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Home My WebLink AboutS Intertie report 8-1997 crema gach ASSOCIATION, INC. P.O. BOX 196300 ANCHORAGE, AK 99519-6300 CHUGACH ELECTRIC ASSOCIATION, INC. —~(F >} —<—_ lectric PD) ECEIVE LN sUu 2 § 1997 Alaska Industrial Development Alaska Industrial Development and Export Authority and Export Authority 480 West Tudor Road Anchorage, Alaska 99503-6690 August 28, 1997 Attention: Mr. Randy Simmons, Executive Director Subject: Southern Intertie Monthly Report for August 1997 W.0.#E9590081 Dear Mr. Simmons: Please find enclosed 1 (one) copy of the Southern Intertie Report for the Month of August 1997. If there are any questions, please contact Dora Gropp, (907) 762-4626. Sincerely, Eugene N. Bjornstad General Manager ENGIDGG:ah Enclosures: 1 (one) copy of Southern Intertie Monthly Report c: Lee Thibert Joe Griffith Michael Massin Dora Gropp John Cooley Mike Cunningham Don Edwards W.0.#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 AUGUST 1997 Report for the Month of August 1997 W.0.#E9590081 Southern Intertie - Phase IB August 28, 1997 TABLE OF CONTENTS Page I. SWIMM RY iter oor or or or of of of elreorey ct or ot ey of of of cl cb ob ool eb opens) of oe) op renep ey sueecl ey hele I-1 I. NANG A Drove o cre otro ot oloo olor on orres oh o1/0) 6101 a1 oll oirol ol siiclisiccleliol eit leltonen elise oie I-1 = = IE Total Project Expenditures as of June through July 1997 os Chugach Statement for June and July 1997 3% Bank Statement of July 1997 SCHEDULE 6 ore ce wriee see me rricinee sere errs ec en Ii-1 ITEMS FORZAPPROVADL.. .. «0c oc ek seine werent ereree IV-1 is Add Rate Impacts to DFI Study (letter of August 11,1997) ITEMS FOR DISCUSSION .... 0... cc ccccccccrcccrrccccccccscs V-1 16 Selection of Proposed Alternative (letter of August 14,1997) ITEMS FOR INFORMATION .... 2... ee ee eee eee eee eee eens VI-1 i POWER Engineers’ Monthly Report Phase IB - Environmental Analysis, August 15, 1997 AML&P Letter of July 31,1997 CEA response to AML&P dated August 18, 1997 HEA Letter to RUS of August 12,1997 Draft Update of DFI Study wR WN ii Report for the Month of August 1997 W.0.#E9590081 Southern Intertie - Phase IB August 28, 1997 SUMMARY The Agency MOU has been executed and several state agencies as well as the Municipality of Anchorage have expressed interest in actively participating in the EIS preparation. RUS has requested that we allow them to hire a “third party consultant” to assist them in timely completion of the EIS and HEA has authorized the process (see Section VI). We expect that RUS will have their consultant under contract by September 1997. The Scoping Report (draft) is still awaiting final review by the lead and cooperating federal agencies. The Quartz Creek route has been deleted from the EIS effort with the concurrence of all but one IPG member. AML&P’s concerns are summarized in their letter of July 31,1997 included in Section VI. A draft of the cost/benefit study of 1990 has been received from DFI and is under review. The benefits of the project are lower than predicted in 1990. This is primarily attributable to lower than anticipated fuel costs and the higher discount rate used for the analysis. Possible benefits from BESS or SMES systems have not been taken into account. We are evaluating the merits of adding these to the analysis. NERC has agreed to review the 1990 reliability assessment of the Railbelt electric system. Both updates should be available by the end of August. IPG member technical staff met with the NERC Reliability Subcommittee on July 25,1997 in Seattle to discuss system operations. Community Working Group meetings were held on July 21,1997 (Kenai) and July 23, 1997 (Anchorage). The Kenai group reacted favorably to the recommended deletion of the Quartz Creek Route. In Anchorage discussions focused on possible alignments for the ENSTAR and TESORO routes in the Anchorage area. The group went on a field trip on August 6,1997 to enhance their understanding of siting problems for transmission lines. 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 67% completion compared to 79% planned. The Environmental Analysis (EVAL) is now estimated to be completed in October 1997. At that time the IPG will have to select the alternative it wishes to propose (see letter of August 14, 1997 in Section V). DESCRIPTION BUDGET ALLOCATED CONTINGENCY TOTAL AMENDMENTS TOTAL COMMITMENT SPENT TO DATE % OF TOTAL Report for the Month of August 1997 Southern Intertie - Phase IB POWER USFS/USFWS | CHUGACH TOTAL ENGINEERS $3,043,423.00 | $100,000.00 $3,543,423.00 $156,295.30 $10,000.00 $40,000.00 $206,295.30 $3,199,718.30 $110,000.00 $3,749,718.30 6807.0 480470 $3,347,765.30 $110,000.00 | $440,000.00 | $3,897,765.30 W.0.#E9590081 August 28, 1997 $2,149,174.00 $41,754.00 $89,237.00 | $2,280,165.00 37.96% 64.20% 20.28% 58.50% Total Project expenditures as of 8/18/97 are $3,104,437 1-2 Report for the Month of August 1997 W.0.#E9590081 Southern Intertie - Phase IB August 28, 1997 Il. FINANCIAL ile Total Project Expenditures as of June through July 1997 De Chugach Statement for June and July 1997 5 Bank Statement of July 1997 II-1 Project Expenditures Direct Labor Indirect Labor Power Engineers Miscellaneous Total Grant Fund Expenditures Direct Charges that Chugach has been Reimbursed for Plus General, Administrative & Construction Overhead Total Amounts Paid to Chugach CHUGACH ELECTRIC ASSOCIATION, INC. Southern Intertie Transactions R ECEIVE D Inception Through June 30, 1997 AUG 0 7 997 TRANSMISSION & Year to Date Month SPECIAL PROJECT Through Through Ended Inception 12/31/96 5/31/97 6/30/97 Through 6/30/97 $68,678.93 $18,284.82 $840.41 $87,804.16 23,471.09 7,090.97 354.76 30,916.82 1,918,877.36 507,946.30 150,790.95 2,577,614.61 30,326.81 30,934.76 6,800.00 68,061.57 $2,041,354.19 $564,256.85 $158,786.12 $2,764,397.16 Month Month Through Ended Ended Inception 12/31/96 5/31/97 6/30/97 Through 6/30/97 $1,433,087.47 $847,946.42 $165,814.35 (1) $2,446,848.24 7,165.42 4,239.74 829.07 (1) 12,234.23 $1,440,252.89 $852,186.16 $166,643.42 (1 $2,459,082.47 (1) Chugach May 29, 1997 invoice for April, 1997 charges. Project Expenditures Direct Labor Indirect Labor Power Engineers Miscellaneous Total Grant Fund Expenditures Direct Charges that Chugach has been Reimbursed for Pius General, Administrative & Construction Overhead Total Amounts Paid to Chugach a ECEIVE D CHUGACH ELECTRIC ASSOCIATION, INC. Southern Intertie Transactions AUG 2 2 1997 Inception Through July 31, 1997 TRANSMISSION SPECIAL PROJECT Year to Date Month Through Through Ended Inception 12/31/96 6/30/97 7/31/97 Through 7/31/97 $68,678.93 $19,125.23 $2,799.85 $90,604.01 23,471.09 7,445.73 1,061.96 31,978.78 1,918,877.36 658,737.25 149,768.29 2,727,382.90 30,326.81 37,734.76 529.05 68,590.62 $2,041,354.19 $723,042.97 $154,159.15 $2,918,556.31 Month Month Through Ended Ended Inception 12/31/96 6/30/97 7/31/97 Through 7/31/97 $1,433,087.47 $1,013,760.77 $158,762.80 (1) $2,605,611.04 7,165.42 5,068.81 793.81 (1) 13,028.04 $1,440,252.89 — $1,018,829.58 $159,556.61 iu ) $2,618,639.08 (1) Chugach June 30, 1997 invoice for May, 1997 charges. CHUGACH ELECTRIC ASSOCIATION, INC. Anchorage, Alaska August 6, 1997 R ECEIVE D AUG 07 $997 Sree BS TO: Dora Gropp - Manager, Transmission & Special Projects FROM: Kimberly Pond, Plant accountant SUBJECT: 9590081 - Southem Intertie Route Selection Study You had previously requested establishment of this work order to study route selection for the Southem Intertie for the Intertie Participants Group. The Association will be reimbursed for charges to this work order. The following charges occurred during June 1997. Direct Labor 840.41 Indirect Labor 354.76 Power Engineers Invoice # 45122 (7,434.42) Power Engineers Invoice # 45123 15,815.18 Power Engineers Invoice # 45124 59,149.77 Power Engineers Invoice # 45125 34,763.84 Power Engineers Invoice # 45126 29,404.91 Power Engineers Invoice # 45127 439.57 Power Engineers Invoice # 45128 7,640.18 Power Engineers Invoice # 45129 ’ 11,011.92 U.S. Fish & Wildlife Service Contract 97-193 6,800.00 Sub-Total $158,786.12 General, Administrative & Construction Overhead (0.5%) 793.93 Total Charges $159,580.05 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. Concur: dove, £- Lop , d on KP/kp WOfiles/E9590081 Attachments CHUGACH ELECTRIC ASSOCIATION, INC. Anchorage, Alaska August 21, 1997 TO: Dora Gropp - Manager, Transmission & Special Projects FROM: Kimberly Pond, Plant Accountant fod 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 July 1997. Direct Labor 2,799.85 Indirect Labor 1,061.96 Power Engineers Invoice # 45739 1,037.27 Power Engineers Invoice # 45740 1,302.29 Power Engineers Invoice # 45741 73,789.74 Power Engineers Invoice # 45742 27,022.83 Power Engineers Invoice # 45743 13,990.74 Power Engineers Invoice # 45744 5,855.00 Power Engineers Invoice # 45745 7,509.67 Power Engineers Invoice # 45746 19,260.75 Dora Gropp's Expenses 107.30 Travel Advance 300.00 Guido's Pizza Invoice 166705 121.75 Sub-Total $154,159.15 General, Administrative & Construction Overhead (0.5%) 770.80 Total Charges $154,929.95 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. Concur: bora Z Poy 5 [97 Signature Date KP/kp ‘ WOfiles/E9590081 Attachments Southern Intertie Grant Fund Bank Account Activity Summary July, 1997 June Ending Balance forward Total Deposits Total Withdrawals (Chugach invoice for May charges) Interest Earned Balance July 31, 1997 $1,232,844.41 $283,474.00 ($159,556.61) $6,164.85 $1,362,926.65 @® CHECKING ACCOUNT STATEMENT First National Bank —_— eee ts Account Number: 0110 606 1 enn ae Prepared After the Close Of Business On: JUL 31 1997 Pog: 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 1 CYCBI osc 5961 PREVIOUS BALANCE AS OF 06/30/97 $.00 Service Charge This Month $.00 45 Deposits & Other Credits $30,240, 162.80 Interest Paid This Month $.00 23 Checks and Other