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HomeMy WebLinkAboutS Intertie report 11-1997CHUGACH ELECTRIC ASSOCIATION, INC. nigach ASSOCIATION, INC. November 25, 1997 Y) She Alaska Industrial Development D FE G6 F | WV E and Export Authority i ii | 480 West Tudor Road per ag Anchorage, Alaska 99503-6690 © 1997 Alaska industrial Development Attention: Mr. Randy Simmons, Executive Director and Export Authority Subject: Southern Intertie Monthly Report for November 1997 W.0.#E9590081 Dear Mr. Simmons: Please find enclosed 1 (one) copy of the Southern Intertie Report for the Month of November 1997. If there are any questions, please contact Dora Gropp, (907) 762-4626. Sincerely, Length L~ fer Eugene N. Bjornstad General Manager ee Enclosures: 1 (one) copy of Southern Intertie Monthly Report c: Lee Thibert Joe Griffith Michael Massin Dora Gropp Jim Borden Mike Cunningham Don Edwards W.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 NOVEMBER 1997 = 2 Report for the Month of November 1997 W.0.#E9590081 Southern Intertie - Phase IB November 25, 1997 TABLE OF CONTENTS Page SSUIMIVTA RWS oie orrosioire voor tee ole cerlolioliey ol olielieyialieiisicisie) scl c se crerene ss 61> er I-1 FUINANGWA UG errestelienoitotierctic elec tie letierieliol elie) oi siiel ol shel ciclo) cve= stele! reve lelererel slerre I-1 ie Total Project Expenditures as of October 1997 2; Chugach Statement for October 1997 3. Bank Statement of October 1997 SCHED UDB operat oh ot oyesoiconrotiel ot elle) «1 ooo oo oe oo ee elle fo elolfe [elfeficlietietietietie¥i= Iil-1 ITEMS FOR APPROVAL 660.06 566 oo cece ccc cece ccs wee vinisiene IV-1 1. DFI’s Draft Update and Reevaluation of Benefits for the Southern Intertie (November 1997) KTEMS FOR DISCUSSION 6 6 5 3565 so cw oe wictine we sisisie 3 515151» = © V-1 i POWER Engineers’ “Decision Process for Route Selection” of October 29, 1997 ITEMS FOR INFORMATION ... 2... 2.2. e ee ee ee eee te ee eee VI-1 I POWER Engineers’ Monthly Report Phase IB - Environmental Analysis, November 15, 1997 De DFI’s Impact on Rates Report of November 12, 1997 ii Report for the Month of November 1997 W.0.#E9590081 Southern Intertie - Phase IB November 25, 1997 I, SUMMARY DFI has completed the “Rate Impact Assessment” for the project. Cost impacts range from 0.03¢ cents/kWh in the initial years of operation for the most expensive alternative (TESORO - 4 single phase submarine cables) to savings of the same amount for the lowest cost alternative (ENSTAR - 2 three phase submarine cables). A copy of the report is included under Section VI. DFI’s new update and reevaluation of the benefits of the Southern Intertie is in review. Overall benefits are now estimated at $143.5 Million. A copy of the draft study is included under Section IV. NERC has completed a draft of their update of the 1990 Railbelt Reliability Assessment. The report underscores the need for additional transmission ties. EPRI staff has not yet issued the promissed letter evaluation, which is expected to support the need for the projects. POWER Engineers/Dames and Moore are gaining on the earlier schedule delays with 84% completion compared to 86% planned. The Environmental Analysis (EVAL) has been issued for review. This draft does not include the alternative proposed by the IPG (applicant). The result of the review will be the selection of a proposed route for the construction of the project to be included in the final EVAL. The final EVAL will then be submitted to RUS in January 1998 for preparation of the Draft Environmental Impact Statement (DEIS). POWER Engineers has prepared a document to assist with the decision process. This document is included under Section V of this report. DESCRIPTION POWER USFS/USFW | CHUGACH TOTAL ENGINEERS S/RUS BUDGET $3,043,423.00 $100,000.00 $3,543,423.00 ALLOCATED $51,907.30 $10,000.00 $40,000.00 $101,907.30 CONTINGENCY Soo 030 | __S110/000.0 658050 AMENDMENTS $25, 485.0 5957 495.00 TOTAL $3,347,765.30 $110,000.00 $440,000.00 $3,897,765.30 COMMITMENT SPENT TO DATE $2,772,284.00 $77,754.00 $110,400.00 $2,960,438.00 % OF TOTAL 82.81% 70.69% Total Project expenditures as of 11/18/97 are $3,748,710 I-1 Report for the Month of November 1997 W.0.#E9590081 Southern Intertie - Phase IB November 25, 1997 Il. FINANCIAL 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 Inception Through October 31, 1997 Year to Date Month Through Through Ended Inception 12/31/96 9/30/97 10/31/97 Through 10/31/97 $68,678.93 $29,488.74 $6,293.83 $104,461.50 23,471.09 11,308.79 2,426.59 37,206.47 1,918,877.36 1,230,534.11 214,098.77 3,363,510.24 30,326.81 42,364.03 36,014.00 108,704.84 $2,041,354.19 _$1,313,695.67 $258,833.19 $3,613,883.05 Year to Date Month Through Through Ended Inception 12/31/96 9/30/97 10/31/97 Through 10/31/97 $1,433,087.47 $1,485,468.84 $436,493.55 $3,355,049.86 7,165.42 7,427.35 2,181.94 16,774.71 $1,440,252.89 _ $1,492,896.19 $438,675.49 $3,371,824.57 R ECEIVE D NOV 18 1997 Th am SSION & SPECIAL PROVECT DIONE merit .< MUU rcg arenes aie CHECKING ACCOUNT STATEMENT ‘Account Number: 0110 606 1 Prepared After the Close Of Business On: OCt 17 1997 Pog: 1 Of 3 CHUGACH ELECTRIC ASSOCIATION INC SOUTHERN INTERTIE GRANT FUND PO BOX 196300 ANCHORAGE AK 99519-6300 I CYCBI osc PREVIOUS BALANCE AS OF 09/30/97 27 Deposits & Other Credits 14 Checks and Other Debits $.00 $14,965, 159.37 $ 150.28 1,281,453.10 181.90 1,281,635.00 181.92 1,281,816.92 545.84 1, 282,362.76 182.02 1, 282,544.78 182.05 1,038, 144.24 147.36 1,038,291.60 147.38 1,038, 438.98 442.20 1,038,881.18 147.46 1,039,028.64 148.93 1,039, 177.57 148.95 1,039, 326.52 148.97 Amount 1,281,453.10 1,281,635.00 81,816.92 82,362.76 82,544.78 14,965, 159.37 Balance Date -00 10/07 -00 10/08 00 10/09 00 10/10 ription FIRSTLINE: (907) 265-4700 BRANCH: MAIN BRANCH ‘ (907) 265-3525 Service Charge This Month $.00 Interest Paid This Month $.00 CURRENT BALANCE AS OF 10/17/97 $.00 INCOMING WIRE TRANSFER - REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO REPO Desc! REPO REPO REPO REPO REPO CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST CREDIT INTEREST ription DEBIT DEBIT DEBIT DEBIT DEBIT Other Debits Date Balance Date 10/13 -00 10/17 10/14 10/15 10/16 CHECKING ACCOUNT STATEMENT Account Number: 0110 606 1 Prepared After the Close Of Business On: OCt 17 1997 Pog: 2 OF 3 CHUGACH ELECTRIC ASSOCIATION INC 1 CYCBI osc 5989 SS Se sa mmm ree eee Other Debits -------------- 299-2 nnn nn nnn nnn nnn nnn enn nee Amount Date Description 244,582.59 10/08 DEBIT MEMO(TCE6O) 1,038, 144.24 10/08 REPO DEBIT 1,038,291.60 10/09 REPO DEBIT 1,038,438.98 10/10 REPO DEBIT 1,038,881. 18 10/13 REPO DEBIT 1,039,028.64 10/14 REPO DEBIT 1,039, 177.57 10/15 REPO DEBIT 1,039,326.52 10/16 REPO DEBIT 1,039,475.49 10/17 REPO DEBIT On Oct. 20, 1997, First National Bank converts to a brand new computer system. Please be patient while we make improvements. O) 000 01 00 PAGE: al _ | DATE: 10/31/97 ACCOUNT: 41100033 First National Bank eee ers BY CHUGACH ELECTRIC ASSOCIATION I 30 PO BOX 196300 ANCHORAGE AK 99519-6300 or See SSS SS SS SS SS SSS SSS SSH SE SSS SSSS SSS SHS SSSSSHPeSsSessseresesssressesssesess==ees= MAIN BRANCH TELEPHONE: 907-777-4362 PO BOX 100720 ANCHORAGE AK 99510-0720 DESCRIPTION DEBITS CREDITS DATE BALANCE ie OPREES 6 066.5.565 04460 cmeeken ewawes cscs cess heesines LOFSS/OT DEPOSIT 1039,475.49 10/20/97 1039,475.49 INTEREST 446.97 10/20/97 1039,922.46 INTEREST 146.44 10/20/97 1040,068.90 INTEREST 146.46 10/21/97 1040,215.36 INTEREST 146.49 10/22/97 1040,361.85 INTEREST 146.51 10/23/97 1040,508.36 INTEREST 146.53 10/24/97 1040,654.89 TRANSFER TO BUSINESS ACCOUNT 1106061 194,093.43 10/27/97 846,561.46 INTEREST ; 412.54 10/27/97 846,974.00 INTEREST 119.50 10/28/97 847,093.50 INTEREST 119.52 10/29/97 847,213.02 INTEREST 119.54 10/30/97 847,332.56 INTEREST 119.56 10/31/97 847,452.12 BALANCE (THIS) STATEMENT, clecie cio cic cronies cisiciolsle sfelieis eicisis etejsic cc cre) LOSSL/97 847,452.12 TOTAL CREDITS (12) 1,041,545.55 TOTAL DEBITS (1) 194,093.43 TAX ID NUMBER 92-0014224 INTEREST THIS STATEMENT 2,070.06 INTEREST PAID 1997 2,070.06 - END OF STATEMENT - CHUGACH ELECTRIC ASSOCIATION, INC. Anchorage, Alaska 14-Nov-97 R E Cc E | V E D NOV 78 1997 TO: Dora Gropp - Manager, Transmission & Special Projects TRANSMISSION & ' SPECIAL PROJECT FROM: Kimberly Pond, Plant Accountant Ke 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 October 1997. Direct Labor 6,293.83 Indirect Labor 2,426.59 Power Engineers Invoice # 47385 2,850.04 Power Engineers Invoice # 47386 61.32 Power Engineers Invoice # 47387 58.65 Power Engineers Invoice # 47388 141,782.09 Power Engineers Invoice # 47389 39,323.79 Power Engineers Invoice # 47390 10,176.11 Power Engineers Invoice # 47391 9,414.82 Power Engineers Invoice # 47392 6,522.60 Power Engineers Invoice # 47393 3,909.35 USDA Rural Utilities Services 36,000.00 Dora Gropp's Expense 14.00 Sub-Total $258,833.19 General, Administrative & Construction Overhead (0.5%) 1,294.17 Total Charges —__ $260,127.36 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: hove K. f£ Kp WE /27 KP/kp WOfiles/E9590081 Attachments #:; CTOO1OR1 WORK SOURCE £9590081 482. PO ' 8 NS! —9590081 104825 POWER ENGINEERS CON95-208 E—9590081 104826 PROF SVCS POWER ENGINEERS CON95~-208 4827 PROF SVCS POWER ENGINEERS 4 CON95~208 col £959008 1 105174 PROF SVCS POWER ENGINEERS CON95-208 GLOO2 SOURCE ID TOTAL 243,365.76- PAY PER. ENDING 09/28/97 PER. ENDING 574264414 DIRECT LABOR 57: £9590081 1862000001 7690 £9590081 PYBWK 574667013 BI-WEEKLY PAY PER. ENDING 09/30/97 DIRECT LABOR 105.87 1862000001 7690 £9590081 PYBWK 574667013 BI-WEEKLY PAY PER. ENDING 09/30/97 DIRECT LABOR 1862000014 7690 £9590081 PYILA ILCD ADMIN ADMIN ILCD 100397 1,002.31 1862000014 7690 £9590081 PYILA ILCD ADMIN cpus ILCD 101797 385.24 s i erere ca 1862000014 7690 §E9590081 PYILB ILCD UNION UNION ILCD 100897 66.15 1862000014 £959008 1 UNIO! —959008 1 WORK ORDER TOTAL 177,660. 36- DUN AND BRADSTREET HR: M SYSTEM REPORT 946 WORK ORDER CHECK EMP # NAME MAJOR CENCC NUMBER TASK DEPT HOURS AMOUNT DATE W/O TOTAL E9590081 TOTAL 148.00 6033.96 M SYSTEM OUN AND BRADSTREET PORT 944 ACCOUNT WORK ORDER CHECK EMP # NAME MAJOR MIN CE CC NUMBER TASK DEPT HOURS AMOUNT DATE itis W/O-TOTAL E9590081 TOTAL 13.50 259.87 hug ach Check Request lectric Attach (Mise Semperting Documentation — ing Documentation ASSOCIATION, INC. ATTACHMENTS TO (Mise Semperting Documentation — WITH CHECK PAGES | DATE CHECK IS REQUIRED | REQUESTED BY: October 2, 1997 10/10/97 DATE Annalisa Williams PURPOSE OR REASON FOR CHECK / SPECIAL INSTRUCTIONS For Rural Utilities Services for "EVAL" phase of cooperative aqreaeti fis 31-018) < on the Southern Intertie Project, Phase IB. 42d es SSS ee ae ACCOUNTING fr TS PAYABLE ATTACHMENT A SUMMARY OF PROJECT COSTS AND APPROVAL MECHANISMS ENVIRONMENTAL IMPACT STATEMENT: The preparation of the Environmental Impact Statement (EIS) will require contractor assistance. RUS has established contractual vehicles which may be easily utilized to meet the needs of the Southern Intertie Project. RUS recommends that the IPG agree to use these previously competitively awarded contracts. In order to maintain fiscal accountability and allow the costs of the EIS to be negotiated in a fixed priced environment, the contract will be broken up into two task orders. The first task order will involve a review of the completed scoping process. The follow-on or second task will be the preparation of the EIS document. General activities for each task order are as follows: Environmental Analysis (EVAL) Phase ; 1. RUS develops Statement of Work and Independent Government Cost Estimate for Scoping Phase. Submits to IPG for review and approval of funds. IPG submits to RUS authorization to proceed. RUS initiates procurement action and negotiates final cost with contractor. Upon successful completion of negotiations, RUS informs IPG of final cost. IPG transmits funds to RUS specified account. Task order is awarded. 2. RUS conducts a site visit to the project area with the contractor that will include a briefing by the IPG and its consultants and meetings with representatives from the cooperating agencies. Participate in two community working group meetings in the project area. 3. Contractor reviews the Scoping Report and primary sources of scoping inputs for compliance with applicable NEPA and RUS regulations as well as adequacy in identifying and addressing the scoping issues. 4. Contractor reviews the IPG consultants prepared draft EVAL and develops comments and recommendations. Contractor assists RUS in discussions with the IPG consultants and cooperating agencies to resolve comments on the draft EVAL and the subsequent final document. Estimated cost and time necessary for completion: $36,000; 3 months from task order award. EIS Preparation Phase 1. RUS develop Statement of Work and Independent Government Cost Estimate. Procedures follows item number 2 above. 2. Contractor prepares draft EIS from the EVAL. Two formal in-progress review meeting will be held in Washington, DC during preparation and prior to publishing the draft EIS. 3. Draft EIS will be published for public review and comment for 45 days. During this review period public meetings will be held in Anchorage, Alaska and Washington, DC to solicit public review comments in compliance with the requirements of the Alaska National Interest Lands Conservation Act. 4. RUS, the cooperating agencies, IPG and contractor will review comments and develop responses for inclusion, as necessary, in the final EIS. The final EIS will be published for 30 days. 6. Upon completion of public comment period, RUS and the cooperating agencies will issue a Record of Decision. bal Estimated cost and time necessary for completion: $60,000 to 80,000 (dependent upon issues to be considered); 12-14 months from task order award. Point-of-contact: Lawrence R. Wolfe Senior Environmental Protection Specialist Rural Utilities Service - Engineering and Environmental Staff Mail Stop 1571 1400 Independence Ave., S.W. Washington, D.C. 20250-1571 Telephone Number: (202) 720-5093 Fax Number: (202) 720-0820 Cooperative Agreement No. RUS-97-16 COOPERATIVE AGREEMENT BETWEEN THE RURAL UTILITIES SERVICE AND — INTERTIE PARTICIPANTS GROUP FOR THE SOUTHERN INTERTIE PROJECT ENVIRONMENTAL IMPACT STATEMENT I iucti - The U. S. Department of Agriculture, Rural Utilities Service (RUS) plans to initiate an Environmental Impact Statement (EIS) as part of its evaluation of an application for financial assistance by Golden Valley Electric Association, and the Homer Electric Association. The two RUS borrowers, participants in the Southern Intertie Project with five other electric utilities, are collectively known as the Intertie Participants Group (PG). The IPG are proposing to construct an electric transmission line from a location on the Kenai Peninsula to a location in or near Anchorage within the State of Alaska. Several alternative locations for each terminal are being considered,.as well as three distinctly different alternative routes ranging in length from approximately 60 miles to over 100 miles. The two borrowers may apply to RUS for financing assistance for their combined 28 percent share of the proposed project. RUS is serving as the Lead Agency for the preparation of an EIS on the proposed action, as announced in the Federal Register on October 9, 1996. The US Fish and Wildlife Service and the US Forest Service are cooperating agencies. The purpose of this Cooperative Agreement (Agreement) is to improve the coordination and effectiveness of activities necessary to successfully develop an EIS that is being prepared pursuant to the National Environmental Policy Act (NEPA) by the Rural Utilities Service (RUS) with the support and cooperation of the IPG, as represented by Chugach Electric Association, Inc. The parties to this Agreement, recognizing the benefits of mutual cooperation in the preparation of the EIS, hereby agree to coordinate their resources and otherwise cooperate to the extent necessary to further the evaluation of the application to RUS. This Agreement describes the responsibilities agreed to by RUS and the IPG with respect to activities necessary to support the preparation of the EIS. This Agreement is entered into pursuant to the Federal Agriculture Improvement and Reform Act of 1996, Section 759A, Cooperative Agreements. Intertie Partici G The IPG and its consultants agree to provide administrative assistance, as necessary, to RUS for any and all activities in the coordination and preparation of the environmental review requirements being performed for the Project. Activities include, but are not limited to: planning, public meeting support, public notification coordination, and procurement and budgetary support, and serving as an administrative liaison to the applicants, and State of Alaska government agencies. In support of this Agreement, the IPG through Chugach agrees to contribute, on a mutually agreed basis, funding for the preparation of the EIS for the Project. Overall proposed project costs and approval mechanisms are enclosed as Attachment A. Funds shall be handled through a payment mechanism mutually agreed upon by both parties. Upon execution of this Agreement, the payment mechanism will be further described and included in this Agreement as an exhibit. Rural Utilities Servi The RUS agrees to provide assistance to the IPG within the context of complying with the requirements of the NEPA and in the preparation of the EIS for the Project. RUS agrees to provide: 1) 1) technical support for all activities consistent with its authority and capacity as Lead Agency, as agreed to in the Memorandum of Understanding enclosed in Attachment B. This agreement has been executed among the IPG, cooperating agencies and RUS in accordance with 40 CFR §1501.5, Lead agencies; 2) all supervisory, technical, and administrative support, to include budgetary and procurement support, for all contractor activities; and 3) all technical support in all interactions with any regulatory agency and for public involvement activities. This Agreement shall be terminated automatically when the Record of Decision is signed or may be canceled by either party upon 30 days written notice to the other party. The signatories hereby certify that they have the authority to enter into said Agreement and by doing so agree to the responsibilities outlined above. Sic Sul Anuaw.A Lb ka LONG THO! ON Norman NormanL. Story = 4 La Under Secretary General Manager Rural Development, Homer Electric Association, Inc. U. S. Department of Agriculture 14-4 _ 9/5/87 Date . A. Eu; . Bjo General Manager Chugach Electric Association, Inc. DLE L97 Date i, Business Expense Report Subtotals (cols. A- Chugach Direct j credit Billed to | Employee | Expenses card Chugach Cash .F-| Account # (14) Work Order (10) Explanation (make daily entries) 10/14/97 Airfare E9590081 | 18620 000 04 7690 10/14/97 Cab Service E9590081 | 18620 000 04 7690 10/14/97 Parking at AIA E9590081 | 18620 000 00 7690 expense (detail) Date Total expenses by category: Ee : c D eC 2 $0.00 $0.00} $137.00] $14.00 $137.00 Business purpose: Southern Intertie presentation at Homer |Less cash advance (attached travel authorization) $0.00 | . o Electric’s Board of Director meeting. RECEIVED Balance Due BlEmployee $14.00 | O company (check attached) 0 att 2 oct 17 1997 TEs AGCTS PAYABLE w aT eae ‘Form No. 532 Mail original approved copy to Accounts Payable CHUX CAB 235-2489 24 Hour Service - All Wheel Drive Vans Charters + Vehicle Delivery - Time Call Pick Up port Service . Sightseeing our ao Driver. Date) o-/ FAID 34 G++ «7904 No. 97-10 PS DT O15-OO0°44 EK 97-10 he DT 14-14 °42EN As++-B,00$ ++ +8008 INVOICE 3940 Glenbrook Drive TOWER Soa P.O. Box 1066 IENGINEERFS ——— JOM 120376-01 TASK 1 SCOPING INVOICE NUMBER: 47385 CONTRACT#: 95-208 P.0.