774 1844 1888 1957 2157 PEAK ***** 1503 1472 1424 1354 1480 1495 1495 1651 1651 1668 1685 1685 1797 1774 1844 1888 1957 . 2157 LOSS OF LOAD PCT. PROBABILITY RES. D/Y H/Y ' **** ·****** ****** 58 • 7 . 0. 000 0 • 52.5 o.ooo o. 44.9 0.002 o. 35.0 0.019 o. 44.7 0.024 o. 43.2 0,030 o. 40.5 0.044 o • 52.3 0.024 o. 47.3 o~o43 o. 44.1 0.065 o. 40.9 0.040 . o. 36.7 0.067 o. 41.5 0.073 o. 34.1 o.o95 o~ 33.9 0.083 o. 32.0 0.097 o. 31 • 9 o. o·a7 · o. 40.3 0.038 o • GENERAL ELECTRIC COMPANY COST IN MILLION $ YEARLY CUM. PW . COST TOTAL ******* ******* 146.5 105.8 15.1.8 212.3 158.3 320.1 187.8 444.3 ·192.6 567.9 20.1.2 693.2 207.6 818.8 228.6 953.1 236.8 1088.2 248.1 1225.5 255.5 1362.9 264.8 1501.1 280.6 ~ 1643.2 . 290.0 1735.9 304.9 1931.5 321.1 2080.5 338.2 2232.7 353.7 2387.3 OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ ' )SKA RAILBELT ~~~U~B~~ 2ML7K5 12/30/81 ************************************** I ************ LOSS OF LOAD PROBABILITY ************ EXCESS ;(·.·· CMW> DAYS/iEAR Ill ****** ******** 247. o.oooo 205. o.ooo2 ;:'·· F ;, ;. ':"lpi 148. 0.0018 68. o.o1s6 66~ 0.0240 0.0302 JAN& FEB. MARCH APRIL MAY JUNE JULY AUG. SEPT. OCT. NOV. DEC. *********************************************** o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo 0.0002 0.0001 o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo 0.0002 0.0015 o.oo17 o.ooos o.ooo1 o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo o.oooo 0.0020 0.0140 0.0029 0.0007 0.0004 0.0002 0.0002 0.0002 Of0002 0.0002 0.0002 0.0002 0.0030 · 0.0158 0.0036 0.0009 0.0005 0.0002 0.0002 0.0002 - . ' .... . . \~ ~.r ~-t.· {i .. v ~f. ~ ~ .... .,., ~1 ~~ ·!t· '':, t .. i . ... ·- ' ... , . . ' I ' . GENERAL ELECTRIC COMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ I . ALASKA RAILBELT I ZER07.-3% ~ . JOB NUMBER HL7K5 12/30/81 ' ~*********** . ******************** . _.... I POOL TOtAL TOTAL YEARLY $/MWH I i PEAK ENERGY LOAD COSTS ***********************~*****~**** o+H N.I. TOTAL : ~ i/, Lt YR 01W> <GWH> FACTOR <MIL.$) INV• FUEL I ** ****** ******* ****** ****** ***** ****'~ ***** ***** ****** . 93 947 4736 57~09 146 12.22 15.29 3.4·2 o • 30.93 94 965 4829 57.13 152 11.98 16.07 3.39 o. 31.44 95. 983 4922 57.16 158 11.75 17.01 3.38 o. 32o15 I ' 96 1003 5031 57.10 188 11.50 22.50 3.34 o. 37.34 : J 97 -' 1023 5141 57.37 193 17.30 16.72 3.43 o. 37.46 98 104·4 5250 57.41 201 17.40 17.50 3.42 o. 38.32 I 99 1064 5360 57.51 208 17.04 18.29 .3.40 o. 38.72 ; j· 0 1084 5469 57.43 229 23 .• 32 1.4.85 3.64 o. 41.81 ---~.._ '1 1121 5661 57.65 237 22.52 15.73 3.57 o. 41.83 248 22.19 16.67 3.53 04-42.39 I· 2 1158 5853 57 .. 70 '3 1196 6044 57.69 255 21.88 16.95 3.44 . 0& 42.27 1233 6236 57.58 265 21.21 17.86 3.39 o. 42.46 3~62 o • 43.66 4 • 5 1270 6428 57.78 281 24.31 15.72 I 6 1323 6701 57 .. 82 290 23.32 16.46 3,51 o. 43.28 7 '!377 6973 57.81 305 22.75 17~52 3.46 o. 43.73 I· 8 1430 7246 57.69 321 22.22 18.69 3.41 o. 44.32 9 1484 7518 57.83 338 21.74 19.86 3.38 o. 44.98 ' .10 1537 7791 57.87 354 24t05 17.75 3.60 o. 45(t40 -... . . 1·:: 1' GENERAL ELECTRIC COMPANY , OGP-5 GENERATION PLANNlNG PROGRAM-SUMMARY OUTPUT ************************************************ I . ALASKA RAILBELT ZEROX -3X .JOB NUMBER 2HL7K5 12/30/81 1'1 i .. ~ .~ I I. -1 I I .. **************************************** . ' GENERATION SYSTEM TYPE 1 2 3 4 5 6 7 8 9 10 SUM 92 0 59 452 141 67 317 155 0 0 0 1191 ********************************************************************** . TOTAL CAPAB. YR Y E A R L Y P E R C E N T H I X ********************************************************************** 93 o. 3.9 29.5 9.3 3.9 21·1 32.3 o. o. o. 1503 94 o. 4.0 28.0 9.5 3.9 21.5 32.9 o. o. o. 1472 95 o. 4.1 28.0 9.4 2.2 22.3 34.0 o. o. o. 1424 96 o. 4.4 29.5 4.8 2.1 23.4 35.8 o. o. o. 1354 97 o. 17.5 26.7 o. 1.6 21.4 32.8 o. ----e. o. 1480 -· "98 y- o.-~-J./.-3 · 21 .a~·· o.-·--· '1..2 · 21+2 -· 32~.·4 - --o .-·--· -o .-:-~ ---o .~·----r-495- .. 99 o~ 17.3 27.8 o. 1.2 21.2 32.4 o. o. o. 1495 0 26.3 24.1 o. 1.0 19.2 29.4 o. o. 0 1651 ~ . 1 26.3 24.1 o. 1.0 19.2 29.4 o. o. o. 1651 2 26.0. 25·0 o. o.9 19.0 29.1 o. o. o. 1668 3 25.8 25.7 o. 0.9 18 .. 8 28.8 o. o. o. 1685 4 25.8 25.7 o.9 18.8 28.8 o. o. o. 1685 5 34.1 20.9 o.4 17.6 27.0 o. o. o. 1797 0.4 17·9 27.3 o, o. o. 1774 u ........ I ' l. ;[ .. ' l r : ' •. ,.,!' I. i !_ '{ 1:! : .J I u • 11 I I I I I I I' JL I I I GENERAL ELECTRIC ~OMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ ALASKA RAILBELT ZERO/. -3Y. JOB NUMBER 2ML7V1 12/31/81 **************************************** GENERATION SYSTEM NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES TYPE 1 2 3 4 5 6 7-10 OPTMZING 0 1993 1993 0 0 1993 *** PC T T R 1M 0 ·o 0 0 0 0 , 1992 MW 0 59 452 141 67 317 155 SUM= 1190 *********************************************************************** TOTAL CAPAB. YR ·Y E A R L Y M W A It II I T I 0 N S + TIES ** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 680* 1853 . 94 1822 95 1774 96 1704 97 1630 98 1575 99 1575 0 1531 1 1531 2 601* 2079 3 2026 4 1* 2027 5 1939 6 1* 1917 ~ 1X 70 1987 8 1X 70 1* 2032 9 2031 10 1X 70 1* 2102 ***********~*********************************************************** *********************************************************************** MW AitD 0 0 210 0 0 0 1285 SUM= 1495 MW RET 0 -46 -335 -141 -61 0 0 SUM= -583 ' ****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 13 326 0 6 317 1440 SUM= 2102 PCT TOT 0. 0.6 15.5 O. 0.3 15.1 68.5 SUM=lOO PCT *********************************************************************** AUTO 0 0 210 0 0 0 0 SUM= 210 PCT TOT 0. O. 100.0 O. O. O. O. SUM=100 f'CT % COMMITTED MW -ZXL14i£ I GENERAL·ELECTRIC COMFANY .II·~ ( 'l OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ I ALASKA RAILBELT ZERO% -37. I. . JOB NUMBER 2ML7V1 12/31/81 ~ I **************************************** I 11 l .. ~ I I I I I I I IJ I I I I I I YEAR **** 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 LOAD ***** 947 965 983 1003 1023 1044 1064 1084 1121 1158 1196 1233 1270 1323 1377 1430 1484 1537 TOTAL CAPABILITY <INCLUDING TIES> YEAR TIME OF EN II PEAK ***** ***** 1853 1853 1822 1822 1774 1774 1704 1704 1630 1630 1575 1575 1575 1575 1531 1531 1531 1531' 2079 2079 2026 2026 2027 2027 1.939 1939 1917 1917 1997 1987 2032 2032 2031 2031 2102 2102 LOSS OF LOAII f'CT. PROBABILITY RES. It/Y H/Y **** ****** ****** , 95.7 o.ooo o. 88.8 o.ooo o. 80.5 o.ooo o. 69.9 o.ooo o. 59.4 o.ooo o. 50.8 0.001 o. 48.0 0.002 o. 41.2 0.015 o. 36.6 0.032 o. 79.5 o.ooo o. 69.4 0.001 o. 64.4 0.001 o. 52.7 0.017 o. 44.9 0.068 o. 44.3 0.025 o. 42.1 0.029 o. 36.9 0.050 o. 36.8 0.025 o. - COST IN YEARLY COST ******* 203.8 209.0 211.9 222.2 225.4 229.7 234.6 244.0 253.4 250.7 268.2 250.6 266.9 254.9 278.4 276.7 296.0 299.5 MILLION $ CUM. PW TOTAL ******* 147.2 293.8 438.1 585.0 729.7 &; 872.8 1014.8 1158.1 1302.6 1441.4 1585.6 1716.3 1851.6 1976.9 2109.9 2238.2 2371&4 2502.3 ·li·.· ! ', \ I. ; .il ALASKA RAILBELT GENERAL ELECTRIC COMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ ZERO/. -3! :I' .: JOB NUMBER 2ML7V1 12/31/81 . **************************************** $/MWH I. POOL TOTAL TOTAL YEARLY PEAK ENERGY LOA II COSTS ********************************** ·roTAL ' ' I I I I I I ·I I I I 1\ ' I ·I; . l •1.1 ' YR ** 93 94 95 96 97 98 99 0 1 2 3 4 5 6 7 8 9 10 ..... :· t·: <MW> ****** 947 965 983 1003 1023 1044 1064 1084 1121 1158 •1196 1233 1270 1323 1377 1430 1484 1537 <GWH> FACTOR <MIL.