Debits $30,240, 162.80 CURRENT BALANCE AS OF 07/31/97 $.00 SSSR SESSS— Made seenenaSsasa———e=HSs— Daily Account Balance Summary --------------------------------------- Balance Date Balance Date Balance Date Balance Date -00 07/01 -00 07/10 -00 07/18 -00 07/28 -00 07/02 -00 07/11 -00 07/21 -00 07/29 -00 07/03 -00 07/14 -00 07/22 -00 07/30 -00 07/07 -00 07/15 -00 07/23 -00 07/31 -00 07/08 -00 07/16 -00 -00 07/09 -00 07/17 00 cs--------- Other Credits Amount Date Description 283,474.00 07/01 INCOMING WIRE TRANSFER - 1,232,844.41 07/01 REPO CREDIT 181.84~ 07/01 REPO INTEREST 1,516,500.25 07/02 REPO CREDIT 223.68 ~ 07/02 REPO INTEREST 1,357, 167.32 | 07/03 REPO CREDIT 200.18 07/03 REPO INTEREST 1,357,367.50 07/07 REPO CREDIT 800.85 ~ 07/07 REPO INTEREST 1,358, 168.35 07/08 REPO CREDIT 200.33 ” 07/08 REPO INTEREST 1,358,368.68 07/09 REPO CREDIT 194.32 07/09 REPO INTEREST 1,358,563.00 07/10 REPO CREDIT 194.35 07/10 REPO INTEREST 1,358, 757.35 07/11 REPO CREDIT 194.38 07/11 REPO INTEREST 1,358,951.73 07/14 REPO CREDIT 583.22 ~ 07/14 REPO INTEREST 1,359,534.95 07/15 REPO CREDIT 197.89 07/15 REPO INTEREST 1,359,732.84 07/16 REPO CREDIT 197.92 07/16 REPO INTEREST 1,359,930.76 07/17 REPO CREDIT 197.95 07/17 REPO INTEREST 1,360, 128.71 07/18 REPO CREDIT 197.97 07/18 REPO INTEREST 1,360,326.68 07/21 REPO CREDIT 594.01 ~ 07/21 REPO INTEREST 1,360,920.69 07/22 REPO CREDIT 200.36 07/22 REPO INTEREST 1,361,121.05 07/23 REPO CREDIT 200.39 07/23 REPO INTEREST 1,361,321.44 07/24 REPO CREDIT ~ CHECKING ACCOUNT STATEMENT Account Number: 0110 606 1 Prepared After the Close Of Business On: JUL 31 1997 Pog: 2 OF 3 CHUGACH ELECTRIC ASSOCIATION INC 1 CYCBI O8c 5961 wane n ne nnn nnn nn nnn n neo --- 2-2 -- wno-n------ Other Credits --------------------- 22-2 nn nnn nn nnn ene nee Amount Date Description 200.42 .~ 07/24 REPO INTEREST 1,361,521.86 07/25 REPO CREDIT 200.45 ~ 07/25 REPO INTEREST 1,361,722.31 07/28 REPO CREDIT 601.43 ~ 07/28 REPO INTEREST 1,362,323.74 07/29 REPO CREDIT 200.94 - 07/29 REPO INTEREST 1,362,524.68 07/30 REPO CREDIT 200.97 ~ 07/30 REPO INTEREST 1,362,725.65 07/31 REPO CREDIT 201.00 ~ 07/31 REPO INTEREST meer err een scccnnn-- ee eee roe reenneseereern= OCI) DE nn ee ee a) ao Amount Date Description 1,516,500.25 07/01 REPO DEBIT 159,556.61 07/02 DEBIT MEMO(TC6O) 1,357, 167.32 07/02 REPO DEBIT 1,357,367.50 07/03 REPO DEBIT 1,358, 168.35 07/07 REPO DEBIT 1,358,368.68 07/08 REPO DEBIT 1,358,563.00 07/09 REPO DEBIT 1,358,757.35 07/10 REPO DEBIT 1,358,951.73 07/11 REPO DEBIT 1,359,534.95 07/14 REPO DEBIT 1,359,732.84 07/15 REPO DEBIT 1,359,930.76 07/16 REPO DEBIT 1,360, 128.71 07/17 REPO DEBIT 1,360,326.68 07/18 REPO DEBIT 1,360,920.69 07/21 REPO DEBIT 1,361,121.05 07/22 REPO DEBIT 1,361,321.44 07/23 REPO DEBIT 1,361,521.86 07/24 REPO DEBIT 1,361,722.31 07/25 REPO DEBIT 1,362,323.74 07/28 REPO DEBIT 1,362,524.68 07/29 REPO DEBIT 1,362,725.65 07/30 REPO DEBIT 1,362,926.65 07/31 REPO DEBIT Starting June 28, you can bank at our South Center Branch on Saturdays. The branch (at 36th and c street) will be open Saturdays from 12 to 4 pm. Oo CHECKING ACCOUNT STATEMENT SDT MAE USCCB ar Lil Uae Account Number: 0110 606 1 Neer te Prepared After the Close Of Business On; JUL 31 1997 Pe 3 of 3 CHUGACH ELECTRIC ASSOCIATION INC 1 CYCBI o8C 5961 CHARGE ADVICE OF. -HARC —_——— “TWIS 5S TO ADVISE YOU THAT ON THIS DATE _7-02-37_ WE HAVE CIIARGED YOUR ACCOUNT AT THIS DANK FOR THE FOLLOWING REASON: TRANSFER TO GENERAL ACCOUNT 0110-675-1 eamealaiaate —TAABSTER To GENERAL accouyr oe __ OL1soeost a CUUGACH ELECTRIC ASSOCIATION, IRC. 199,886.1 2 py $ 99,356.61 O10028956 C024 0G PDO 2050Gie SS003060 26 Serialf 8 “$159,556.61 Report for the Month of August 1997 W.0.#E9590081 Southern Intertie - Phase IB August 28, 1997 il. SCHEDULE Iil-1 Report for the Month of August 1997 W.0.#E9590081 Southern Intertie - Phase IB August 28, 1997 IV. ITEMS FOR APPROVAL 1. Add Rate Impacts to DFI Study (letter of August 11,1997) CHUGACH ELECTRIC I eee AM Geek kectric ASSOCIATION, INC. August 11, 1997 Alaska Electric Generation & Transmission Cooperative, Inc. 1018 Galena Street Fairbanks, Alaska 99709 Attention: Mr. Robert Hufman, Executive Manager Subject: Southern Intertie - EIS Preparation Rate Impact Assessment Dear vw hs 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. SinC¢rely, CONCURRENCE: ugene N. General ger Mr. Robert Hufman, Executive Manager gn ENB cahw Enclosures: 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 Report for the Month of August 1997 W.0.#E9590081 Southern Intertie - Phase IB August 28, 1997 V. ITEMS FOR DISCUSSION 1 Selection of Proposed Alternative (letter of August 14,1997) CHUGACH ELECTRIC hs ASSOCIATION, INC. ‘aS niga ASSOCIATION, INC. August 14, 1997 Alaska Electric Generation & Transmission Cooperative, Inc. 1018 Galena Street Fairbanks, Alaska 99709 Attention: | Mr. Robert Hufman, Executive Manager Subject: Southern Intertie - EIS Preparation Selection of Proposed Alternative Dear Mr. Hufman: The delays encountered in executing the MOU between the federal agencies and RUS’ need for a third party preparer of the EIS have delayed the overall schedule for this project by about 3 to 4 months. Our consultants, Power Engineers and Dames and Moore, estimate now that the Draft Environmental Analysis (EVAL) will be completed in early October of this year. This draft will include the “environmental preference”, but not the Applicant’s proposed action. Prior to submitting the EVAL to RUS the IPG will have to select it’s “Proposed Alternative”. This alternative may or may not be the same as the “environmental preference” . We would like to suggest that the technical representatives of the IPG for the project get together to discuss all options after the draft EVAL is available and prepare a recommendation for the proposed action. The consultants could then make a presentation to the IPG prior to finalizing the EVAL which will incorporate the proposed alternative. If the proposed alternative involves lands in the Kenai Wildlife Refuge a permit application under ANILCA will have to be prepared at that time and submitted to USFWS. This application triggers that agency’s permit/EIS process which dictates the time frame to a Record of Decision (ROD) in 1999. 5601 Minnesota Drive * P.O. Box 196300 » Anchorage, Alaska 99519-6300 Phone 907-563-7494 * FAX 907-562-0027 Southern Intertie - EIS Preparation - Selection of Applicant’s Proposed Alternative August 14, 1997 . Page 2 of 2 The following tentative dates are anticipated for the various events: Draft EVAL available October 13, 1997 Technical Committee Review October 22 or 23, 1997 Consultant’s presentation to IPG and IPG approval of “Applicant’s Proposed Alternative” November 4, 1997 Complete and Submit ANILCA Application November 10, 1997 Submit Final EVAL to RUS November 17, 1997 Please, let me or our project manager Dora Gropp know, if any of the above dates present a conflict for you, so that we can attempt to find a mutually acceptable time frame for the necessary actions. 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. Sincerely, Sno et Eug General Manager thos ENB/IALG:tjh Cs IPG Tech AIDEA ' MEM Lee Thibert Don Edwards Brian Hickey Jim Borden John Cooley W.O. E9590081, Sec.2 RF Report for the Month of August 1997 W.0.#E9590081 Southern Intertie - Phase IB August 28, 1997 VI. ITEMS FOR INFORMATION Me POWER Engineers’ Monthly Report Phase IB - Environmental Analysis, August 15, 1997 AML&P Letter of July 31,1997 HEA Letter to RUS of August 12,1997 CEA response to AML&P dated August 18, 1997 Draft Update of DFI Study Se VI-1 OS DOME August 15, 1997 i ECEIVE D JENGINEERS AUG 18 4997 Ms. Dora Gropp Chugach Electric Association TRANSMISSION & 5601 Minnesota Drive, Building A SPECIAL PROJECT Anchorage, AK 99518 Subject: POWER Project #120376 EIS & Preliminary Engineering Chugach Contract #95-208 Monthly Status Report No. 14 For Period July 13, 1997 - August 9, 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 The Memorandum of Understanding has been signed. e Coordination with Rural Utilities Service (RUS) and cooperating agencies regarding Project issues. e RUS third party Preparer needs to be formally hired by RUS (RUS responsibility) Invoice Period Overview: visual resources field review of new alternative routes. overflight of remaining alternatives for biological resources. aerial reconnaissance of submarine transition station. prepared materials and conducted Community Working Group (CWG) Meeting #4. visual resources field verification of initial impacts. met with the Municipality of Anchorage regarding undergrounding. prepared draft mitigation measures for review. met with the ADF&G regarding Anchorage Coastal Wildlife Refuge. conference call with ADF&G, USFWS, and USFS to discuss brown bear impacts. continued initial impact assessment. reviewed scope of work for third party Preparer. prepared recommendation for elimination of alternative routes. documented alternative route screening process. completed initial draft of Chapter 3 for all resources. review of Chapter 3 text. : draft of the cost - benefit update was submitted. incorporating comments on the Draft Supplemental Studies Report. continued work on preliminary engineering. PEI-HLY 23-281 POWER Engineers, Incorporated 0 LLL 3940 Glenbrook Dr. * P.O. Box 1066 Phone (208) 788-3456 Hailey. Idaho 83333 Fax (208) 788-2082 Chugach Electric Association August 15, 1997 Page 2 Work Planned for the Next Invoice Period: finalize work plan and project schedule with agencies. finalize and distribute scoping report. continue additional field inventory as necessary. finalize inventory maps and associated data tables. finalize initial impacts and review. assign mitigation measures. conduct CWG field trip in Anchorage area. assess residual impacts for each resource. finalize route selection criteria. continue alternative screening process. begin comparison of remaining routes. continue development of Chapters 1, 2, and 4 for EVAL. continue work on preliminary engineering. issue final engineering system studies report. complete Draft Cost Estimate Summary Report. issue the final report for the cost - benefits update. Schedule: 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 September before RUS has Mangi under contract. 