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BPMC Meeting - April 6, 1989 2
10. ll. 12. 13. 14. 15. 16. 17. FILE COPY . —_—->-_—e BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE APRIL 6, 1989 AGENDA Alaska Power Authority Conference Room Juneau, Alaska CALL TO ORDER Kelly 10:30 a.m. ROLL CALL PUBLIC COMMENT MODIFICATION OF AGENDA Kelly APPROVAL OF MINUTES Kelly March 3, 1989 FINANCE COMMITTEE REPORT LeResche TECHNICAL COORDINATING COMMITTEE REPORT Yerkes INSURANCE COMMITTEE REPORT BUDGET COMMITTEE REPORT TAX COMMITTFE REPORT FERC LICENSURE REPORT OPERATING AND DISPATCH AGREEMENT COMMITTEE REPORT REVIEW OF PROJECT STATUS Eberle OLD BUSINESS Kelly NEW BUSINESS Kelly Schedule Next Meeting i. Date ii. Location iii. Time COMMUNICATIONS ADJOURNMENT Kelly 5273/953(1) / I 10. 11. 12: £3. 14. 15: 16. 17. 5273/953(1) BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE APRIL 6, 1989 AGENDA Alaska Power Authority Conference Room Juneau, Alaska CALL TO ORDER Kelly 10:30 a.m. ROLL CALL PUBLIC COMMENT MODIFICATION OF AGENDA Kelly APPROVAL OF MINUTES Kelly March 3, 1989 FINANCE COMMITTEE REPORT LeResche TECHNICAL COORDINATING COMMITTEE REPORT Yerkes INSURANCE COMMITTEE REPORT BUDGET COMMITTEE REPORT TAX COMMITTEE REPORT FERC LICENSURE REPORT OPERATING AND DISPATCH AGREEMENT COMMITTEE REPORT REVIEW OF PROJECT STATUS Eberle OLD BUSINESS Kelly NEW BUSINESS Kelly Schedule Next Meeting 1... Date ii. Location iii. Time COMMUNICATIONS ADJOURNMENT Kelly +29 Se eee 10. ll. 12. 13. 14. 15. 16. 17. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE APRIL 6, 1989 AGENDA Alaska Power Authority Conference Room Juneau, Alaska CALL TO ORDER 10:30 a.m. ROLL CALL PUBLIC COMMENT MODIFICATION OF AGENDA APPROVAL OF MINUTES March 3, 1989 FINANCE COMMITTEE REPORT TECHNICAL COORDINATING COMMITTEE REPORT INSURANCE COMMITTEE REPORT BUDGET COMMITTEE REPORT TAX COMMITTEE REPORT FERC LICENSURE REPORT OPERATING AND DISPATCH AGREEMENT COMMITTEE REPORT REVIEW OF PROJECT STATUS OLD BUSINESS NEW BUSINESS Schedule Next Meeting i. Date ii. Location iii. Time COMMUNICATIONS ADJOURNMENT 5273/953(1) Kelly Kelly Kelly LeResche Yerkes Eberle Kelly Kelly Kelly FROM MEQ PALMER Qk 4. 3.1999 erst P. 2 7. TECHNICAL COORDINATING COMMITTEE REPORT BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE REPORT FOR PROJECT MANAGEMENT COMMITTEE MEETING OF APRIL 6, 1989 JUNEAU, ALASKA The TCC has conducted two meetings since the last report to the PMC on March 3, 1989. The meeting of March 10, 1989 concentrated on the Bradley Lake Stability Study, Phase II report from PTI. The March 30, 1989 meeting again touched on this subject but concentrated on review of project SCADA technical proposals. Minutes of the meetings in draft form are attached for your review. Significant items and actions ace summarized below: MEETING OF MARCH 10, 19689 ’ The Committee concluded that the final PTI recommendations were mot adequately supported by the necessary technical analysis. The Committee also questioned certain important assumptions utilised by pTz in the analysis. ‘ The Committee listed twelve major areas requiring additional analysis and recommended that this work he completed by PTt or appropriate consultant. The Committee recommanded that the draft Phase If by PTI report be reviewed and corrected to reflect the additional work and analysis. ¢ In approving the Committee’s action, APA stated for the record "if the utilities feel that the PTI Study raises unansweced questions, then these questions should be addressed prior to the final recommendation." ’ The TCC unanimously approved the follewing communication to the PMC: "The TCC has reviewed the draft ‘Railbelt Stability Study - Phase Il,’ dated February 28, 1989 from PTI, This review indicated various weaknesses or gaps in the analysis which must be addressed. The Committee has listed these items for action by APA and/or PTI. Although the proposed solution may prove to be a viable option, pending successful completion of these items, the committee can not, at this time, recommend the proposed PTI 115 kv additions as a viable solution to the system stability and reliability concerns." ’ The TCC Operation and Maintenance Subcommittee was abolished in favor of the same established directly by the enc. BRADLEY LAKE P1.__ECT TECHNICAL COORDINATION COMMITTEE REPORT FOR PROJECT MANAGEMENT COMMITTEE MEETING OF APRIL 6, 1989, JUNEAU, ALASKA Page 2 MEETING OF MARCH 30, 1989 ¢ The TCC approved a subcommittee recommendation to reject the SCADA technical proposal from HSQ as containing critical technical deficiencies and conditionally allow other proposers to submit formal bids for required SCADA equipment. The Committee reviewed the PTI response and budget to complete additional work listed by the Committee during the March 10, 1989 meeting. The Committee agreed with APA intentions to delay additional PTI analysis until legislative action on the proposed "Southern Intertie" is apparent. This action will prevent unnecessary project work and cost. APA proposes PTI complete the work as a subcontractor to Stone & Webster, the project engineer. Accordingly, future PTI costs will be capitalized as a project cost. The 115 kv project transmission line contract has been awarded by APA to the second low bidder, Newberry Electric. The low bid was disqualified for lack of a Alaska business licence for one partner. APA has received four protests which they hope to resolve swiftly by court review. APA does not feel that either of the two low bids may qualify for the 5% Alaska bidder preference. “ve Cc. Giz P.E. SECRETARY MY:BB 302A.033189.89 BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 2, 1989 MEETING The meeting came to order at 8:30 a.m. in the Anchorage offices of the Alaska Power Authority. In attendance were: John Cooley ML&P Mike Yerkes MEA David Burlingame CEA Larry Hembree ML&P Moe Aslam ML&P Ron Krohn SWEC O. Johnson APA Don Shira APA Afzal H. Khan APA Remy Williams APA John Yale SWEC Harrison Clark PTI Ken Ritchey MEA Jack Anderson SED Mike Easley CVEA Sam Matthews HEA The proposed meeting agenda was approved followed by a presenta- tion of the PTI - Phase II Stability Report by Harrison Clark. APA distributed draft copies of the report to Committee members. During the presentation, the various concerns surfaced for dis- cussion. The discussions and resulting agreements were generally summarized by PTI by document titled "Summary of Remaining Phase II Tasks", dated March 6, 1989 (attached). Items of concern not included in the PTI summary are: LT. Ability of the Bradley governor controls (including defectors and needles) to perform in accordance with the PTI computer model. Stone & Webster rep- resentatives supported the concern that Woodward (governor contractor) and Fuji (Deflector/valve contractor) have not yet constructed such a device and were not sure if it is possible today to con- struct such a control system. 2 Accuracy of other generation control models used by PTI. Mr. Clark summarized the models as "generic" based upon typical similar units. Actual unit characteristics is an unknown which must be consid- ered in this critical analysis. BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 2, 1989 MEETING Page 2 oe Strong concern was voiced against the large fre- quency and voltage swings which occur in many of the PTI cases analyzed with the proposed 115 KV system additions. Utility representatives noted that these swings exceed various industrial and equipment standards. PTI agreed to modify the pro- posed system additions as required to insure that voltages would be limited to +10% and -15% of nominal for swings lasting between .05 and .5 seconds. Frequency would be limited to +1.5 HZ of nominal. 4. It was noted that the proposed excitation "stabi- lizers" are critical to the PTI solution and that PTI is the sole source of this device. Conflict of interest and procurement problems were apparent. Ss CEA voiced concern for the protection of their Sol- dotna 115 KV capacitor bank following installation of the proposed Soldotna SVS. HEA and CEA noted similar concern for the protection of the Soldotna and Bernice turbine generators. 6. PTI and APA were advised that minimal land is available in Soldotna and other areas where the equipment proposed by PTI will be located. The Committee next approved the December 8, 1989 meeting minutes as drafted. Under Old Business, the Committee deferred consideration of a recommendation on system stability to the Bradley PMC until the members had adequate time to review the draft document provided by APA. The TCC would meet again on Friday, March 10, 1989, at 9:30 AM in the Anchorage APA offices for this purpose. Next the Committee received a status report from APA regarding the SCADA system proposals. The TCC SCADA Subcommittee had re- viewed the proposals and visited various existing installations. The group will shortly make recommendations to the full TCC for approval. HEA briefly discussed the recently opened Soldotna-Bradley-Fritz Creek 115 KV transmission line bids. Only four of the six pre- qualified firms submitted bids. Low bid was submitted by Irby. BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 2, 1989 MEETING Page 3 Consideration of a wood pole installation at Bradley Junction was deleted since it is no longer required. Next the Committee agreed to form an Operations Subcommittee to consider previously received O&M issues from the PMC. The com- mittee would consist of representative from CEA, HEA and APA with Dave Burlingame acting as interim chair. (At the time of writing, PMC has abolished this subcommittee in favor of a direct PMC sub- committee). ] Mr. Johnson provided the Committee with an update of the project communications plan and a proposal to utilize SCADA system radio systems early for the on-site project manager (PM) communica- tions. After considerable discussion, the Committee recommended that the SCADA radios not be procured early for on-site use and that the required construction radios be purchased at a cost of approximately $25,000 independently. It was noted that the PM communications were provided by APA from left over equipment from other projects. The Committee concluded that early purchase of radio systems independently would cloud SCADA contractor perfor- mance responsibilities and result in costs exceeding independent purchase. (See attached "UHF Radio System".) The meeting ad- joured at approximately 4:00 P.M. SUBMITTED: MYLES C. YERK APPROVED: DAVID EBERLE, CHAIR MY:BB 302A.032389.77 BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 30, 1989 MEETING The meeting came to order at 9:30 a.m. in the Anchorage offices of the Alaska Power Authority. In attendance were: Mike Yerkes MEA John Yale SWEC Dave Eberle APA Afzal H. Khan APA David Burlingame CEA Paul Johnson CEA Fred LeBeau GVEA Steven Haagenson GVEA Tom Small HEA Maynard Gross HEA Sam Matthews HEA John Cooley ML&P Minutes of the previous March 2 and March 10, 1989 TCC meetings were approved with minor corrections. The meeting agenda was approved after adding a report on the APA transmission line bid status under old business. Next the SCADA Subcommittee distributed documents and discussed the results of their evaluation of SCADA technical proposals. John Yale reviewed the following documents with the Committee: Le Trip report "SCADA owners site visits" 2e "Reasons for rejecting HSQ’s proposal" 3m "Exception or clarification" listing by vendor 4. Section 2.0 "technical specification" of the SCADA Invitation to Bid (3/24/89 date) Following discussion, the Committee unanimously voted to accept the Subcommittee recommendation which finds the HSQ technical proposal unacceptable due to critical technical deficiencies and finds the other proposals as acceptable subject to compliance with the list of exceptions and clarification for each respective proposer. BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 30, 1989 MEETING Page 2 Following Committee action, APA advised formal SCADA bid documents would be completed and mailed to successful proposers within approximately two weeks. Formal bid opening is tentatively scheduled for May 4, 1989. Next, APA distributed a memorandum of March 15, 1989 and a memorandum of March 16. 1989 from Harrison Clark of PTI to Afzal Kahn of APA. The memorandum of March 15 responded to the TCC listing of March 10 which summarized additional required work on the non - 230 KV - intertie option. This memo also provided a budget for PTI to complete the additional work. The memo of March 16 discussed additional technical issues with proposed "brakes" and "stabilizer controls." Dave Eberle stated APA’s intention to complete this work by allowing Stone & Webster to employ PTI as a subcontractor. The additional work will be delayed to consider legislative action on the 230 KV alternative, since the additional work will require re-direction if the 230 KV "Southern Intertie" is approved. In any case, additional PTI costs will be capitalized as a project cost. John Hale discussed the recent meeting with PTI, Woodward Govenor, and Stone and Webster. Apparently, an agreement on the validity of the PTI Govenor model was not achieved. Woodward will prepare a model and provide same to PTI in the future. Dave Eberle noted that Newberry Electric has been awarded the Bradley to Bradley Junction transmission line contract. The low bid was determined "non-responsive" due to a lack of an Alaskan Business License by one of the venture partners. APA questions if Newberry or the low bidder are entitled to the 5% "Alaska Bidder Preference." Four formal protests from bidders have been received. APA hopes to have all protestors stipulate to waive the administrative process and immediately submit the protest to a court of law for a binding legal review. SUBMITTED: , SECRETARY APPROVED: DAVID EBERLE, CHAIR MY:BB 302A.033189.88 a4/as7s9 i4ios B 303 226 ae79 LHNew as 8. INSURANCE Liwpsar, Hagt, Nair & Wrroter Stee oe wreme acot Pours Avinuit Piaca asia, ecoceea. ee Prace \Suariner Supe. Sorrs 03 . ory, Suite 400 aon earademipeee Pourrarn, Onmcon 072010618 ‘Motus, Youuo eoTOE wos ows arn TsLernons (590) S50 -1101 geve 900-9949 ae Trrancorient (20S) 286-0078 {QRS 10vw SY RERT, N.w, Toran 404-7009 pen Cas roants Oranar x01 ROO Sores ab00 Yuseuarax, D.C. 20088 April 3. 