$) ******* ****** ****** 4736 57.09 204, 4829 57.12 209 4922 57.16 212 5031 57.10 222 5141 57.37 225 5250 57.41 230 5360 57.51 235 5469 57.44 244 5661 57.65 253 6352 62.61 251 6455 61.61 268 6599 60.92 251 6698 60fi21 267 6880 59.36 255 7079 58.69 278 7310 58.20 277 7551 58.08 296 7827 58.14 300 INV. FUEL O+M N.I. ***** ***** ***** ***** ****** 34.49 4.99 3.54 o. 43.02 33.83 5.95 3.50 o. 43.28 33.19 6.42 3.44 o. 43.05 32.47 8.35 3.35 o. 44,17 31.78 8.ao 3.27 o. 43.84 31.12 9.43 3.21 o. 43.76 30.48 10;11 3.18 o. 43.76 29.87 11.63 3 t 12 o. 44.62 28.86 12.81 3.09 o. 44.76 35.96 o. 3.51 o. 39.47 35.39 2.66 3.50 o. 41.54 34.62 o. 3.36 o. 37.97 34.10 2.44 3.29 o. 39.84 33.20 0.69 3.15 o. 37.04 32.60 3.56 3.16 o. 39.32 31.90 2.89 3.07 o. 37.85 30.88 5.28 3.04 o. 39.20 30.10 5.21 2.96 o. 38.26 ·~. - il:.· ' . • ,,'j ;r 1,, j '1. ) . I i ' ' II' l 'i ;I I l ;1·1 I , i. j il···.; l f i I .. I I I I' f i .J • ~· I I I I I BEGIN FILE -L7090207 SNUMB = ML709, ACTIVITY 02, REPORT CODE = 07, RECORD COUNT = 000349 GENERAL ELECTRIC COMPANY, OGP-5 GENERATION PLANNING PROGRAM -~ JOB NUMBER 2ML709 12/31/81 TD ::ti L lOCi NAMELIST DATA RECORD NAMELIST DATA RECORD 1 HAS BEEN READ 2 HAS BEEN ~EAD . ****** END OF NAMELIST DATA CHECKING ****** A'"~~-t~t.. ~ ~ ~-e~(. . 0 "' ~\. ,o~A GENERAL ELECTRIC COMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ ALASKA RAILBELT ZERO% -37.~ JOB NUMBER ,ML709 12/31/81 **********· ********************* -GENERATION SYSTEM NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES TYPE 1 2 3 4 5 6 7-10 OPTMZING 0 1993 1993 0 0 1993 *** PCT TRIM 0 0 0 0 0 0 1992 MW 0 59 452 141 67 317 155 SUM= 1190 *********************************************************************** TOTAL CAPAB. YR 1 E A R L Y M W A D D I T I 0 N S + TIES ** ******* ******* ******* ******* ******* ******* ***** ****** **** 93 200* 1373 94 1X 200 1542 95 1495 96 200* 1624 97 70* 1620 98 70* 1635 99 1635 0 1591 1 70* 1661 2 1608 3 70* 1625 4 200* 1825 5 70* 1807 6 70* 1854 7 70* 1924 8 200* 2098 9 2097 10 2097 *********************************************************************** *********************************************************************** MW ADD 0 1000 490 0 0 0 0 SUM= "1490 MW RET 0 -46 -335 -141 -61 0 0 SUM= -583 ****** ****** ****** ****** ****** ****** ****** **** *********** 2010 0 1013 606 0 6 317 155 SUM= 2097 PCT TOT Oe 48.3 28.9 O. 0~3 15.1 7.4 SUM=100 PCT *********************************************************************** AUTO 0 200 0 0 0 0 0 SUM= 200 PCT TOT o. 100,0 O. O, O. O. O. SUM=100 PCT - I 9 -~~ i69; i4B4 0.0627 10 2097 1537 0.0603 *********************~************************************************* ·I•· *********************************************************************** · . MW ADD 1490 0 0 0 0 SUM= 1490 MW RET -583 0 0 0 0 SUM=. -583 I ****** ****** ****** ****** ****** ****** ************ I ~ 2010 1942 155 0 0 0 SUM= 2097 PCT TOT 92.6 7.4 0. O. 0. SUM= 100 PCT ****************************************************************~****** I AUTO 200 0 0 0 SUM= 200 PCT TOT 100.0 O. 0. Oo SUM= 100 PCT .·.·I. ~ { , * COMMITTED MW ' ' GENERAL ELECTRIC COMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT il· \ i 1 • t J ************************************************ I. : ; ALASKA RAILBEL T " ZERO/. -3/. ~ JOB NUMBER ~ML709 12/31/81 I *********** . . ·********************** T~TAL CAPABILITY 'I <INCLUDING TIES) LOSS OF L-8AD COST IN ' r 1 YEAR TIME OF PCT. PROBABILITY -¥E-ARLY L, ~ . -yEAR 1.-uAit ENrr--PEAK REs.----LI7Y----~H/1-COST I **** ***** ***** ***** **** ****** ****** ******* 1993 947 1373 1373 45.0 0.063 o. 171.3 . 1994 965 1542 1542 59.8 0.027 o. 194.7 I 1995 983 1495 1495 52.0 0.077 o. 201.0 1996 1003 1624 1624 61.9 0.059 o .. 250.6 1997 1023 1620 1620 58.4 0.084 o. 261.2 1998 1044 1635 1635 56.6 0.092 o. 271.6 I 1999 1064 1635 1635. 53.6 0.055 ~ o. 278.5 2000 1084 1.591 1591 46.8 0.059 o. 285.0 2001 1121 . .1661 1661 48.2 0.038 o. 296.9 11 2002 1158 1608 1608 38.9 0.062 o. 305.3 2003 1196 1625 1625 35.9 0,087 o. 320.1 2004 1233 1825 1825 48.0 0.029 o. 356.5 2005 1270 1807 1807 42.3 0.062 o. 373.1 I 2006 1323 1854 1854 40.2 0.064 o. 391.2 2007 1377 1924 1924 39.7 Ot057 o. 410.2 2008 1430 2098 2098 46.7 0.033 o. 453.3 I 2009 1484 2097 2097 41*3 0.063 o. 468.0 2010 1537 2097 2097 36.4 0.060 o. 481.8 . .. GENERAL ELECTRIC COMPANY I OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ ll; AL~SKA RAILBELT ZEIRO/. -37. JOB NUMBER 2ML709 12/31/81 **************************************** MILLION $ CUM. PW -·TOTAl: ******* 123.8 260.4 397.3 563.0 730.6 899~9 1068.4 1235.8 1405.1 1574.1 1746.2 1932.3 2121.3 2313.7 2509.6 2719.8 2'!30.5 3141.1 I I ************ LOSS OF LOAD PROBABILITY ************ EXCESS JAN• · FEB. MARCH APRIL HAY JUNE JULY AUG. SEPT. OCT. NOV. DEC. *********************************************** • ~ -<r: < MW )1 DAYS/YEAR ****** ******** .n .. ~· lll$lt!JI} - I ,, ' ; ·( \ -~ : il '·< 'I { '. ' __ J !I ,J I ; .. . \ I ~ . 'j ' . '•' I ' . . j I _,./ I I ' -: I; -~ I I __ _ I I .,. I ·; '' ' ' : :+;' :LE.RU/. -~~--~ JOB NUMBER 2ML709 12/31/81 3/,, *********** . ·***~ ******************** YEARLY $/MWH . POOL TOTAL TOTAL PEAK ENERGY LOAD COSTS ********************************** YR <MW> <GWH> FACTOR <MIL.$) INV. FUEL O+M N.I. ** ****** ******* ****** ****** ***** ***** ***** ***** 93 947 4736 57.09 171 9.31 22.43 4.43 o. 94 965 4829 57.12 195 15.31 20.35 4.67 o. 95 983 4922 57.16 201 15.02 21.11 4.71 o. 96 1003 5031 57.10 251 22.69 21.92 5.21 o. 97 1023 5141 57.37 261 22.82 22.74 5.26 o. 98 1044 5250 57.40 272 22.96 23.46 5.31 o. 99 10'64 5360 57.51 278 22.48 24+15 5.32 o. 0 1084 5469 57.44 285 22.04 24.84 5.24 .o. 1 1121 5661 57.65 297 21.89 25.26 5 •. 29 o. 2 1158 5853 57.70 305 21.17 25.76 5.23 o. 3 1196 6044 57.69 320 21.09 . 26.61 5.27 o. 4 1233 6236 57.58 356 26.27 25.06 5.83 o. 5 1270 6428 57.78 373 26.06 . 26.19 5.79 o. 6 1323 6701 57.82 391 25.56 27.01 5.80 o. 7 1377 6973 57.81 410 25.11 27.86 5.85 o. 8 f430 7246 57.69 453 29.60 26.61 6.35 o. 9 1484 7518 57.83 468 28.53 27.39 ·6.33 o. 10 1537 7791 57.86 482 27.53 28.03 6.29 o. GENERAL ELECTRIC COMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ ALASKA RAILBELT ZERO/. -3/. JOB NUMBER 2ML709 12/31/81 **************************************** TOTAL ****** 36.18 40.33 40.84 49.82 50.82 51.73 51.96 52.12 52.44 52.16 52.97 57.16 58.04 58.37 58.82 62.56 62.25 61.85 GENERATION SYSTEM TYPE 1 2 3 4 5 6 7 8 9 10 SUM 92 0 59 452 141 67 317 155 0 0 . 0 1191 ***********************************************~********************** TOTAL CAF'AB. YR Y E A R L Y P E R C E N T M I X ********************************************************************** 93 o. 18.9 32.3 10.2 4.3 23.1 11.3 o. o. o. 1373 94 o. 29.8 26.8 9.1 3.7 20.6 10.1 o. o. 0~ 1542 95 o. 30.7 26.7 8.9 2.1 21.2 10.4 o. o. o. 1495 96 o. 40.6 24.6 4.0 1.8 19.5 9.5. o. o. o. 1624 97 o. 40.7 28.8 o. 1.4 19.6 9.6 o. o. o. 1620 98 o. 40.3 29.7 o. 1.1 19.4 9.5 o. o. o. 1635 99 Oi 40.3 29.7 O. 1.1 19.4 9.5 o.. O. o. 1635 0 o. 39.8 29.4 o. 1.1 19.9 9.7 o. o. o. 1591 1 o. 38.2 32.4 o. 1.0 19.1 9.3 o. o. o. 1661 2 o. 39.4 30.3 o. o.9 19.7 9.6 o. -o·-;-__ o. 1608 3 .o. 39,0 31.o o. o.9 19.5 .9.5 o.--o-;-··-~ 1625 4 o. 45.7 2~·--o-.---o-.g··-17.4 --a-;s-----o-.· -o. -=· o. IB2s- s o. 45.0 28~5 o. 0.4 17.5 8.6 o. o. o. 1807 6 o. 43.8 30.4 o. o.3 17.1 a.4 o. o~ o. 1854 7 o. 42.3 32.9 o. 0.3 16.5 8.1 o. o. o. 1924 8 o. 48.3 28.9 o. 0.3 15.1 7.4 o. o. o. 2098 9 o. 48.3 28.9 o. 0.3 15.1 7.4 o. o. o. 2097 10 o. 48.3 28~9 O. Ot3 15.1 7.4 o. O. o. 2097 ********************************************************************** ******************************************** -t f . ' ( I I 0 G f--5 G E N E F: A 11 0 N F L A t·u·~ lr~ G t h 0 G F\1; 1 t -2 d n r1 A F.'1 i..JLn f U 1 ************************************************ ALASKA RAILBELT ZERO/. -37. JOB NUMBER 2ML7V7 12/31/81 **************************************** GENERATION SYSTEM NUKE COAL NGASGT OIL GT DIESEL COMCYC TYPES TYPE 1 2 3 4 5 6 7-10 OPTMZING 0 1993 1993 0 0 1993 *** . PCT T·RIM 0 0 0 0 0 0 .. 