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: PEI-HLY 23-281 +) owes <a Chugach Electric Association August 15, 1997 Page 3 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 e Working Session with IPG Technical Committee to discuss Project alternatives and the Draft EVAL e Presentation of Project Alternatives to the IPG November 4, 1997 ** e Complete and submit ANILCA Application November 10, 1997 e Submit Final EVAL to RUS November 17, 1997 ** Proposed dates, subject to IPG availability. October 13 to November 4, 1997 October 22 or 23, 1997 ** 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 has 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. During the next two reporting periods, 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. PEI-HLY 23-281 #) “MER ese Chugach Electric Association August 15, 1997 Page 4 Task 4 - Alternative Selection Refer to Tasks 1-5 comment. Task 5 - Draft EIS Refer to Tasks 1-5 comment. Task 6 - Final EIS No action. Task 7 - Studies The Final Supplemental Studies Report will be issued in August. Task 8 - Engineering Field Work Additional field investigations will be performed as required to support environmental activities. Task 9 - Preliminary Engineering The draft Cost Estimate Summary Report will be prepared and issued in August. Project Overview: Total Budget $3,191,469 Actual $ Expended (to date) $2,149,174 Actual Remaining Project Budget $1,042,295 Dora, should you have any questions about this report or any of the backup, please do not hesitate to contact me or Mike Walbert. MW/rth ce: PROJECT TEAM PEI-HLY 23-281 Sincerely, POWER Engineers, Inc. Randy P6fiock, P.E. Project Manager gown SOUTHERN INTERTIE ROUTE SELECTION STUDY - PHASE 1 120376-01 PROJECT FINANCIAL SUMMARY AUGUST, 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 $365,824 N/A $679,591 $612,929 N/A $606,612 $449,465 N/A $336,341 $64,431 $45,000 $452,474 $48,387 N/A $247,616 $0 N/A $101,480 $67,540 N/A $202,655 $190,652 N/A $189,861 $113,360 $45,000 $3,191,469 $1,912,588 Current Invoice Amount $580 $10,970 $97,136 $46,260 $44,991 $0 $3,299 $14 $33,336 $236,586 Actual Budget Expended Through Current Invoice $366,404 $623,899 $546,601 $110,691 $93,378 $0 $70,839 $190,666 $146,696 $2,149,174 Remaining Budget PEI-HLY 23-281 $8,435 $55,692 $60,011 $225,650 $359,096 $247,616 $30,641 $11,989 $43,165 $1,042,295 AUGUST 1997 INVOICE ACTIVITIES SUMMARY TASK 1 - SCOPING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Scoping e reviewed scope of work for third-party contractor. e finalize work plan and project schedule. e finalize and distribute scoping report. 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 374,839 366,404 8,435 SCOPE: No outstanding issues. HLY 23-281bk 1 AUGUST 1997 INVOICE ACTIVITIES SUMMARY TASK 2 - INVENTORY DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Inventory visual resources field review of new alternative routes. overflight of remaining alternatives for biological resources. aerial reconnaissance of submarine transition station. continue additional field inventory as necessary. finalize inventory maps and associated data tables. 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 679,591 623,899 55,692 SCOPE: No outstanding issues. HLY 23-281bk iz AUGUST 1997 INVOICE ACTIVITIES SUMMARY TASK 3 - IMPACT ASSESSMENT/MITIGATION PLANNING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Impact Assessment / |e prepared materials and conducted CWG meeting Mitigation Planning #4 in Cooper Landing/Anchorage. visual resources field verification of initial impacts. met with the Municipality of Anchorage (MOA) planning department regarding undergrounding. prepared draft mitigation measures for review. met with the Alaska Department of Fish and Game (ADF&G) regarding Anchorage Coastal Wildlife Refuge. conference call with ADF&G, USFWS, USFS to discuss brown bear impacts. continued initial impact assessment for land use, recreation, biology, cultural, geology, visual, and socioeconomics. finalize initial impacts and review. assign mitigation measures. conduct CWG field trip in the Anchorage area. assess residual impacts for each resource. 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 606,612 546,601 60,011 SCOPE: No outstanding issues. HLY 23-281bk 3 AUGUST 1997 INVOICE ACTIVITIES SUMMARY TASK 4 - ALTERNATIVE SELECTION DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Alternative Selection e prepared recommendation for elimination of alternative routes. documented alternative route screening process. finalize route selection criteria. continue alternative screening process. KEY ISSUES: SCHEDULE: BUDGET: SCOPE: HLY 23-281bk begin comparison of remaining routes. No outstanding issues. No outstanding issues. Contract Amendment No. 4 is included in the budget ($303,475 + $32,866 = $336,341). $ Budgeted $ Expended $ Remaining 336,341 110,691 225,650 No outstanding issues. AUGUST 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 23-281bk Draft EIS completed initial draft of Chapter 3 for all resources. review Chapter 3 text. draft of the cost - benefit update was submitted. issue the final report for the cost - benefits update. continue development and review of Chapters 1, 2, and 4. No outstanding issues. No outstanding issues. Contract amendments No. 4 and No. 5 are included in the budget ($402,570 + $4,904 + $45,000 = $452,474). $ Budgeted $ Expended $ Remaining $452,474 93,378 359,096 No outstanding issues. AUGUST 1997 INVOICE ACTIVITIES SUMMARY ’ TASK 6 - FINAL EIS DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Final EIS e no action. KEY ISSUES: No outstanding issues. SCHEDULE: No outstanding issues. BUDGET: No outstanding issues. $ Budgeted $ Expended $ Remaining 247,616 00 247,616 SCOPE: No outstanding issues. HLY 23-281bk 6 AUGUST 1997 INVOICE ACTIVITIES SUMMARY TASK 7 - STUDIES DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS KEY ISSUES: SCHEDULE: BUDGET: SCOPE: HLY 23-281bk Studies e Incorporate comments into final Studies Report. Complete EMF, Inductive Coordination, and Cathodic Protection Studies. No outstanding issues. The final Supplemental Studies Report will be issued in August. No outstanding issues. $ Budgeted $ Expended $ Remaining 101,480 70,839 30,641 No outstanding issues. AUGUST 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 23-281bk 8 AUGUST 1997 INVOICE ACTIVITIES SUMMARY TASK 9 - PRELIMINARY ENGINEERING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS KEY ISSUES: SCHEDULE: BUDGET: SCOPE: HLY 23-281bk Preliminary Engineering |e Continued work on preliminary design and cost estimates for overhead lines, submarine cables and substations. e prepare and distribute for review the draft cost estimate report. No outstanding issues. The draft Cost Estimate Report will be submitted in August. No outstanding issues. $ Budgeted $ Expended $ Remaining 189,861 146,696 43,165 No outstanding issues. 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% oo) GES SEY «125 : 3 FILE NOTICE OF INTENT WITH 10/9/96 | 10/10/96] 100% a ian FEDERAL REGISTER 4 MOU AND WORKPLANWITHCO | _—-11/6/96| 3/31/97| 100% LEAD AGENCIES 116 | 3/31 6 FILEADDENDUMTONOTICEOF | 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 EE 3/30 9 PUBLIC/AGENCY SCOPING | 11/76/96 | 11/14/96| 100% MEETINGS - INITIAL INTERAGENCY | | 416 1414 "1 PREPARE MATERIALS/DEVELOP | 7/15/96 10/25/96| 100% — 715 EE 10/25 13 FINALIZE ALTERNATIVES AND FIELD | 6/24/96| 10/11/96] 100% REVIEW | | | + 6/24 EE 10/11 15 DRAFT SCOPING REPORT 11/14/96 | 2/14/97; 100% | | | RECS 7 | AGENCY COMMENTS | atai97|4/11/97| 100% ie au 19 FINALIZE SCOPING REPORT | anitie7| 4/25/97/ 95% 34 att | | | | 21 TASK 2 INVENTORY Git | 911297 91% ant Bb 4/25 | | : 22 "INVENTORY ALTERNATIVES | alii 2/28/97 | 100% CS cc a | | ; 24 | CONDUCT FIELD REVIEW AND [6/11/96 | 3/31/97| 100% ( ze 22: AGENCY CONTACTS 3 26 AGENCY FIELD RECONAISANCE 6/2/97 | 6/6/97| 75% ee 27 | DATA 8/13/96| 9/12/97| 80% MANAGEMENT/DOCUMENTATION | | 62 @H ce : i pe eprint NT [SheAS ERNE ANPRAIESER CT SURVEYS AND DOCUMENTATION | 813 ' site 3 TASK 3 IMPACT ASSESSEMENT AND 7122196| 8/1/97| 83% MITIGATION PLANNING | 421 NE 6/27 32 DEVELOP PROJECT | 7/22/96| 5/2197| 90% DESCRIPTION/LOCATION | | 7/22 | Dc anes NR aa RT TI METI J 34 DEVELOP IAMP APPROACHAND | 10/21/96| 5/2/97 95% CRITERIA 722 RSs aR 52 36 AGENCY REVIEWAND APPROVE | 5/5/97| 5/23/97] 90% | 10/21 5/2 37 CONDUCT INITIAL IA/MP 2/3/97| 6/6/97| 70% 9 5/5 5/23 39 AGENCY REVIEW AND APPROVE 6/9/97| 6/27/97| 75% POWER Engineers, Inc. Summary F__ B® SCOMiilestone = Task EGE Percent Compete Project: 120376-01 Revision #3 (0920 08/09/97 PROJECT SCHEDULE SOUTHERN INTERTIE PROJECT EIS Peninsula Transmission Line 1996 1997 1998 1999 1D | 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 “1 FINALIZE IAIMP/DOCUMENTATION | @30/97 | 7/1197 0% 6/30 M711. 