1989 Sas Pmuscra0o, CAtapomIA O4104 (C061 006-4400 MS Been MEMORANDUN TO: BRADLEY PMC FROM: RON SAXTON RE: INSURANCE COMMITTEE The Insurance Committee met on March 16, 1989. Committee members Brent Petrie, Bob Hansen, Mike Cunningham and Ron Saxton were present. Member Kent Wick was absent. Marcey Rawitscher also attended the meeting. The Committee prepared a Getailed list of types of insurance that may be necessary for the project and discuased the requ, easnts of the bond resolution. Assignments were made to individual Committee members to gather information on probable logs analysis, bond requirements, alternatives available for funding an insurance fund and related matters, The Committee scheduled its next meeting for April 6th prior to the reguiarly scheduled Bradley PMC meeting. Because of the movement of the April 6th meeting From Anchorage to Juneau, the Insurance Committee meeting has been rescheduled to April 11th. RLGders33 BerRasR2 14185 @ 38% 276 Bare ikweu ae 9. BUDGET COMMITTEE REPORT Laxpsay, Hart, Nait & Wmorrm AAA tes 100% Fovarn averre Ynez Srtrx anne earner Cee Bsey sure BOG 280 6. Gnomes mete 5G Smarrus. Wounwernw paisa PORTLAND. OREGON 87201-6610 Bow Lon cue. twos aS-a7 ‘Tanersows (800) 260-3191 ‘oom aaaseean — - Texscorran (600) e2e-0070 998 o Sraant, h.W THLEx 404-7060 BAS CALIBORYIA STR Fvrra 800 sore Wainetmccon, D.C. G0008 April 3, 1989 Sax Bi a smcren, 1 MANCISCD. CALIPONLA BRIDS MEMORANDUM Sear TO: BRADLEY PMC FROM; RON SAXTOI RE: BUDGET COMMITTEE The BPMC Budget Committee met on March 16, 19895. Dennis Lapp, Cathy Jacobs, mMarcey Rawitscher, Tom Klinkner and Ron Saxton were present for the meeting. Brent Patrie attended for part of the meeting. The Committee had a detailed discussion of the various funds required by the Power Sales Agreement and the bond resolution and the rclaticnship of those funds to each other. Substantial discussion focused on control of individual funds and of the benefit from funds' earnings, The Committee Made assignments to individual committee members. The group has scheduled its next meeting on April 11th in order to meet with the APA's Bradlay finance advisors (Jim Seagraves and Don Grimms). The Committee postponed selection of a chairman until the next meeting, It was agreed that the Committee tasks need to be completed by September to allow timely consideration of bond sale options. RLSder8a4 ec: Budget Committee Members aeraesss 16:85 B sas 226 ae79 Levee as 10. TAX COMMITTEE REPORT Liusasay, Hag, Nezz & Waren Lay nes ites Poeere AvERne Put srTR 18Oo deereees Pure Smarizer free). Suite 0200 ete 2W. Coranema wee A era, Serra we Suara, WasrinoTOR 06184 Pomstam Ommaom o7201-0018 ores, Inawo 80709 (ow 6 29-a Terermorx (bod! £80-1161 Ob U98-Guda a Taonscorrms (500) £6 '007Te BRE ew Xruteler, NW. TALEN 4h8-7008 as Cazsposnrta Sraasr filenmoosce) Dict anno! april 3, 1989 is Patacones Caustonan P04 Woe) OOD-a4e0 (4% Gat seen MEMORANDUM TOr BRADLEY PMC FROM: RON SAXTOM AND BRENT PETRIE RE: TAX Issba We have discussed the possible application of the tax issue to the Bradley PMC. The key to this issue is the organization of committee funds and the terms of the bond resolution, etc. We are keeping the tax iasue in mind as we work with the Budget Committee and will focus on the discreet tax iasues as they become more developed. RLSder832 04704789 14:83 4 &_383 226 0979 LHNGw es 11. FERC LICENSURE REPORT Lrnpsay, Hart, Nein & WEIGLER LAWYERS 1001 Founr Avsoryn Pyaas Surre 1860 Jagrsxegn Prace Sumas? sina, Suree BzeO san SW. Cotumms 080 N Oru Gerve 400 Smarr. WARBRTTEN WaLDe PortTtiarD OpRGeX 47201-6018 Boren, Inazo 09702 fave eba-arn TELRPUDHA (BO) fBH-1161 tN Sn nme TreLscorizn (DOG) ooTe 920 iavw Semmes, NW, Triter ana Fons Oth Carssonre Sraxsr Sum woo t Sovre 8800 ecowionl D.% 20008 April 3, 1989 Bas Yaarors00, Caxirnmia 84104 (ROT 208-4450 (416) 084-6848 MEMORANDUM TO: BRADLEY PMC FROM: RON SAXTON AND BRENT PETRIE RE: PERC HYDROELECTRIC LICENSING FEES The Federal Power Act requires that operators of licensed hydroelectric projects pay an annual fee to the Federal Energy Regulatory Commission (PERC) for the cost of administering the licenses and for use of state or federal lands. FERC may grant exempticns from these Fees for several reasons. The one relevant for our purposes is that 18 CFR 11.6(e) provides for exemption from license fees if {1) the project is state ownsd: (2) the project power 15 sold for resale; and (3) power is "sold to the ultimate consumer without profit.” Bradley Lake will meet at least the First two parts of this test, It is a state owned project selling power at cost to nonprofit utility systems - cooperatives and municipal utilities for resale to their consumers. The third part of the test is a little harder. To the extent utilities pass through actual costs to their consumers pursuant to automatic power cost adjustments, the test is probably met. Utilities that will not use such a mechanism for Bradley costa will need to fashion arguments that the cost of the Bradley Lake power aré passed through to consumers without a "mark-up" on the Bradley Lake costs. We can amplify on this point at the meeting. The even more difficult requirement is that utilities net tranefer electric utility earnings out of the electric utility system for any purpose. While this is not an isave for the co-ops, it is likely to be a significant issue for the municipalities. In the Four Dam Pool's case, substantial discussion has been had about characterization of "retained earnings" and the legal significance of co-ops paying capital credits. The key issue here is FERC's concern about "profit" and FERC definea this in a broad way. RLSder831 ~-MEMORANDUM TO: THRU Bradley Project Management 12. OPERATING & DISPATCi AGREEMENT COMMITTEE REPORT State urAtaska i April 4, 1989 Committee AILENG TELEPHONE NO: SUBJECT: Operation & Dispatch Agreement Committee Status as of 4/4/89 On March 14, 1989 the Operation & Dispatch Agreement Committee met to identify agreements needed for the Bradley Lake Project, and to make assign- ments for drafting the agreements. The following people were in attendance: Donald L. Shira, Alaska Power Authority Tom Lovas, Chugach Electric Association (CEA) John Cooley, Anchorage Municipal Light & Power (AML&P) Sam Matthews, Homer Electric Association (HEA) Marvin Riddle, Golden Valley Electric Association (GVEA) The Committee identified eight agreements that are required for the success- ful operation, maintenance and dispatch of the Bradley Lake Project. of these agreements and the responsible individuals are listed helow: Agreements Dispatch Agreement between Power Authority and CEA. Maintenance Agreement between Power Authority and Maintenance Contractor. Transmission Line Maintenance Agreement between Power Authority and HEA. Participants Scheduling Agreement Substation Maintenance Agreement between Power Authority and HEA Joint Operations Agreement between CEA and HEA Communications Equipment Agreement between Power Authority and Division of Telecommunications Soldotna #1 Dispatch Agreement between CEA and AEG&T 5435/DD48(1) Responsibility Tom Lovas, CEA Donald L. Shira, Power Authority Sam Matthews, HEA Sam Matthews, HEA Afzal Khan, Power Authority All members Sam Matthews, HEA Afzal Khan, Power Authority Tom Lovas, CEA Sam Matthews, HEA Afzal Khan, Power Authority Sam Matthews, HEA A list Page ? The following list of sample agreements were distributed to members for reference: Alaska Intertie Agreement Among Power Authority, AML&P, CEA, GVEA, and AEG&T Alaska Intertie Maintenance Agreement Between Power Authority and GVEA Alaska Intertie Maintenance Agreement Between Power Authority and AEG&T SCADA Agreement Between Power Authority and CEA SCADA Agreement Between Power Authority and AMLAP Transmission Service Agreement Between Power Authority and Matanuska Electric Association (MEA) Operations and Maintenance Agreement for the Tyee Lake Project The next meeting is scheduled at 10:00 a.m. on April 5, 1989 at the Chugach Electric Association Conference Room. OLS: it 5435/DD48(2) 12. OPERATING & DISPATC:: AGREEMENT COMMITTEE REPORT State @Ataska DATE: MEMORANDUM Bradley Project Management April 4, 1989 THRU: FROM Committee eine TELEPHONE NO: SUBJECT. Operation & Dispatch Agreement Committee Status as of 4/4/89 On March 14, 1989 the Operation & Dispatch Agreement Committee met to identify agreements needed for the Bradley Lake Project, and to make assign- The following people were in attendance: ments for drafting the agreements. Donald L. Shira, Alaska Power Authority Tom Lovas, Chugach Electric Association (CEA) John Cooley, Anchorage Municipal Light & Power (AML&P) Sam Matthews, Homer Electric Association (HEA) Marvin Riddle, Golden Valley Electric Association (GVEA) The Committee identified eight agreements that are ful operation, maintenance and dispatch of the Bradley Lake Project. required for the success- of these agreements and the responsible individuals are listed below: Agreements spati igreement between Power Authority an CEA. Maintenance Agreement between Power Authority and Maintenance Contractor. Transmission Line Maintenance Agreement between Power Authority and HEA. Participants Scheduling Agreement Substation Maintenance Agreement between Power Authority and HEA Joint Operations Agreement between CEA and HEA Communications Equipment Agreement between Power Authority and Division of Telecommunications Soldotna #1 Dispatch Agreement between CEA and AEG&T 5435/DD48(1) Responsibility Tom Lovas, CEA Donald L. Shira, Power Authority Sam Matthews, HEA Sam Matthews, HEA Afzal Khan, Power Authority All members Sam Matthews, HEA Afzal Khan, Power Authority Tom Lovas, CEA Sam Matthews, HEA Afzal Khan, Power Authority Sam Matthews, HEA A list April 4, 1989 Page 2 The following list of sample agreements were distributed to members for reference: Alaska Intertie Agreement Among Power Authority, AML&P, CEA, GVEA, and AEG&T Alaska Intertie Maintenance Agreement Between Power Authority and GVEA Alaska Intertie Maintenance Agreement Between Power Authority and AEG&T SCADA Agreement Between Power Authority and CEA SCADA Agreement Between Power Authority and AML&P Transmission Service Agreement Between Power Authority and Matanuska Electric Association (MEA) Operations and Maintenance Agreement for the Tyee Lake Project The next meeting is scheduled at 10:00 a.m. on April 5, 1989 at the Chugach Electric Association Conference Room. DLS:it 5435/DD48(2) BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE APRIL 6, 1989 AGENDA Alaska Power Authority Conference Room Juneau, Alaska CALL TO ORDER 10:30 a.m. 2. ROLL CALL 3. PUBLIC COMMENT 4. MODIFICATION OF AGENDA 5. APPROVAL OF MINUTES March 3, 1989 6. FINANCE COMMITTEE REPORT 7. TECHNICAL COORDINATING COMMITTEE REPORT 8. INSURANCE COMMITTEE REPORT 9. BUDGET COMMITTEE REPORT 10. TAX COMMITTEE REPORT 11. FERC LICENSURE REPORT 12. OPERATING AND DISPATCH AGREEMENT COMMITTEE REPORT 13. REVIEW OF PROJECT STATUS 14. OLD BUSINESS 15. NEW BUSINESS Schedule Next Meeting i. Date ii. Location iii. Time 16. COMMUNICATIONS 17. ADJOURNMENT As annotated @ m4 5273/953(1) ee Kelly Kelly Kelly LeResche Yerkes Eberle Kelly Kelly Kelly SS ah ¢. TECHNICAL COORDINATING COMMITTEE REPORT SS Se ee ee BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE REPORT FOR PROJECT MANAGEMENT COMMITTEE MEETING OF APRIL 6, 1989 JUNEAU, ALASKA The TCC has conducted two meetings since the last report to the PMC on March 3, 1989. The meeting of March 10, 1989 concentrated on the Bradley Lake Stability Study, Phase II report from PTI. The March 30, 1989 meeting again touched on this subject but concentrated on review of project SCADA technical proposals. Minutes of the meetings in draft form are attached for your review. Significant items and actions are summarized below: MEETING OF MARCH 10, 1969 ’ The Committee concluded that the final PTI recommendations were not adequately supported by the necessary technical analysis. The Committee alco questioned certain Important ageumpttone utilised by pTI in the analysis. ‘ The Committee listed twelve major ulring additional analysis a I Or appropriate consultant. The Committee recommended that the Fite Phase II by PTI report be reviewed and corrected to reflect the additional work and analysis. ’ In approving the Committee’s action, APA stated for the cecord “if the utilities feel that the PTI Study raises unansweced questions, then these questions should be addressed prior to the final recommendation." ’ The TCC unanimously approved the follewing communication to the PMC: “The TCC has reviewed the draft ‘Railbelt Stability Study - Phase 11,’ dated February 28, 1989 from PTI. This review indicated various weaknesses or Although the prop Glution may prove to e option, pending successful completion of these items, the committee can not, at this time, recommend the proposed PTI 115 kv additions as a viable solution to the system stability and reliability concerns." ’ The TCC Operation and maintenance Subcommittee was abolished in favor of the same e shed directly by the Pmc. BRADLEY LAKE P..wJECT TECHNICAL COORDINATION COMMITTEE REPORT FOR PROJECT MANAGEMENT COMMITTEE MEETING OF APRIL 6, 1989, JUNEAU, ALASKA Page 2 MEETING OF MARCH 30, 1989 ¢ The TCC