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S Intertie report 9-1997
rack ASSOCIATION, INC. P.O. BOX 196300 ANCHORAGE, AK 99519-6300 CHUGACH ELECTRIC fn ASSOCIATION, INC. IN gach ASSOCIATION, INC. September 30, 1997 IN an erin es 1 Alaska Industrial Development Alaska Industrial Development and Export Authority and Export Authority 480 West Tudor Road Anchorage, Alaska 99503-6690 Attention: Mr. Randy Simmons, Executive Director Subject: Southern Intertie Monthly Report for September 1997 W.0.#E9590081 Dear Mr. Simmons: Please find enclosed 1 (one) copy of the Southern Intertie Report for the Month of September 1997. If there are any questions, please contact Dora Gropp, (907) 762-4626. MU tht Eugene N. Bjornstad General Manager Sincerely, ENG. cahw Enclosures: 1 (one) copy of Southern Intertie Monthly Report c: Lee Thibert Joe Griffith Michael Massin Dora Gropp Jim Borden Mike Cunningham Don Edwards W.O0.#E9590081, Sec., 2.1.3 RF 5601 Minnesota Drive * P.O. Box 196300 * Anchorage, Alaska 99519-6300 Phone 907-563-7494 * FAX 907-562-0027 CHUGACH ELECTRIC ASSOCIATION, INC. Anchorage, Alaska SOUTHERN INTERTIE Report for the Month of SEPTEMBER 1997 Il. Ill. VI. Report for the Month of September 1997 W.0.#E9590081 Southern Intertie - Phase IB September 30, 1997 TABLE OF CONTENTS Page SUMMARY) ieieliclie eo cl cl's s) schauels mre wel 4 ol of elleiicte lets © o Sialsiedeiielislio wie @ im I-1 RIINAN GTA Ua irerreteitorcere! leo) 5) alieltaitencons ralfe fo 01 61 oF off onferieiistte yore "sre)' oi o}iey cu ehaentsiteriartotre Il-1 af Total Project Expenditures as of August 1997 2s Chugach Statement for August 1997 3) Bank Statement of August 1997 SCHEDULE oo) o le; sicticte le & a a) on a Hirriiort @ (wi 0) e) ticeitelisyfensieisiaie os siaia a aie Iil-1 ITEMS FOR APPROV ADs eiiicj oreo oe) sisters erie foto oe} etlosloiisnsisisie 6 61s 664.6 IV-1 None TTEMS FOR DISCUSSION) tsi )6 6.0.4) 0) 0: orerisiione seo 0) a)/9) si sl.esiisy's fs (W166 20 V-1 None TEEMS FORUINFORMATION (icc cic o a siclons @ < Wile leile 4! wi elley incl ejicile oe VI-1 Le POWER Engineers’ Monthly Report Phase IB - Environmental Analysis, September 17, 1997 Cooperative Agreement between RUS and IPG Purpose and Need Narrative Elimination of Quartz Creek Route Utility Concurrences DFI - Update of Feasibility Study, Utility Concurrences U2 tS ii Report for the Month of September 1997 W.0.#E9590081 Southern Intertie - Phase IB September 30, 1997 IL SUMMARY RUS will utilize The Mangi Environmental Group, which is under retainer to a federal agency, to assist in preparation of the EIS. The project team met in Washington, D.C. to brief Mangi on the status of the project. Mangi representatives and RUS staff will travel to Alaska to conduct a field visit, meet with Federal, State and Municipal agencies, as well as attend Community Working Group meetings during the week of September 29, 1997. The Municipality of Anchorage has expressed interest in becoming a cooperating agency /[ ay. | ¥) in the EIS preparation. The Scoping Report has been finalized and distributed. Lt Wi | aptroy The cost/benefit study of 1990 has been updated by DFI and has been distributed. POW Since possible benefits from BESS or SMES systems as well, impacts of changed system operations have not been taken into account, this work has been added to the study effort. We have also added an investigation of the project’s impact on rates to the DFI task. This effort will only address concerns voiced during the scoping process and not extend into the rate structure of each of the participating utilities. NERC has agreed to review the 1990 reliability assessment of the Railbelt electric system. Delay in the data collection will result in completion of this update by the end of September. IPG staff will meet with EPRI on September 25 and 26, 1997 to further discuss reliability issues related to the interties. The final Community Working Group meetings will be held on September 29, 1997 (Kenai) and October 1, 1997 (Anchorage). The Consultant’s schedule continues to show the effects of delays encountered in bringing the federal agencies together in the scoping , inventory and impact assessment tasks, standing at 73% completion compared to 84% planned. The Environmental Analysis (EVAL) is now estimated to be completed in October 1997. We are investigating, whether the Applicant (IPG) has to declare a preferred route at that time. I-1 DESCRIPTION BUDGET ALLOCATED CONTINGENCY TOTAL $3,199,718.30 $110,000.00 $440,000.00 AMENDMENTS TOTAL COMMITMENT SPENT TO DATE % OF TOTAL Report for the Month of September 1997 Southern Intertie - Phase IB W.0.#E9590081 September 30, 1997 POWER ENGINEERS $3,043 ,423.00 $156,295.30 $148,047.00 $3,347,765.30 $2,332,948.00 USFS/USFWS/R US $100,000.00 $10,000.00 $0.00 $110,000.00 $41,754.00 37.96% 22.00% CHUGACH $400,000.00 $40,000.00 $0.00 $440,000.00 $96,779.00 Total Project expenditures as of 9/19/97 are $3,295,753 $3,543 ,423.00 $206,295.30 $3,749,718.30 $148,047.00 $3,897,765.30 $2,471,481.00 63.41% Report for the Month of September 1997 W.0.#E9590081 Southern Intertie - Phase IB September 30, 1997 Il. FINANCIAL II-1 CHUGACH ELECTRIC ASSOCIATION, INC. Southern Intertie Transactions Inception Through July 31, 1997 Project Expenditures Year to Date Month Through Through Ended Inception 12/31/96 7/31/97 8/31/97 Through 8/31/97 Direct Labor $68,678.93 $21,925.08 $3,974.36 $94,578.37 Indirect Labor 23,471.09 8,507.69 1,491.74 33,470.52 Power Engineers 1,918,877.36 808,505.54 236,585.38 2,963,968.28 Miscellaneous 30,326.81 38,263.81 1,314.28 69,904.90 Total $2,041,354.19 $877,202.12 $243,365.76 $3,161,922.07 Grant Fund Expenditures Year to Date Month Through Through Ended Inception 12/31/96 7131197 8/31/97 Through 8/31/97 Direct Charges that Chugach has been Reimbursed for $1,433,087.47 $1,172,523.57 $312,945.27 (1) $2,918,556.31 Plus General, Administrative & Construction Overhead 7,165.42 5,862.62 1,564.73 (1) 14,592.77 Total Amounts Paid to Chugach $1,440,252.89 _$1,178,386.19 $314,510.00 (1 $2,933, 149.08 (1) Chugach August 6, 1997 invoice for June, 1997 charges and Chugach August 21, 1997 invoice for July, 1997 charges. CHUGACH ELECTRIC ASSOCIATION, INC. Anchorage, Alaska September 24, 1997 TO: Dora Gropp - Manager, Transmission & Special Projects FROM: Kimberly Pond, Plant Accountant {27 SUBJECT: 9590081 - Southern Intertie Route Selection Study You had previously requested establishment of this work order to study route selection for the Southern Intertie for the Intertie Participants Group. The Association will be reimbursed for charges to this work order. The following charges occurred during August 1997. Direct Labor 3,974.36 Indirect Labor 1,491.74 Power Engineers Invoice # 46258 579.52 Power Engineers Invoice # 46259 10,969.85 Power Engineers Invoice # 46260 97,135.59 Power Engineers Invoice # 46261 46,260.18 Power Engineers Invoice # 46262 44,990.86 Power Engineers Invoice # 46263 3,298.79 Power Engineers Invoice # 46264 14.39 Power Engineers Invoice # 46265 33,336.20 American Express 378348463551 989.00 Dora Gropp's Travel Expenses 249.78 Arctic Cad Invoice 7046 75.50 Sub-Total $243,365.76 General, Administrative & Construction Overhead (0.5%) 1,216.83 Total Charges ____ $244,582.59 © Please review the attached backup and indicate your concurrence below if you are in agreement that these charges are correct for this work order and time period. As you requested, I'll keep the original in my files. re Als bo 9/29/47 Concur: KP/kp WOfiles/E9590081 Attachments Southern Intertie Grant Fund Bank Account Activity Summary July Ending Balance forward Total Deposits Total Withdrawals (Chugach invoices for June and July charges) Interest Earned Balance August 29, 1997 August, 1997 $1,362,926.65 $0.00 ($314,510.00) $5,427.78 $1,053,844.43 R ECEIVE D SEP 16 1997 TRANSMISSION & SPECIAL PROJECT oO) CHECKING ACCOUNT STATEMENT First National Bank Net eae ee — aay Prepared After the Clase Of Business On: AUG 29 1997 Pose: 1 Of 3 CHUGACH ELECTRIC ASSOCIATION INC SOUTHERN INTERTIE GRANT FUND PO BOX 196300 ANCHORAGE AK 99519-6300 FIRSTLINE: (907) 265-4700 BRANCH: MAIN BRANCH (907) 265-3525 2 CYCBI osc 5869 REVIOUS BALANCE AS OF 07/31/37 $.00 Service Charge This Month $.00 42 Deposits & Other Credits $26,450,995.37 Interest Paid This Month $.00 23 Checks and Other Debits $26,450,995.37 CURRENT BALANCE AS OF 08/29/97 $.00 --- Daily Account Balance Date -00 08/11 -00 08/12 -00 08/13 oOo 08/14 oo 08/15 00 08/18 ae a er oh as Other Credits ------- cnn nnn nnn nnn nn nn nn nnn n ener ne ceeeceocccce Amount Date Description 1, 362,926.65 08/01 REPO CREDIT 201 .03- 08/01 REPO INTEREST 1,363, 127.68 08/04 REPO CREDIT 603. 18” 08/04 REPO INTEREST 1,363, 730.86 08/05 REPO CREDIT 202.29“ 08/05 REPO INTEREST 1, 363,933.15 08/06 REPO CREDIT 202.32“ 08/06 REPO INTEREST 1,364, 135.47 08/07 REPO CREDIT 202.35” 08/07 REPO INTEREST 1,364,337.82 08/08 REPO CREDIT 202.38 * 08/08 REPO INTEREST 1,364,540.20 08/11 REPO CREDIT 607. 22° 08/11 REPO INTEREST 1,205,567.37 08/12 REPO CREDIT 179.507 08/12 REPO INTEREST 1,205, 746.87 08/13 REPO CREDIT 179.527 08/13 REPO INTEREST 1,205,926.39 08/14 REPO CREDIT 179.55“ 08/14 REPO INTEREST 1,206,105.94 08/15 REPO CREDIT 179.587 08/15 REPO INTEREST 1,206,285.52 | 08/18 REPO CREDIT 538.81 ° 08/18 REPO INTEREST 1, 206,824.33 08/19 REPO CREDIT 176.67 ” 08/19 REPO INTEREST 1,207,001.00 08/20 REPO CREDIT 176.69 “ 08/20 REPO INTEREST 1,207, 177.69 08/21 REPO CREDIT 176.72 ° 08/21 REPO INTEREST 1,207,354.41 08/22 REPO CREDIT 176.74 © 08/22 REPO INTEREST 1,207,531. 15 08/25 REPO CREDIT 530.31 7 08/25 REPO INTEREST CHECKING ACCOUNT STATEMENT Account Number: 0110 606 1 Prepared After the Close Of Business On: AUQ 29 1997 Pog: 2 OF 3 CHUGACH ELECTRIC ASSOCIATION INC 2 CYCBI oO8c. 5869 Amount Date Description 1, 208,061.46 08/26 REPO CREDIT 178.19 ~ 08/26 REPO INTEREST 1,208,239.65 08/27 REPO CREDIT 178.22 08/27 REPO INTEREST 1,208,417.87 08/28 REPO CREDIT 178.24- 08/28 REPO INTEREST 1,208,596.11 08/29 REPO CREDIT 178.27 ~ 08/29 REPO INTEREST acer aa ee ena ee ea ees Other DORi ts -<9< 999-9 nnn nnn nen ee ne seneseeesenweweesce Amount Date Description 1,363, 127.68 08/01 REPO DEBIT 1,363, 730.86 08/04 REPO DEBIT 1,363,933.15 08/05 REPO DEBIT 1,364, 135.47 08/06 REPO DEBIT 1, 364,337.82 08/07 REPO DEBIT 1,364,540.20 08/08 REPO DEBIT 159,580.05 08/11 DEBIT MEMO(TC6O) 1,205,567.37 08/11 REPO DEBIT 1,205, 746.87 08/12 REPO DEBIT 1,205,926.39 08/13 REPO DEBIT 1,206, 105.94 08/14 REPO DEBIT 1,206,285.52 08/15 REPO DEBIT 1, 206,824.33 08/18 REPO DEBIT 1,207,001.00 08/19 REPO DEBIT 1,207, 177.69 08/20 REPO DEBIT 1,207,354.41 08/21 REPO DEBIT 1,207,531.15 08/22 REPO DEBIT 1,208,061.46 08/25 REPO DEBIT 1,208,239.65 08/26 REPO DEBIT 1,208,417.87 08/27 REPO DEBIT 1,208,596.11 08/28 REPO DEBIT 154,929.95 08/29 DEBIT MEMO(TC6O) 1,053,844.43 ~ 08/29 REPO DEBIT Starting June 28, you can bank at our South Center Branch on Saturdays. “ne branch (at 36th and c street) will be open Saturdays from 12 to 4 pm. Report for the Month of September 1997 W.0.#E9590081 Southern Intertie - Phase IB September 30, 1997 Il. SCHEDULE Il-1 CHUGACH ELECTRIC ASSOCIATION ANCHORAGE - KENAI INTERTIE 9/19/97 PHASE IB 1995 1996 1997 1998 1999 2000 2 ID _| Task Name % Comp. Act. Cost Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | Q4 |} Q1 | Q2} Q3 | Q4] Q1 | Q2 | Q3] Q4] Q1 | Q2] Q3 | Q4| Qi | Q2] Q3 | Q4| at | Q2 1 [ENVIRONMENTAL & ENGINEE FTE RAEN 2 PROJECT MANAGEMENT 24% $96,006.60 5/34 3 ROUTE SELECTION STUD 100% $871 ,650.00 | 4 Els & PREL.ENGINEERIN 65% | $2,331,161.20 5 SCOPING 99% $372,234.72 6 INVENTORY 95% $642,612.90 7 IMPACT/MITIGATION 98% $591,930.92 8 ALTERN.SELECTION 40% $171,528.22 9 DRAFT EIS 23% $104,128.36 10 FINAL EIS ; 0% $0.00 | 6/20 1" STUDIES 73%| $74,077.34 12 ENG.FIELD WORK 94%| $190,486.44 13 PREL. ENGINEERING 97%| $184,162.30 14| AGENCIES 20%| $41,754.00 18 USFS 20%| $34,954.00 16 USFWS 20% $6,800.00 Task eee Summary Qaaaamy Rolled Up Progress ee, MEE Rolled Up Task es Milestone Sa Rolled Up Milestone <> C:\WINPROJ\SOUTHTIE\PH_IB.MPP Page 1 Report for the Month of September 1997 W.0.#E9590081 Southern Intertie - Phase IB September 30, 1997 IV. ITEMS FOR APPROVAL None. Report for the Month of September 1997 W.0.#E9590081 Southern Intertie - Phase IB September 30, 1997 V. ITEMS FOR DISCUSSION None. V-1 Report for the Month of September 1997 W.0.#E9590081 Southern Intertie - Phase IB September 30, 1997 ITEMS FOR INFORMATION 16 POWER Engineers’ Monthly Report Phase IB - Environmental Analysis, September 17, 1997 Cooperative Agreement between RUS and IPG Purpose and Need Narrative Elimination of Quartz Creek Route Utility Concurrences DFI - Update of Feasibility Study, Utility Concurrences EES VI-1 #) a WUE/F September 17, 1997 IENGINEERS ) R EceEive D Ms. Dora Gropp Chugach Electric Association SEP 1 8 1997 5601 Minnesota Drive, Building A Anchorage, AK 99518 SPeo AL SSN 8 Subject: POWER Project #120376 EIS & Preliminary Engineering Chugach Contract #95-208 Monthly Status Report No. 15 For Period August 10, 1997 - September 6, 1997 Dear Dora: The following activities were performed during this invoicing period on the Environmental Impact Statement (EIS) and Preliminary Engineering portion of the Southern Intertie Project. Key Issues: e Coordination with Rural Utilities Service (RUS) and cooperating agencies regarding Project issues. e RUS and Mangi (RUS’ third party Preparer) briefing on the Project in Washington D.C. e Completion of the Draft EVAL in October Invoice Period Overview: finalized work plan and project schedule. updated scoping comment summary database. finalized scoping report and began copying for distribution. overflight of routes with USFWS. conducted CWG field trip in the Anchorage area. finalized initial impact assessment for land use, recreation, biology, cultural, geology, visual, and socioeconomics. began assignment of mitigation measures. began assessment of residual impacts for each resource. met with the Municipality of Anchorage (MOA) planning department regarding future land use impacts. met with USFWS to discuss impact assessment process. updated construction activities matrix and alternative corridors map. initial draft of route comparison matrix. documented alternative route screening process. reviewed collection agreement between CEA, RUS, and Mangi. distributed CWG meeting #4 minutes. PEI-HLY 23-321 POWER Engineers, Incorporated I 3940 Glenbrook Dr. * P.O. Box 1066 : Phone (208) 788-3456 Hailey. Idaho 83333 Fax (208) 788-2082 Chugach Electric Association September 17, 1997 Page 2 set CWG meeting #5 date. conferred with RUS regarding scope of work for Mangi in relation to EVAL. completed purpose and need and alternatives text for Chapter 1 development of Chapter 2 project description text reviewed Chapter 3 text. preparation for the RUS/Mangi briefing in Washington D.C. worked to incorporate comments into the final Studies Report. completed Review and Update of the Project benefits (DFT). completed the draft Cost Estimate Summary Report. Work Planned for the Next Invoice Period: distribute scoping report and work plan. finalize inventory maps and associated data tables. update future land use data. finalize residual impacts and mitigation measures document and map impact assessment results. complete alternative screening process. complete comparison of alternative routes. identify environmentally preferred route. CWG meeting #5 in Anchorage and Kenai. conduct RUS/Mangi briefing in Washington D. C. conduct agency meetings with Mangi and RUS in Anchorage. continue development and review of Chapters 1, 2, 3, and 4. prepare and distribute the final Studies Report. complete EMF, inductive coordination, and cathodic protection analyses. review comments on the Draft Cost Estimate Summary Report. calculation of overall rate impacts by Decision Focus, Inc. (DFI). attendance by Decision Focus , Inc. (DFI) at the September IPG meeting to discussthe update of the cost/benefit study. PEI -HLY 23-321 OT Chugach Electric Association September 17, 1997 Page 3 Schedule: Since last months report, there have been no new issues that effect the schedule. As noted in last months report, the Memorandum of Understanding (MOU) between the Rural Utilities Service (RUS) and the cooperating agencies and the Intertie Participants Group (IPG) has been signed. The delays encountered in executing the MOU between the federal agencies and RUS’ need for a third party Preparer of the Environmental Impact Statement (EIS) have delayed the overall schedule for the Project by about three to four months. A portion of that delay is reflected in the current Revision #3 schedule for the Project. RUS is still uncertain as to when Mangi, the third party Preparer that RUS has selected to help them prepare the EIS, will be under contract. Our understanding is that it now may be late Sep2tember before RUS has Mangi under contract. We hope to receive clarification on this issue at our planned meeting wity RUS in Washington, DC on September 16. We would like to wait until the RUS/Mangi schedule becomes more well known to prepare a fourth revision of the Project schedule. At the same time as we revise the Project schedule, we will also review the cash flow projections for our contract and update those as warranted. In the meantime, important near term schedule dates for the Project include the following: ¢ Completion of the Draft EVAL and submittal to IPG October 10, 1997 for review (including environmental preference, but without IPG’s preference) e IPGreview of Draft EVAL October 13 to November 4, 1997 e Working Session with IPG Technical Committee to | October 22 or 23, 1997 ** November 4, 1097 November 10, 1997 e Submit Final EVAL to RUS November 17, 1997 ** Proposed dates, subject to IPG availability. PEI -HLY 23-321 Dower Chugach Electric Association September 17, 1997 Page 4 Monthly Status Report Issues: This monthly status report contains a Project Summary Report spreadsheet to reflect the current and projected cash flows. Tasks 1 - 5 Completion Please refer to the Activities Summary attached for work completed and planned for each Task. The continuing development of the Memorandum of Understanding led to delayed efforts in Project Tasks 1 through 5, however with the signing of the MOU we expect to expend our efforts that were planned for previous months. As mentioned in last month’s status report, during August and September, activities on Tasks 1 through 5 will be substantially completed with submission of the Draft EVAL for review on October 10. The completion of these Tasks will extend through October and November with the final version of the EVAL being completed in November, as noted in the Schedule comments above. Task 1 - Scoping Refer to Tasks 1-5 comment. Task 2 - Inventory Refer to Tasks 1-5 comment. Task 3 - Impact Assessment/Mitigation Planning Refer to Tasks 1-5 comment. Task 4 - Alternative Selection Refer to Tasks 1-5 comment. Task 5 - Draft EIS (EVAL) Refer to Tasks 1-5 comment. Task 6 - Final EIS Preparation for the RUS and Mangi briefing in Washington, D.C. Task 7 - Studies The Final Supplemental Studies Report will be issued in September. PEI -HLY 23-321 4) (EES Chugach Electric Association September 17, 1997 Page 5 Task 8 - Engineering Field Work Additional field investigations will be performed as required to support environmental activities. Task 9 - Preliminary Engineering Review of comments on the Draft Cost Estimate Summary Report. Project Overview: Total Budget $3,191,469 Actual $ Expended (to date) $2.332.948 Actual Remaining Project Budget $ 858,521 Dora, should you have any questions about this report or any of the backup, please do not hesitate to contact me or Mike Walbert. Sincerely, POWER Engineers, Inc. Qpaitgejifeo™ Rant Pollock, PLE. Project Manager MW/th cc: PROJECT TEAM PEI -HLY 23-321 4 sr J: Si: SOUTHERN INTERTIE ROUTE SELECTION STUDY - PHASE 1 120376-01 PROJECT FINANCIAL SUMMARY SEPTEMBER, 1997 INVOICE Task 1 Task 2 Task 3 | Task 4 Task 5 Task 6 Task 7 Task 8 Task 9 Project Total Base Not to Exceed Budget $351,050 $660,706 $584,010 $303,475 $402,570 $247,616 $101,480 $202,655 $189,861 $3,043,423 CWG Contract Amendment No. 4 $23,789 $18,885 $22,602 $32,866 $4,904 N/A N/A N/A N/A $103,046 DFIContract Amendment No. 5 Total Not to Exceed Budget Actual Budget Expended Through Previous Invoice N/A $374,839 $366,404 N/A $679,591 $623,899 N/A $606,612 $546,601 N/A $336,341 $110,691 $45,000 $452,474 $93,378 N/A $247,616 $0 N/A $101,480 $70,839 N/A $202,655 $190,666 N/A $189,861 $146,696 $45,000 $3,191,469 $2,149,174 Current Invoice Amount $3,607 $20,973 $49,174 $59,360 $10,284 $441 $3,279 $0 $36,656 $183,774 Actual Budget Expended Through Current Invoice $370,011 $644,872 $595,775 $170,051 $103,662 $441 $74,118 $190,666 $183,352 $2,332,948 Remaining Budget & ad a7 PEI-HLY 23-321 $4,828 $34,719 $10,837 $166,290 $348,812 $247,175 $27,362 $11,989 $6,509 $858,522 SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 1 - SCOPING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Scoping finalized work plan and project schedule. updated scoping comment summary database. finalized scoping report and began copying for distribution. distribute scoping report and work plan. KEY ISSUES: No outstanding issues. SCHEDULE: No outstanding issues. BUDGET: Contract Amendment No. 4 is included in the budget ($351,050 + $23,789 = $374,839). $ Budgeted $ Expended $ Remaining 374,839 370,011 4,828 SCOPE: No outstanding issues. HLY 23-321bk 1 SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 2 - INVENTORY DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Inventory overflight of routes with USFWS. conducted CWG field trip in the Anchorage area. conducted analysis of Project ROW issues finalize inventory maps and associated data tables. update future land use data. completion of analysis of ROW associated issues KEY ISSUES: No outstanding issues. SCHEDULE: No outstanding issues. BUDGET: Contract Amendment No. 4 is included in the budget ($660,706 + $18,885 = $679,591). $ Budgeted $ Expended $ Remaining 679,591 644,872 34,719 SCOPE: No outstanding issues. HLY 23-321bk 2 SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 3 - IMPACT ASSESSMENT/MITIGATION PLANNING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Impact Assessment / finalized initial impact assessment for land use, Mitigation Planning recreation, biology, cultural, geology, visual, and socioeconomics. began assignment of mitigation measures. began assessment of residual impacts for each resource. met with the Municipality of Anchorage (MOA) planning department regarding future land use impacts. met with USFWS to discuss impact assessment process. updated construction activities matrix and alternative corridors map. finalize residual impacts and mitigation measures document and map impact assessment results. KEY ISSUES: No outstanding issues. SCHEDULE: No outstanding issues. BUDGET: Contract Amendment No. 4 is included in the budget ($584,010 + $22,602 = $606,612). $ Budgeted $ Expended $ Remaining 606,612 595,775 10,837 SCOPE: No outstanding issues. we HLY 23-321bk SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 4 - ALTERNATIVE SELECTION DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Alternative Selection initial draft of route comparison matrix. documented alternative route screening process. reviewed collection agreement between CEA, RUS, and Mangi. distributed CWG meeting #4 minutes. set CWG meeting #5 date. conferred with RUS regarding scope of work for Mangi in relation to EVAL. complete alternative screening process. complete comparison of alternative routes. identify environmentally preferred route. CWG meeting #5 in Anchorage and Kenai. conduct agency meetings with Mangi and RUS in Anchorage. KEY ISSUES: No outstanding issues. SCHEDULE: No outstanding issues. BUDGET: Contract Amendment No. 4 is included in the budget ($303,475 + $32,866 = $336,341). $ Budgeted $ Expended $ Remaining 336,341 170,051 166,290 SCOPE: No outstanding issues. HLY 23-321bk 4 SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 5 - DRAFT EIS DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS KEY ISSUES: SCHEDULE: BUDGET: SCOPE: HLY 23-321bk Draft EIS completed Purpose and Need and Alternatives considered text for Chapter 1. completed review and update of the Project benefits (DFI) development of Chapter 2 project description text reviewed Chapter 3 text. continue development and review of Chapters 1, 2, 3, and 4. calculation of overall rate impacts from the Project (DFI) No outstanding issues. No outstanding issues. Contract amendments No. 4 and No. 5 are included in the budget ($402,570 + b $4,904 + $45,000 = $452,474). The budget addition of $11,400 for Decision Focus Inc. to proceed with the investigation of kwh rate impacts (reference Scope below) has not been added to the budget. $ Budgeted $ Expended $ Remaining $452,474 103,662 348,812 Chugach Electric Association’s letter, dated September 11, 1997, provided authorization for Power Engineers and Decision Focus to proceed with the investigation of kwh rate impacts as described in Power’s letter of August 6, 1997 and Decision Focus’ proposal dated August 4, 1997. SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 6 - FINAL EIS DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Final EIS e preparation for the RUS/Mangi briefing in Washington D.C. conduct RUS/Mangi briefing in Washington D:G: KEY ISSUES: No outstanding issues. SCHEDULE: No outstanding issues. - BUDGET: No outstanding issues. $ Budgeted $ Expended $ Remaining 247,616 441 247,175 SCOPE: Chugach Electric Association’s letter, dated September 2, 19997, provided authorization for Power Engineers and Dames & Moore to travel to Washington D.C. for a presentation to RUS and Mangi on the week of September 14, 1997. HLY 23-321bk 6 SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 7 - STUDIES DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Studies incorporate comments into final Studies Report. prepare and distribute the final Studies Report. complete EMF, inductive coordination, and cathodic protection analyses. KEY ISSUES: No outstanding issues. SCHEDULE: The final Supplemental Studies Report will be issued in September. BUDGET: No outstanding issues. $ Budgeted $ Expended $ Remaining 101,480 74,118 27,362 SCOPE: No outstanding issues. HLY 23-321bk 7 SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 8 - ENGINEERING FIELD WORK DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Engineering Field Work |e additional field investigations as required to support environmental work. KEY ISSUES: No outstanding issues. SCHEDULE: No outstanding issues. BUDGET: No outstanding issues. $ Budgeted $ Expended $ Remaining 202,655 190,666 11,989 SCOPE: No outstanding issues. HLY 23-321bk 8 SEPTEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 9 - PRELIMINARY ENGINEERING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Preliminary Engineering |e completed the draft Cost Estimate Report. e review comments on the draft report. e prepare and distribute the final Cost Estimate KEY ISSUES: SCHEDULE: BUDGET: SCOPE: HLY 23-321bk Report. No outstanding issues. The draft Cost Estimate Report was completed in August. No outstanding issues. $ Budgeted $ Expended $ Remaining 189,861 183,352 6,509 No outstanding issues. 9/17/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: 9-6-97 Rev. 1 Updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97 the DFI Contract Amendment #5 is included in Task 5 and the Total. PROJECT SUMMARY REPORT 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 2ND QUARTER. 1997 3RD QUARTER 1997 TASK MONTH] JUN/JUL AUG SEP | _OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SCOPING Actual % Work Completed _ 5% 20% 28% 33% __ 51%| 2%| 77% —-938%| 99%] 99% 99%| -99%| = 99% ~——s99% Base Planned % Complete $ (to date) 2% 25%| 26% 33% 52% 74% 87% 93% 100% 100% 100% 100% 100% 100% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 77% 93% 100%| 100% 100%| 100% 100% 100% Actual % Expended $ (to date) 5% 30% 30% 33% 51% 63% 77% 93% 99% 99% 99% 97% 98% 98% _ Base Planned $ (this period) $6,743 $81,045 $2,745 $25,645 $67,045 $75,045 $46,045 $23,645 $23,092 $0 $0. $0 $0 | $0 Rev. 1 Planned $ (this period) _ N/A N/A N/A N/A - N/A N/A $67,538 $60,112 $27,222 $0 $0 $0 $0 $0. Actual $ Expended (this period) $15,925 $89,330 ($558) $9,848 $63,340 $42,082 $67,538 $59,509 $25,800 $0 ($593) ($7,434) $1,037 $580 | Base Planned $ (to date) | $6,743 $87,788 $90,533 | $116,178 | $183,223 | $258,268 | $304,313 | $327,958 | $351,050] $351,050| $351,050] $351,050] $351,050| $351,050 | Rev. 1 Planned $ (to date) i N/A N/A N/A N/A N/A N/A| $287,505 | $347,617 | $374,839 | $374,839 | $374,839 | $374,839| $374,839| $374,830 | Actual $ Expended (to date) $15,925 | $105,255 | $104,697 | $114,545 | $177,885 | $219,967 | $287,505 | $347,014 | _$372,814| $372,814| $372,221| $364,787| $365,824| $366,404 __ Base NTE Budget (Amend. #3) | $351,050 | $351,050] $351,050 | $351,050 $351,050 | $351,050| $351,050 | $351,050] $351,050| $351,050| $351,050 $351,050| $351,050| $351,050 _ | CWG Contract Amend. #4 Budget | N/A N/A N/A N/A; N/A N/A $23,789 $23,789 $23,789 $23,789 $23,789 | _ $23,789 $23,789 | $23,789 Total Task NTE Budget _| $351,050 | $351,050 | $351,050] $351,050| $351,050| $351,050] $374,839| $374,839 $374,839] $374,839| $374,839| $374,839| $374,839! $374,839. Actual Remaining Task Budget $335,125 | $245,795 | $246,353 | $236,505 | $173,165 | $131,083 $87,334 $27,825 $2,025 | $2,025 $2,618 | $10,052 $9,015| $8,435 | INVENTORY j Actual % Work Completed | 0% 6% 25%| 45% 60% 67%| 73% 80% _87%| 88% 88% 90% 90%| 92% | Base Planned % Complete $(todate)| _—=—=——«0% 5% 23% 53% 73% 83% 84% 84% 84% 84% 84% 87% 95%| ——-—-100%. Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 73% 82% 85% 86% 86% 89% 92% 96% Actual % Expended $ (to date) 0% 5% 24% 43% 58% 72% 73% 78% 87% 88% 88% 90% 90% 92% Base Planned $ (this period) $941 $29,441 | $121,000] $200,500] $129,500 $69,768 $5,000 $0 $0 $0 $1,000 $16,500 $52,000 $34,056 _ Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $19,728 $58,932 $20,240 $8,817 $3,000 $17,500 $19,000 $29,613 Actual $ Expended (this period) $0 $32,162 | $124,454 | $129,043 $100,796 $89,331 $19,728 $33,908 $63,502 $2,888 $0 $15,815 $1,302 $10,970 _ Base Planned $ (to date) $941 $30,382 | $151,382 | $351,882 | $481,382 | $551,150 | $556,150| $556,150 | $556,150| $556,150] $557,150 | $573,650] $625,650| $659,706 _ Rev. 1 Planned $ (to date) a N/A N/A N/A N/A N/A NWA| $495,514 | $554,446 | $574,686 | $583,503| $586,503| $604,003] $623,003| $652,616 _ Actual $ Expended (to date) $0 $32,162 | $156,616 | $285,659 | —$386,455| $475,786 | $495,514 | $529,422 | $592,924] $595,812| $595,812| $611,627] $612,929| $623,899 _ Base NTE Budget (Amend. #3) $660,706 | $660,706 | $660,706 | $660,706 | $660,706 | $660,706 | $660,706 | $660,706 | $660,706] $660,706 | $660,706| $660,706| $660,706 | $660,706 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 Total Task NTE Budget $660,706 | $660,706 | $660,706 | $660,706 | $660,706 | $660,706] $679,591| $679,591 | $679,591| $679,591| $679,591| $679,591| $679,591 | $679,591 | Actual Remaining Task Budget $660,706 | $628,544 | $504,090] $375,047| $274,251| $184,920| $184,077| $150,169 $86,667 $83,779 $83,779 | $67,964 $66,662 $55,692 IMPACT ASSESSMENT/MITIGATION PLANNING f Actual % Work Completed 7 0% 0% 0% 0% 1% 5% 7% 10% 16% 31% 52%| «62% 75% 90% Base Planned % Complete $ (to date) 0% 0% 0% 5% 10% 25% 40% 50% 60% 80% 95% 100% 100% 100% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 7% 20% 37% 55% 69% 82% 89% 96% Actual % Expended $ (to date) 0% 0% 0% 0% 1% 5% 7% 9% 16% 31% 52% 62% 74% 90% | Base Planned $ (this period) $0 $0 $0 $29,000 $30,000 $85,000 $90,000 $57,000 $58,000 | $117,000 $90,000 $28,010 $0 $0 Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A| $10,408 $81,590 $99,490 | $111,370 $88,030 $78,700 $42,295 $37,600 _ Actual $ Expended (this period) $0 $383 $64 $0 $5,788 $23,901 $10,408 $14,998 $41,883 $92,212 | $126,888 $59,150 $73,790 $97,136 - Base Planned $ (to date) $0 $0 $0 $29,000 $59,000 | __ $144,000 | __ $234,000 | $291,000 | $349,000 | $466,000 | $556.000| $584,010| $584,010 | $584,010 | Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A N/A $40,544 | $122,134 | $221,624 | $332,994| $421.024| $499,724] $542,019| $579,619 Actual $ Expended (to date) $0 $383 $447 $447 $6,235 $30,136 $40,544 $55,542 $97,425 | $189,637 | $316,525 | $375,675| $449,465 | $546,601 _ Base NTE Budget (Amend. #3) $584,010 | $584,010 | $584,010 $584,010| $584,010| $584,010] $584,010] $584,010| $584,010] $584,010] $584,010| $584,010| $584,010| $584,010 _ CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 Total Task NTE Budget $584,010 | $584,010 | $584,010 | $584,010 | $584,010 | $584,010 | $606,612 $606,612 | $606,612| $606,612| $606,612| $606,612] $606,612| $606,612 _ Actual Remaining Task Budget $584,010 | $583,627 | _$583,563| $583,563| $577,775 | $553,874 | $566,068| $551,070 $509,187| $416,975| $290,087| $230,937| $157,147 $60,011 SEP N00 Page 1 9/17/97 Rev. 1 Updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97 the DFl Contract Amendment #5 is included in Task 5 and the Total. SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT ern 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 2ND QUARTER 1997 38RD QUARTER 1997 TASK MONTH] JUN/JUL AUG SEP OcT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG | SEP 4 ALTERNATIVE SELECTION i Actual % Work Completed 0%] 0% 0%! 0% HC 0% 0% 0%] 0% 1% 10%] 20%| 35%. Base Planned % Complete $ (to date) 0% 0% 0% 0% 0% 0% 0% 0% 0%| 0% 11% 35% 61%| 80%. Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 0% 5% 15%| 31% 49%| 71% 91% 100% Actual % Expended $ (to date) 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 11% 19% 33% Base Planned $ (this period) $0 $0 $0 $0 _ $0 $0 $0 $0 $0 $0 $32,400 | _ $74,400 $77,400 | $58,400 __ Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $0 | _ $15,000 $35,000 | $52,000 $62,000 $72,000 $69,000 | $29,972 Actual $ Expended (this period) $0 $1,369 $0 $0 $0 $0 $0 $0 $0 $0 $1,275 $34,764 $27,023 $46,260 Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $0 $0 $0 | $0 $32,400 | $106,800] $184,200 | $242,600 | Rev. 1 Planned $ (to date) N/A N/A N/A N/A _ N/A N/A $1,369 $16,369 $51,369 $103,369 $165,369 $237,369 $306,369 | $336,341 _ Actual $ Expended (to date) $0 $1,369 $1,369 $1,369 $1,369 $1,369 $1,369 $1,369 $1,369 $1,369 $2,644 $37,408 $64,431 $110,691 © Base NTE Budget (Amend. #3) $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 | $303,475 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A $32,866 $32,866 $32,866 | $32,866 $32,866 $32,866 $32,866 a $32,866 Total Task NTE Budget $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 Actual Remaining Task Budget $303,475 | $302,106 | $302,106 | $302,106 | $302,106 | $302,106| $334,972 | $334,972| $334,972| $334,972] $333,697| $298,933| $271,910| $225,650. 5 DRAFT EIS Actual % Work Completed (0% 0% 0% 0% 0% 0% __0%| 0% 0%] —=——s—«0% 1% 8% 11% 20% | Base Planned % Complete $ (to date) 0% 0% 0% 0% _ 0% 0% 0% 0% 1% 2% 3% 4% 11%| 19% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 0% 1% 1%] 1% 2% 2% 17% 39% Actual % Expended $ (to date) 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 8% 11% 21%. Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $5,772 $1,572 $5,772 $1,582 $31,570 $31,570 © Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $0 $6,100 $0 $0 $4,000 $332 $65,634 $100,38' Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $4,991 $29,405 | $13,991 $44,99 Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $0 $0 $5,772 $7,344 $13,116 $14,698 $46,268 $77,838 Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A N/A $0 $6,100 $6,100 $6,100 $10,100 $10,432 $76,066 $176,452 © Actual $ Expended (to date) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $4,991 $34,396 $48,387 $93,378 | Base NTE Budget (Amend. #3) $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 | $402,570 $402,570 $402,570 $402,570 $402,571 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 DFI Contract Amend. #5 Budget N/A N/A N/A N/A N/A| N/A N/A N/A N/A N/A N/A $45,000 $45,000 | $45,000 Total Task NTE Budget $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $407,474 $407,474 $407,474 $407,474 $407,474 $452,474 $452,474 $452,474 © Actual Remaining Task Budget $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $407,474 $407,474 $407,474 $407,474 $402,483 $418,078 $404,087 $359,096 | 6 FINAL EIS i Actual % Work Completed 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% | Base Planned % Complete $ (to date) 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A MA 0% 0% 0% 0% 0% 0% 0% 0% Actual % Expended $ (to date) 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 | Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $0 $0 $0 $0 $0 $0 $0 $0 | Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A N/A $0 $0 $0 $0 $0 $0 $0 $0 Actual $ Expended (to date) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Base NTE Budget (Amend. #3) $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Total Task NTE Budget $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 Actual Remaining Task Budget $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 Page 2 9/17/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT 9-6-97 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 2ND QUARTER 1997 3RD QUARTER 1997 TASK MONTH] JUN/JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP i STUDIES Actual % Work Completed (a 5% ee.” 7% 8%! 14% 27%| 85%! = 48% 55% 60%) 60% 68% ___ 709 Base Planned % Complete $ (to date) 1% 5% _ 9% 21% 51%) | 73% 73% : 73% 76%! —-—- 78% 80% __ 83% : 87% ; fo Rev. 1 Planned % Complete $ (to date) N/A| N/A N/A N/A NA) N/A 27% 38% 55%| 56% 56% 67%| 78% 89% Actual % Expended $ (to date) 0% 3% 7% 7% 8% 14% 27% 33% 47% 55% 60% 61% 67% 70% Base Planned $ (this period) $927 $3,927 $4,427 $12,200 $30,325 | __ $22,780 | $0 $0 $2,300 |_ $2,300 $2,280 | $2,300 $4,139 $4,175 Rev. 1 Planned $ (this period) _NA N/A N/A| N/A NA) N/A| $13,352 $10,492 $18,035 ___ $500 $500 | $11,156 | $11,300 $11,207 Actual $ Expended (this period) $0 $2,569 $4,177 $637 $1,148 $5,705 $13,352 $5,455 $14,793 $8,252 $5,157 $440 $5,855 $3,299 Base Planned $ (to date) $927 $4,854 $9,281 $21,481 $51,806 | $74,586 $74,586 $74,586 $76,886 | _—_ $79,186 $81,466 | $83,766 $87,905 $92,080 Rev. 1 Planned $ (to date) __N/A N/A N/A N/A N/A\ VA $27,588 $38,080 $56,115 | $56,615 $57,115 | $68,271 $79,571 ; $90,778 _ Actual $ Expended (to date) $0 $2,569 $6,746 $7,383 $8,531 $14,236 $27,588 $33,043 $47,836 $56,088 $61,245 $61,685 $67,540 $70,839 Base NTE Budget (Amend. #3) $101,480 | $101,480 $101,480 $101,480 $101,480 | $101,480 $101,480 $101,480 $101,480 | $101,480 $101,480 $101,480 $101,480 $101,480 CWG Contract Amend. #4 Budget _NA N/A N/A N/A N/A\ N/A N/A N/A NAL N/A N/A N/A|_ N/A N/A Total Task NTE Budget $101,480 | $101,480 $101,480 | $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 | $101,480 $101,480 $101,480 Actual Remaining Task Budget $101,480 | $98,911 $94,734 $94,097 $92,949 $87,244 $73,892 $68,437 $53,644 | _ $45,392 $40,235 $39,795 $33,940 $30,641 8 ENGINEERING FIELD WORK Actual % Work Completed 5% 15% 50%| _ 60% 70%! 74% 77%| 79% 84%] 87% 87% 90% 95% 95% Base Planned % Complete $ (to date) 5% 18% 52% 63% 68%| 78% 86% 91% 91%| 91% 91%| 94% 97% 100% Rev. 1 Planned % Complete $ (to date) N/A\ N/A N/A N/A NA A 77% 79%| 81%| 81% 81%) 88% 95% ___ 100% - Actual % Expended $ (to date) 5% 13% 48% 60% 70% 74% 77% 79%| 84% 87% 87%| «90% 94% 94% Base Planned $ (this period) $9,600 $27,600 $68,900 $20,980 $10,800 $20,680 $16,600 $9,955 | $0 $0 $0 $5,500 $5,500 $6,540 Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $7,645 $4,000 $2,601 $0 $0 | $15,000 $14,000 $10,026 S Actual $ Expended (this period) $10,330 $17,007 $69,770 $23,487 $20,840 $7,949 $7,645 $2,827 $10,789 $4,825 $33 $7,640 $7,510 $14 | Base Planned $ (to date) $9,600 $37,200 $106,100 $127,080 $137,880 $158,560 $175,160 $185,115 $185,115 | $185,115 $185,115 $190,615 $196,115 $202,655 _ Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A N/A] $157,028 $161,028 $163,629 $163,629 $163,629 | $178,629 $192,629 $202,655 Actual $ Expended (to date) $10,330 $27,337 $97,107 $120,594 $141,434 $149,383 $157,028 $159,855 $170,644 $175,469 $175,502 $183,142 $190,652 $190,666 Base NTE Budget (Amend. #3) $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Total Task NTE Budget $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 $202,655 _ Actual Remaining Task Budget $192,325 $175,318 $105,548 $82,061 $61,221 $53,272 $45,627 $42,800 $32,011 $27,186 $27,153 $19,513 $12,003 $11,989 9 PRELIMINARY ENGINEERING Actual % Work Completed 1% 1% 1% 1% 12% 17% 18% 20% 25% 36% 45% 50% 60% 78% Base Planned % Complete $ (to date) 1% 2% 4% 9% 23% 31% 44% 57% 71% 88% 97% 98% 98% 98% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 18% 36% 53% 71% 85% 98% 98% 98% Actual % Expended $ (to date) 1% 1% 1% 1% 12% 17% 18% 20% 24% 36% 44% 50% 60% 77% Base Planned $ (this period) $2,580 $2,137 $2,137 $10,337 $27,417 $14,557 $23,697 $25,557 $26,837 $32,397 $16,076 $2,132 $0 $0 Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $1,937 $33,000 $33,000 $35,000 $25,000 $25,330 $0 $0 Actual $ Expended (this period) $1,694 $0 $1,080 $0 $20,307 $9,513 $1,937 $2,746 $8,432 $23,434 $13,944 $11,012 $19,261 $33,336 _ Base Planned $ (to date) $2,580 $4,717 $6,854 $17,191 $44,608 $59,165 $82,862 $108,419 $135,256 $167,653 $183,729 $185,861 $185,861 $185,861 Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A N/A $34,531 $67,531 $100,531 $135,531 $160,531 $185,861 $185,861 $185,861 Actual $ Expended (to date) $1,694 $1,694 $2,774 $2,774 $23,081 $32,594 $34,531 $37,277 $45,709 $69,143 $83,087 $94,099 $113,360 $146,696 Base NTE Budget (Amend. #3) $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Total Task NTE Budget $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 Actual Remaining Task Budget $188,167 $188,167 $187,087 $187,087 $166,780 $157,267 $155,330 $152,584 $144,152 $120,718 $106,774 $95,762 $76,501 $43,165 _ Rev. 1 Updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97 the DFI Contract Amendment #5 is included in Task 5 and the Total. Page 3 9/17/97 SOUTHERN INTERTIE PROJECT PROJECT SUMMARY REPORT THROUGH PERIOD ENDING: 9-6-97 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 2ND QUARTER 1997 38RD QUARTER 1997 TASK MONTH| JUN/JUL AUG SEP OcT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP TOTAL PROJECT 120376-01 E Sa __ Actual % Work Completed 1%| 5%| 12% 18%) 24% 30%] 33% | 38% 40%! 46% 51%) 55% 60% 68% Base Planned % Complete $ (to date) |_ 1% 5%| 12% 22% | 31%) 41%| 47% 51% 55% 60% 64%! 69% 74% 79% | Rev. 1 Planned % Complete $ (to date) N/A N/A N/A’ N/A} N/A NWA 33% 42% 49% 56% 62% 68% 75% 81% Actual % Expended $ (to date) 1% 6% 12% 18% 24% 30% 33% 37% 42% 46% 51% 55% 60% 67% Base Planned $ (this period) $20,791 $144,150 $199,209 $298,662 $295,087 $287,830 $181,342 $116,157 $116,001 $153,269 $147,528 $130,424 $170,609 $134,741 Rev. 1 Planned $ (this period) N/A N/A N/A’ N/A| N/A WA|__ $120,608 $269,226 $235,588 | _ $207,687 $182,530 $220,018 $221,229 $218,804 Actual $ Expended (this period) $27,949 $142,820 | $198,987 $163,015 $212,219 $178,481 $120,608 $119,443 $165,199 $131,611 $151,695 $150,792 $149,769 $236,586 __Base Planned $ (to date) $20,791 $164,941 | $364,150 $662,812 $957,899 | $1,245,729 | $1,427,071 | $1,543,228 | $1,659,229 | $1,812,498 | $1 960,026 | $2,090,450 | $2,261,059 | $2,395,800 Rev. 1 Planned $ (to date) N/A N/A| N/A N/A N/A N/A|_ $1,044,079 | $1,313,305 | $1,548,893 | $1,756,580 | $1,939,110 | $2,159,128 | $2,380,357 | $2,599,161 Actual $ Expended (to date) $27,949 $170,769 $369,756 $532,771 $744,990 $923,471 | $1,044,079 | $1,163,522 | $1,328,721 | $1,460,332 | $1,612,027 | $1,762,819 | $1,912,588 | $2,149,174 Base NTE Budget (Amend. #3) $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 _ CWG Contract Amend. #4 Budget _ N/A N/A) N/A N/A N/A WA] $103,047 $103,047 $103,047 $103,047 $1 03,047 | $103,047 $103,047 $103,047 | __DFl Contract Amend. #5 Budget | N/A _ NA) N/A N/A| N/A| WAL N/A N/A N/A N/A N/A | $45,000 $45,000 | $45,000 © Total Project NTE Budget $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,146,470 | $3,146,470 | $3,146,470 | $3,146,470 | $3,146,470 | $3,191,470 | $3,191,470 | $3,191,470 | Actual Remaining Project Budget $3,015,474 | $2,872,654 | $2,673,667 | $2,510,652 | $2,298,433 | $2,119,952 | $2,102,391 | $1,982,948 | $1,817,749 | $1,686,138 | $1,534,443 | $1,428,651 | $1,278,882 | $1,042,296 _ BASE PLANNED QUARTER TOTALS $364,150 $881,579 $413,500 $431,221 nl $424,795 BASE PLANNED YEARLY TOTALS $1,245,729 REV. 1 PLANNED QUARTER TOTALS} $369,756 $553,715 $625,422 $610,235 $527,827 REV. 1 PLANNED YEARLY TOTALS $923,471 ACTUAL QUARTER TOTALS $369,756 $553,715 $405,250 $434,098 $570,129 ACTUAL YEARLY TOTALS $923,471 Rev. 1 Updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97 the DFI Contract Amendment #5 is included in Task 5 and the Total. Page 4 9/17/97 SOUTHERN INTERTIE PROJECT PROJECT SUMMARY REPORT THROUGH PERIOD ENDING: 9-6-97 4TH QUARTER 1997 1ST QUARTER 1998 2ND QUARTER 1998 3RD QUARTER 1998 4TH QUARTER 1998 Rev. 1 Updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97 the DFI Contract Amendment #5 is included in Task 5 and the Total. TASK MONTH OcT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC 1 SCOPING Actual % Work Completed a te a i fe 7 _ | a i Base Planned % Complete $ (to date) 100% 100% 100% 100% 100% 100%| 100% 100% 100% 100%| 100%) 100% 100% 100% 100%| Rev. 1 Planned % Complete $ (to date) 100% 100% 100% 100%| ——: 100% 100% 100% 100% 100% 100% 100%| 100% 100% 100% 100%| Actual % Expended $ (to date) ; | | Base Planned $ (this period) $0 $o| _—- $0 $0 ___$0 __ 80 _ $0 $0 $o| go; SO $0 $0 $0 $0 | Rev. 1 Planned $ (this period) $0 $o| «$0. $0 $0 $0 _ $0 $0 $0 $0 $0 $0 $0 $0_ $0 | Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 | $0 $0 $0 $0 __Base Planned $ (to date) $351,050 $351,050 | $351,050 $351,050 $351,050 $351,050 | $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 | Rev. 1 Planned $ (to date) $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 | _ $374,839 $374,839 $374,839 $374,839 | Actual $ Expended (to date) [ Base NTE Budget (Amend. #3) $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 $351,050 CWG Contract Amend. #4 Budget $23,789 $23,789 $23,789 $23,789 $23,789 $23,789 |: $23,789 $23,789 $23,789 $23,789 $23,789 $23,789 $23,789 $23,789 $23,789 | Total Task NTE Budget $374,839 $374,839 | $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 Actual Remaining Task Budget _| a ; i fT _ 2 INVENTORY . Actual % Work Completed ae | _ i Base Planned % Complete $ (to date)| 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%| 100% 100% 100% 100%| Rev. 1 Planned % Complete $ (to date) 100% 100%| 100% 100% 100% 100%] =: 100% 100% 100% 100% 100%| 100% 100% 100% 100% Actual % Expended $ (to date) Base Planned $ (this period) $0 $0 $0 $0 $0 $0 _ $0 $0 $0 $0 _ $0 $0 $0 $0 $0 Rev. 1 Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Base Planned $ (to date) $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 Rev. 1 Planned $ (to date) $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 Actual $ Expended (to date) Base NTE Budget (Amend. #3) $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 CWG Contract Amend. #4 Budget $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 $18,885 | Total Task NTE Budget $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 $679,591 Actual Remaining Task Budget 7 3 __|IMPACT ASSESSMENT/MITIGATION F Actual% Work Completed | _ Base Planned % Complete $ (to date) 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Rev. 1 Planned % Complete $ (to date) 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Actual % Expended $ (to date) Base Planned $ (this period) $0 $0 $0 $0 $0 so $0 $0 $0 $0 $0 $0 $0 $0 $0 Rev. 1 Planned $ (this period) $8,993 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Base Planned $ (to date) $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 Rev. 1 Planned $ (to date) $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 Actual $ Expended (to date) Base NTE Budget (Amend. #3) $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 $584,010 CWG Contract Amend. #4 Budget $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 $22,602 Total Task NTE Budget $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 $606,612 Actual Remaining Task Budget Page 5 9/17/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUNIMARY REPORT 9-6-97 4TH QUARTER 1997 1ST QUARTER 1998 2ND QUARTER 1998 3RD QUARTER 1998 4TH QUARTER 1998 TASK MONTH OcT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP oct NOV I DEC 4 ALTERNATIVE SELECTION Tt Actual % Work Completed _ fe _ | ee _ | Base-Planned % Complete-$(to-date)| ---100%| = 100%, 100%| 100% 100% 100% 100%| __—_—:100% 100% 100% 100%, 100% 100% 100% 100% Rev. 1 Planned % Complete $ (to date) 100% 100%] 100% 100%| 100%) 100% 100%| _ 100% 100% 100% 100%] —: 100% 100% 100% 100% Actual % Expended $ (to date) _| Base Planned $ (this period) $0 $o| _—_—_—_—g0 $0 ___ $0 $0 $0 | $0 $0 ____ $0 $0 | $0 $o| $0 $0 Rev. 1 Planned $ (this period) $0 $0 ___ $0 $o| $0 $o $o| $0 $0 $0 $o| $0 $o| $0 $0 Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Base Planned $ (to date) $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 | $303,475 $303,475 $303,475 $303,475 Rev. 1 Planned $ (to date) $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 il $336,341 $336,341 | $336,341 $336,341 $336,341 $336,341 Actual $ Expended (to date) [ Base NTE Budget (Amend. #3) $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 CWG Contract Amend. #4 Budget $32,866 $32,866 $32,866 $32,866 * $32,866 $32,866 $32,866 $32,866 $32,866 $32,866 $32,866 | __ $32,866 $32,866 | $32,866 $32,866 Total Task NTE Budget $336,341 $336,341 _ $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 | $336,341 $336,341 | $336,341 $336,341 $336,341 $336,341 Actual Remaining Task Budget Sp ro v—vo—o—cSsSaoaS—— ERG DRAFT EIS | | Actual % Work Completed {| : LL Base Planned % Complete $ (to date) 50% 55% ___ 60% 66% 85% 95% 100% 100% 100% 100% 100%| 100% 100% 100% 100% Rev. 1 Planned % Complete $ (to date) 63% 69% __ 76% 87% 93% 100%] _ 100% 100% 100% 100% 100% 100% 100% 100% 100% Actual % Expended $ (to date) Base Planned $ (this period) $64,570 $21,570 $19,570 $25,570 $74,570 $42,570 $18,742 $0 $0 $0 $0 $0 $0 $0 $0 Rev. 1 Planned $ (this period) $66,200 $29,000 $29,000 $49,900 $28,000 $30,001 $1,904 $0 $0 $0 $0 $0 $0 $0 $0 Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Base Planned $ (to date) $199,978 $221,548 $241,118 $266,688 $341,258 $383,828 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 Rev. 1 Planned $ (to date) $284,669 $313,669 $342,669 $392,569 $420,569 $450,570 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 l $452,474 $452,474 Actual $ Expended (to date) Base NTE Budget (Amend. #3) $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 CWG Contract Amend. #4 Budget $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 DFI Contract Amend. #5 Budget $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 $45,000 Total Task NTE Budget $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 $452,474 FINAL EIS | Actual Remaining Task Budget Actual % Work Completed v6 Base Planned % Complete $ (to date) 0% 0% 0% 0% 0% 0% 16% 26% 50% 60% 74% 84% 94% 100% 100% Rev. 1 Planned % Complete $ (to date) 0% 0% 0% 0% 0% 17% 40% 53% 73% 86% 90%| 93% 96% 98% 100% Actual % Expended $ (to date) Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $39,100 $25,100 $59,600 $25,100 $35,100 $24,600 $24,600 $14,416 $0 Rev. 1 Planned $ (this period) $0 $0 $0 $0 $0 $42,900 | $55,563 $33,700 $48,065 $33,804 $8,200 $8,700 $6,660 $6,163 $3,860 Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $39,100 $64,200 $123,800 $148,900 $184,000 $208,600 $233,200 $247,616 $247,616 Rev. 1 Planned $ (to date) $0 $0 $0 $0 $0 $42,900 $98,463 $132,163 $180,229 $214,033 $222,233 $230,933 $237,593 $243,756 $247,616 Actual $ Expended (to date) _t Base NTE Budget (Amend. #3) $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 | $247,616 $247,616 $247,616 $247,616 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A| N/A N/A N/A N/A Total Task NTE Budget $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 | $247,616 $247,616 $247,616 $247,616 Actual Remaining Task Budget As of 6/1/97 the DFI Contract Amendment #5 is included in Task 5 and the Total. | ————__————_—_-_--> ern OOO | Rev. 1 Updated as of 1/1/97; includes Contract Amendment #4. Page 6 * 9/17/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT oo 4TH QUARTER 1997 1ST QUARTER 1998 2ND QUARTER 1998 3RD QUARTER 1998 4TH QUARTER 1998 TASK MONTH] OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP oct NOV DEC 7 STUDIES Actual % Work Completed LET ATT il WA Le Te ETE TST RIL TCcet COTATI WAT Base Planned % Complete $(todate)| 91%] 91%| 1%] 1% 91% 96%! ss 96% = (BM 96%| «96% ~96%| 100% == 100%| = 100%| = 100% Rev. 1 Planned % Complete $ (to date)| ==: 90% 90% 90%| 90% 90% | 96%| 96%) 96% 96%| «96% 96%| 100% 100% 100% 100% Actual % Expended $ (to date) imi Base Planned $ (this period) $0 $0 of $0 $0 $5,400 $0] $0 go| «$0 $0 $4,000 $0 $0 $0 Rev. 1 Planned $ (this period) $0 $0 me $0 $0 $5,900 | $0 | $0 0 TE: $0| $4,000 SOIC LIo!) TMI IL $0 Actual $ Expended (this period) $0 $0 $0 | $0 $0 $0 $0 $0 $0 $0 gol $0 $0 $0 $0 Base Planned $ (to date) $92,080 $92,080 $92,080 $92,080 $92,080 $97,480 $97,480 | $97,480 $97,480 $97,480 $97,480 | $101,480| $101,480 $101,480| $101,480 ____ Rev. 1 Planned $ (to date) $91,580 $91,580 $91,580 $91,580 $91,580 $97,480 $97,480 | $97,480 $97,480 $97,480 $97,480 | $101,480| $101,480| $101,480 | $101,480 Actual $ Expended (to date) iii Base NTE Budget (Amend. #3) $101,480 | $101,480 | $101,480 | $101,480 | $101,480 | $101,480 | $101,480 $101,480 | $101,480] $101,480| $101,480] $101,480] $101,480| $101,480| $101,480 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A| N/A N/A N/A N/A| N/A N/A N/A N/A | __ Total Task NTE Budget $101,480 | $101,480 | $101,480 | $101,480 | $101,480 | $101,480 | $101,480 $101,480 | $101,480] $101,480| $101,480| $101,480| $101,480| $101,480| $101,480 Actual Remaining Task Budget 8 ENGINEERING FIELD WORK Actual % Work Completed Base Planned % Complete $ (to date) 100% 100% 100% 100% __ 100% 100% 100% 100% 100%| 100% 100%| ——: 100% 100% 100%| ——:100% Rev. 1 Planned % Complete $ (to date) 100% 100% 100% 100% 100% 100%| ———-100%| 100% 100%| 100% 100%| —: 100% 100% 100% 100% Actual % Expended $ (to date) Mn | _Base Planned $ (this period) $0 $0 $0 $0 $0 $0 SOU] $0 $0 $0 $o| _—_— $0 $0 $0 $0 Rev. 1 Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 go| «$0 $0 $0 $0 Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 | __ Base Planned $ (to date) $202,655 | $202,655 | $202,655 | $202,655 | $202,655] $202,655| $202,655| $202,655 | $202,655| $202,655| $202,655| $202,655] $202,655| $202,655 | $202,655 Rev. 1 Planned $ (to date) $202,655 | $202,655 | $202,655 | $202,655 | $202,655 | $202,655 | $202,655 | $202,655| $202,655] $202,655 | $202,655| $202,655] $202,655 | $202,655| $202,655 Actual $ Expended (to date) Base NTE Budget (Amend. #3) $202,655 | $202,655 | $202,655 | $202,655 | $202,655 $202,655 | $202,655| $202,655 $202,655 | $202,655 | $202,655| $202,655| $202,655| $202,655| $202,655 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A\ N/A N/A N/A N/A N/A N/A N/A N/A N/A Total Task NTE Budget $202,655 | $202,655 | $202,655| $202,655 | $202,655 $202,655 | $202,655 | $202,655| $202,655] $202,655 | $202,655| $202,655| $202,655 | $202,655| $202,655 Actual Remaining Task Budget [ | 9 PRELIMINARY ENGINEERING Actual % Work Completed Base Planned % Complete $ (to date) 98% 98% 98% 98% 98% 98% 98% 98% 98% 98% 98% 98% 100% 100% 100% Rev. 1 Planned % Complete $ (to date) 98% 98% 98% 98% 98% 98% 98%) 98% 98% 98% 98% 98% 100% 100% 100% Actual % Expended $ (to date) Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $4,000 $0 $0 Rev. 1 Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $4,000 $0 $0 Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Base Planned $ (to date) $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $189,861 $189,861 $189,861 Rev. 1 Planned $ (to date) $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $185,861 $189,861 $189,861 $189,861 Actual $ Expended (to date) Base NTE Budget (Amend. #3) $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Total Task NTE Budget $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 | $189,861 | $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 Actual Remaining Task Budget Rev. 1 Updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97 the DFI Contract Amendment #5 is included in Task 5 and the Total. Page 7 9/17/97 SOUTHERN INTERTIE PROJECT PROJECT SUMMARY REPORT THROUGH PERIOD ENDING: 9-6-97 4TH QUARTER 1997 1ST QUARTER 1998 2ND QUARTER 1998 3RD QUARTER 1998 4TH QUARTER 1998 TASK MONTH| OCT NOV DEC JAN FEB MAR _ APR MAY JUN JUL AUG SEP oct NOV DEC TOTAL PROJECT 120376-01 Actual % Work Completed i - Se a _ ED | | Base Planned % Complete $ (to date)| 85% 85% 86% 87%| «89% 91%] 93%) = 4%) BM 96%| 98% 99%] ~=—:100%| += 100%| +=: 100% Rev. 1 Planned % Complete $ (to date) 87% 87% 88% 90%| 91% 93%] ——-95%| 96% 98% 99%| 99% 99%| —: 100% 100%| 100% Actual % Expended $ (to date) | | _ Base Planned $ (this period) $64,570 $21,570 $19,570 $25,570 | $74,570 $47,970 | $57,842 $25,100 | $59,600 $25,100 | $35,100 $28,600 $28,600 $14,416, $0 | Rev. 1 Planned $ (this period) _ $75,193 $29,000 | $29,000 $49,900 | $28,000 $78,801 | $57,467 $33,700 | $48,065 $33,804 $8,200| $12,700 | —_ $10,660 $6,163, —_- $3,860 Actual $ Expended (this period) $0 $0 $0 $0 | $0 $0 $0 $0 | $0 $0 $0 $o| —«$0 $0 $0 ii Base Planned $(todate) _—_—|_ $2,579,815 | $2,601,385 | $2,620,955 | $2,646,525 | $2,721,095 | $2,769,065 | $2,826,907 | $2,852,007 | $2,911,607 | $2,936,707 | $2,971,807 | $3,000,407 | $3,029,007 | $3,043,423 | $3,043,423 | __ Rev. 1 Planned $ (to date) _ $2,762,148 | $2,791,148 | $2,820,148 | $2,870,048 | $2,898,048 | $2,976,849 | $3,034,317 | $3,068,017 | $3,116,082 | $3,149,886 | $3,158,086 | $3,170,786 | $3,181,446 | $3,187,609 | $3,191,469 Actual $ Expended (to date) | | | _ Base NTE Budget (Amend. #3) | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 CWG Contract Amend. #4 Budget | $103,047 | __ $103,047 | __ $103,047] $103,047 | __ $103,047 | __ $103,047 | $103,047 | $103,047: $103,047 | $103,047 | $103,047 | $103,047| $103,047| $103,047 | $103,047 | __DFl Contract Amend. #5 Budget $45,000 $45,000 | _$45,000| $45,000 ~—-$45,000 $45,000 | $45,000 $45,000 $45,000| $45,000 —_ $45,000 $45,000 $45,000 $45,000 | $45,000 Total Project NTE Budget $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 | $3,191,470 Actual Remaining Project Budget | BASE PLANNED QUARTER TOTALS $105,710 $148,110 $142,542 $88,800 $43,016 BASE PLANNED YEARLY TOTALS $1,375,226 $422,468 REV. 1 PLANNED QUARTER TOTALS, $133,193 $156,701 7 $139,233 $54,704 $20,683 REV. 1 PLANNED YEARLY TOTALS $1,896,677 $371,321 ACTUAL QUARTER TOTALS $0 $0 $0 $0 $0 ACTUAL YEARLY TOTALS $1,409,477 $0 Rev. 1 Updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97 the DFI Contract Amendment #5 is included in Task 5 and the Total. Page 8 SOUTHERN INTERTIE PROJECT EIS Proposed Anchorage to Kenai Peninsula Transmission Line 1996 / 1997 1998 1999 ID __| Task Name Start Finish | % Compl | Apr |May| Jun | Jul | Aug | Sep | Oct | Nov | Dec | Jan |Feb| Mar | Apr |May| Jun } Jul | Aug | Sep | Oct | Nov | Dec | Jan |Feb| Mar | Apr |May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | Jan | Feb} Mar | Apr | May | Jun | Jul 2 TASK 1 SCOPING 6/11/96 | 4/25/97| 99% ; 0 FE a 3 FILE NOTICE OF INTENT WITH 10/9/96 | 10/10/96 | 100% e FEDERAL REGISTER d0/8 4 MOU AND WORKPLAN WITH CO 11/6/96 | 3/31/97] 100% LEAD AGENCIES 11/6 TT) 3/31 6 FILE ADDENDUM TO NOTICE OF 3/31/97| 4/11/97| 100% INTENT. > 3/31 7 DEVELOP BASE MAPS AND ORDER | 6/11/96] 8/30/96] 100% PHOTOGRAPHY 6/11 3/30 9 PUBLIC/AGENCY SCOPING 11/6/96 | 11/14/96| 100% MEETINGS - INITIAL INTERAGENCY a6 M1404 1 PREPARE MATERIALS/DEVELOP 7/15/96 | 10/25/96| 100% ee 715 A «0/25 13 FINALIZE ALTERNATIVES AND FIELD | 6/24/96| 10/11/96] 100% REVIEW 6/24 i 10/11 15 DRAFT SCOPING REPORT 11/14/96 | 2/14/97| 100% 17 AGENCY COMMENTS 314/97| 4/11/97 100% 1114 I 2114 19 FINALIZE SCOPING REPORT 4i11/97| _4/25/97| 98% 314 MD 41 21 TASK 2 INVENTORY 6/11/96| 9/12/97 95% ant Ml ars : 22 INVENTORY ALTERNATIVES 6/11/96 | 2/28/97] 100% 0 Qa SCC IRAE: we 9/12 24 CONDUCT FIELD REVIEW AND 6/11/96 | 3/31/97] 100% 61 TT 22: AGENCY CONTACTS N 9, 26 AGENCY FIELD RECONAISANCE 6/2/97| 6/6/97| 100% ant a4 27 DATA 8/13/96| 9/12/97] 90% MANAGEMENT/DOCUMENTATION 6/2 FH ais i 29 ADDITIONAL FIELD REVIEW 4/21197| 6/27/97| 90% i SURVEYS AND DOCUMENTATION 8 ee, © 2/41 2 31 TASK 3 IMPACT ASSESSEMENT AND 7/22/96 8/1/97| 97% MITIGATION PLANNING 421 EE sc27 32 DEVELOP PROJECT 7/22/96| 5/2/97| 98% DESCRIPTION/LOCATION 7122 re 8/1 34 DEVELOP IA/MP APPROACH AND 10/21/96| 5/2/97] 100% CRITERIA 7122 | 5/2 36 AGENCY REVIEW AND APPROVE 5/5/97| 5/23/97| 95% 10/21 37 CONDUCT INITIAL IA/MP | 27/9e7| 6/6971 100% ei | = 9 5/5 5/23 39 AGENCY REVIEW AND APPROVE 6/9/97| 6/27/97| 95% POWER Engineers, Inc. Summary v_ ® siMilestone ee Task EE ect ont Project: 120376-01 Revision #3 (09203-009 D&M) 09/06/97 PROJECT SCHEDULE SOUTHERN INTERTIE PROJECT EIS Proposed Anchorage to Kenai Peninsula Transmission Line 1996 1997 1998 1999 ID | Task Name Start Finish | % Compl | Apr |May| Jun | Jul | Aug | Sep | Oct | Nov | Dec | Jan |Feb| Mar | Apr |May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | Jan |Feb| Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | Jan |Feb/} Mar | Apr | May | Jun | Jul 41 FINALIZE IA/MP/DOCUMENTATION 6/30/97| 7/11/97| 90% 6/30 I 7/11 | 43 AGENCY REVIEW AND APPROVE 7/14197| 8/1197] 30% a® on 45 TASK 4 ALTERNATIVE COMPARISONS | 12/16/96| 8/1/97| 53% : ee ___ I) 46 DEVELOP ENVIRONMENTAL 12/16/196| 5/9/97| 85% SELECTION CRITERIA 1216 a 5/0 48 AGENCY REVIEW AND APPROVE §/12/97| 5/30/97] 25% 5/12 5/30 49 CONDUCT ENVIRONMENTAL 5/12/97| 6/27/97 75% ALTERNATIVE COMPARISONS 5/12 EE 6/27 51 AGENCY REVIEW AND APPROVE 5/12/97| 7/18/97| 10% 512 i 718 53 PREFFERED ALTERNATIVE 6/30/97| 7/25/97| 10% SELECTION 7 _ 6/30 MM 7/25 55 APPLICANTS PROPOSED 7/18/97| 8/1/97| 0% ALTERNATIVE 56 TASK 5 DRAFT EIS 12/10/96| 10/5/98| 19% 718 OH a Cama 57 DEVELOP PURPOSE AND NEED 116/97| 6/27/97| 95% ve) 8 105 59 PREPARE PDEIS 12/10/96| 8/29/97| 15% 16 i SS 6/27 61 AGENCY REVIEW 9/1/97| 10/3197| 0% | 1210 i eT 3/29 63 PREPARE ANILCA APPLICATION 8/1/97| 10/6/97| 0% 91 BE 10/3 64 PREPARE DEIS. 10/16/97| 11/14/97| 0% ot GF 1016 66 FILE ANILCA APPLICATION 10/3/97| 10/3/97 0% Ae iis 67 ANILCA REVIEW 10/3/97| 10/5/98| 0% i 10/3 @ 10/3 68 PRINT DEIS 11/24/97 | 12/19/97] 0% : 103 B @ 10/5 70 FILE DEIS WITH EPA 1/5/98| 1/5/98] 0% 11/24 FE 12/19 7 ~| DISTRIBUTE 7 12/22/97| 1/6/98| 0% oO 15 73 PUBLIC REVIEW 1/5/98| 2/19/98] 0% 12/22 [16 75 FEDERAL HEARING 1/5/98| 2/19/98] 0% ; 1/5 TEE 29 77 | +TASK6FINALEIS 2/23/98| 5/20/99| 0% POWER Engineers, Inc. Summary vB Milestone a Task EEE °ecent one's Project: 120376-01 Revision #3 (09203-009 D&M) 09/06/97 PROJECT SCHEDULE SOUTHERN INTERTIE PROJECT EIS Proposed Anchorage to Kenai Peninsula Transmission Line 1996 1997 1998 1999 ID | Task Name Start Finish | % Compl | Apr |May| Jun | Jul | Aug | Sep | Oct | Nov | Dec | Jan |Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | Jan | Feb} Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | Jan | Feb} Mar | Apr | May | Jun | Jul 135 PUBLIC/AGENCY INVOLVEMENT 8/5/96 | 11/15/98| 58% 2 8/5 eS wy 11/15 PROGRAM | 136 INTERDISCIPLINARY TEAM 116/97| 7/3/98| 78% i 4116 Re 2 BE TI yw 7/3 137 ID TEAM FORMULATION 1/6/97| 4/25/97| 95% 116 @ OD 425 138 MEETINGS 1114197| 7/3/98] 75% MM MI TTT Imm MM? 139 COMMUNITY WORKING GROUP 8/5/96| 6/27/97| 82% Secs eererenenc: mR O 6/27 140 INTERVIEWS 8/5/96 | 10/10/96] 100% 35 BW 10/10 141 MEETINGS 1/13/97| 6/27/97| 75% 142 PUBLIC MEETING/HEARING 11/11/96| 2/19/98] 16% 11 143 SCOPING MEETINGS (3) 11/11/96 | 11/15/96| 100% 8 a9 144 PUBLIC HEARINGS (3) 115/98| 2/19/98| 0% © 3 Scoping Meetings 145 NEWSLETTERS/FACT SHEETS 2/24/97 | 11/15/98| 60% (TM) Public Hearings 146 SCOPING 4/30/97| 4/30/97 95% TT iii iii COLT @® 4 Newsletters/Fact Sheets 147 ALTERNATIVE 8/1/97| 8/1/97| 0% COMPARISON/ANILCA APPLICATION 4130 4/30 9 148 FEIS 7/1198| 7/1/98| 0% a BH a 7 Bm POWER Engineers, Inc. Summary Vv ® Milestone Sa Task HE ¢ont _———— Project: 120376-01 Revision #3 (09203-009 D&M) 09/06/97 PROJECT SCHEDULE SOUTHERN INTERTIE PROJECT EIS Proposed Anchorage to Kenai Peninsula Transmission Line 1996 1997 1998 1999 ID | Task Name Start Finish | % Compl! |Apr|May| Jun] Jul [Aug |Sep | Oct [Nov] Dec | Jan [Feb] Mar | Apr [May] Jun | Jul [Aug [Sep] Oct [Nov] Dec | Jan [Feb] Mar | Apr [May | Jun | Jul | Aug [Sep | Oct [Nov] Dec | Jan [Feb] Mar | Apr [May | Jun | Jul 78 RESPOND TO COMMENTS 2/23/98| 3/20/98; 0% i 2123 MM 3/20 80 | PREPARE PRELIMINARY FEIS 3/23/98| 4/17/98| 0% 3/23 HE 417 82 AGENCY REVIEW AND APPROVE 4/20/98; 5/8/98| 0% 4/20 Hl 5/8 84 PREPARE FEIS 5/11/98| 5/29/98| 0% 5/11 HE 5/29 86 AGENCY REVIEW AND APPROVE 6/1/98| 6/12/98] 0% 64 HE 612 88 PRINT 6/15/98| 6/26/98] 0% 615 ME 6/26 90 FILE FEIS WITH EPA 7/3/98| 7/3/98; 0% 1 DISTRIBUTE 6/15/98| 7/3/98] 0% o 73 93 PUBLIC REVIEW 7/3/98; 8/2/98| 0% 615 Mi 7/3 95 RECORD OF DECISION 70/5/98| _2/5/99| 0% 713 ME 82 97 APPEAL PERIOD 2/5/99 | 5/20/99 0% 10/5 a 25 99 TASK 7 STUDIES - 12/15/96| 7/18/97| 95% —=<= =] Fs 108 Da 100 BENEFIT ANALYSIS 3/17/97| _7/11/97| 100% 1245 — 7/15 101 LIABILITY STUDIES 3/17/97| _7/11/97| 100% Ae ' ° 37 mi 102 ELECTRIC SYSTEM STUDIES 12/15/96| 7/11/97| 90% Cl MiSTU ° 37 Om 1 AGENC! 