43 AGENCY REVIEW AND APPROVE 7A4I97| B/197| 10% 45 TASK 4 ALTERNATIVE COMPARISONS | 12/16/96| 8/1/97| 18% i | | 26 Bt 46 DEVELOP ENVIRONMENTAL | 1216/96| 5/9/97| 25% i SELECTION CRITERIA | | 1216 a s/o 48 AGENCY REVIEW AND APPROVE 5/12/97| 5/30/97| 10% | 512 OH 5:30 49 CONDUCT ENVIRONMENTAL 5/12/97| 6/27/97| 25% ALTERNATIVE COMPARISONS | 512 EE 6/27 51 AGENCY REVIEW AND APPROVE 5/12/97| 7/18/97, 10% i | 512 7/18 53 PREFFERED ALTERNATIVE | 6/30/97| 7/25/97} 10% : | _ SELECTION | | 6/30 HB 7/25 55 | APPLICANTS PROPOSED 718/97 8/1/97| 0% : ALTERNATIVE [56 | TASKS DRAFTEIS 12/10/96 | 10/5/98, 16% 718 OH 3 | 12/1 ad 57 DEVELOP PURPOSE AND NEED 116/97 | 6/27/97 75% . F 1085 59 PREPARE PDEIS 12/10/96 | 8/29/97| 15% 1; I 627 61 AGENCY REVIEW 91/97| 103/971 0% 121) aS eae aaIENED « <2 | 3 63 | PREPARE ANILCA APPLICATION 8/1/97| 10/6/97 0% 91 EEE 103 [64 | PREPARE DEIS 10/16/97 | 11/14/97, 0% at OF 1016 | 66. | _ FILE ANILCAAPPLICATION 10/3/97| 10/3/97 0% 406 BM 1414 67 ANILCA REVIEW 10/3/97 10/5/98| 0% i | | » 103 F 10/3 68 PRINT DEIS | 11/24/97 | 12/19/97| 0% : | | | : 103 & WD i105 70 FILE DEIS WITH EPA 1/5/98| 1/5/98| 0% 41124 HE 12/19 | 71 DISTRIBUTE | tareae7| 116/98) 0% | | oO 115 73 PUBLIC REVIEW | 4598] 2/19/98) 0% | 1222 HB 16 75 FEDERAL HEARING | 1/5/98 | 2/19/98| 0% | | 15 HE 219 77 TASK 6 FINAL EIS | 2/23198| 5/20/99 0% | POWER Engineers, Inc. Summary B® OMilestone > Task HGP eccent Compete Project: 120376-01 Revision #3 (0920 : 08/09/97 PROJECT SCHEDULE SOUTHERN INTERTIE PROJECT EIS Proposed Anchorage to Kenai | | : s = e | | Peninsula Transmission Line | . 1996 1997 | 1993 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% 2/23 HE 3/20 | | = 80 PREPARE PRELIMINARY FEIS | 32398| 4/17/98) 0% 323 M417 82 AGENCY REVIEW AND APPROVE 4/20198| 5/8/98| 0% | 4720 HE ss 34 | PREPARE FEIS 5/11/98| 5/29/98| 0% | | 5/11 [EB 5/29 a6 | AGENCY REVIEW AND APPROVE 6/1/98| 6/12/98| 0% | | | | 6 612 88 PRINT 6/15/98| 6/26/98) 0% | | 61s Ei 6/26 [90 | FILE FEIS WITH EPA 7/3/98| 7/3/98) 0% | | ; 1 | DISTRIBUTE 6/15/98| 7/3/98, 0% om a 6/15 713 93 PUBLIC REVIEW 7/3/98| 8/2/98 0% @ | [95 RECORD OF DECISION 10/5/98| _2/5/99| 0% 73 GM 8/2 [97 | APPEAL PERIOD 2/5199| 5/20/99 0% 10/5 ay 2/5 | 98) TASK7 STUDIES 12/15/96 | 7/18/97; 95% =] ps i08 De | | i | 100 | BENEFIT ANALYSIS 3/17197| 7/11/97| 100% 1215 8 m8 | | (i ' | 9, [ 104] RELIABILITY STUDIES 3/17/97|_7/11/97| 100% 317 Gt a a —e | 102 | ELECTRIC SYSTEM STUDIES 12/15/96| 7/11/97| 90% i a ET | = _ _t | 103 | AGENCY REVIEW 7419771897, 100% Aone TF | | | : 104 | TASK 8 ENGINEERING FIELD WORK 6114196 | 7/15/97| 93% 714 @ 718 | {__——— 10, 0s) | BNOROGRARHIC STUDIES | anaes NOT eT 100% 6/14 (GLA ET wy 715 108 | GEOTECHNICAL EVALUATION 7/2I96| 1/2197| 100% | | | | 14 EE 10/14 110 "FIELD INVESTIGATIONS | 6/14/96| 7/15/97| 100% | | 7. a «2 112 SUMMARY REPORT | 10/15/96] 7/15/97| 75% | | 14 Sabena Atami Sauna eRe Meiers |S 114 TASK9 PRELIMINARY ENGINEERING | 8/1/96| 9/16/97, 79% | | | 0) Ses eT 134 UPDATE COST ESTIMATE | 1/15/97| 7/11/97 | 80% POWER Engineers, Inc. Summary v__SCW@@®SsMiilestone = Task retronr! Project: 120376-01 Revision #3 (0920 08/09/97 PROJECT SCHEDULE Peninsula Transmission Line 1996 1997 1998 1999 1D | 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 | Jui de PUBLICIAGENCY INVOLVEMENT | 8/5/96 | 11/15/98| 56% 25. Giemsa ee | ee OB uns PROGRAM | : ie INTERDISCIEINATENTEAM | all pisee ero (5 SCREEN KORE EO EE SESS! _# 73 ] | | : 137 ID TEAM FORMULATION 1/6/97| 4/25/97| 95% i 16 GH 425 | 138 MEETINGS | 114197| _7/3/98| 65% | | © @ 139 COMMUNITY WORKING GROUP 8/5/96| 6/27/97| 82% | | Tec aan TTR SERS AIL WO 627 140 | INTERVIEWS 8/5/96 | 10/10/96| 100% | | | | a5 B_ W100 [441 | MEETINGS 1113/97| 6/27/97| 75% | | 3 = | (J) Y) 4 Separate Meetings 142 | PUBLIC MEETING/HEARING 11/11/96 | 2/19/98| 16% : | | | | + _——- 111 219 [143 | SCOPING MEETINGS (3) 11/11/96 | 11/15/96, 100% = | = ~ : - [144 | PUBLIC HEARINGS (3) 1/15/98| 2/19/98| 0% Y) 3 Scoping Meetings | | | | i | a / ; | 145 | NEWSLETTERS/FACT SHEETS 2/24197| 11/15/98| 60% Public Hearings | _ | 146 | SCOPING 4/30/97| 4/30/97 95% @ @ 4Newsietters/Fact Sheets 147 | ALTERNATIVE 8/1/97, 8/1197, 0% 4130 ® 4/30 i COMPARISON/ANILCA APPLICATION : 148 | FEIS 7198 7/1/98| 0% ant @ ait | 7 @B 7a POWER Engineers, inc. Summary FC ® ss Milestone e Task Hct Ont Project: 120376-01 Revision #3 (0920 08/09/97 PROJECT SCHEDULE POWER Engineers _ Deliverable Tracking System Deliverables by Project Report Printed: Fri, Aug 15,1997 11:15AM Period Ending: 8/9/97 Project: 120376-01 TASK 1 SCOPING 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 Rein indie Milestone Dates % Comp Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-01-55-01-01 1.1.01 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 90 1.2.04 Identify scope of issues to be addressed . Tim Tetherow 11/1/96 = 12/31/96 100 4.2.05 Develop Preparation Plan Tim Tetherow 6/24/96 1/15/97 98 1.2.06 Review Preparation Plan Chugach Electric 1/15/97 1/31/97 95 1.2.07 40 Copies of Preparation Plan for EIS Tim Tetherow 2/20/97 2/28/97 0 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 4.2.11 1 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: 8/9/97 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 95 1.2.17 Provide Mailing List Tim Tetherow 7/15/96 9/3/96 100 1.2.18 Update Existing Public & Agency Mailing List Tim Tetherow 7/15/96 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 1:2.22 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 80 120376-01-55-01-04 1.4.01 Agency Review & Approval of Scoping Rpt Tim Tetherow 9/30/96 1/31/97 80 1.4.02 40 Copies of Scoping Report Tim Tetherow 1/1197 1/31/97 0 Deliverable Tracking System Deliverables by Project Period Ending: 8/9/97 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 85 2.1.01 Agency Contacts (Continuing) Tim Tetherow 6/11/96 85 2.1.02 Inventory of Resource Data/Alternatives Tim Tetherow 6/11/96 = 11/6/96 98 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 98 2.2.02 Provide Associated Data Tables by Route Tim Tetherow 10/15/96 11/29/96 98 2.2.03 Additional Review & Documentation Tim Tetherow 5/7/97 11/20/97 98 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: 8/9/97 120376-02-55-02-04 2.4.01 Provide Right of Entry for ElS Field Studies Frank Rowland 10/15/96 9/8/97 0 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: 8/9/97 Project: 120376-03 Project Manager: Randy Pollock TASK 3 IMPACT ASSESS/MITIG PLN Client: CHUGACH ELECTRIC ASSOCIATION MIS Project Start Date: 6/10/96 MIS Project End Date: 6/10/97 Task/Subtask - Deliverable Resp Indiv Milestone Dates, -,,, 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 — 90 3.1.01 ID Team Review of impact criteria, results, mtg Tim Tetherow 1/1197 1/31/97 0 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 2/14/97 2/28/97 0 3.1.04 Final Determination of Project Description Tim Tetherow 11/1/96 11/8/96 80 120376-03-55-03-02 3.2.01 |A/MP Site Specific Models Tim Tetherow 10/21/96 11/29/96 85 3.2.02 Impact Maps & Tables Tim Tetherow 10/21/96 2/28/97 80 3.2.03 Develop/Conduct IA/MPP Tim Tetherow 10/21/96 12/31/96 70 3.2.03-A Define:Potential Direct/Indirect/Cumltv Impacts Tim Tetherow 10/21/96 12/31/96 65 3.2.03-B Define: |nterrelationships(cause/effect)impacts Tim Tetherow 10/21/96 12/31/96 65 3.2.03-C Define: Criteria Definition Tim Tetherow 10/21/96 12/31/96 65 3.2.03-D Define: Determination of Impact Significance Tim Tetherow 10/21/96 12/31/96 65 3.2.04 Preliminary Mitigation Asessement(mitigation ID) Tim Tetherow 10/21/96 12/31/96 75 3.2.05 Review Preliminary Mitigation Criteria Tim Tetherow 11/1/96 = 11/29/96 75 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 4/1/97 4/25/97 0 3.2.08 Impacts Reassessed Tim Tetherow 2/3/97 2/28/97 0 3.2.09 Residual Impacts Determined Tim Tetherow 3/3/97 3/31/97 0 3.2.10 Finalize Results IA/MP Address Cumulative Effects Tim Tetherow 5/1/97 5/30/97 0 Deliverable Tracking System Deliverables by Project Period Ending: 8/9/97 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: 8/9/97 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, Come 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 20 4.1.02 Development of Criteria&Rte Comparison Mat Tim Tetherow 4/1/97 4/18/97 25 4.1.03 Two Day Route Comparison Meeting Tim Tetherow 46/97 4/18/97 0 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 TI1197 7131/97 0 4.2.02 Review & Approve Newsletter # 2 Chugach Electric 7/15/97 = 7/31/97 0 4.2.03 Documentation of Route Selection Process Tim Tetherow 4/1/97 8/29/97 20 Deliverable Tracking System Deliverables by Project Period Ending: 8/9/97 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 i Deliverable Resp Indiv Milestone Dates comp 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 25 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 5.2.01 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 §.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 114/98 =. 3/16/98 0 5.3.02 File with EPA Tim Tetherow 1/14/98 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 aa SS SSS 8 PSS a 8 Deliverable Tracking System Deliverables by Project Period Ending: 8/9/97 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 §.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 §.