#: INVOICE DATE : 16-oct-i997 BiLL THROUGH DATE : ti-oct-1997 PAGE NUMBER: L CHUGACH ELECTRIC ASSOCIATION 560i MINNESOTA DR. PO BOX 196300 ANCHORAGE. AK 99519-6300 ATTN:MS. DORA GROPP REIMBURSABLE EXPENSES Amount SUBCONTRACTOR EXPENSE 2850.04 TOTAL EXPENSES 2850.04 2850.04 CURRENT CHARGES 2850.04 GUTSTANDING INVOICES Date Amount Paymente Open oe” 17-sep-1997 3607.14 0.00 3607.14 \& A re af \ ¥ *Public Involvement $2,850.04 iw \ *Lands/Regulatory $ 0.00 \ | *Included in Invoice Total KLE £AEAOUE| Fucd BO HI >: AU ‘ z (ha+ tr tat oe QoS Oct 50)! / eet a7 — ee @ For any accounting questions please contact Ginaveve McGraw at (208)788-O0311. For any other questions please contact Randy Pollock. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 1%% PER MONTH. ay DOWER GINEERS JOR = 120376-02 TASK 2 {NVENTORY CONTRACT#: 95-208 P.O.#: : INVOICE Seana el saneian aise eerereiel [all Glannciaineeraaneetn Ramininnenininnatoncnecceenantanecrear nae 3940 Glenbrook Drive P.O. Box 1066 Hailey, Idaho 83333 (208) 788-3456 INVOICE NUMBER: 47386 INVOICE DATE : i6-act-1997 BILL THROUGH DATE : lit-oct~-1997 PAGE NUMBER: 1 CHUGACH ELECTRIC ASSOCIATION S60L MINNESOTA DOR. PG BOX 196300 ANCHORAGE, AK 99519-6300 ATTN:MS. DORA GROPP RE(MBURSABLE EXPENSES Amount SUBCONTRACTOR EXPENSE 61.32: TOTAL EXPENSES 61.32 61.32 CURRENT CHARGES 61.32 | OUTSTANDING INVOICES Date Amount Paymentea Open eo L7-sep~-1997 20972.793 0.00 20972.79 Nj in S “we Py 9? *Public Involvement $61.32 if a , *Lands/Regulatory $ 0.00 K jn *included in Invoice Total Al [A 4 a ALB EI nC [ACO ca HOI : T= Sere OF. , 90,1999 @ For any accounting questions please contact Ginaveve McGraw at (208) 788-0311. For any other questions please contact Randy Pollock. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 142% PER MONTH. INVOICE s 3940 Glenbrook Drive SY P.O. Box 1066 ww) Hailey, Idaho 83333 NGINEERS = 3 + 120376-03 TASK 3 IMPACT ASSESS/MITIG PLN INVOICE NUMBER: 47387 CONTRACT#: 95-208 P.O.#: INVOICE DATE : i16-oct-1997 BILL THROUGH DATE : Li-oct-1997 PAGE NUMBER: 1 CHUGACH ELECTRIC ASSOCIATION S601 MINNESOTA DR. PO BOX 196300 ANCHORAGE. AK 99519-6300 ATTNW:MS. DORA GROPP PROFESSIONAL SERVICES * Hours Rate Amount McGraw. Ginaveve 1.00 53.55 53.55 TOTAL LABOR 1.00 53.55 53.55 REIMBURSABLE EXPENSES Amount SUBCONTRACTOR EXPENSE 5.10 TOTAL EXPENSES 5.10 5.10 CURRENT CHARGES $8.65 QUTSTANDING INVOICES Date Amount Paymente Open 46822 {7-sep-1997 49174.24 9.00 49174.24 A |r ur Ala by A\B A gt AA eave | [8630 COO Fle FC: o (4. 30,45 Public Involvement $0.00 Lands/Regulatory $0.00 For any accounting questions please contact Ginaveve McGrau at (208)788-O0311. Fer any other questions please contact Randy Po! lock. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 1%% PER MONTH. INVOICE 4 i ~~ ¥ iG 3940 Glenbrook Drive Y M P.O. Box 1066 Ey) Hailey, Idaho 83333 IENGINEERS a k 120376-05 TASK S DRAFT EIS INVOICE NUMBER: 47389 CONTRACT#: 95-208 - P.0.#: {NVOICE DATE : 16-oct-1997 BILL THROUGH DATE : il-oct-1997 PAGE NUMBER: . i CHUGACH ELECTRIC ASSOCIATION S601 MINNESOTA DR. PO BOX 196300 ANCHORAGE. AK 99519~-6 AP? ATTN:MS. DORA GROPP . EN Shey, Of /G 7 PROFESSIONAL see ie Lj LO", flours’ Rate ‘Amount Arpp, Liifian “yy D 4 Eft i200 44.10 485.10 Cross. Vicki L * jo /YP25 2.00 61.20 122.40 Hoehner. Karen E fay “1.00 44.10 44.10 Landis, Amy UTP 14.00 61.20 856.80 Lewia. Joel 20.00 61.20 1224.00 McGrau. Ginaveve N | # 9.00 $3.55 481.95 Olson, Meliteasa Cece 1.00 44.10 44.10 Locks Randy £45 ocd C5623: 00 gee a thuarz, Melisea Gr ~-, . ; ' . « . Walbert, Michael BU OCCE C8410, A4F31.00 93.45 2896.95 TOTAL LABOR 125.00 10046.76 10046.70 REIMBURSABLE EXPENSES Amount REPRODUCTION 64.20 PHONE & FAX 150.00 POSTAGE & SHIPPING = 140.71 SUBCONTRACTOR LABOR ; J+ 2223.60 SUBCONTRACTOR EXPENSE os 26698.58 , Ui it TOTAL EXPENSES 29277.09 29277.09 i rE | BS we CURRENT CHARGES 39323.79 OUTSTANDING INVOICES Date Amount Paymente Open 46824 17-sep~1997 10284.09 0.00 10284.09 Public Involvement $0.00 Lands/Regulatory $0.00 For any accounting questions please contact Ginaveve McGraw at (208)788-0311. For any other queations please contact Randy Poliock. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 142% PER MONTH. ea INVOICE 1) Eff 3940 Glenbrook Drive P.O. Box 1066 Hailey, Idaho 83333 ENGINEERS 20S) TER SASS. fan 120376 -06 TASK 6 FINAL EIS INVOICE NUMBER: 473930 CONTRACT#: 95-208 go P.O.#: : ae Ft INVOICE DATE BILL THROUGH DATE PAGE NUMBER 16-oct-1997 :ll-oct-1997 1 CHUGACH ELECTRIC ASSOCIATION S601 MINNESOTA DR. PO BOX 196300 ANCHORAGE. AK 99519-6300 ATTN:MS. DORA GROPP PROFESSIONAL SERVICES Hours Rate Amount Pollock, Randy 32.00 110.25 3528.00 TOTAL LABOR 32.00 3528.00 3528.00 REIMBURSABLE EXPENSES Amount VEHICLE 72.35 MEALS 29.20 IDGING & RENTS f 414.86 iONE & FAX . Sant 28.54 SUBCONTRACTOR EXPENSE a : 6005.10 MATERIALS PURCHASE : ; 63.06 MISCELLANEOUS : 5.00 TOTAL EXPENSES 6648.11 6648.11 CURRENT CHARGES 10176.11 OUTSTANDING INVOICES Date Amount Payments Open 46825 17-Bep-1997 441.00 0.00 441.00 \ ia ak ‘ ; 1, : A 4 ve x Public Involvement $0.00 . Ve x. Poe Lands/Regulatory $0.00] ? al A] % AUB ult EGF) Ce | For any accounting questions please contact Ginaveve McGraw (208) 788-0311. [B= OGogar, Werder Cet BG IGaG ETO For any other queations please contact Randy Pollock. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 142% PER MONTH. “ - INVOICE - Que i) 3940 Glenbrook Drive | P.O. Box 1066 | Hailey, Idaho 83333 IENGINEEFIS 208) '788-S468 J 120376-07 TASK 7 SYSTEM STUDIES INVOICE NUMBER: 47391 CONTRACT#: 95-208 P.O. #: INVOICE DATE : i6-oct-1997 BILL THROUGH DATE 11-oct-1997 PAGE NUMBER: 1 CHUGACH ELECTRIC ASSOCIATION S60L MINNESOTA DR. PO BOX 196300 ANCHORAGE. AK 99519-6300 ATTN:MS. DORA GROPP PROFESSIONAL SERVICES Hours Rate Amount Beazer, Ronald E 31.00 99.75 3092.25 . Hansen. Bill 3.00 933.75 897.75 Johngon. Jerry A 12.00 72.45 869.40 a a eee — Karat. Dan 5. .55 Ors) Murphy. Lance C ; » if 2.00 53.55 107.10 Newcomb. David ~ 4 Ss.00 53.55 267.75 " gon, Melieaa 18.00 44.10 793.80 liock. Randy 21.00 110.25 2315.25 TOTAL LABOR 107.006 8825.25 8825.25 REIMBURSABLE EXPENSES Amount REPRODUCTION . 392.99 POSTAGE & SHIPPING iff i a, 21.58 SUBCONTRACTOR LABOR pO 3 : 175.00 - TOTAL EXPENSES 589.57 589.57 CURRENT CHARGES 9414.82 OUTSTANDING INVOICES Date Amount Payments Open 46826 17-sep-1997 1h 3279.15 0.00 3279.15 ‘Atv c 3 2 yf ese F Public Involvement $0.60 / FO weg ot Lands/Kegulatory $0.00 K| ln Al | A | 4 ae GEGOO EE For any accounting duest (Sha lt enwe contact Ginaveve McGraw at_ (208) 788-0311. (7600 UGC CaS —— 20% vt a(, CG 10 For any other questions please contact andy ‘Pollack. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 142% PER MONTH. INVOICE a) 1 3940 Glenbrook Drive P.O. Box 1066 staal Hailey, Idaho 83333 IENGINEEFRIS — ae eects d 120376-08 TASK 8 ENGINEERING FIELD WORK INVOICE NUMBER: 47392 CONTRACT#: 95-208 P.0.#: INVOICE DATE : 16-o0ct-1997 BILL THROUGH DATE ;: it-oct-1997 PAGE NUMBER: 1 CHUGACH ELECTRIC ASSOCIATION - S601 MINNESOTA DR. PO BOX 196300 ANCHORAGE. AK 99519-6300 ATTN:MS. DORA GROPP | PROFESSIONAL SERVICES: Hours Rate Amount Hansen, Bill 55.00 99.75 $486.25 Kuemmerer. Uta K 1.00 44.10 44.10 Pollock. Randy 9.00 110.25 992.25 TOTAL LABOR 65.00 6522.60 6522.60 Public Involvement $0.00 Lands/Regulatory $0.00 i fio: « Pe - I For any accounting questions please contact Ginaveve McGraw at (208)788-0311. For any other queations please contact Randy Pollock. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 1% PER MONTH. 1#) , : INVOICE e \ 3940 Glenbrook Drive Y P.O. Box 1066 x Hailey, Idaho 83333 IE NGINEERIS aD Ebeasar A 120376-09 TASK 9 PRELIM ENGINEERING INVOICE NUMBER: 47393 CONTRACT#: 95-208 P.O.#: INVOICE DATE BILL THROUGH DATE : 16-oct-1997 11-oct-1997 PAGE NUMBER 1 CHUGACH ELECTRIC ASSOCIATION 5601 MINNESOTA DR. PO BOX 196300 ANCHORAGE, AK 99519-6300 ATTN:MS. DORA GROPP PROFESSIONAL SERVICES Hours Rate Amount Alexus, Tom 8.00 72.45 579.60 “ Hansen. BiIlL 10.00 39.75 997.50 Joyner, Linette 5.00 53.55 267.75 Newcomb, David 18.00 53.55 963.90 TOTAL LABOR 41.00 2808.75 2808.75 es EXPENSES Amount ALS 36.00 NGINEERING WORKSTATION 60.00 PHONE & FAX 53.00 POSTAGE & SHIPPING 138.06 SUBCONTRACTOR LABOR _ 749.70 SUBCONTRACTOR EXPENSE 45.57 MISCELLANEOUS | * 18.27 o ‘a & i ees TOTAL EXPENSES 1100.60 1100.60 CURRENT CHARGES 3909.35 OUTSTANDING INVOICES Date Amount Paymente Open 46828 17-sep-1997 A oe ‘9.00 36655. 83 “i Yee a i ACY Pete ee eran a ifpy 5 in 7. Public Involvement $0.00 i/ H Lands/Regulatory $0.00 _ ‘ Sia aL] A ‘[O/ _ AIA ECGLCE! For any accounting questions please rg meee MeGraw __ G53, at (208) 788-0311. OOO LO0CATYGU 0-308 Os. Bo JIG For any other questions please contact andy Pollock. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 1%2% PER MONTH. ey ee INVOICE , =~ | = NT eee Se 3940 Glenbrook Drive : P.O. Box 1066 hy JME Hailey, Idaho 83333 IENGINEEFRTS 208) ree-stee 3 120376-04 TASK 4 ALTERNATIVE SELECTION INVOICE NUMBER: 47388 CONTRACT#: 95-208 P.O.#: INVOICE DATE : 16-oct-1997 “BILL THROUGH DATE : !1-oct-1997 PAGE NUMBER: 1 CHUGACH ELECTRIC ASSOCIATION S601 MINNESOTA DR. PO BOX 196300 ANCHORAGE. AK 99519-6300 ATTN:MS. DORA GROPP PROFESSIONAL SERVICES Hours Rate Amount t Bobbitt, Michelle 2.00 44.10 88.20 Crogas, Vicki L 4 VA 1.00 61.20 61.20 Givens. Shirley anh {3.00 44.10 132.30 Kuemmerer. Uta K , 2 1.00 44.10 44.10 McGraw. Ginaveve . we 7 18.00 $3.55 963.90 Olaon. Meliaea “a g¢ Z| a .°F.00 44.10 308.70 Pollock. Randy \¢ wit 32.00 110.25 3528.00 “ohwarz, Melissa : Ue Ay 1.00 32.55 22.55 ilbert. Michael E 82.00 93.45 7662.90 TOTAL Ty ae 12821.85 12821.85 A RE{MBURSABLE EXPENSES Amount AIRFARE 564.80 VEHICLE 472.75 MEALS 154.11 LODGING & RENTS 453.60 REPRODUCTION : 85.60 PHONE & FAX pe Ee life 201.39 POSTAGE & SHIPPING fez 61.61 SUBCONTRACTOR EXPENSE N j ya 126966. 38 E00 x TOTAL EXPENSES 128960.24 128960.24 TT | ee x 10 COOP HG0 2 ttt taanne Ons... CfARREWT CHARGES 141782.09 SO NITG OUTSTANDING INVOICES Date Amount Paymente Open 46823 17-aep-1997 59359.68 0.00 59359.68 *Public Involvement $13,538.26 *Lands/Regulatory $ 0.00 *Included in Invoice Total For any accounting questiona please contact Ginaveve McGrau at (208)788-O311. For any other queations please contact Randy Pollock. TERMS: NET 30 DAYS FROM RECEIPT OF INVOICE. PAST DUE AMOUNT SUBJECT TO FINANCE CHARGE OF 1%2% PER MONTH. Report for the Month of November 1997 W.0.#E9590081 Southern Intertie -- Phase IB November 25, 1997 Il. SCHEDULE CHUGACH -___ “RIC ASSOCIATION 3 ANCHORAGE - .._. .Al INTERTIE 11/18/97 PHASE IB 1995 1996 1997 1998 1999 2000 2 ID _|Task Name % Comp. | __Act. Cost Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3} Q4] Q1 | Q2 | Q3 | Q4{ Q1 | Q2 | Q3 | Q4] Q1 | Q2} Q3} Q4/Q1 | Q2 1 | ENVIRONMENTAL & ENGINEE 50% | $3,774,604.57 (Qe ne ee i : 2 PROJECT MANAGEMENT 27% $108,007.20 | 45 vee i : Bl sis 3 ROUTE SELECTION STUD| 100%| — $871,650.00 4 EIS & PREL.ENGINEERIN -78%| $2,717,193.37 onih SCOPING 100%| $375,997.34 6 “INVENTORY 97%| — $659,981.25 7 IMPACT/MITIGATION 100% | $607,560.00 8 ALTERN.SELECTION | 100%| $335,392.00 9| _‘DRAFTEIS 56%| $253,529.92 10 FINALEIS 4% $9,903.28 "1 STUDIES 83%| $84,225.02 12 ENG.FIELD WORK 100%| $202,645.44 3 PREL. ENGINEERING 99%| $187,959.12 14 AGENCIES 28% $77,754.00 | (Pere emer EY 15 "USFS 20% $34,954.00 16 USFWS 50% $6,800.00 17 RUS 10%| $36,000.00 Task SCO summary Qe koled Up Progress Project: ANCHORAGE - KENAI INTE Re Ee Date: 11/18/97 Progress Rolled Up Task Milestone Sa Rolled Up Milestone <> C:\DATA\PROJMGR\SOUTHTIE\PH_IB.MPP Page 1 Report for the Month of November 1997 W.0.#E9590081 Southern Intertie - Phase IB November 25, 1997 Iv. ITEMS FOR APPROVAL ile DFI’s Draft Update and Reevaluation of Benefits for the Southern Intertie (November 1997) IV-1 Report for the Month of October 1997 W.0.#E9590081 Southern Intertie - Phase IB October 29, 1997 IV. ITEMS FOR APPROVAL None. IV-1 Decision Focus Incorporated - Confidential Update and Reevaluation of Economic Benefits of Southern Intertie Project Prepared by: Stephen Haas Ralph Samuelson Decision Focus Incorporated 650 Castro Street, Suite 300 Mountain View, California 94041-2055 (650) 960-3450 Prepared for: Power Engineers Incorporated 3940 Glenbrook Drive Hailey, ID 83333 November 1997 Cen -e: 0, S¥SF00G/ R2947a TABLE OF CONTENTS Section Page 1.0 Introduction and Summary do. 1.2 13 14 2.0 Benefits Estimation Methodology Dt 22 2.3 2.4 Spinning Reserve Sharing 2.5. Reduced Maintenance Costs for Existing Anchorage-Kenai Line...........7 2.6 | Avoiding Minimum Combustion Turbine Generation OMNES eral erercessesectessteecrstccracueneerarereassecscvesseasrsvassensseestsenseserssraastressrectversercastra 7 2.7 Avoiding Not Loading the Existing Line During Bad Weather and Comnstruction......ssssscsssssssneesssneessneseenneesesneesenne 7 3.0 Updates Of Key (Data Items -reecccssstcrzccrssnsseasscesanscaseasconssecscasecesssesensseveevecerscesseeseetteesevesee 8 3.1 DeemmannG FOre casts csssecesesacvesscesonvsscarsscnsssnscrrsssvessrvsssuvsorvosvacsssoverorserascyevsrergsserst? 8 3.2 Generating Capacity: Planned Additions and Retirements ...........-++: 8 3.3. Cost of New Combustion Turbine .........ssssscssssssssnescesnsesssneeesenseesnneessnneessneses 9 3.4 Bite) Price escsseseecnssseesscseesovssane orvasvacssevssresstsereuresvissevseseessergesvavesereecaerecerereeraztees 9 3.5 —_ Existing Transmission Capacity......ssssssssssssssnsssessnsesnneessnesensecneccnsessneesneess 10 S61) evel of Customer, Outages lrerccccescenesensenseete.trersreresrossetrstrecerrareet=croreserseraresea 10 B:7———- Walure (ofial Gustomier Outage <scssnccssssscscnssezcssccacssssanessvansesesasssecnnsccncserercscronese at ES OB Decision Focus Incorporated - Confidential R2947a Page INe@w: Datta Tera ns rs csarccaracecancosvcsveczsnctsssesscasesensccnssrnscsancesnesensseonzesuessevescenssseessnosoewsscesse 11 4.1 Cost of Maintaining Minimum Generation on the Kenai... 11 4.2 Frequency of Zero Line Loading Conditions .........ssssssssssscssssessneessnneees al 4.3 Cost of Zero Line Loading ........sesccssssssnsscsnecseneccsneessaseccenneessencessnecsenneeeees at Decision Focus Incorporated - Confidential R2947a iii LIST OF TABLES Table 1 Net Present Value of Benefits of Proposed SIP eh FP iO 2 Comparison of Peak Demand Forecasts for 2010..... 3 Comparison of 1997 Fuel Price Forecast with Actual Prices......... ae) Decision Focus Incorporated - Confidential R247a 1.0 Introduction and Summary 1.1 Background In 1989 Decision Focus Incorporated (DFI) carried out an economic analysis of the benefits of several proposed transmission line upgrades or additions in the Railbelt area of Alaska. The results of the analysis were documented in a December 1989 report entitled “Economic Feasibility of the Proposed 138 KV Transmission Lines in the Railbelt”. One of the lines studied in the 1989 analysis, the Southern Intertie Project (SIP) between Anchorage and the Kenai Peninsula, 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 what changes have occurred in the years since 1989, and whether they would alter the conclusions of the analysis. The December 1989 report estimated benefits of a new Kenai-Anchorage transmission line in seven different categories: Capacity sharing Economy energy transfer Reliability Transmission losses Maintenance of existing line Operating reserve sharing State revenue from gas royalty and severance taxes NSS Shi The update 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. Finally, two new categories of benefits were identified and quantified. 