1 7/14197| 7/18/97| 100% * eens ° 28 ats 104 TASK 8 ENGINEERING FIELD WORK 6/14/96| 7/15/97| 93% 714 @ 7118 196 | 10/14/: 9 aos HYDROGRAPHIC STUDIES ei 4/26 Cree a00% 6/14 Ch OR) ww 715 108 GEOTECHNICAL EVALUATION 7/2196| 1/2/97| 100% 6/14 i 10/14 110 FIELD INVESTIGATIONS 6/14/96| 7/15/97| 100% 72 «2 112 SUMMARY REPORT 10/15/96| 7/15/97| 75% es 7/15 114 TASK 9 PRELIMINARY ENGINEERING 8/1/96 | 9/16/97| 97% : 115 Ys 7/15 134 UPDATE COST ESTIMATE 1/15197| 7/11/97| 97% POWER Engineers, Inc. Summary vv ®siMilestone > Task Ee cont! _ Project: 120376-01 Revision #3 (09203-009 D&M) 09/06/97 PROJECT SCHEDULE POWER Engineers __ Deliverable Tracking System Report Printed: Tue, Sep 16,1997 3:41PM Deliverables by Project Period Ending: 9/6/9 Project: 120376-01 TASK 1 SCOPING Project Manager: Randy Pollock Client: CHUGACH ELECTRIC ASSOCIATION MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask Deliverable Hep inet Milestone Dates comp Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-01-55-01-01 21.04 Reproducible Map/Atlas(using quad maps) Tim Tetherow 6/11/96 9/30/96 100 1.1.02 Presentation Maps(EIS/Public Meetings) Tim Tetherow 6/11/96 100 1.1.03 Color Aerial Photos(1 stereo) Tim Tetherow 6/11/96 9/30/96 100 1.1.03-A 3 Sets Aerial Photos 1":500' Tim Tetherow 6/11/96 9/30/96 100 1.1.03-B 3 Sets Aerial Photos 1":2000' Tim Tetherow 6/11/96 9/30/96 100 120376-01-55-01-02 1.2.01 File Notice of Intent with Fed Register Lead Agency 10/15/96 10/15/96 100 1.2.02 Develop MOU with Agencies Tim Tetherow 11/1/96 1/3/97 100 1.2.03 RUS Scheduled Review Times Tim Tetherow 9/30/96 1/31/97 98 1.2.04 Identify scope of issues to be addressed Tim Tetherow 11/1/96 = 12/31/96 100 1.2.05 Develop Preparation Plan Tim Tetherow 6/24/96 1/15/97 100 1.2.06 Review Preparation Plan Chugach Electric 1/15/97 1/31/97 100 1.2.07 40 Copies of Preparation Plan for EIS Tim Tetherow 2/20/97 2/28/97 100 1.2.08 Public Notification for Scoping Meetings Tim Tetherow 10/1/96 10/31/96 100 1.2.09 Conduct/Coordinate Agency Scoping Tim Tetherow 11/4/96 = 12/31/96 100 1.2.10 Conduct/Coordinate Public Scoping Tim Tetherow 11/4/96 12/31/96 100 1.2414 41 Meeting Anchorage(public/agency scoping) Tim Tetherow 11/1/96 11/29/96 100 1.2.12 1 Meeting Cooper Landing(public/agency scoping) Tim Tetherow 11/1/96 11/29/96 100 1.2.13 1 Meeting Soldotna(public/agency scoping) Tim Tetherow 11/1/96 11/29/96 100 1.2.14 Attend 1 Mtg(Anch, Cooper, Soldotna) Randy Pollock 11/1/96 11/29/96 100 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 1.2.15 Prepare Mat for Public/Agency Scoping Mtg Tim Tetherow 7/15/96 9/3/96 100 1.2.16 Prepare Issues/Scoping Report(documentation) Tim Tetherow 12/2/96 12/31/96 100 C27 Provide Mailing List Tim Tetherow 7/15/96 9/3/96 100 1.2.18 Update Existing Public & Agency Mailing List Tim Tetherow 715/96 9/3/96 100 1.2.19 Review & Approve Mailing List Chugach Electric 8/15/96 9/3/96 100 1.2.20 Newsletter # 1 (prior to scoping) Tim Tetherow 8/15/96 9/3/96 100 1.2.21 Review and Approve Fact Sheet/Newsletter Chugach Electric 8/15/96 9/3/96 100 A:2'22 Establish CWG in Anchorage Tim Tetherow 9/2/96 10/31/96 100 1.2.23 25 Key Informant Interviews(Anchorage) Tim Tetherow 8/1/96 9/30/96 100 1.2.24 12-15 Interviews Kenai/determine need for CWG Tim Tetherow 8/1/96 9/30/96 100 1.2.25 Agency Contacts (Continuing) Tim Tetherow 6/11/96 100 1.2.26 ID Team Meeting #1 (Scoping) Tim Tetherow 12/2/96 12/31/96 100 1.2.27 50 Copies Executive Summary Report Revision 1 Tim Tetherow 10/1/96 10/30/96 100 1.2.28 20 Copies Environmental Report Revision 1 Tim Tetherow 10/1/96 10/30/96 100 120376-01-55-01-03 1.3.03 Review Alternatives Tim Tetherow 8/1/96 10/31/96 100 1.3.04 Field Review of Alternatives Tim Tetherow 6/24/96 9/27/96 100 1.3.05 Identification of Alternatives for EIS Tim Tetherow 12/2/96 12/31/96 100 1.3.06 Agency Meeting to finalize Alternatives Tim Tetherow 12/2/96 12/31/96 100 120376-01-55-01-04 1.4.01 Agency Review & Approval of Scoping Rpt Tim Tetherow 9/30/96 1/31/97 98 1.4.02 40 Copies of Scoping Report Tim Tetherow 1/1/97 1/31/97 100 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 Project: 120376-02 TASK 2 INVENTORY Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask Deliverable ee Milestone Dates comp Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-02-55-02-01 ° 2.1.00 ID Team Mtg(Inventory Results) Tim Tetherow 12/2/96 12/31/96 100 2.1.01 Agency Contacts (Continuing) Tim Tetherow 6/11/96 100 2.1.02 Inventory of Resource Data/Alternatives Tim Tetherow 6/11/96 11/6/96 100 2.1.30 CWG Mtg(Inventory/Assessement Criteria Tim Tetherow 12/2/96 12/31/96 100 120376-02-55-02-02 2.2.01 Compile and Reproduce Inventory Maps Tim Tetherow 10/15/96 11/29/96 99 2.2.02 Provide Associated Data Tables by Route Tim Tetherow 10/15/96 11/29/96 100 2.2.03 Additional Review & Documentation Tim Tetherow 5/7/97 11/20/97 100 120376-02-55-02-03 2.3.01 Identify Number of Parcels for Routes Frank Rowland 8/13/96 11/27/96 100 2.3.01-A 5 Routes Anchorage Frank Rowland 8/13/96 11/27/96 100 2.3.01-B Tesoro Route-Kenai Frank Rowland 8/13/96 11/27/96 100 2.3.01-C Tesoro Route - Soldotna (up to 3 routes) Frank Rowland 8/13/96 11/27/96 100 2.3.01-D Enstar Route Frank Rowland 8/13/96 11/27/96 100 2.3.01-E Quartz Creek Route - Kenai Peninsula Frank Rowland 8/13/96 11/27/96 100 2.3.01-F Quartz Creek between Portage & University Frank Rowland 8/13/96 11/27/96 100 2.3.02 ID Owner, Size, Config sub cable landfall sites Frank Rowland 8/13/96 11/27/96 100 2.3.02-A 3 Sites Kenai Peninsula Frank Rowland 8/13/96 11/27/96 100 2.3.02-B 5 Sites north side of Turnagain Arm Frank Rowland 8/13/96 11/27/96 100 2.3.03 ID Owner,Size,Config of t Alternate Substn Sites Frank Rowland 8/13/96 11/27/96 100 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 120376-02-55-02-04 2.4.01 Provide Right of Entry for ElS Field Studies Frank Rowland 10/15/96 9/8/97 45 120376-02-55-02-05 2.5.01 Conduct Centerline Surveys Soldotna Area Frank Rowland 5/7/97 11/20/97 0 2.5.02 Conduct Centerline Surveys Bernice Lake Area Frank Rowland 5/7/97 11/20/97 0 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 Project: 120376-03 TASK 3 IMPACT ASSESS/MITIG PLN Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask Deliverable Resp Indiv Milestone Dates 4, oon, Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-03-55-03-01 3.1.00 Develop Project Description Tim Tetherow 7/22/96 = 11/8/96 98 3.1.01 ID Team Review of impact criteria, results, mtg Tim Tetherow 1/1197 1/31/97 100 3.1.02 Attend CWG Meeting(Impact Assessement) Tim Tetherow 2/3/97 2/28/97 100 3.1.03 IPG Review of Impacts Chugach Electric 2114/97 2/28/97 0 3.1.04 Final Determination of Project Description Tim Tetherow 11/1/96 11/8/96 98 120376-03-55-03-02 3.2.01 |A/MP Site Specific Models Tim Tetherow 10/21/96 11/29/96 100 3.2.02 Impact Maps & Tables Tim Tetherow 10/21/96 2/28/97 100 3.2.03 Develop/Conduct IA/MPP Tim Tetherow 10/21/96 12/31/96 100 3.2.03-A Define:Potential Direct/Indirect/Cumltv Impacts Tim Tetherow 10/21/96 12/31/96 100 3.2.03-B Define: Interrelationships(cause/effect)impacts Tim Tetherow 10/21/96 12/31/96 100 3.2.03-C Define: Criteria Definition Tim Tetherow 10/21/96 12/31/96 100 3.2.03-D Define: Determination of Impact Significance Tim Tetherow 10/21/96 12/31/96 100 3.2.04 Preliminary Mitigation Asessement(mitigation ID) Tim Tetherow 10/21/96 12/31/96 100 3.2.05 Review Preliminary Mitigation Criteria Tim Tetherow 11/1/96 = 11/29/96 100 3.2.06 Review Prel Assessement & Mitigation Plan Randy Pollock 1/16/98 1/31/97 0 3.2.07 Agency Review & Approval Lead Agency 4/1197 4/25/97 0 3.2.08 Impacts Reassessed Tim Tetherow 2/3/97 2/28/97 100 3.2.09 Residual Impacts Determined Tim Tetherow 3/3/97 3/31/97 95 3.2.10 Finalize Results IA/MP Address Cumulative Effects Tim Tetherow 5/1/97 5/30/97 90 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 120376-03-55-03-03 3.3.01 IA/MPP Incorporated into DEIS & FEIS Tim Tetherow 3/3/97 5/30/97 0 3.3.02 Mitigation Measures incorporated into ROD Tim Tetherow 3/3/97 5/30/97 0 3.3.03 Agency Review & Approval Tim Tetherow 5/15/97 5/30/97 0 3.3.04 Review & Approve Selection Criteria Chugach Electric 5/1/97 5/30/97 0 3.3.05 Review & Approve Preliminary Results Chugach Electric 5/1/97 5/30/97 0 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 Project: 120376-04 TASK 4 ALTERNATIVE SELECTION Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask Deliverable Resp Indiv Milestone Dates» 4, Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-04-55-04-01 4.1.01 Compilation of Impact Data/by Alternative Tim Tetherow 4/1/97 4/18/97 75 4.1.02 Development of Criteria&Rte Comparison Mat Tim Tetherow 4/1/97 4/18/97 85 4.1.03 Two Day Route Comparison Meeting Tim Tetherow 4116/97 = 4/18/97 50 4.1.04 ID Team Meeting(Envirn Pfrd Rte & Agency/Pro Tim Tetherow 6/2/97 6/30/97 0 4.1.05 CWG Meetings(Comparison of Alternatives) Tim Tetherow 5/1/97 5/30/97 0 4.1.06 IPG Meeting Chugach Electric 6/2/97 6/30/97 0 4.1.07 Public Open House (Optional) Tim Tetherow 5/1/97 5/30/97 0 4.1.07-A Anchorage(Optional) Tim Tetherow 5/1/97 5/30/97 0 4.1.07-B Cooper Landing(Optional) Tim Tetherow 5/1/97 5/30/97 0 4.1.07-C Soldotna(Optional) Tim Tetherow 5/1/97 5/30/97 0 4.1.08 Review & Approve Selection Criteria Chugach Electric 4/21/97 = 4/30/97 0 4.1.09 Select Agency Preferred Route Lead Agency 5/15/97 6/13/97 0 4.1.10 Comparison & Cross Discipline rankings/Alt Corr Tim Tetherow 4/1/97 4/30/97 0 4.1.11 Consideration of Public & Agency Comments Tim Tetherow 6/13/97 7/18/97 0 4.1.12 Select Environmentally Preferred Alternative Tim Tetherow 6/13/97 7/18/97 0 120376-04-55-04-02 4.2.01 Newsletter # 2 (Route Selection Results) Tim Tetherow 7/1197 7131197 0 4.2.02 Review & Approve Newsletter #2 Chugach Electric 7/15/97 7131/97 0 4.2.03 Documentation of Route Selection Process Tim Tetherow 4/1/97 8/29/97 55 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 Project: 120376-05 TASK 5 DRAFT EIS Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask | Deliverable Reap liv Milestone Dates 4, Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-05-55-05-01 5.1.01 ID Team Mtg # 4 (PDEIS Review/Approval) Tim Tetherow 9/1/97 9/30/97 0 5.1.02 Environmental Data Maps Tim Tetherow 2/3/97 9/15/97 45 5.1.03 14 - 8 1/2 X 11 Color Map Photos Tim Tetherow 2/3/97 9/15/97 0 5.1.04 2 - 18 X 30 Color Maps Tim Tetherow 2/3/97 9/15/97 0 5.1.05 23 - 11 X 17 Color Maps Tim Tetherow 2/3/97 9/15/97 0 5.1.06 Develop Purpose and Need Statement Tim Tetherow 2/3/97 9/15/97 10 5.1.07 Prepare Preliminary DEIS Tim Tetherow 6/23/97 9/17/97 15 5.1.08 40 Copies (150 pages each) PDEIS Tim Tetherow 9/15/97 9/30/97 0 5.1.09 Distribution of Copies Chugach Electric 9/15/97 9/30/97 0 5.1.10 Review PDEIS Chugach Electric 9/1/97 9/15/97 0 120376-05-55-05-02 §.2.01 ID Team Mtg # 5 (DEIS Review/Approval) Tim Tetherow 11/3/97 = 11/28/97 0 5.2.02 Compile & Incorporate Changes to PDEIS Tim Tetherow 10/31/97 11/21/97 0 5.2.03 Finalize DEIS Tim Tetherow 10/31/97 11/21/97 0 5.2.04 Review DEIS Lead Agency 11/25/97 12/19/97 0 5.2.05 Review & Approve DEIS Chugach Electric 11/25/97 12/19/97 0 120376-05-55-05-03 5.3.01 Provide Lead Agency Signature Lead Agency 1114/98 =. 3/16/98 0 5.3.02 File with EPA Tim Tetherow 1114/98 = 3/20/98 0 5.3.03 Print & Distribute DEIS Tim Tetherow 12/22/97 1/9/98 0 5.3.04 200 Copies(150 pgs/each) to Lead Fed Agency Tim Tetherow 1/26/98 = 1/30/98 0 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 5.3.05 Publish Notices of Availability Lead Agency 2/2/98 3/20/98 0 5.3.06 Distribute Copies to Interested Parties & Agencies Lead Agency 2/2/98 3/20/98 0 120376-05-55-05-04 5.4.01 ID Team Meeting # 6 (Pre-Hearing) Tim Tetherow 1/1/98 1/30/98 0 5.4.02 Newsletter # 3 (Announce Public Hearings) Tim Tetherow 1/1/98 1/30/98 0 5.4.03 Review & Approve Newsletter # 3 Chugach Electric 1/15/98 1/30/98 0 5.4.04 Schedule & Conduct Public Hearing # 1 Tim Tetherow 2/2/98 2/27/98 0 5.4.04-A Anchorage Tim Tetherow 2/2/98 2/27/98 0 5.4.04-B Cooper Landing Tim Tetherow 2/2/98 2/27/98 0 5.4.04-C Soldotna Tim Tetherow 2/2/98 2/27/98 0 5.4.05 Public/Agency Review of DEIS Lead Agency 2/2/98 3/20/98 0 5.4.06 Recieve/Compile Public Comments on DEIS Tim Tetherow 2/2/98 3/20/98 0 5.4.07 Respond to Comments Tim Tetherow 2/2/98 3/20/98 0 5.4.08 Attend Federal Hearings Tim Tetherow 2/16/98 3/11/98 0 120376-05-55-05-22 5.22.01 Review Comments on SIP Randy Pollock 6/1/97 6/20/97 0 5.22.02 Increased Reliability Randy Pollock 6/1/97 7/25/97 0 5.22.03 Increased Transfers-Econ Energy Randy Pollock 6/1/97 7/25/97 0 5.22.04 Reduced Transmission Losses Randy Pollock 6/1/97 7/25/97 0 5.22.05 Increased State Gas Royalty Randy Pollock 6/1/97 7/25/97 0 5.22.06 Deferral/Avoidance New Generation Cap Randy Pollock 6/1/97 7/25/97 0 5.22.07 Reduced Maintenance Cost Randy Pollock 6/1/97 7/25/97 0 5.22.08 Teleconference-Rww Project Status Randy Pollock 6/23/97 6/27/97 0 5.22.09 Issue Draft Statement Randy Pollock T1197 7/25/97 0 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 Project: 120376-06 TASK 6 FINAL EIS Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask Deliverable Resp Indiv Milestone Dates 4 con, Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-06-55-06-01 ° 6.1.01 Newsletter(Announce FEIS) Tim Tetherow 7/1/98 7/31/98 0 6.1.02 ID Team Mtg(Rvw Comments) Tim Tetherow 3/20/98 3/31/98 0 6.1.03 Respond to comments Tim Tetherow 3/20/98 4/17/98 0 6.1.04 Prepare PFEIS Tim Tetherow 4/20/98 5/20/98 0 6.1.05 ID Team Mtg(Review PFEIS) Tim Tetherow 5/1/98 5/29/98 0 6.1.06 Agency Review & Approval Lead Agency 5/21/98 6/10/98 0 6.1.07 Review PFEIS Chugach Electric 6/21/98 6/10/98 0 6.1.08 40 Copies of PFEIS Tim Tetherow 5/11/98 5/20/98 0 120376-06-55-06-02 6.2.01 Compile & Respond to Comments Tim Tetherow 6/21/98 6/10/98 0 6.2.02 Prepare FEIS Tim Tetherow 6/11/98 7/3/98 0 6.2.03 Review & Approve FEIS Chugach Electric 7/6/98 7/27/98 0 6.2.04 Provide Lead Agency Signature Tim Tetherow 8/10/98 8/20/98 0 6.2.05 Prepare FEIS for Printing Tim Tetherow 7/28/98 8/18/98 0 6.2.06 Agency Review & Approval Lead Agency 7/6/98 7/27/98 0 120376-06-55-06-03 6.3.01 Print & Distribute FEIS Tim Tetherow 9/4/98 9/9/98 0 6.3.02 200 Copies for Distribution Tim Tetherow 9/4/98 9/9/98 0 120376-06-55-06-04 6.4.01 FEIS Available to Public Tim Tetherow 9/9/98 10/23/98 0 6.4.02 Public Review Tim Tetherow 9/9/98 10/23/98 0 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 120376-06-55-06-05 6.5.01 File FEIS with EPA Lead Agency 8/20/98 9/2/98 0 6.5.02 Record of Decision Lead Agency 7/6/98 8/28/98 0 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 Project: 120376-07 TASK 7 SYSTEM STUDIES Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask Deliverable Milestone Dates Scheduled Review Dates ID Number Description apne Start Finish “°°? 50% Client _Final 120376-07-22-07-05 7.5.01 Summary Report William Riall 7I15/96 = 8/14/97 50 7.5.02 Recommend Dsg Parameters William Riall TNS5/I96 = 8/14/97 70 7.5.03 Telephone Contacts William Riall 715/96 = 8/14/97 70 120376-07-22-07-06 7.6.01 EMF Models Larry Henriksen 7/15/96 = 8/14/97 100 7.6.02 EIS & Prelim Eng Calculations Larry Henriksen 715/96 8/14/97 100 7.6.03 Text & Graphs or Charts-EIS Larry Henriksen 75/96 ~—- 8/14/97 100 7.6.04 RFI/TVI & Audible Noise Analysis Larry Henriksen 75/96 = 8/14/97 80 7.6.05 Attendance at Public Hearings (Mike Silva) Larry Henriksen 2/2/98 2/27/98 0 120376-07-22-07-07 7.7.01 Summary Report William Riall 7INS/96 8/14/97 90 7.7.02 Recommend Design Parameters William Riall 75/96 8/14/97 90 7.7.03 Office Visit to Pipeline-Anchorage William Riall 715/96 8/14/97 100 7.7.04 Telephone Contact of Pipeline William Riall 7/15/96 8/14/97 60 120376-07-23-07-01 t01 Determine System Requirements Ronald Beazer 7H1I96 12/31/96 100 7.1.02 Transfer Limits Ronald Beazer 7/1196 12/13/96 100 7.1.03 Meeting with IPG Members Ronald Beazer 8/5/96 8/6/96 100 120376-07-23-07-02 7.2.01 Emergency Transfer Limits Ronald Beazer 7/1196 12/13/96 100 12 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 120376-07-23-07-03 7.3.01 Dynamic Stability Analysis Ronald Beazer 7/1196 =: 12/13/96 100 120376-07-23-07-04 7.4.01 10 Copies Draft Report Section Ronald Beazer 11/25/96 12/6/96 100 7.4.02 IPG Teleconference Ronald Beazer 12/2196 12/9/96 0 7.4.03 Final Report Section Ronald Beazer 12/9/96 12/13/96 90 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 Project: 120376-08 TASK 8 ENGINEERING FIELD WORK Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask Deliverable Resp Indiv Milestone Dates comp Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-08-22-08-01 8.1.01 Hydrographic Rpt Bottom Profiles William Riall 6/14/96 10/14/96 100 8.1.02 One Mobilization-Hydrographic Subcontractor William Riall 6/14/96 8/15/96 100 120376-08-22-08-02 8.2.01 Report Findings of Investigations William Riall 6/14/96 10/14/96 100 8.2.02 Work Log of Hydrographic Survey William Riall 6/14/96 10/14/96 100 8.2.03 Field Eng Present During Hydro Survey William Riall 6/14/96 = 10/14/96 100 8.2.04 Analyze Data-Hydrographic Survey William Riall 6/14/96 10/14/96 100 8.2.05 Feasibility Submarine Cable Crossings William Riall 6/14/96 10/14/96 90 8.2.06 Assessment of Cable Embedment Opt. William Riall 6/14/96 10/14/96 90 8.2.07 Recommend Prelim Cable Const William Riall 10/1/96 10/14/96 35 8.2.08 Prelim Recommend-Armoring & Install William Riall 10/1/96 10/14/96 35 120376-08-22-08-03 8.3.01 Geotechnical Information Summary Larry Henriksen 11/1/96 1/2/97 0 8.3.02 Review Existing Geotech Data Larry Henriksen 7/1/96 1/2/97 5 8.3.03 Review Construction & Operations Experience Larry Henriksen 7/1196 1/2/97 0 8.3.04 Arrange For & Use Geotech Larry Henriksen 7/1196 1/2197 0 8.3.05 Visit to Enstar's Offices Lower 48 William Riall 7/1196 1/2/97 0 8.3.06 Visit to Tesoro's Offices Lower 48 William Riall 71196 1/2/97 0 120376-08-22-08-04 8.4.01 Summarize Field Notes Larry Henriksen 6/14/96 8/15/97 95 8.4.02 Field Observations-Environ Personnel Tim Tetherow 6/14/96 = 8/15/97 95 14 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 8.4.03 Field Observations-Eng Personnel Larry Henriksen 6/14/96 8/15/97 95 8.4.04 Identify Propective Centerline Locations Larry Henriksen 6/14/96 8/15/97 95 8.4.05 Identify Potential Mitigation Methods Larry Henriksen 6/14/96 8/15/97 95 8.4.06 Identify Most Appropriate Structure Types Larry Henriksen 6/14/96 8/15/97 95 8.4.07 Select Submarine Cable Landfall Locations William Riall 6/14/96 8/15/97 95 8.4.08 Identify Tech or Environmental Challenges Larry Henriksen 6/14/96 8/15/97 95 8.4.09 Note Other Observed Features Larry Henriksen 6/14/96 8/15/97 95 8.4.10 Fixed Wing Aircraft Overflight-ID'd Routes Larry Henriksen 6/14/96 8/1/96 100 8.4.11 3 Days Helicopter Reconnaissance Larry Henriksen 6/14/96 8/1/96 100 8.4.12 9 Days on Ground Reconnaissance Larry Henriksen 6/14/96 8/15/97 100 8.4.13 Detailed Field Review/Alternatives in Table 1 Larry Henriksen 6/14/96 8/15/97 95 120376-08-22-08-05 8.5.01 Copies of Summary Field Report Michael Walbert 10/15/96 2/13/98 16 8.5.02 Prelim Submarine Cable Recommendations William Riall 6/14/96 =—-.2/13/98 30 8.5.03 Observations & Conclusions Impacting Project William Riall 6/14/96 2/13/98 75 15 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 Project: 120376-09 TASK 9 PRELIM ENGINEERING Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date 6/10/96 MIS Project End Date 6/10/97 Task/Subtask Deliverable Resp Indiv Milestone Dates % Comp Scheduled Review Dates : : : ‘0 . . ID Number Description P Start Finish 50% Client Final 120376-09-21-09-07 9.07.01 One-Line and General Arrangement Drawings Stanley Sostrom 8/1/96 12/2/96 100 9.07.02 Modify Existing General Arrangement Plans Stanley Sostrom 8/1/96 12/2/96 100 9.07.03 Identify & Note Bus Connct & Phasing on DWGS Stanley Sostrom 8/1/96 12/2/96 100 9.07.04 Determine Const/Operation/Maintenance Stanley Sostrom 8/1/96 12/2196 100 120376-09-21-09-08 9.08.01 Supplemental Design Criteria Stanley Sostrom 8/1/96 12/2/97 100 120376-09-21-09-09 9.09.01 Modify One Lines and General Arrangements Stanley Sostrom 8/1/96 12/2/96 100 9.09.02 Determine Const/Operation/Maint Requirements Stanley Sostrom 8/1/96 12/2/96 100 120376-09-21-09-10 9.10.01 Cost Estimates William Riall 1115/97 5/14/97 100 120376-09-21-09-13 9.13.01 Cost Estimate Stanley Sostrom 4/15/97 = 5/14/97 100 9.13.02 Compile/Review Vendor Support Data Stanley Sostrom 1/15/97 5/14/97 100 120376-09-21-09-14 9.14.01 3 Identified Alternative Routes Cost Estimates Frank Rowland 4115/97 5/14/97 100 9.14.02 Develop Land Costs Frank Rowland 1/15/97 5/14/97 100 9.14.03 Develop Labor/Exp Costs to Acquire Easements Frank Rowland 1/15/97 = 5/14/97 100 120376-09-22-09-01 9.01.01 Manufacturer & Factory Inspections William Riall 10/16/96 4/15/97 100 9.01.02 Utility Specific Operating Data William Riall 10/16/96 4/15/97 100 16 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 9.01.03 1- 7 Day Trip for 2 people to Denmark William Rial! 10/16/96 4/15/97 100 120376-09-22-09-02 9.02.01 Preliminary Design Parameters William Riall 10/16/96 4/15/97 100 9.02.02 Preliminary Performance Specs William Riall 10/16/96 4/15/97 100 9.02.03 Determine Const/Operation/Main Requirements William Riall 10/16/96 4/15/97 100 120376-09-22-09-03 9.03.01 10 Copies of Summary Report William Riall 2/3/97 4/15/97 80 9.03.02 Recommend Specific Cable Type William Riall 2/3/97 4/15/97 80 9.03.03 Recommend Most Probable Method of Installation William Riall 2/3/97 4/15/97 80 120376-09-22-09-04 9.04.01 Preliminary Site Specific Arrangements William Riall 1/1/97 4/15/97 100 9.04.02 Engineering Sketches of Transition Station William Riall 1/1/97 4/15/97 100 9.04.03 DSGN Parameters/EIS Support/10 Sub CBL Landfalls William Riall 1/1/97 4/15/97 100 9.04.04 DSGN Parameters/EIS Support/2 Transiton Sites William Riall 1/1/97 4/15/97 100 120376-09-22-09-05 9.05.01 Preliminary Design for Wood Pole H-Frame Larry Henriksen 9/16/96 9/16/97 100 9.05.02 Prel DSGN for DBL Circuit Single Pole Structures Larry Henriksen 9/16/96 9/16/97 100 9.05.03 Est/Dist Underbuilt to Single Pole Struct Larry Henriksen 9/16/96 9/16/97 100 9.05.04 Determine Const/Operation/Maint Requirements Larry Henriksen 9/16/96 9/16/97 100 120376-09-22-09-06 9.06.01 Site Visits Stanley Sostrom 8/1/96 8/30/96 100 9.06.02 Data Acquisition/Drawing Collection Stanley Sostrom 9/2/96 10/15/96 100 9.06.03 Schedule and Attend Meetings Stanley Sostrom 9/2/96 12/2/96 100 9.06.04 Provide Supplemental Design Criteria Stanley Sostrom 9/2/96 12/2/96 100 9.06.05 One Mobilization/Office Visit Stanley Sostrom 9/2/96 12/2/96 100 17 Deliverable Tracking System Deliverables by Project Period Ending: 9/6/9 120376-09-22-09-11 9.11.01 Cost Estimates guyed "X" Larry Henriksen 1/15/97 5/14/97 100 9.11.02 Cost Estimates Single Sti Pole Single Circuit Larry Henriksen 1/15/97 5/14/97 100 9.11.03 Cost Estimates Wood Pole H-Frame Larry Henriksen 1/15/97 5/14/97 100 9.11.04 Cost Estimates DBL Circuit Single Pole Larry Henriksen 1/15/97 = 5/14/97 100 9.11.05 Cost Est Addition of Underbuilt to Single Pole Larry Henriksen 1/15/97 5/14/97 100 9.11.06 Narrative of Cost Estimate Process Larry Henriksen 1/15/97 5/14/97 100 9.11.07 Summary Cost Report Larry Henriksen 4/15/97 = 5/14/97 100 120376-09-22-09-12 9.12.01 Cost Estimate for 2 New Endpoints Stanley Sostrom 1/15/97 5/14/97 100 9.12.02 Narrative of Cost Estimate Process Stanley Sostrom 1/15/97 5/14/97 100 9.12.03 Summary Cost Report Stanley Sostrom 4/15/97 = 5/14/97 100 120376-09-23-09-15 9.15.01 15 Copies Summary Reports Michael Walbert 4/15/97 5/14/97 75 18 United States Department of Agriculture Rural Development Rural Business— Cooperative Service Rural Housing Service Rural Utilities Service Washington, DC 20250 CPO USDA S—n Se pret by Cee Cre Ws Mcmnth Ctinripel fo SEP 3 1997 TEAL by Are eat Ms. Dora L. Gropp Manager, Transmission & Special Projects g SEP 5 1997 Chugach Electric Association, Inc. e 5601 Minnesota Drive Anchorage, Alaska 99519-6300 SPECIAL PROJECT Dear Ms. Gropp: Enclosed is a copy of the Cooperative Agreement between the Rural Utilities Service (RUS) and the Intertie Participants Group for the preparation of the Environmental Impact Statement (EIS) for the Southern Intertie Project. The Cooperative Agreement has been signed by the Under Secretary for Rural Development. Please ensure that Mr. Eugene Bjornstad, General Manager of Chugach Electric Association, and Mr. Norman Story, General Manager of Homer Electric Association sign the Cooperative Agreement as soon as possible. A signed copy should be faxed to RUS at (202) 720-0820. The copy with the original signatures can be returned to RUS when you travel to Washington, DC for the project briefing that is scheduled for September 16, 1997. The Interagency Agreement between the Corps of Engineers (Huntington District) and RUS has also been signed. This agreement allows RUS to use the Mangi Environmental Group to prepare the EIS for the project under Mangi’s existing contract with the Corps of Engineers. Timely receipt of the signed Cooperative Agreement should enable RUS to have the Mangi Environmental Group under contract prior to the scheduled site visit. If you have any questions, please contact Larry Wolfe at (202) 720-5093. Engineering and Environmental Staff Rural Utilities Service Enclosures Rural Development is an Equai Opportunity Lender. Complaints of discrimination should be sent to: Secretary of Agriculture, Washington, OC 20250. (srr be RR ECEIveE D USDA SIE United States Prete aetreter oe SEP 3 1997 Agriculture jie R Eceive p cooperative Service Ms. Dora L. Gropp . Manager, Transmission & Special Projects SEP 5 wt Chugach Electric Association, Inc. 897 a an __ 5601 Minnesota Drive TRANSMISSION ¢ ral uuitles Serve2 AW Hchorage, Alaska 99519-6300 SPECIAL PROJECT “fashington, DC 0250 Dear Ms. Gropp: Enclosed is a copy of the Cooperative Agreement between the Rural Utilities Service (RUS) and the Intertie Participants Group for the preparation of the Environmental Impact Statement (EIS) for the Southern Intertie Project. The Cooperative Agreement has been signed by the Under Secretary for Rural Development. Please ensure that Mr. Eugene Bjornstad, General Manager of Chugach Electric Association, and Mr. Norman Story, General Manager of Homer Electric Association sign the Cooperative Agreement as soon as possible. A signed:eepy: should. be-faxed to RUS at (202) 720-0820. The copy:with the-original-signatures can be feturtied to RUS when you travel to Washington, DC for the project briefing that is scheduled for September 16, 1997. The Interagency Agreement between the Corps of Engineers (Huntington District) and RUS has also been signed. This agreement allows RUS to use the Mangi Environmental Group to prepare the EIS for the project under Mangi’s existing contract with the Corps of Engineers. Timely receipt of the signed Cooperative Agreement should enable RUS to have the Mangi Environmental Group under contract prior to the scheduled site visit. If you have any questions, please contact Larry Wolfe at (202) 720-5093. Sincerely, RYY Me CH" pu? irectér yo Engineering and Environmental Staff g | oT Rural Utilities Service fl Enclosures Rural Development is an Equal Opportunity Lender. Complaints of discrimination should be sent to: Secretary of Agriculture, Washington, OC 20250. (Darna ATTACHMENT B No.18 06/20/97 MEMORANDUM OF UNDERSTANDING BETWEEN RURAL UTILITIES SERVICE, U.S. FOREST SERVICE, U.S. FISH AND WILDLIFE SERVICE, AND CHUGACH ELECTRIC ASSOCIATION, INC. FOR THE PREPARATION OF AN ENVIRONMENTAL IMPACT STATEMENT FOR THE SOUTHERN INTERTIE PROJECT TD: VK eR. USFS: 97TMOU-10-04-002 eye) USFWS: 1448-70181-97-K004 - fvrolixe 2) CEA: £9590081 : S(ad-1099 I. INTRODUCTION AND PURPOSE Seven electric utilities that are collectively known as the Intertie Participants Group (IPG) have proposed to construct a new transmission line in Alaska. The IPG consists of Chugach Electric Association, Inc. (Chugach); Municipality of Anchorage - Municipal Light and Power; City of Seward - Seward Electric System Matanuska Electric Association, Inc.; the Municipality of Fairbanks - Fairbanks Municipal Utilities System; Golden Valley Electric Association, Inc. (GVEA); and Homer Electric Association, Inc. (HEA). These seven utilities are jointly identified as the Applicant. The proposal, which is referred to as the Southern Intertie Project (Proposed Project), consists of the construction and operation of a 230 kilovolt (kV) transmission line and associated facilities to be operated initially at 138kV between Anchorage and a location on the Kenai Peninsula in Alaska. Chugach will act as the construction manager for the Proposed Project. j Whereas Federal lands and/or Federal financing assistance may be required, the Rural Utilities Service (RUS) will be the Lead Agency; and U.S. Fish and Wildlife Service (USFWS) and U.S.D.A. Forest Service (USFS) will be Cooperating Agencies for the National Environmental Policy Act (NEPA) process. It is the purpose of this memorandum to establish an understanding between the Lead Agency, Cooperating Agencies, and Applicant regarding the