1992 MW 0 , 59 452 141 67 317 155 SUM= 1190 I :(··· . j *********************************************************************** TOTAL CAF'AB. Y E A R L Y M W A.D D I T I 0 N S + TIES ******* ******* ******* ******* ******* ******* ***** ****** **** 680* 1853 YR ** 93 I . :~ 1822 1774 1704 1630 1575 1575 1531 1531 96 .I :~ I I I ' '.~ I I I I I I I I ,.. ... _ 99 0 1 601* 2079 2 3 2026 -4 '!, _ 't •• • -' • • • .., ~ , • a' • -1 * 2027 5 1939 6 1* 1917 7 70* 1987 8 70* 1* 2032 9 2031 10 70* 1* 2102 *********************************************************************** *********************************************************************** MW ADD 0 0 210 0 0 0 1285 SUM= 1495 MW RET 0 -46 -335 -141 -61 0 0 SUM= -583 ****** ****** ****** ****** ****** ****** ****** **** *~********* 2010 0 13 326 0 6 317 1440 SUM= 2102 PCT TOT o. 0.6 15.5 O. 0.3 15.1 68.5 SUM=100 PCT ******************************~**************************************** AUTO Q 0 0 0 0 0 0 SUM= 0 PCT TOT o. o. O. Oe o. Q, O. SUM= 0 PCT * COMMITTED MW ~· '' t> .• ,,, -t' () • . ! ; . -. ,!, '.- I ( I • ':; ,j... I r l GENERAL ELECTRIC COMPANY f r OGP-5 GENERATION PLANNING F' R 0 GRAM·-S U ~1 H A R Y OUTPUT ?· h· I ************************************************ r i 1.· ALASKA RAILBELT tJ ~ I ZEROX -3i. ~ JOB NUMBER 2ML7V7 12/31/81 1: ·• **************************************** * •. ~ c• .,. I ,! POOL TOTAL TOTAL YEARLY $/MWH F PEAK ENERGY LOA It COSTS ********************************** ~. ....._ .... (GWH> YR <MW> FACTOR <MIL.$) If~·v. FUEL O+H N.I. TOTAL ~ f:: I ** ****** ******* ****** ·****** ***** ***** ***** ***** ****** ~"' f 93 947 4736 57.09 243 42.05 4.99 4.32 o. 51.36 ~ -:r 94 965 4829 57.12 249 41.24 5.95 4.35 o. 51.55 If !: I 95 983 4922 57.16 252 40.46 6~33 4.36 o. 51.16 ii 96 1003 5031 57.10 263 39.59 8.35 4.35 o. 52.28 t. -.... 'er' 97 1023 5141 57.37 267 38.74 8.ao 4.33 o. 51.87 :!~ w;. 98 1044 5250 57.41 271 37.94 9.43 4.34 o. 51.71 ~ ·I 99 1064 5360 57.51 277 37.16 10.11 4.39 o. 51.65 ~~ 0 1084 5469 57.44 287 36.42 11.72 4.40 o. 52.54 f 52.43 ... 1 1121 5661 57.65 297 35~ 18 12.81 4 • .44 o. ' , ·I 2 1158 6352 62~61 327 46.28 o~ 5.14 o. 51.42 .,. 3 1196 6455 61.61 345 45.54 2.66 5.23 o. 53.42 .. 4 1233 6599 60.92 328 44.55 o. 5.11 o. 49o66 •• 5 1270 6698 6~Y. 21 345 43.89 2.44 5.12 o. 51.45 ""' 6880 ~t? 36 333 42.73 0.69 s.oo o. 48.41 ·~ I 6 1323 •.. . ! ""',, . 7 1377 7079 58.69 359 42.07 3.56 5.12 o. 50.74 B 1430 7310 ~ 8 "~o ;;;.} . ' 360 41.27 2.89 5.05 o. 49.21 .I 9 1484 7551 58.08 3,80 39.96 5.28 5.11 o. 50.34 10 1537 7827 58.14 386 39.07 5.21 s.o8 o. 49.35 I ' $ . .. ! i. I J ' . I ,I 11 ·-~j I . ., ' '~ K, (\ -·' ::;a: ' IJilllil ,-·\ I GENERAL ELECTRIC COMPANY OGP-5 GENERATION PLANNING PROGRAM-SUMMARY OUTPUT ************************************************ {LASKA RAILBEL T ZEROk -3~ I JOB NUMBER 2HL7V7 12/31/81 ·*************************************** I ' ~EAR LOA II *~* ***** 1993 947 1994 965 ll995 983 1996 1003 1997 1023 ~t::~ 1044 1064 2000 1084 11)01 1121 2002 1158 2003 1196 2004 1233 12005 1270 eoo6 1323 2007 1377 coos 1430 .. 009 1484 2010 1537 I 1. I 11 I I I I I . f) TOTAL CAPABILITY (INCLUIIING TIES> YEAR TIME OF END PEAK ***** ***** 1853 1853 iB22 1822 1774 1774 1704 1704 1630 1630 1575 . 1575 1575 1575 1531 1531 1531 1531 2079 2079 2026 2026 2027 2027 1939· 1939 1917 1917 1987 1987 2032 2032 2031 2031 2102 ' 2102 PCT. RES. **** 95.7 88.8 80.5 69.9 59.4 50.8 48.0 41.2 36.6 79.5 69.4 64.4 52.7 44.9 44.3 42.1 36.9 36.8 LOSS OF LOAD PROBABILITY D/Y H/Y ****** ****** o.ooo o. o.ooo o. o.ooo o. o.ooo o. o.ooo o. 0.001 . o. 0.002 o. 0.015 o. 0.032 o • o.ooo . 0. 0.001 o. 0.001 o. 0.017 o. 0.068 o. 0.025 o. 0.029 o. 0.050 o • 0.025 o. .... ' - COST IN YEARLY COST ******* 243.3 248e9 251.8 263.0 266.7 271.5 276.8 287.3 296.8 326.6 344.9 327.7 344.6 333.1 359.2 359.8 380.1 386.3 MILLION S CUM. PW TOTAL ******* 175.7 350.3 521.8 695.7 866.9 1036.0 1203.5 1372.3 1541.6 1722.4 1907.8 2078+8 2253.4 2417.3 2588.8 2755o6 2926.8 3095 • .6 . j i . :~ I I I . I I I I I I I I I IJ I& I I I I l ITEM 5 -LOAD PROJECTIONS :1 ·1·, .. :I '.I· .. I I il I . 'l· .. ".··.· . . I I I II jl II I :I I ACRES AMERICAN ALASKA RAILBELT YEAR 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 l996 1997 1998 1999 2000. 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 INC., COLUMBIA MD., 21044 . BATTELLE MEDIUM FORECAS! <HW> <HWH> POOL PEAK TOTAL ENERGY 574. 2893000. 601. 3027000. 626. 3162000. 652. 3296000. 678. 3431000. 721. 3636000. 764. 3841000. 806. 4046000. 849. 4251000. 992. 4456000. 910. 4549000 ·• 928. 4642000 • 947. . 4 736.000. 965. 4829000. 983. 4922000. 1003. 5031000. 1023. 5141000. 1044. 525.0000. 1064. 5360000. 1084. 5469000. 1121. 5661000. 1158. 5853000. 1196. 6044000. 1233. 6236000. 1270t 6428000. 1323. 6'701000. 1377· 6973000. 1430. 7246000. . 1484. 7518C,OO ~ 1537. 7791000. - LOAD FACTOR 57.54 57.50· 57.66 s~ ~s ,,;;s 57.77 57.57 57.39 57.15 57.16 57.03 57.07 56.95 57. 09· 57.12 57.16 57.10 57.37 57.41 57.51 57. 4.4 57.65 57.70 57.69 57.58 57.78 57.82 S7.81 57.69 57.83 57"86 Item 5 r;._: r f j {) I I I I ACRES AMERICAN ALASKA RAILBELT INC., COLUMBIA Mit.~, 210..:'f4 I BATTELLE ~OW FORECAST . . YEAR I 19B1 1982 1983 1984 I 1-~ 1985 1986 1987 1988 198~- 1990 I ·I I I I. ,, I. I. (, JJ -1991 1992 1993 1994 1995 19~6 '1Cf97 1798 1999 2000 2001 2002 2003 2004 2005 2006 2007 2003 2009 2010 .. <HW> POOL PEAK 568. 586. 60S~ 623. 642. •674. 706. 738. 770. 802. 811. 821. 830. 840. 849. 863. 878. 892. 907~ 921o 950. 979. 1008. 1037. 1066. 1102. .1138. 117:1. i.209. 1245. . <MWH> TOTAL ENER'GY 2853000. 2948000. 3044000. 3139000. 3234000. 3387000. 3S~oooo•-- 36930007 .. ~. ··~-.... 3846tt00ft 3999000. 4047000 •. 4095000. 4144000. 4192000. 4240000. 4320000. 4400000. 4481000., 4561000f 4641000. 4784000. 4928000. 5071000. 5215000. 5358000. 5547000. 5736000. 5925000. 6114000. 6303000. - , LOA!I FACTOR 57.34 57.43 57.44 57.36 57.50 57.37 57.24 56.97 " -s/.02 56.92 56.97 56.78 57.00 56.97 57.01 56.99 57.21 57.35 57~40 57.37 57~49 57.46 57.43 57.25 57.38 57.46 57.54 57.50 57.73 . 57.79 1&1DC!i4414G I I I I I I I I I I I I. JOB NUMBER 1ML4VS 12/30/81 ACRES AMERICAN INC,, COLUMBIA MD., 21044 ALASKA RAILBELT BATTELLE HIGH FORECAST <HW) <MWH> YEAR POOL PEAK TOTAL ENERGY LOAD FACTOR 1981 598. 3053000. 58.28 1982 647. 3347000. 59.05 1983 696. 3642000. 59.73 1984 745. 3936000. 60.15 1985 794. 4231000. 60 t 83 1986 855. 4525000. 60.42 1987 916. 4820000. 60.07 1988 976. 5114000. 59.65 1989 1037. 5409000. 59,54 1990 1098. 5703000. 59.29 1991 1128. 5855000. 59.25 1992 1158. 6007000. 59.06 1993 1188. 6160000. 59.19 1994 1218. 6312000. 59.16 1995 1248. 6464000. 59.13 1996 ''1286. 6663000~ 58.98 1997 1324. 6861000.-59.16 1998 1363. 7060000. 59.13 1999 1401. 7259000. 59o14 2000 1439. 7457000~ 58.99 2001 1505. 7795000. 59.13 2002 1571. 8133000. 59.10 2003 1637. 8472000~ 59.08 2004 1703. 8810000. 58.89 2005 1769. 9148000. 59.03 2006 1848. 9605000. 59.33 2007 1927. 10063000. 59.61 2008 2007. 10520000. 59.67 I . 2009 2086. 10978~ 60.08 ___ .,....;..-"'20i0-"A" __....__. ....... :.....;. ._!, .... "2165 .of -·~ ........ 11'435000 ; .... ~..,. ......... -.-60'. 29 • < • '~• I I. I I. I. (\ t ' t f I I' I· I I I I I I. ~~ I I I I I I. I. I I ·~ ITEM 6 -SUMMARY -GE OGP MODEL I Item 6 ----t(.'