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-Rvw Project Status Randy Pollock 6/23/97 6/27/97 0 §.22.09 Issue Draft Statement Randy Pollock 7/1197 7/25/97 0 Deliverable Tracking System Deliverables by Project Period Ending: 8/9/97 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, -,,, Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-06-55-06-01 6.1.01 Newsletter(Announce FEIS) Tim Tetherow 71198 7131/98 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 5/21/98 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: 8/9/97 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: 8/9/97 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 mandy Milestone Dates, -,, Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-07-22-07-05 7.5.01 Summary Report William Riall 75/96 ~—- 8/14/97 50 7.5.02 Recommend Dsg Parameters William Riall 7/15/96 —- 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 80 7.6.02 EIS & Prelim Eng Calculations Larry Henriksen 7/5/96 = 8/14/97 80 7.6.03 Text & Graphs or Charts-EIS Larry Henriksen 7/15/96 8/14/97 80 7.6.04 RFI/TVI & Audible Noise Analysis Larry Henriksen 7/15/96 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 75/96 ~—- 8/14/97 90 7.7.02 Recommend Design Parameters William Riall 7/15/96 = 8/14/97 90 7.7.03 Office Visit to Pipeline-Anchorage William Riall 7/15/96 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 7.1.01 Determine System Requirements Ronald Beazer TII96 =: 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 7/1/96 12/13/96 100 12 Deliverable Tracking System Deliverables by Project Period Ending: 8/9/97 120376-07-23-07-03 7.3.01 Dynamic Stability Analysis Ronald Beazer 7196 = 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 12/2/96 12/9/96 0 7.4.03 Final Report Section Ronald Beazer 12/9/96 12/13/96 80 13 Deliverable Tracking System Deliverables by Project Period Ending: 8/9/97 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 7 Deliverable Regitniy 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 4/2/97 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 1/2/97 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 7/1196 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: 8/9/97 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 15 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: 8/9/97 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 . . ‘° 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 98 9.07.02 Modify Existing General Arrangement Plans Stanley Sostrom 8/1/96 12/2/96 98 9.07.03 Identify & Note Bus Connct & Phasing on DWGS Stanley Sostrom 8/1/96 12/2/96 98 9.07.04 Determine Const/Operation/Maintenance Stanley Sostrom 8/1/96 12/2/96 98 120376-09-21-09-08 9.08.01 Supplemental Design Criteria Stanley Sostrom 8/1/96 12/2/97 85 120376-09-21-09-09 9.09.01 Modify One Lines and General Arrangements Stanley Sostrom 8/1/96 12/2/96 98 9.09.02 Determine Const/Operation/Maint Requirements Stanley Sostrom 8/1/96 12/2/96 98 120376-09-21-09-10 9.10.01 Cost Estimates William Riall 1/15/97 5/14/97 60 120376-09-21-09-13 9.13.01 Cost Estimate Stanley Sostrom 1/15/97 5/14/97 85 9.13.02 Compile/Review Vendor Support Data Stanley Sostrom 1115/97 = 5/14/97 85 120376-09-21-09-14 9.14.01 3 Identified Alternative Routes Cost Estimates Frank Rowland 1/15/97 5/14/97 70 9.14.02 Develop Land Costs Frank Rowland 1/15/97 = 5/14/97 70 9.14.03 Develop Labor/Exp Costs to Acquire Easements Frank Rowland 1/15/97 5/14/97 70 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: 8/9/97 mY 9.01.03 1- 7 Day Trip for 2 people to Denmark William Riall 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 80 9.02.02 Preliminary Performance Specs William Riall 10/16/96 4/15/97 80 9.02.03 Determine Const/Operation/Main Requirements William Riall 10/16/96 4/15/97 80 120376-09-22-09-03 9.03.01 10 Copies of Summary Report William Riall 2/3/97 4/15/97 0 9.03.02 Recommend Specific Cable Type William Riall 2/3/97 4/15/97 0 9.03.03 Recommend Most Probable Method of Installation William Riall 2/3/97 4/15/97 0 120376-09-22-09-04 9.04.01 Preliminary Site Specific Arrangements William Riall 1/1/97 4/15/97 0 9.04.02 Engineering Sketches of Transition Station William Riall 1/1/97 4/15/97 0 9.04.03 DSGN Parameters/EIS Support/10 Sub CBL Landfalls William Riall 1/1197 4/15/97 0 9.04.04 DSGN Parameters/EIS Support/2 Transiton Sites William Riall 1/1197 4/15/97 0 120376-09-22-09-05 9.05.01 Preliminary Design for Wood Pole H-Frame Larry Henriksen 9/16/96 9/16/97 95 9.05.02 Prel DSGN for DBL Circuit Single Pole Structures Larry Henriksen 9/16/96 9/16/97 95 9.05.03 Est/Dist Underbuilt to Single Pole Struct Larry Henriksen 9/16/96 9/16/97 95 9.05.04 Determine Const/Operation/Maint Requirements Larry Henriksen 9/16/96 9/16/97 95 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: 8/9/97 120376-09-22-09-11 9.11.01 Cost Estimates guyed "X" Larry Henriksen 1/15/97 = 5/14/97 95 9.11.02 Cost Estimates Single Stl Pole Single Circuit Larry Henriksen 1115/97 5/14/97 95 9.11.03 Cost Estimates Wood Pole H-Frame Larry Henriksen 1/15/97 5/14/97 95 9.11.04 Cost Estimates DBL Circuit Single Pole Larry Henriksen 15/97 = 5/14/97 95 9.11.05 Cost Est Addition of Underbuilt to Single Pole Larry Henriksen 115/97 = 5/14/97 95 9.11.06 Narrative of Cost Estimate Process Larry Henriksen 1/15/97 5/14/97 95 9.11.07 Summary Cost Report Larry Henriksen 4/15/97 = 5/14/97 95 120376-09-22-09-12 9.12.01 Cost Estimate for 2 New Endpoints Stanley Sostrom 1/15/97 = 5/14/97 75 9.12.02 Narrative of Cost Estimate Process Stanley Sostrom 1/15/97 5/14/97 75 9.12.03 Summary Cost Report _ Stanley Sostrom 4115/97 = 5/14/97 75 120376-09-23-09-15 9.15.01 15 Copies Summary Reports Michael Walbert 4115/97 5/14/97 0 18 8/15/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: 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 5 PROJECT SUMMARY REPORT 59-97 | 4TH QUARTER 1997 1ST QUARTER 1998 | 2ND QUARTER 1998 38RD QUARTER 1998 4TH QUARTER 1998 im TASK MONTH OCT [ae NOV DEC JAN FEB MAR APR MAY JUN JUL | AUG SEP OcT NOV DEC 1 SCOPING HH om | | | | | Actual % Work Completed i a | aoe | OTT KO | I | iil | 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% vee 100% 100% 100% 100%| 100% |___ Actual % Expended $ (to date) - | | | i Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Rev. 1 Planned $ (this period) He $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) $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) it | | 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 | $374,839 Actual Remaining Task Budget | | | | | 2 INVENTORY | | Hi | | | | | wan | Actual % Work Completed | | | | i | | | Base Planned % Complete $ (to date) 100% 100% 100% 100%| 1 00%| 1 00%| 100% 100%! 100% 100%} 100% 100% 100%) 100%| 100% Rev. 1 Planned % Complete $ (to date) 1 00%| 100% 100% 100% | 100% 100% 100% 100%! 100% 100% | 100% 100% 100%| 100%| 100% Actual % Expended $ (to date | | | a) 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 ra $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) |r | | | | | | 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 |! 3 __|IMPACT ASSESSMENT/MITIGATION PL i | | ue | HL 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%| 1 00%| 100%) 100%} 100% 100% 100% 100% 100%| 100% 100% Actual % Expended $ (to date) | a | | Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $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 | | ase? SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT 8-9-97 4TH QUARTER 1997 1ST QUARTER 1998 2ND QUARTER 1998 38RD QUARTER 1998 4TH QUARTER 1998 TASK MONTH APR MAY | JUN JUL AUG i SEP OcT NOV DEC 4 ALTERNATIVE SELECTION | | | Actual % Work Completed _ | ae Base Planned % Complete $ (to date) 100% 100%| 100% 100% 100% 100% 100% 100% 100% Rev. 1 Planned % Complete $ (to date) 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 | a!) $0 $0 | $o| $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) $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 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 Actual $ Expended (to date) | =i _| Base NTE Budget (Amend. #3) | $303,475 $303,475 $303,475 $303,475 1 $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 | | | | | | 5 DRAFT EIS | | _t | | | i Actual % Work Completed | | | | Base Planned % Complete $ (to date) | 50% 55% 60% 66%) 85% 96% _ 1 00%| 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) _| | | | | | iL 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 a!) $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 | $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 Actual Remaining Task Budget | | | | | | | | | 6 FINAL EIS | | | | | _| | | Actual % Work Completed | | : | | | 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% 7%| 40% 53% 73% 86% 90% 93% 96% 98% 100% Actual % Expended $ (to date) | l | | | _ 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 —|— 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 | 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 6 8/15/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT 8:9-97 | 4TH QUARTER 1997 L: 1ST QUARTER 1998 | 2ND QUARTER 1998 38RD 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 _ . ee | SS | - _ Base Planned % Complete $ (to date 91% 91% 91% 91% 91% 96% 96%| 96%) 96% 96% 96% 100% 100%| 100% 100% Rev. 1 Planned % Complete $ (to aati 90% 90% 90% 90%| 90% 96% 96%| 96% 96% 96%) 96% 100% 100% 100% 100% Actual % Expended $ (to date) L | | | [_ Base Planned $ (this period) $0 $0 $0 $0 | $0 $5,400 $0 | $0 | $0 $0 $0 $4,000 | _ $0 | $0 $0 | Rev. 1 Planned $ (this period) $0 $0 $0 $0 $0 $5,900 $0 | $0 $0 $0 | $0 $4,000 $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) $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) | | | | | | _| 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 so | 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% 1 00%! 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) $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 | | | ES Ee eee eee L.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 | $o| $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/AI 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 8/15/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: 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 8-9-97 4TH.QUARTER 1997 1ST QUARTER 1998 2ND QUARTER 1998 38RD 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 IIL | (ic LTE SUL : ll] mi | ; Base Planned % Complete $ (to date) | 85% 85% 86% 87%| 89%| 91% 93%| 94%| 96% 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) ii $0 $0 $0 $0 | $0 $0 $0 | $0 | $0 $0 $0 $0 $0 $0 | $0 | Base Planned $ (to date) $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) | | | | cn | 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 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 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 | | | | I | | | | 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 $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 | $1,225,703 | $0 Page 8 8/15/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: 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 8-9-97 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 2ND QUARTER 1997 3RD QUARTER 1997 TASK MONTH| JUNUL | AUG | SEP Oct NOV Dec | JAN FEB | MAR APR MAY JUN Ju__| AUG SEP 1 SCOPING | Actual % Work Completed 5% 20% 28% 33%|_ 51% 72% __77%|_ 98% 99% 99% 99%) 99% 99% 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% : 0. 