conditions and procedures to be followed in preparation of the environmental impact statement (EIS) through a joint Applicant/Agency effort. The EIS will be prepared in compliance with NEPA, as implemented by the Council on Environmental Quality (CEQ) Regulations 40 CFR Parts 1500-1508 and RUS environmental policies and procedures (7 CFR Part 1794) plus the pertinent regulations of the USFWS and USFS as appropriate. One or more of the alternative routes being considered would cross the Kenai National Wildlife Refuge, a designated conservation system unit under the Alaska National Interest Lands Conservation Act (ANILCA) (P.L. 96-487). Therefore regulations implementing Title XI of ANILCA will apply to the entire project (43 CFR Part 36). The Title XI Transportation/Utility Systems Permit Application will P:\09203\0WMOUIS.DFT 1 06/20/97 No.18 be prepared in conjunction with the EIS and will be filed with the USFWS and USFS 16 months prior to the issuance of the Record of Decision (ROD). The objective of this Memorandum of Understanding (MOU) is to ensure the timely preparation of an EIS that (a) satisfies the environmental review requirements of the Lead Agency, Cooperating Agencies, and other applicable Federal environmental regulations and legislative requirements; and (b)establish a process to conduct an environmental review of the alternatives identified that would meet the needs of the IPG. The Lead Agency and the Cooperating Agencies have agreed to achieve consensus on the process and content of the EIS, and the decision-making in accordance with their applicable laws and regulations. The EIS will be prepared by a third-party contractor under the direction of the lead and cooperating agencies. To facilitate the environmental review process, the Applicant will provide an environmental analysis (EVAL). The EIS will be based on the EVAL prepared by the Applicant’s Consultant. The Applicant and its Consultant will also provide the Lead Agency and Cooperating Agencies technical assistance for the EIS preparation, as required. Il. JOINT RESPONSIBILITIES The Lead Agency, Cooperating Agencies, and Applicant, to the extent of their involvement and jurisdiction in the Proposed Project, shall: ’ = Identify the significant issues to be studied, identify the project alternatives to be studied and the environmentally preferred alternative, and coordinate the decision process. ® Actively participate in all phases of EVAL and EIS preparation as specified in the attached work plan. The work plan may be modified by the Lead Agency with input from Cooperating Agencies in the event that action or policy changes occur which affect proposed project scope, or as a result of the public participation process. ® Participate in the process as appropriate with Federal, state, regional, and local agencies and the public for the purpose of increasing communication and soliciting comments on the EIS. = Facilitate coordination of efforts and exchange of information. = Designate a representative(s) to serve as the day-to-day liaison and/or contact person for this proposed project. ® Hold public hearings on the draft EIS (DEIS) as required. = After the close of the DEIS review and comment period, review the comments submitted by the public and Federal, state, and local agencies, and develop responses to comments for incorporation into the final EIS (FEIS). P\O7203WOMMOUI8.DFT 2 06/20/97 No.18 = Prepare a mailing list for distribution of project information. II. INDIVIDUAL RESPONSIBILITIES In addition to the joint responsibilities mentioned above, the parties will have the following individual responsibilities: 1. LEAD AGENCY RESPONSIBILITIES RUS as the Lead Agency will: provide direction to the Applicant’s Consultant in the preparation of the EVAL ensure that the DEIS is based on the Applicant’s EVAL and other information, with support from the Cooperating Agencies direct the development of the DEIS by the third-party contractor receive all comments on the DEIS direct the preparation of the FEIS by the third-party contractor, with support from the Cooperating Agencies issue a ROD if required, review the S.F.299 application 2. USFWS RESPONSIBILITIES (COOPERATING AGENCY) The USFWS will: provide assistance to the Lead Agency and the Applicant’s Consultant in the preparation of the EVAL to ensure that USFWS issues are incorporated review and formally comment on the Applicant’s EVAL or sections thereof review and comment on the DEIS and FEIS prior to filing with EPA if required, review the S.F.299 application for a right-of-way across National Wildlife Refuge lands under Title XI of ANILCA and issue a ROD 3. USFS RESPONSIBILITIES (COOPERATING AGENCY) PAO9AS\OMMOUI.DFT 3 06/20/97 No.18 The USFS will: provide assistance to the Lead Agency and the Applicant’s Consultant in the preparation of the EVAL to ensure that USFS issues are incorporated review and formally comment on the Applicant’s EVAL or sections thereof review and comment on the DEIS and FEIS prior to filing with EPA if required, review the S.F.299 application for a right-of-way permit across Chugach National Forest lands and issue a ROD 4. APPLICANT RESPONSIBILITIES - The Applicant will: IV. provide engineering, construction, financial analysis, technical and environmental informa- tion to the Lead Agency and Cooperating Agencies for the preparation of the EIS be responsible for identifying and securing all Federal, state, and local permits and authorizations required for construction and operation of the proposed project in accordance with applicable laws reimburse the lead and Cooperating Agencies for costs associated with preparation of the EIS prepare the EVAL through their Consultant mim the following EIS support: prepare work plan/scoping report - develop purpose and need statement and project description - conduct supplemental public involvement activities - assist in preparing responses to the DEIS comments and incorporation into the FEIS - maintain project mailing list - print and assist in distribution of the EIS - schedule public hearings if required - manage the schedule MODIFICATIONS AND TERMINATION 1. Each party to this MOU may terminate this agreement after thirty days prior notice, in writing, to the other parties. During the intervening thirty days, the parties agree to actively attempt to resolve any outstanding disputes and disagreements. P:\0920300AMOU18.DFT 4 06/20/97 No.18 2. The Applicant shall not direct the modification, inclusion, or exclusion of any materials pertinent to the EIS preparation excepting the exclusion of confidential information. 3. The Applicant recognizes the responsibility of the Lead Agency and Cooperating Agencies to comply with NEPA, determine the necessity for preparing an EIS, define the issues, review and require modifications of the EIS, and respond to the public and the agencies' comments on the EIS. However, in executing the MOU, the Applicant reserves the right to contest, in any administrative or judicial proceedings, any adverse decision concerning the issues in the EIS or any other Federal or state requirements relating to the proposed project. 4. No member of, or delegate to, congress or resident commissioner shall be admitted to any share or part of this agreement, or to any benefit that may arise therefrom; but this provision shall not be construed to extend to this agreement if made with a general corporation for its general benefit. 5. This MOU becomes effective upon the signature by the last party. It will remain in force thereafter, unless terminated in writing as discussed in Item 1 of this section. The MOU may be subject to annual amendments, or as otherwise becomes necessary, which will outline work to be accomplished during that period. In no event will this MOU remain in effect longer than three years from its effective date. 6. Nothing herein shall be construed as delegating the government to expend, or as involving the United States in any contract or other obligation for the future payment of, money in excess of appropriations authorized by law and administratively allocated for this work. 7. During the performance of this MOU, the participants agree to abide by the terms of Executive Order 11246 on non-discrimination and will not discriminate against any person because of race, color, religion, sex, or national origin. The participants will take affirmative action to ensure that Applicants are employed with no regard to their race, color, religion, age, or national origin. P:\09203\00"AMOUI8.DFT 5 06/20/97 No.18 We have read the foregoing and agree to accept the provisions herein. For the U.S. Forest Service: For the Rural Utilities Service: For the U.S. Fish and Wildlife Service: For Chugach Electric Association, Inc. -for Intertie Participants Group: Date: C‘éCTD ttl”: 24 \9 oil signea:_Colouyn Tove WM. hye Signed: Title: Acting Kegicnai Director Title: W447 ’ Ss / (lp P:\O9203\009\MOUIS.DFT 6 ql Transmission Report Date/Time Local 1D Local Name Company Logo Qrnis document was confirmed. (reduced samp Document Size le and detai Letter-S ATIACHMENT B No.18 0620/97 MEMORANDUM OF UNDERSTANDING BETWEEN RURAL UTILITIES SERVICE, U.S, FOREST SERVICE, U.S. FISH AND WILDLIFE SERVICE, AND (CHUGACH ELECTRIC ASSOCIATION, INC. FOR THE PREPARATION OF AN ENVIRONMENTAL IMPACT STATEMENT FOR THE ‘SOUTHERN INTERTIE PROJECT a D: MK R, js ‘STMOU-10-04-002 a 2448-70181-97-K004 - Storm: Nove); i ® = 19590081 7 'e Sila? 12% 1. INTRODUCTION AND PURPOSE Seven electric utilities that are collectively imown as the Intertie Participan's Group (IPG) have proposed 10 conserect & new transmission line in Alaska. The IPG consists of Chugach Electric Association, Inc. (Chugach); Municipality of Anchorage - Municipal Light and Power; City of Seward - Seward Electric ‘Systemy Maramuska Electric Association, Inc.; the Municipality of Fairbanks - Fairbanks Manicipal Utilities System; Golden Valley Electric Association, Inc. (GVEA); and Homer Electric Association, Inc, GHEA). These seven wtlities aro jointly ideatified as the Applicant. The proposal, which ix referred to as the Souther Interie Project (Proposed Project), consists of the construction and opecation of a 230 Kilovolt (KV) transmission line and associated facilities to be operated initially at 138kV betweex ‘Anchorage and 2 location on the Kenai Peninsula in Alaska. Chogach will act as the constmctioa managex for the Proposed Project. s Whereas Fedecal lands and/or Federal financing assistunce may be required, the Rural Utilities Service (RUS) will be the Lead Agency; and U.S. Fish and Wildlife Service (USFWS) and U.S.D.A. Forest Service (USFS) will be Cooperating Agencies for the National Environmental PoEcy Act (NEPA) process. It isthe purpose of this memorandum to establish an underseanding between the Lead Agency, Cooperating Agencies, sad Applicant regarding the conditions und procedares to be followed in Preparation of the eavironmenta! impact statement (EIS) through a joint Applicaut/Agency effort. The EIS will be prepared in compliance with NEPA, ax implemented by the Council on Environmental Quilisy (CEQ) Regulations 40 CFR Parts 1500-1508 and RUS environmental policies and procedures (7 CFR Part 1794) plus the pertinent regulations of the USFWS and USFS as appropriate. ‘Que or more of the alternative routes being considered would cross the Kenai Natiowal Wildlife Refuge, ‘\ designated conservation system unit under the Alaska National Interest Lands Conservation Act (ANILCA) (P.L. 96-487). Therefore regutations implementing Title X1 of ANILCA will apply to the entire project (43 CFR Part 36). The Title XI Transportation/Utility Symems Permit Application will 9-15-97; 2:13PM 907 762 4617 Trans Sp. Projects CHUGACH ELECTRIC ASSOC. INC Is below) Prema FT Total Pages Scanned : 6 Total Pages Confirmed : 6 No. |Doc|Remote Station Start Time Duration|Pages Mode Ccomments|Results 1)028 DAMES & MOORE — ANC 9-15-97; 2:10PM S* ee" 6/7 6 Ec cP 14400 xx Notes ** Ec: Error Correct RE: Resend PD: Polled by Remote MB: Receive to Mailbox BC: Broadcast Send MP: Multi-Poll PG: Polling a Remote Pl: Power Interruption cP: Completed RM: Receive to Memory OR: Document Removed TT: Terminated by user LS: Local Scan LP: Local Print FO: Forced Output WT: Waiting Transfer FAX TRANSMISSION CHUGACH ELECTRIC ASSOCIATION, INC. P.O. Box 196300 ANCHORAGE, ALASKA 995 | S-G6300 (907) 762-460! Fax: (GO7) 762-461 7 To: Randy Pollock, P.E. Date: September 9, 1997 Fax #: (303) 716-8980 Pages: 7, including this cover sheet. From: Annalisa Williams//.,. Subject: | RUS Cooperative Agreement COMMENTS: Attached please find the “Cooperative Agreement Between the Rural Utilities Service and Intertie Participants Group for the Southern Intertie Project Environmental Impact Statement”, with cover letter dated September 3, 1997. The agreement was signed by Chugach on 9/5 and then hand carried to Homer for General Manager signature. The MOU of 6/20/97 (No.18) was included with this Cooperative Agreement as “Attachment B”. We have previously faxed the MOU to you, but please let me know if you would like this portion re-faxed. C: Dere_Qtey e WO. Seve Rey Transmission Report Date/Time Local 1D Local Name Company Logo This document was confirmed. (reduced sample and details below) Dogqument Size Eerrer=s FAX TRANSMISSION (CRUGACH ELECTRIC ASSOCIATION, INC. F.0. Box 196300 AncHOMaE, Arex G95 19-6300 GON 762-4001 Fac BON 702-4017 Te: Randy Pollock, P.E. Date: September 9, 1997 Faxt: (303) 716-8980 Pages: 7, incheling this cover shoct. From: Annalisa Wil COMMENTS: Participants Group for the Southern Intertie Project Environmental Impact Statemen”, with ‘cover letier dated September 3, 1997. The agreement was signed by Chugach on 9/5 and then band carried to Homer for General Manager signature. ‘The MOU of 6/20/97 (No.18) was included with this Cooperative Agreement as “Attachment 3”. We have previously finxed the MOU to you, but please let mc know if you would like this portion re-faxed. 9- 9-97; 8:47AM 907 762 4617 Trans Sp. Projects CHUGACH ELECTRIC ASSOC. INC Cs ee 20. 4. he Total Pages Scanned : 7 ‘Total Pages Confirmed : is No. |Doc}|]Remote Station Start Time Duration|Pages Mode |Comments|Results + 1};081 POWER ENG DENVER 9- 9-97; 8:44AM a? it* 77 7 Ec cP 14400 xx Notes ** Ec: Error Correct RE: Resend Polled by Remote MB: Receive to Mal !lbox BC: Broadcast Send MP: Multit-Poll Polling a Remote Pi: Power Interruption cP: Completed RM: Receive to Memory DR: Document Removed TM: Terminated by user LS: Local Scan LP: Local Print FO: Forced Output WT: Walting Transfer Southern Intertie Project —_——_———_22 Purpose and Need Summary of Costs and Benefits Alternatives Considered September 8, 1997 R ECEIVE D U0. 85% 08S Sec. 7 SEP 2 3 1997 transmissions Letter of Transmittal SPECIAL PROJECT September 11, 1997 To: Dora Gropp - CEA, Nural Islam - RUS, Mangi Environmental Services, Tim Tetherow - D&M, Nik Ranta - D&M, Mike Doyle - D&M, Mike Walbert - Power Subject: | 120376-05 Draft Purpose and Need, Cost and Benefit Summary, Alternatives Considered Document Enclosed are the following items: Document Date Copies Description 9/8/97 2 To Dora Gropp 4 To Nural Islam 1 To Jim Mangi 1 To Tim Tetherow 2 To Niklas Ranta 1 To Mike Doyle 2 To Mike Walbert These are transmitted: O For your O For action O For review @ Foryouruse O As requested information specified below and comment Sincerely, POWER Engineers, Inc. Lf Kee Randy Pollock, PE rp/RP Enclosure(s) Sent Via: Federal Express ce: File 120376-05 HLY 26-1319e If enclosures are not as noted, please notify us at once. DEN 26-13.19a rlp (9/8/97) Southern Intertie Project Purpose and Need Summary of Costs and Benefits Alternatives Considered Draft Prepared by Power Engineers, Inc. September 8, 1997 Purpose of this Document The purpose of this document is to present the following sections of the EVAL in draft form for review: Purpose and Need Cost and Benefits Summary e Alternatives Considered but Eliminated from Further Study e Alternatives to a Second Transmission Line e Alternative Transmission Systems e Alternatives Studied in Detail e No Action Alternative A discussion of alternative transmission routes is not included in this document. Please see the Scoping Report for a discussion regarding routing alternatives. DEN 26-1319a rip (9/8/97) Table of Contents Section Page Purpose of the Project 1 Project Background 1 Need for the Project. 4 Introduction 4 Planning and Operating Criteria. 4 Need Categories, 5 Increasing Reliability and Reducing Load Shedding. 7 Increasing the Power Transfer Capacity. 10 Utilizing the Most Economic Generation Mix. 11 Improving System Stability 13 Reducing Spinning Reserve Requirements 14 Reducing Line Losses and Maintenance Costs. 15 Background and Current Status 16 Development of Planning and Operating Criteria. 16 Avalanche Outages and Damage 17 How the System is Operated 19 Comprehensive Studies Conducted. 21 Cost and Benefit Summary 23 Alternatives Considered but Eliminated from Further Study. 26 Alternatives to a Second Transmission Line 28 Battery Energy Storage Systems 28 Demand Side Management and Energy Efficiency 29 New Generation, 30 Wind Generation 31 Fuel Cells 32 Increasing Spinning Reserves 33 Alternative Transmission Systems, 33 Upgrade of the Existing Quartz Creek Line. 33 Alternate Voltage Levels 34 Alternatives Studied in Detail 35 No Action Alternative 35 Page i DEN 26-1319b rp (9/8/97) Table of Contents Section Page Appendix A 38 List of References 39 NERC and ASCC Planning Criteria 41 List of Tables Table 1 - Alaska Systems Coordinating Council Criteria and 6 Southern Intertie Project Purpose and Need: System Improvements to meet ASCC Criteria Resulting from the Project Table 2 - Studies Addressing Key Project Issues, 21 Table 3 - Net Present Value of Benefits for the Southern Intertie Project 24 Table 4- Summary of Benefits and Costs 25 Table 5 - Alternatives Considered vs. Project Purpose and Need. 27 Table Al - Electrical Utility Planning Criteria. 41 List of Figures Figure 1 - Railbelt Service Area 2 Figure 2 - Anchorage to Kenai Power Transfer Example 19 Figure 3 - Example of Generation Coordination, 20 Figure 4 - Railbelt Generation and Loads. 30 Page ii DEN 26-1319b rip (9/8/97) Southern Intertie Project Purpose of the Project The Southern Intertie Transmission Line Project (Project) is proposed as a system improvement project to increase the overall Railbelt system reliability and transfer of energy capabilities between the Kenai Peninsula and Anchorage. The Project would consist of constructing a second electrical transmission line between the Kenai Peninsula and Anchorage. The Project as proposed would correct existing system deficiencies by providing a second line to increase the: e electrical transfer capability of the transmission system between the Kenai Peninsula and Anchorage to more economically use existing generation resources and reduce operating costs, reduce system requirements for spinning reserves, and improve electrical system stability; and the e reliability of the overall Railbelt system and the power supply to consumers on the Kenai Peninsula and in Anchorage by providing a second path for the power during an interruption of the existing Quartz Creek line, and reduce load shedding requirements in case of system disturbances; and e reduce transmission line losses and reduce maintenance costs on the Quartz Creek line. The proposed Project would also provide better access to and distribution of the hydroelectric power from Bradley Lake on the Kenai Peninsula to the Railbelt Utilities, and will result in more efficient transmission of electrical energy between the Kenai and Anchorage, by relieving the current restrictions due to limitations in the capacity of the existing Quartz Creek line. Project Background The Railbelt system is a power grid that electrically connects south-central Alaska from Homer to Fairbanks. The railbelt service area is illustrated in Figure 1. There are three distinct regions — interior area, centered around Fairbanks; Anchorage and Matanuska Valley area (Anchorage Bowl); and Kenai Peninsula. Electrical generation, transmission and distribution within the Alaska Railbelt are currently provided by seven utility companies which comprise the Intertie Participants Group (IPG), also referred to as the Railbelt Utilities. Members of the IPG include Fairbanks Municipal Utility System, Golden Valley Electric Association, Matanuska Electric Association, Chugach Electric Association, Anchorage Municipal Light and Power, Homer Electric Association, and Seward Electric Association. Page 1 DEN 26-1319 rip (9/8/97) RAILBELT ELECTRIC UTILITY SERVICE AREA 1B ANCHORAGE MUNICIPAL LIGHT & POWER MME cHuGACH ELECTRIC ASSOCIATION Il FAIRBANKS MUNICIPAL UTILITIES SYSTEM IM GOLDEN VALLEY ELECTRIC ASSOCIATION (MB HOMER ELECTRIC ASSOCIATION _ MATANUSKA ELECTRIC ASSOCIATION SUBSTATION A GENERATING PLANT a 115 KV 69 KV 230 KV 138 KV NOTE: LOCATION FOR ELECTRICAL IS APPROXIMATE 1g 1020 Railbelt Utilities System Southern Intertie Project Proposed Anchorage To Kenai Peninsula Transmission Project Figure 1 The Kenai Peninsula and the Anchorage Bowl are connected by one transmission line, known as the Quartz Creek 115 kilovolt (kV) Line. The Quartz Creek Line was originally constructed in 1960 to transmit power from Chugach Electric Associations’ Cooper Lake hydro-electric project to the Anchorage Bowl. As Alaska has grown, so has the need for transmission line interconnections between load areas to efficiently utilize generating plants across the system, and to reliably distribute that power to the load centers. Over time, use of the line has evolved beyond simply transmitting the Cooper Lake power to Anchorage. The Quartz Creek line currently provides the sole path for coordinating the operation of generation on the Kenai with Anchorage area generation. The line is also used to provide backup power in the case of outages in the Anchorage area or on the Kenai. Unfortunately, the Quartz Creek line is limited in electrical transfer capability and in its ability to provide reliable backup power during system outages. The line is routed across known and historically active avalanche areas. With the addition of the Bradley Lake Hydroelectric Project in 1991, the limitations of the Quartz Creek line have exacerbated these problems, resulting in operation of the Railbelt electrical system in a less than optimum manner, and at higher costs than if a second line were to be constructed between the Kenai Peninsula and Anchorage. In 1990, the North American Electric Reliability Council (NERC) completed a reliability assessment' that considered a number of factors relating to both the reliability of the system, as well as the adequacy of the generation and the interconnected transmission system. As a result of that study, NERC concluded that the proposed Southern Intertie Project would provide a second circuit between the Kenai peninsula and the Anchorage Bowl and is necessary to help improve the reliability of electric supply to the Kenai Peninsula, the Anchorage Bowl, and the Fairbanks area. The line would increase the electric transfer capability between the Kenai peninsula and the Anchorage area, improve system stability”, and help to reduce the number of load shedding incidents in the Anchorage and Fairbanks areas and the blackout or loss of electric supply to Kenai Peninsula consumers following certain system outages or contingencies. It would also help to reliably distribute the output of the Bradley Lake hydro generation facility to the appropriate utility purchasers of the hydro capacity. Without this line, reliability on the Kenai peninsula would likely be reduced following the completion of the Bradley Lake project’. ' Reliability Assessment of the Railbelt Interconnected Electric Utility Systems, North American Electric Reliability Council (NERC), 1990. 2 System stability is broadly defined as that property of a power system that enables it to remain in a state of operating equilibrium under normal operating conditions and to regain an acceptable state of equilibrium after being subjected to a disturbance. > NERC, 1990. Page 3 DEN 26-1319 rlp (9/8/97) Need for the Project Introduction The purpose and need for the Southern Intertie Project has been studied extensively and confirmed repeatedly through numerous studies since 1987*. In 1995, Power Engineers and Dames & Moore prepared updated cost estimates, electrical system studies, and conduct an alternatives analysis, environmental, and macro corridor studies’. Completed in 1996, these latest studies took a fresh look at the electrical, cost and environmental siting aspects of the project. In 1997, the value of the Project benefits and costs were reviewed and updated by Decision Focus, Inc.° and Power Engineers, Inc.’ Planning and Operating Criteria In 1991, as a result of discussions with NERC, ASCC adopted coordinated interconnection planning and operating criteria. The 12 operating criteria adopted are based on NERC planning guides for bulk electric system planning and are adapted specifically to Alaska. The NERC and ASCC criteria are shown in Table Al, Appendix A. These criteria have been developed based on the “lessons learned” from the construction and operation of the interconnected bulk power systems of North America, and are the industry accepted practices for planning and measuring the performance of bulk power interconnected systems. The Project has been planned and is proposed in accordance with these criteria. The Project would correct deficiencies in the existing interconnected system and is consistent with the ASCC criteria on system balance, contingencies, the provision of emergency support, support from adjacent systems, reactive power resources, real and reactive power margins, reliability during maintenance, and switching flexibility. * An extensive list of studies is presented later in the document. > Southern Intertie Project, Route Selection Study. Phase 1, Power Engineers, Inc. & Dames and Moore, 1996. In five separate reports. ® Review and Update of the Economic Feasibility of the Southern Intertie Project; Decision Focus Inc., August 1997. 7 Southern Intertie Project, Draft Cost Estimate Summary Report, Power Engineers, Inc., August 1997. Page 4 DEN 26-1319 rip (9/8/97) Need Categories Specifically, the proposed Project will provide a second path for power to flow between the two areas and is needed to: e Increase the reliability of the interconnected Railbelt electrical system from the Kenai Peninsula to Fairbanks, and reduce the requirement for load shedding during system disturbances.; e Increase the power transfer capacity between the Kenai Peninsula and the Anchorage Bowl; e Provide the capability to utilize the most economic generation mix available to reduce costs to consumers and to allow generation capacity in one area to support the load in the other area; e Improve Railbelt electrical system stability; e Reduce area requirements for spinning reserve generation, thereby reducing operating costs and increasing the life-span of generation plants; e Reduce transmission line losses for power transfers and reduce maintenance costs; Each of these points is discussed in detail in the sections that follow. Table 1 provides an overview of the Project Purpose and Need as compared with the ASCC Criteria for system planning and performance. Page 5 DEN 26-1319 rip (9/8/97) Table 1 Alaska Systems Coordinating Council Criteria and Southern Intertie Project Purpose and Need System Improvements to meet ASCC Criteria resulting from the Project Project Purpose and ASCC Criteria #1 ASCC Criteria #2 ASCC Criteria #3 ASCC Criteria #4 ASCC Criteria #5 ASCC Criteria #6 ASCC Criteria #8 ASCC Criteria #9 Need Categories V System Balance Contingencies Emergency Support Support from Reactive Power Real & Reactive Power Reliability during Switching Flexibility Adjacent Systems Resources Margins Maintenance Increase the reliability of the Interconnected System A 204 line and reduces excessive dependence on the Quartz Creek (QC) Line. A 20d |ine will mitigate or eliminate the current impact of single contingency outages. A 2nd jine provides added system support in the event of outages. A 294 Jine will allow planned & emergency power transfers, to minimize outages. A 204 Jine will provide access to overall system reactive support to minimize outages A 2nd line provides support to both areas improving dynamic response and system reliability. A 2N4 Jine allows for continued power transfers during maintenance activities, maintaining reliability A 20d jine provides flexibility to maintain service reliability with switching on the QC or a 2d |ine. Increase the Power transfer capacity from Kenai to Anchorage Increased power transfers lessen dependence on the QC Line Power transfers during outages of the QC ora 2nd jine would not be interrupted and Increased power transfer relieves transmission constraints during emergencies. Two lines provide increased ability to support adjoining areas. Increased power transfer capability provides increased access to reactive resources. Increased power transfer capacity improves system response to disturbances Increased power transfer capacity provides flexibility in maintenance scheduling Increasing the power transfer capacity makes the timing and duration of switching more maintenance costs Page 6 DEN 26-1319 rip (9/8/97) maintenance to be more effectively scheduled during and as follow-up to emergencies. to adjacent systems can be provided through more timely maintenance and lowered line losses. increased support for flexible. system wide outages. Utilize the most Generation can be N/A N/A A 2d Jine allows A 2nd fine provides With a second line, The Project allows N/A economic generation shared in a more generation in adjacent increased access to the increased flexibility in economic dispatch of mix to reduce costs balanced and systems to be utilized most economic reactive | assigning which power to continue economical manner economically for resources at existing generation provides during system system wide. planned and emergency | generation plants. spinning reserves can maintenance. conditions. reduce costs. Improve overall system | Adding a second line A 24 Jine will enable A 29d jine will increase | A 204 Jine will provide | A 294 ]ine will provide | A 29 line provides A 2nd Jine allows N/A stability during reduces dependence on | the system to withstand | the level of support that | addition system wide better system wide better access to real and | continued support to disturbances the QC line and QC & other outages can be provided during | support during outage access to available reactive resources adjacent areas during provides a loop feed to with higher power emergencies. conditions enhancing reactive resources to during system maintenance of the QC Kenai, enhancing transfer and maintain system stability enhance stability during | disturbances to maintain | Line and to maintain system stability system stability. disturbances. stability. stability during disturbances. Reduce spinning reserve || A 24 line allows A 2nd Jine provides A 29d jine allows Increased transmission | N/A A 2d jine allows A 24 Jine allows N/A requirements sharing of spinning enhanced system wide increased spinning capacity allows an adequate real & reactive | flexibility in designating reserve resources access to spinning reserves to be provided | increased level of power resources to be spinning reserves during between areas reducing | reserve resources during | from an adjacent area support from adjacent provided on a system maintenance