approved a subcommittee recommendation to reject the SCADA technical proposal from HSQ as containing critical technical deficiencies and conditionally allow other proposers to submit formal bids for required SCADA equipment. The Committee reviewed the PTI response and budget to complete additional work listed by the Committee during the March 10, 1989 meeting. The Committee agreed with APA intentions to delay additional PTI analysis until legislative action on the proposed "Southern Intertie" is apparent. This action will prevent unnecessary project work and cost. APA proposes PTI complete the work as a subcontractor to Stone & Webster, the project engineer. Accordingly, future PTI costs will be capitalized as a project cost. The 115 kv project transmission line contract has been awarded by APA to the second low bidder, Newberry Electric. The low bid was disqualified for lack of a Alaska business licence for one partner. APA has received four protests which they hope to resolve swiftly by court review. APA does not feel that either of the two low bids may qualify for the 5% Alaska bidder preference. “ve Cc. Lyle P.E. SECRETARY MY:BB 302A.033189.89 BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 2, 1989 MEETING The meeting came to order at 8:30 a.m. in the Anchorage offices of the Alaska Power Authority. In attendance were: John Cooley ML&P Mike Yerkes MEA David Burlingame CEA Larry Hembree ML&P Moe Aslam ML&P Ron Krohn SWEC O. Johnson APA Don Shira APA Afzal H. Khan APA Remy Williams APA John Yale SWEC Harrison Clark PTE Ken Ritchey MEA Jack Anderson SED Mike Easley CVEA Sam Matthews HEA The proposed meeting agenda was approved followed by a presenta- tion of the PTI - Phase II Stability Report by Harrison Clark. APA distributed draft copies of the report to Committee members. During the presentation, the various concerns surfaced for dis- cussion. The discussions and resulting agreements were generally summarized by PTI by document titled "Summary of Remaining Phase II Tasks", dated March 6, 1989 (attached). Items of concern not included in the PTI summary are: Lis Ability of the Bradley governor controls (including defectors and needles) to perform in accordance with the PTI computer model. Stone & Webster rep- resentatives supported the concern that Woodward (governor contractor) and Fuji (Deflector/valve contractor) have not yet constructed such a device and were not sure if it is possible today to con- struct such a control system. 2. Accuracy of other generation control models used by PTI. Mr. Clark summarized the models as "generic" based upon typical similar units. Actual unit characteristics is an unknown which must be consid- ered in this critical analysis. BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 2, 1989 MEETING Page 2 3. Strong concern was voiced against the large fre- quency and voltage swings which occur in many of the PTI cases analyzed with the proposed 115 KV system additions. Utility representatives noted that these swings exceed various industrial and equipment standards. PTI agreed to modify the pro- posed system additions as required to insure that voltages would be limited to +10% and -15% of nominal for swings lasting between .05 and .5 seconds. Frequency would be limited to +1.5 HZ of nominal. 4. It was noted that the proposed excitation "stabi- lizers" are critical to the PTI solution and that PTI is the sole source of this device. Conflict of interest and procurement problems were apparent. 5. CEA voiced concern for the protection of their Sol- dotna 115 KV capacitor bank following installation of the proposed Soldotna SVS. HEA and CEA noted similar concern for the protection of the Soldotna and Bernice turbine generators. 6. PTI and APA were advised that minimal land is available in Soldotna and other areas where the equipment proposed by PTI will be located. The Committee next approved the December 8, 1989 meeting minutes as drafted. Under Old Business, the Committee deferred consideration of a recommendation on system stability to the Bradley PMC until the members had adequate time to review the draft document provided by APA. The TCC would meet again on Friday, March 10, 1989, at 9:30 AM in the Anchorage APA offices for this purpose. Next the Committee received a status report from APA regarding the SCADA system proposals. The TCC SCADA Subcommittee had re- viewed the proposals and visited various existing installations. The group will shortly make recommendations to the full TCC for approval. HEA briefly discussed the recently opened Soldotna-Bradley-Fritz Creek 115 KV transmission line bids. Only four of the six pre- qualified firms submitted bids. Low bid was submitted by Irby. BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 2, 1989 MEETING Page 3 Consideration of a wood pole installation at Bradley Junction was deleted since it is no longer required. Next the Committee agreed to form an Operations Subcommittee to consider previously received O&M issues from the PMC. The com- mittee would consist of representative from CEA, HEA and APA with Dave Burlingame acting as interim chair. (At the time of writing, PMC has abolished this subcommittee in favor of a direct PMC sub- committee). Mr. Johnson provided the Committee with an update of the project communications plan and a proposal to utilize SCADA system radio systems early for the on-site project manager (PM) communica- tions. After considerable discussion, the Committee recommended that the SCADA radios not be procured early for on-site use and that the required construction radios be purchased at a cost of approximately $25,000 independently. It was noted that the PM communications were provided by APA from left over equipment from other projects. The Committee concluded that early purchase of radio systems independently would cloud SCADA contractor perfor- Mance responsibilities and result in costs exceeding independent purchase. (See attached "UHF Radio System".) The meeting -ad- joured at approximately 4:00 P.M. SUBMITTED: sc. CRETARY APPROVED: DAVID EBERLE, CHAIR MY:BB 302A.032389.77 BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 30, 1989 MEETING The meeting came to order at 9:30 a.m. in the Anchorage offices of the Alaska Power Authority. In attendance were: Mike Yerkes MEA John Yale SWEC Dave Eberle APA Afzal H. Khan APA David Burlingame CEA Paul Johnson CEA Fred LeBeau GVEA Steven Haagenson GVEA Tom Small HEA Maynard Gross HEA Sam Matthews HEA John Cooley ML&P Minutes of the previous March 2 and March 10, 1989 TCC meetings were approved with minor corrections. The meeting agenda was approved after adding a report on the APA transmission line bid status under old business. Next the SCADA Subcommittee distributed documents and discussed the results of their evaluation of SCADA technical proposals. John Yale reviewed the following documents with the Committee: 1. Trip report "SCADA owners site visits" as "Reasons for rejecting HSQ’s proposal" 3. "Exception or clarification" listing by vendor 4. Section 2.0 "technical specification" of the SCADA Invitation to Bid (3/24/89 date) Following discussion, the Committee unanimously voted to accept the Subcommittee recommendation which finds the HSQ technical Proposal unacceptable due to critical technical deficiencies and finds the other proposals as acceptable subject to compliance with the list of exceptions and clarification for each respective proposer. BRADLEY LAKE PROJECT TECHNICAL COORDINATION COMMITTEE MINUTES OF MARCH 30, 1989 MEETING Page 2 Following Committee action, APA advised formal SCADA bid documents would be completed and mailed to successful proposers within approximately two weeks. Formal bid opening is tentatively scheduled for May 4, 1989. Next, APA distributed a memorandum of March 15, 1989 and a memorandum of March 16. 1989 from Harrison Clark of PTI to Afzal Kahn of APA. The memorandum of March 15 responded to the TCC listing of March 10 which summarized additional required work on the non - 230 KV - intertie option. This memo also provided a budget for PTI to complete the additional work. The memo of March 16 discussed additional technical issues with proposed "brakes" and "stabilizer controls." Dave Eberle stated APA's intention to complete this work by allowing Stone & Webster to employ PTI as a subcontractor. The additional work will be delayed to consider legislative action on the 230 KV alternative, since the additional work will require re-direction if the 230 KV "Southern Intertie" is approved. In any case, additional PTI costs will be capitalized as a project cost. John Hale discussed the recent meeting with PTI, Woodward Govenor, and Stone and Webster. Apparently, an agreement on the validity of the PTI Govenor model was not achieved. Woodward will prepare a model and provide same to PTI in the future. Dave Eberle noted that Newberry Electric has been awarded the Bradley to Bradley Junction transmission line contract. The low bid was determined "non-responsive" due to a lack of an Alaskan Business License by one of the venture partners. APA questions if Newberry or the low bidder are entitled to the 5% "Alaska Bidder Preference." Four formal protests from bidders have been received. APA hopes to have all protestors stipulate to waive the administrative process and immediately submit the protest to a court of law for a binding legal review. SUBMITTED: M , SECRETARY APPROVED: DAVID EBERLE, CHAIR MY:BB 302A.033189.88 8. INSURANCE COMMITTEE REPORT Liwpsar, apr, Nazis & Wrroter =<=e 2008 Pours Avewun Pisa ossawi 100 nee Praca amuicis Seen Goes . Coummma ru, Bours 400 Roaresaseinononer met Pourraws. Onrmcon 07201-0618 eorex, MO4eo BOTOD woe wwu arn TaLsramuns (000) S60-110% bros ovo 9049, — Turavorien (000) 240-0078 1925 tO SvRERT, Now. Tera 404-7OU: en Cas roams Oresat Burrs 2800 *usezednen, B.C. 2008 April 3. 1989 Sas Paustera0e, Catapomria C4104 (200: 000400 we oseonsn MEMORANODUN TO: BRADLEY PMC FROM: RON SAXTON RE: INSURANCE COMMITTEE The Insurance Committee met on March 16, 1989. Committee members Brent Petrie, Bob Hangen, Mike Cunningham and Ron Saxton were present. Member Kent Wick was absent. Marcey Rawitscher also attended the meeting. The Committee prepared a detailed list of types of insurance that may be necessary for the fe pe and discussed the requirementea of the bond resolution. Assignments were made to individual Committee members to gather information on probable loss analysis, bond requirements, alternatives available for funding an insurance fund and related matters. The Committee scheduled its next meeting for April 6th prior to the regularly scheduled Bradley PMC meeting. Because of the movement of the April 6th meeting From Anchorage to Juneau, the Insurance Committee meeting has been rescheduled to April Auth 4 yh RLSder833 wen Strom, sencfom APA + Hansenis 7 Giz Freon Cons(lir. hon -& th ky hag Bred + AFL Ipsarne, 9. BUDGET COMMITTEE REPORT Lixpsay, Hart, Neit & Werorrr ———————————— ate ee 1001 Fooarn Averve Yuata ewes Pace ‘SmaTtus. Yoana ease = iii hed we pha See 1999 101m Oraane, XW. B1e CALBORYIA SYaEat Evrre 800 $urrz s200 ee Me a a eee MEMORANDUM —— TO: BRADLEY PMC FROM: RON SAXTO? RE: BUDGET COMMITTEE The BPMC Budget Committee met on March 16, 1989. Dennis Lapp, Cathy Jacobs, mMarcey Rawitscher, Tom Klinkner and Ron Saxton were present for the meeting. Brent Patrie attended for part of the meeting. The Committee had a detailed discussion of the various funds required by the Power Sales Agreement and the bond resolution and the relaticnship of those funds to each other. Substantial discussion focused on control of individual funds and of the benefit from funds' earnings. The Committee made assignments to individual committee members. The group has scheduled its next meeting on April llth in order to meet with the APA's Bradley finance advisors (Jim Seagraves and Don Grimg’s) . The Committee postponed selection of a chairman until the next meeting. It was agreed that the Committee tasks need to be completed by September to allow timely consideration of bond sale options. RLSder834 6 | cc: Budget Committee Members io 4h at Ww rv (om *) ar 10. TAX COMMITTEE REPORT Luwpsay, ag, Nery & Wricier Oey tes rom: Poeern Avene Puane Snitz 1KOD Jassie ae Raarixer recy. SviTR 0200 eee LW Commumas wee X ore, Sus we Smarrin, Waser ueron 6018+ Torsten Omscon o7201-0018 ‘Mots, Dawo 80700 Neo an Tsrurmors (D00! 680-1161 au 008 ooee Tarscorras (000) C£0:0078 1286 Jor xrieir, Now TALRN 408-7008 0s Catspomsta Sreaee a April 3, 1989 im Paseo tates ones (206, 008-e480 08 oot eeee MEMORANDUM TOr BRADLEY PMC FROM: RON SAXTOH AND BRENT PETRIE RE: TAX I6Sta We have discussed the possible application of the tax issue to the Bradley PMC. The key to this issue is the organization of committee funds and the terms of the bond resolution, etc. We are — the tax issue in mind as we work with the Budget Committee and will focus on the discreet tax issues as they become more developed. RLSder832 11. FERC LICENSURE REPORT Loepsay, Hart, Nuit & WEIOLER Lawyane 1004 FounTa Avmrva Py sas Burrs 1800 Jarrareon Pisce ; ’ ane gen SW. Cotummis 060 N Oru Gerre 400 castes tnagenanen wee Porttarn, OvsGox w78G1-6018 Mores, rac 60700 hero ofe-901 TELePuowa (BOM fEO-1101 ion oon-enee Tetacorisn (D00) 900 oem Reamer, dW. Truter ane Oab Caszomnts Seems asmorezon, D6. 