£!i I \WJ} ELECTRIC UTILITY SYSTEMS ENGINEERING DEPARTMENT I I I I I I I I :1 :1 I ,J I I I ,I OPTIMIZED GENERATION PLANNING PROGRAM . ' PROGRAM DESCRIPTION : :. GENERAL ELECTRIC COh·1PAr-JY 1 RIVER ROAD SCHENECTADY. N.Y. 12345 - , .. MARCH 1979 .. . I I I I I I I I I I I I I Table of Contents OPTI~HZED GENERATION PLANNING {OGP) PROGRAM • • • • • • Reliability Evaluation • • • • • • • • • • .. • • • Production Simulation . , • • o • • • • .. .. • • .. Purchases and Sales • • • • • • • • : . .. • • Conventional Hydro Scheduling . • • • • • o • Thermal Unit Maintenance • • • • • • • • • • Energy Storage Scheduling • • • • • • • • • • Thermal Unit CommiL~ent •••••••••• ~ Thermal Unit Dispatch • • . . • • • . • • • • Fuel and Energy Limitations • Q • • • •• Investment Costing • • • • • • • • • • • • • • . • OGP Optimization Procedure • • • • • • • . • • • • Sample Output Results . • • • • . . . • . • • • • FINP..NCIAL SIMULATION PROGRAM (FSP) 0 • • • • • • • • • Introduction • . . • • • • .. • • • • . . .. • • . • !1odel Structure .. .. . • • • • • • • • • • • . • • Capital Expenditures ............ . Generation Projects • • • . • • • • • • Transmission, Distribution and ·Miscellaneous Plant •••••••• Investment Credits • • • • • • • • .. • • Plant Retirement .. • • • • • • • • • • • .. • Depreciation • • .. • • • • • • • • • o • • • Revenue • • • • • . • • • .. • • • • .. . • • • Expenses • • • . . • • • • • • • • . • • • • Financial Planning • • • • • 5 .. • • • • .. • Cash Management and Accounting • • • • • • • Income Taxes . . • • • • • . . . o • • • $ • Rate Regulation • • • • • • • • . . . • • • • Sample Output Results .••••..••••••• ·- Page 1 1 5 5 6 6 6 7 9 9 10 10 12 18 18 18 18 21 21 21 21 21 22 22 22 23 23 23 24 ~ t - I; '! [ t; I I I ' I I ! I I I I I I I I I I c ,· OPTIMIZED GENERATION PLANNING (OGP) PROGRk~ The OGP program was developed over ten years ago to combine the three main elements of gensration expansion planning (system reliability, operating and investment costs) and automate generation addition decision analysis. The first calculation in selecting the generating capacity to install in a future year is the reliability evaluation using either percent installed reserves or loss- of-load probability (LOLP). This answers the questions of 11 how much" capacity to add and "when" it should be in- stalled. A production costing simulation is also done to determine the operating costs for the generating system with the given unit additions. Finally, an investment cost analysis of the capital costs of the unit additions is perforrnede The operating and investment costs help to answer the question of "what kind" of generation to add to the system. The next three sections review the elements of these c9mputations. Reliability Evaluation Historically, electric utility system planners measured generation system reliability with a percent reserves index. This planning design criterion compared the total installed generating capacity to the annual peak load demand. How- ever, this approach proved to be a relatively insensitive indicator of system reliability, particularly when comparing alte~-native units whose size and forced outage rate varied. Since its ir:. ::reduction in 1946, the measure that has gradually gained widest acceptance in the industry is the "loss-of-load probability." The LOLP method is a probabi- listic determination of the expected number of days per year on which t...l).e demand exceeds the available capacity. It factors into the reliability calculation. the forced and planned outage rates of the units on the system as well as their sizes. Computing LOLP requires an identification of all outaga events possible (in a system with n units, this means 2 events) and then a determination of the probability of each outage event~ However, since LOLP is concerned with system capacity outages and not so much with particular unit out- ages, the probability of a given total amount of capacity on outage is calculated. This information can be presented as a H cumulat.i ve capacity outage table" c:ts shown in Figure 1 .. -1- I ~· ,; ft, ~ ; I I I a I a a I Q =j I a I a 1.0 0.1 CUMULATIVE PROBAB1LITY OF MW OR MORE ON 0.01 OUTAGE 0.0001 ,;•.-.... !i TOTAL INSTALLED CAPACITY O.OOOOIL---------------------------------~ MW CAPACITY OR MORE ON OUTAGE Figure 1. Cumulative Capacity Outage Table [cAPACITY MODEL) OUTAGE CUMULATIVE . . OR GREATER PROBABILITY MW 0 MW 10 20 30 40 50 LOLP 1.0000 0.6342 0. 37 19 0.2463 0. 19 86 4--, ' ' ) ·I I I I I t -L PROBABILITIES INSTALLEti CAPACITY HOURLY LOADS HOURS Figure 2. LOLP Calculation Procedure -2- - ONE YEAR I • ~ Q ' i I ~' l I W·"~ i l PI! •• Fl1 w Utilizing a highly efficient recursive computer technique, these capacity outage tables are calculated directly from a list of unit ratings and forced outage rates. The LOLP for a particular hour is calculated based on the demand and installed capacity for that hour. The re- serves are given by capacity minus demand. On this basis, a deficiency in available capacity (i.e., loss of load) occurs if the capacity on forced outage exceeds the reserves. The probability of this happening is read directly from the cumulative outage table and is the LOLP for a single hour as shown in Figure 2. In addition to calculating the percent installed re- serves, OGP can also calculate a daily LOLP (days/year) and an hourly value {hours/year). The daily LOLP is determined by summing the probabilities o£ not meeting the peak demand for each weekday in the year. The hourly LOLP is calculated by summing the probabilities of not meeting the load for all the hours in the year.. These two values are not related by a factor of 24 because a deficiency for the peak hour of the day does not necessarily imply a deficiency for the entire day. The discussion above proceeded on the assumption that the hourly demand was specified deterministically. The in- clusion of load forecasting uncertainty can also be impor- tant and has be5=n integrated into the OGP computational procedure. At each demand point in tlie uncertainty distri- bution, the LO{..J? is calc"Q.lated. The equivalent ·is then determined by weighting the LOLP result at each demand point by the probability distribution value. Utilizing this technique, generation planners can design the generation system to a specified level of relia- bility. As the demand grows through time, generation addi- tions are automatically timed by OGP such that the LOLP does not exceed the design criterion. Figure 3 plots LOLP versus the annual peak load for a specific generation system. As the graph indicates, LOLP varies exponentially with load changes. The design cri- terion in this case is 0.1 days/year.. For the 1985 peak load indicated on the graph, the generation system is at a level of reliability better than 0.1 days/year. Therefore, no additional capacity is required. In 1986, the annual peak has increased to a point where the generation system cannot maintain the desired 0.1 days/ year LOLP. In anticipation of this, a unit addition would ' ~3 .. t I I ; ' ' ' I I I ' ' I a I" ' a I I a;- lr c:t lLJ )- ' 10.0 1.0 U') • ~ I ~ ..J 0 ..J ..J <l ;::) z z <t !0.10 0.01 t ORIGINAL S'fSTEM I I .t 1985 1986 ; WITH 1986 UNIT ADDITION DESIGN ----- CRITERION o.oor~---------------------------- ANNUAL PEAK LOAO-M\V Figure 3. LOLP vs. Annual Peak Load -4- - . . 420 C:1. i ! .g1 ·.} i C: \ . ' c R ~tf, ~~ ~· be scheduled for 1986. What happens to the LOLP versus peak load curve? With the new unit addition installed, the curve shifts to the right as in Figure 3. In 1986, the LOLP has de- creased from 1. 