1.2 Updated Benefits Estimates Table 1 summarizes the conclusions of this update. The dollar values shown are the net present value of benefits in each category over the expected 40-year life of the new transmission line. In 1989 the line was expected to come into operation in 1994, so the 1989 benefits values are for the period 1994-2033 with the present values in 1994; the line is now planned to come into operation January 1, 2004, so the benefits values are for the period 2004-2043 with the present value in 2004. The December 1989 study calculated benefits for two cases representing different capabilities of the existing Kenai-Anchorage line, because it was not clear at the time how that line would be operated after the Bradley Lake Hydro facility began operating. Case 1 assumed the existing line would be rated at a maximum of 70 MW input and 61 MW output, while Case 2 assumed 90 MW input and 75 MW output. Because Case 1 corresponds to how the line is now operated, all the 1989 values shown in Table 1 are for Case 1. Decision Focus Incorporated - Confidential R2947a The first challenge in comparing 1989 estimates with current estimates is to make sure that the numbers are all based on the same year’s dollars; this eliminates the effects of inflation that make a dollar today worth less than a dollar 7 or 8 years ago. DFI’s 1989 benefits study expressed all values in end of 1989/beginning of 1990 dollars. For this update all values are expressed in 1997 dollars. Therefore, before we can compare the dollar values from the previous study to the new information, we have to inflate them so that we can compare old values expressed in 1997 dollars to new values expressed in 1997 dollars. We have used the GNP Price Inflator to convert beginning of 1990 dollars to mid-1997 dollars. With this inflation rate, a value of $1.00 from the December 1989 study corresponds to $1.205 in mid-1997 dollars, which are what is used in this update. Notes: a of & Table 1 Net Present Value of Benefits of New Southern Intertie December December New 1989 Value | 1989 Value Value (millions of | (millions of | (millions Category 1990 $) 1997$) | of 1997$) Capacity Sharing 34.6 41.7 20.9 Economy Energy Transfer 43.2 52.1 37.8 —+__ Reliability 41.0 49.4 49.4 Spinning Reserve Sharing 10.6 12.8 9.3 Reduced Line 5.0 6.0 4.0 Maintenance Costs | | Avoid Minimum CT na na 10.7 Generation on Kenai (*) Avoid Not Loading Line na na 11.4 During Bad Weather/Construction (* Total 134.5 162.0 143.5 Present values in 1994 for 1989 study, and in 2004 for current update. All present values calculated using discount rate of 4.5 per cent, as recommended by Alaska Energy Authority. Values expressed in 1989/1990 dollars converted to 1997 dollars using GNP price inflator. Economy energy transfer includes reductions in transmission losses and gas royalties. (*)/na indicates benefits not considered in 1989 due to different assumptions for system operating parameters prior to Bradley Lake Hydro. Decision Focus Incorporated - Confidential K R2947a The new total benefits estimate is substantial, but is somewhat lower than for the 1989 study, when expressed in the same year dollars, due primarily to lower forecasts of fuel prices, life extension of existing generating units, and a lower cost of new generating capacity. The changes in benefits and the reasons for them are explained in Sections 2 and 3. The biggest reductions are for capacity sharing and economy energy transfer benefits, which are significantly lower for the reasons just listed. However, these reductions are partially offset by the addition of two new categories of benefits not considered in 1989, due to different assumptions about how the system would be operated once Bradley Lake Hydro was in operation. To put the benefits of the proposed SIP in context, it is helpful 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. We should also point out that, in general, we have updated the 1989 calculations rather than redo the entire analysis. In some cases this has led to benefits levels that could be considered too conservative. In particular, some Railbelt utility staff believe that the economy energy and spinning reserve numbers shown in Table 1 are too low. 1.3 Range of Benefits Estimating the future benefits of a project like the SIP is difficult because it depends on numerous factors that can not be predicted or measured with precision, ranging from future fuel prices to how much consumers would pay to avoid an outage to how the Railbelt utilities will choose to operate their interconnected systems in the future. Asa result, there is necessarily a great deal of uncertainty and imprecision in the benefits estimates presented here. The December 1989 study showed a range of values within which the benefits were expected to lie. This review takes the midpoint of that range (for Case 1 existing line capability; see discussion above) as a starting point, but does not try to update the range. This should not be interpreted as a failure to recognize the uncertainty and lack of precision; if anything, the range of possible benefits may be even wider than presented in the December 1989 study. (See page 6-1 of the Railbelt Intertie Feasibility Study - Final Report, prepared by the Alaska Energy Authority, March 1991, for further discussion of this point.) 1.4 Major Changes Since 1989 There are four major factors contributing to the differences between the new benefits estimates and those developed in 1989: 1. Projected fossil fuel prices are substantially lower now, in real terms than projected in 1989. Decision Focus Incorporated - Confidential R2947a 2. The price of new combustion turbine generating units has dropped, in real terms. 3. A number of existing Railbelt generating units that had been scheduled to be retired by the turn of the century or soon after have had their planned operating lives extended. 4. The Bradley Lake hydro facility on the Kenai Peninsula started operating in 1991. Bradley Lake’s size relative to other generating units on the Kenai and relative to the existing transmission line, and the resulting implications for the stability of the electrical system, have required some changes to operating policies for the existing line that were not anticipated in 1989. 2.0 Benefits Estimation Methodology This section outlines the methodology used for calculating the numerical estimates in each category, summarizing the key assumptions and listing the major data items affecting the estimates. 2.1 Capacity Sharing There are two types of capacity sharing benefits: 1. As load grows ina 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, even if only for a limited time. For the Railbelt, the SIP would allow Anchorage to rely on the Kenai Peninsula generation capacity surplus for a greater portion of the Anchorage capacity requirement, thus deferring the need to build new generation capacity in Anchorage. 2. The larger and more interconnected a system, the lower is 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 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. terol Decision Focus Incorporated - Confidential R2947a 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 operation and maintenance cost; this is a standard yardstick for measuring the value of capacity. key data items: Total generating capacity available Peak demand growth Required reserve margin Fixed cost of new combustion turbine 2.2 Economy Energy Transfers There are two primary situations in which this type of benefit occurs. First, it occurs when high cost energy in one area, usually expensive thermal, is displaced by lower cost energy from another area, either hydro or low-cost thermal. Second, it occurs when access to certain kinds of resources, especially hydro, makes it possible to operate thermal units more efficiently even if their total output is unchanged. 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 first situation mentioned above involves 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 electricity) than others. 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. This benefit occurs to a limited extent between Anchorage and Kenai. A far greater benefit occurs from the second situation: improved hydro-thermal coordination. Greater access to Bradley Lake hydro would allow thermal units in Anchorage to be operated for fewer hours, but at higher levels of output where they are more efficient. Whereas the efficiency of a hydro unit varies relatively little with output, operating thermal units at levels well below their maximum capacity reduces their efficiency, sometimes substantially. An additional benefit is closely linked to the first two: in addition to increasing the maximum amount of power that can be transferred between the Kenai and Anchorage, adding a second line reduces the transmission losses associated with such transfers, improving the economics for both situations described above. 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 Decision Focus Incorporated - Confidential R2947a roughly the same percentage increase in economy energy benefits if all fuel prices in both regions 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 re- estimated. key data items: a Fuel price projections a Load growth projections a Transmission losses 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, the duration of the outage, and whether or not customers receive advance notice of the outage. key data items: a Reduction in unserved energy as result of new line a Value of unserved energy 2.4 Spinning Reserve Sharing Spinning reserves provide quick response to failures in the generation and transmission system. While sometimes referred to as “spinning capacity”, maintaining spinning reserves imposes operating costs, not capacity costs. Maintaining spinning reserves improves reliability, but they can be expensive. The hydroelectric capacity on the Kenai can provide a less expensive source for some of the spinning reserves that would otherwise be provided by thermal units in Anchorage. The new transmission line would increase the ability to access these low-cost reserves. key data items: Decision Focus Incorporated - Confidential R2947a a Capacity of existing line and new line a Fuel prices 2.5 Reduced Maintenance Costs for Existing Anchorage-Kenai Line The existing Kenai-Anchorage line is scheduled for incremental line replacement over a multi- year period. A second line would allow the deferral of some of the scheduled maintenance and allow the maintenance to be carried out more cost-effectively. key data item: a Cost savings of greater flexibility in scheduling and carrying out maintenance 2.6 Avoiding Minimum Combustion Turbine Generation on the Kenai Current practice is to maintain a minimum of 25 MW of combustion turbine generation operating on the Kenai Peninsula at all times. With the new transmission line, this practice would no longer be necessary to reduce reliability problems in the existing line trips; whatever generating units could serve load most economically would be used. key data item: a Difference in operating costs between combustion turbines on the Kenai and units in Anchorage 2.7 Avoiding Not Loading the Existing Line During Bad Weather and Construction The existing 115kV Anchorage-Kenai line is at times operated at zero electrical flow, in anticipation of possible storm or construction-related outages. During such periods, higher cost generation sources must be used. The new line would allow power transfers to continue during such conditions, since the second line could continue to transfer power even during an outage of the existing line. key data items: a Frequency of zero loading conditions a Increase in operating costs resulting from not utilizing the existing line Decision Focus Incorporated - Confidential R247a 3.0 Updates Of Key Data Items The major factors that went into determining the various benefit categories in 1989 are: a Demand /load forecasts a Generating capacity: planned additions and retirements and characteristics of each unit Cost of new generating capacity Fuel price projections Existing transmission capacity 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. 3.1 Demand/Load Forecasts Table 2 compares the demand forecast used in the 1989 study with current demand forecasts, by looking at the forecast for the year 2010. Table 2 COMPARISON OF PEAK DEMAND FORECASTS FOR 2010 (MW) Anchorage Kenai Fairbanks 1989 Study Low 403 75 143 Mid 474 96 151 High 511 106 171 Current Update 509 128 256 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. Because of the limited transmission between Anchorage and Fairbanks, this change has little impact on the economics of the new Kenai-Anchorage line. 3.2 Generating Capacity: Planned Additions and Retirements There have been a number of changes since the 1989 study. Life extensions and postponing the retirement of several units, particularly Beluga, result in a substantially higher projection of available generating capacity, reducing the need for new capacity and pushing capacity sharing benefits further into the future. Decision Focus Incorporated - Confidential R2947a 3.3 Cost of New Combustion Turbines A new combustion turbine is assumed to cost $600 per kilowatt installed, with fixed operations and maintenance cost of $9 per kilowatt per year (per discussion with Power Engineers Incorporated, for a unit in the 50 megawatt size range, at an unspecified site; a larger unit at an established site would cost less). Levelizing the capital cost over 20 years at 4.5 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. 3.4 Fuel Prices Lower fuel prices reduce the value of the benefits from economy energy transfers, from reduced transmission losses, and from spinning reserve sharing. However, without detailed system modeling (i.e., determining 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. We can say, however, that if all fuel prices are reduced by some percentage, then the benefits in these categories will go down by about the same percentage. New estimates for benefits in these categories were determined by calculating an aggregate ratio of current fuel price projections to 1989 projections, and then scaling the 1989 benefits by this aggregate ratio. The ratio was calculated by: 1. Obtaining today’s fuel prices 2. Assuming that gas prices would escalate at the same rate as world oil prices 3. Calculating for each comparable year of operation of the new line the ratioof the __ current projected price of gas at two locations (Anchorage and the Beluga generating station) to the price projected in 1989 (for example, the ratio of the gas price now projected for 2004 to the price projected in 1989 for 1994, 2004 and 1994 being the planned first year of line operation now and then.) 4. Combining the ratios for the two locations and for all forty years into a single aggregate ratio, accounting for the fraction of gas used at each location and discounting future years. Following this procedure, the ratio derived was 0.725; i.e., currently projected gas prices for corresponding years of line operation are almost 30 per cent lower than in 1989. The actual reduction is even greater than this, because the gas prices used in the December 1989 study were wellhead prices excluding delivery charges. This update follows the practice used in the 1989 Reconnaissance study, which was to include gas delivery charges in the total gas prices, since this is what is paid by the Railbelt utilities to gas suppliers. To illustrate the extent to which fuel price projections have changed and need to be updated, Table 3 shows the fuel prices projected for 1997 in the 1989 analysis, converts them to 1997 Decision Focus Incorporated - Confidential R2947a 10 dollars, and compares the forecasts to today’s actual prices, which were provided by Anchorage Municipal Light and Power, Golden Valley Electric Association, and Chugach Electric Association. The actual prices today are substantially lower than the forecast, when both are expressed in 1997 dollars. Table 3 Comparison of 1997 Fuel Price Forecast with Today’s Prices [$/million Btu] 1989 Forecast of 1997 1989 Forecast of 1997 Actual Price 1997 Price* Price** Fuel (1990 $) (1997 $) (19 97 $) $1.50 $2.04/2.27 Anchorage North Pole $4.29 $5.16 Chena *gas prices at wellhead **gas prices including delivery charge The December 1989 study assumed that gas prices would escalate at the same rate as world oil prices, because of market linkages between the two fuels and because the contracts between the Railbelt utilities and the gas suppliers directly link the price paid for gas to oil prices. At that time oil prices were expected to escalate about two per cent per year in real terms. For the current update we maintain the underlying assumption, and assume that gas prices will escalate at the same rate as the United States Department of Energy’s Energy Information Administration reference projection of crude oil prices, which is almost exactly one per cent per year, from now until 2020. Because of the difficulty of forecasting prices that far into the future, we have assumed prices remain flat after 2020. 