20008 April 3, 1989 ase Vuasoreco, Cauryain 94104 0m n0s-4460 ae 084-0888 MEMORANDUM TO: BRADLEY PMC FROM: RON SAXTON AND BRENT PETRIE RE: FERC HYDROELECTRIC LICENSING FEES The Federal Power Act requires that operators of licensed hydroelectric projects pay an annual fee to the Federal Energy Regulatory Commission (PERC) for the cost of administering the licenses and for use of state or federal lands. FERC may grant exemptions Erom these Fees for several reasons. The one relevant for our purposes is that 18 CFR 11.6(e) provides for exemption from license fees if (1) the project is state owned; (2) the project power 15 sold for resale; and (3) power is “sold to the ultimate consumer without profit.” Bradley Lake will meet at least the First two parts of this test. It is a state owned project selling power at cost to nonprofit utility systems - cooperatives and municipal utilities for resale to their consumers. The third part of the test is a little harder. To the extent utilities pass through actual costs to their consumers pursuant to automatic power cost adjustments, the test is probably met. Utilities that will not use such a mechanism for Bradley costa will need to fashion arguments that the cost of the - Bradley Lake power are passed through to consumers without a "mark-up" on the Bradley Lake costs. We can amplify on this point at the meeting. The even more difficult requirement is that utilities not transfer electric utility earnings out of the electric utility system for any purpose. While this is not an issve for the co-ops, it is likely to be a significant issue for the _ municipalities. ae ee In the Four Dam Pool's case, substantial discussion has been had about characterization of “retained earnings" and the legal significance of co-ops paying capital credits. The key issue here is FPERC's concern about "profit" and FERC defines this in a broad way. might red to 4 accel. precka RLSder831 ord of magni dt 7 100 200000 /yV- a \" yo ye Ve ye / Pee eet “ ae Coe oll be deckimied 9 vekt py. 005° ave yn re, . yh oben WLI um peed ppp ean elly sm He queen wi ETS pom grr J Pree fiogny) ene een pr . / io ritod +f pepe seokia) flim ose tysm ebhove » LeSe acct fy Conus) now only ands EWC the ry ceil + Boe bes tr Bh 12. OPERATING &DISPATCH ‘MEMORANLE M State f ARiast COMMITTEE REPORT TO Bradley Project Management oa April 5, 1989 Committee FILE NO: TELEPHONE NO THRU: SUBJECT: Summary of Operations and Dispatch Agreement Committee Meetings March 14, 1989 oe and April 5, 1989 nog FROM: Donald L. Shira, Chairman ,~ Operating & Dispatch Agreément Committee On March 14, 1989 the Operating & Dispatch Agreement Committee met to identify agreements needed for the Bradley Lake Project, and to make assign- ments for drafting the agreements. The following were in attendance: Donald L. Shira, Alaska Power Authority Tom Lovas, Chugach Electric Association (CEA) John Cooley, Anchorage Municipal Light & Power (AML&P) Sam Matthews, Homer Electric Association (HEA) Marvin Riddle, Golden Valley Electric Association (GVEA) The Committee identified eight agreements that are required for the success- ful operation, maintenance and dispatch of the Bradley Lake Project. A list of these agreements and the responsible individuals are listed below: Agreements Responsibility Dispatch Agreement between Power Authority and om Lovas, CEA. Maintenance Agreement between Power Authority Don Shira, Power and Maintenance Contractor. Authority Sam Matthews, HEA Transmission Facilities Maintenance Agreement Sam Matthews, HEA between Power Authority and HEA. Afzal Khan, Power Authority Participants Allocation & Scheduling Agreement All members Substation Maintenance Agreement between Power Sam Matthews, HEA Authority and HEA Afzal Khan, Power Authority Joint Operations Agreement between CEA and HEA Tom Lovas, CEA Sam Matthews, HEA Communications Equipment Agreement between Power Afzal Khan, Power Authority and Division of Telecommunications Authority 5446/DD48(1) Bradley Project Me ement Committee April 5, 1989 Page 2 Soldotna #1 Dispatch Agreement between CEA and AEG&T Sam Matthews, HEA The following list of sample agreements were distributed to members for reference: Alaska Intertie Agreement Among Power Authority, AML&P, CEA, GVEA, and AEG&T Alaska Intertie Maintenance Agreement Between Power Authority and GVEA Alaska Intertie Maintenance Agreement Between Power Authority and AEG&T SCADA Agreement Between Power Authority and CEA SCADA Agreement Between Power Authority and AML&P Transmission Service Agreement Between Power Authority and Matanuska Electric Association (MEA) Operations and Maintenance Agreement for the Tyee Lake Project On April 5, 1989 the Operating & Dispatch Agreement Committee met at CEA to review progress on preparation of agreements. Don Shira, Alaska Power Authority Tom Lovas, Chugach Electric Association (CEA) John Cooley, Anchorage Municipal Light & Power (AML&P) Sam Matthews, Homer Electric Association (HEA) Those in attendance were: The Committee agreed to the following completion dates for agreements to be approved by the PMC: Agreement 1spatch Agreement between Power Authority an CEA. Maintenance Agreement between Power Authority and Maintenance Contractor. a) Timeline for Maintenance personnel b) Final Agreement Transmission Facilities Maintenance Agreement between Power Authority and HEA. Participants Allocation & Scheduling Agreement Substation Maintenance Agreement between Power Authority and HEA Joint Operations Agreement between CEA and HEA Communications Equipment Agreement between Power Authority and Division of Telecommunications 5446/DD48(2) Approval by PMC 6791 6/89 6/90 6/91 6/90 6/91 1/91 9/91 Bradley Project Mé ement Committee April 5, 1989 Page 3 8's Soldotna #1 Dispatch Agreement between CEA and 10/89 AEG&T It was agreed that Agreements 4 and 6 were required to be finalized before completion of Agreement 1. It was further decided that outside assistance would be recommended to prepare the initial draft of the All Participants Allocation & Scheduling Agreement (4). Prior to the next Committee meeting, the participants will prepare detailed schedules for each agreement reflecting key target dates and draft review times including legal review. The committee also reviewed the memorandum of October 31, 1988 from Mike Yerkes to Jim Palin and Ken Ritchey, subject "Outstanding AEG&T/HEA Issues & Concerns". The recommended solutions (remarks) for each item are noted in the margin of the attached copy. It was agreed that the Committee would meet on a regularly scheduled basis to ensure that progress is being made toward the completion dates. The first Friday of every month was established. The next meeting will be at_ AML&P on Friday, May 5 beginning at 10:00 a.m. DLS: it cc: All members 5446/DD48(3) C FF MEMORANDUM DATE: October 31, 1988 TO: Jim Palin Ken Ritchey career at FROM: Mike Yerkes Berne SUBJECT: OUTSTANDING AEG&T/HEA ISSUES AND CONCERNS You asked me to prepare a listing of concern items which should be discussed if additional agreement with HEA is required to provide for construction of the Bradley Junction to Fritz Creek Transmission Line. In preparing this list, | solicited review and input from ML&P, GVEA and CEA engineering types. Many items are covered by existing agreement and may only require some “puritication." Other items may require substantial discussion. The items are briefly summarized as follows: REMARK sya I. Control of HEA transmission facilities related to Bradley Lake power flows. Exist, Gureact A. Soldotna Substation ExisT ConTRACT B. Soldotna Capacitor Bank New AGREEMENT-8 C. Soldotna Unit No. 1 (Generator Dispatch) fo. Diamond Ridge Substation New Acreement-6 | <é. Fritz Creek Substation iF. “Permissive Control" definition ure - Ct + Mares z Intertace with HEA proposed SCADA system Exist. ConTRACT A. Soldotna (CEA) B. Homer (Bradley Project) New Aceeeme uT C. Diamond Ridge (CEA) S566 1D. Scheduling of work BE. Operations and Equipment specifications ~— 3. Access to Another Utility Station . Oo i New ACREEMEWT ii For manual Operation = . (8. Maintenance ( Rounes + Joon Kgect cy) "MEMURANIEME OU ANDING AEG&T/HEA ISSLES ANI INCERNS Page 2 October 31, 1988 REMARK ComPcé TE 4, Bradley Lake O&M definitions - Resolution of HEA problems Com PLETE by Cost/schedule agreement to allow completion ot the Bradley Junction to Fritz Creek Transmission Line prior to Bradley start up. ComPrETE 6, AEG&T/HEA communications and control requirements for O&M A. Cost/Schedule tor Construction of a communications drop into Homer B. Project control/monitoring terminal in Homer is Coordination of protective relaying systems HEA Issu& A. Closing of 69 KV transmission "loops" ComPLeETE B. Ground tault relaying on the Tesoro Interconnection Néw AGREE mE +37 C. Intertace with CEA and Bradley relays Nor APPLICABLE DO. Future relays and coordination policy 8. Detinition of acceptable voltage, frequency, watt and var limits on HEA systems. A. Normal and emergency criteria B. Load balancin NEW ACREE MIE WT ' -6 C. Harmonic correction D. Capacitor compensation in Homer 9. HEA wheeling and other costs to be billed to utilities as a Bradley O&M cost 7o BE INICCI OED wi Transmission line wheeling IN OEM AR ALREALY A B. Transmission Line O&M costs PART OF C. Substation costs. Sm1Sssrard 4 . eae ° D. Communication system changes SERVICES AGREEANE AIT E. SCADA system charges F. Overhead and margin charges Li fl— ike Yerkes bb/358-1.1031.1, .2 13. REVIEW OF PROJECT STATUS BRADLEY LAKE PROJECT STATUS April 5, 1989 Tunnel: The Tunnel Boring Machine (TBM) is operating at an average of more than 100 feet per day. It has progressed 3,000 feet into the tunnel and has reached station number 46+00. Dam Site: The road to the dam site is now open and work on removing overburden from the site began Monday morning April 3089: Penstock: Three penstock thrust blocks have been placed and anchor rods are being tensioned. Powerhouse: H.C. Price has mobilized. Mud slabs have been placed in units 1 and 2 and preparation is underway to start structural concrete work. Transmission Line Clearing has been completed. Transmission Line Construction Bid: The notice of intent to award the contract was issued to Newbery Alaska, Inc. on March 15, 1989. Presently three protests have been lodged. The award is being withheld pending resolution of the protests. 1” 84/86/89 @9:@5 DECISION FOCUS INC 883 pitas Fee eet RECORD UOPY FILE NO _ PRO 37h Lumind 4 lel&4 Uv Section 1 ; INTRODUCTION 1.1 OBJECTIVE The primary purpose of the Railbelt intertie studies undertaken by the Alaska Power Authority (APA) is to assess the economic feasibility of various intertie proposals that have been suggested for the Railbelt, as well as the feasibility of coal-fired power plants, electric end-use conservation programs, and a natural gas pipeline between Anchorage and Fairbanks. The purpose of this report is to present the feasibility results. 1.2 BACKGROUND Statutory direction to undertake these studies was provided in the capital budget passed during the special legislative session in July 1987: The sum of $2,500,000 is appropriated from the Railbelt energy fund in the general fund to the Alaska Power Authority for preparing studies required under AS 44.83.177-44.83.185 for electric interties between the Kenai Peninsula and Fairbanks. This language directs the Alaska Power Authority to perform u feasibility study of Railbelt intertie alternatives. Further action in the 1988 legislative session resulted in a reduction of the appropriation to $2,250,000 and added legislative intent that the feasibility of a proposed natural gas pipeline between Cook Inlet and Fairbanks also be assessed as part of the overull study. The electric intertie projects that were initially identified for review were 1. A new transmission line between Anchorage and the Kenai Peninsula. 2. Upgrade of the existing intertie between Anchorage and Fairbanks to substantially higher transfer capability. RITID 1-1 fa pRarT 44, 25% 04/86/89 @9:@5 DECISION FOCUS INC 204 Decision Focus Incorporated Two additional intertie projects were later added for consideration as alternatives to the proposed upgrade of the Anchorage-Fairbanks line. 3. A new transmission line from Palmer through Glennallen to Delta Junction, where it would connect with the Golden Valley, system in the Fairbanks area. (This project has been referred to as the “Northeast Intertie.") 4. A limited upgrade of the existing Anchorage-Fairbanks iatertie from 70 MW to 100 MW transfer capability. Further, although the statutory direction makes it clear that the intertie projects are intended as the main focus of the study, it was decided that the feasibilily of several other Railbelt energy proposals would also be assessed within the study’s overall framework, specifically as A natural gas pipeline from Cook Inlet to Fairbanks. 2. Coal-fired power plants in the Railhelt. 3. Electric end-use conservation programs (i.e., programs designed to induce higher levels of efficiency among electric energy consumers). 13 FEASIBILITY STUDY OVERVIEW The feasibility assessment of these selected projects and progrums is focused on a comparison of their expected economic costs and benefits. APA assigned the primary task of performing these economic assessments to Decision Focus Incorporated (DFI). The costs of each proposal, as well as certain other inputs Ww the economic analysis such as fuel price and electric demand forecasts, were extublished in advance of the overall economic assessment through a series of studies undertaken by APA in conjunction with other contractors. Several categories of possible benefit have been evaluated for the intertie proposals. These primary benefit categories include: a System Stability. An intertie project may enhance the stability of an electrical system following certain transmission disturbances and, as a result, may either allow greater operating flexibility or the avuidance of uther costs thut would be necessary to provide R117 1-2 pRarr 04/06/89 @9:206 DECISION FOCUS INC 385 Decision Focus Incorporated comparable stability conditions.' This element of the analysis is presented in Section 3. 