0 daysjyear to about 0. OS days/year because of the uni~ addition. This is below the desired 0.1 days/ year criterion established by the utility system planner and hence the unit addition process is completed in that year. Production Simulation Once a system with sufficient generating capacity has been determined by the reliability evaluation, the fuel and related operating and maintenance (O&M) costs of the system must be calculated. OGP does this by an hourly simulation of system operation. The program commits and dispatches generation based on economics· so as to minimize costs 0 • However, the user has the option of biasing or overriding the no:nn.al economic operation of the system. This can be accomplished in two ways. The user may specify weighting factors for various environmentally related quanti ties such that the program will operate those units to minimize their impact. The user mcty also limit, on a monthly basis, the nurnber of hours that units may run or the amounts of different fuels that may be consumed .. The production simulation in OGP is performed in six steps: load modification based on recognition of contrac- tual purchases and sales; conventional h:xTdro scheduling and its· associated load modification; monthly thermal unit maintenance scheduling based on planned outage rates; pumped storage hydro or other energy storage scheduling; thermal unit comrni tment for the remaining loads based on economics and/or environmental factors, spinning reserve rules, and unit cycling capabilities; and unit dispatch based on incre- mental production costs and environmental emissions. The production simulation is for a single utility system or nool. Unrestrained power transfer capability is assumed between aLeas or companies internal to the pool represented. Purchases and Sales The OGP production cost load model is an hour-by-hour model of a typical weekday and weekend day for each month, arranged in monotonically decreasing order. These hourly loads are modified to reflect the firm purchases and sales between the area being studied and entities outside that -s- -. c c 11 ' \ ~ area. Each contract has associated wi~h it a demand charge . ( $/kW/yr) and an energy charge ( $/MWh). Conventional Hydro Scheduling Hydro energy generally has a very small incremental variable cost and, therefore, in OGP it is used as much as possible so as to minimize system operating costs. There are two types of conventional hydro.. First, run of river hydro is typically an installation which has a low head and minimal storage. These units tend to be base loaded since. the river and dam characteristics dictate that the unit must be running most of the time. The second form of convention- al hydro is pondage hydro, -characterized by a significant volume of storage. · J.:>ondage hydro units are usually sche- duled during peak load time periods because it is during these periods that the system's incremental fuel cost is at its highest. Thus, the pondage hydro is scheduled to shave peaks. In scheduling conventional hydro, attention must be given to the fact that hydro capability is affected by seasonal conditions. This is handled in OGP by specifyin~J data on a monthly basis. · Thermal Unit Maintenance On a utility system, the planned maintenance of indi- vidual units is usually performed on a monthly basis. t>uring these periods, the units are unavailable for ene~~.f production. Maintenance scheduling is normally done so as to minimize the effect on both system reliability and system operating costs. A common ·strategy for scheduling main- tenance, and the method used in OGP, is the levelized re- serves approach. Basically, t...'he monthly peak loads are examined throughout the year and incremental amounts of generating capacity maintenance scheduled to try and level- ize the peak load plus capacity on maintenance throughout the year .. Increased maintenance levels which might be required during the first few years of a unit's operation are modeled using an immaturity multiplier. OGP also allows the user to annually input a predetermined maintenance schedule for units for which this information is available. Energy Storage Scheduling Although very often applied to studies of pumped stor- age hydro, OGP may also be used to study other types of energy storage on electric utility systems such as bat- teries, thermal storage, and compressed air storage. - I I t ~-···· ~ I ... n n ·a n ~ 0 c a. f1 IJ fl u fl i.rii Recognizing losses in the cycle, generating and charg- ing energy is scheduled to maximize the savings in sy&tem production costs on a weekly basis.. ·Energy storage units are assumed to be fully charged at the beginning of ·the week. Incremental amounts of generation are balanced by enough charging to fully recharge the·unit by the start of the next week. Becar~s~ of the nonlinearity in system oper- ating costs, the energy storage units can operate so as to decrease costs despite a cycle efficiency less than 100%. Thermal Unit Commitment After modifications for contracts, hydro, unit main- tenance, and energy storage, the remaining loads must be served by the thermal units on the system. In OGP, the units can be committed to minimize either the operating costs, as is usually done, or some combination of user specified environmental factors and operating costs. The operating costs are calculated from the fuel and variable O&M costs and input-output curve for each unit. Fixed O&M costs do not effect the order in which units are committed, but are included in the total production cost. Figure 4 illustrates the type of input-output represen- tation used by OGP to model the thermal characteristics of generating units. This model specifies the fuel input in Btu per hour as a function of the electric power output in megawat.ts. H.owever, performance economics are dictated not only by the heat input but also the price ($/MBtu) of the fuel used by the generating unit. Therefore, the cost characteristic relating fuel cost per hour to power output is simply the product of the heat input characteristic and the fuel price. In addition to the fuel input versus power output specification, the maximum and minimum output are specified as operating limits. The environmental qu~~tities that OGP can factor into the operation of the system along with the operating costs are: heat rejection into the atmosphere, heat rejection into the cooling medium, SO emissions, NO emissions, CO emissions, particulate emis~ionsv and wat~r consumption. Figure 5 shows that these characteristics are modeled much like the unit heat rate. The unit comrni tment logic determineS! how many units will be on-line each hour and also attempts to provide an adequate level of operating reliability while minimizing the system operating costs and/or environmental emissions. The operating reliability requirement is met by committing sufficient generation to meet the loa~ plus a user specified -7- 1 t .. . \ "· • " ' . . t--v J ·I:. v ... ~ .. ~ , • ~ /r;r 1,' . l. ·I'. t •• , .• .rGI I , "to... • . . . • . : .;: . f / ~·· I ~ !:1 a . ., '=.: '" . ' l g t::::::1 Jt:::i ~:::,;;; JE:.J rll IC:I &:::1 ~ K::l £:]" ! co I i FUEL INPUT (,;u) .MINIMUM i . INCREMENTAL FUEL INPUT (MDtll) 'Rfnl I I I ! 'MAX! MUM LJ MW OOTPUT i FUEL INPUT <k> I i INCREMENTAL FUEL INPUT ( $ -) MWh Figure 4. Generating Unit Input-Output Rep~esentation BL:l --.........,.-~:;;us,;; ?4tH ;: ~ ,... .... "" i-1 A %, W 0' f" F.