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 $0 S$ $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 eS $0 Actual $ Expended (this period) _ $15,925 $89,330 ss $9,848 | $63,340 | $42,082 $67,538 $59,509 $25,800 $0 | _($593)|_ ($7,434)| $1,037 ks $0 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) N/A N/A N/A N/A N/A| WA| $287,505 | $347,617 $374,839 $374,839 $374,839 $374,839 $374,839 $374,839 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 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 2 INVENTORY | | | | Actual % Work Completed 0% 6% 25% 45%| 60% 67% 73%| 80%) 87% 88%) 88%) 90% 90% Base Planned % Complete $ (to date) 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% 100% Actual % Expended $ (to date) 0% 5% 2A%| 43%| 58% 72% 73%) 78%! 87% 88%) 88%| 90% 90% 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 $1,000 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 $26,975 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 $0 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 $660,706 Rev. 1 Planned $ (to date) N/A N/A N/A N/A| N/A N/A| $495,514 $554,446 $574,686 $583,503 | $586,503 | —_ $604,003 $623,003 $679,591 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 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 3__|IMPACT ASSESSMENT/MITIGATION PLANNING | | | | Actual % Work Completed 0% 0%| 0% 0%| 1% 5% 7% | 10% | 16% 31%) __ 52%| 62% 75% Base Planned % Complete $ (to date) 0% 0% 0%| 5% 10% 25% 40% | 50%| 60%] 80%) 95%| 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% Actual % Expended $ (to date) 0% _0%I 0% 0% 1% 5% 7% 9% 16% 31% 52%| 62% g 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 Sg : $18,000 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 is $0 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 $584,010 010 $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 $597,619 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 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 Page 1 8/15/97 SOUTHERN INTERTIE PROJECT PROJECT SUMMARY REPORT THROUGH PERIOD ENDING: 8-9-97 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. 3RD QUARTER 1996 4TH QUARTER 1996 | 1ST QUARTER 1997 i 2ND QUARTER 1997 38RD QUARTER 1997 MONTH| JUN/JUL DEC JAN | FEB | MAR | APR MAY JUN ALTERNATIVE SELECTION al | | | Ae | | Actual % Work Completed - 0% 0% 0%| 0% 0%| 0% 0% OHO]. 1%)” 10% Base Planned % Complete $ (to date) | 0% 0% 0%| 0% 0% 0%| 0% 0% 0% 11%| 35% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A’ 0%| 5%| 15% 31% 49% 71% 100% Actual % Expended $ (to date 0% 0% 0% 0% 0%! 0% 0% 0% 1% 11% Base Planned $ (this period) $0 $0 $0 $0 $0 | $0 $0 $0 $32,400 $74,400 $60,875 Rev. 1 Planned $ (this period) N/A| N/A WA $0| $15,000 $35,000 $52,000 $62,000 $72,000 $69,000 | $0 Actual $ Expended (this period $0 | $0 $0 $0 | $0 $0 $0 $1,275 $34,764 $27,023 a) Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $0 | $0 $0 $0 $32,400 $106,800 $184,200 : $303,475 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 © 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 $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 5 {——_ourtes ——_] | | mail | | | Actual % Work Completed 0% 0% 0% 0%| 0% 0%| 0%| 0% 0%| 1% 8% 11% Base Planned % Complete $ (to date) 0% 0% 0% 0%| 0% 0% 0%| 0%| 1% 2%! 3%| 4% 11% 34% Rev. 1 Planned % Complete $ (to date) N/A N/A| N/A N/A} N/A WA 0%| 1%| 1% 1%) 2% 2% 17%5 48% Actual % Expended $ (to date) | 0% 0%| 0% 0%! 0% 0% 0%! 0%! 0% 0%| 1% 8% 11%} Base Planned $ (this period) $0 $0 $0 $0 | $0 so| $0 | $0 | $5,772 $1,572 | $5,772 $1,582 $31,570 © $57,570 Rev. 1 Planned $ (this period) N/A N/A N/A N/A| N/A NZ $0 | $6,100 | $0 $0 | $4,000 $332 $65,634 = 86. $42,017 Actual $ Expended (this period $0 $0 $0 $0 | $0 $o $0 | $0 | $0 $0 | $4,991 | $29,405 $13,991 | 991 $0 Base Planned $ (to date) $0 $0 $0 $0 | $0 $0 $0 | $0 | $5,772 $7,344 | $13,116 | $14,698 $46,268 j $135,408 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 — $218,469 Actual $ Expended (to date $0 $0 $0 $0 | $0 $0 $0 | $0 | $0 $0 | $4,991 | $34,396 $48,387 "> 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 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 US | OFI 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 FINAL EIS | vi | | Actual % Work Completed 0% 0% 0%! 0%! 0% 0% 0%) 0%) 0%] 0%| ___ 0% 0% 0% E 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 N/A 0% 0% 0%} 0% 0% 0% O%E 0%' Actual % Expended $ (to date 0% 0% 0% 0%! 0% 0% 0%| 0% 0% 0% 0%| 0% 0% <a e: Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 | $0 $0 $0 $0 | $0 ; Es $0 Rev. 1 Planned $ (this period) | N/A N/A N/A N/A N/A N/A $0 $0 $0 $0 $0 $0 ee: $0 Actual $ Expended (this period $0 $0 $0 $0 $0 $0 $0 | $0 $0 $0 $0 $0 ae 5 $0 Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $0 | $0 $0 $0 $0 $0 E= $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| Actual $ Expended (to date $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 NWA N/A N/A N/A N/A N/A N/A N/A N/A| N/AE 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 © 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 * Sj | 8/15/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT 8-9-97 TE: 3RD QUARTER 1996 4TH QUARTER 1996 | 1ST QUARTER 1997 2ND QUARTER 1997 3RD QUARTER 1997 — MONTH] JUN/JUL | AUG SEP OCT NOV iE DEC JAN FEB | MAR APR MAY JUN JUL STUDIES | | | Actual % Work Completed 1% 5% a 1% 8% 14% 27%| 35% 48% 55% 60% 60% Base Planned % Complete $ (to date’ 1% 5% 9% 21%! 51% 73% 73%| 73%| 76% 78%| 80%) 83% Rev. 1 Planned % Complete $ (to date) | N/A N/A N/AI N/A N/A N/A 27%! 38%) 55% 56% 56% 67% Actual % Expended $ (to date) 0% 3%t 7% 7%| 8% 14% 27%| 33% 47%) 55% 60% 61% 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 Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $13,352 | $10,492 $18,035 $500 $500 | $11,156 $11,300 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 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 Rev. 1 Planned $ (to date) | N/A N/A N/A N/A N/A N/A $27,588 | $38,080 | $56,115 $56,615 | $57,115 $68,271 $79,571 Dg 5 Actual $ Expended (to date) $0 $2,569 $6,746 $7,383 | $8,531 314.206 | $27,588 | $33,043 $47,836 $56,088 | $61,245 | $61,685 $67,540 ©% 2 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 1015480 $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 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 1,480: $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 8 ENGINEERING FIELD WORK = | _| | | | | = Actual % Work Completed 5%| 15%| 50% 60%! 70% 74% 77%| 79%| 84% 87%! 87%| 90% |_Base Planned % Complete $ (to date) 5% 18% 52% 63%| 68%| 78% 86%! 91%! 91% 91%) 91%| 94% Rev. 1 Planned % Complete $ (to date) N/A} N/A N/A N/A| N/A N/A 77%| 79%! 81% 81%) 81%| 88% Actual % Expended $ (to date) 5% 13% 48% 60%! 70%! 74% 77%! 79%| 84%| 87%! 87%| 90% 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 © 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 Actual $ Expended (this period) a $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 p14 Base Planned $ (to date) =i $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 3 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 \ 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 PRELIMINARY ENGINEERING | | __|} | L | | i Actual % Work Completed | 1% 1% 1% 1%| 12% 17% 18%) 20%| 25% 36%| 45%| 50% ‘ | Base Planned % Complete $ (to date) 1% 2% 4% 9%| 23%| 31% 44%| 57%| 71%| 88% 97%| 98% "2 98%: 98% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A Nat 18%| 36%| 53% 71% 85%] 98%) * ; 98% | Actual % Expended $ (to date) 1% 1% 1%| 1%) 12% 17% 18% 20% 24% 36% 44% 50% Pees 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 agesos $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 — 3° «SO | 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 b $185,861 Rev. 1 Planned $ (to date) N/A N/A| NWA N/A N/A N/A $34,531 | $67,531 $100,531 $135,531 $160,531 $185,861 $185,861 BSi86t. $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 © Segia6;590: | 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 © : 36 |__CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A NA\ N/A N/A| N/A N/A N/A NA NAL | CNA Total Task NTE Budget $189,861 $189,861 $189,861 $189,861 $189,861 $189,851 $189,861 $189,861 $189,861 $189,861 $189,861 | $189,861 $189,861 $489.86 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 eessiess | 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 8/15/97 SOUTHERN INTERTIE PROJECT PROJECT SUMMARY REPORT THROUGH PERIOD ENDING: 8-9-97 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 | 2ND QUARTER 1997 oe 3RD QUARTER 1997 MONTH| JUN/JUL AUG SEP OCT NOV DEC DAN ae ares MAR a JUL SEP TOTAL PROJECT 120376-01 Actual % Work Completed 1% 5% 12% 18%| 24%] 30%| 3394 | iimnmnTe%)| 40%| 46% 51% 55% 60% Base Planned % Complete $ (to date) 1% 5% 12% 22%| 31% 41% 47%| 51%] 55% 60% 64% 69% 74% 83% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A| N/A| N/A 33%| 42% | 49% 56% 62% 68% 75% 84% Actual % Expended $ (to date 1% 6% 12% 18%| 24%| 30% 33% 37%| 42% 46% 51% 55% 60% 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 | $119,445 Rev. 1 Planned $ (this period) N/A N/A N/A N/A| N/A NA| $120,608 | $269,226 | $235,588 | $207,687| $182,530| $220,018] $221,229 © $87,794 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 $0 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 $2,515,245 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 $2,686,955 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 © 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 N/A| $103,047 | _ $103,047| $103,047| $103,047| $103,047| $103,047| $103,047 $103,047 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/Al___ $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 __$1,042028 BASE PLANNED QUARTER TOTALS $364,150 $881,579 $413,500 $431,221 24,795 [ BASEPLANNEDYEARLYTOTALS | $1,245,729 REV. 1 PLANNED QUARTER TOTALS $553,715 $625,422 i] $610,235 | $527,827 | REV. 1 PLANNED YEARLY TOTALS | ACT | RG O39°47"4 ACTUAL QUARTER TOTALS $553,715 $405,250 $434,098 $386,355 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 Cy 7 CC: Le Wy ae. Mruke pla Mw Municipality of Anchorage Municipal Light & Power Fick Mystrom, Mayor 4200 East First Avenue Anchorage, 99501-1685 July 31, 1997 Telephone: Precew PE? Dp” 277-9272 AUG 05 1997 Mr. Eugene N. Bjornstad, General Manager Chugach Electric Association, Inc. TRANSMISSION P.O. Box 196300 SPECIAL PROJECT Anchorage, Alaska 99519-6300 Re: Your Letter of July 9, 1997, Southern Intertie, EA/EIS. Process, Quartz Creek Route Alternative Dear Mr. Bjornstad: The reasons cited by Power Engineers’ are not compelling enough to cause ML&P to endorse elimination of the Quartz Creek Route for consideration as a potential route for the Southern Intertie. Furthermore, I question the wisdom of eliminating any of the three routes now under consideration; the thrust of the consultant’s effort at this time ought to be to establish the relative priority of the routes—not to eliminate them before such comparisons are made. By announcing to the world that we are no longer considering the Quartz Creek route because, among other reasons, we anticipate opposition from the Chugach Park Service; or if we acquiesce to a judgment that the presence of a second circuit along a pre-existing right-of-way makes the right-of-way unavailable for public outdoor recreation, we play into the hands of those opponents who may now proceed to oppose the next route we consider. The game changes significantly for any opponents of a new Southern Intertie, if they are forced to choose which route they wish to oppose more vehemently than any other, knowing we are committed to build on one of the three. : The Power Engineers argument on reliability does not ring entirely true either. The five year look-back on outages caused by avalanche does not give a true measure of the incremental improvement a second Quartz Creek circuit provides. The true measure of the value of a second circuit should be based upon the incremental reliability improvement provided against all causes. Putting Energy into Anchorage for Over 60 years July 31, 1997 Mr. Eugene N. Bjornstad S. Intertie, EA/EIS Process, Quartz Creek Route Alternative Finally, the value of the second circuit in enabling greater use of Bradley Lake capacity for spinning reserves is conservatively estimated to be worth at least $500,000 a year to ML&P alone. The spinning reserve benefit of a second circuit should be included in the cost-benefit analysis for each of the routes. Acting General Manager C:\offiwin\StieQC August 18, 1997 Mr. Hank Nikkels Anchorage Municipal Light & Power 1200 East First Avenue Anchorage, Alaska 99501 Subject: Southern Intertie - EIS Process Quartz Creek Alternative Dear Mr. Nikkels: We have received concurrence with the deletion of the Quartz Creek Route from all IPG members but AML&P. Your letter of July 31,1997 recommends to include the Quartz Creek Route in the EIS as a fully evaluated alternative. Please, be assured that the route has been evaluated in depth and deleted on the basis of constraints that cannot reasonably be mitigated: The Land and Water Conservation Fund Act (L&WCF)is a law and does not allow incompatible facilities in this park. An overhead transmission line is not compatible with the purpose of the park. The Alaska Division of Parks has informed us in writing (copy enclosed) that they are not willing to consider requesting a “conversion” of park lands from the National Park Service for construction of an overhead transmission line. 2. Reliabili Reliability of two circuits routed adjacent to each other is impaired. Exposure to avalanches adds to the impairment. RUS has stated during the scoping process that loan funds may not be approved for such a route. Deleting the alternative from those with full impact analysis does not mean that the route will not be included in the EIS. It will be treated as an alternative investigated, but not found suitable for the purpose of the project. The benefits of the second circuit are addressed in the original feasibility study for the project prepared by Decision Focus Inc. (DFI). DFI has completed a draft of its update of the 1989 feasibility study, which addresses reliability improvements for all causes. DFI does not address relative reliability of the various routes and therefore does not allow an assessment of the impacts of diminished reliability of one route over another. DFI has also not addressed the impact of 5601 Minnesota Drive * P.O. Box 196300 » Anchorage, Alaska 99519-6300 Phone 907-563-7494 * FAX 907-562-0027 Southern Intertie - EIS Process Quartz Creek Alternative August 18, 1997 Page 2 of 2 BESS or SMES facilities. We may want to add this analysis to their work, especially if SMES benefits to AML&P are estimated at $500,000, as indicated in your July 31,1997 letter, to $1,000,000 annually, as mentioned in your letter of May 2,1997. Please, let us know whether you wish to pursue additional study of these benefits and we will obtain a cost proposal from DFI. If you have any questions or would like more information, please, contact our Project Manager, Dora Gropp at 762-4626 or contact her by e-mail at dora_gropp@chugachelectric.com. Sincerely, Epo A Gel Eugene N. Bjornstad General Manager ENB/DLG:tjh Enc c Tim MacConnell, AML&P Mike Massin Lee Thibert W.0.#E9590081 RF ets i iin ; 1:58PM : DAMES & MOORE Ui OO? ato O0zTi# 2/3 TONY KNOWLES, GOVERNOR DEPARTMENT OF NATURAL RESOURCES MAILING ADDRESE: DIVISION OF PARKS & OUTDOOR RECREATION - CHUGACH HC 2 BOX seep INDIAN, ALASKA 59540 rgunseene Eraat, chupetpagekenen ns? June 25, 1997 Via FAX 562-1297 Niklas Rante Dames and Mcore 5600 B Street, Suite 100 Anchorage, AK 99518 Ref: Southern irtertie Project Deer Niklas: This letter is in response to your FAX of June 20, 1897 posing several questions regarding the Southem Intertie Project and Chugach State Park. in response to your first question, the Division of Parks and Outdoor Recreation would not support a “conversion of use” under the Land and Water Conservation Fund (LWCF) Act _ toallow an additional overhead power transmission line in a second right-of-way through the perk. Chugach State Park was established in 1970 , in part, fo protect areas of unique and exceptional scenic value. The existing powerline, which is in conflict with this purpose, existed at the time of the park's establishment and was allowed to continue as a “valid entry’ under AS 41.21.121. A new powerline would be grossly incompatible with the purposes of the park. Our agency could not support a conversion of use petition under the LWCF Program. Likewise, we would not agree.to an amendment of the existing 115kv transmission line right-of-way by BLM to allow a second overhead transmission line adjacent to the existing Quartz Creek line. The placement of a second line in the same right-of-way does not lessen the significant and adverse impact to the park's scenic resources. Hyou have any questions regarding our position on this matter, please give me s call. rely, ~ JUN 25 Al Meiners iil Park Superintendent rT em ne c: Jim Stratton Jim Price 06/25/97 WED 12:56 [TX/RX NO 9762} AL -14 97 11:12 FROM: TO:987 762 4617 PAGE: 62 Homer Electric Association, Inc. Corporate Office Central Peninsula Service Center 3977 Luke Stet 280 Airport Way | Thommen Alaski S600 Toxo Kenai. Mask 99611 9280 Phong (9077 248 NOS] Phone 1907) 2N3-S834 BAN CONT) DaN S3T5 VAN (907) 383-7122 August 12, 1997 Rural Utilities Service 1400 Independence Avenue, SW Washington, D.C. 20250-1571 Attention: Gary Morgan, P.E. Director, Engineering and Environmental Staff Dear Mr. Morgan: RE: Southern Intertie Project - Notice of Proposal to Fund Consultant Services Homer Electric Association, RUS Borrower, Alaska 5 A Memorandum of Understanding (MOU) for the preparation of an Environmental Impact Statement (EIS) for subject project has been executed between RUS and the federal lead agency, USFW and USFS as cooperating agencies and Chugach Electric Association (CEA) on behalf of the Intertie Participant Group (IPG) as the applicant. HEA is a RUS borrower and a member of the IPG and vitally interested in timely completion of the environmental process. The MOU includes a workplan and schedule for the development of the EIS, which require that preparation of the EIS be closely coordinated with regulations governing the cooperating agencies. It is our understanding from your letter of July 16, 1997, that RUS will not be able to complete the process in the time frame contemplated without the assistance from a consultant. This letter shal] serve as notice of a proposal to fund consultant services for the preparation of en EIS from an Environmental Analysis prepared by the applicant in accordance with 7 CFR, 1789.158. HEA will fund this effort up to $100,000. The services required are outlined in the attached “Statement of Work and Schedule”. Please note that we have changed the “Statement of Work” to reflect a tie to the MOU and its provisions; the validation procedures to rely on approval by RUS and the cooperators and the schedule to allow closer tracking with the schedule included in the MOU. RECEIVED AUG 13 1997 Ans’d..........