3.5 Existing Transmission Capacity When the 1989 study was carried out, the Bradley Lake hydro plant was not yet in operation, and it was not clear how heavily the existing Kenai-Anchorage line could be loaded, since up to that time there had been little or no need to transfer the levels of power that are now available from Bradley Lake. As a result, two cases for the transfer capability of the existing line were examined in the 1989 study. One case assumed that the line could handle up to 70 MW input, corresponding to about 61 MW after losses; the second case assumed 90 MW input and 75 MW after losses. Current operating policies for the line correspond to the first case, so only that case has been used in this update. , 3.6 Level of Customer Outages Two key assumptions about the impact of the new Kenai-Anchorage line were made in the 1989 study: Decision Focus Incorporated - Confidential hoy R2947a 1 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. Review of these assumptions with Railbelt utility staff indicated that they are still appropriate. 3.7 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 $21 (1997 dollars). 4.0 New Data Items 4.1 Cost of Maintaining Minimum Generation on the Kenai Chugach Electric Association studies project that by 2003 the annual cost of maintaining a minimum of 25 MW of combustion turbine generation in operation at all times on the Kenai will be about $490,000 for the Railbelt utilities as a whole. 4.2 Frequency of Zero Line Loading Conditions Chugach Electric Association staff estimate that without a new line, the existing line will be operated at zero load an average of 20 days per year in the winter due to weather conditions and avalanche danger, and another 20 days per year in the summer due to activities such as construction or other work adjacent to the line. 4.3 Cost Of Reducing Line Loading to Zero Chugach Electric Association studies have shown a cost of $13,000 per day, in added generating costs for the entire Railbelt, from taking the existing line out of service. Decision Focus Incorporated - Confidential R2M7a Report for the Month of October 1997 W.0.#E9590081 Southern Intertie - Phase IB October 29, 1997 V. ITEMS FOR DISCUSSION 1. POWER Engineers’ “Decision Process for Route Selection” of October 29, 1997. V-1 SOUTHERN INTERTIE PROJECT DECISION PROCESS FOR ROUTE SELECTION INTRODUCTION The purpose of this document is to provide assistance to the Intertie Participant Group (IPG) toward selecting a proposed alternative for the Southern Intertie Project (Project). Dames & Moore and Power Engineers, Inc. are currently in the process of preparing the Environmental Analysis (EVAL) for the Project. As the applicant for the Project, the EVAL is the IPG’s document and submittal to the lead Federal agency, Rural Utilities Service (RUS). The EVAL and the identified proposed alternative by the IPG will become the basis for the RUS to prepare the Environmental Impact Statement (EIS) with the assistance of their third-party contractor, Mangi Environmental consultants; and the cooperating agencies, U.S. Fish and Wildlife Service and the U.S. Forest Service. Two alternative routes, Tesoro and Enstar, are investigated in detail in the EVAL and the IPG has to decide which alternative to propose for construction. A draft of the EVAL will be made available to the IPG in mid-November. The EVAL is scheduled to be completed in January 1998, based on comments by the IPG, RUS, USFWS, USFS and other Federal, State, Borough and Municipal agencies. In order to include the IPG’s preference in the final EVAL document, we have prepared this document to assist in the decision. The principle factors to consider in the decision include: Cost Submarine cable operations Regulatory criteria Environmental criteria Community, public and special interest group preferences and issues The following section provides a summary of the regulatory process and how each of the above criteria relate to the Project alternatives. This is followed by more detailed descriptions of the regulatory background of the Project and the cost of the alternative toutes. The EVAL will provide in depth comparisons and discussions of these criteria. SUMMARY The purpose of this summary is to briefly describe both the regulatory processes and criteria that will influence the decision on the IPG’s proposed alternative for the project. Regulatory Process The regulatory process for the Project is driven by two primary and related regulations, including the National Environmental Policy Act (NEPA); and the Alaska National Interest DEN 26-1413(10/29/97)ukk 1 Lands Conservation Act (ANILCA). The extent that the ANILCA regulations would apply will depend on the proposed alternative: if the Enstar alternative is selected, then the ANILCA process will be required in conjunction with the Project Environmental Impact Statement (EIS) prepared under NEPA; whereas, if the Tesoro alternative is selected, then the NEPA process would be the primary regulatory process, and ANILCA would not apply. The relationships between the regulatory processes, NEPA and ANILCA, are illustrated in Figure 1. For the Enstar route, the time frames for the Draft EIS (9 months), Final EIS (3 months), and Record of Decision (4 months) are established in the ANILCA regulations (43 CFR 36.6). It is possible that for the Tesoro route, the overall process could be completed in a shorter time frame since an ANILCA application would not be necessary. Figure 1 is also intended to explain the implications of the regulatory process. If the IPG selects the Tesoro alternative, then the standard NEPA steps would include the preparation of a draft and final EIS, and a Record of Decision (ROD) by RUS. A hearing is not required by RUS, but could be held if requested by the public. From a regulatory perspective the NEPA process for Tesoro would be straight forward and a favorable ROD is considered achievable. In contrast, if the IPG selects the Enstar alternative, the process is far more complex, and the anticipated result is not certain. An ANILCA application would be prepared and submitted with the EVAL. This would trigger both an ANILCA application review and a compatibility determination by USFWS for the portion of the Enstar route that crosses the Kenai National Wildlife Refuge. The details of these steps are described in the following section, Regulatory Background. The ANILCA review and compatibility determination would be conducted to answer the following general questions: e Is there an economically feasible and prudent alternative to routing the Enstar route through the Kenai National Wildlife Refuge? What are the short and long term impacts to the Refuge? Would the impacts affect the purpose for which the Refuge was established? The results of the ANILCA review, compatibility determination, and the findings from the draft and final EIS would be considered together in the RUS and USFWS decisions. At this point in time, the IPG should anticipate that the ROD would be to deny an application for the Enstar route. We have been told by the USFWS Refuge Manager that it would be very difficult to approve Enstar. This is because of the availability of the Tesoro alternative, in an area that was set aside from the Refuge through a boundary shift back from the coast of the Cook Inlet, for purposes of providing a transportation corridor. If the ROD denies the application for the Enstar route, the IPG may appeal the decision to the President. The appeal would be reviewed by the President using the same criteria used to prepare the ROD. If the appeal is denied, the IPG would have exhausted its administrative options, and the only resort remaining would be a suit in Federal court. DEN 26-1413(10/29/97)ukk 2 If Tesoro - RUS Prepares EIS Public Hearing not required but could be held based on RUS decision If Enstar - RUS Public Hearings If ANILCA Application President reviews If Appeal is denied: Prepares EIS *Washington D. C. 5 ] f is denied, IPG may either IPG Appeal: IPG may file suit in Alaska - — accept Tesoro Alternative Decision within Federal Court to t : or appeal the Decision 4 months challenge Decision USFWS ANILCA Application Review USFWS Compatibility Determination RELATIONSHIP BETWEEN REGULATORY PROCESSES - NEPA AND ANILCA SOUTHERN INTERTIE PROJECT EIS Proposed Anchorage to Kenai Peninsula Transmission Line Figure 1 Route Comparison A brief preliminary comparison of the two routes is provided in Figure 2. The criteria, regulatory and environmental issues, submarine cable operations and costs are applied to the Enstar and Tesoro alternative routes. The comparisons are provided on both a local basis with regard to the Kenai Peninsula, Turnagain Arm and coastal zones, and Anchorage areas; as well as a summary of the entire route. The EVAL will provide extensive detail regarding each specific alternative location being considered for Enstar and Tesoro. Figure 2 provides a general characterization of the Enstar and Tesoro alternatives in terms of general preference. Regulatory compliance clearly favors the Tesoro alternatives due to the ability to avoid the Kenai National Wildlife Refuge as well as the Anchorage Coastal Wildlife Refuge and the South Anchorage area. The Tesoro alternatives are also considered environmentally preferable based on consideration for soils, geology, surface water, vegetation, wildlife, existing and planned land uses, and views from residences, recreation areas and travel routes. Cultural resources (history and archaeology) and subsistence uses are not issues in the comparison of alternative routes. The environmental issues are related to potentially significant cumulative impacts to brown bears, and visual impacts to residences, recreation areas and travel. Based on scoping, agency contacts, and the community working group comments, the Tesoro alternatives would be preferred due to the opportunity to minimize environmental impacts. In contrast, submarine cable operations favor the Enstar alternatives over Tesoro. The potential for cable failure during the life of the Project is greater at Point Possession due to slopes, boulders, and hard bottom and tidal conditions, and because it does not appear to be feasible to successfully embed the cables. Cable replacement in future years has been included in an economic analysis, to financially account for the shorter cable life expected for Tesoro, and the results of the analysis are shown in the cost section. Project costs favor the Enstar alternativé. Current cost estimates indicate a first cost differential of about 10% in favor of the Enstar alternative. The life cycle analysis also favors the Enstar route. However, both routes have the potential for increased costs. On the Tesoro route, the outcome of the negotiations with the Pt. Possession group regarding right- of-way across the conveyed lands could increase the cost, in the worst case, by up to $4.1 million. For the Enstar route, the potential for the USFWS to require undergrounding, as mitigation in the area south Burnt Island, could increase the cost of that alternative, in the worst case, by up to $4.7 million. As we move further through the process, the actual impact of these factors on cost will become clearer. A summary of the Project costs, as well as a discussion of these factors are included under Significant Factors Influencing Project Cost. In the south Anchorage area, the cost estimates for the Enstar route currently include undergrounding of certain segments as mitigation, and these costs could increase depending on which route links in south Anchorage might be selected. For example, route links along DEN 26-1413(10/29/97)yukk 3 Kenai Peninsula ALTERNATIVE ENSTAR TESORO ALTERNATIVE Turnagain Arm and Coastal Zones Turnagain Arm and Coastal Zones Kenai Peninsula Anchorage Anchorage Costs | Submarine Cable Operations Regulatory Compliance Environmental Preference *Soils/Geology/Surface Water *Biology - Vegetation/Wildlife *Land Use Visual - Residential/Recreation/Travel Agency Issues Special Interest Group Issues Public/Community Issues Cle Si clojelo/Ole @|'0@'@|' e'e/ @|0;/O/}@/O)]O| summry O!O/]O!]O/]O}0/;/01/O/O1@1O Summary e\eie@ieie/ei\ol\eloO © Most Preferable ew Low to Moderate Preference @ Least Preferable — Not Applicable PRELIMINARY ALTERNATIVE ROUTE COMPARISON OVERVIEW SOUTHERN INTERTIE PROJECT EIS Proposed Anchorage to Kenai Peninsula Transmission Line Figure 2 Klatt Road or Old Seward Highway near Rabbit Creek, if selected, might require additional undergrounding. Conclusion When the regulatory processes and comparative criteria are viewed in their broadest context, the Tesoro alternative would best ensure a favorable ROD in a timely manner. Support could be expected at all levels of government. A decision that selects Enstar would lead to an uncertain outcome both in terms of success and timing. The Point Possession corporation land that is crossed at the north end of the Kenai Peninsula along Tesoro is an issue to be addressed. The Point Possession group is currently trying to sell 4500 acres for $4.1 million. We are exploring their willingness to negotiate a right-of- way rather than having to purchase the entire property, which is their current position, or if possible, condemnation. Worst case, however, would be property acquisition. REGULATORY BACKGROUND The purpose of this section is to provide background information regarding the key Federal regulatory factors that will apply to the decision process for the Project, as outlined in the Southern Intertie EIS Memorandum of Understanding (MOU) between the following entities: e Rural Utilities Service (RUS) - Lead Federal Agency e US. Fish and Wildlife Service (USFWS) - Cooperating Agency e US. Forest Service (USFS) - Cooperating Agency e Intertie Participants Group (IPG) - Applicant Included are discussions on the following topics: e Federal Lands Jurisdiction USFWS Junsdiction Alaska National Interest Lands Conservation Act (ANILCA) ANILCA Appeals Process Alaska Native Claims Settlement Act (ANCSA) Consideration of the following regulatory guidelines and their interrelationships as they apply to the Tesoro and Enstar alternatives will be a central aspect in assisting the IPG in selecting a proposed alternative for the project. Federal Lands Jurisdiction The EIS must be in compliance with the National Environmental Policy Act (NEPA), as implemented by the Council on Environmental Quality (CEQ) Regulations 40 CFR Parts 1500-1508; RUS environmental policies and procedures (7 CFR Part 1794); and the pertinent regulations of the USFWS. Of the current alternative routes under study between the Kenai Peninsula and Anchorage, the Enstar route crosses the Kenai National Wildlife Refuge, which is under the jurisdiction of the USFWS. DEN 26-1413(10/29/97yukk 4 Crossing the Chugach National Forest is not currently under consideration for the Project because the alternative of paralleling the existing Quartz Creek transmission line does not meet the purpose and need for the project and has been eliminated from consideration. Improvements to the Daves Creek Substation will occur in a parcel of state land that is located within the Forest. As a result, the role of the USFS is primarily in a review capacity to track the Project and comment on any indirect impacts to the Forest. USFWS Jurisdiction The Kenai National Wildlife Refuge is a designated conservation system unit that is managed by the USFWS under the Alaska National Interest Lands Conservation Act (ANILCA) (P.L. 96-487). Therefore regulations implementing Title XI of ANILCA apply to the entire Project (43 CFR Part 36). A Title XI Transportation/Utility Systems (TUS) Application would be required if the Enstar alternative route is selected by the IPG as the proposed alternative for the Project. ANILCA Application The regulations and decision process that would be applied to the Enstar alternative route by USFWS are defined in 43 CFR Part 36 - Transportation and Utility Systems In and Across, and Access Into, Conservation System Units in Alaska. In general, criteria applicable to the approval of the Enstar route under ANILCA Title XI require that this alternative must 1) be found “compatible with the purposes for which the Unit (Kenai National Wildlife Refuge) was established” and 2) there must be no “economically feasible and prudent alternative route for the system.” These two criteria imply separate factors that are described below. Compatibility 43 CFR 26.2 defines compatibility as “compatible with the purposes for which the unit was established.” It means that the system (Southern Intertie Project Transmission System - Enstar alternative) “will not significantly interfere with or detract from the purpose for which the area (Kenai National Wildlife Refuge) was established. The determination of “compatibility” is established through a separate formal process that is tied to ANILCA. In addition to NEPA and the ANILCA Title XI Process, the National