-~ .... ,~-~; K:::l Ed g;;( ... ·. . . . i EMISSIONS (lba) nr- I . r I INCREMENTAL EMISS~ONS <~~K> MINIMUM ~ ~ . it~l. /1 / /I I . I I I I I ' I I I I iCf. ~: 'MJ\XIMUM ' MW OOTPUT Figure 5. Generating Unit Emissions Output Representation '-' ~ . . ... D D 0 . spinning reserve margin,, Units are committed in order of their full load energy costs or emissions, starting with the least expensive. This conuni trnent is then reviewed to determine if the thermal cycling capability of any units is being violated. If so, this preliminary commitment will be modified to keep such units on line as may be dictated by their cycling restrictions. . , Thennal Unit Dispatch If a unit is committed, the unit's m1n1murn loading level requires that its output be at that level or higher. When the final commitment has been established, each unit will be loaded to at least it's minimum. Typically the sum of the minimums does not equal the load. Additional load will be serVed by the units' incremental loading sections. The dispatching function in the OGP production simulation loads the incremental sections of the units committed in a ma_nner which serves the demand at minimum system fuel cost or emissions. This dispatch technique is the equal incre- mental cost approach. Figures 4 and 5 also show the incremental fuel cost and enviro1mental emissions models used in dispatching the incremental loading sections to serve the load. OGP can model the forced outages of units either deter- ministically, by extending the planned maintenance period, or stochastically. In the .stochastic dispatch, the program recognizes that units will be out of service in each zone of constant commitment for a period of time proportional to the forced outage rate. The load previously served by these units will be transferred to higher cost units. This usual- ly requires the commitment of additional generating units. If additional units are not available, emergency tie ener~I will be supplied a·t a cost input by the user. Fuel and Energy Limit~ti~ps OGP ·has the option of performing ·the production simula- tion subject to additional constraints. The amount of energy to be generated each month by each unit or the quan- ti ties of the different fuels consumed in a month may be limited. If any limits are reached, other~ less economic units will be cornrni tted and dispatched as needed. -9- ,,, iiiMii ; I I I o: Q Q u D D Investment Costing The investment cost analysis in OGP calculates the annual carrying charges for each generating unit added to the system. This is computed based on a $/kW installed cost, a kW nameplate rating, and an annual levelized fi~ed charge rate. · OGP Optimization Procedure Figure 6 outlines the procedure used by OGP to deter ..... mine an optimum generation expansion plan. . For the year under study, a reliability evaluation is. performed. This determines the need for additional generat- ing capacity. If the capacity is sufficient, the program ' calculates the annual production and investment costs, prints these values, and proceeds to the next year. If' additional capacity is needed, the program wili add units from a list of available additions until ~~e relia- bility index is met. This list can contain up to six ther- mal types and three types of energy storage units. These units can be added both by themselves and in combinations with other types of generation. · For each combination of units added to the system, OGP does a production simulation and investment cost calculation for the year under study. The program uses the information gained from the cost calculations to logically step through the different combinations of units to add, eliminating from consideration combinations that would produce higher annual costs than previously found. This process continues until the expansion giving the lowest annual costs is found~ The selected units are added to the system, and the program proceeds to the next year of the study • • In cases where operating cost inflation and/or tim~~ variation in unit outage rates' are present, the OGP optimi-. zation logic utilizes a 11 look-ahead 11 feature. The look- ahead feature develops levelized fuel and .o&M costs and mature outage rates for use in the economic evaluation. As part of the output information available, t.he user obtains documentation of the relative costs of all the alternatives examined. Afte:r the generating unit selection, the reli-- ability and costing calculations are repeated for t.he chosen alternative so that the expansion report available for the user contains the correct annual values. -10- . ' 4-: .. ~"r:··--·t··---,~~-----:"~-·-·--···•···~ .......... _ ..... ---····--·· " ............... ~--·---. -·---.. ----~;-,.-~--~ -----~~) r---:-. I * --! t .•• --·~ t :\ ;we: ~~---Fo_~-~-~-~_s_T __ ~] ~---~G-E~~~~~:~;~;~~~o~N~ __ ]I ~------s~~~-~_J ____ ~ EXISTING UNITS & ALLOWABLE TECHNOLOGIES HOURLY BASED PEAKS & ENERGIES FUTURE ECONOMICS & OPERATING GUIDELINES ---· . ~ ....... -.• .. . . ·• -~-~ . ·---=-·"""-.:.:;;;,;;;;; I OPTIMIZED GENERATION PLANNING (OGP) . ' .. --_._,_ -· ., . ~' --·'~""-' .. -..... . EVALUATE RELIABILITY m lt:d r-----------'W EVALUATE ALL CHOICES U VVITH ""LOOK·AHEAD" I t .. SELECT UNIT SIZES & TYPES ! CALCULATE OPERATING & INVESTMENT COSTS USING ULOOK-AHEAD" ~ -~ CHOOSE LOWEST COST ADDITIONS & CALCULATE CURRENT YEAR'S COSTS : ~-.. . ... RESULTANT OPTIMUM EXPANSION PATTERN & DOCUMENTATION OF NEAR-OPTIMUM PLANS l _ _.. "-·15 • ~ . J STUDY ALL YEARS -----OUTPUT FINANCIAL ANALYSIS OF EXPANSION PLAN 1----OUTPUT D D 0 D D 0 D Figure 6. Optimized Generation Planning (OGP) Program r! u 0 -11- - D D D 0 D D D 0 D 0 D 0 Sample Output Results The "bottom linen result from the OGP program is the annual summary of additions. Figures 7 and 8 present the annual capacity additions by type {nuclear, coal, gas tur- bine, etc.}. For example, in year 1995, the· OGP program added in this sample run one 1300 MW nuclear unit and two 300 MW blocks of gas turbines as '-tell as 500 MW of pumped storage hydro. The generating units indicated with an asterisk ( *) are those units which have been previously committed for service. For example, in 1984, a 1200 MW. nuclear unit and a 500 MW battery storage unit are conunitted for service. At the bottom of the additions report, a summary is provided. The first row is the sum of megawatt additions and retirements (MW ADD and HW RET) during the period. The second row is the capacity in service in 1998 (end of the study). The third row is the MW additions that were added automatically (AUTO) by the OGP program (total additions less comrni·tted additions) .. Other summaries are also provided by the program. Figure 9 p~esents the load, capacity, reserve, LOLP and cost summary. Figure 10 presents a more detailed cost summary both on a yearly basis and also on a cumulative present worth basis. OGP also makes available more detailed yearly and even monthly results. One of these results is illustrated in Figure 11. This is the annual production cost summary and illustrates the annual history of each generating unit's maintenance period, hours on line, capacity factor, ftiel cost, etc. At the bottom of the page, the energy output, capacity factor, and fuel cost results are summarized ~y generating plant type (nuclear, coal, gas turbine, etc.). Other summaries are also available. including annual fuel consumption by fuel type (nuclear, coal, oil #2, oil #6, natural gas, etc.), and annual environmental summaries (water consumption, so 2 , and NOx emrnissions, etc.). While these swnrnaries are output, a complete printout would ing of the input paraJneters and information. -12- - examples of OGP program include a formatted list- other useful displays of .. -- ..-: d 0 0 D 0 D 0 0 0 0 0 0 0 GENE~AL E!,ECTRIC COMPANY OGP-5 GENERATlON ~LAN~JNG PROGRAM-SUMMARY OUTPUT ZSX2%allts•z~:=x~~2~7x:~xz~:~zx~zxx~~xx•zxxx:zz~• OGP-5 ELECTRIC SYSTEM USERS MANIJ.~I-f!XAI1?LE JOB NUMBER 24939S 03/14/79 GC:NERATJ ON SYSTEM NUCL. F-COAL G.T. TYPE 1 2 3 O?Tt"iZ l.NG 1 989 19C7 1979 PCT TRIM 2~ 25 0 1978 MW 5005 4781 702 YR y EARL'' M li:S li:%%XZX:I: ::z:::::l::i::xs: :z::z:xlr.liCZ 79 225• 2X 150 80 1200• 2X 150 81 750• 2X 150 82 , 200• 83 1200:& 1X 150 84 1200:& 85 as 87 2X 300 as 89 1X 300 90 1X 300 91 2X1300 92 2X1300 93 3X 300 94 1X 300 9t5 1X1300 2X 300 96 2X1300 2X 300 97 1X1300 1X 300 98 2Xi300 2X 300 STAB C-COAL F-OIL TYPES ·4 5 6 7-10 1954 1984 1987 lkll:llf 25 25 25 600 300 4792 934 SUt-1= 17114 TOTAL CP.PAB. w A 0 0 I T J 0 N S + TIES Xli:'ZXli:lfll: x:~~:xxxx:r ll:x::x:r:li::a ::::..ll:C =«•==:rz xxxa 18367 19844 2080.S 400• 22289 23514 500:r 25214 500 25534 500:r 500 26554 600 27609 1300 28778 2X 400 500 30378 3X 400 100 31863 34~48 3€.i348 3('!) 