activities, overall spinning reserve | disturbances, reducing during emergencies, areas for planned and wide basis instead of for | reducing overall costs. requirements. overall spinning reserve | reducing overall emergency conditions, each area, reducing requirements. spinning reserve lowering overall overall spinning reserve requirements. spinning reserve requirements. requirements. Reduce line losses and N/A N/A A 2nd jine allows With a 294 Jine, support | N/A N/A A 2nd jine maintains Maintenance costs can service reliability and lowers costs during maintenance of either line. be reduced with a 2nd line due to increased flexibility in the timing ~ and duration of switching. Increase the reliability of the interconnected Railbelt electrical system from the Kenai Peninsula to Fairbanks, and reduce the requirement for load shedding during system disturbances. Definitions — Reliability is the degree of performance of the elements of the bulk electric system that results in electricity being delivered to consumers within accepted standards and in the amount desired. Reliability may be measured by the frequency, duration, and magnitude of adverse effects on the electric supply. Electric system reliability can be addressed by considering two basic and functional aspects of the electric system: Adequacy — The ability of the electric system to supply the aggregate electrical demand and energy requirements of the consumers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements; and Security — The ability of the electric system to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements. Load shedding is the process of deliberately removing (either manually or automatically) preselected loads from a power system in response to an abnormal condition to maintain the integrity of the system and minimize overall outages®. Current System Deficiency — System reliability depends on system components remaining in-service. Typical system components which can fail and cause major outages are; generation plants (generators, turbines, fuel sources, control systems, etc.), transmission lines, power circuit breakers, and power transformers. Adding transmission lines to a system improves system reliability by providing multiple paths for the power to flow; thus, an outage of a single component does not completely disrupt the system. In the 1990 NERC reliability assessment study’ of the Railbelt interconnected system, NERC states that the transmission system in the Anchorage Bowl area is such that it can be considered a network and, as such, should be able to withstand loss of any given circuit. The Kenai Peninsula transmission is essentially a branched arrangement, with underlying subtransmission on the cross-peninsula sections, such that loss of any branch should be sustainable with only that loss of the area served by that branch. However, the Quartz Creek line between the Kenai Peninsula and Anchorage is, and has historically been subject to outages. These outages place the Kenai Peninsula in jeopardy from the effects of isolation from the Anchorage Bowl. The addition of the Bradley Lake hydroelectric plant at the southem extremity of the peninsula near Homer tends to exacerbate this situation, with the further problem that loss of the existing Quartz Creek interconnection interrupts Bradley Lake capacity entitlements of the Anchorage Bowl and Fairbanks area utilities. § Glossary of Terms, Prepared by the Glossary of Terms Task Force North American Electric Reliability Council, August 1996. ° NERC, 1990. Page 7 DEN 26-1319 rip (9/8/97) In addition, the existing Quartz Creek line has a poor reliability history and has a transmission transfer capacity limit of 70 megawatts (MW). The chances of significantly improved performance is not great due to its physical/geographical location and system conditions that exist'®. NERC also concluded that the existing Quartz Creek line poses a significantly higher than traditional reliability risk for system-wide blackouts due to single contingency outages. In terms of traditional reliability criteria, the proposed Southern Intertie Project is needed to help improve the reliability of the electric supply to the Kenai Peninsula, the Anchorage Bowl, and the Fairbanks area''. Power Technologies, Inc., in their 1989 study on Kenai power export limits concludes that at 70 MW export, the Kenai-Anchorage transmission line operation goes beyond the Railbelt practice of lean system design. Nowhere in the Railbelt is so much resource so critically dependent on stability aids and a single line....... A new line from the Kenai area to Anchorage would provide Kenai-Anchorage interconnection reliability at least on a par with most of the remainder of the Railbelt system’. Because of the power transfer limitations of the existing Quartz Creek line, current practice is to maintain a minimum generation of 25 MW on the Kenai Peninsula to support the Kenai system in the event of a system disturbance, to prevent a blackout of the Kenai Peninsula. This minimum generation is required to maintain power to key loads on the Kenai in the event of a single contingency outage, such as a Quartz Creek line outage”. Avalanche studies of the existing Quartz Creek line produced recommendations that resulted in the construction of upgrades to the existing structures along the line to mitigate the potential damage to the lines from avalanches. However, even with the improvements to the line to mitigate damage from avalanches, the line remains susceptible to extended outages from this cause". How the Project Corrects the Deficiency — The construction of the Project between Anchorage and the Kenai Peninsula would not only provide a parallel path to the existing Quartz Creek interconnection, but would also make the Kenai system more of a loop arrangement. Construction of the Project provides the needed second path to improve the overall system reliability. NERC offers the following observations as well’: '° Thid. " Tbid. " Railbelt Intertie Feasibility Study, Final Report, Alaska Energy Authority, March 1991. Chugach Electric Manager of Power Control, January 1997. '* Comprehensive Avalanche Atlas: Alaska Mountain Safety Center, Inc., October 1991. '’ NERC, 1990. Page 8 DEN 26-1319 rp (9/8/97) e A second transmission line interconnection from the Kenai Peninsula to the Anchorage Bowl area would improve reliability by preventing the shedding of consumer load if the existing interconnection line trips (with the possible exception of those times when the Kenai Peninsula generation is operated in anticipation of loss of the existing tie’®.) e When Bradley Lake comes into service, reliability will suffer without a second interconnection line. That is, the second Kenai Peninsula to Anchorage Bow! line is necessary to support Bradley Lake and to help reliably distribute the Bradley Lake capacity to the purchasing systems, to minimize blackouts in the Kenai Peninsula, and to minimize underfrequency load shedding in the Fairbanks area and the Anchorage Bowl. With a second transmission line in service, a minimum generation of 25 MW on the Kenai would not be needed to maintain reliability and service to key loads in the case of a single contingency outage, and this minimum generation requirement could instead be provided from the most economical generation resource’’. Benefits from the Project — Reliability is important because the value of electric power exceeds the cost of producing the power. The cost to a utility of an outage may be small, while the cost of that same outage to an industrial or commercial consumer may be very large. For example, the unserved energy during an outage represents lost revenue for the utility. For industrial and commercial consumers, outages cause loss of product or sales that would otherwise occur if not for the power outage. Reliability is determined by the number, magnitude, and duration of consumer outages. Reliability benefits occur if consumer outages are reduced as a direct consequence of constructing a new transmission line. The proposed Project is expected to reduce both the frequency and duration of generation and transmission related outages, i.e., outages related to unexpected loss of generating units or the existing Quartz Creek line’’. The assessment of the value of improved system reliability requires an estimate of the outages that the Project will avoid, and the cost to consumers of the outages that are '© The existing 115kV Anchorage-Kenai interconnection is at times operated at zero electrical flow, in anticipation of possible storm outages. This is an inefficient way of operating the system because during the period the line is not transferring electrical power between the Kenai and Anchorage Bowl, higher cost alternate generation sources must be used. The Project would allow power transfers to continue even during poor weather conditions, since the Project provides a second line to continue the power transfers during an outage of the existing line. "’ Chugach Electric Manager of Power Control, January 1997. 'S Review and Update of Economic Feasibility of Souther Intertie Project, Decision Focus, Inc., August 1997. Page 9 DEN 26-1319 rlp (9/8/97) avoided. The value of improved system reliability from the Project has been studied and evaluated in detail by Decision Focus, Inc." Increase the power transfer capacity between the Kenai Peninsula and the Anchorage Bowl. Definitions — Power transfer capacity (or capability) is the measure of the ability of interconnected electric systems to move or transfer power in a reliable manner from one area to another over all transmission lines (or paths) between those areas under specified system conditions. The units of transfer capability are in terms of electric power, generally expressed in megawatts (MW). Economy energy is energy produced and supplied from a more economical source in one system and substituted for that being produced or capable of being produced by a less economical source in another system”. Current System Deficiency — The secure power transfer’ between the Kenai Peninsula and the Anchorage area is currently limited to 70 MW over the existing Quartz Creek line”. This limitation prevents the Railbelt utilities from taking full advantage of the available generation on the Kenai Peninsula to maximize potential benefits from economy energy transfers. . How the Project Corrects the Deficiency — Economy energy transfers result when high cost energy in one area is displaced by lower cost energy from another area over an interconnecting transmission line. The capability for increased secure power transfers between the Kenai and Anchorage areas would allow the Railbelt generation to be provided at a lower cost to consumers. Construction of the Project would cause the secure power transfer between the Kenai Peninsula and Anchorage to increase from 70 MW to 125 MW. Benefits from the Project — Construction of the Project would allow lower cost energy in one area to displace energy that would otherwise be produced at a higher cost in the other area. The economy energy benefits accruing from the Project are substantial, and are primarily due to disparities in marginal power production costs in the two areas, and because the optimal power flow across the existing Quartz Creek line exceeds its present capacity. The benefits resulting from construction of the Project in terms of economy '9 Benefit/Cost Analysis, Decision Focus, Inc., June 1989; Economic Feasibility of the Proposed 138kV Lines in the Railbelt, Decision Focus Inc., December 1989; Decision Focus, Inc., August 1997. 2? NERC Glossary, 1996. 2! Secure transfer is defined as the maximum transfer permissible for the system to remain stable and operational with a sudden loss of the transferred power. = Southern Intertie Route Selection Study . Phase 1. Final Studies Section Report, Power Engineers, Inc., June 14, 1996. Page 10 DEN 26-1319 rip (9/8/97) energy are primarily due to increased hydro-thermal coordination” between the hydro generation on the Kenai Peninsula and the thermal generation in the Anchorage Bowl. The value of these benefits have been studied and evaluated in detail in the Decision Focus studies”. Provide the capability to utilize the most economic generation mix available to reduce costs to consumers and to allow generation capacity in one area to support the load in the other area Definitions — Capacity is the rated continuous load-carrying ability, expressed in megawatts (MW) or megavolt-amperes (MVA) of generation, transmission, or other electrical equipment”. Generation capacity sharing is the sharing of generation capacity between load areas, such that a deficiency or inefficiency in one area can be overcome through use of another areas generation resources. The degree of capacity sharing that can occur between areas is based to a large degree on the capacity of available transmission interconnections between areas. The process of allocating available generation resources is also sometimes referred to as Economic Dispatch — The allocation of demand to individual generating units on line to effect the most economical production of electricity”. Current System Deficiency — Standard utility practice is to determine generation requirements and operate individual generation plants in a mix so as to meet the instantaneous demand for power and to produce the least cost power. The present limitation on power transfers between the Anchorage Bowl and the Kenai Peninsula, due to the limitations of the existing Quartz Creek Line, results in more a expensive mix of power being generated from the existing power plants to supply the load than if the Project were in service. NERC concluded in their reliability assessment study that the existing single line transmission interconnections between the Kenai Peninsula and the Anchorage Bowl (the Quartz Creek Line) and between the Anchorage Bowl and the Fairbanks area constrain the sharing of generation between and among load centers and pose a significantly higher than traditional reliability risk for system-wide blackouts due to single contingency outages” **. 2 Hydro-thermal coordination is the operation of hydro and thermal generation resources in a way that results in overall lower system operating costs. Hydro-thermal coordination is explained in more detail later in the document. *4 Decision Focus, June 1989, December 1989, August 1997. *5 NERC Glossary 1996. * Ibid. 77 A single contingency outage occurs with the loss of any one system component. A double contingency Page 11 DEN 26-1319 rlp (9/8/97) Because of the power transfer limitations of the existing Quartz Creek line, current practice is to maintain a minimum generation of 25 MW on the Kenai Peninsula to support the Kenai system in the event of a system disturbance, to prevent a blackout of the Kenai Peninsula. This minimum generation is required to maintain power to key loads on the Kenai in the event of a single contingency outage, such as a Quartz Creek line outage”. How the Project Corrects the Deficiency — The proposed Project would allow the Kenai Peninsula and Anchorage and north to more efficiently share the generation capacity in each area, and throughout the Railbelt. Increased transmission capacity allows one area to rely more heavily on generation capacity in another area, for capacity as well as for energy. For the Railbelt, the Project would allow Anchorage and Fairbanks to rely on a greater portion of the Kenai Peninsula generation capacity surplus for meeting capacity requirements, thus deferring the need to build new generation capacity. With a second transmission line in service, there would not be a minimum generation requirement on the Kenai to maintain system stability in the case of a single contingency outage, and the required generation resources could instead be provided from the most economical source*. Benefits from the Project — The Project would produce two types of benefits from capacity sharing, resulting in reduced costs for the generation of power: e As load grows in a region, enough generation capacity must be available to meet the peak load in that region plus a required generation reserve margin, in case of system outages. Increased transmission capacity increases access to generation capacity in regions with surplus generation capacity, thus making it possible to defer adding generation capacity to the system. e The larger and more interconnected a system, the lower the reserve margin that is required to provide the same level of reliability. Increasing transmission capacity increases the level of interconnectedness for the Railbelt, allowing utilities to permanently avoid building some of the generation capacity that would have been constructed to maintain the desired generation reserve margin. Construction of the Project would allow the Railbelt utilities to take advantage of the increased “interconnectedness” of the system by allowing them to more readily share outage occurs with the loss of two system components during the same event. 78 NERC, 1990. ?° Chugach Electric Manager of Power Control, January 1997. °° Ibid. Page 12 DEN 26-1319 rlp (9/8/97) generation capacity between areas. and so reduce the overall costs of producing and delivering power throughout the system. Improve Railbelt system stability Definitions — System Stability is the ability of an electric system to maintain a state of equilibrium during normal and abnormal system conditions or disturbances, and is composed of two aspects: Small-Signal Stability — The ability of the electric system to withstand small changes or disturbances without the loss of synchronism among the synchronous machines in the system; and Transient Stability — The ability of an electric system to maintain synchronism between its parts when subjected to a disturbance of specified severity and to regain a state of equilibrium following that disturbance*!. Operation of a utility power system requires matching generation to consumer loads and providing a system of interconnected lines to transmit the power from the generator to the load on a continuous basis. When a transmission line is carrying a power flow and that power flow is suddenly interrupted, the remaining lines and generators must quickly compensate for the lost component of the system. If the system can compensate for the interrupted power flow, without significant outage of consumer load or damage to equipment, then the system is said to remain stable. If the loss of a system component results in outages of other lines, generators or consumer loads then the system is referred to as being unstable. One of the primary reasons for creating an interconnected power grid is to provide system flexibility to allow for the outage of one of the many system components. A system comprised of many generation sources with many transmission line paths to transmit the energy to the loads is much more likely to remain stable with the loss of a single component. Current System Deficiency —The existing Quartz Creek Line is limited to a 70 MW power transfer for secure system operation. Under certain system configurations and power flows, when the existing Quartz Creek Line experiences an interruption, it is necessary to implement automatic load shedding schemes to immediately reduce the overall system load, so that the loads on the remaining generators and transmission lines are reduced to a level where the system will remain stable, and a system wide blackout is prevented. The operational policy of reducing the transfers over the Quartz Creek Line to near zero during adverse weather conditions, which may cause an outage of the line, is a preventative measure to assure that a sudden loss of the line does not result in a complete system collapse due to system instability. However, reducing the flow over the line to zero requires additional generation to be operated in the Anchorage Bowl and on the Kenai Peninsula, resulting in inefficient operations and overall higher system operating costs. >! NERC Glossary, 1996. Page 13 DEN 26-1319 rip (9/8/97) How the Project Corrects the Deficiency — The Project would enhance the stability performance of the Railbelt system by providing a second path for power to flow in the event of an interruption of the existing Quartz Creek Line, and would reduce the need for the implementation of load shedding schemes during system disturbances by increasing the secure power transfer between Anchorage and the Kenai from 70 MW to 125 MW. The Project would also be available to support the system in Anchorage and north in the event of system disturbances in Anchorage and north. Benefits from the Project — The benefits of this enhanced stability would be evidenced in the increased reliability of the overall system, and in the reduction of load shedding and system wide outages. The Project would also eliminate the need to reduce the power transfer over the Quartz Creek line to zero during adverse weather conditions. Reduce area requirements for spinning reserve generation, thereby reducing operating costs and increasing the life-span of generation plants Definitions — Spinning Reserve is a portion of the Operating Reserves maintained by utilities. Spinning Reserve is unloaded generation, which is synchronized and ready to serve additional demand. It consists of Regulating Reserve — An amount of spinning reserve responsive to Automatic Generation Control, which is sufficient to provide normal regulating margin; and Contingency Reserve — An additional amount of operating reserve sufficient to reduce Area Control Error to zero in ten minutes following loss of generating capacity, which would result from the most severe single contingency. At least 50% of this operating reserve is typically Spinning Reserve, which will automatically respond to frequency deviation®. Current System Deficiency — Spinning reserves respond to changes in consumer demand and failures in the generation and transmission system. Spinning reserves improve reliability, but they are often expensive. In order to maintain adequate spinning reserve margins, generation units must be operated without serving any load. The hydroelectric capacity on the Kenai Peninsula could provide a less expensive source for some spinning reserves that otherwise would be provided by thermal generating units in the Anchorage area. Current operating practices and agreements among the Railbelt utilities result in the provision of approximately 65 MW of operating reserve accessible in the Anchorage area”. Limited amounts of this spinning reserve can be provided from outside the Anchorage area. Transmission capacity between Kenai and Anchorage is a constraint on the transfer of spinning reserves between areas with only the single Quartz Creek line in service. 2 NERC Glossary, 1996. * Decision Focus, December 1989. Page 14 DEN 26-1319 rip (9/8/97) How the Project Corrects the Deficiency — Construction of the Project to provide a second transmission line interconnection would allow increased access to spinning reserves, so that spinning reserves for the system could be provided from the most appropriate generation source, whether that source is in Anchorage or on the Kenai Peninsula. Decision Focus has estimated that approximately 30 MW of spinning reserve can be transferred from Kenai to Anchorage over the existing line. This transfer of spinning reserves results from the practice of distributing these reserves such that they are not all lost with a single event. With a second transmission line in service, it would be feasible to transfer more than 30 MW of spinning reserve from Kenai to Anchorage. The existence of two lines would provide a second path between Kenai and Anchorage in the event of a line outage so that spinning reserves are not all lost. With a second line in service, it is estimated that up to 50 MW of spinning reserves could be transferred from Kenai to Anchorage™*. Benefits from the Project — The benefits of increased spinning reserve sharing in the interconnected Railbelt system resulting from construction of the Project would be realized through lower generation costs. In addition, because existing generation resources can be more readily shared with a second line in service, system generation can be operated fewer hours overall, resulting in power plant life extension benefits from the Project. Reduce transmission line losses for power transfers and reduce maintenance costs Definitions — Electric system losses are total electric energy losses in the electric system. The losses consist of transmission, transformation, and distribution losses between supply sources and delivery points. Electric energy is lost primarily due to heating of transmission and distribution elements**. Transmission losses play an important role in the cost of power transfer between two areas, since energy lost in transmission can be considered to have the same value as delivered power. Maintenance costs are those system operating costs attributable to testing, replacement or refurbishment of system components in the normal course of business. Current System Deficiency — Electrical system studies by Power Engineers” indicate that line losses for the existing Quartz Creek intertie are calculated to be 7 MW for a 70 MW power transfer. Losses increase to 25 MW as the power transfer over the existing line increases to 125 MW. Line losses are completely dependent on the current flow and * Ibid. >5 NERC Glossary, 1996. *© Southern Intertie Route Selection Study . Phase 1. Final Studies Section Report, Power Engineers, Inc., June 14, 1996. Page 15 DEN 26-1319 rip (9/8/97) the resistance of the line conductors and increase by the square of the current (i.e. if the current doubles, the losses increase by a factor of four). Maintenance costs on the existing Quartz Creek Line are higher than they would be if the Project were constructed. Currently, because the existing line is the only path between the Kenai Peninsula and Anchorage, it is difficult to schedule outages for maintenance. Removing the line from service to conduct maintenance activities requires additional generation to be operated both on the Kenai Peninsula and in the Anchorage Bowl to support the load and to provide the necessary spinning reserves. This additional generation on line increases overall system operating costs. In addition, the scheduling of construction crews to conduct the maintenance activities is restricted in the timing and duration available to conduct the maintenance, also resulting in increased costs. How the Project Corrects the Deficiency — Construction of the Project would reduce transmission system losses. The losses for a 125 MW transfer between the Kenai and Anchorage with two circuits would be reduced from 25 MW (with only the existing line) to 5 MW, with both the Project and the existing Quartz Creek Line in service. With two independent transmission lines between the Kenai Peninsula and Anchorage, the addition of the Project would provide greater load transfer capability while reducing transmission line losses. With the Project in service as a second path between Anchorage and the Kenai Peninsula, maintenance activities can be scheduled and conducted to result in lower overall costs. Benefits from the Project — Benefits of construction of the Project result from cost savings due to reduced line losses and more efficient scheduling of maintenance activities. Background and Current Status Development of Planning and Operating Criteria As the high voltage electrical network in the United States grew from isolated systems into the interconnected bulk power system that exists today, the need to establish planning and operating practices that would result in the economical and reliable operation of the bulk power interconnected systems grew as well. The ability to operate the interconnected systems reliably and economically continues to be an integral part of the social and economic fabric of the United States. As with most businesses, the establishment of realistic planning criteria for the electrical system came about as a result of lessons learned in operating the systems. The North American Electric Reliability Council (NERC) was formed in 1968 in the aftermath of the November 9, 1965 Blackout that affected the Northeastern United States and Ontario, Canada. NERC's mission is to promote the reliability of the electricity Page 16 DEN 26-1319 rip (9/8/97) supply for North America. In short, NERC helps electric utilities and other electricity suppliers work together to keep the lights on. It does this by reviewing the past for lessons learned, monitoring the present for compliance with policies, standards, principles, and guides, and assessing the future reliability of the bulk electric systems. The Alaska interconnected system has grown in much the same way as interconnected systems in the lower 48. First as isolated systems, and then as an interconnected system to take advantage of capabilities in adjoining systems to provide system support. The Railbelt interconnected system is a power grid that was set up by the State of Alaska, and cooperating utilities, to electrically connect south-central and interior Alaska, from Homer to Fairbanks. This area, called the Railbelt, is home to the majority of Alaska’s population. Development of the Railbelt high voltage electrical network resulted from long-term planning studies conducted by the State, through the Alaska Energy Authority (AEA). The Railbelt power grid allows the participating utilities to buy and sell power with each other, taking advantage of lower costs in other areas, and to provide backup power to each other. In this manner, lower cost generation resources in adjacent areas can be more fully utilized and the cost of procuring electricity minimized. The Intertie Participants Group (IPG) was formed by Railbelt utilities to improve electric reliability and coordination within the Railbelt by working together to improve the interconnected system through intertie improvements and cooperative energy projects. The Southern Intertie is one of these cooperative projects. The Alaska Systems Coordinating Council (ASCC) is an association of Alaska’s electric power utilities with the responsibility for reviewing the Alaska interconnected system on a continuing basis to promote reliable system operation through coordination between utilities in the planning and operation of the interconnected system. ASCC is a NERC affiliate member and as a result gains the benefit of the experience and insights from the NERC organization. With NERC's support, ASCC works toward Alaska's responsible electric system development and operation. In 1991, as a result of discussions with NERC, ASCC adopted coordinated interconnection planning and operating criteria for the participating utilities. The 12 operating criteria adopted are based on NERC planning guides for bulk electric system planning and are adapted specifically to Alaska (recognizing the differences between the Alaska interconnected system and the interconnected systems in the lower 48 states). These criteria provide guidance to utilities in evaluating electric system performance and provide requirements and recommendations to be considered in planning and designing additions and modifications to the system. Application of these criteria is one of the ways that the lessons learned over time throughout the electric utility industry are applied to the responsible development of Alaska’s power grid. Avalanche Outages and Damage At the present time, the Kenai Peninsula and the Anchorage Bowl are connected by a single 115kV transmission line between the Quartz Creek area and the University Page 17 DEN 26-1319 rlp (9/8/97) Substation in Anchorage. The Quartz Creek line is routed around the east end of Turnagain Arm through areas where avalanches have consistently damaged the line and interrupted power transfers between the Kenai and Anchorage. The existing Quartz Creek 115kV transmission line is exposed to potential avalanche hazard in several locations between the University and Quartz Creek substations. Studies by the Alaska Mountain Safety Center” show that 88 structures and 117 spans along the line are exposed to some degree of potential hazard from destructive avalanches. Extended outages to the existing line have occurred because of avalanches in the Bird Flats area, between Girdwood, and Portage as well as in the Summit Lake area. Historic records indicate that during an 18- year period from 1971 to 1988 the line was hit and severely damaged by avalanches on 11 occasions at six different areas, for an average of once every 1.6 years or more frequently. The longest period of time without interruption was eight years while the least was less than one year. From 1988 to 1989 Chugach Electric Association implemented mitigation to reduce the overall risk of exposure to avalanche damage, including tower relocations and diversion structures; however, the remaining hazard is still rated as moderate. A moderate risk means that one to four large, potentially destructive avalanches may reach an individual structure or span during a 50-year period. Even with the improvements to the line to mitigate damage from avalanches, the line remains susceptible to extended outages from this cause. Current system operating practice is to reduce flows on the existing Kenai-Anchorage interconnect to near zero during poor weather conditions to avoid major service disruptions in the event the line is damaged. This is an inefficient, but necessary practice that results in overall higher costs to operate the system. >” Alaska Mountain Safety Center, 1991. Page 18 DEN 26-1319 rlp (9/8/97) How the system is operated The existing intertie is limited to transferring 70 megawatts (MW) of power for a secure transfer. To allow full use of the Kenai Peninsula generation, the intertie secure transfer capacity needs to be increased to 125 MW. The Project would provide the increased transmission capacity to make these higher transfers possible in a secure manner. F Currently the existing system Anchorage to Kenai between Anchorage and the Power Transfer Example — Kenai is operated so as to maximize the transfers of 2 economy energy and to Ss ge S 2 52 coordinate the hydro and thermal 5 g 7 generation resources on the re 2 g Kenai Peninsula and in = . . g a= Anchorage, within the 6 8a limitations of the existing Quartz ag g = Creek 115kV Line. Power flows 12M 6 AM 12PM 6PM 12AM to and from the Kenai Peninsula Time of Day Figure 2 are monitored at the Daves Creek Substation, which is located just north of the intersection of the Seward and Sterling highways. As depicted in Figure 2, power flows in both directions, to and from the Kenai Peninsula and Anchorage. The average variation of the import/export of power to the Kenai is +/- 40 MW, on a daily basis. During the day, when loads in the Anchorage area are high, hydro power is dispatched from the Kenai to Anchorage to “shape” the overall generation so that the Anchorage Bowl thermal generation units operate near full load for maximum efficiency, which results in overall lower generation costs. At night when electrical loads are lower, the hydro generation is reduced to conserve the water in the reservoirs, while continuing to run the thermal generation units at maximum efficiency. For hydro generation, water is essentially the “fuel” that allows generation of electricity from a hydro project such as Bradley Lake. Page 19 DEN 26-1319 rip (9/8/97) The hydro generation resource is coordinated with the thermal resource (hydro-thermal coordination) so that thermal resources such as the gas fired turbines at the Beluga Power Exam ple of Generation Station can be operated at Coordination maximum efficiency, while using the hydro resource to “shape” the instantaneous system load requirements. The hydro-thermal generation coordination process is illustrated in Figure 3**. With the Project in service as a second transmission line interconnection between the Anchorage Bowl and the Kenai Peninsula, increased economy energy transfers and hydro-thermal coordination would be possible, currently limited by the existing single Quartz Creek Line, and full advantage can be taken of the Bradley Lake hydro resource. 