Wildlife Refuge System Administration Act (16 U.S.C. 668dd-668¢ee) requires a compatibility determination by the Refuge Manager. The USFWS Policy requires the Regional Director’s approval of the manager’s compatibility determination when the proposed action, i.e., Southern Intertie Project, is being evaluated through the NEPA process. The term “compatible use” as defined in Section 5 (16 U.S.C. 668ee) of the Act means a “wildlife-dependent recreational use or any other use of a refuge that, in the sound professional judgment of the Director, will not materially interfere with or detract from the fulfillment of the Mission of the System or the purposes of the refuge.” DEN 26-1413(10/29/97yukk 5 “Wildlife-dependent recreational use’ means “a use of a refuge involving hunting, fishing, wildlife observation and photography, or environmental education and interpretation.” ‘Sound professional judgment’ means “a finding, determination, or decision that is consistent with principles of sound fish and wildlife management and administration, available science and resources, and adherence to the requirements of this Act and other applicable laws.” 1 -National -Witdiife Refuge Manager, Robin We [Ss adv e Kenat Nationa g aQeT, a ised-us (September ti 1997) that the analysis and comparison of impacts of alternatives that occur off the Refuge, i.e., Tesoro alternative, cannot be taken into account in the compatibility determination. The finding is based only on effects to Refuge lands and resources. While the compatibility determination has not been conducted, based on conversations with Robin West it is our understanding that it would be very difficult for the Refuge Manager to find the Enstar route compatible with the Kenai National Wildlife Refuge. One of the reasons is that the Tesoro Pipeline is located in a transportation corridor that was created by pulling the original boundary of the refuge back from the edge of the Cook Inlet to allow for utility and transportation projects, such as the Southern Intertie, to traverse the northern portion of the Kenai Peninsula without conflicting with the refuge. Economically Feasible and Prudent The definition of the term “economically feasible and prudent alternative route” (43 CFR part 36.2) has recently been revised to mean “a route either within or outside an area that is based on sound engineering practices and is economically practicable, but does not necessarily mean the least costly alternative route.” This is a Final rule that was signed September 22, 1997. This rule will now apply to the USFWS decision-making process when reviewing applications under ANILCA Title XI. This recent ruling changing the definition drastically reduces the probability of a favorable decision for the Enstar route. Previously, an “economically feasible and prudent alternative route” was defined as one that would be considered feasible if it is “able to attract capital to finance its construction,” and prudent “only if the difference of its benefit minus its costs (Tesoro alternative) is equal to or greater than that of the benefits of the proposed TUS (Enstar alternative) minus its costs. In summary, if the IPG decides to propose the Enstar alternative, an ANILCA Application to USFWS will be evaluated in conjunction with the NEPA Process. The criteria regarding compatibility and economic feasibility and prudence will be applied to the proposed Enstar route. An independent compatibility review will be conducted by Robin West, Refuge Manager. The Enstar route is not likely to be found compatible, and economic criteria no longer emphasize differences in cost/benefits between alternatives in the decision process. DEN 26-1413(10/29/97)yukk 6 Administrative Appeal Process Under ANILCA According to Section 1106 (a) of ANILCA, if the IPG should propose the Enstar route and file an ANILCA application, and if the application were to be disapproved, the IPG may appeal the denial. Under Section 1106 (a), if each Federal agency (RUS, USFWS) decides to approve the application within its jurisdiction, then the application is approved. RUS would need to decide to provide financing assistance, and USFWS would need to approve the ANILCA application. However, if either agency disapproves the application within its jurisdiction, then the entire application would be disapproved. If the application is disapproved the IPG may appeal the disapproval to the President of the United States. Under Section 1106 (a) (2), if the IPG appeals, the President must decide within four months after receiving the appeal whether to approve or deny the application. To approve the application, the President would need to find that the proposed action would be in the public interest, that it would be compatible, and that there is no economically feasible and prudent alternative. The President also considers the EIS, public and agency comments on the EIS, and findings and recommendations in RUS and USFWS ROD’s. The President’s decision to approve or deny is then published in the Federal Register. Under Section 1106 (a) (4), if the President were to deny the application, the IPG would have exhausted its administrative avenues, and could file suit in any appropriate Federal court to challenge the decision. Alaska Native Claims Settlement Act (ANCSA) The Tesoro route crosses a 4500 acre property at Point Possession that is owned by the Point Possession Native Group. This property was transferred from the Kenai National Wildlife Refuge through the authorization of ANCSA. The process for such an exchange of lands is discussed in 22 (f) of ANCSA. The property, located within the boundaries of the Kenai National Wildlife Refuge, is currently for sale by the Point Possession Native Group. Section 22 (g) of ANCSA explains that when lands such as the Point Possession property are sold, there is a provision that they “remain subject to the laws and regulations governing the use and development of such Refuge.” The land that was conveyed to the Point Possession Group had been in a wilderness designation as a part of the Kenai National Wildlife Refuge. With the restrictions carried through 22 (g), facility siting through this parcel must conform with minimum surface disturbance from facilities or construction impacts. The USFWS has informed us that their solicitor has determined that ANILCA does not apply to lands subject to 22 (g). With regard to right-of-way acquisition, the Point Possession Group has notified Dames & Moore that they are only interested in selling their entire property at a price of $4.1 million. We are trying to explore their willingness to consider right-of-way acquisition rather than acquiring the entire parcel. DEN 26-1413(10/29/97)ukk 7 COST OF THE ALTERNATIVE ROUTES Each of the routing alternatives, Enstar and Tesoro, is composed of various route links which can be combined to form complete routes between the proposed endpoints. To compare the cost of the two alternatives, specific combinations of links have been selected, representing realistic routes which could be constructed. Following Table 1 are additional comments addressing: e Significant Factors Influencing Project Cost e A description of the routes represented by the cost estimates e Notes explaining the various items in the Table Table 1 Summary of Benefits and Costs (millions of 1997 dollars) |___TesoroRoute___|_Enstar Route Submarine Cable 2-3 core | 4-1 core | 2-3 core | 4-1 core | cables cables | cables cables IPW of Project | Benefits Significant Factors Influencing Project Cost The following factors may significantly influence the cost of the alternatives, by increasing the cost estimates by up to the amounts indicated. Tesoro Route - The right-of-way cost of $12,000 included in the estimate for crossing the native conveyed lands at Pt. Possession (Link T5.2, about one mile) is based on a survey of current land values by Land Field Services, Inc. As discussed elsewhere in this document, the conveyed lands, comprising approximately 4500 acres, are currently for sale by the natives. Without more in depth negotiations with the natives it is not known if a partial purchase could be made for a line right-of-way, or in the worst case, if the entire parcel would have to be purchased. The current asking price for the entire parcel is $4.1 million. DEN 26-1413(10/29/97yakk 8 Enstar Route - The route along the Enstar pipeline north of Big Indian Creek to Burnt Island is proposed to be constructed overhead. It may be necessary to underground all or part of this stretch of the route, contingent on mitigation that the KNWR may deem appropriate to mitigate waterfowl or other issues. The total distance from Big Indian Creek north to the transition station near Burnt Island is 4.7 miles (Links E2.1 and MS.1). In the worst case, if it were necessary to underground the line for this entire distance it would add an additional $4.7 million to the cost of the Enstar route shown in the Table. Route Descriptions represented by the Cost Estimates For the Tesoro Route, the link combination selected would begin at Bernice Lake Substation, and proceed north along the east side of the north Kenai Spur Road utilizing single shaft steel poles. There are two airports which would require short distances of underground where the route crosses the end of the runways. Through Captain Cook State Recreation Area (CCSRA), the line would be placed underground parallel to the road through the CCSRA to comply with Section 6(£)(3) of the Land and Water Conservation Fund Act. North of the CCSRA, the line would parallel the Tesoro pipeline and would be composed of steel X Structures north to the Point Possession area, where the line would transition from overhead to submarine cable. The transition station at Point Possession would be located approximately one mile south of where the cable would enter the water, so that where the line crosses the native conveyed lands, the line would be underground in compliance with Section 22g of the ANCSA regulations. The marine route would extend from Point Possession to Point Campbell where a transition from submarine cable to solid dielectric land type cable would be constructed. The line would then be placed underground from Pt. Campbell to Pt. Woronzof Substation, because of the proximity to Kincaid Park and the Anchorage International Airport respectively, and would terminate at the Pt. Woronzof Substation. For the Enstar Route, the link combination selected would begin at the Soldotna Substation and proceed south and east following the existing 69kV line route, which currently extends to the Quartz Creek Substation near Cooper Landing. The existing 69kV line would be rebuilt to operate at 138kV, up to a point about 4 miles east of Naptowne, and a new substation would be constructed at that location with voltage transformation from 138kV to 69kV so that the 69kV connection to the Quartz Creek Substation can be maintained. From that location the line would proceed north through the KNWR paralleling the Enstar pipeline to the north coast of the Kenai Peninsula near Burnt Island. At that point the line would transition from overhead to submarine cable, and would then extend across Turnagain Arm, coming ashore at the Oceanview Park area. Horizontal directional drilling techniques would be used to cross under the coastal wildlife refuge and the submarine cable would then parallel the Alaska Railroad ROW to a point north of Cross Road. At that point an SF6 Gas Insulated (GIS) transition from submarine cable to solid dielectric cable would be installed within a small building (30x30x25H), and due to the proximity of the Flying Crown airstrip, the underground cable would continue north within the railroad right-of-way north to 120 Avenue. At that point the line would transition to overhead single shaft steel pole construction and would continue along the railroad right-of-way, terminating at the International Substation. DEN 26-1413(10/29/97)ukk 9 Notes explaining the various items in the Table Constructed Cost Constructed cost includes those costs associated with the EIS process, preliminary design, detailed design, right-of-way, procurement, and construction of the Project. Internal utility, legal, or financing costs which might be associated with the Project are not included. A 10% contingency has been included in the construction cost estimates. Present Worth Calculations Present Worth calculations are a based on a project life of 40 years and a real discount rate of 45%. The values shown are in 1997 dollars in the year 2004, the first year that the line is scheduled to be in service. Operation and Maintenance (O&M) Costs The present worth costs indicated for each of the alternatives are based on the cost of a representative annual maintenance program for each facility type. In addition, O&M costs for the Enstar route include a $136,000 annual right-of-way payment to the Alaska Railroad. Submarine Cable Replacement Costs Based on the hydrographic surveys conducted for the Project in 1996, marine bottom conditions on the Tesoro submarine crossing between Pt. Possession and Pt. Campbell are such that it was concluded that embedment of the cable would not be feasible, although the cable would be embedded on the shore ends and in the mud flats. The marine bottom conditions on the Enstar submarine crossing from Burnt Island to Oceanview Park are such that it is feasible to embed the cables. Based on experience with the existing cables crossing the Knik Arm, and through discussions with cable installation contractors, it was concluded that the submarine cable life that could be expected on the non-embedded Tesoro crossing would be less than for the embedded Enstar crossing. To reflect this difference in marine conditions for the two crossings, the present worth of the cable replacement costs were calculated. The present worth cable replacement costs shown in the table represent replacement of one three core cable at 17 year intervals for the Tesoro route, and at 30 years for the Enstar route. For the four one core cable alternate, the present worth of the cable replacement costs shown in the table represent replacement of two one core cables at 17 year intervals for the Tesoro route, and replacement of one single core cable at 30 years for the Enstar route. Project Benefits The benefits of the Project are currently being updated by Decision Focus, Inc. Adjusted Benefit/Cost Ratio The adjusted benefit/cost ratio accounts for the $46.8 million State grant for the Project. DEN 26-1413(10/29/97)ukkc 10 Report for the Month of October 1997 W.0.#E9590081 Southern Intertie - Phase IB October 29, 1997 VI. ITEMS FOR INFORMATION I POWER Engineers’ Monthly Report Phase IB - Environmental Analysis, October 15, 1997. VI-1 4) OOM November 17, wool? Ec E! Ve NOV ig D Ms. Dora Gropp 997 Chugach Electric Association SPER SMssioy 5601 Minnesota Drive, Building A PRo, Et Anchorage, AK 99518 Subject: POWER Project #120376 EIS & Preliminary Engineering Chugach Contract #95-208 Monthly Status Report No. 17 For Period October 12, 1997 - November 8, 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 Completion of the Draft EVAL and distribution for comment. e Decision by the IPG on route preference. Invoice Period Overview: completed scoping activities. finalized transition facilities sites. finalized residual impacts and mitigation measures. finalized mapping of impact assessment results. completed alternative route comparison. distributed the preliminary draft EVAL and Map Volume. prepared maps for the draft EVAL. reviewed/compiled text for Chapters 1, 2, 3, 4, & 5 and appendices. received initial comments on the draft Cost Estimate Summary Report. completed the “Decision Process for Route Selection” document to assist the IPG in determining a route preference. Work Planned for the Next Invoice Period: Distribute the complete draft EVAL and Map Volume sections. e e Completion of Decision Focus Benefits Update Report. e Coordinate receiving comments on the Draft EVAL. e Work on final revisions to the Draft Cost Estimate Summary document. HLY 23-401 POWER Engineers, Incorporated 3940 Glenbrook Dr. * P.O. Box 1066 : Phone (208) 788-3456 Hailey, Idaho 83333 Fax (208) 788-2082 Chugach Electric Association November 17, 1997 Page 2 Schedule: Completion of the Draft EVAL has taken longer than expected, due to continuing interaction with the agencies regarding resource issues and the incorporation of those issues into the alternatives comparison process. Detailed interaction with the agencies had been difficult prior to the signing of the MOU in August, and intensive interaction has been ongoing with the agencies since then. It is expected that the Draft EVAL will be completed and sent out on November 18, rather than the November 3 date indicated in last month’s report. We have been in contact with the agencies regarding this delay, and they have indicated that they would still be able to provide their comments by December 18, as is currently scheduled. The January 15, 1998 date for completion of the Final EVAL is in part contingent on the IPG deciding on a route preference by December 18, 1997. The route preference would be declared in the Final EVAL. The current schedule looking forward is: Preliminary Draft EVAL - October 13, 1997 Complete Draft EVAL November 18, 1997 (revised from November 3) Review