37902 3X 400 300 39410 500 41647 100 4-"S27 1X 400 300 46777 100 49761 Xll:l!:XXXlkZ~ZZZZZ2~Z~ZSZZZ:~z=z~zzzxzzzz~liCZZZZZZ~%*ZZZ2XZ::I:X%Z%ZZZ~X~ZZZZ~S **~***~•~=zz:zxzz~•~xxz~zzz~z~zx:r:xz~~~•••zxzzzazzz:rz~::::ll::x~:rzz:~==zzzzz MW ADO 7400 11375 5550 4000 0 0 6100 SUM= 34~25 M'W RET 0 -1-455 0 0 0 -1373 0 SUf1= -2828 lk%Zllell:& li:Zli:Zlkll: Zli:JitXlltlE lJZZZ:t:lt **~•*• zxzzz:a **•••• Z::I:ZX :s::r:e:~==zxz:alit 1998 12405 1470l 6252 4600 300 3419 7034 SUt•i= 4871, PCT TOT 25.5 30.2 12.8 9.-4 0.6 7.0 14.4 Sllt1-= 1 00 PCT zz~~***********=xz::rz:xxz~zzxzzzzz:rxzzz:rzzxzz==•••***=z~~~•===•~~•***** AUTO 2600 10400 5550 3600 0 0 5100 SUM= 27250 PCT TOT 9.5 38.2 20.4 13.2 o. 0. 18.7 SlJM::100 PCT z COt-1M I TTED MW Figure 7. Annual Capacity Additions by Type ··13- ,. 0 D 0 0 0 0 0 fl u 0 0 GENERAL ELECTRIC COMPANY OGP-~ GE~ERATJOH PLANNJNG PROGRAM-SUMMARY OUTPUT tx~~••x1x:sxx~~~-~-•~~-2~~~~=••••xxxxx~xx:xxxxtx OGP-~ ELECTRJC SYSTEM USERS MANIJ.~.L EXAf'l?LE JCB NUMBER 2d939S 03/14/79 GENERATICJN SYSTEM THERMAL HYDRO PSH TYPE 1-6 1 8 OPTMZING ••• 1984 PCT TRlH 0 1978 MW 161SO 310 624 VR Y E A R L V M W A xlk lt:t::t::xs: li:Xll::::lt• S::t::li:S:X:Z 79 525 80 1500 81 1050 82 1600 83 1350 84 1200 85 ~X 100 86 5X 100 87 600 6X 100 sa t3X 100 89 1, 00 5X 100 90 1500 1X 100 91 2600 92 2500 93 900 3)( 100 94 1500 3X 100 95 1900 5X 100 96 3200 1X 100 97 2000 3X 100 96 3200 1X 100 BATRES COMPAR g 10 1984 1984 0 0 0 0 SUM :a 17114 TOTAL CAPAB. LOAD 0 0 l T I 0 N S +TIES MW Xli:Xlllllk XliXXXlk x::::xx:~:s: x=~•• 18367 14091 19844 14656 20604 15684 222£9 16546 23514 17456 500z 25214 18416 2558..:! 19-129 so oz. 2Goa4 20498 27509 21625 28778 22814 30378 2406S 31'363 25393 34348 25790 36848 28263 37902 29818 39410 31453 41647 33188 44627 35013 46777 3(;939 49761 38970 . LOLP 0/Y ll::l:XXliOt• 0.4153 0.3813 0. 4021 0.3362 o. 4551 0. 2454 0.-4728 C.4290 0.~926 O • .t!S30 . 0.3~91 0.3360 0.4140 0.3910 0.470~ 0.46Et5 0.4498 0.4217 o. 4551 0.4303 zxxxxxxz~:x:xx::x*xxzxx:a::xx~==~*=•xxxsx:::x:a::xx~xzzsz:::xxxx~~%xz~xx~~=~:x~zs: xxss:xxxx:x:xxxzxz~xzxxx::::x:::x~zz:zxxxxxxx~xsxx:zzxxftsxxx~xxx~x:r:::x::xx MW ADD 28325 MW RET -2828 XZXXZJI[ Slt%Xlt2' 1998 41677 PCT TOT 85.6 AUTO 22150 PCT TOT 81.3 • C0?-1Ml TTED MW 0 0 z:r.~x:ts 310 0.6 Figure 8. 5100 0 lt)l(ltltltl: 5724 11.8 5100 16.7 500 0 Xltllll:ltJI 500 1. 0 0 o. 500 SUM= 344~5 0 SUM= -2828 lt::tltlt%lt ZXlt%%lt%~%li:Zlt 500 SUM= 48711 1.0 sur-1:: 100 PCT 0 SUM= 27250 0. SUM= 100 PCT Annual Capacity Acditions by Type -14- - . . .. n tJ G 0 0 0 0 0 0 0 0 0 0 GENERAL ELECTRJC COMPANY OGP-5 GENt:~AT 1 ON PLANNl NG PROGRAt1-SUt.,f1ARY OUTPUT ~~~zx«xxxxxxx~•~xx:~x•~•••••=~•x:xxxx**•~=•~~••• OGP-~ ELECTRIC SYSTEM USr;:Rs 1"1ANUAL EXAMPLE JOB NU!1SER 24939$ 03/14/79 ••~=:xx:2x~~~xzs::z:•xx::zxxx•~••~xxzxxs ---- TOTAL CAPABILITY CINCLUOING TlESl LOSS OF LOAD COST IN MILLION S YEAR TIME OF PCT. PROBABILITY YEARLY CUM. PW YEAR LOAD END PEAK RSS • DIY H/Y COST TOTAL •••• s:a:x:a:s :I::C1t:kS Sli::'Xt scz:e: szx:::xs XSZ1t:ZS J::ltx:::xss 'Xx:r:xt 1979 14091 18422 18367 30.3 0.415 0.53 1207.9 l098.0 1980 14866 19884 19844 33.5 0.381 0.48 1547.0 2:376.5 1961 15Ci84 20544 20S04 ~2.6 0.402 0.51 1827.6 3749.6 1982 16546 22'329 22289 34.7 0.336 0.42 2236.2 5277.0 1983 17456 23'354 23514 34.7 0.455 0.58 2£52.9 6924.2 1984 184\6 25254 25214 36.S 0.245 0. 31 3146.7 8700.4 1985 1S429 25624 25584 31.7 0.473 0.59 33!:18.3 10444.2 1986 20498 26524 ·26584 29.7 0.429 0.52 3754.7 12iss.s 1987 21625 27649 27609 27.7 0.493 0.58 41 B4. 1 13970.3 1988 22814 28S18 28776 26. 1 0.483 0.56 4731.0 15794.4 1989 24069 30418 30378 26.2 0.339 0.36 5:::l64.5 1767-L 6 1990 25~93 31903 31863 25.!5 0,33S 0.37 6099.1 19613.0 1991 26790 34388 34::48 28.2 0.414 0.47 7233., 21713.2 .1992 28263 36S88 36648 30.4 0.391 0.45 8:391.6 23922.9 1993 29a1e 37942 37902 27.1 0.478 0.54 930S.6 26151.3 1994 31458 39450 39410 2~.3 0.470 0.52 1 04SJ. a 28·~27 .. 7 1995 33188 41687 41647 25.~ 0.450 0.49 120?3.4 30~06.5 1996 35013 44667 44€27 27.5 0.4122 0.46 137f-0.1 3~281.4 1997 36939 46817 46777 26.6 0.455 0.50 155'77.~ 3e>S28.4 1998 38970 49801 49761 27.7 0.430 0.47 17F95.6 ~8~58 .. 7 Figure 9. Summary of Load, Capacity, Reserve, ·LOLP, and Cost -15- . . . ' ~~[·-~{~~~~~~~~~~~[~~~~ 1 ~-~ .-1 __ J ___ j L_.-.-J L....::.-J L __ _j L-. ....J 1.~ L...,...__._1 L-.. J L_____....J _ • .......J t_ _ _j ~ L--» ~ENERAL ELECTRIC COMPANY. OGP-5 GENERATION PLANNING PROGRAM PAGE . 78 .l bGP·~ ELECTRIC SYSTEM 24939$ ~ -~ ~SERS MANU~L EXAMPLE 03/14/79 I ------ YEARLY COSTS CMILLION $) YEARLY COSTS C$/MWHl l ~EAR POOL PEAK <MW> TOTAL ENERGY ( G\-IH) LOAD FACTOR ···························~~··············· ~-···~················-················· ' INVEST. FUEL O+M NUC 1 NV TtlTAL · ~·~=·----·7·~*=·=·~~---·~·=·~*=*=·7·-·~·---·~·~~-·~~~·~·---·-·-·~~~·~·~·~-·-·~·~·~·~·~·~-·~·~·~·~·~·~·~---·~·~·~·~·~·~~--~·-·7·~·~*~·~·~· ,1979 1~091. 74061.4 60.00 24.5 997,0 156,2 30.0 1207.8 l900 14866. 78348.9 60100 24611 ~08~.0 176,2 39.6 1547.0 ~961 10684. 82432.~ 60,00 364.4 1228,3 192.7 42,2 1827.6 ~~~2 105~6. 8696~0 60,00 633,8 1333.6 21510 5317 2236.2 ~9~3 174"G· 91749.6 60.00 896.0 1451.2 239,2 06,4 2652,9 1904 10416, 91061,3 60,00 1235~2 HiG313 2G7,5 00~6 3t~G.7 p1Hnl 191lf!9, 10?.1?.0,2 60,00 . 1272,6 1759~1 200,6' 85,8 3!396.3 ~906 20498. 101735,4 60,00 l35217 2012.7 ?.97,9 9114 3754.7 ~907 21625, ll3G62.2 60100 1427,0 2345.2 313~9 97,4 4184~1 ~900. 228141 12024116 60.00 1539.8 2754.4 33314 103.7 4731,!) {1989 2·!10691 12G500.G 60.00 1077.1 3214.2 362.8 110.4 ~364,5 b990· ~53q3, 133466.2 60,00 1827.9 3756.4 39712 117.6 6099.1 11991 26790, 140UOG.2 60,00 ?.4!35,3 4229,4 44!3.a 125~3 7233~1 11992 20?.63~ 140950,2 GO~OO 3050~10 4711~3 49013 133,4 Ot\01.0 p993 29018, 1~6722.0 oo.oo 31~5.2 ~490,7 530.6 1~2.1 9308.0· :1994 31450. 1vfi341,3 6o~oo 3352.2 6381,1 !575.2 151.3 10459.8 ... _..._~ 33lOO. 1741134~9 GO,OO 402&~5 7173.2 639,2 182,5 12023.4 I I 3!\013; 184533.4 60,00 4006.8 7990,0 706,9 194,4 13700,1 Il l r-a 369391 1 g .. 1150~ G 60,00 ~G42, G 8920,6 78.:3, 1 231,2 'i 5~77, 6 m , 30970. 204828.5 so.oo 6503.5 10005.~ 860,3 245.3 17695.6 I CUMULATIVE PRESENT WORTH <MILLION S) ·····*·····-··········~··~·················· YEA_R 1 NVEST. FllEL O+M NUC I NV TOTAL • • • • - - - -----.. -< < ----- -• •-• ---·-- ---•• -· ·--~ • ·-• ... • ·- 1979 1900 1901 l!J02 1903 1904 t 90~ ~"'ftJI;;.I 1 I V'•C.V t I I ....,C-W. '-" L'-•,;-, • ~ I U'-"1-"'~ t &.. 19£\0 -·------··-· -----·-·--- 1907 1900 '-----=-1-=909 ......... ,., ••• ,...,-,-• .....,.,, '""""'•" _,L., • ..J .,. ..... ..,.- -l 9!)0 --"-----. -• 1991 1992 '!"-'" __ 1!.Hl3 .. 199·1 1995 199G 19!l7 ! I • ' 1908 J NV. ···~** 0.3 3. 1 4,4 7.3 9,8 1217 . 12,5 j_2.G 12.6 12.8 13,3 13.7 17.3 . 20, 5• 20. 1 20,3 2311 20.4 29. 1 32.1 FUEL CHI"t N. I. TOTAL **-•**)!( •••••• *****-:l ***lt*:tt* 13.~ 2. 1 0,4 16,3 1318 .2.2 0.5 19.7 1.:l,9 2.3 0.5 22.2 15,3 2.5 0.6 25.7 HS,8 2.6 0,7 28,9 16 I t 2.0 0,8 32,4 1712 2.7 o,8 33,3 1817 2.8 0,8 34.9 20,6 ~.8 019 3G.e' 2219 2.6 019 39.3 25.4 2.9 0,9 42.4 201 t 3.0 0,9 45.7 30,0 3. 1 019 51.4 31, G 3.3 019 !56,3 35.0 3.4 019 59,4 30,6 3.5 0.9 63.3 41.1 317 . 1 I 0 68.9 4:)13 3,8 1 • 1 74,6 I 45,9 4.0 1.2 80.2 48.8 4.2 1.2 8G.4 ~ L,_..:.:.J ~ I I ~~=-----~--------------------~-Figure 10. Detailed Summary of Costs ., __________________________ __ ------------------------------a.