12 AM 6 AM 12 PM 6PM 12 AM Time of Day Figure 3 8 In the generation coordination graphic, CT means combustion turbine, and CC means combined cycle combustion turbine. Both are thermal generation resources. Page 20 DEN 26-1319 rip (9/8/97) Comprehensive Studies have been Conducted A series of engineering, economic and environmental studies have been conducted for the proposed Project to confirm the need for the Project and to establish key cost and technical parameters. Key Project issues have been addressed repeatedly since 1987 as shown in Table 2, and the need for the Project has also been repeatedly confirmed. Table 2 Southern Intertie Project Studies Addressing Key Project Issues* Year Study Completed > | 1987 | 1989 | 1990 | 1991 Project Issue ¥ System Reliability 2 1 Increased Transfer Capacity 2 1,5,6 Economic Utilization of Available 1,5,6 4,8 GI] Gat Go Generation System Stability 1 Spinning Reserves 1 Project Costs Project Benefits Environmental Siting Analysis Transmission Line Losses Maintenance Costs * See List of References for specific studies referenced by number in this table. Ga] Lo Initial Southern Intertie-related studies included a cost estimate and corridor feasibility study by Power Engineers, Inc. in 1987, and the Alaska Power Authority (APA) Railbelt Intertie Reconnaissance Study*’, completed in 1989. The APA 1989 study was very comprehensive and included eleven volumes (please see References for a complete list). Two of the key volumes included in the 1989 Reconnaissance Study were a Benefit/Cost Analysis, prepared by Decision Focus, Inc. (DFI) in June 1989*', and updated in December 1989*, and a Reliability Assessment of the Railbelt Interconnected Electric Utility Systems in 1990 conducted by the North American Electric Reliability Council (NERC)®. 3° Anchorage-Kenai_ Transmission Intertie Feasibility Study, Power Engineers, Inc., May 1987. Two volumes. * Railbelt Intertie Reconnaissance Study, Alaska Power Authority, 1989. Eleven Volumes & Addendum. *' Decision Focus, Inc., June 1989. , *® Decision Focus Inc., December 1989. * NERC, 1990. Page 21 DEN 26-1319 rip (9/8/97) The reconnaissance studies were summarized in the Alaska Energy Authority (AEA) Railbelt Intertie Feasibility Study, Final Report, March 19914 (The Alaska Power Authority became part the Alaska Energy Authority). The Final Report included updated cost estimates, prepared by Dryden and LaRue in 1991”. In 1997, the value of the Project benefits and costs were reviewed and updated by Decision Focus, Inc.*® and Power Engineers, Inc.*”. * Alaska Energy Authority, March 1991. *5 Cost Estimate, Kenai/Anchorage and Healy/Fairbanks 138 kV Transmission Line Interties, Dryden and LaRue, March 1991. “ Decision Focus Inc., August 1997. 4” Southern Intertie Project, Draft Cost Estimate Summary Report, Power Engineers, Inc., August 1997. Page 22 DEN 26-1319 rlp (9/8/97) Cost and Benefit Summary The benefits from construction and operation of the Project have been studied and evaluated in detail by Decision Focus, Inc.** (DFI) and by the Alaska Energy Authority” (AEA). A discussion of the benefits from the Project accruing from each need category is included in the Purpose and Need section of this document, along with a description of the deficiencies that the Project would correct. Please refer back to that section for additional detail regarding the benefits of the Project. The DFI December 1989 Report focused on the benefits of the Project, and DFI evaluated benefits for the Project in several different categories including: Capacity Sharing Economy Energy Transfer Reliability Transmission Line Losses Operating Reserve Sharing (Spinning Reserves) Reduced Maintenance Costs The total value of the benefits calculated in the December 1989 study is $122.6 million. In August 1997 the benefit estimates were reviewed and updated by DFI. The updated benefit calculations concentrated on the first three categories, which accounted for about 90% of the benefits. The update focused on the key data values underlying the estimates, determined how the data values have changed, and calculated the impacts on the benefits. In addition, all of the values were converted to 1997 dollars for comparison with current cost estimates for the Project. Table 3 summarizes the results of the 1989 study and of the 1997 update of the benefits. * Decision Focus, Inc., December 1989 and August 1997. * Alaska Energy Authority, March 1991. Page 23 DEN 26-1319 rip (9/8/97) Table 3 Net Present Value of Benefits for the Southern Intertie Project® (millions of dollars) 4.5% Discount Rate”! 6% Discount Rate 1989 Study 1990S 1997$ 24.4 43.4 41.0 The AEA also evaluated the benefits of the Project based on DFI’s quantitative analysis, and from the point of view of accepted industry practice and compliance with NERC and ASCC criteria for planning and operation of the Alaska interconnected system. While the AEA noted that there can be a wide range of benefit values associated with the Project, based on the qualitative and quantitative analyses conducted for the Project, the life cycle benefits of the Project will exceed the costs, and the Project is needed and should be constructed”. The construction costs for the Project were estimated by Power Engineers, Inc. in 1996* and were updated in 1997* to reflect the potential facility requirements identified as part of the current siting studies being conducted for the EIS. The updated cost study also determined the present value of the operation and maintenance and submarine cable replacement costs over the 40 year project life. Two types of submarine cable are presently under consideration for crossing the Turnagain Arm, and costs and benefit/cost ratios are included for both cable types. Since a preferred route has not yet been °° Decision Focus Inc., August 1997. Values are for the year in which the Project was/is expected to come into service, 1994 for the 1989 Study and 2004 for the 1997 Update. 5! For the 1989 study, a discount rate of 4.5% was specified by the Alaska Energy Authority based on the long-term real cost of money (Alaska Energy Authority, March 1991). For the current update, benefits were also calculated using a 6% discount rate. These two values represent a range of values for the discount rate, corresponding to a range of benefits. * Alaska Energy Authority, March 1991. 5 Southern Intertie Route Selection Study . Phase_1. Final Economic Section Report, Power Engineers, Inc., June 14, 1996. 5* Southern Intertie Project, Draft Cost Estimate Summary Report, Power Engineers, Inc., August 1997. Page 24 DEN 26-1319 rip (9/8/97) identified, Table 4 includes cost ranges for the Tesoro and Enstar routes, and a range of benefit/cost ratios are calculated based on the benefit values discussed above. Table 4 Summary of Benefits and Costs (millions of 1997 dollars) Tesoro Route Enstar Route 2-3 core cables} 4-1 core cables} 2-3 core cables} 4-1 core cables Discount Rate > 4.5% | 6.0% | 4.5% | 6.0% || 4.5% | 6.0% | 4.5% | 6.0% Constructed Cost” 98.6 110.7 O&M Costs 4.3 3.5 4.3 Cable Replacement | 14.9 | 11.3 | 18.8 a te 117.8 133.8 Value of Benefits | 132.1 | 132.1 Benefit/Cost Ratio Range 55 Constructed cost is for the Base Route as designated in the Power Engineers, August 1997 report. Other local alternatives would result in differing constructed costs. *6 The adjusted benefit/cost ratio is calculated by subtracting the $46.8 million state grant funding for the Project from the constructed cost and dividing into the benefit value. Page 25 DEN 26-1319 rlp (9/8/97) Alternatives Considered but Eliminated from Further Study In addition to the no action alternative and the proposed action, a number of other alternatives were considered to meet the purpose and need for the Project. These other alternatives included: Alternatives to a Second Transmission Line Battery Energy Storage Systems Demand Side Management Energy Conservation New Generation Wind Generation Fuel Cells Increasing Spinning Reserves Alternative Transmission Systems e Upgrade of the Existing Quartz Creek Line e Alternate Voltage Levels Each of these alternatives was considered by assessing the ability of an alternative to meet the stated purpose and need for the Project. Table 5 summarizes and compares the no action and proposed action with the alternatives considered but eliminated. Following the table, each alternative is addressed in more detail. Page 26 DEN 26-1319 rlp (9/8/97) Table 5 Southern Intertie Project Alternatives Considered vs. Project Purpose and Need Do the Alternatives Considered Meet the Project Purpose and Need? Second Project Alternatives Alternatives Considered but Eliminated Transmission Line Alternatives to a Second Transmission Line Alternative Transmission Proposed Action: Enstar or Tesoro Upgrade the Quartz Creek Routes INew Generation Line Project Purpose and Need Category Increase the reliability of the Interconnected | PARTIAL NO 7 PARTIAL System Increase the power transfer capacity between the PARTIAL PARTIAT r ves Kenai and Anchorage Utilize the most economic generation mix to PARTIAL PARTIAL ‘ PARTIAL reduce costs Improve overall system stability during PARTIAL NO s PARTIAL disturbances Reduce spinning reserve requirements PARTIAL NO PARTIAL Reduce transmission line losses NO PARTIAL YES NO | Reduce maintenance costs Page 27 DEN 26-1319¢ rlp (9/8/97) Alternatives to a Second Transmission Line Battery Energy Storage Systems A Battery Energy Storage System (BESS) consists of a very large bank of electrical batteries and automatically controlled electronic equipment to convert the electrical energy stored in the batteries from direct current (DC) to alternating current (AC) that can be supplied to the electrical transmission system. Similarly, energy can be absorbed from the electrical transmission system and stored in the batteries. Energy can be supplied to or absorbed from the electrical transmission system virtually instantaneously. This capability allows a BESS to compensate very quickly for imbalances between generation and load, such as might occur if the transmission intertie between the Kenai Peninsula and the Anchorage Bowl were to be severed. A BESS could be particularly applicable to address the need for increasing the reliability of the system and improving overall system stability during disturbances. Battery Energy Storage Systems were examined in some detail in the electrical system study effort*”. Several alternative locations for a BESS including Bernice Lake, International, Soldotna, Bradley Lake, and Kasilof Substations were evaluated. Dynamic stability analyses were performed for incremental power transfers over the existing line of 70 MW, 90 MW, 100 MW, and 120 MW. The conclusion of the electrical studies is that the BESS mitigates power swings due to a sudden interruption of power over the existing line, but introduces some instability and increases the likelihood of tripping other existing lines. Potential gains in system performance and increased power transfer are not fully achievable. For a Kenai BESS, transfers greater than 90 MW result in violations of the ASCC criteria for system stability for a trip of the existing line. It was also noted that installation of a BESS on the Kenai and in Anchorage would result in three BESS on the system (including Fairbanks), and that this would add uncertainty to the interaction of the controls with the existing static var compensation system and generation controls. There is no comparable industry experience with the operation of an isolated system similar to the Alaska interconnected grid with three BESS installed and in operation. Considering the results of the electrical studies, the BESS at best only partially meets the purpose and need for the Project. Consequently, the BESS was eliminated as an alternative to the proposed action. 57 Southern Intertie Route Selection Study, Phase _1B. Studies Section Report, September 1997, Power Engineers, Inc. Page 28 DEN 26-1319 rip (9/8/97) Demand Side Management and Energy Efficiency Demand-Side Management (DSM) consists of electric utilities' planning, implementing, and monitoring of activities designed to encourage consumers to modify their levels and patterns of electricity consumption. While DSM effects only a small percentage of the system load, utilities implement DSM programs to achieve two basic objectives: energy efficiency and load management. Energy efficiency (or energy conservation) is primarily achieved through programs that reduce overall energy consumption of specific end use devices and systems by promoting high-efficiency equipment and building design. Energy efficiency programs typically reduce energy consumption over many hours during the year. Examples include energy saving appliances and lighting, high-efficiency heating, ventilating and air conditioning (HVAC) systems or control modification, efficient building design, advanced electric motors and drive systems, and heat recovery systems. Load management programs, on the other hand, are designed to achieve load reductions, primarily at the time of peak load. For example, utilities can by agreement with their customers have direct control over loads that can be interrupted during periods of peak demand by the utility system operator, by directly interrupting power supply to individual appliances or equipment. This method usually involves consumers who allow the utility to periodically interrupt service to water or space heating units during the hours of peak load. Another type of load management program makes use of interruptible loads. Interruptible load is load that can be separated from the system during periods of peak load or system disturbances, either by direct control of the utility system operator or by action of the consumer, at the direct request of the system operator. For example, large commercial and industrial consumers are candidates for interruptible load management, depending on the type of business. Other load management programs that limit peak loads, shift peak load from on-peak to off-peak hour's, or encourage consumers to respond to changes in the utility's cost of providing power, are also used. Included are technologies that primarily shift all or part of a load from one time of day to another and also may affect overall energy consumption. Examples include space heating and water heating storage systems, cool storage systems, and load limiting devices in energy management systems. Members of the IPG have implemented energy efficiency and load management programs to varying degrees. Homer Electric Association, for example, encourages energy efficiency through their water heater rebate program. Matanuska Electric Association has implemented load management programs that allow direct control of customer water heaters, interruptible load, and off peak space and water heating incentives. Golden Valley Electric Association has several Energy$ense programs that address both energy efficiency and load management. Anchorage Municipal Light & Power focuses their Page 29 DEN 26-1319 rip (9/8/97) efforts on energy efficiency through betterment projects at their generating plants and is also developing other energy storage options. Chugach Electric, Seward, and Fairbanks Municipal Utility System work with their customers to encourage energy efficiency, but have no formal programs. Energy efficiency and load management programs are important tools that Alaska utilities are using, and will continue to use to manage the demand for and consumption of electricity. However, while valuable, these programs do not address any of the need categories of the Project. These DSM programs focus on managing a very small part of the load on the system, whereas the Project need is for improvements to allow better operational management of the existing interconnected system. For example, DSM will not increase system reliability or increase the power transfer capacity between Anchorage and the Kenai Peninsula, nor will it improve system stability during disturbances or allow the utilities to use the most economic mix of generating plants to reduce costs. Since energy efficiency and load management programs do not address the purpose and need for the Project, DSM was not considered further as an alternative to the proposed action. New Generation The Railbelt system is a power grid that electrically connects south-central Alaska from Homer to Fairbanks. There are three distinct regions — interior area, centered around Fairbanks; Anchorage and Matanuska Valley area (Anchorage Bowl); and the Kenai Peninsula. These areas are currently interconnected by the existing Anchorage - Fairbanks intertie and the Quartz Creek line between Anchorage and the Kenai Peninsula. As an alternative to constructing a second line from Anchorage to the Kenai Peninsula, adding generation capacity on the Kenai and/or in Anchorage was considered. Adding OEMs Fairbanks) 334 MW (Oil & Coal) generation capacity would increase the generation resources available to serve load on the system, however, the overall 88 MW (Coal) Submarine 138kV system currently has an excess of - 138kV : . 386 MW (Gas) 230kV 32 MW (Hydro) generating capacity over 386 MW (Gas) 4 iB MW (Toul) electrical load. p20 ae ga Currently, the installed 244 MW i generation capacity of the Railbelt is about 1470 MW, as opposed to a winter 1997 load of Rail Belt Generation & Loads =—PProximately 721 MW as shown Figure 4 in Figure 4. Generation capacity as well as electrical load is distributed throughout the Railbelt. As illustrated, Railbelt generation resources currently exceed electrical loads by a factor of two. While new generation resources could be used to enhance reliability and Page 30 DEN 26-1319 rip (9/8/97) improve system stability during disturbances, generation resources that could be used for this purpose already exist. Additional generation resources are not needed. What is needed is an enhanced ability to use the existing generation resources in the most economical manner. As noted in the Purpose and Need section, one of the primary purposes for the Project is to allow the existing system generation resources to be utilized more efficiently so as to reduce system operating costs while increasing reliability. In order to accomplish this, additional transmission line capacity is needed rather than new generating plants. Wind Generation Harnessing the wind to provide electric generation resources has been successful in California and in other parts of the world. The addition of wind generation to the Railbelt system would be another way of adding new generation resources to the system. Power can be generated from the wind through the use of large wind turbines, or windmills, that are sited in areas that exhibit high average wind speeds. In 1980, a study was completed for the Alaska Power Administration to evaluate the wind energy potential in the Cook Inlet area®*. The study examined wind data from the Pacific Northwest Laboratory wind energy database for the area. The area studied was in proximity to the existing electrical transmission system including: the eastern shores of Cook Inlet from Kenai to Homer, east from Kenai to Seward, north and west from Seward through Turnagain Arm past Anchorage and into the Matanuska - Susitna Valley regions around Palmer, and west to Beluga. In addition, the terrain up through Broad Pass, up the Matanuska Valley to Tahneta Pass, and down to the southern tip of the Kenai Peninsula were also studied in order to understand the behavior of winds in the region. The data was screened for likely sites for wind generation in and around the Cook Inlet area. Climatology in the area was studied by researching the literature on large scale weather patterns, examining wind speeds and direction at potential sites, and by interpreting both the large scale weather patterns and the local wind characteristics in terms of the interaction between the terrain features and the air flow. Potential sites identified were visited and observations made as to the suitability of a potential site for wind generation. The study concluded that there was no conclusive evidence that large scale generation of electrical energy by megawatt scale wind turbines would be a significant viable energy option in the Cook Inlet area. This conclusion was based on the criteria that a site must °*® Preliminary Evaluation of Wind Energy Potential—Cook Inlet _Area, Alaska, Pacific Northwest Laboratory, May 1980. Page 31 DEN 26-1319 rip (9/8/97) have a minimum annual average wind speed at 10 meters above ground of 6.5 meters/second. No sites were found where it was concluded that the criteria had been met. Therefore, wind generation is not a viable option for the Project. As noted earlier, additional generation is not needed in any case, rather the Project is needed, in part, to utilize the existing generation resources more efficiently so as to lower overall operating costs. Fuel Cells As an emerging technology, fuel cells were considered as to how they might apply to the Project. The addition of fuel cell generation to the Railbelt system would be another way of adding new generation resources to the system. Fuel cells are power-generating systems that produce DC electricity by combining hydrogen and oxygen in an electrochemical reaction. Fuel cells can be designed to use a variety of fuels, such as natural gas, landfill gas, liquid petroleum gas, propane, and coal gasification. Compared with traditional generating technologies that use combustion processes first to convert fuel to heat and mechanical energy, fuel cells convert the chemical energy of a fuel to electrical energy directly, without intermediate conversion processes. Fuel cell power plants consist of three major subsystems: a fuel processing subsystem (the reformer), the fuel cell stack subsystem, and the power conditioning unit (static power converter). The reformer converts the fuel supply to a hydrogen-rich fuel gas. It can be designed to accept many different fuels, including natural gas, propane, methanol, and coal gas. The fuel cell stack subsystem is where the electrochemical process occurs and the DC electricity is produced. The static power converter subsystem converts DC power to AC power. A 2 MW fuel cell demonstration plant has been constructed in Santa Clara, CA, and is the largest fuel céll plant ever tested in the US. Fuel cell generating units of 200 kW capacity are commercially available today for about $3000/kW, as compared to combustion turbine plants that have been and are being constructed for between $450 and $600/kW depending on the size of the unit and other factors. Combustion turbine units are commercially available in sizes from several MWs to several hundred MW and are currently in use by many utilities across the country and in Alaska for utility system power generation applications. Additional research and development efforts will likely result in lower costs for fuel cell generation plants, although wide spread use of fuel cells for utility generation applications is still several years off. While fuel cell generation plants offer potential for the future, larger size units are not currently commercially available. Consequently, fuel cells are not a viable option for the Project. Page 32 DEN 26-1319 rlp (9/8/97) Additionally, fuel cells are simply another form of new generation. As noted earlier, additional generation is not needed, rather the Project is needed, in part, to utilize the existing generation resources more efficiently so as to lower overall operating costs. Increasing Spinning Reserves Spinning Reserve is a portion of the Operating Reserves maintained by utilities. Spinning Reserve is unloaded generation, which is synchronized and ready to serve additional demand”. Spinning reserves respond to changes in consumer demand and failures in the generation and transmission system. Spinning reserves improve reliability, but they are often expensive. In order to maintain adequate spinning reserve margins, generation units must be operated without serving any consumer load. Increasing reliability and improving system stability during disturbances by operating additional generation in a spinning reserve mode could be accomplished at higher system operating costs. These higher costs would be reflected through increased fuel and maintenance expenses, and shorter life for the generating plants. Spinning reserves would need to be increased over present levels in order to enhance the reliability of the system. One of the reasons the Project is being proposed as a system improvement is to reduce spinning reserve requirements. The alternative of increasing spinning reserves to meet the purpose and need for the Project is in contradiction to the purpose of the Project. Consequently, increasing the amount of spinning reserves on the system was eliminated as an alternative. The need for and the benefits of reducing the system spinning reserve requirements are discussed in more detail in the Purpose and Need section of the document. Alternative Transmission Systems Upgrade of the Existing Quartz Creek Line The electrical system study effort conducted by Power Engineers® analyzed the performance of the system by modeling several different upgrade scenarios for the existing Quartz Creek Line, as an alternative to constructing a second transmission line. The primary benefit to upgrading the existing line would be to increase the power transfer capability between Anchorage and the Kenai. Conversion of the operating voltage of the * NERC Glossary, 1996. © Southern Intertie Route Selection Study , Phase _1, Final Studies Section Report, Power Engineers, Inc., June 14, 1996. Page 33 DEN 26-1319 rip (9/8/97) line from 115kV to 138kV or 230kV and the addition of reactive compensation to the line were analyzed. Conversion of the operating voltage from 115kV to 138kV could only increase the power transfer capacity of the existing line by about 20%, since the line voltage is only increased 23kV. In addition, most of the line would require reinsulation and the substation transformers at Indian, Girdwood, Portage, Hope, Summit Lake, Daves Creek, and Quartz Creek Substations would require replacement, along with modifications at University and Soldotna Substations. The high cost of reconstructing all of the intermediate substations along the line, associated with little change in performance eliminates this option. Increasing the operating voltage of the line from 115kV to 230kV can almost double the power transfer capability of the line. As with the 138kV conversion, converting the voltage to 230kV would require replacement of the transformers at the intermediate substations, and would also require upgrades to the substations at the endpoints of the line in Anchorage and at the Soldotna Substation. To be capable of carrying 230kV, the entire line would need to be reconstructed by replacing all of the structures. Even