of Draft EVAL by Agencies Comments on Draft EVAL - December 18, 1997 Final EVAL - anticipated January 15, 1998 Preliminary Draft EIS (PDEIS) - April 15, 1998 Comments on PDEIS - May 29, 1998 DEIS - August 1, 1998 This maintains the schedule for producing the DEIS by August 1998, and is consistent with the completion date for the Draft EIS noted in the Environmental Impact Statement Workplan dated September 1997, which was produced with the agencies along with the MOU. HLY 23-401 ) poueg Chugach Electric Association November 17, 1997 Page 3 Monthly Status Report Issues: Please refer to the Activities Summary attached for work completed and planned for each Task. Specific areas of interest are noted below: Task 5 - Draft EIS (EVAL) The completion of this Task will result in the Draft and Final EVAL documents as noted in the above schedule. The Preliminary Draft EVAL was submitted to Chugach for preliminary review by selected agencies on October 14. The Draft EVAL is expected to be completed and distributed for review in November. Work with Decision Focus, Inc. (DFI) to refine the calculation of Project Benefits and impacts on overall kWh rates has been completed. Task 6 - Final EIS (Same comment as last month’s report) As we have discussed, with RUS bringing Mangi on board to assist them in producing the EIS documents from the EVAL, our work scope for Task 6 will change from our original proposal. As we previously agreed, the trip to Washington DC to brief RUS and Mangi was allocated to this Task. The MOU addresses certain tasks for our Project Team to complete subsequent to completion of the EVAL in January. It will be necessary to revise our Work Plan for this Task, and we will coordinate this with you. Task 9 - Preliminary Engineering The remaining task is to issue the Final Cost Summary Report, which will be an updated version of the Draft Report. Modifications to the various links have been ongoing the last two months, to respond to changes in link distances and required equipment resulting from the siting effort. The cost estimates included in the Draft EVAL reflect these changes. The Final Cost Summary Report will be issued prior to the Final EVAL, scheduled for January. HLY 23401 ) MER Chugach Electric Association November 17, 1997 Page 4 Project Overview: Total Budget $3,295,858 Actual $ Expended (to date) $2,772,284 Actual Remaining Project Budget $ 523,575 The Total Budget includes the addition of $89,487 for Contract Amendment No. 8. Contract Amendment No. 8 is for providing further updates of the 1989 Decision Focus Inc. Feasibility Study. Dora, should you have any questions about this report or any of the backup, please do not hesitate to contact me or Mike Walbert. . cde a Rdndy Pollock, P.E. Project Manager Sincerely, POWER Eng MW/mo cc: PROJECT TEAM HLY 23-401 SOUTHERN INTERTIE ROUTE SELECTION STUDY - PHASE 1 120376-01 PROJECT FINANCIAL SUMMARY NOVEMBER, 1997 INVOICE Project Task 1 Task 2 Task 3 Task 4 L Task 5 Task 6 Task 7 Task 8 Task 9 Total Base Not to Exceed $351,050 $660,706 $584,010 $303,475 $402,570 $247,616 $101,480 $202,655 $189,861 $3,043,423 Budget | : CWG Contract $23,789 $18,885 $22,602 $32,866 $4,904 N/A N/A N/A N/A $103,046 Amendment No. 4 DFI Contract N/A N/A $45,000 $45,000 Amendment No. 5 DFI Contract N/A N/A $11,400 $11,400 DFI Contract N/A N/A $3,502 $3,502 Amendment No. 7 DFI Contract N/A N/A N/A N/A $89,487 N/A N/A N/A N/A $89,487 Amendment No. 8 Total Not to Exceed $374,839 $679,591 $606,612 $336,341 $556,863 $247,616 $101,480 $202,655 $189,861 $3,295,858 Budget Actual Budget $372,861 $644,933 $595,834 $311,833 $142,968 $10,617 $83,533 $197,189 $187,261 $2,547,047 Expended Through Previous Invoice Current Invoice $1,978 $12,141 $10,706 $24,482 $168,703 $345 $403 $5,421 $1,058 $225,237 Amount Actual Budget $374,839 $657,074 $606,540 $336,315 $311,689 $10,962 $83,936 $202,610 $188,319 $2,772,284 Expended Through Current Invoice Remaining $0 $22,517 $72 $26 $245,175 $236,654 $17,544 $45 $1,542 $523,575 Budget HLY 23-401 NOVEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 1 - SCOPING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Scoping e finalized the scoping task. 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 374,839 374,839 0 SCOPE: No outstanding issues. HLY 23-401a 1 NOVEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 2 - INVENTORY DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Inventory e finalized transition facilities sites. 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 679,591 657,074 22,517 COPE: No outstanding issues. HLY 23-401a 2 NOVEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 3 - IMPACT ASSESSMENT/MITIGATION PLANNING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Impact Assessment/ |e finalized residual impacts and _ mitigation Mitigation Planning measures. e finalized mapping of impact assessment results. KEY ISSUES: No outstanding issues. SCHEDULE: No outstanding issues. BUDGET: Contract Amendment No. 4 is included in the budget ($584,010 + $22,602 = $606,612). $ Budgeted $ Expended $ Remaining 606,612 606,540 72 SCOPE: No outstanding issues. HLY 23-401a 3 NOVEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 4 - ALTERNATIVE SELECTION DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS KEY ISSUES: SCHEDULE: BUDGET: SCOPE: HLY 23-401a Alternative Selection e completed alternative route comparison. No outstanding issues. No outstanding issues. Contract Amendment No. 4 is included in the budget ($303,475 + $32,866 = $336,341). $ Budgeted $ Expended $ Remaining 336,341 336,315 26 No outstanding issues. NOVEMBER 1997 INVOICE DESCRIPTION ACTIVITIES SUMMARY TASK 5 - DRAFT EIS ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS KEY ISSUES: SCHEDULE: ‘UDGET: SCOPE: HLY 23-401la Draft EIS distributed the preliminary draft EVAL and Map Volume. prepared maps for the draft EVAL. reviewed/compiled text for Chapters 1, 2, 3, 4, & 5 and appendices. distribute the draft EVAL and Map Volume. No outstanding issues. No outstanding issues. Contract amendments Nos. 4, 5, 6, 7, and 8 are included in the budget ($402,570 + $4,904 + $45,000 + $11,400 + $3,502 + $89,487 = $556,863). $ Budgeted $556,863 $ Expended $ Remaining 311,689 245,175 Contract Amendment No. 8 has been included. Contract Amendment No. 8 is for providing further updates of the 1989 Decision Focus Inc. Feasibility Study. NOVEMBER 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 10,962 236,654 COPE: Chugach Electric Association’s letter, dated September 2, 19997, provided authorization for Power Engineers and Dames & Moore to travel to Washington D.C. for a presentation to RUS and Mangi on the week of September 14, 1997. HLY 23-401a 6 NOVEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 7 - STUDIES DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS KEY ISSUES: SCHEDULE: BUDGET: SCOPE: HLY 23-401a Studies No outstanding issues. No outstanding issues. No outstanding issues. $ Budgeted 101,480 No outstanding issues. e work to incorporate inductive coordination and cathodic protection studies into the Cost Estimate Summary document. $ Expended $ Remaining 83,936 17,544 NOVEMBER 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 202,655 202,610 45 SCOPE: No outstanding issues. HLY 23-401a 8 NOVEMBER 1997 INVOICE ACTIVITIES SUMMARY TASK 9 - PRELIMINARY ENGINEERING DESCRIPTION ACTIVITIES DURING CURRENT PERIOD AND PLANNED FOR NEXT 30 DAYS Preliminary Engineering review comments on the draft Cost Estimate Summary Report. work on final Cost Estimate Summary Report. KEY ISSUES: The Final Cost Summary Report will be issued subsequent to completion of the Draft EVAL, so any changes resulting from the siting work can be included. SCHEDULE: No outstanding issues. ‘UDGET: No outstanding issues. $ Budgeted $ Expended $ Remaining 189,861 188,319 1,542 SCOPE: No outstanding issues. HLY 23-401a 9 POWER Engineers __ Deliverable Tracking System Deliverables by Project Report Printed: Mon, Nov 17, 1997 3:24PM Period Ending: 11/8/97 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 pentane 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(E!S/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 1/31/97 100 1.2.04 Identify scope of issues to be addressed Tim Tetherow 11/1/96 12/31/96 100 1.2.05 Develop Preparation Plan Tim Tetherow 6/24/96 1/15/97 100 1.2.06 Review Preparation Plan Chugach Electric 1/15/97 1/31/97 100 1.2.07 40 Copies of Preparation Plan for ElS Tim Tetherow 2/20/97 = 2/28/97 100 1.2.08 Public Notification for Scoping Meetings Tim Tetherow 10/1/96 10/31/96 100 1.2.09 Conduct/Coordinate Agency Scoping Tim Tetherow 11/4/96 12/31/96 100 1.2.10 Conduct/Coordinate Public Scoping Tim Tetherow 11/4/96 12/31/96 100 1.2.11 1 Meeting Anchorage(public/agency scoping) Tim Tetherow 11/1/96 11/29/96 100 T2412 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: 11/8/97 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 12/31/96 100 A210 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 a2:21 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 qe. 50 Copies Executive Summary Report Revision 1 Tim Tetherow 10/1/96 10/30/96 100 1.2.28 20 Copies Environmental Report Revision 1 Tim Tetherow 10/1/96 10/30/96 100 120376-01-55-01-03 1.3.03 Review Alternatives Tim Tetherow 8/1/96 10/31/96 100 1.3.04 Field Review of Alternatives Tim Tetherow 6/24/96 9/27/96 100 1.3.05 Identification of Alternatives for EIS Tim Tetherow 12/2/96 12/31/96 100 1.3.06 Agency Meeting to finalize Alternatives Tim Tetherow 12/2/96 12/31/96 100 120376-01-55-01-04 1.4.01 Agency Review & Approval of Scoping Rpt Tim Tetherow 9/30/96 1/31/97 100 1.4.02 40 Copies of Scoping Report Tim Tetherow 1/1/97 1/31/97 100 Deliverables by Project Period Ending: 11/8/97 Deliverable Tracking System 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 Milestone Dates Scheduled Review Dates ID Number Description oan ae stat Finish “~°"P 50% Client Final 120376-02-55-02-01 2.1.00 ID Team Mtg(Inventory Results) Tim Tetherow 12/2/96 12/31/96 100 2.1.01 Agency Contacts (Continuing) Tim Tetherow 6/11/96 100 2.1.02 Inventory of Resource Data/Alternatives Tim Tetherow 6/11/96 11/6/96 100 2.1.30 CWG Mtg(Inventory/Assessement Criteria Tim Tetherow 12/2/96 12/31/96 100 120376-02-55-02-02 2.2.01 Compile and Reproduce Inventory Maps Tim Tetherow 10/15/96 11/29/96 100 2.2.02 Provide Associated Data Tables by Route Tim Tetherow 10/15/96 11/29/96 100 2.2.03 Additional Review & Documentation Tim Tetherow 5/7/97 11/20/97 100 120376-02-55-02-03 2.3.01 Identify Number of Parcels for Routes Frank Rowland 8/13/96 11/27/96 100 2.3.01-A 5 Routes Anchorage Frank Rowland 8/13/96 11/27/96 100 2.3.01-B Tesoro Route-Kenai Frank Rowland 8/13/96 = 11/27/96 100 2.3.01-C Tesoro Route - Soldotna (up to 3 routes) Frank Rowland 8/13/96 11/27/96 100 2.3.01-D Enstar Route Frank Rowland 8/13/96 11/27/96 100 2.3.01-E Quartz Creek Route - Kenai Peninsula Frank Rowland 8/13/96 11/27/96 100 2.3.01-F Quartz Creek between Portage & University Frank Rowland 8/13/96 11/27/96 100 2.3.02 ID Owner, Size, Config sub cable landfall sites Frank Rowland 8/13/96 11/27/96 100 2.3.02-A 3 Sites Kenai Peninsula Frank Rowland 8/13/96 11/27/96 100 2.3.02-B 5 Sites north side of Turnagain Arm Frank Rowland 8/13/96 11/27/96 100 2.3.03 ID Owner, Size, Config of t Alternate Substn Sites Frank Rowland 8/13/96 11/27/96 100 nee ne seemed ea te nae een en ma ae ene cenmne ma reeemenatnaeereenerenernenen neem ARNNNR Hin Nemes 3 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 120376-02-55-02-04 2.4.01 Provide Right of Entry for EIS Field Studies Frank Rowland 10/15/96 9/8/97 45 120376-02-55-02-05 2.5.01 Conduct Centerline Surveys Soldotna Area Frank Rowland 5/7/97 =. 11/20/97 0 2.5.02 Conduct Centerline Surveys Bernice Lake Area Frank Rowland 5/7/97 = 11/20/97 0 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 Project: 120376-03 TASK 3 IMPACT ASSESS/MITIG PLN Client: CHUGACH ELECTRIC ASSOCIATION Project Manager: Randy Pollock MIS Project Start Date: 6/10/96 MIS Project End Date: 6/10/97 Task/Subtask Deliverable evn Milestone Dates, | Scheduled Review Dates ID Number Description nae Start Finish ~~"? 50% Client —_ Final 120376-03-55-03-01 3.1.00 Develop Project Description Tim Tetherow 7/22/96 11/8/96 100 3.1.01 ID Team Review of impact criteria, results, mtg Tim Tetherow 1/1197 1/31/97 90 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 = 11/8/96 100 120376-03-55-03-02 3.2.01 |A/MP Site Specific Models Tim Tetherow 10/21/96 11/29/96 100 3.2.02 Impact Maps & Tables Tim Tetherow 10/21/96 2/28/97 100 3.2.03 Develop/Conduct |A/MPP. Tim Tetherow 10/21/96 12/31/96 100 3.2.03-A Define: Potential Direct/Indirect/Cumitv Impacts Tim Tetherow 10/21/96 12/31/96 100 3.2.03-B Define: |nterrelationships(cause/effect)impacts Tim Tetherow 10/21/96 12/31/96 100 3.2.03-C Define: Criteria Definition Tim Tetherow 10/21/96 12/31/96 100 3.2.03-D Define: Determination of Impact Significance 3 Tim Tetherow 10/21/96 12/31/96 100 3.2.04 Preliminary Mitigation Asessement(mitigation ID) Tim Tetherow 10/21/96 12/31/96 100 3.2.05 Review Preliminary Mitigation Criteria Tim Tetherow 11/1/96 11/29/96 100 3.2.06 Review Prel Assessement & Mitigation Plan Randy Pollock 1/16/98 1/31/97 100 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 2/28/97 100 3.2.09 Residual Impacts Determined Tim Tetherow 3/3/97 3/31/97 100 3.2.10 Finalize Results IA/MP Address Cumulative Effects Tim Tetherow 5/1/97 §/30/97 100 Deliverable Tracking System 120376-03-55-03-03 3.3.01 |A/MPP Incorporated into Draft Eval Tim Tetherow 3/3/97 5/30/97 3.3.02 Mitigation Measures incorporated into ROD Tim Tetherow 3/3/97 5/30/97 3.3.03 Agency Review & Approval Tim Tetherow 5/15/97 5/30/97 3.3.04 Review & Approve Selection Criteria Chugach Electric 5/1/97 5/30/97 3.3.05 Review & Approve Preliminary Results Chugach Electric 5/1/97 5/30/97 100 o;}o;o];o Deliverables by Project Period Ending: 11/8/97 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 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 indi Milestone Dates 36 'Com Scheduled Review Dates ID Number Description Stet te Start Finish ~~”? 50% Client _Final 120376-04-55-04-01 4.1.01 Compilation of Impact Data/by Alternative Tim Tetherow 4/1/97 4/18/97 100 4.1.02 Development of Criteria&Rte Comparison Mat Tim Tetherow 4/1/97 4/18/97 100 4.1.03 Two Day Route Comparison Meeting Tim Tetherow 416/97 4/18/97 100 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 5/30/97 100 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 4/30/97 100 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 4/30/97 100 4A Consideration of Public & Agency Comments Tim Tetherow 6/13/97 7/18/97 100 4.1.12 Select Environmentally Preferred Alternative Tim Tetherow 6/13/97 7/18/97 100 120376-04-55-04-02 4.2.01 Newsletter # 2 (Route Selection Results) Tim Tetherow 7/1197 7/31/97 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 8/29/97 100 —— A ee eR ER A ee em Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 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 Deliverable Milestone Dates Scheduled Review Dates Resp Indiv % Comp ID Number Description Start Finish 50% Client Final 120376-05-55-05-01 5.1.01 ID Team Mtg # 4 (Draft Eval Review/Approval) Tim Tetherow 9/1/97 9/30/97 0 5.1.02 Environmental Data Maps Tim Tetherow 2/3/97 9/15/97 100 5.1.03 14 - 8 1/2 X 11 Color Map Photos Tim Tetherow 2/3/97 9/15/97 100 5.1.04 2 - 18 X 30 Color Maps Tim Tetherow 2/3/97 9/15/97 100 5.1.05 23 - 11 X 17 Color Maps Tim Tetherow 2/3/97 9/15/97 100 5.1.06 Develop Purpose and Need Statement Tim Tetherow 2/3/97 9/15/97 100 5.1.07 Prepare Preliminary Draft Eval Tim Tetherow 6/23/97 9/17/97 100 5.1.08 40 Copies (150 pages each) Preliminary Drft Eval Tim Tetherow 9/15/97 9/30/97 100 5.1.09 Distribution of Copies Chugach Electric 9/15/97 9/30/97 100 5.1.10 Review Preliminary Draft Eval Chugach Electric 9/1/97 9/15/97 100 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 Chgs- Preliminary Drft Eval Tim Tetherow 10/31/97 11/21/97 100 5.2.03 Finalize Draft Eval Tim Tetherow 10/31/97 11/21/97 90 §.2.04 Review Draft Eval Lead Agency 11/25/97 12/19/97 0 5.2.05 Review & Approve Draft Eval Chugach Electric 11/25/97 12/19/97 0 120376-05-55-05-03 5.3.01 Provide Lead Agency Signature Lead Agency 1/14/98 3/16/98 0 5.3.02 File with EPA Tim Tetherow 1/14/98 3/20/98 0 5.3.03 Print & Distribute Final Eval Tim Tetherow 12/22/97 1/9/98 0 5.3.04 200 Copies(150 pgs/ea) to Lead Fed Agency (40 cop) Tim Tetherow 1/26/98 1/30/98 0 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 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 1D Team Meeting # 6 (Pre-Hearing) Tim Tetherow 1/1/98 1/30/98 0 5.4.02 Newsletter # 3 (Announce Public Hearings) Tim Tetherow 1/1198 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 §.22.01 Review Comments on SIP Randy Pollock 6/1/97 6/20/97 0 5.22.02 Increased Reliability Randy Pollock 6/1/97 7/25/97 0 5.22.03 Increased Transfers-Econ Energy Randy Pollock 6/1/97 7/25/97 0 5.22.04 Reduced Transmission Losses Randy Pollock 6/1/97 7/25/97 0 5.22.05 Increased State Gas Royalty Randy Pollock 6/1/97 7/25/97 0 5.22.06 Deferral/Avoidance New Generation Cap Randy Pollock 6/1/97 7/25/97 0 5.22.07 Reduced Maintenance Cost Randy Pollock 6/1/97 7/25/97 0 5.22.08 Teleconference-Rvw Project Status Randy Pollock 6/23/97 6/27/97 0 §.22.09 Issue Draft Statement Randy Pollock 7/1/97 7/25/97 0 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 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 Milestone Dates Scheduled Review Dates ID Number Description eer Start Finish re 50% Client Final 120376-06-55-06-01 6.1.01 Newsletter(Announce FEIS) Tim Tetherow 7/1198 7/31/98 0 6.1.02 ID Team Mtg(Rvw Comments) Tim Tetherow 3/20/98 3/31/98 0 6.1.03 Respond to comments Tim Tetherow 3/20/98 4/17/98 0 6.1.04 Prepare PFEIS Tim Tetherow 4/20/98 5/20/98 0 6.1.05 ID Team Mtg(Review PFEIS) Tim Tetherow 5/1/98 5/29/98 0 6.1.06 Agency Review & Approval Lead Agency 5/21/98 6/10/98 0 6.1.07 Review PFEIS Chugach Electric 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 5/21/98 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 10 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 RI RR 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 ad Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 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 pegpinai Milestone Dates % Comp Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-07-22-07-05 7.5.01 Summary Report William Riall 7/15/96 8/14/97 90 7.5.02 Recommend Dsg Parameters William Riall 7/15/96 8/14/97 90 7.5.03 Telephone Contacts William Riall 7/15/96 =: 8/14/97 95 120376-07-22-07-06 7.6.01 EMF Models Larry Henriksen 7/15/96 8/14/97 100 7.6.02 EIS & Prelim Eng Calculations Larry Henriksen 7/15/96 8/14/97 100 7.6.03 Text & Graphs or Charts-ElS Larry Henriksen 715/96 8/14/97 100 7.6.04 RFI/TVI & Audible Noise Analysis Larry Henriksen 7/15/96 8/14/97 100 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 7/15/96 = 8/14/97 90 tt.