----~--------------L-~----~ .......... .a .... .a ............ ~~ .. --~~--~ 1 • • -• l; l t I ! ' l !" [ j' r ,, J I ' . i ·'" .,-. -"-m-,;r.,,_,,..,_,..,-""·~-~·•ft'=""';o~'~e~-1'..;,:;..;.:-r·"~.,.'"i~:~:>-~..,-:.'fi'"l 41 ::;::_1:~--~ M ..., I ~ ~~~-r~~~E~•~A~L~E~L~E~C~i~~~I~C~~~-w~·~P~~~N~Y~,-=C=Q~P-·=~--=G=E~N=E~q~~~T~lC=N~P~L~~~~~N~I~N~G~P~R~=~3~R~A~~~--------------------------=P~A~G=E----------~3~A~------------------------­ ~GP~~ ELECTRIC SYST~ USERS MAN~AL EXAMPLE CPTlHUI'1 G.T. PSH 258~~ Dl/Z~/78 1957 YEARLY PROPUCTION COST SUMMARY cesTS IN THOUSANDS Or DOLLARS TERRI TORY P"EAK ll SPINNING RESERVE 2162~. MW 1200. 1'1\i THERI'IAL PEAK 180~0. ,....., ~~u~"k~lrrt;s~1nx~,r.jr.e~N~h~X~R~E~--~co2r.--~u~R~l~l--~Fno~t•L~RA~1~l~NnQ--~HAT>IN~1~~R~A~N~C~E~~Hnl~k~.--~t~N~t~R~G~T--~M~R~s-.--~c~A~P~A?c~t~Vr-~F~U~l~~--~o~P~E~K-.~.--~Fno~EL.-~F~O~R~c~£~D~'P~LA-nN~N~E~O~F~u~EL~- JD IDENT, TYPE TYPE MW PTRN. MO~~HS UP OUTPUT ON FACTO~ COST KAINT. lNVT. OUTAGE OUTAGE PRICE RUU: f1WH !..IN£ ~TS COSTS RATE RAT£ S/l'laTU ~~w10N 0\ ~OlSOh Z 2 705.6 2 -1 ~65786!. 73!§. o.7S. 11~662. §!o9. o. 0.6!2 0.1\3 2.6§1 SEASHORE 02 EDISON 1 1 ~60.0 ~ 1 8799g1Q. 7053. 0.808 77051. 1~51&. ~533. 0.118 0.120 1.1~ SE~SHORE 01 EDISON t 1 ~60.0 3 1 8170665. 8~21. 0,73~ 69~~5. 1481&. ~533, 0.11• 0.120 1.134 EAST I"T 02 I"UBSEPI 1 1 5160,0 0 MA~CM 1 S77lil612. 7052. 0.506 768!58. '4eHS. lil!533. 0.118 0.120 1.134 44 EAST ?1 01 PuO:Sz:.R 1 I i12:S.O 0 lv·RIL HAY 1 :S~322J!2. 6Za5. o.73:S 67dl. t~a4i7. 918!. 0.111 0.\20 1.\!ii rl ~7 SEASHORE OS PUDSER 1 1 1200.D 0 ~AY 1 6372475. 6lil80. 0.796 &7776. 17235. t1lil1&. 0,121 0.120 1.134 1 3 6 S 0 E~ST PT 03 PU8SER 1 1 1200.0 0 APftlL MAY 1 7~~01S.. 6352. 0.718 56228. 1723~. lllii1S. 0.121 0.120 1.134 & 1 SEAShORE 06 EDISON 1 1 1200.0 0 AP~IL 1 8413056. 7011. 0.800 98238. 17235. 11918. 0.121 0.120 1,134 ~--~~-~~s~~~~~s~n~o~Rr.z:.~~o~a--~~~or..~~~o~Nr-~~-----T~--~~~:z~o~o~.~o--~5-=~~------~\--~6~\~a~o~9~3~a~._;G~~~g~o~.--~o~.~,~,~4~i~t~~~3~o~3~.--~t~,~2~3~!~.--~t~\~9~l~&~.-o~.~~2~a~~o~.~,n2~o~~,r.~lnsc~-- 50 sEAsHoRE 04 EDISON 1 1 1200.0 0 OCT. 1 7383211. sgliiO. 0.702 1043lil3. 17235. 1llii1S. 0.121 0.120 1.13C STATE OZ EDISON Z 2 21D.D 0 MARCfof 2 1380801. 7607. 0.71!51 34297. 4682. 0. 0.01!51 O.lOG 2,5511 LINCOLN 02 EDISON 2 2 17~.0 0 JUNE 2 1125;80, 7638. 0.71!57 25078. ~\38. D. D.O~O 0.\00 2.691 .o RA.z:.RS1D~ 01 t.JlScN 2 2 1oa.o o MA~cn AFRJL 2 9~0472. 6~31. o.s5g z~71. acaa. o. o.oso o.IOo 2.sg6 & LINCOLN 01 EDISON 2 2 1~0.0 0 J~Y 2 ~7131~. 781&. 0.73i 24223. 3~5. O. 0.050 0.100 2.6511 l2 STATE 01 EDISON ~ 2 125.0 0 JULY 2 B03247, ?eti!S. 0.73. 20038. ~57. 0. 0.050 0.100 2,6;1 11 \.iATERSIOE 02 EDISON 2 2 117.0 0 MAY 2 7:3!!95!. 761!5. 0.'721 1~~0. 3326. 0. D.050 0,100 2.691 51 r:o~C:. ... Ar..~ OS r-...IO:lSE.R :S 2 :mo.C C AFrtl~ 2 li'700'l!J2. i'Si:lil. o,o7<4 42431. 6501. 0. 0.066 O.lO!J 2.E!iil-n • HA?~OR 01 EDISON 2 2 131.D 0 NOV. 2 eto;o5. 763&. 0.707 20976, 3~53. 0, 0,050 0.100 2.S;I 1 _:~ NEoiTON OZ EOls:!N 2 2 750,0 1 2 4008005. 6727. 0.510 1062&1. Sl8BO. 0. O.Oe.t (1,11~ Z.SSiD U ... FR::lNTlER 02 PUSSE!t 2 3 621.0 0 FElL 2 3"66765, ?4173. 0.637 113~24. 8820. 0. 0.078 0.1t1 3,57:5 · --~~rc~r~rt~~~s~1~t~~rt~~o~,~~~-~·~~~~:.~R.---zr---~3.---Jrc~o~.~cr-~or-v~ATh-.--~r~~~.--~:z~~:~e~o~.~-Y~c~o~.~o~»~c~$•.--~o~.,~~3n;~,s~tr,~ansr.--~s~.~Yn\~.------~o•.~o•.~c~s·~1--~0-.Tt~o~3---3~.s~,~-- 46 s._UE LAi<~ 64 PuBSER 2 3 210.0 0 JULY 2 11251133. 7607. 0.614 375•6. 416!52. 0. 0,051 0.100 !L:S7S 34 ~~u~ LAKE 03 ?USSER 2 3 146.0 0 AUG. SEPT. 2 711~3~. 65131. 0.~56 23770. 37!6. 0. 0,050 0.100 3.:S7S n 37 ~lVE?.SIOE 05 PUBS£~ 2 3 105,0 0 AUG. 2 :S:S~SOS. 751~. O.:S99 18443. 3122. 0. O,OSO 0.100 3.57~ ~~,r-~o~L~u~E~L~A~r..~t~o~zr-~~~w~,.~s~t~R~~2~--~3~~17a~~~.~o--~c-M~~~~~~·H~------~2r-~,~a~J~2~0~7~.~~~6~i~s~.--~u~.~5~a~t--~2~sz~a~a~.--~a~~~a~s~.------~o-.~o~.o~s~o~~o~.-n,o~o~~3~.~s~7~:sr-- . 30 RJVERSlOE 04 PUBSE~ 2 ~ 100.0 0 NOV. 2 S10:S2S. 7631. 0.583 17621. 30~. O. O.OSO 0.100 3.!575 ~ :S8 NEwTON 01 PUBSE~ 2 3 7:SO.O 0 JU~Y 2 3633441. 7343. O.:S~3 128988. lii8SO. D. 0,084 0.11~ 3,:S7S :S2 FRONTIER 03 PUSSE~ 2 ~ 22~.0 0 AUG. SEPT. 2 51544~3. 6&17. 0,484 ~038. 4571!5. 0. D.052 0.101 3.575 45 cA'i Vl~w 04 :.01SCN 6 <4 550.0 0 oCi. 2 2:>430\ •. 75!i5J. 0,526 lii\ 126. 4665. b. 0 •. 052 O.oa; 3.602 rl 39 LOON MT 03 PUBSER 8 A 550.0 0 SEPT. 2 243:S~~8. 7531. O,:SOS 57473, 4855. D. 0.052 0.088 3.852 · 36 LOON MT 02 PUBSEH 6 A 117.0 0 JAN. FEB. 2 4~~710. 7018. 0,444 16642, ta7:S. 0. 0,030 0.080 3.662 Lj __ ~3~3~L~o~o~N~M~T~~o~1~~p~ue~-~s~EqR~~&~--~4,-_,t~:s~or.7or-~o~J~u~~~E~------~2~~SA~41~4~2~8~·~7"7~;rgr·~,o~·~4~9~o~_2n~~sr~ne~-~~2r.2ne4~·------~or.~or.~o~3~o.-~o~·~o~a~o--~3~-~~~s~2--~' ~~~~~ 03 ~01SeN 6 4 527.0 C MArtC" 2 20o~ss;. 7511. O,la& 1933~. 4764. 0. 0.050 0.068 3.E~2 11 ST~TE 04 EDISON 6 4 ~27.0 C AUG. 2 li712~~. 73SS. 0,427 75727. 47~. 0. 0.0~0 O.O~S 3.a52 16 P.~~aolt 03 E~'SON 6 A ~~s.o o MAY 2 150473a. ss~7. 0.377 56260. •~71. D. D.046 o.oes 3,&62 1~ w,e.<BOR 02 E:l!SON 6 4 :2::"' 0 0 JAH. 2 633113. 6~3. 0.346 24564. 277~. 0, 0,031 0.080 3.862 70 a~s 1viblRE EDI~oR a :s • .:::5.0 o JAh. a !5724. :nas. o.oru sa§. :;o:~. o. o.oso 15,046 41,736 70 G/~ TURBINE EDISON 3 S 150.0 0 3 52Sii, 386. 0.004 870. 2gs. D. 0.060 0,040 4.730 70 GAS TURBINE EDISON 3 S 1~0.0 0 OCT. 3 3827. 283. 0.003 660. 285. 0. 0,060 0,040 4.730 70 GAS TURBINE :DISON 3 ~ 150.0 0 3 2851., 22g, 0.002 ~2S, 247. 0, 0.060 0.040 ~.730 22 MA~oR-GT o2 ~olSoN a 5 1!0.0 0 FEE. 3 210\. \6\. o.oo~ So~. 230. o, o.o&o o.OJO 4.736 n 42 O.T. kUMP 3 PUBSE~ 3 S lOO.D 0 3 ~22S. 153. 0.001 2DO. 1A7. 0. 0,067 0,040 ~.730 U-~2~1--U~~T~O~W-N~-G~TW-0-2~~E~C~IMSO~N~~3~---;S~~1~0~0r.~Or-~O~Ar.P~R~I-L------~3~----~~~0~S~.~-1~2~i~·~~0~.00~1r----2~2~7~·~--·~1n4~0~·~----;0~·~0r.7o~67~--7or.704~0~~4r.~7~3~0.-61 G.T. LU~P A EDISON 3 S 94.0 0 ~ s;o. 100, 0.001 171. 127. 0, 0.067 0.040 4.730 20 ti.l. L:uRP EDISoN 3 5 \25.0 0 JURE a 727. 7il. 0,001 \lil:i. }SG. o. 0.063 O.oao 4.730 41 G.T. LUM~ 2 PUSSEK 3 S 130.0 0 3 707. 10, O.OOt 200. 168, D. 0,063 0,040 4.7~ __ ___2CTAL THERMAL 2302~.D 112437672. 2315~7~. 30~~21. ;7363. 0 TIE ENERGY 368, &1. CONV. HYDR:S :no. D 22oeooo. •ce. 4P-dS, 11123. PUMPED HVORe 2224.0 •11.485180, C. SATTERl£! ~00.0 -~6827. O. CCMPR~SD AlR 500.0 -88074. 6271. 11 e:s. rl u· PURCHASE + SALES 10~0.D 310200. 225168. -----.. ~-""''1' ... S ... 1.,..El" ... ,-.. ,ro l ALS iZI60lii.O 1136clliiS:Z. 23452\Q, 31Z026. ii73Sa. f/ TYP~ RA Tl Ntl ENERGY OUTPUT CAf',f,Cl TY FUEL COST 0 + t1 THERP'IAL 1 :--------------------------~~------~,H~.~~~~~~M'-w~H~~~-=r;A~C~10~R~,--~IM;O~J;S~ArN~D~£r---TJ~HO~v~ST~rN~U~sr-~s£,;.H~w~H~--------·--------------------- L....t I ll· ' t NUCL. ;eo~. 65!162~7<4. D. 7633 7DA321. usosa. .-, 2 ~-COAL 51A~. 26706043. 0.6370 $40487. ~373. I 3 G. 1. ..:J5Z. 160t6~:>. O,Oti/6 2013:1, 5:203. I· 1 ~ STAO 1000. 6995170. o.07iS 2e5a7. •4~7. ); GC·COAL. 300, 1770432. 0,6737 AA~31, 6~07. LJ------------------~----~~~F~-~O~I~L~--~4=4~2=4~·-----1~~~S~3~7~6~0;2~·----~0~·~4~0~0~1~----=5=B~7=9~~&~.------~4~51~~~3~1~.--~~;T----------------------------- TOTAL 230:ZS. 112<437672. 30~l52SI. 23.32 r--1 i I U~-------------------------------------------------------------------------------------------------------------- • • • •M~NUAL MAINTENANCE PATTERNS• • • • PTRN J F' M A 1"1 J J A a 0 H D n u 1 110000000000 0 0 !) 0 ::: 0 0 0 0 0 0 a c a 0 0 c 0 D 0 0 D 0 0 0 0 0 0 c 0 0 a 1 D 0 0 1 tl c 0 0 1 0 0 0 1 ("I NC1'E ~HEN USED, PA i":"ERNS OVERR l OE THE l ~---------------------------------------------~ce~~~M;·~~U~T;E;O~P~·;O~.~ft;·;·A~1~riN~O~IC=A~T~E=S~-------------------------------------------------------­l t w Figure 11. Annual Production Cost SQmmary -17-