though the power transfer capability of the line would be increased, there would still only be one line, and at higher power transfer levels system stability problems would become worse for an outage of the line. The addition of either shunt or series compensation would also increase the power transfer capability of the line. Again, the higher power transfer levels would aggravate problems associated with system stability and operation of the system. While an upgrade of the existing line could increase the power transfer capability, none of the upgrade alternatives address the issues associated with having only one transmission line interconnection between Anchorage and the Kenai. The system stability issues would continue to limit the secure power transfer over the line to 70 MW, the same as the existing situation. The interconnection would still not meet ASCC criteria for single contingency outages. The existing problems associated with system reliability and stability would become worse. An upgrade to the line to achieve higher power transfer levels would aggravate the problems associated with these issues, and would make system wide blackouts and load shedding more likely for an outage of the line®’. Asa result, the alternative of upgrading the existing line was eliminated. Alternate Voltage Levels The appropriate operating voltage for a second transmission line interconnection between Anchorage and the Kenai Peninsula has been studied on several occasions”. Operating §! Please refer to the Purpose and Need Section for additional discussion. ® Power Engineers, Inc., 1987 and Southern Intertie Route Selection Study . Phase 1. Final Studies Section Report, Power Engineers, Inc., June 14, 1996. Alaska Energy Authority, March 1991. Page 34 DEN 26-1319 rlp (9/8/97) voltages of 138kV and 230kV were studied, because both of these voltage levels are used for transmission line and substation facilities that are part of the Alaska interconnected system. The advantage of 230kV over 138kV as an operating voltage would be higher power transfer capability with reduced transmission line losses. Each of the studies that considered the two voltage levels reached the same conclusions. Both the 138kV and 230kV alternatives exhibited similar performance for the expected steady state power transfers and system disturbance analyses. The additional power transfer capability offered by 230kV is not required for the power transfer levels projected during the Project life. The only advantage exhibited by the 230kV voltage level was slightly reduced transmission line losses. The 230kV alternative has the disadvantage of requiring larger and more expensive equipment than the 138kV alternative. The substantially higher cost of the 230kV facilities® makes the 230kV operating voltage alternative uneconomical, when compared to the 138kV. Therefore, an operating voltage of 230kV was eliminated and 138kV is proposed for the Project. Alternatives Studied in Detail No Action Alternative The Project is proposed as a system improvement to correct existing system deficiencies and lower operating costs, and the option of not constructing the Project was evaluated as part of the study process. The no action alternative was evaluated as part of the electrical system studies to determine the limitations of the existing Quartz Creek intertie between the Kenai Peninsula and Anchorage™. It was determined that the no action alternative does not address any of the existing system deficiencies related to the purpose and need for the Project. If the Project is not constructed, the deficiencies addressed by the Project would not be corrected and the system would continue to be operated less reliably and at a higher cost than if the Project were constructed. Existing system deficiencies in the areas of reliability, power transfer, economic utilization of existing generation, capacity sharing, system stability, spinning reserves, line losses, and maintenance would remain. The system currently does not meet industry accepted levels of performance as specified by the NERC and as described by the ASCC planning and operating criteria®. The no action alternative would not improve the system performance and would not bring the ® Southern Intertie Route Selection Study . Phase 1. Final Economic Section Report, Power Engineers, Inc., June 14, 1996. © Southern Intertie Route Selection Study , Phase _1, Final Studies Section Report, Power Engineers, Inc., June 14, 1996 and Southern Intertie Route Selection Study, Phase_1B. Studies Section Report, Power Engineers, Inc., September 1997 §° Please refer to the Purpose and Need Section for additional detail. Page 35 DEN 26-1319 rip (9/8/97) system into conformance with the criteria. The ASCC criteria have evolved over many years to become the standard by which the performance of the system can be measured. With respect to reliability, a single contingency outage of the Quartz Creek line can currently result in system wide blackouts and load shedding during system disturbances. The potential for these outages limits the way in which the system can be efficiently and cost effectively operated. For example, because the existing Quartz Creek line route traverses areas of known avalanches and high wind, to maintain system reliability during poor weather conditions, the existing line is at times operated at zero electrical flow, in anticipation of possible storm outages. This is an inefficient way of operating the system because during the period the line is not transferring electrical power between the Kenai and Anchorage Bowl, higher cost alternate generation sources must be used. Also, to maintain reliable service on the Kenai Peninsula, a minimum of 25 MW of gas turbine generation is operated on the Kenai at all times to help prevent blackouts in case of an outage of the Quartz Creek line. A minimum generation requirement would not be necessary to maintain reliability with a second line, and generation resources to maintain system integrity and reliability could be provided from the most cost effective source, whether in the Anchorage area or on the Kenai. With respect to power transfer, the existing line is limited to a 70 MW power transfer capability between the Kenai and Anchorage. Existing generation capacity on the Kenai is currently about 244 MW, but the peak load on the Kenai is only 85 MW. This 70 MW power transfer limitation effectively leaves stranded much of the existing generation on the Kenai. With this limitation, cost saving economy energy transfers to take advantage of lower cost energy in the Anchorage area or on the Kenai are restricted, resulting in higher operating costs. This limitation also restricts access to Bradley Lake power entitlements for the utilities in Anchorage and north, and the ability to use the Bradley Lake resource for hydro-thermal coordination with Anchorage area generation to lower operating costs. With respect to the economic utilization of existing generation and generation capacity sharing, the 70 MW limitation of the Quartz Creek line substantially constrains the sharing of generation between the Kenai, Anchorage, and north. This constraint does not currently allow the most cost effective generation resources to be operated in a coordinated manner to serve the load at the lowest cost. A second line is needed to relieve this constraint and allow the system to be operated more efficiently, and at lower cost. With respect to system stability, the current operating limitations imposed on the system by the Quartz Creek line require load shedding during certain system disturbances to maintain system stability and minimize system blackouts. With a second line, the ability of the system to maintain stable operation during disturbances will be substantially improved. Page 36 DEN 26-1319 rip (9/8/97) With respect to spinning reserves, the amount of spinning reserves that must be currently operated on the Kenai Peninsula and in the Anchorage area is greater than if a second line were in service, because of the limitations of the Quartz Creek line. Spinning reserves are generation resources that must be operated without serving any load, in anticipation of an outage of another generator, transmission line, or other system component. In the event of an outage, the spinning reserve can pick up the load immediately, helping to prevent a system wide blackout. While a necessary part of system operations, operating generation without serving any load is expensive, and the overall system level of spinning reserves and costs can be reduced with the addition of a second line. With respect to the reduction of transmission system losses, currently line losses are 10% or 7 MW with a power transfer of 70 MW over the Quartz Creek line. If the power transfer over the Quartz Creek line were to be increased to 125 MW, losses would increase to 25 MW or 20% of the power transferred. These are high levels of line losses, and the power lost in this manner represents lost revenue and energy that could have been used to supply loads. High losses result in additional costs for the operation of the system. Adding a second line would reduce the line losses for a 125 MW transfer to 5 MW, or 4% of the power transfer, lowering operating costs and increasing system operating efficiency With respect to maintenance costs for the Quartz Creek line, outages of the line to conduct maintenance are difficult to schedule, since the line is the only tie between Anchorage and the Kenai. This is because with the line out of service, additional generation on the Kenai and in Anchorage must be operated at increased cost to supply loads and spinning reserves in the absence of the interconnection between Anchorage and the Kenai. For the same reason, the duration of the scheduled outages are also limited, so maintenance activities must be extended over several days or weeks, whereas with a second line, scheduled outage durations could be increased allowing maintenance to be completed more quickly. With a second line, maintenance activities can be scheduled and conducted to result in lower overall costs. If the Project is not constructed, the benefits accruing from the Project, estimated between $116 and $132 million dollars”, would be lost and would continue as costs embedded in the rates for electricity. The no action alternative would not do anything to reduce operating costs and would perpetuate the present higher cost operating situation, whereas a second line would allow cost savings to be realized and benefits to accrue to the consumers served by the system. The alternative of taking no action and not constructing the Project does not address the needs that the Project is being proposed to resolve. * Decision Focus, Inc., August 1997. Page 37 DEN 26-1319 rip (9/8/97) Appendix A List of References NERC and ASCC Planning Criteria Page 38 DEN 26-1319 rip (9/8/97) List of References: 1. Railbelt Intertie Reconnaissance Study, Alaska Power Authority, 1989. Eleven Volumes & Addendum. List of Volumes: Volume Number | Volume Title Economic and Demographic Projections for the Alaska Railbelt: 1988-2010 Forecast of Electricity Demand in the Alaska Railbelt Region: 1988-2010 Analysis of Electrical End Use Efficiency Programs for the Alaskan Railbelt Fuel Price Outlooks: Crude Oil, Natural Gas, and Fuel Oil Anchorage-Kenai Transmission Intertie Project Anchorage-Fairbanks Transmission Intertie Expansion and Upgrade Project Railbelt Stability Study, Power Technologies, Inc. Northeast Transmission Intertie Project Estimated Cost and Environmental Impacts of Coal-Fire Power Plants in the Alaska Railbelt Region Estimated Cost and Environmental Impacts of a Natural Gas Pipeline system Linking Fairbanks with the Cook Inlet Area Benefit/Cost Analysis Addendum Economic Feasibility of the Proposed 138kV Transmission Lines in the Railbelt This volume includes revised benefit/cost analysis and critiques by independent reviewers. 2. Anchorage-Kenai Transmission Intertie Feasibility Study, Power Engineers, Inc. and Hart Crowser, May 1987. Two volumes. 3. Reliability Assessment of the Railbelt Interconnected Electric Utility Systems, North American Electric Reliability Council (NERC), 1990. 4. Railbelt Intertie Feasibility Study. Final Report, Alaska Energy Authority, March 1991. 5. Benefit/Cost Analysis, Decision Focus, Inc., June 1989. 6. Economic Feasibility of the Proposed 138kV Lines in the Railbelt, Decision Focus Inc., December 1989, this document is an addendum to the June 1989 Decision Focus, Inc., Benefit/Cost Analysis. 7. Review and Update of the Economic Feasibility of the Southern Intertie Project: Decision Focus Inc., August 1997. 8. Comprehensive Avalanche Atlas: Alaska Mountain Safety Center, Inc., October 1991. 9. Glossary of Terms, Prepared by the Glossary of Terms Task Force North American Electric Reliability Council, August 1996. 10. Southern Intertie Project. Route Selection Study. Phase I, Power Engineers, Inc. & Dames and Moore, 1996. In five separate reports. 11. Cost Estimate. Kenai/Anchorage and Healy/Fairbanks 138 kV Transmission Line Interties, Dryden and LaRue, March 1991. Page 39 DEN 26-1319 rip (9/8/97) 12. Southern Intertie Route Selection Study Phase 1B. Studies Section Report, Power Engineers, Inc., September 1997. 13. Southern Intertie Project. Draft Cost Estimate Summary Report, Power Engineers, Inc., August 1997. Page 40 DEN 26-1319 rip (9/8/97) Table A1 - Electrical Utility Planning Criteria North American Electric Reliability Council Planning Guides” These Planning Guides describe the characteristics of a reliable bulk electric system. They are intended to provide guidance to the Regional Councils, Subregions, Pools, and/or the Individual Systems in planning their bulk electric systems. To the extent practicable, a balanced relationship is maintained among bulk electric system elements in terms of size of load, size of generating units and plants, and strength of interconnections. Application of this guide includes the avoidance of : e Excessive concentration of generating capacity in one unit, at one location or in one area; e Excessive dependence on any single transmission circuit, tower line, right-of-way, or transmission switching station; and e Excessive burdens on neighboring systems. Page 1 of 2 Alaska Systems Coordinating Council Planning Criteria” Balance Among System Elements - A balanced relationship shall be . maintained among bulk electric system elements so as to avoid excessive dependence on any one element. ASCC Planning Criteria Number The system is designed to withstand credible contingency situations. Contingencies - Additions to the interconnected system shall be planned and designed to allow the interconnected system to withstand any credible contingency situation without excessive impact on the system voltages, frequency, load, power flows, equipment thermal loading, or stability. Dependence on emergency support from adjacent systems is restricted to acceptable limits. Emergency Support - Reserves should be provided such that emergency support from adjacent systems is restricted to acceptable limits as determined by studies of the interconnected system. Adequate transmission ties are provided to adjacent systems to accommodate planned and emergency power transfers. *™ NERC Planning Guides as approved by NERC Engineering Committee on February 28, 1989 °8 ASCC Planning Criteria adopted by the ASCC on April 4, 1991 Page 41 DEN 26-1319 rlp (9/8/97) Support From Adjacent Systems - Adequate transmission ties between adjacent systems shall be provided to accommodate planned and emergency power transfers. Table A1 - Electrical Utility Planning Criteria North American Electric Reliability Council Planning Guides These Planning Guides describe the characteristics of a reliable bulk electric system. They are intended to provide guidance to the Regional Councils, Subregions, Pools, and/or the Individual Systems in planning their bulk electric systems. Reactive power resources are provided which are sufficient for system voltage control under normal and contingency conditions, including of emergency power transfer. support for a reasonable level of planned transfers and a reasonable level Page 2 of 2 Alaska Systems Coordinating Council Planning Criteria Reactive Power Resources - Each control area shall provide sufficient capacitive and inductive resources at proper levels to maintain system steady state and dynamic voltages within established limits, including support for reasonable levels of planned and emergency power transfers. ASCC Planning Criteria Number extent of system disturbances and to allow for malfunctions in the protective relay system without undue risk to system reliability. Adequate margins are provided in both real and reactive power resources |] Real and Reactive Power Margins - Margins in both real and reactive 6 to provide acceptable dynamic response to system disturbances. power resources are provided for acceptable dynamic response to system disturbances. Recording of essential system parameters is provided for both steady Recording System Parameters - Essential system parameters shall be 7 state and dynamic system conditions. recorded. System design permits maintenance of equipment without undue risk to |] Reliability During Maintenance - System design shall allow for 8 system reliability. equipment maintenance without unduly degrading reliability. Planned flexibility in switching arrangements limits adverse effects and Switching Flexibility - Switching arrangements shall be provided to limit 9 permits reconfiguration of the bulk power transmission system to adverse effects and permit reconfiguration of the bulk power transmission facilitate system restoration. system to facilitate system restoration. Protective relaying equipment is provided to minimize the severity and Protective Relaying - Provide sufficient relaying equipment such that the 10 severity and extent of the system disturbances is minimized and that malfunctions in the protective relay system do not jeopardize system reliability. Black start-up capability is provided for individual systems. Black Start-up - Black start-up capability is to be provided for individual systems. Fuel supply diversity is provided to the extent practicable. Page 42 DEN 26-1319 rip (9/8/97) Fuel Supply - Plans for generation additions shall consider fuel supply diversity. July 3, 1997 SOUTHERN INTERTIE QUARTZ CREEK ROUTE ALTERNATIVE Recommendation for Elimination The Quartz Creek Route altemmative was identified and studied as a potential routing opportunity for the Southern Intertie Transmission Project (Intertie) because it would follow an existing transmission line conidor. The Quartz Creek Route altemative would involve siting the proposed Intertie in a right-of-way adjacent to the existing 115 kilovolt (kV) transmission line right-of-way. The parallel right-of-way would extend from one of three endpoints in the Anchorage area—University Substation, APA Substation, or AML&P Plant No.2 Substation—to the Soldotna Substation on the Kenai Peninsula. There have been numerous comments on the Quartz Creek Route alternative from federal, state, and local agencies and the public through the scoping process, extensive inventory studies, and legal review. At this time, the Quartz Creek Route alternative does not meet the purpose and need for the project and is recommended for elimination from further study in the Environmental Impact Statement. The following discussions highlight the key issues leading to the recommendation to eliminate the Quartz Creek Route altemative from further study, including reliability/purpose and need and land rights constraints. Reliability/Purpose and Need The primary reasons for constructing the Intertie is to increase the reliability and electric transfer capability of the Railbelt electrical system by establishing a second tie between Anchorage and the Kenai Peninsula which would be independent of the existing Quartz Creek transmission line. Reliability of the electric power supply to Anchorage and the Kenai Peninsula is compromised because the Quartz Creek line is vulnerable to weather and avalanche-caused outages. Constructing a second, parallel line along the Quartz Creek line right-of-way would make both lines vulnerable to the same weather and avalanche-caused outages. The existing Quartz Creek 115kV transmission line is exposed to potential avalanche hazard in several locations between the University and Quartz Creek substations. Studies by the Alaska Mountain Safety Center (1991) show that 88 structures and 117 spans along the line are exposed to some degree of potential hazard from destructive avalanches. Extended outages to the existing line have occurred because of avalanches in the Bird Flats area, between Girdwood, and Portage as well as in the Summit Lake area. Historic records indicate that during an 18-year period from 1971 to 1988 the line was hit and severely damaged by avalanches on 11 occasions at six different areas, for an average of once every 1.6 years or more frequently. The largest period of time without interruption was eight years while the least was less than one year. From 1988 to 1989 Chugach Electric Association implemented mitigation to reduce the overall risk of exposure to avalanche damage, including tower relocations and diversion structures; however, the remaining hazard is still rated as moderate. A moderate risk means that one to four large, potentially destructive avalanches may reach an individual structure or span during a 50-year period. Since the Quartz Creek line is the only transmission line between the Kenai Peninsula and the Anchorage Bow, the loss of the line has a severe impact on the electrical systems on both the Kenai Peninsula and the Anchorage Bowl, causing outages for consumers in both areas. A second parallel line would be subject CAWPWIN6(\WPDOCS\SOUTHTIE\POWERIQUCRELIM. 1 July 3, 1997 to the same potential for outages as the existing line, and would only marginally increase the reliability of the system. ‘Thus, the Intertie would not meet the purpose and need for the project in terms of significantly increasing the reliability of the system. In terms of increased energy transfer, a second parallel line would increase the transfer capacity of the system between Anchorage and the Kenai Peninsula. However, with the second line parallel to the existing lineand subject to the same outage events as the existing line, an avalanche or similar event could remove both lines from service. Consequently, the new parallel line would be subject to the same single contingency outage events as the existing line, and would not reliably provide increased energy transfers during a significant outage event on the existing line. Conversion of Chugach State Park Lands The existing 115kV transmission line crosses 23.8 miles of Chugach State Park, traversing Powerline Pass to Indian, and then generally paralleling the Seward Highway National Scenic Byway to Girdwood. The Quartz Creek Route alternative would parallel this existing line. In 1973, Chugach State Park applied for funding assistance from the National Park Service under the Land and Water Conservation Fund Act (L2&WCFA). The funds were to be used for certain acquisitions within the park to support outdoor recreation activities. Accompanying the federal funds assistance is legal protection which states that grant-assisted areas are to remain forever available for public outdoor recreation use or be replaced by lands of equal market value and recreation usefulness. Section 6(f)(3) protection states: No property acquired or developed with assistance under this section shall, without the approval of the Secretary [of the Interior], be converted to other than public outdoor recreation uses. The Secretary shall approve such conversion only if he finds it to be in accord with the then existing comprehensive statewide outdoor recreation plan and only upon such conditions as he deems necessary to assure the substitution of other recreation properties of at least equal fair market value and of reasonably equivalent usefulness and location. The entire park was placed under this legal protection, and Alaska Department of Natural Resources- Division of Parks and Outdoor Recreation staff have indicated that they perceive an additional overhead transmission line as a conversion of use. The existing 115kV line predates the park and funds assistance. Division of Parks staff have indicated that they would not support a request for conversion to the National Park Service for conveyance of additional right-of-way for a second overhead line. Undergrounding the transmission line through Chugach State Park would require 18.8 miles of underground cable. The length of the route through the Park is 23.8 miles, and approximately 5 miles of the line would be constructed as a double circuit on the existing steel lattice tower section west of Girdwood, which is the only practical alternative for that section. The additional cost of undergrounding (excess cost of underground minus ovethead cost) would be on the order of $22 million. By using the alternative route along Sixmile Creek the distance through Chugach State Park is approximately 15.3 miles resulting in an additional $19 million for undergrounding and associated reactor/transition stations. July 3, 1997 A double circuit configuration of the existing facilities would be another altemative, which would not require additional ROW, but is viewed by the Division of Parks as a significant change in the visual aeshetics of the property. Division of Parks therefore would not support a request for conversion to the National Park Service for a double circuit line. Conversion of the existing line would require an amendment to the FERC license, under which this line was originally constructed. With the known opposition of the underlying land owner (Division of Lands), it is very unlikely that such an amendment would be approved. It should be noted that any plans for double circuit construction of existing lines have generally been avoided for the Intertie, because of the need for increased reliability of the Railbelt system. If both circuits occupy the same transmission structure, the resulting line would not enhance the single contingency performance of the electrical system for a structure failure. , TUL 16 ’97 @8?17AM GVEA PMINISTRATION ~ pve oe CHUGACH ELECTRIC ~ ugach IN ASSOCIATION, INC. July 9, 1997 @e | &; Golden Valley Electric Association, Inc. WN y “En P.O. Box 71249 c 4 199 Fairbanks, Alaska 99707 “tg 7 Attention: Mr. Michael P. Kelly, General Manager an, Subject: Southern Intertie, EA/EIS Process Quartz Creek Route Alternative Dear Mr. Kelly: ‘The Quartz Creek Route for the Southern Intertie represents an alternative that follows an existing transmission line from Soldotna to Quartz Creek into Anchorage. The new tie would be constructed on its own support structures next to the existing facilities. POWER Engineers and Dames and Moore have evaluated this route extensively and recommend that it be eliminated from the EIS preparation as a viable alternative. This recommendation is based on an assessment of the reliability of a line built along this route and added costs resulting from underground construction over approximately 23.8 miles of lands in the Chugach State Park. The existing line’s reliability is compromised, primarily due to avalanche, wind and snow exposure. Chugach State Park Service, created after the existing transmission line was built, cannot allow non recreational use (e.g-, construction of a transmission line) without requesting concurrence from the National Park Service. The park’s administration has informed us that they will not support such a conversion request. Underground construction could be allowed, but would add more than $20 Million to the construction costs. A copy of POWER Engineers’ analysis and recommendation is enclosed. We agree with the consultants recommendation and are requesting your concurrence. This leaves two alternative corridors for the Southern Intertie: 1. Enstar Route 2. Tesoro Route 5601 Minnesota Drive * PO. Box 196300 * Anchorage, Alaska 99519-6300 Phone 907-563-7494 » FAX 907-562-0027 » JUL 16 °97 @8217AM GVEA “MINISTRATION : \ p.2e se Southern Intertie, EA/EIS Process - Quartz Creek Route Alternative July 9, 1997 Page 2 of 2 Both of these routes would terminate in South Anchorage at Chugach’s International Substation (Enstar Route) or at the Point Woronzof Substation (Tesoro Route). Please indicate that you concur with the proposed action by signing in the space provided and returning a copy of this letter. If there are any questions, please contact Dora Gropp, Project Manager at (907) 762-4626 by telephone or by e-mail to dora_gropp@chugachelectric.com. Sincerely, CONCURRENCE: Date: CHUGACH ELECTRIC ASSOCIATION, INC. “MN. Eugen. Bi 2-19-97 - Bjorms . Mr. Michael P. Kelly, Manager ENB/DLG/ahw Enclosures: Quartz Creek Route Alternative dated July 3, 1997. Gc Randy Simmons, AIDEA Lee Thibert . Mike Massin Brian Hickey "| aa. Sec., 2.1.2.1 : . G . vB OK , 7-15-1997 89:37AM FROM Seward Engr & Utilities TO 19875628827581 P.