- A -14 97 11:12 FROM:- TO:907 762 4617 PAGE : 63 Notice of Proposal to Fund Consultant Services August 12, 1997 Page 2 of 2 We are anxious to continue work on this project and trust that you will secure the consultant services in a manner, where a Notice to Proceed can be issued no later than August 15, 1997. We stand ready to enter into the required indemnification and escrow agreements as described in 7 CFR 1789.162 and 1789.166/167 respectively. Should you have any questions or require additional information, please contact our Project Manager, Dora Gropp, c/o Chugach Electric Association, Inc., by telephone at (907) 762- 4626, by e-mail to dora_gropp@chugachelectric.com or by fax to (907) 562-0027. We appreciate your cooperation on this project. Sincerely, HOMER ELECTRIC ASSOCIATION, INC. al N. L. Story General Manager sinter rus:NLS/es enclosures: c: RUS, Larry Wolfe, w/ RUS, Alan Yost, w/ IPG-GMs, w/ USFWS, Brian Anderson, w/ USES, Fred Prange, w/ Power Engincers/Dames and Moore, w/ Dora Gropp, Project Manager, CEA w/ 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 @.0- EFS0S/, See -7 7eceurol S4/? 7 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 tesults of the analysis were documented in a December 1989 report entitled “Economic Feasibility of the Proposed 138 KV Transmission Lines in the Railbelt”. One of the lines studied in the 1989 analysis, the Southern Intertie Project (SIP) between Anchorage and Kenai, is currently under serious consideration, and an environmental impact statement (EIS) is being prepared for the proposed project. Because DFI’s 1989 analysis helped to justify the project, it is desirable to review that analysis to determine whether any changes have occurred in the years since 1989 that would alter the conclusions of the analysis. The December 1989 report estimated benefits of new transmission lines in six different categories: capacity sharing economy energy transfer reliability transmission losses operating reserve sharing State revenue from gas royalty and severance taxes AAP YN 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 (millions of 1997 $, 6% discount The new total benefits estimate is substantial, but is about 25 per cent lower than for the 1989 study, when expressed in the same year dollars, due primarily to lower forecasts of fuel prices, a lower 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 affecting the estimates. 2.1 Capacity Sharing Capacity sharing benefits occur when: © ome region has a capacity shortfall (i-e., demand plus the required reserve margin exceeds the capacity available) another region has a capacity surplus transmission links allow the first region to rely on excess capacity in the second region, even if only for a limited time Increased transmission capacity allows one region to rely more heavily on generation capacity in another region, for capacity as well as for energy. For the Railbelt, the SIP would allow Anchorage to rely on a greater portion of the Kenai Peninsula generation capacity surplus for meeting the Anchorage capacity requirement, thus deferring the need to build new generation capacity in Anchorage. Decision Focus Incorporated - Confidential R2947— 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 e required reserve margin ° fixed cost of new combustion turbine 2.2 Economy Energy Transfers This benefit occurs when high cost energy in one area is displaced by lower cost energy from another area. In the Railbelt all available hydro energy, which uses no fuel and for which the variable cost is essentially zero, will be used with or without the proposed new transmission line. Thus the benefits in this category result from displacing electricity generated from thermal units (gas-fired or oil-fired) with electricity from other thermal units with lower variable costs. These lower costs may result from access to less expensive fuel or from some units being more efficient (converting a greater fraction of the energy content of the fuel to 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 roughly 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. a reduction in unserved energy as result of new line a value of unserved energy Decision Focus Incorporated - Confidential 3.0 Updates Of Key Data Items The major factors that go into determining benefits of capacity sharing, economy energy, and reliability 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 Incorpomied - 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 reflect any changes in underlying conditions, but rather a change in assumptions away from a rate mandated by a government agency to a rate more appropriate for a utility and its ratepayers. 3.3 Demand Forecasts Table 2 compares the demand forecast used in the 1989 study with current demand forecasts, by looking at the forecast for the year 2010. Table 2 COMPARISON OF PEAK DEMAND FORECASTS FOR 2010 Decision Focus Incorporated - Confidentia) (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. Levelizing 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 $51 per kilowatt per year, in 1990 dollars. When both are expressed in the same year dollars, the new value is about 15 per cent lower. 3.6 Fuel Prices Table 3 shows the fuel prices projected for 2010 in the 1989 analysis, converts them to 1997 dollars, and compares the forecasts to today’s actual prices. The actual prices today are about 40 to 70 per cent lower than the forecast, when both are expressed in 1997 dollars. Table 3 Comparison of 1997 Fuel Price Forecast with Actual Prices [$/million Btu] 1989 Forecast of 1997 Price (1990 $) Table 4 compares the 1989 fuel price forecasts for 2010 with current fuel price forecasts for 2010. As in Table 3, all numbers are converted to 1997 dollars. We see a similar pattern, in that the prices forecast today for 2010 are 25 to 50 per cent lower than the prices that were forecast for 2010 in 1989. Table 4 Comparison of Fuel Price Forecasts for 2010 Made in 1989 With Those Made in 1997 [$/million Btu] Decision Foous Incorporated - Confidential R2947a Lower fuel prices reduce the value of the benefits from economy energy. Without detailed system modeling (i.e., how each generating unit would be operated over the 40-year time horizon, with and without the proposed new transmission line), it is impossible to say precisely how much the benefits are reduced (see recommendation 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 - Confideatia) R2947a, 10 Table 5 Net Present Value of Benefits of Proposed SIP 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. i 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 R29478 11 a 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. 3 Decision Focus Incorporated - Confidential R2947a SENT BY! 8 6-87; 10:52; POWER ENGIMRS» 907 562 0027:# 2/ 6 WAN mons WED ECEIVE D peel |i) Aue 11 1997 ‘Anchorage, AK 99519-6300 Subject 120376-04 Southern Intcrtie 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 thc meetings has been that the rate impacts would be addressed as part of the EIS process. The Scoping Report, which is in the process of being cumpleted 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 re aE eos So mien Bee fen cat Lae hn ssecomenct off tee vale ioxpacts from the IP is nol cenvently « past off our scope of work. As we discussed last week, Decision Focus, Inc. (1) would be a good choice to compictc this task, as they have most of the data required, and are well qualified to complete the " analysis and bo listed os a “Preparer” in the EIS. We requested DFT to send us a letter proposal outlining their approach tn the analysis, and additional data requirements needed to complcte 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 Fngincers will require some time to incorporate DFT’s results into the EVAI.. BLY 23-373 | e “bates 81 Y940 Glenbmok Or, P.0.;Bux 1066 Phone (208) 788-3456 Hailey, Idaho K3353 : Fax (208) 788-2082 SENT_BY: 8- 6-87 ; 10:33 ; POWER ENGINFERS> 907 562 0027;# 3/ 6 August 4, 1997 Page 2 " DF I has requested the following information to complete the analysis: Ktem Party to supply data to DF1 Cost Estimates - ee Power Enginccrs Timing of Construction E) enditures Power Enginccrs Financmg - = Wisivasitaaatined ta ota cha at Chugach to ‘be incurred “Tose rates (cr in Hoy of kux raica) which spply to Ge IPG Chugach mexnber firms Accounting Rules applicable tp Alaska utilities Chugach pextaining to: allowed rates of return, depreciation - schedules, rules on AFUDC Any other pertinent information that DFI should know j Chugach regarding limitations or special cxceptions to any of the _EWh data or above information . DFT 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. ‘Io coordinate this work and to incorporate the results into the EIS documentation, would require labor and expense an the part of Power Engineers of “$1200. ‘The cost of the work would be invoiced on a time and expense basis, with an overall 5 fueaidieeninentteat eaenien ere salmaaa "LY 23.273 (aay ae Suen ew SENT BY: & 6-87 ; 10:34; — PORER ENGIM=RS+ 907 562 0027;# 4/ 6 August 4, 1997 - Page3 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. Va fafa Randy Pollock, PE. Project Manager Enclosure pyRP cc: =‘Tim Tetherow - D&M Niklas Ranta - D&M BLY 33-273 Det pSaTe= wh see ; SENT BY: ‘8 6-87 + 10:34 ; POWER ENGIP"TRS~ 907 562 0027;# S/ 6 mist | | |) | |e i 2? ~~ # he SLO S 7b-25 - SS yer 22 FOCUS | ae "NCORPORATED Corporate Office 450 Castro Street, Suite 300 Aountain View, Califomia 4041-2055 415 960 3450 August 1, 1997 Mr. Michael Walbert Power Engineers Incorporated 3940 Glenbrook Drive Hailey, ID 83333 | Dear Mike- Thisletter 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 i epee jr The project is being proposed by seven utilities, all having different rate stractures, 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 costs 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 study. 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 in-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 retum, depreciation 8- 6-97; 10:35 5 POWER ENGIM"§RS~ 907 562 0027;# 6/-6 Mr, Michael Walbert Page2 August 1, 1997 schedules, and rules on allowance for funds used during construction, will help make ou results more accurate. 5 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. Plas pie mea call at (05) 960-450 you have any quetons, or want uso get eared We look forward to working with you. Sincerely, pach Acne . fam cx: Steve Haas