2. Reliability. Intertie projects can affect system reliability and a value can be attached to estimated improvements. Reliability can be measured by the number, duration, and magnitude of customer outages. Reliability benefits are explored in Section 4. 3. Economy Energy Transfer. Savings are realized when an iutertie project allows more displacement of higher cost energy in one area with lower cost energy imported from another area. This is presented in Section 5. 4. Transmission Efficiency. Improved interties can produce savings tu the extent that transmission losses are reduced. This is also presented in Section 5. 5. Capacity Sharing. An intertie project may allow two or more areas to share capacity and, as a result, an increment of future investment in plant capacity could be deferred or avoided. This is presented in Section 6. 6. Operating Reserve Sharing. Operating reserves are typically maintained to help avoid customer outages. An inlertie project could allow two or more areas to share operuting reserves and therefore reduce operating costs. This is presented in Section 7. The economic feasibility of a coal-fired power plant is assessed by comparing total system cusls over the lung term for scenarios that include the coal plant with scenarios that do not. A 50-MW coal-fired power plant at Healy was selected for evaluation. The impact on project economics of cogeneruling steam to supply a coal drying process was also explored. These issues are presented in Section 8. The economic feasibility of end-use conservation programs cun be similarly assessed. The evaluation was performed with respect Ww the top three end-use programs identified in an earlier screening analysis (presented in Appendix G), and also with respect to the top eight programs identified in that analysis. The evaluation of these programs is presented in Section 9. lin the case of the proposed new intertie between Anchorage and the Kenai Peninsula, the new line would allow the avoidance of certain costs that might otherwise be incurred fur stability considerations. i776 1-3 DRAPT 04706789 9:26 DECISION FOCUS INC 226 Decision Focus Incorporated The economic feasibility of the proposed gas pipeline linking Fairbanks with the Cook Inlet area has been assessed by estimating its impacts both within the electric power sector and also within the residential and commercial heating markets. The power sector analysis is presented in Section 10. Impacts outside the power sector were explored by the Institute of Social and Economic Research (ISER). Section 1i of this report presents the results of their analysis. i This report also includes a comparison of the expected environmental consequences of the projects and programs selected for review. These cumparative assessments are presented in Section 12, which was prepared by Dames & Moore. 1.4 SUMMARY OF FINDINGS Table 1-1 and Figure 1-1 show the expected costs and benefits for each of the eight alternatives selected for evaluation. The totul costs include both the capital costs and the present value of future operations aud maintenance costs. Figure 1-2 shows the expected benefit/cost ratios. The alternatives for which expected benefits exceed costs include: 1. Limited upgrade of the Anchorage-Fairbanks intertie from 70 MW to 100 MW 2. Construction of a natural gas pipeline linking Fairbanks with the Cook Inlet area 3. Electric end-use conservation programs The alternatives for which costs exceed the expected benefits include: ib New intertie between Anchorage and the Kenai Peninsula 2. Full upgrade of the Anchorage-Fairbanks intertie 8. The proposed Northeast intertie linking Anchorage and Fairbanks via Glennallen 4. The proposed 50-MW coal-fired power plant. These findings are presented briefly below in the order (hey appear in Figures 1-1 and 1-2. RIT 1-4 mrt 04/06/89 89:87 DECISION FOCUS INC 207 Decision Focus Incorporated Table 1-1 RAILBELT ALTERNATIVES: COSTS AND BENEFITS Estimated ” Batimated Cost‘ Benefits” {$1987 midiion) ($1887 million) New Kenai Anchorage Intertie 103 39 to 44° Full Upgrade of Anchorage-Fairbanks Intertie 134 96 Limited Upgrade of Anchorage Fairbanks Intertie 9 40 Northeast Intertie 188 159° 50-MW Coal-Fired Power Plant 177 to 2577 102° Gas Pipeline Between Cook Inlet and Fairbanks 284 Se7* Top Three End-Use Conservation Programs 16 24 to 27 Top Bight End-Use Conservation Programs 43 $1 to 57 Notes: a. Includes both capital and O&M costs b. Present value of total benefits between 1994 and 2028 c,. Benefits would be $8-9 million higher if existing line were shut down for maintenance two months per year for the next 35 years, d. Benefits would be $13 million lower if none of the backscatter radar load were supplied by the grid; benefits could be $6 million higher it the Northeast intertie allowed Faicbanks to share in future new capacity in Anchorage. e. Cost does not include any consideration of possible subsidy by the tederal government. f£, Benefits do not include any credit for cugeneration or coal drying. g. Includes all benefits, both within and oulside the electric power sector. i776 1-5 84/86/89 9:87 DECISION FOCUS INC a8 Decision Focus Incorporated Costs and Benefits ($87M) 600 -—— : ; ; = 500 400 300 200 100 ll A _S! : KA AF AF100 NE COAL GAS END3 ENDS Capita Costs $61.7M $118.2M 36.5M 9949.0M $90-160M 8215.2 State Appropnapon $61 7™ $116.2M $6.4M $149.0mM 330.0M 3190.0 $10.7M $29.6M Reaver! HE costs Low Benefits 3 High Benes EST High Costs Note: Each cost column shows expected total costs, including cupital costs and the present value of future O&M costs. Each benefit column shows the present value of future benefits. Additional information is included below each set of columns. First, the estimated cupital cost (expressed in 1987 dollars) is identified for each project except the end-use cumservation programs. The budgetary cost of these programs consists primarily of rebates rather than capital costs. Both a high and a low capital cost estimate is included for the 50-MW coal-fired power plant alternative. Second, an estimate of "Stute appropriation request” is shown to indicate the extent of State funding that either is presently sought or apparently would be sought by project advocates. In the case of the end-use programs, these estimates are equal to total estimated budgetary costs of program implementation over a 10-year period. All of the State appropriation requests also are shown in 1987 dollars, except for the coal plant request which is expressed in today’s dollars. Figure 1-1. Railbelt Alternatives: Costs and Benefits R1776 1-6 DRarT 04/86/89 89:28 DECISION FOCUS INC aas Decision Focua Lncorporated Benatits/Costs ‘| KA AF AF100 NE COAL GAS ENDS ENDS Alternative WB Low B/C ratio RSS High 8/6 ratio Based on expected net benefits for nine base case scenarios. Figure 1-2. Railbelt Alternatives: Benefit/Cost Ratios 1.4.1 New Kenai-Anchorage Intertie This alternative consists of a new 230-KV transmission line between Auchorage and the Kenai Peninsula with a transfer capacity of 250 MW. The capital cost of the proposed Kenai-Anchorage intertie is $81.7 million for the "Enstar" route and $99.4 million for the “Tesoro” route*. This analysis of benefits and costs is based on the lower of these two capital cost estimates. Operations and maintenance cust is estimated at $1.2 million per year. The present value of total costs is estimated at $103.1 million, The expected value of benefits is estimated between $38.8 million and $44.0 million. This consists of benefits in the following six categories: 15 Stability: The new intertie would allow the avoidance of $2.8 million in costs to provide stability with Bradley Lake at peak output. "Unless otherwise noted, these und ull uther costs und benefits are presented in terms of 1987 dollars. R176 1-7 DBAFT 04/06/89 29:88 DECISION FOCUS INC 218 Decision Focus Incorporated 2. Reliability; The value of improved reliability due to the new intertie is estimated between $8.8 million and $14.0 million. 3. Increased Economy Energy Transfer: Savings due to increased transfers between the Kenai Peninsula and Anchorage are estimated at $8.9 million’. 4, Reduced Transmission Losses: Because of its higher transfer efficiency, the new intertie would reduce transmission losses, The value of savings due to reduced transmission losses is estimated at $8.6 million. 5. Increased Capacity Sharing: The improved transmission link would allow Anchorage to rely on a greater portion of the Kenai Peninsula generation capacity surplus for meeting the Anchorage capacity requirement. This value is estimated at $9.0 million. 6. Increased Spinning Reserve Sharing: Improved access to Kenai Peninsula spinning reserves is estimated to produce a value of $0.7 million. It was recently suggested that, in the future, the existing line may be unavailable for transfers during two months each year due to scheduled maintenance. Though insufficient time was available for careful evaluation of this issue, a brief analysis suggests that the benefits of the new intertie would increase by $8 to $9 million if two month per year transfer interruptions for the existing line were assumed over the next 35 years. 1.4.2 Full Upgrade of Anchorage-Fairbanks Intertie to 225 MW This alternative consists of new transmission line segments between Healy and Fairbanks and between Willow and the Wasilla area. Transfer capacity between Anchorage and Fairbanks would be increased to 225 MW. The capital cost of the proposed full upgrade of the Anchorage-Fuirbanks intertie is $118.2 million. The ‘This is far below the estimate presented in the preliminary economic assessment issued by APA in March 1987. The main reason for this is the assumption on natural gas transportation costs. In the 1987 analysis, APA assumed that the cost of transporting natural gas by pipeline from the Kenai Peninsula to Anchorage was essentially variable und cuuld be avuided if trunsport volumes were reduced. Very large benofits were calculated by assuming that, if the new intertie wore built, generation would be moved from Anchorage, where the gas price includes a delivery margin, to the Kenai Peninsula where gas is available at wellhead prices. lowever, although the electric utility may face lower gas prices on the Kenai Peninsula, there is no real cost savings overall because the cust of gas transportation via pipeline is primarily fixed. Lower gas transport volumes do not result in signiticant overall cost reductions. RITI6> 1-8 pmarr 24/786/89 Q@3:a9 DECISION FOCUS INC 11 Decision Focus Incorporated additional operations and maintenance cost is estimated at $0.9 million per year. The present value of total costs is estimated at $133.9 million. The expected value of benefits is estimated at $95.7 million in the following four categories: e 1. Reliability: The value of improved reliability is estimated at $1.4 million. 2. Increased Economy Energy Transfer: Savings due to increased transfers between Anchorage and Fairbanks are estimated at $87.1 million. 8. Reduced Transmission Losses: Because of its higher transfer efficiency, the upgraded intertie would reduce transmission losses. The value of this reduction is estimated at $6.3 million. 4. Increased Capacity Sharing: The upgrade would allow Anchorage to rely on a greater portion of the Fairbanks generation capacity surplus for meeting the Anchorage capacity requirement. This value is estimated at $0.9 million. 1.4.3 Limited Upgrade of Anchorage-Fairbanks Intertie to 100 MW This alternative consists of electrical equipment to provide a limited increase in the transfer capacity of the existing line. Presently, when the maximum of 70 MW is input at one end (typically in Anchorage), 61.6 MW can be received at the other end (typically in Fairbanks). This alternative would allow an additional 30 MW to be input at one end with the result that an additional 22.6 MW would be received at the other end. Transmission losses for this increment would therefore be 25 percent from the sender’s perspective and 33 percent from the receiver’s perspective. The estimated capital cost of this limited upgrade is $8.5 million (again, expressed in 1987 dollars)‘. The expected value of benefits is $39.7 million in the following two categories: 1. Increased Economy Energy Transfer: Savings due to increased transfers between Anchorage and Fairbanks, after adjusting for ‘Operations and maintenance cost has now been estimated at $0.1 million per year. The analysis in this draft report did not incorporate the O&M coat for this alternative. As a result, total costs of the limited upgrade should be increused by $1.8 million, the present value of the estimated O&M costs. However, this added cost is too small to affect the feasibility conclusions. R778» 1-9 DRayt 04/86/89 @9:@9 DECISION FOCUS INC Q@12 Decision Focus Incorporated increased transmission losses, are estimated at $38.8 million. Unlike the full upgrade proposal, transmission losses are increased for this alternative and this increase is accounted for in the estimate of net savings. 2. Increased Capacity Sharing Benefits: As with the full upgrade proposal, these benefits are estimated at $0.9 million. 1.4.4 Northeast Intertie This alternative consists of a new transmission line from Palmer through Glennallen to Delta Junction with a transfer capacity of 150 MW. It would provide an alternate route for transfers between the Anchorage and Fairbanks areas, and would provide the Copper Valley area with access to the Railbelt electric grid. The capital cost of the Northeast intertie is estimated at $149 million (1987 dollars), and the annual operations and maintenance cost is estimated at $2.2 million. The present value of total costs is estimated at $188.1 million. The expected value of benefits is $159.1 million in the following three categories: ie Reliability. The value of improved reliability, primarily in the Fairbanks area, as a result of the Northeast intertie is estimated at $10.3 million. 