@1 Southern Intertie, EA/EIS Process - Quartz Creek Route Alternative Jaly9,1997° Page 2 of 2 i —————————— ee Both of these routes would terminate in South Anchorage-at Chugach’s International | Substation (Eristar Route) or at the Point Woronzof Substation (Tesoro Route). | Please indicate that you concur With the proposed action by signing in the space proved and returning a copy of this letter. If there are any questions, please contact Dora Gropp, Project Manager at (907) 762-4626 by ‘teeehome “pene eee oe: : 4 ! \ aan Eugene N Bjorns' iar. Dave Calvert, Utility ? ! ENB/DLG/ahw Enclosures: Quartz Creek Route Alternative dated July 3, 1997. i | c: Randy Simmons, AIDEA ' a | Mike Massin John Cooley i Brian Hickey ‘ Jim Borden W.O. £9590081, Sec., 2.1.2.1 ' TOTAL P.21 07/15/97 TUE 09:41 [TX/RX NO 5151) (07/12/87 «11:28 FAX 9074740549 UCS R L HUFMAN +++ GENE oo2 Southern Intertie, EA/EIS Process - Quartz Creek Route Alternative July 9, 1997 Page 2 of 2 Both of these routes would terminate in South Anchorage at Chugach’s International Substation (Enstar Route) or at the Point Woronzof Substation (Tesoro Route). Please indicate that you concur with the proposed action by signing in the space provided and retuming a copy of this letter. If there are any questions, please contact Dora Gropp, Project Manager at (907) 762-4626 by telephone or by e-mail to dora_gropp@chugachelectric.com. Sincerely, CONCURRENCE: = ELECTRIC ASSOCIATION, INC. < re Ca et Cltfaen 7 7-1A-97 ee ENB/DLG/zhw Enclosures: Quartz Creek Route Alternative dated July 3, 1997. c: Randy Simmons, AIDEA Lee Thibert . Mike Massin John Cooley Brian Hickey Jim Borden W.O. E9590081, Sec., 2.1.2.1 RF JUL 18 797 @4:@8PM FMUS ‘NERAL MANAGER P.3 Southern Intertie, EA/EIS Process - Quartz Creek Route Alternative July 9, 1997 20f2 Both of these routes would terminate in South Anchorage at Chugach’s International Substation (Enstar Route) or at the Point Woronzof Substation (Tesoro Route). Please indicate that you concur with the proposed action by signing in the space provided and returning a copy of this letrer. If there are any questions, please contact Dora Gropp, Project Manager at (907) 762-4626 by telephone or by e-mail to dora_gropp@chugachelectric.com. Sincerely, CONCURRENCE: CHUGACH SW hse ASSOCIATION, INC. Se ENBIDLG/ahw Enclosures: Quartz Creek Route Alternative dated July 3, 1997. (4 Randy Simmons, AIDEA Lee Thibert Mike Massin John Cooley Brian Hickey Jim Borden W.O. E9590081, Sec., 2.1.2.1 RF APs 7A OPT teen ore mw ain reens Review and Update of Economic Feasibility of Southern Intertie Project DRAFT Prepared by: Stephen Haas Annette Hulse Decision Focus Incorporated 650 Castro Street, Suite 300 Mountain View, California 94041-2055 (415) 960-3450 Prepared for: Power Engineers Incorporated 3940 Glenbrook Drive Hailey, ID 83333 August 1997 @-d- EFS-F0OS/, See -7 yecednol 6/4/P7 1.0 Introduction and Summary In 1989 Decision Focus Incorporated (DFI) carried out an economic analysis of ‘the benefits of several proposed transmission line upgrades or additions in the Railbelt area of Alaska. The results of the analysis were documented in a December 1989 report entitled “Economic Feasibility of the Proposed 138 KV Transmission Lines in the Railbelt”. One of the lines studied in the 1989 analysis, the Southern Intertie Project (SIP) between Anchorage and Kenai, is currently under serious consideration, and an environmental impact statement (EIS) is being prepared for the proposed project. Because DFI’s 1989 analysis helped to justify the project, it is desirable to review that analysis to determine whether any changes have occurred in the years since 1989 that would alter the conclusions of the analysis. The December 1989 report estimated benefits of new transmission lines in six different categories: 1. capacity sharing economy energy transfer reliability transmission losses operating reserve sharing state revenue from gas royalty and severance taxes AAS eh The first three of these categories accounted for about 90 per cent of the total benefits in the 1989 study; the current effort, described in this report, concentrates on these three categories. The effort focused on the key data values underlying the estimates, determined how these data values have changed, and calculated the impacts on the benefits estimates. In addition, all benefit estimates were converted to 1997 dollars for easy comparison to current cost estimates _ of the proposed line. Table 1 summarizes the conclusions of the update. The dollar values shown are the net present value of benefits in each category over the period 2004-2043; the new line is assumed to come into operation January 1, 2004, and to last for 40 years; the present values are in 2004. Each of the last three columns reflects an additional charge: converting to 1997 dollars, discounting at 6 per cent, and updating values such as fuel price projections. Decision Focus Incorporated - Confidextial Table 1 Net Present Value of Benefits of Proposed SIP December 1989 Value | December 1989 Value | December 1989 Value New Value The new total benefits estimate is substantial, but is about 25 per cent lower than for the 1989 stady, when expressed in the same year dollars, due primarily to lower forecasts of fuel prices, alower cost of new generating capacity, and the use of a higher discount rate. The changes in benefits and the reasons for them are explained in the following sections. 2.0 Benefits Estimation Methodology This section outlines the methodology used for calculating the numerical estimates in each of the three major categories, summarizing the key assumptions and listing the major data items 2.1 Capacity Sharing Capacity sharing benefits occur when: © one region has a capacity shortfall (i.e., demand plus the required reserve margin exceeds the capacity available) © another region has a capacity surplus e transmission links allow the first region to rely on excess capacity in the second region, even if only for a limited time Increased transmission capacity allows one region to rely more heavily on generation capacity in another region, for capacity as well as for energy. For the Railbelt, the SIP would allow Anchorage to rely on a greater portion of the Kenai Peninsula generation capacity surplus for meeting the Anchorage capacity requirement, thus deferring the need to build new generation capacity in Anchorage. ‘Decision Focus Incorporated - Confidential R297 There are two types of capacity sharing benefits: 1. As load grows in a region, enough capacity must be available to meet the peak load in that region plus a required reserve margin. Increased transmission capacity increases access to generation capacity in regions with surplus capacity, thus making it possible to defer adding generation capacity in the first region 2. The larger and more interconnected a system, the lower the reserve margin required to provide the same level of reliability. Increasing transmission capacity increases the level of interconnectedness for the Railbelt, allowing utilities to permanently avoid building some of the capacity that would have been constructed to maintain the desired reserve margin. Construction of the SIP would produce both types of capacity sharing benefits. Demand growth, taken together with available capacity, determines the timing of any capacity sharing benefits. Demand tends to grow over time, while unless new generating units are installed, capacity holds steady or shrinks somewhat due to retirements. Therefore, capacity sharing benefits tend to first grow over time as surplus is eliminated in relatively capacity-poor regions, then fall as surplus also disappears in the relatively capacity-rich regions. The capacity sharing benefit in a year is the amount of capacity avoided or deferred in the year, measured in kilowatt-years, times the cost of a kilowatt-year of capacity. For the latter we use the annualized fixed cost of a new combustion turbine, including both the installed capital cost and the fixed operations and maintenance cost; this is a standard yardstick for measuring the value of capacity. key data items: e total generating capacity available e peak demand growth © required reserve margin e fixed cost of new combustion turbine 2.2 Economy Energy Transfers This benefit occurs when high cost energy in one area is displaced by lower cost energy from aother area. In the Railbelt all available hydro energy, which uses no fuel and for which the variable cost is essentially zero, will be used with or without the proposed new transmission line. Thus the benefits in this category result from displacing electricity generated from thermal units (gas-fired or oil-fired) with electricity from other thermal units with lower variable costs. These lower costs may result from access to less expensive fuel or from some uiits being more efficient (converting a greater fraction of the energy content of the fuel to dectricity) than others. Decision Focus Incorporated - Confidential The economy energy benefit is equal to the increased amount transferred between Kenai and Anchorage (as a result of the new line) times the difference in marginal variable operating costs between the two regions. Secondary impacts result from being able to better operate units at or near their optimal loading levels, and improved hydro-thermal coordination. The variable costs of producing electricity, i.e., costs of economy energy, are roughly proportional to fuel prices. This means that higher fuel prices translate directly to a higher level of economy energy transfer benefits; a percentage increase in fuel prices translates to toughly the same percentage increase in economy energy benefits if all fuel prices in both tegions are increased by the same percentage. Similarly, a reduction in price forecasts for all fuels translates directly to reductions in economy energy transfer benefits. Changes in load growth forecasts since 1989 may impact economy energy amounts transferred, also impacting the benefits in this category, but this is a smaller effect and has not been key data items: a fuel price projections a load growth projections 2.3 Reliability Reliability is determined by the number, magnitude, and duration of customer outages. Reliability benefits occur if customer outages are reduced as a direct consequence of constructing a new transmission line. The proposed SIP is expected to reduce both the frequency and duration of generation- and transmission-related outages, i.e., outages related to unexpected loss.of generating units or the existing Anchorage-Kenai transmission line. In the event of an outage, unserved energy is defined as the electricity that would have been consumed if the outage had not occurred. The reliability benefit is equal to the expected reduction in unserved energy as a result of the proposed line times the value of each unit of unserved energy. Several studies have shown that the value per unit of unserved energy depends on the customer class affected and the duration of the outage. key data items: a reduction in unserved energy as result of new line a value of unserved energy Decision Focus Incorporated - Confaiential 3.0 Updates Of Key Data Items The major factors that go into determining benefits of capacity sharing, economy energy, and teliability include: discount rate demand forecasts generating capacity: planned additions and retirements cost of new capacity fuel price projections level of customer outages (number, size, duration) and outage causes value of customer outages Each of these is discussed below, followed by a qualitative discussion of the impact on benefits estimates given the new information. 4.1 Converting to 1997 Dollars The first challenge in comparing 1989 estimates with current estimates is to make sure that the mumbers are all based on the same year’s dollars; this eliminates the effects of inflation that make a dollar today not as valuable as a dollar was 7 or 8 years ago. DFI’s 1989 benefits study expressed all values in 1990 dollars. For this update all values are expressed in 1997 dollars. Therefore, before we can compare the data from the previous study to the new information, we have to inflate it so that we can compare old values expressed in 1997 dollars to new values expressed in 1997 dollars. We have assumed an annual average inflation rate over the last 7 years of 3.23 per cent, which is the annual average increase in the Consumer Price Index from 1990 to 1997. With this inflation rate, a value of $1.00 in 1990 dollars corresponds to $1.25 in 1997 dollars. 3.2 Discount Rate In order to make simple comparisons between two or more multi-year streams of costs or benefits, the multi-year streams are usually converted to a net present value by discounting costs and benefits that occur in future years back to an initial year, and summing over all years. This means that costs or benefits that occur in the future carry less weight than those occurring now. For example, at a discount rate of 6 per cent, $1 of benefits in 1998 is worth $0.94 now, while $1 of benefits in 2010 is worth only $0.47 now. The choice of discount rate can make a significant difference to the net present value of a benefits stream if many of the benefits occur in the future. A lower discount rate gives relatively more weight to future benefits than a higher discount rate. ‘Decision Focus Incorporated - Confidential Which discount rate to use for evaluating projects such as the SIP is not obvious. The discount tate is supposed to reflect the time preference of the party or parties making the decisions; Is this the state, the ratepayers, or some other entity? Should a higher discount rate be used to teflect the riskiness of the project? We believe that for the SIP the appropriate discount rate should reflect the cost (or value) to the ratepayer of investing money today to capture future benefits. The cost of capital for the investing organization is a good measure of the cost to the ratepayer. For instance, Chugach Electric Association has an average historic cost of debt of about 8.6 per cent. This means that, on average, when Chugach has borrowed money in the past, it has paid a nominal interest tate of 8.6 per cent on the debt. The nominal interest rate includes inflation; to get the equivalent real interest rate we take out the effects of inflation. Fuel prices provided by Golden Valley Electric Association indicate a projected forward-looking inflation rate of 2 per cent, and historical inflation has been 2.5 to 3 per cent over the last 5 years. For this update of the 1989 study, we have chosen a discount rate of 6 per cent to represent the teal cost of capital for the Railbelt area (8.6 per cent nominal = 6 per cent real + 2.6 per cent _ inflation). Using a 6 per cent discount rate instead of 4.5 per cent, as was used in the 1989 study, with no other changes in assumptions would lower the present value of benefits by 15 to 20 per cent, depending on the pattern of benefits over time. Note that both the 4.5 per cent rate used in 1989 and the 6 per cent rate used here are real discount rates, i.e., rates excluding inflation. The switch from 4.5 to 6 per cent does not teflect any changes in underlying conditions, but rather a change in assumptions away from a fate mandated by a government agency to a rate more appropriate for a utility and its ratepayers. 3.3. Demand Forecasts Table 2 compares the demand forecast used in the 1989 study with current demand forecasts, by looking at the forecast for the year 2010. Table 2 COMPARISON OF PEAK DEMAND FORECASTS FOR 2010 (MW) Decision Focus incorporated - Confidential (Fairbanks forecast is preliminary.) For Anchorage and the Kenai Peninsula, the new forecasts for 2010 are not too different from the 1989 forecasts. However, the newer projection for Golden Valley/Fairbanks is substantially higher. 3.4 Generating Capacity: Planned Additions and Retirements There have been some changes since the 1989 study. Life extensions and postponing the retirement of several units, particularly Beluga, result in a substantially higher projection of available capacity, pushing capacity sharing benefits further into the future. 3.5 Cost of New Combustion Turbine A new combustion turbine is assumed to cost $600 per kilowatt installed (per discussion with Power Engineers Incorporated), with fixed operations and maintenance cost of $11.50 per kilowatt per year. Levdizing the capital cost over 20 years at 6 per cent and adding the fixed operations and maintenance cost yields a value of $55 per kilowatt per year, in 1997 dollars. The 1989 study used a value of $51 per kilowatt per year, in 1990 dollars. When both are expressed in the same year dollars, the new value is about 15 per cent lower. 3.6 Fuel Prices Table 3 shows the fuel prices projected for 2010 in the 1989 analysis, converts them to 1997 dollars, and compares the forecasts to today’s actual prices. The actual prices today are about 40 to 70 per cent lower than the forecast, when both are expressed in 1997 dollars. Decisios Focus Incorporated - Confidential Table 3 Comparison of 1997 Fuel Price Forecast with Actual Prices [$/million Btu] Table 4 compares the 1989 fuel price forecasts for 2010 with current fuel price forecasts for 2010. As in Table 3, all numbers are converted to 1997 dollars. We see a similar pattern, in that the prices forecast today for 2010 are 25 to 50 per cent lower than the prices that were forecast for 2010 in 1989. Table 4 Comparison of Fuel Price Forecasts for 2010 Made in 1989 With Those Made in 1997 [$/million Btu] Decision focus Incorporated - Confidential R2947— Lower fuel prices reduce the value of the benefits from economy energy. Without detailed system modeling (i.e., how each generating unit would be operated over the 40-year time horizon, with and without the proposed new transmission line), it is impossible to say precisely how much the benefits are reduced (see recommendation Section 4.2). However, in aggregate, we would expect that if all fuel prices are lower by some percentage, then the benefits will similarly go down by about the same percentage. 3.7 Level of Customer Outages Two key assumptions about the impact of the new Kenai-Anchorage line were made in the 1989 study: a the new line would reduce outages (unserved energy) in the Kenai by about 55 per cent from historical levels (1986-1987); this assumption took into account the fraction of time that energy was flowing in each direction, and the likely impact of an outage for each direction of flow. a the new line would reduce outages in the Anchorage area by 30 to 60 megawatthours; this is based on avoiding 1 to 2 outages of 30 MW and one hour duration per year. The current update uses these same assumptions. New outage data has been provided, but it is incomplete, and completely redoing the reliability benefits component was beyond the scope of this update (see recommendations in Section 4.2). 3.8 Value of a Customer Outage Except for converting to 1997 dollars, we used the same assumptions as the 1989 study. About 88 per cent of outages are industrial or commercial, with the remainder residential. The outages that would be impacted by the proposed line range from a few minutes to a few hours in duration. Based on the distribution by customer class and duration, the average value of each kilowatthour of unserved energy avoided is about $22 (1997 dollars). 4.0 Conclusions and Recommendations 4.1 Updated Benefits Estimates Table 5 (which is identical to Table 1) shows the updated benefits estimates. While they are lower than in the 1989 study, they are still substantial. To put the benefits of the proposed SIP in context, it is useful to compare them to the current level of expenditures (total paid by retail customers) on electricity in the Railbelt. These are roughly $450 million per year. If we assume these will grow at 2 per cent per year, then the net present value of these expenditures over the period 2004-2043, for which we have estimated the benefits of the proposed Kenai-Anchorage line, is about $9 billion. Decision Focus Incorporated - Confidential R2947—, 10 Table 5 Net Present Value of Benefits of Proposed SIP (milbons of 1997 $, 4.5% discount ra The updated benefits estimates in all categories are lower than in the 1989 study as a result of using a higher discount rate, 6.0 per cent versus 4.5 per cent; where we did not re-calculate the entire benefits stream, we reduced the value by 15 per cent to account for this effect. In addition, the capacity sharing and economy energy transfer benefits are substantially lower, primarily as a result of lower cost of new generating capacity and lower fuel price projections. Benefits of improved reliability are the same as the 1989 study, except for the conversion to 1997 dollars and the use of a higher discount rate, because incomplete data was provided, and complete updating of the reliability numbers was beyond the scope of this update. Benefits in the other categories are the same as the 1989 study, except for the conversion to 1997 dollars and the use of a higher discount rate; they were significantly smaller than the first three categories, so we did not attempt to update them. 4.2 Recommendations If additional analysis of the benefits of the SIP is considered warranted, it should focus on the following areas: a Uncertainty in projections of fuel prices and load growth. a Economy energy benefits: projections of how the entire Railbelt system would be operated with and without the new line, should be developed, instead of simply adjusting the 1989 estimates in proportion to the change in projected fuel prices. a Reliability benefits: the assumptions about the extent to which unserved energy would be reduced by constructing the proposed line, and about the value of each unit of unserved energy, should be reviewed. a Other potential benefits not included in either study, such as transmission system stability and economies of scale in installing new generating capacity. Decision Focus Incorporated - Confidential R294¢7a 11 & Impacts of adding battery energy storage (BESS) or superconducting magnetic energy storage (SMES) in addition to the SIP to the Railbelt system; Anchorage Municipal Light and Power (AMLP) has estimated that the savings in spinning reserve costs from adding storage would be $1 million per year for AMLP alone, but only if there is adequate transmission capacity. Additional analysis of these areas would require considerable interaction with staff of the IPG members. . Decisice Focus Incorporated - Confidential R294ia SENT BY: 6-87 ; 10:32; POWER ENGIN .S+ 907 562 0027:# 2/ 6 7 mons ED ECEIVE D DorGropp AUG 1 1 4997 ‘Anchorage, AK 99519-6300 Subject 120376-04 — Southem Intrtie Project ‘Calculation of kWh Rate Impacts from the SIP Dear Dora, ‘The impact of the SIP on rates has been an issue ever since the very first public meetings last year. The Project Team’s response at the meetings has been that the rate impacts would be addressed as part of the EIS process. The Scoping Report, which is in the proccss of being completed by Dames and Moore, currently states that the rate issue would be addressed as The impacts to kWh rates will be assessed using the cost and benefit data resulting from the studies. The Project is being proposed by seven of the Railbelt Utilities (the IPG), all having differing rate structures. The cost of end use kWh rates for cach of the utilities is based on many factors which vary from utility to utility, and so to provide an overall Project assessment of rate impacts, the cost and benefit impacts of the Project on kWh rates will be calculated based on the overall system sales of kWh. - This is the wording that we worked out earlier this ycar to address this issue, and to include in the Scoping Report to explain how this issue would be addressed. An assessment of the rate impacts from the SIP is not currently a part of our scope of work. As we discussed last week, Decision Focus, Inc. (FI) would be a good choice to compictc this task, as they have most of the data required, and are well qualified to complete the ‘ gaalysis smd be Hated es a “Prepasee” in the ETS. We requested DFI to send us a letter proposal outlining their approach tn the analysis, and additional data requirements needed to compicte the analysis, We forwarded the above wording to them to describe the required scope of work, Attached is DFI’s proposed scope of work and budget. In addition to DFI’s scope, Power Engineers will require some time to incorporate DFT’s results into the EVAI.. BLY 23-373 & ath err \tt : 940 Gienbmok Dr, P.O! Bux 1066 Phone (208) 788-3456 SENT_BY: ~~ 6-87 5 10:33 ; POWER ENGIN. «S- 907 562 0027;# 3/ 6 ' ‘ } August 4, 1997 Page 2 " DFl has requested the following information to complete the analysis: Itern Party to supply data to DF Se en ard mnt Power Engincers Timing of Construction Expenditures Power Enginccrs Financing - Setis meciiaaoe ad diz datalis Germay Gk Chugach tobe incurred Wee tates (or in Won oP lax vais) wk apply Gn PG Chugach mexnber firms Accounting Rules applicahle tn Alaska utilities Chugach schedules, rules on AFUDC Any other pertinent information that DFI should know | Chugach ees Raeiiien seen eee oe _EWh data or above information DFI has estimated a cost to produce the required analysis of between $5000 and $10,000, and that they would executp the scope of work according to their letter proposal, on a time and txpense basis. If it mects with your approval, a not to exceed budget of $10,000 for D¥I to complete. the work is suggested. To coordinate this work and to incorporate the results into the EIS documentation, would require labor and expense on the part of Power Engineers of “$1200. ‘The cost of the work would be invoiced on a time and expense basis, with an overall et eel Nola oe Sis ak as eee: "ALY 23.373 aay se setae SENT BY: + 6-87; 10:34; PONER ENGID 8+ 907 562 0027; # 4/ 6 August 4, 1997 ~ Pages Since this work is in connection with preparation of thc EVAI. documentation, adding the approved amount to our Task 5 - Draft EIS is suggested. you for your consideration of this matter. Sincerely, POWER Engineers, Inc. Gat fea Randy Pollock, PE. Project Manager Enclosure _ 1p/RP BLY23-273 eet pears emt SENT BY: $- 6-87 + 10:34; POWER eee ye 807 562 0027;# 5/ 6 4, fe 76-25 - 35-422. FOCUS | hens INCORPORATED Corporane Office 650 Castro Sree, Suite 300 Mountain View, Califomia 94041-2055 415 960 3450 August 1, 1997 Power Engineers Incorporated 3940 Glenbrook Drive Hailey, ID 83333 . Dear Mike- This letter is in response to your inquiry regarding an assessment of how IPG utility rates will be impacted due to the Southern Intertie Project. . Steve Haas and my understanding is that you need us to prepare a spreadsheet and accompanying documentation showing these rate impacts, The spreadsheet would show rate impacts year-by-year for each of the next N years, where N is some number we would agree upor, a5 well as an average impact over this time. The project is being proposed by seven utilities, all having different rate structures, The cost of the end use kWh rates for each of the utilities is based on many factors which vary from utility to utility, 80 you would like us to calculate the overall impacts of the project on kWh rates based on the overall system sales in kWh. Our understanding is that you want us to examine only the change in the kWh rates due to the project (the deltas), not the absolute levels of these rates, The impact of the project on kWh rates would be equal to the capital costs (depreciation and rate of return) and maintenance cosis of the line, less the benefits to ratepayers in the form of reduced generation capatity additions (capital and maintenance), reduced transmission losses, reduced energy costs, and reduced spinning reserve costs, all divided by the kWh sales each year. The aggregate values of each of the ratepayer benefits will be based on the results of our We will need your assistance in providing information on cost estimates for the line (construction and maintenance), the timing of the construction expenditures, the financing (state assistance and the details on any debt to be incurred), and the tax rates (or ir-liew-of-tax rates) which apply to the IPG member firms. Also, any information you can provide on - accounting rules applicable to Alaska utilities, especially allowed rates of return, depreciation - 6-87; 10:35; — PORER ENGI™ .RS+ 907 562 0027:# 6/-6 Mr, Michael Walbert Page2 August 1, 1997 shel and radeon allowance fo fu ed sing consrsion wil nip make ou results more accurate. We would propose to perform the work on a time’and niaterials basis, We estimate the cost as being between $5,000 and $10,000 dollars, although, with your cooperation, we should be able . to keep it toward the low end of that range. Plewe give me acall at (45) 960-380 you hae any qunton, or want unto get tated We look forward to working with you. Sincerely, Hh, Aon. Sask accinsn | /lam cc: Steve Haas August 11, 1997 Matanuska Electric Association, Inc. P.O. Box 2929 Palmer, Alaska 99645 Attention: Mr. Wayne D. Carmony, General Manager Subject: Southern Intertie - EIS Preparation Rate Impact Assessment Dear Mr. Carmony: The rate impact of the proposed construction of the Southern Intertie has been an issue throughout the scoping process and needs to be addressed in the EIS. It is understood that impacts will vary among the participating utilities, but can probably be addressed by establishing a differential to given rates. POWER Engineers proposes to have DFI evaluate the impact in conjunction with the update of the Feasibility Study. We agree with that recommendation and enclose PEI’s letter and DFI’s offer to perform the services for about $11,000 for your approval. The project budget includes funds for this work. Please, indicate your approval by signing in the space provided and return the signed letter by facsimile. If you need any additional information, please, give our project manager Dora Gropp a call at 762-4626 or contact her by e-mail at dora_gropp@chugachelectric.com. CONCURRENCE: haf Mr. Wayne D. Carmony, General Man4ger CH IPG Tech AIDEA Lee Thibert Mike Massin Mark Fouts Brian Hickey JimBorden W.O. E9590081, Sec.2.1.2.1 RF 5601 Minnesota Drive * P.O. Box 196300 » Anchorage, Alaska 99519-6300 Phone 907-563-7494 * FAX 907-562-0027 AUG 15 w97 08/18/97 12:55. FAX 9074740549 UCS R L HUFMAN oor Hee CHUGACH ELECTRIC £6 kectric R ECEIVE D August 11, 1997 AUG 27 1997 Alaska Electric Generation & TRANSMISSION & Transmission Cooperative, Inc. SPECIAL PROJECT 1018 Galena Street Fairbanks, Alaska 99709 Attention: Mr. Robert Hufman, Executive Manager Subject: Southern Intertie - EIS Preparation Rate Impact Assessment wef The rate impact of the proposed construction of the Southern Intertic has been an issue throughout the scoping process and needs to be addressed in the EIS. It is understood that impacts will vary among the participating utilities, but can probably be addressed by cstabhshing a differential to given rates. POWER Engincers proposes to have DFI evaluate the impact in conjunction with the update of the Feasibility Study. We agree with that recommendation and enclose PET’s letter and DFI’s offer to perform the services for about $11,000 for your approval. The project budget includes funds for this work. Please, indicate your approval by signing in the space provided and return the signed letter by facsimile. If you need any additional information, please, give our project manager Dora Gropp a call at 762-4626 or contact her by e-mail at dora_gropp@chugachelectric.com. CONCURRENCE: Cede tHpror Us/97 Mr. Robert Huiman, Excditive Manager co IPG Tech AIDEA Lee Thibert Mike Massm MarkFouts Srian Hickey Jm Borden W.0_E9590081, Sec.2.J.2.1 RF 5601 Minnesota Drive = P.O. Box 196300 » Anchorage, Alaska 99519-6300 Phone 907-563-7494 * FAX 907-562-0027 08/18/97 MON 12:57 [TX/RX NN 52871 AUG 15 797 @3:@68PM GVEA ADMINISTRATION | , CHUGACH ELECTRIC fui Fa ASSOCIATION, INC. August 11, 1997 AUG 15 1997 Services Golden Valley Electric Association, Inc. eves Adan : P.O. Box 71249 Fairbanks, Alaska 99707 R ECEIVE D Attention: Mr. Michael P. Kelly, General Manager best Subject: Southern Intertic - EIS Preparation / 1997 Rate Impact Assessment TRANSMIS Dear The rate impact of the proposed construction of the Souther Intertie has been an issue throughout the scoping process and needs to be addressed in the EIS. It is understood that impacts will vary among the participating utilities, but can probably be addressed by establishing a differential to given rates. POWER Engineers proposes to have DFI evaluate the impact in conjunction with the update of the Feasibility Study. We agree with that recommendation and enclose PEI’s letter and DFI’s offer to perform the services for about $11,000 for your approval. The project budget includes funds for this work. Please, indicate your approval by signing in the space provided and return the signed letter by facsimile. If you need any additional information, please, give our project manager Dora Gropp a cal] at 762-4626 or contact her by e-mail at dora_gropp@chugachelectric.com. CONCURRENCE: Keb Renn — fax Mr. Michael P. Kelly, General Manager c: IPG Tech AIDEA Lee Thibert Mike Massin Mark Fouts Brian Hickey JimBorden W.O. E9590081, Sec.2.1.2.1 RF 5601 Minnesota Drive » P.O. Box 196300 « Anchorage, Alaska 99519-6300 Phone 907-563-7494 * FAX 907-562-0027 @9-@2-1997 @8:3@AM FROM Seward Engr & Utilities TO 19875620027581 P.@1 ~ CHUGACH ELECTRIC ) pe ASSOCIATION, INC. August 11, 1997 ee) erm Division RECEIVED Seward, Alaska 99664 nue is WD 7 Attention: Mr. Dave Chlvert, Utility Manager “SENAR Subject: Southern Infertic - EIS Preparation Rate Impact] Assessment CNN FF <a funy Mr, Dave Calvert, Utility Manager 8-29-37 c: IPG Tech EA Lee Thibert Mike Massin Mark Fouts Brian Hickey JimBorden W.Q, E9590081, Sec.2.1.2.1 RF * eget® 5601 Minnesota Drive » RO. Box 196300 »* Anchorage, Alaska 99519-6300 Phone 907-563-7494 * FAX 907-562-0027 TOTAL P.@1 09/02/97 TUE 09:41 [TX/RX NO 6161)