2: Increased Economy Energy Transfer: Savings due to increased transfers, again adjusting for increased transmission losses, are estimated at $147.9 million. Although the cumbination of the two lines between Anchorage and Fairbanks provides mure efficient transfer than the single line alone, the increase in transfer levels results in a net increase in total expected transmission losses. The expected savings account for transfers both to Fairbanks and to the Copper Valley area for displacement of Copper Valley's diesel generation. 3. Increased Capacity Sharing: As for the other intertie alternatives between Anchorage and Fairbanks, increased capacity sharing benefits are estimated at $0.9 million. These estimates include the assumption in a number of cases that a portion of the electrical load for the backscatter radar facility will be served by the utility grid. If that assumption is removed from the analysis, expected benefits would decline by approximately $13 million. RIT 1-10 DRAFT 04/26/89 @9:18 DECISION FOCUS INC 9 Be UW Decision Focus Incorporated 1.4.6 560-MW Coal-Fired Power Plant A 50-MW coal-fired power plant at Ilealy was selected for evaluation, The possible contribution of cogenerated steam for provision to a coal-drying facility was considered after the power plant economics had been assessed separately. The costs and benefits presented here pertain to a single-purpose power "plant with no cogeneration component. Further, the costs expressed are total costs without any consideration of possible subsidy from the federal government or elsewhere. The power plant economics were reviewed with both a high and a low assumption on capital costs. For the high case, an estimate of approximately $160 million was used as developed for this study by Stone & Webster Engineering Corporation. The low case was based on a total capital cost of $80 million. The fixed O&M expense was assumed to be $5.6 million per year. The fuel cost was assumed at $0.85 per MBtu, reflecting a blend of 50 percent waste coal valued at $0.50 per MBtu and 50 percent standard coal valued at $1.20 per MBtu. The present value of total costs was estimated between $177 million and $257 million. The expected value of benefits is estimated at $102 million in the following three categories: a5 Reduced Energy Costs: These are savings in the variable costs of power generation (ie. fuel and variable O&M costs), and are estimated at $67 million. 2. Reduced Transmission Losses: Because power delivered to Fairbanks from Healy would displace power delivered from Anchorage, transmission losses would be reduced. Approximately 70 percent of the losses between Anchorage and Fairbanks occur on average between Iealy and Fairbanks. The estimule of savings from reduced transmission losses is $4.3 million, 3. Capacity Benefit: Construction of a 50-MW coal plant allows the avoidance of 50 MW of altornative capacity, assumed in this analysis to be combustion turbine capacity. The estimuted value of this capacity benefit is $30 million. If steam were also produced at the plant for provision to au adjacent facility, it is estimated that the cost of production would be $3.65 per MBtu of additional steam. This cogeneration component would add benefit to the vverall plant economics if the value of the steam to the adjacent facility were to exceed $3.65 per MBtu. No estimate of the value of steam to a coal drying facility has been made for this analysis. i778» 1-11 DRAFT 04/86/89 89:18 DECISION FOCUS INC 214 Decision Focus Incorporated 1.4.6 Gas Pipeline Betwecn Cook Inlet and Fairbanks This alternative consists of a natural gas transmission and distribution system linking Fairbanks with the Cook Inlet area. The estimated capital cost is $183 million (1987 dollars) for the main pipeline between Cook Inlet and Fairbanks, plus $32.5 million for the distribution system within Fairbanks. The annual O&M cost is estimated at $3.9 million. The present value of total costs is therefore $284 million. The present value of benefits is estimated at $527 million in the following four categories: 1. Reliability: Electric system reliability would be improved in the Fairbanks area to the extent that local generation is increased and intertie purchases decline. The value of improved reliability is estimated at $5.8 million. 2. Reduced Energy Costs: Variable costs of power production in the Fairbanks area are estimated to decrease as a result of natural gas availability. The value of this reduction is estimated at $95.3 million. 3. Reduced Transmission Losses: Because intertie purchases would be substantially reduced, transmission losses would decline. The value of reduced transmission losses is estimated at $17.8 million. 4, Benefits Outside the Electric Power Seciur: Most of the benefits attributed to the gas pipeline alternative are estimated within the residential and commercial heating sectors in the Fairbanks area due primarily to the substitution of natural gas for fuel oil. The value of these benefits is estimated at $408 milliun. 1.4.7 Electric End-Use Conservation Programs Proposed electric end-use conservation programs were analyzed in two groups: (1) three programs judged to be most economic on the basis of a preliminary economic screening, and (2) all eight programs judged to be promising on a preliminary basis, including the top three. Both the top three and the top eight programs are described here. The top three programs include (1) electric-to-gas water heat conversiuns, (2) efficient fluorescent lamps, and (3) incandescent to fluorescent lamp conversious. Tho top eight programs include, in addition to the three listed above: (4) efficient electric R1776> 1-12 DRAPT Decision Focus Incorporated Section 13 SUMMARY AND CONCLUSIONS 13.1 OVERVIEW This section provides a summary of the overall cost-benefit results for each of the alternatives analyzed in this study. The costs and benefits that have been estimated in the previous sections are aggregated and compared.’ In accordance with the practice followed throughout this analysis, all costs and benefits are expressed in terms of 1987 dollars. The expected value of net benefits for each of the eight alternatives is shown in Figure 13-1. Positive net benefits are estimated for the limited upgrade of the Anchorage-Fairbanks intertie (AF100), the gas pipeline from Cook Inlet to Fairbanks (GAS), and the two groups of end-use conservation programs (END3 and END8). Net economic loss is indicated for each of the other alternatives, including the new Kenai- Anchorage line (KA), the full upgrade of the Anchorage-Fairbanks intertie (AF), the Northeast intertie (NE), and the 50-MW coal-fired power plant at Healy (COAL). Figure 13-2 shows the expected value of costs and benefits for each of the alternatives. The costs of the capital projects include both capital costs and the present value of associated operations and maintenance costs. The difference between the estimates of cost and benefit is the estimate of net benefits. Figure 13-3 presents this information in the form of benefit/cost ratios. The AF100 alternative, which has the lowest total cost, is estimated to provide the highest benefit per dollar expended. lattributes that have not been quantified in the previous sections, such as environmental costs and benefits, are not reflected in these summaries. Further, utility representatives have suggested there may be other less tangible benefits created by the interties such as enhanced competition among fuel suppliers and enhanced siting flexibility. R176 13-1 DRAFT 4-87 35.4 F Decision Focus Incorporated Net Benefits ($M) 300 200 F 100 + — ; . ae z 0 BS mS _— A00 as a = -200 +: aoeste 7 a‘ aeaeees exeey 5 aR RAVRIGERTRERUN AROS -300 1 1 1 = | 4 1 1 1 KA AF AF100 NE COAL GAS END3 END8 Alternative HM Low Net Benefit High Net Benefit Expected net benefits for nine base case scenarios. Figure 13-1. Railbelt Alternatives: Net Benefits Costs and Benefits ($M) 600 500 400 300 200 100 0 KA AF AF100 NE COAL GAS END3 END8 Alternative HE Costs Low Benefits HHH) High Benefits Expected benefits for nine base case scenarios. Figure 13-2. Railbelt Alternatives: Cost and Benefits RI776> 13-2 DRAFT Decision Focus Incorporated Benefits/Costs KA AF AF100 NE COAL GAS END3_ ENDS Alternative MM Low BIC ratio SSS High B/C ratio Based on expected net benefits for nine base case scenarios. Figure 13-3. Railbelt Alternatives: Benefit/Cost Ratios R1776> 13-3 arr Decision Focus Incorporated 13.2 NEW KENAI-ANCHORAGE INTERTIE Table 13-1 shows the present value of costs and benefits for the new Kenai- Anchorage line in each of the categories identified in this analysis. The expected value of net economic loss (i.e., negative net benefits) is between $59.1 million and $64.3 million. The difference between the low and high estimates of benefit reflects only the difference between the high and low reliability benefit. The estimate of total costs is comprised of the capital cost estimate for the "Enstar" route discussed in Section 2 plus the present value of operations and maintenance cost over the analysis period. If the "Tesoro" route were ultimately selected, the capital cost would be $17.7 million higher. Figure 13-4 displays net benefits for each scenario. Figure 13-5 shows the relative contribution of each benefit category to the total expected benefits. Table 13-1 NEW KENAI-ANCHORAGE INTERTIE: SUMMARY OF COSTS AND BENEFITS Increased IncreasedIncreased Economy Reduced Capacity Spinning Total Benefits Net Benefits Energy Trans. Sharing Reserves ----------------- Total = ----------------- Prob Transfer Losses Benefits Sharing Low High Costs Low LL 0.30 8.2 5.2 12.6 0.61 38.2 43.4 103.1 -64.9 ° LM 0.23 7.3 7.58 7.9 0.61 34.9 40.1 103.1 -68.2 . LH 0.06 Ted 8.8 6.4 0.61 34.4 39.6 103.1 -68.7 . ML 0.03 11.2 7.2 12.6 0.84 43.3 48.5 103.1 -59.8 . MM 0.08 10.1 10.1 7.9 0.84 40.4 45.6 103.1 -62.7 . MH 0.19 10.0 12.0 6.4 0.84 40.8 46.0 103.1 -62.3 . HL 0.00 14.0 8.9 12.6 1.06 48.2 53.4 103.1 -54.9 . EM 0.02 12.4 12.5 7.9 1.06 45.5 50.7 103.1 -57.6 . HH 0.08 12.7 14.9 6.4 1.06 46.6 51.8 103.1 -56.5 . eee Seeeees Sees Sees Sees Seeeeees Seeee=== Sseees=e Exp Val 8.9 8.6 9.0 0.72 38.8 44.0 103.1 -64.3 -59.1 weeeeees Saesesss s=eseses seesee=s seeeeees seeesess ssese=e= ssse==s= UL 0.60 6.9 8.1 4.4 0.61 31.6 36.8 103.1 -71.5 -66.3 UM 0.30 9.7 10.9 4.4 0.84 37.4 42.6 103.1 -65.7 -60.5 UH 0.10 12.1 13.5 4.4 1.06 42.7 47.9 103.1 -60.4 -55.2 eeeeees seeesses soessees seseeess seessees eeeeees= =eeesss= =sse=2s= Exp Val 8.2 9.5 4.4 0.72 34.4 39.6 103.1 -68.7 -63.5 mmmees semeeses sessSes5 saeesses Sseeeees seeeesss saeesee= ==se=ss= DOR 7.1 7.6 6.4 0.61 33.3 38.5 103.1 -69.8 -64.6 ™M 7.1 8.7 6.4 0.61 34.4 39.6 103.1 -68.7 -63.5 DE 7.6 is 6.4 0.61 37.3 42.5 103.1 -65.8 -60.6 WH 7.5 7.3 6.4 0.61 33.4 38.6 103.1 -69.7 -64.5 GE 7.3 10.7 6.4 0.61 36.5 41.7 103.1 -66.6 -61.4 Smuwsuesemmomee smmmsess sess=se= S=5=5==5 ssesssse2 SseSessa =s=sese= ===s===5 ===2==== Notes: 1. All values are in 1987 million dollars (present value for discounted at 4.5%/yr). Total benefits include: N Reliability benefits Stability benefits Total costs include capital costs and O&M costs. Net Benefits = Total Benefits - Total Costs. ew RI776> 13-4 DRAFT Decision Focus Incorporated Net Benefits ($M) 75 Base Cases Sensitivity Cases 50+ poeta adaReaacrslasbll ee ieee a LL. Low Fuel / Low Load Ud” Low Fuel / Middle Load 255° LH Low Fuel/ High Load ML Middle Fuel / Low Load ee ee N N RY NY NY BAY HL High Fuel / Low Load N N NAAR f= ss> N \ NAIR INK coe N ; N HN RN N UL Low Fuel Utility Load N N N N N BY] | ut Mice Fost unity Lona N N N WN NBN) | ut Hon Fuel unity Load N N N N N BRN! | 008 Mice ADOR Fuel High Load N N SN NY SN N NM Low Fuel / Hi Load No Mil. Load N N N N N RY | | OH = Low Fuel / High Load Dry Hydro N WH Low Fuel / High Load Wet Hydro ig eI ap ge GE _Low Fusl/ High Load Gas Ese. - LL LM LH ML MM MH HL HM HH UL UM UH DOR NM OH WH GE Scenario Hl Low SSS High Figure 13-4. New Kenai-Anchorage Intertie: Net Benefits Reduced Trans. Loss $8.60M 20% Capacity Sharing $9.00M 20% Spinning Reserve $0.72M 2% Only high reliability benefits are shown. Figure 13-5. New Kenai-Anchorage Intertie: R1776b 13-5 Reliability $14.00M 32% ee Increased Economy Energy $8.90M 20% Stability $2.77M 6% Breakdown of Expected Benefits DRAFT Decision Focus Incorporated 13.3 FULL UPGRADE OF ANCHORAGE-FAIRBANKS INTERTIE TO 225 MW Table 13-2 shows the present value of costs and benefits for the full Anchorage- Fairbanks upgrade to 225 MW. The expected value of net economic loss (i.e., negative net benefits) is $38.2 million. As discussed in Section 5, the benefits are sensitive to the load forecast in the Fairbanks area. Positive net benefits are estimated when the utility load forecast? is combined with either the middle or the high fuel price scenario. Figure 13-6 displays the net benefits estimated for each scenario. Figure 13-7 shows the relative contribution of each benefit category to the total expected benefits. Table 13-2 ANCHORAGE-FAIRBANKS FULL UPGRADE: SUMMARY OF COSTS AND BENEFITS Increased All values are in 1987 million dollars (present value for 1994 Capacity Sharing Total Benefits Benefits 1.1 88.4 1.4 90.0 0.3 99.8 ae 61.3 1.4 76.7 6.3 111.8 1:2 72.2 1.4 90.4 0.3 132.3 ee 0.9 95.7 ee 0.0 111.2 0.0 144.3 0.0 171.0 —=—=—== == 0.0 127.1 === 0.3 99.1 0.3 92.8 0.3 98.6 0.3 100.7 os 89.5 === === through 2028 discounted at 4.5%/yr). Total benefits include a reliability benefit of $1.40 million. Total costs include capital costs and O&M costs. Increased Economy Reduced Energy Trans. Prob Transfer Losses LL 0.30 83.2 2.7 LM 0.23 83.8 3.4 LH 0.06 92.9 5.2 ML 0.03 46.1 sae) MM 0.08 62.2 11.7 MH 0.19 99.7 10.3 HL 0.00 55.0 14.7 HM 0.02 74.8 12.8 HH 0.08 119.7 10.8 === Exp Val 87.1 6.3 es UL 0.60 104.0 5.8 UM 0.30 134.1 8.8 UH 0.10 158.7 11.0 === == Exp Val 118.5 er === DOR 93.6 3.8 NM 86.3 4.8 DEH 91.3 5.6 WH 94.4 4.6 GE 83.3 4.5 === Notes: i. 2. 3. 4. 5. Net Benefits = Total Benefits - Total Costs. Table includes North Pole adjustment. . study (refer to Appendix C). RI776b 13-6 The utility load forecast includes the highest load forecast for Fairbanks that is considered in this DRAFT Decision Focus Incorporated Net Benefits ($M) 78 Base Cases Sensitivity Cases ele EFE é i i k REVERSE a i = i & E i 1 ri L 1 4 4 L 1 4 i 1 1 1 1 LL LM LH ML MM MH HL HM HH UL UM UH DOR NM DH WH GE Scenario Figure 13-6. Anchorage-Fairbanks Full Upgrade: Net Benefits Other Increased $2.30M 2% Economy Energy Reduced Trans. Loss $87.10M 91% $6.30M 7% Other benefits include: Capacity Sharing $0.9M Reliability $1.4M Figure 13-7. Anchorage-Fairbanks Full Upgrade: Breakdown of Expected Benefits RI1776b 13-7 DRAFT Decision Focus Incorporated 13.4 LIMITED UPGRADE OF THE ANCHORAGE-FAIRBANKS INTERTIE TO 100 MW Table 13-3 shows the present value of costs and benefits for the limited Anchorage-Fairbanks upgrade to 100 MW. Positive benefits are indicated for each scenario examined. The expected value of net economic benefit is $31.2 million. Figure 13-8 displays the net benefits estimated for each scenario. Figure 13-9 shows the relative contribution of each benefit category to the total expected benefits. Table 13-3 ANCHORAGE-FAIRBANKS UPGRADE TO 100 MW: SUMMARY OF COSTS AND BENEFITS Increased Increased Economy Reduced Capacity Energy Trans. Sharing Total Total Net Prob Transfer Los Benefits Benefits Costs Benefits LL 0.30 44.2 -3.6 1.2 41.7 8.46 33.2 IM 0.23 40.6 -5.5 1.4 36.5 8.46 28.1 LH 0.06 33.4 11.5 0.3 22.3 8.46 13.8 ML 0.03 25.6 -2.8 1.2 23.8 8.46 15.4 MM 0.08 32.8 -3.7 1.4 30.5 8.46 22.0 MH 0.19 53.1 -8.0 0.3 45.4 8.46 37.0 HL 0.00 29.3 -1.0 1.1 29.4 8.46 21.0 EM 0.02 39.0 -2.4 1.4 38.1 8.46 29.6 HH 0.08 63.1 -6.2 0.3 57.2 8.46 48.8 Eee Sees Seesese= Sess SS Exp Val 44.3 -5.5 0.9 39.7 8.46 31.2 Sees See SS SSE SSeS UL 0.60 41.0 -17.0 0.0 24.1 8.46 15.6 UM 0.30 53.9 -15.8 0.0 38.1 8.46 29.7 UH 0.10 62.0 -15.6 0.0 46.3 8.46 37.9 ees See Sees See Exp Val 47.0 -16.5 0.0 30.5 8.46 22.1 ——= SSesSes= seeesess Sees DOR 32.2 -11.8 0.3 20.8 8.46 12.3 NM 36.2 -8.4 0.3 28.1 8.46 19.6 DH 32.8 -11.6 0.3 21.6 8.46 13.1 WH 33.5 -11.5 0.3 22.4 8.46 13.9 GE 26.1 -9.1 0.3 17.4 8.46 8.9 al See SSE SSS SS » All values are in 1987 million dollars (present value for 1994 through 2028 discounted at 4.5%/yr). 2. Total benefits include: Benefit Reliability benefits 0.00 Stability benefits 0.00 3. Total costs include capital costs and O&M costs. 4. Net Benefits = Total Benefits - Total Costs. 5. Table includes North Pole adjustment. RIT76> 13-8 DRAFT Decision Focus Incorporated Net Benefits ($M) 75 Base Cases Sensitivity Cases DOR Middle ADO Fuel / High Load NM Low Fuel / Hi Load No Mil. Load DH —_Low Fuel / High Load Dry Hydro WH Low Fuel / High Load Wet Hydro GE - 1 1 n 1 1 1 4 1 1 1 1 L ai -75 Hi LL LM LH ML MM MH HL HM HH UL UM UH DOR NM DH WH GE Scenario Figure 13-8. Anchorage-Fairbanks Upgrade to 100 MW: Net Benefits pacer eee ED Capacity Sharing ee $0.90M 2% Increased Economy Energy $38.80M 98% Economy energy benefits include $5.5M of increased transmission losses. Figure 13-9. Anchorage-Fairbanks Upgrade to 100 MW: Breakdown of Expected Benefits 13-9 DRAFT R1776b Decision Focus Incorporated 13.5 NORTHEAST INTERTIE Table 13-4 shows the present value of costs and benefits for the Northeast intertie. The expected value of economic loss (i.e., negative net benefit) is $29 million. As in the case of the full Anchorage-Fairbanks upgrade proposal, the combination of high load forecasts and high fuel prices is needed to produce an estimate of positive economic benefit. Figure 13-10 displays the net benefits estimated for each scenario. Figure 13-11 shows the relative contribution of each benefit category to the total expected benefits. Table 13-4 ANCHORAGE-FAIRBANKS NORTHEAST INTERTIE : SUMMARY OF COSTS AND BENEFITS Increased Increased Economy Reduced Capacity Energy Trans. Sharing Total Total Net Prob Transfer Losses Benefits Benefits Costs Benefits IL 0.30 152.0 -6.0 1.1 157.4 188.1 -30.7 IM 0.23. 134.4 -5.6 1.4 140.5 188.1 -47.6 IH 0.06 8 =©154.1 -4.4 0.3 160.3 188.1 -27.7 ML 0.03 =—-:121.5 S52 1.1 136.0 188.1 -52.0 MM 0.08 119.5 1.6 1.4 132.7 188.1 -585.3 MHO.19 =-:169.7 -1.3 0.30 «179.0 188.1 -9.0 HL 0.00 138.5 2.9 1.1 152.8 188.1 -35.3 HM 0.02 =: 140.2 0.9 1.4 152.8 188.1 -35.3 HH 0.08 200.2 -2.5 0.3 208.4 188.1 20.3 EE SS A So Exp Val 151.5 -3.6 0.9 159.1 188.1 -29.0 a SS —_— UL 0.60 158.0 -3.9 0.0 164.4 188.1 -23.7 ™ 0.30 195.9 -3.9 0.0 202.2 188.1 14.2 UH 0.10 217.8 -4.2 0.0 224.0 188.1 35.9 EE SS Se Sams Exp Val 175.3 -3.9 0.0 181.7 188.1 -6.4 A A DOR 151.3 -4.0 0.3 158.0 188.1 -30.1 MM 146.3 -4.3 0.3. 152.6 188.1 -35.5 DH 174.0 -4.0 0.3 180.6 188.1 -7.4 WH 161.0 -4.8 0.3 166.9 188.1 -21.2 219.7 -5.2 0.30 225.1 -188.1 9751 a A SS A Se Ss e tes: » All values are in 1987 million dollars (present value for 1994 through 2028 discounted at 4.5%/yr). Total benefits include a reliability benefit of $10.30 million. Increased economy energy transfer is based on: Railbelt average variable O&M of ICEs (6.05 $/MWh) Total costs include capital costs and O&M costs. Net Benefits = Total Benefits - Total Costs. Table includes North Pole adjustment. ane wn R176 13-10 DRAFT Decision Focus Incorporated Net Benefits ($M) 75 Base Cases Sensitivity Cases EEFEEFSEF| f i Low Fuel / Low Load Low Fuel / Middle Load Low Fuel / High Load Middle Fuel / Low Load Middle Fuel / Middle Load Middle Fuel / High Loed High Fuel / Low Load High Fuet / Middle Load High Fuel / High Load RELERSE -75 U4 1 4 4 iz 1 1 1 1 4 1 4 1 L 4 4 4 lL LM LH ML MM MH HL HM HH UL UM UH DOR NM DH WH GE. Scenario Figure 13-10. Northeast Intertie: Net Benefits : 7 Utility Load Middle Fuel / Utility Load High Fuel / Utility Load Mididie ADOR Fuel / High Load Low Fuel / Hi Load No Mil. Load Low Fuet / High Load Dry Hydro Low Fuel / High Load Wet Hydro Low Fuel / High Load Gas Esc. Increased Economy Energy $147.90M 93% Capacity Sharing % ReliSbi oy ' $10.30M 6% Economy energy benefits include $3.6M of increased transmission losses. Figure 13-11. Northeast Intertie: Breakdown of Expected Benefits RI776b 13-11 DRAFT Decision Focus Incorporated 13.6 50-MW COAL-FIRED POWER PLANT AT HEALY Table 13-5 shows the present value of costs and benefits for the 50-MW coal- fired power plant at Healy. The expected value of economic loss (ie., negative net benefit) is between $75.9 million and $155.6 million. The difference between the low and high benefit estimates is due entirely to the capital cost estimate of the power plant. These results were based on the economics of a single-purpose power plant as discussed in Section 8. The plant economics would improve if the value of cogenerated steam to a steam purchaser (such as the operator of a coal drying facility) exceeded the incremental cost of producing the additional steam. The possibility of federal subsidy has been raised in conjunction with the proposed coal plant. This analysis has not considered such a subsidy. If there were a subsidy, it could make a substantial difference in the price of power to potential power purchasers. Figure 13-12 displays the net benefits estimated for each scenario. Figure 13-13 shows the relative contribution of each benefit category to the total expected benefits. Table 13-5 50-MW COAL-FIRED POWER PLANT AT HEALY: SUMMARY OF COSTS AND BENEFITS Reduced Reduced Total Costs Net Benefits Energy Trans. Capacity Total ---------------- ---------------- Prob Costs LL 0.30 43.9 3.1 30.0 77.0 177.4 257.1 -100.4 -180.1 LM 0.23 46.4 3.3 30.0 79.7 177.4 257.1 ~97.7 -177.4 LH 0.06 53.9 4.4 30.0 88.3 177.4 257.1 -89.1 -168.8 ML 0.03 75.4 5.1 30.0 110.5 177.4 257.1 -66.9 -146.6 MM 0.08 86.3 5.3 30.0 121.5 177.4 257.1 -55.9 -135.6 MH O.19 90.5 5.7 30.0 126.2 177.4 257.1 -51.3 -130.9 HL 0.00 115.0 6.1 30.0 151.1 177.4 257.1 -26.4 -106.0 EM 0.02 129.1 6.0 30.0 165.0 177.4 257.1 -12.4 -92.1 HH 0.08 134.8 6.1 30.0 170.9 177.4 257.1 -6.5 -86.2 =ESEEEES EEESSess sesecses Sseeeesss Seesess= seeeses= =eee=== Exp Val 67.3 4.3 30.0 101.5 177.4 257.1 -18.9 -155.6 =EEEEESS Seseeses sesesess seeeess= seeeeses seeseess seee=so= UL 0.60 52.7 5.3 30.0 88.0 177.4 257.1 -89.4 -169.1 UM 0.30 96.3 6.6 30.0 132.8 177.4 257.1 -44.6 -124.3 UH 0.10 142.3 7.8 30.0 179.7 177.4 287.1 2.3 -77.4 =EEEEESS Saaesscss scoeses=s ssesess= =s=eese== =ssesese= ======== Exp Val 74.7 5.9 30.0 110.6 177.4 257.1 -66.8 -146.5 =_uEEEEES SEESESes sesseses =see==== =eeeee== ===s==== DOR 30.9 4.2 30.0 65.0 177.4 257.1 -112.4 -192.1 NM 53.1 4.0 30.0 87.0 177.4 257.1 -90.4 -170.1 DEH 54.8 4.5 30.0 89.3 177.4 257.1 -88.1 -167.8 WH $1.1 4.4 30.0 85.5 177.4 257.1 -92.0 -171.6 87.6 3.7 30.0 121.3 177.4 257.1 -56.2 -135.8 Notes: 1. All values are in 1987 million dollars (present value for 1994 through 2028 discounted at 4.5%/yr). 2. Total costs include: Cost Low Hi Capital ($/KW) 1600.00 3194.00 Fixed O&M ($M/yr) 5.58 5.58 3. Capacity benefits are based on $39/kW-yr (including Fixed O&M). 4. Net Benefits = Total Benefits - Total Costs. 5. Table includes North Pole adjustment. R1776> 13-12 DRAFT Decision Focus Incorporated Net Benefits ($M) 200 Base Cases Sensitivity Cases 100 Por = . cial LL Low Fuel / Low Load Ud Low Fuel / Middle Load LH Low Fuel / High Load ML Middle Fuel / Low Load MM Middle Fuel / Middle Load MH Middle Fue! / High Load HL HM J 55 High Fuel / Low Load N IN| is _ eer N N ae N N UL Low Fuel / Utility Load N N UM — Middle Fuel / Utiity Load N N UH High Fuel / Utility Load N N DOR Middle ADOR Fuel / High Load NY NN NM Low Fuel / Hi Load No Mil. Load S No] i peso, 1 L L L GE Low Fuel / High Load Gas Esc. LL LM LH ML MM MH HL HM HH UL UM UH DOR NM DH WH GE Scenario MB High SS tow Figure 13-12. 50-MW Coal-Fired Power Plant at Healy: Net Benefits Reduced Energy Costs $67.30M 66% Reduced Trans. Loss $4.30M 4% Capacity Benefits $30.00M 30% Figure 13-13. 50-MW Coal-Fired Power Plant at Healy: Breakdown of Expected Benefits RI1776b 13-13 DRAFT 13.7 Decision Focus Incorporated COOK INLET-FAIRBANKS GAS PIPELINE Table 13-6 shows the present value of costs and benefits estimated for the gas pipeline from Cook Inlet to Fairbanks. The expected value of economic benefit is $243 million. Positive benefits are estimated for every scenario. Nearly 80 percent of the estimated benefits accrue outside the electric power sector, i.e., primarily in the residential and commercial heating sectors in the Fairbanks area. Figure 13-14 displays the net benefits estimated for each scenario. Figures 13-15 and 13-16 show the allocation of benefits between the power and non-power sectors. R1776b Notes: Table 13-6 COOK INLET-FAIRBANKS GAS PIPELINE: SUMMARY OF COSTS AND BENEFITS Reduced Reduced Energy Trans. Prob Costs Losses LL 0.30 80.9 15.0 IM 0.23 93.6 17.7 LH 0.06 105.0 20.4 ML 0.03 53.1 14.9 MM 0.08 72.2 16.6 MH 0.19 116.7 21.0 HL 0.00 62.6 15.8 EM 0.02 85.6 17.1 HH 0.08 137.9 21.6 —== Exp Val 95.3 17.8 —— UL 0.60 123.0 21.8 UM 0.30 155.2 24.6 UH 0.10 180.6 27.0 === Exp Val 138.4 23.2 === DOR 110.0 19.3 NM 97.4 19.4 DE 107.4 20.6 WH 103.1 20.0 GE 90.3 16.2 1. 2. 3. All values are in 1987 million dollars (present value for Outside Elec Power Sector Total Total Net Benefits Benefits Costs Benefits 414.0 515.8 284.1 231.7 426.0 543.1 284.1 259.0 462.0 593.1 284.1 309.1 334.0 407.8 284.1 123.7 349.0 443.6 284.1 159.5 389.0 532.5 284.1 248.4 371.0 455.2 284.1 171.1 388.0 496.5 284.1 212.5 432.0 597.3 284.1 313.2 =Seass= Sees sees See 408.4 527.3 284.1 243.3 eee Sees Sees Se 462.0 612.6 284.1 328.5 389.0 574.6 284.1 290.6 432.0 645.4 284.1 361.3 eee Sees see Se 437.1 604.5 284.1 320.4 =sssees seesessse= sees === 462.0 597.1 284.1 313.0 462.0 584.6 284.1 300.5 462.0 595.8 284.1 311.7 462.0 590.9 284.1 306.8 351.0 463.3 284.1 179.2 1994 through 2028 discounted at 4.5%/yr). Total benefits include a reliability benefit of $5.80 million. Total costs include capital costs, O&M costs and the following costs/benefits: Conversion costs of FMUS Chena 5 = $950,000, conversion costs of North Pole = $1350,000, and reduced O&M costs for FMUS = $595,000 Net Benefits = Total Benefits - Total Costs. Table includes North Pole adjustment. Benefits outside the electric power sector for the DOR Fuel, NoMiltry, DryHydro, and WetHydro sensitivity cases are estimated based on the Low Fuel/High Load scenario. 13-14 DRAFT Decision Focus Incorporated Net Benefits ($M) “agtlity ght aatgtaty ayn —_ Tete ats leee Bea geese adedyans | | il Siateer Ieasinars 923599522 315338 Reliability $5.80M 1% Reduced Energy Costs $113.10M 21% thin Versus Outside the Electric e: Net Benefits GE ; ; ULLZITZLILLLLLLLLLLLL LLL = Benefits ($M) (LLLLZZLLLLTLLLLLLLL LLL, 4 400 300 200 100 0 100 F -200 + 300 F -400 2888 8 8 ° 3 = = a a .* Z 2 4 as a = 8 9 3 =o z a 3 & yA a 3 ab : Dag ° 2 WLLL LLL Ld gggegieg € 3.2 5 32 6 ° z & VLLZZIZILLLL LLL LALA gL z 2 Z a Pa * QD a z 8 w (ZZZZLZZLZZZZLLLLLL LS 8 3 j 7 8 (ZLL7LITILILLLL LAL zZ & Fs = o z 3 & 83 z Z CLLLZZZZZZZZZLI A & 2 a i z iq CLZIZLZTZZLZLL LLL z 8 g 5 3 (LLZZZTTTZLLL LLL LLL A x i 6 3 = 3 8 A Breakdown of Expected Benefits 13-15 line: ipe: Reduced energy costs include reduced transmission losses. Reduced O&M costs of $0.6M for FMUS not shown. Gas Pi Figure 13-16. R1776b 13.8 END-USE CONSERVATION PROGRAMS Decision Focus Incorporated Table 13-7 shows the present value of resource costs and benefits for the top three end-use programs. for all scenarios. The expected value of economic benefit is between $8.0 million and $10.5 million for the top three programs. Positive benefits are estimated The difference between the low and high benefit estimate is due entirely to alternative values assigned to avoided generation capacity savings. Figures 13-17 and 13-18 display net benefits for each scenario and the breakdown of benefits into their main categories. Table 13-7 TOP THREE END-USE PROGRAMS : SUMMARY OF COSTS AND BENEFITS Reduced Reduced Capacity Value Total Benefits Net Benefits Low High 5.60 8.09 6.10 8.59 6.94 9.43 8.75 11.24 9.52 12.01 12.63 15.12 13.92 16.41 7.98 10.47 7.32 9.81 11.21 13.70 14.73 17.22 9.23 11.72 for 1994 through Betegy 4 6—TERRB weet nr saa) Sennenaesensese== Total Prob Costs Losses Low High Low High Costs LL 0.30 0.12 4.71 7.20 21.02 23.51 15.42 LM 0.23 0.19 4.71 7.20 21.52 24.01 15.42 LH 0.06 0.19 4.71 7.20 22.36 24.85 15.42 ML 0.03 0.27 4.71 7.20 25.53 28.02 16.78 MM 0.08 0.26 4.71 7.20 26.30 28.79 16.78 MH O.19 0.26 4.71 7.20 27.45 29.94 16.78 HL 0.00 0.21 4.71 7.20 29.77 32.26 18.01 EM 0.02 0.08 4.71 7.20 30.64 33.13 18.01 HH 0.08 0.17 4.71 7.20 31.93 34.42 18.01 Seessass saessss Sssss555 S5555555 Ss25S555 S=e==555 Exp Val 19.17 0.19 4.71 7.20 24.07 26.56 16.09 NS ———————————————————— UL 0.60 17.86 0.17 4.71 7.20 22.74 25.23 15.42 UM 0.30 23.05 0.23 4.71 7.20 27.99 30.48 16.78 UH 0.10 27.85 0.18 4.71 7.20 32.74 35.23 18.01 Seeeescs seessaes seesess= S==SS5e5 Ss=Ssee5 seeeaa== Exp Val 20.42 0.19 4.71 7.20 25.32 27.81 16.09 EEE DOR 14.99 0.05 4.71 7.20 19.75 22.24 14.68 NM 17.26 0.22 4.71 7.20 22.19 24.68 15.42 DH 17.66 0.20 4.71 7.20 22.57 25.06 15.42 WH 17.36 0.20 4.71 7.20 22.27 24.76 15.42 GE 20.04 0.13 4.71 7.20 24.88 27.37 15.42 guEGEEES soseeces =s55555= =====555 s=-s5555 =2=2=55= Notes: i. All values are in 1987 million dollars (presént value discounted at 4.5%/yr). 2. Total benefits include: Benefit Reliability benefits 0.00 Stability benefits 0.00 3 Capacity value is 50.7$/KW-yr (High) and 33.2$/KW-yr (Low) 4. Total costs include capital costs and O&M costs. 5. Net Benefits = Total Benefits - Total Costs. - R1776b 13-16 2028 DRAFT Decision Focus Incorporated Net Benefits ($M) 30 Base Cases Sensitivity Cases 20r | Foaitawtaes Low Fuel / Low Load Low Fuel / Middle Load Low Fuel / High Load Middie Fuel / Low Load Middie Fuel / Middle Load Middle Fue! / High Load High Fuel / Low Load High Fuel / Middle Load High Fuel / High Load ‘Sensitivity Low Fuel 7 Utility Load Middle Fuel / Utility Load High Fuet / Utility Load Middie ADOR Fuel / High Load Low Fuet / Hi Load No Mil. Load Low Fuel / High Load Dry Hydro Low Fuel / High Load Wet Hydro Low Fuel / High Load Gas Esc. EEZFERETEE! f aevegeer 1 4 L 1 if. 4 n pes -30 1 1 1 4 4 i 1 LL LM LH ML MM MH HL HM HH UL UM UH DOR NM DH WH GE Scenario ME Low High Figure 13-17. Top Three End-Use Programs: Net Benefits Reduced Energy Costs $19.17M 72% Reduced Trans. Loss $0.19M 1% Capacity Benefits $7.20M 27% Only high capacity benefits are shown. Figure 13-18. Top Three End-Use Programs: Breakdown of Expected Benefits R1776b 13-17 DRAFT Decision Focus Incorporated 13.9 END-USE CONSERVATION PROGRAMS Tables 13-8 shows the present value of resource costs and benefits for the top eight end-use programs. The expected value of economic benefit is between $8.0 million and $13.7 million for all eight programs. Positive benefits are estimated for all scenarios. The difference between the low and high benefit estimate is due entirely to alternative values assigned to avoided generation capacity savings. Figures 13-19 and 13-20 display net benefits for each scenario and the breakdown of benefits into their main categories. Table 13-8 TOP EIGHT END-USE PROGRAMS : SUMMARY OF COSTS AND BENEFITS Reduced Reduced Capacity Value Total Benefits Net Benefits Energy TANS. annem nnn nnn nnn wenn nnn n-ne Total = ----------------- Prob Costs Low High Low High Costs Low High LL 0.30 33.43 0.27 10.89 16.65 44.59 50.35 42.25 2.34 8.10 LM 0.23 34.58 0.46 10.89 16.65 45.93 51.69 42.25 3.68 9.44 LH 0.06 36.65 0.56 10.89 16.65 48.10 53.86 42.25 5.85 11.61 ML 0.03 42.71 0.70 10.89 16.65 54.30 60.06 44.81 9.49 15.25 MM 0.08 44.59 0.59 10.89 16.65 56.07 61.83 44.81 11.26 17.02 MH 0.19 47.51 0.74 10.89 16.65 59.14 64.90 44.81 14.33 20.09 HL 0.00 52.09 0.68 10.89 16.65 63.66 69.42 47.20 16.46 22.22 HM 0.02 54.36 0.37 10.89 16.65 65.62 71.38 47.20 18.42 24.18 HH 0.08 57.82 0.45 10.89 16.65 69.16 74.92 47.20 21.96 27.72 =EGEEEES SaesmeES sosessss s=ssse== sseeces= sesesse= =sssese= =sss==== Exp Val 40.12 0.48 10.89 16.65 51.48 57.24 43.51 7.97 13.73 SeeSSSS seseeses seeesses seeeeses Seeeesss saeesse= seesese= ==see=== UL 0.60 37.63 0.38 10.89 16.65 48.90 54.66 42.25 6.65 12.41 UM 0.30 52.02 0.53 10.89 16.65 63.44 69.20 44.81 18.63 24.39 UH 0.10 59.76 0.50 10.89 16.65 72.18 76.91 47.20 23.95 29.71 ==amE=SS Saeeeees seeeesss secesses soeersss sseesse= seeeeses sasce=== Exp Val 44.16 0.44 10.89 16.65 55.49 61.25 43.51 11.97 17.73 SeSnSSSS seessse= seecses= seesees= seeeeses seeeess= seeeese= ======== DOR 30.65 0.15 10.89 16.65 41.69 47.45 40.86 0.83 6.59 NM 35.95 0.62 10.89 16.65 47.46 53.22 42.25 5.21 10.97 DE 37.05 0.52 10.89 16.65 48.46 54.22 42.25 6.21 11.97 WH 36.25 0.56 10.89 16.65 47.70 53.46 42.25 5.45 11.21 GE 40.52 0.10 10.89 16.65 51.51 57.27 42.25 9.26 15.02 =umEEESS aumeeess seessse= =sessee= seeeees= sseesces seeecses saseacce Notes: 1. All values are in 1987 million dollars (present value for 1994 through 2028 discounted at 4.5%/yr). 2. Total benefits include: Benefit 0.00 Stability benefits 0.00 Ss Capacity value is 50.7$/KW-yr (High) and 33.2$/KW-yr (Low) 4. Total costs include capital costs and O&M costs. 5. Net Benefits = Total Benefits - Total Costs. RIT776b 13-18 DRAFT Decision Focus Incorporated Net Benefits ($M) 30 20 f F Low Fuel / Low Load Low Fuel / Middte Load Low Fuel / High Load Middle Fuel / Low Load Middle Fuel / Middle Load Middle Fuel / High Load High Fuel / Low Load High Fuel / Middle Load High Fuel / High Load Low Fuel / Utility Load Middle Fuel / Utility Load High Fuel / Utility Load Middle ADOR Fuet/ High Load || Low Fuel / Hi Load No Mil. Load Low Fuel / High Load Ory Hydro Low Fuel / High Load Wet Hydro Low Fuel / High Load Gas Esc. || 10 LLLLLLLLL LLL LLB VLLLLLLLLLLL LLL LL [EEZEEESEF Base Cases Sensitivity Cases REPERSES -go W4—2 11 -- 4-1 1 st td Lt tM LH ML MM MH HL HM HH UL UM UH DOR NM DOH WH GE Scenario Hl Low SSS High Figure 13-19. Top Eight End-Use Programs: Net Benefits Reduced Energy Costs $40.12M 70% Reduced Trans. Loss $0.48M 1% Capacity Benefits $16.65M 29% Only high capacity benefits are shown. Figure 13-20. Top Eight End-Use Programs: Breakdown of Expected Benefits RI776> 13-19 DRAFT Decision Focus Incorporated 13.10 OTHER PROPOSALS AND COMMENTS 13.10.1 Modified Intertie Proposals Railbelt utilities submitted two modified intertie proposals to us for review near the end of March. Golden Valley Electric Association (GVEA) has proposed construction of a new 138-KV line between Healy and Fairbanks in conjunction with the limited upgrade of the Anchorage-Fairbanks intertie (AF100) evaluated in this study. Chugach Electric Association (CEA) has proposed construction of a new 138-KV line between Soldotna and Anchorage rather than a new 230-KV line.® Time constraints did not allow detailed analyses of these proposals. It appears that the modified Kenai-Anchorage proposal from CEA would cost less than the 230-KV alternative, but would also achieve lower benefits in the form of reduced transmission losses. The GVEA proposal would apparently reduce transmission losses between Healy and Fairbanks. Estimates of the economic viability of these two proposals will be provided in the final report. 13.10.2 Existing Kenai-Anchorage Line: Two Month per Year Interruptions for Maintenance In the same letter, CEA stated that the system modeling should reflect the idea that the existing Kenai-Anchorage transmission line will be unavailable for transfers for two months per year during the summer due to long-term maintenance. Chugach suggested that these interruptions in transfer capability be assumed to begin in 1994, the first year of the model simulation, and extend for the following ten years. Further, the analysis attached to the letter reflected continuing one month per year scheduled interruptions extending from 2005 (the end of the initial ten-year period) through 2028 (the last year of the simulation). Again, this idea was not expressed in time to receive careful consideration or scrutiny in this analysis. To evaluate the impact of this possibility, the preferred approach would be to incorporate the new constraint into the simulation modeling and examine the results. Although that approach was not possible given the date the issue was raised, we did make some rough calculations to estimate what the impact of this possibility would be on the new Kenai-Anchorage feasibility results. We considered the following benefit categories. ls Stability: We see no impact on the stability benefits attributed to the new intertie. 3Letter from Gerald M. Mackey (CEA) to Salim J. Jabbour, March 20, 1989. RI776> 13-20 DRAFT R1776b Decision Focus Incorporated Reliability: For the scenario with the existing line, reliability would probably improve to the extent that the line is unavailable for transfers and to the extent that the preventive maintenance program is successful. Outages in Anchorage and Kenai caused by failure of the existing line while transfers are occurring, would be avoided for two months per year. Reducing the reliability benefit of the new intertie by one-sixth would mean a reduction of $1 to $2 million in net benefits for the new Kenai-Anchorage line. Capacity Sharing: Because the interruptions would be scheduled and would occur during the off-peak months, there should not be any impact on the capacity sharing value of the existing line. Consequently, the capacity sharing benefit of the new line should be unaffected. Economy Energy and Reduced Transmission Losses: Economy energy benefits of the new line would increase and the transmission loss benefit would be slightly lower. This is because there would be lower losses in the “existing intertie" case to be reduced by the new intertie. Table 13-9 summarizes the first step in estimating the magnitude of change in economy energy benefit. The average value of each unit of increased economy energy transfer is estimated for three selected years based on the simulation results presented in Section 5. The next step is to estimate the value of transfer benefit lost in the “existing line" scenario due to the two-month interruptions, as shown in Table 13-10. This value can then be added to the net benefits of the new intertie, since these transfers would occur with the new line but not with the existing line. For this estimate, we assume a two-month interruption for every year between 1994 and 2028. The "lost transfer benefits" for the existing line shown in Column D in Table 13-10 due to the 2 month interruptions can be used as estimates of the increased transfer benefits of the new line. The annual increase in benefit from 1994 through 2010 was estimated by interpolating between the three selected years calculated in Tables 13-9 and 13-10. The value from 2011 through 2028 was assumed to be the same as 2010. The present value of this stream was then calculated at a 4.5 percent real discount rate, yielding an estimated increase in net benefit of $7.3 million. 13-21 DRAFT Decision Focus Incorporated Table 13-9 AVERAGE VALUE OF INCREASED ECONOMY ENERGY TRANSFER Change in Kenai-Anchorage Transfers Due to New Line’ Transfer Benefits Due To New Line’ (Gwh/yr) ($_million/yr) $/MWh 1994 89.6 OS 5:6 2002 90.1 0.5 S15 2010 Tso 0.6 Tad, Includes both south to north and north to south transfers. Also includes hydro-thermal coordination transfers. Does not include reduced transmission loss benefits. Table 13-10 VALUE OF TWO-MONTH TRANSFER BENEFIT (A) (B) (Cc) (D) Lost Kenai- Lost Transfer Anchorage Benefits Kenai-Anchorage Transfers Due Lost Adjusted For Transfers’ With to 2 Month Transfer Transmission Existing Line Interruptions’? Benefit’ Losses‘ (GWh/yr) (GWh/yr) ($/Mwh) ($million/yr) 1994 356.4 59.4 5216 0.326 2002 37135 61.9 Sas 0.334 2010 413.3 68.9 aie! 0.520 Includes both south to north and north to south transfers. Also includes hydro-thermal coordination transfers. One sixth of Column A. Based on transfer benefits due to new line. Does not include reduced transmission loss benefits. Column B multiplied by Column C. Product reduced by two percent transmission losses of new line. RIT76> 13-22 DRAFT 5. Operating Reserve Sharing: For the scenario with the existing line, an annual two-month outage would reduce the time when operating reserves can be transferred from Kenai to Anchorage. We estimate this reduction at 517 hours per year. Decision Focus Incorporated This change in line availability is not sensitive to load growth. The lost benefit to the existing line scenario would increase the net benefits of the new line by the amounts shown in Table 13-11. The net result of these rough calculations would be to increase the net benefits estimated for the new Kenai-Anchorage line by $8 million to $9 million, given a two- month transfer interruption for maintenance on the existing line from 1994 through 2028. This estimate is comprised of (1) $7.3 million for economy energy transfer, (2) minus $1 to $2 million for reliability value, and (3) $2 to $4 million for spinning reserves. With this adjustment, the Kenai-Anchorage new intertie would have an expected net economic loss of $50 million to $55 million. Table 13-11 IMPACT OF TWO-MONTH OUTAGE ON OPERATING RESERVE BENEFIT 1994 2002 2010 Present Value Impact 1994-2028 R1776b Lost Benefit ($ million) Low Mid Fuel Fuel 0212 o.45 0212 0.16 0.14 0.18 2.09 2.88 13-23 High Fuel Ooty 0.20 0.23 3.60 DRAFT