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 8/14/97 100 120376-07-23-07-01 7.1.01 Determine System Requirements Ronald Beazer 7/1196 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 TI1I96 = 12/13/96 100 12 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 120376-07-23-07-03 7.3.01 Dynamic Stability Analysis Ronald Beazer 7HI96 = 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 12/13/96 100 ——— cee RL LNs eR ASRS 13 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 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 Deliverable . Milestone Dates Scheduled Review Dates 1D Number Description Respindiv = ‘stat 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 10/14/96 100 8.2.06 Assessment of Cable Embedment Opt. William Riall 6/14/96 10/14/96 100 8.2.07 Recommend Prelim Cable Const William Riall 10/1/96 10/14/96 100 8.2.08 Prelim Recommend-Armoring & Install William Riall 10/1/96 10/14/96 100 120376-08-22-08-03 8.3.01 Geotechnical Information Summary Larry Henriksen 11/1/96 1/2/97 0 8.3.02 Review Existing Geotech Data Larry Henriksen 7/1196 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 99 8.4.02 Field Observations-Environ Personnel Tim Tetherow 6/14/96 8/15/97 100 [ST Sea ES A NEES Te RR RI FOE RR ER EE SE RE ET SN A A TT A A SELES BESS SNE 14 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 8.4.03 Field Observations-Eng Personnel Larry Henriksen 6/14/96 8/15/97 100 8.4.04 Identify Propective Centerline Locations Larry Henriksen 6/14/96 = 8/15/97 100 8.4.05 Identify Potential Mitigation Methods Larry Henriksen 6/14/96 8/15/97 100 8.4.06 Identify Most Appropriate Structure Types Larry Henriksen 6/14/96 8/15/97 100 8.4.07 Select Submarine Cable Landfall Locations William Riall 6/14/96 8/15/97 100 8.4.08 Identify Tech or Environmental Challenges Larry Henriksen 6/14/96 8/15/97 100 8.4.09 Note Other Observed Features Larry Henriksen 6/14/96 8/15/97 100 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 8/15/97 100 120376-08-22-08-05 8.5.01 Copies of Summary Field Report Michael Walbert 10/15/96 2/13/98 99 8.5.02 Prelim Submarine Cable Recommendations William Riall 6/14/96 =. 2/13/98 95 8.5.03 Observations & Conclusions Impacting Project William Riall 6/14/96 —- 2/13/98 95 —__ eee SS 15 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 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 a Deliverable Rapin Milestone Dates cane Scheduled Review Dates ID Number Description Start Finish 50% Client Final 120376-09-21-09-07 9.07.01 One-Line and General Arrangement Drawings Stanley Sostrom 8/1/96 12/2/96 100 9.07.02 Modify Existing General Arrangement Plans Stanley Sostrom 8/1/96 12/2/96 100 9.07.03 Identify & Note Bus Connct & Phasing on DWGS Stanley Sostrom 8/1/96 12/2/96 100 9.07.04 Determine Const/Operation/Maintenance Stanley Sostrom 8/1/96 12/2/96 100 120376-09-21-09-08 9.08.01 Supplemental Design Criteria Stanley Sostrom 8/1/96 12/2/97 100 120376-09-21-09-09 9.09.01 Modify One Lines and General Arrangements Stanley Sostrom 8/1/96 12/2/96 100 9.09.02 Determine Const/Operation/Maint Requirements Stanley Sostrom 8/1/96 12/2/96 100 120376-09-21-09-10 9.10.01 Cost Estimates William Riall 1/15/97 5/14/97 100 120376-09-21-09-13 9.13.01 Cost Estimate Stanley Sostrom 15/97 = 5/14/97 100 9.13.02 Compile/Review Vendor Support Data Stanley Sostrom 1/15/97 5/14/97 100 120376-09-21-09-14 9.14.01 3 Identified Alternative Routes Cost Estimates Frank Rowland 1/15/97 5/14/97 100 9.14.02 Develop Land Costs Frank Rowland 115/97 5/14/97 100 9.14.03 Develop Labor/Exp Costs to Acquire Easements Frank Rowland 1/15/97 5/14/97 100 120376-09-22-09-01 9.01.01 Manufacturer & Factory Inspections William Riall 10/16/96 4/15/97 100 9.01.02 Utility Specific Operating Data William Riall 10/16/96 4/15/97 100 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 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 4/15/97 100 9.02.02 Preliminary Performance Specs William Riall 10/16/96 4/15/97 100 9.02.03 Determine Const/Operation/Main Requirements William Rial! 10/16/96 4/15/97 100 120376-09-22-09-03 9.03.01 10 Copies of Summary Report William Riall 2/3/97 4/15/97 95 9.03.02 Recommend Specific Cable Type William Riall 2/3/97 4/15/97 95 9.03.03 Recommend Most Probable Method of Installation William Riall 2/3/97 4/15/97 95 120376-09-22-09-04 9.04.01 Preliminary Site Specific Arrangements William Riall 1/1/97 4/15/97 100 9.04.02 Engineering Sketches of Transition Station William Riall 1/1197 4/15/97 100 9.04.03 DSGN Parameters/EIS Support/10 Sub CBL Landfalls William Riall 1/1197 4/15/97 100 9.04.04 DSGN Parameters/EIS Support/2 Transiton Sites William Riall 1/1/97 4/15/97 100 120376-09-22-09-05 9.05.01 Preliminary Design for Wood Pole H-Frame Larry Henriksen 9/16/96 9/16/97 100 9.05.02 Prel DSGN for DBL Circuit Single Pole Structures Larry Henriksen 9/16/96 9/16/97 100 9.05.03 Est/Dist Underbuilt to Single Pole Struct Larry Henriksen 9/16/96 9/16/97 100 9.05.04 Determine Const/Operation/Maint Requirements Larry Henriksen 9/16/96 9/16/97 100 120376-09-22-09-06 9.06.01 Site Visits Stanley Sostrom 8/1/96 8/30/96 100 9.06.02 Data Acquisition/Drawing Collection Stanley Sostrom 9/2/96 10/15/96 100 9.06.03 Schedule and Attend Meetings Stanley Sostrom 9/2/96 12/2/96 100 9.06.04 Provide Supplemental Design Criteria Stanley Sostrom 9/2/96 12/2/96 100 9.06.05 One Mobilization/Office Visit Stanley Sostrom 9/2/96 12/2/96 100 Deliverable Tracking System Deliverables by Project Period Ending: 11/8/97 120376-09-22-09-11 9.11.01 Cost Estimates guyed "X" Larry Henriksen 1/15/97 5/14/97 100 9.11.02 Cost Estimates Single Stl Pole Single Circuit Larry Henriksen 1/15/97 5/14/97 100 9.11.03 Cost Estimates Wood Pole H-Frame Larry Henriksen 1/15/97 5/14/97 100 9.11.04 Cost Estimates DBL Circuit Single Pole Larry Henriksen 115/97 5/14/97 100 9.11.05 Cost Est Addition of Underbuilt to Single Pole Larry Henriksen 1/15/97 5/14/97 100 9.11.06 Narrative of Cost Estimate Process Larry Henriksen 1/15/97 5/14/97 100 9.11.07 Summary Cost Report Larry Henriksen 415/97 5/14/97 100 120376-09-22-09-12 9.12.01 Cost Estimate for 2 New Endpoints Stanley Sostrom 1/15/97 = 5/14/97 100 9.12.02 Narrative of Cost Estimate Process Stanley Sostrom 1/15/97 5/14/97 100 9.12.03 Summary Cost Report Stanley Sostrom 4/15/97 5/14/97 100 120376-09-23-09-15 9.15.01 15 Copies Summary Reports Michael Walbert 4/15/97 5/14/97 90 TW7/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT meee ae 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 2ND QUARTER 1997 3RD QUARTER 1997 TASK MONTH] JUNWUL | AUG | SEP | ocT | __ Nov DEC JAN FEB MAR | APR | MAY | sun | su | auc | sep | 1 SCOPING Actual % Work Completed 5% 20% 28% 33% 51% 72% 77% 93% 99% 99% 99% 99% 99% 99% 99% Base Planned % Complete $ (to date 2% 25% 26% 33% 52% 74% 87% 93% 100% 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% 100% Actual % Expended $ (to date 5% 30% 30% 33% 51% 63% 77% 93%| 99% 99% 99% 97% 98% 98% 99% Base Planned $ (this period) $6,743 $81,045 $2,745 $25,645 $67,045 $75,045 $46,045 $23,645 $23,092 $0 $0 $0 $0 $0 $0 | __ Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $67,538 $60,112 $27,222 $0 $0 $0 $0 $0 $0 Actual $ Expended (this period) $15,925 | __ $89,330 ($558 $9,848 $63,340 $42,082 | $67,538 $59,509 $25,800 $0 ($593)| ($7,434) $1,037 $580 $3,607 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| $351,050 Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A N/A| _$287,505| $347,617| $374,839] $374,839 | $374,839| $374,839| $374,839 | $374,839| $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| $366,404| $370,011 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 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 $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| $374,839 Actual Remaining Task Budget $335,125 | $245,795 | $246,353| $236,505| $173,165 | $131,083 $87,334 $27,825 $2,025 $2,025 $2,618 $10,052 $9,015 $8,435 $4,828 Ee INVENTORY Actual % Work Completed 0% 6% 25% 45% 60% 67% “73% ~80%| 87%| 88% | _—~ 88% 90% 90% 92% 95% Base Planned % Complete $ (to date) 0% 5% 23% 53% 73% 83% 84% 84% 84% 84% 84% 87% 95% 100% 100% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A\ N/A N/A N/A\ 73% 82% 85% 86% 86% 89% 92% 96% 100% Actual % Expended $ (to date) 0% 5% 24% 43% 58% 72% 73% 78% 87% 88% 88% 20% 90% 92%|_ 95% Base Planned $ (this period) $941 $29,441 | $121,000] $200,500| $129,500 $69,768 $5,000 $0 $0 $0 $1,000 $16,500 $52,000 $34,056 $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 $29,613 $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 $10,970 $20,973 Base Planned $ (to date) $941 $30,382 | $151,382] $351,882| $481,382 | $551,150| $556,150| $556,150| $556,150| $556,150| $557,150| $573,650| $625,650| $659,706 | $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| $652,616 | $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| $623,899| $644,872 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 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 $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 | $679,591 Actual Remaining Task Budget $660,706 | $628,544 | $504,090] $375,047| $274,251 | $184,920] $184,077| $150,169 $86,667 $83,779 $83,779 $67,964 $66,662 $55,692 $34,719 | 3 _|IMPACT ASSESSMENT/MITIGATION PLANNING Actual % Work Completed 0% 0% 0% 1% 7% 10% 16% 31% 52% 62% 75% 90% 99% Base Planned % Complete $ (to date) 0% 0% 5% 10% 40% 50% 60% 80% 95% 100% 100% 100% 100% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A 7% 20% 37% 55% 69% 82% 89% 96% 99% Actual % Expended $ (to date) 0% 0% 0% 1% 7% 9% 16% 31% 52% 62% 74% 90% 98% Base Planned $ (this period) $0 $0| $29,000 $30,000 $90,000 $57,000 $58,000 | $117,000 $90,000 $28,010 $0 $0 $0 Rev. 1 Planned $ (this period) N/A N/A N/A $10,408 $81,590 $99,490 | $111,370 $88,030 $78,700 $42,295 $37,600 $18,000 Actual $ Expended (this period) $383 $0 $5,788 $10,408 $14,998 $41,883 $92,212 | $126,888 $59,150 $73,790 $97,136 $49,174 Base Planned $ (to date) $0 $59,000 $234,000] $291,000] $349,000] $466,000] $556,000] $584,010 | $584,010 | $584,010] $584,010 Rev. 1 Planned $ (to date) N/A N/A N/A $40,544 | $122,134 | $221,624| $332,994| $421,024| $499,724] $542,019| $579,619| $597,619 $383 $447 $6,235 $40,544 $55,542 $97,425 | $189,637 | _$316,525| _$375,675| $449,465 | $546,601 | _ $595,775 | 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 $22,602 $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 $606,612 | $606,612| $606,612| $606,612] $606,612| $606,612| $606,612] $606,612| $606,612 Actual Remaining $584,010 | $583,627 $583,563 | $577,775 $566,068 | $551,070 | $509,187| $416,975 | $290,087| $230,937] $157,147 $60,011 $10,837 Rev. 1 updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97the DFI Contract Amendment #5 is included in Task 5 and the Total. As of 10/1/97 the DFI Contract Amendments #6 and #7 are included in Task 5 and the Total. Page 1 41/17/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: 11-08-97 PROJECT SUMMARY REPORT 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 2ND QUARTER 1997 3RD QUARTER 1997 TASK MONTH} _JUN/JUL AUG SEP OocT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP 4 ALTERNATIVE SELECTION Actual % Work Completed 0% 0% 0%| 0% 0% 0% 0% 0%| _ 0% 0% 1% 10% 20% 35% 50% Base Planned % Complete $ (to date) 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 11% 35% 61% 80% 100% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 0% 5% 15% 31% 49% 71%) 91% 100% 100% Actual % Expended $ (to date 0% 0% 0% 0% 0% 0% Oe) III iil 0% 0% 0% 1% 11% 19% 33%) 51% Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $32,400 $74,400 $77,400 $58,400 $60,875 Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/AI $0 $15,000 $35,000 $52,000 $62,000 $72,000 $69,000 $29,972 $0 Actual $ Expended (this period) $0 $1,369 $0 $0 $0 $0 $0 $0 $0 $0 $1,275 $34,764 $27,023 $46,260 $59,360 Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $32,400 $106,800 $184,200 $242,600 $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 $336,341 Actual $ Expended (to date) $0 $1,369 $1,369 $1,369 $1,369 $1,369 $1,369 $1,369 $1,369 $1,369 $2,644 $37,408 $64,431 $110,691 $170,051 Base NTE Budget (Amend. #3) $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 $303,475 CWG Contract Amend. #4 Budget 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 $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 $336,341 : Actual Remaining Task Budget $303,475 $302,106 $302,106 $302,106 $302,106 $302,106 $334,972 $334,972 $334,972 $334,972 $333,697 $298,933 $271,910 $225,650 $166,290 a DRAFT EIS Uni tL : Actual % Work Completed 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 8% 11% 20% 22% Base Planned % Complete $ (to date) 0% 0% 0% 0% 0% 0% 0% 0% 1%| 2%! 3% 4% 11% 19% 34% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 0% 1% 1% 1% 2% 2% 13% 32% 43% Rev.1+DFl Planned % Cmp $ (to date) N/A N/A N/A N/A N/A N/A| N/A N/A N/A N/A N/A 2% 17% 39% 48% Actual % Expended $ (to date) 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 8% 11% 21% 23% Base Planned §$ (this period) $0 $0 $0 $0 $0 $0 $0 $0 $5,772 $1,572 $5,772 $1,582 $31,570 $31,570 $57,570 Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/A $0 $6,100 $0 $0 $4,000 $0 $43,300 $78,052 $42,017 Rev. 1 + DFI Planned $ (this period) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A $332 $65,634 $100,386 $42,017 Actual $ Expended (this period) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $4,991 $29,405 $13,991 $44,991 $10,284 Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $0 $0 $5,772 $7,344 $13,116 $14,698 $46,268 $77,838 $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 $10,100 $53,400 $131,452 $173,469 Rev. 1 + DFI Planned $ (to date) N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A $10,432 $76,066 $176,452 $218,469 Actual $ Expended (to date) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $4,991 $34,396 $48,387 $93,378 | _ $103,662 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 N/A N/A N/A N/A N/A N/A $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 $4,904 | DFI Contract Amend. #5 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A $45,000 $45,000 $45,000 $45,000 | DFI Contract Amend. #6 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/AI DFI Contract Amend. #7 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 DFI Contract Amend. #8 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 $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 $452,474 Actual Remaining Task Budget $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $407,474 $407,474 $407,474 $407,474 $402,483 $418,078 $404,087 $359,096 $348,812 Rev. 1 updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97the DFI Contract Amendment #5 is included in Task 5 and the Total. As of 10/1/97 the DFI Contract Amendments #6 and #7 are included in Task 5 and the Total. Page 2 ‘11/17/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT ieee? 7 EE ee 1ST QUARTER 1997 2ND QUARTER 1997 TASK JUNJUL | AUG SEP oct NOV DEC JAN (pepe | AR ee a on sO ae see 6 | _FINALEIS,— HU. Actual % Work Completed 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%’ Base Planned % Complete $ (to date) 0% 0% 0%’ 0% 0% 0% 0% 0% 0%} 0% 0% 0% 0% 0% 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% 0% 0% 0% Actual % Expended $ (to date) 0% 0% 0%’ 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%) 0% Base Planned $ (this period) $0 $0 $0 | $0 $0 $0 | $0 $0 $0 $0 $0 $0 $0 $0 $0 | Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A N/AI $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 | $441 Base Planned $ (to date) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A N/A $0 $0 $0 $0 $0 $0 $0 $0 $0 Actual $ Expended (to date) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 | $0 $0] $0 $441 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 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 $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 $247,175 STUDIES Actual % Work Completed 1% 5% 7% 7% 8% 14% 27% 35% 48% 55% 60% 60% 68% 70% 75% Base Planned % Complete $ (to date) 1% 5% 9% 21% 51% 73% 73% 73% 76% 78% 80% 83% 87% 91% 91% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A| N/A N/A N/A 27% 38% 55% 56% 56% 67% 78% 89% 90% Actual % Expended $ (to date) 0% 3% 7% 7% 8% 14% 27% 33% ara 55% 60% 61% 67% 70% 73% Base Planned $ (this period) $927 $3,927 $4,427 $12,200 $30,325 $22,780 $0 $0 $2,300 $2,300 $2,280 $2,300 $4,139 $4,175 ia $0 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 $11,207 $802 Actual $ Expended (this period $0] $2,569 $4,177 $637 $1,148 $5,705 $13,352 $5,455 $14,793 $8,252 $5,157 $440 $5,855 $3,299 $3,279 Base Planned $ (to date) $927 $4,854 $9,281 $21,481 $51,806 $74,586 $74,586 $74,586 $76,886 $79,186 $81,466 $83,766 $87,905 $92,080 $92,080 Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A NWA $27,588 $38,080 $56,115 $56,615 $57,115 $68,271 $79,571 $90,778 $91,580 Actual $ Expended (to date) _ $0 $2,569 $6,746 $7,383 $8,531 $14,236 $27,588 $33,043 $47,836 $56,088 $61,245 $61,685 $67,540 $70,839 $74,118 Base NTE Budget (Amend. #3) $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 | CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A NWA 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 $101,480 $98,911 $94,734 $94,097 $92,949 $87,244 $73,892 $68,437 $53,644 $45,392 $40,235 $39,795 $33,940 $30,641 $27,362 ENGINEERING FIELD WORK Actual % Work Completed 5% 15% 50% 60% 70% 74% 77% 79% 84% 87% 87% 90% 95% 95% 95% Base Planned % Complete $ (to date) 5% 18% 52% 63% 68% 78% 86% 91% 91% 91% 91% 94% 97% 100% 100% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 77% 79% 81% 81% 81% 88% 95% 100% 100% Actual % Expended $ (to date) 5% 13% 48% 60% 70% 74% 77% 79% 84% 87% 87% 90% 94% 94%) 94% Base Planned $ (this period) $9,600 $27,600 $68,900 $20,980 $10,800 $20,680 $16,600 $9,955 $0 $0 $0 $5,500 $5,500 $6,540 $0 Rev. 1 Planned $ (this period) N/A N/A N/A N/A N/A NWA $7,645 $4,000 $2,601 $0 $0 $15,000 $14,000 $10,026 $0 Actual $ Expended (this period) $10,330 $17,007 $69,770 $23,487 $20,840 $7,949 $7,645 $2,827 $10,789 $4,825 $33 $7,640 | $7,510 $14 $0 Base Planned $ (to date) $9,600 $37,200 $106,100 $127,080 $137,880 $158,560 $175,160 $185,115 $185,115 $185,115 $185,115 $190,615 $196,115 $202,655 $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 $202,655 Actual $ Expended (to date) $10,330 $27,337 $97,107 $120,594 $141,434 $149,383 $157,028 $159,855 $170,644 $175,469 $175,502 $183,142 | $190,652 $190,666 $190,666 Base NTE Budget (Amend. #3) $202,655 $202,655 $202,655 $202,655 $202,655 sero [ $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 wal 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 $192,325 $175,318 $105,548 $82,061 $61,221 $53,272 $45,627 $32,011 $27,186 $27,153 $19,513 $12,003 $11,989 $11,989 Rev. 1 updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97the DFI Contract Amendment #5 is included in Task 5 and the Total. As of 10/1/97 the DFI Contract Amendments #6 and #7 are included in Task 5 and the Total. $42,800 Page 3 ‘11/17/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT aed 3RD QUARTER 1996 4TH QUARTER 1996 1ST QUARTER 1997 2ND QUARTER 1997 3RD QUARTER 1997 TASK MONTH| JUN/JUL AUG SEP ocT NOV DEC JAN FEB MAR APR | MAY | gun | vu__| auG | sePp_ | | 9 | PRELIMINARY ENGINEERING Actual % Work Completed 1% 1% 1% 1% 12% 17% 18% 20% 25% 36% 45% 50% 60% 78% 98% Base Planned % Complete $ (to date) 1% 2% 4% 9% 23% 31% 44% 57% 71% 88% 97% 98% 98% 98% 98% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A 18% 36% 53% 71% 85% 98% 98% 98% 98% Actual % Expended $ (to date) 1% 1% 1% 1% 12% 17% 18% 20% 24% 36% 44% 50% 60% 71% 97%| Base Planned $ (this period) $2,580 $2,137 $2,137 $10,337 $27,417 $14,557 $23,697 $25,557 $26,837 $32,397 $16,076 $2,132 $0 $0 $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 $0 Actual $ Expended (this period) $1,694 $0 $1,080 $0 $20,307 $9,513 $1,937 $2,746 $8,432 $23,434 $13,944 $11,012 $19,261 $33,336 $36,656 | Base Planned $ (to date) $2,580 $4,717 $6,854 $17,191 $44,608 $59,165 $82,862 | $108,419| $135,256| $167,653 | $183,729| $185,861| $185,861 | $185,861| $185,861 Rev. 1 Planned $ (to date) N/A N/A N/A N/A N/A N/A] $34,531 $67,531 | $100,531] $135,531 | $160,531| $185,861 | $185,861 | $185,861 | $185,861 Actual $ Expended (to date) $1,694 $1,694 $2,774 $2,774 $23,081 $32,594 $34,531 $37,277 $45,709 $69,143 $83,087 $94,099 | $113,360| $146,696 | $183,352 | Base NTE Budget (Amend. #3) $189,861 | $189,861 | $189,861| $189,861| $189,861 | $189,861| $189,861 | $189,861| $189,801| $189,861 | $189,861| $189,861 [ $189,861 | $189,861 | $189,861 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Total Task NTE Budget $189,861 | $189,861] $189,861| $189,861| $189,861 | $189,661] $189,861 | $189,861| $189,861| $189,861| $189,861| $189,861| $189,861 | $189,861 | $189,861 Actual Remaining Task Budget $188,167 $188,167 $187,087 $187,087 $166,780 $157,267 $155,330 $152,584 $144,152 $120,718 $106,774 $95,762 $76,501 $43,165 $6,509 TOTAL PROJECT 120376-01 : = Actual % Work Completed 1% 5% 18% 24% 30%] 33% 38% 40%] 46% 51% 55% 60% 68% 74% Base Planned % Complete $ (to date) 1% 5% 22% 31% 41% 47% 51% 55% 60% 64% 69% 74% 79% 83% Rev. 1 Planned % Complete $ (to date) N/A N/A N/A N/A N/A N/A| 33% 42% 49% 56% 62% 69% 75% 81% 84% Rev.1+DFI Planned % Cmp $ (to date) N/A N/A N/A N/A N/A NA\ N/A N/A N/A N/A N/A 68% 75% 81% 84% Actual % Expended $ (to date) 1% 6% 12% 18% 24% 30%! 33% 37% 42% 46% 51% 55% 60% 67% 73% Base Planned $ (this period) $20,791 | $144,150] $199,209] $298,662| $295,087 | $287,830| $181,342 | $116,157| $116,001| $153,269| $147,528| $130,424| $170,609| $134,741 | $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| $219,686| $198,895 | $196,470 $87,794 Rev. 1 + DFI Planned $ (this period) N/A N/A N/A N/A N/A NA N/A N/A N/A N/A N/A| $220,018] $221,229| $218,804 $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| $236,586 | $183,774 Base Planned $ (to date) $20,791 | $164,941 | $364,150| $662,812| $957,899 | $1,245,729 | $1,427,071 | $1,543,228 | $1,659,229 | $1,812,498 | $1,960,026 | $2,090,450 | $2,261,059 | $2,395,800 | $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 | $2,158,796 | $2,357,691 | $2,554,161 | $2,641,955 Rev. 1 + DFI Planned $ (to date) N/A N/A N/A N/A N/A NA N/A N/A N/A N/A N/A| $2,159,128 | $2,380,357 | $2,599,161 | $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 | $2,149,174 | $2,332,948 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 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 | $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/A $45,000 $45,000 $45,000 $45,000 DFI Contract Amend. #6 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 DFI Contract Amend. #7 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 Project NTE Budget $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,043,423 | $3,146,469 | $3,146,469 | $3,146,469 | $3,146,469 | $3,146,469 | $3,191,469 | $3,191,469 | $3,191,469 | $3,191,469 Actual Remaining Project Budget__| $3,015,474 | $2,872,654 | $2,673,667 | $2,510,652 | $2,298,433 | $2,119,952 | $2,102,390 | $1,982,947 | $1,817,748 | $1,686,137 | $1,534,442 | $1,428,650 | $1,278,881 | $1,042,205 | $858,521 | __ |BASE PLANNED QUARTER TOTALS $364,150 $881,579 __ $413,500 $431,221 |__| BASE PLANNED YEARLY TOTALS | ; $1,245,729 : pee : /-—ie¥. L PLANNED QUARTER TOTALS|_$369.788_}_sssais____ | | REV. 1 PLANNED YEARLY TOTALS |: = ld a ie eS oe |_| REV. 1+DFI PLANNED QTR TOTALS “$369,756 ee SSO ig ee Sbab aes etn Seen tet es ee | __|REV. 144DFl PLANNED YRLY TOTALS |__| ACTUAL QUARTERTOTALS | $369,756 $405,250 $434,098 $570,129 [Se AGIUAL VeAREY (Grabs. =f $923,471 __ Rev. 1 updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97the DFI Contract Amendment #5 is included in Task 5 and the Total. As of 10/1/97 the DFI Contract Amendments #6 and #7 are included in Task 5 and the Total. Page 4 W7187 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ee PROJECT SUMMARY REPORT 1ST QUARTER 1998 2ND QUARTER 1998 3RD QUARTER 1998 4TH QUARTER 1998 [way [wun [ue Tua | sep | oct | Nov | rea Se Rev. 1 Planned % Complete $ (to date) 100% Actual % Expended $ (to date) Base Planned $ (this period) $0 Rev. 1 Planned $ (this period) $0 Actual $ Expended (this period $0 0 Base Planned $ (to date) $. 10 $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 5 $374,839 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 Actual $ Expended (to date’ $372,861 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 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 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 Actual Remaining Task Budget $1,978 INVENTORY [ian Actual % Work Completed Base Planned % Complete $ (to date) 100% Rev. 1 Planned % Complete $ (to date)! 100% Actual % Expended $ (to date) 95% Base Planned $ (this period) $0 $0 $0 $0 $0 Rev. 1 Planned $ (this period) $0 $0 $0 $0 $0 Actual $ Expended (this period) $61 $0 $0 $0 Base Planned $ (to date) $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 $660,706 | _ $660,706 $660,706 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 Actual $ Expended (to date) $644,933 | 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 $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 Actual Remaining Task Budget $34,658 IMPACT ASSESSMENTIMITIGATION F : Actual % Work Completed Base Planned % Complete $ (to date) 100% 100% Rev. 1 Planned % Complete $ (to date) 100% 100% Actual % Expended $ (to date) 98% Base Planned $ (this period) $ $0 $0 Rev. 1 Planned $ (this period) $0 $0 Actual $ Expended (this period $0 $0 Base Planned $ (to date) $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 Actual $ Expended (to date’ $595,834 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 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 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 Actual Remaining Task Budget $10,778 & Rev. 1 updated as of 1/1/97; includes Contract Amendment #4. Aa 96 2/4/07the NEI Cantract Amendment #5 is included in Task 5 and the Total. Page 5 TWATBT SOUTHERN INTERTIE PROJECT THROUGH PERIOD anna: PROJECT SUMMARY REPORT 4TH QUARTER 1997 1ST QUARTER 1998 2ND QUARTER 1998 3RD QUARTER 1998 4TH QUARTER 1998 MONTH [pec | van [ rep [ mar | apr [ may | sun | su [| auc | sep | ALTERNATIVE SELECTION | AACA ee ee Te AC OE at Uo eT Actual % Work Completed Base Planned % Complete $ (to date) 100% Rev. 1 Planned % Complete $ (to date) 100% 100% Actual % Expended $ (to date; 93% $0 Base Planned $ (this period) $0 Rev. 1 Planned $ (this period) $0 $0 Actual $ Expended (this period $141,782 $0 Base Planned $ (to date) $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 Actual $ Expended (to date) $311,833 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 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 Total Task NTE Budget $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 $336,341 Actual Remaining Task Budget $24,508 TP TE eg CRASS SL TT Actual % Work Completed Base Planned % Complete $ (to date 85% 100% 100% Rev. 1 Planned % Complete $ (to date 92% 100% 100% Rev.1+DFI Planned % Cmp $ (to date) 92% 100% 100% Actual % Expended $ (to date) a Base Planned $ (this period) $19,570 $25,570 $74,570 $18,742 $0 Rev. 1 Planned $ (this period) $29,000 $49,900 $28,000 $1,904 $0 Rev. 1 + DFI Planned $ (this period) $56,187 $62,900 $39,500 $1,904 $0 Actual $ Expended (this period) $0 $0 $0 $0 $0 Base Planned $ (to date) $199,978 $241,118 $266,688 $341,258 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 $402,570 Rev. 1 Planned $ (to date) $239,669 $297,669 $347,569 $375,569 $405,570 $407,474 $407,474 $407,474 $407,474 $407,474 $407,474 $407,474 $407,474 $407,474 Rev. 1 + DFI Planned $ (to date) $288,171 $412,058 $474,958 $514,458 $554,960 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 e $142,986 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 $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 DFI Contract Amend. #6 Budget $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 DFI Contract Amend. #7 Budget $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 DFI Contract Amend. #8 Budget N/A $89,487 $89,487 $89,487 $89,487 $89,487 $89,487 $89,487 $89,487 $89,487 $89,487 $89,487 Total Task NTE Budget $467,376 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 $556,864 Actual Remaining Task Budget $324,390 Rev. 1 updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97the DFI Contract Amendment #5 is included in Task 5 and the Total. nae eas (a eae 20 Waals B anal tan Faant Page 6 » V1N7/97 SOUTHERN INTERTIE PROJECT THROUGH PERIOD ENDING: PROJECT SUMMARY REPORT 11-08-97 4TH QUARTER 1997 1ST QUARTER 1998 2ND QUARTER 1998 3RD QUARTER 1998 4TH QUARTER 1998 MONTH] oct | Nov | pec | van | rep | maR | apm | may | JUN | Be ae tS SBe | Actual % Work Completed 98% i Base Planned $ (this period) $14,416 Rev. 1 Planned $ (this period) $6,163 Actual $ Expended (this period) $10,176 $0 Base Planned $ (to date) $0 $64,200 $123,800 $148,900 $208,600 $233,200 $247,616 $247,616 Rev. 1 Planned $ (to date) $0 $132,163 $180,229 $214,033 $230,933 $237,593 $243,756 $247,616 Actual $ Expended (to date) $10,617 Base NTE Budget (Amend. #3) $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Total Task NTE Budget $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 $247,616 Actual Remaining Task Budget $236,999 Actual % Work Completed Base Planned % Complete $ (to date) 91% 96% Rev. 1 Planned % Complete $ (to date) 90% 96% Actual % Expended $ (to date) Base Planned $ (this period) $0 $0 $0 $0 $0 $0 Rev. 1 Planned $ (this period) $0 $0 $0 $0 $0 $0 Actual $ Expended (this period) : $0 $0 $0 $0 $0 $0 Base Planned $ (to date) $92,080 $92,080 $92,080 $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 $97,480 $97,480 $97,480 $101,480 $101,480 $101,480 $101,480 Actual $ Expe pn Base NTE Budget (Amend. #3) $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Total Task NTE Budget $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 $101,480 Actual Remaining Task Budget $17,947 ENGINEERING FIELD WORK Actual % Work Completed 98% Base Planned % Complete $ (to date 100% Rev. 1 Planned % Complete $ (to date) 100% Actual % Expended $ (to date 97% Base Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 Rev. 1 Planned $ (this period) $0 $0 $0 $0 $0 $0 $0 $0 Actual $ Expended (this period) $6,523 $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 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 Actual $ Expended (to date) $197,189 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 NWA 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 $5,466 § : Rev. 1 updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97the DFI Contract Amendment #5 is included in Task 5 and the Total. es akan ab te Pants © mend tan Tatas Page 7 » 117/97 SOUTHERN INTERTIE PROJECT PROJECT SUMMARY REPORT 4TH QUARTER 1997 1ST QUARTER 1998 PRELIMINARY ENGINEERING 2ND QUAR TER 1998 AY Actual % Work Completed =f ae THROUGH PERIOD ENDING: 11-08-97 4TH QUARTER 1998 SEP fs Oey. |. mow oe een eel Base Planned % Complete $ (to date) 98% Rev. 1 Planned % Complete $ (to date) 98% Actual % Expended $ (to date) Base Planned $ (this period) $0 $0 $4,000 $0 Rev. 1 Planned $ (this period) $0 $0 $4,000 $0 Actual $ Expended (this period Base Planned $ (to date) $185,861 $185,861 $185,861 $185,861 $0 $185,861 $185,861 $0 $185,861 $0 $189,861 $0 $185,861 $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 $189,861 $189,861 $189,861 Actual $ Expended (to date) Base NTE Budget (Amend. #3) $187,261 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 aaocnmh $189,861 $189,861 $189,861 $189,861 CWG Contract Amend. #4 Budget N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A NA N/A N/A Total Task NTE Budget $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 $189,861 Actual Remaining Task Budget TOTAL PROJECT 120376-01 Actual % Work Completed $2,600 Base Planned % Complete $ (to date 87% 89% 93% 94% 96% 98% 100% 100% -|Rev. 1 Planned % Complete $ (to date) 90% 91% 95% 96% 99% 99% 100% 100% Rev.1+DFl Planned % Cmp $ (to date) 90% 91% 95% 96% 99% 99% 100% 100% Actual % Expended $ (to date) Base Planned $ (this period) $64,570 $19,570 $25,570 $74,570 $47,970 $57,842 $25,100 $25,100 $35,100 $28,600 $14,416 Rev. 1 Planned $ (this period) $75,193 $29,000 $49,900 $28,000 $78,801 $57,467 $33,700 $33,804 $8,200 $10,660 $6,163 Rev. 1 + DFI Planned $ (this period) $78,695 $56,187 $62,900 $39,500 $89,302 $57,467 $33,700 $33,804 $8,200 $12,700 $10,660 $6,163 Actual $ Expended (this period, Base Planned $ (to date) $214,099 $2,579,815 $0 $2,620,955 $0 $2,646,525 $0 $2,721,095 $0 $2,769,065 $0 $2,826,907 $0 $2,852,007 $2,911,607 $0 $2,936,707 $0 $2,971,807 $0 $3,000,407 $0 $3,029,007 $0 $3,043,423 | $3,043,423 Rev. 1 Planned $ (to date) $2,717,148 $2,775,148 | $2,825,048 | $2,853,048 | $2,931,849 | $2,989,317 $3,023,017 $3,071,082 $3,104,886 $3,113,086 $3,125,786 | $3,136,446 | $3,142,609 | $3,146,469 Rev. 1 + DFI Planned $ (to date) $2,765,650 $2,889,537 | $2,952,437 | $2,991,937 | $3,081,239 | $3,138,707 $3,172,407 $3,220,472 $3,254,276 $3,262,476 $3,275,176 | $3,285,836 | $3,291,999 | $3,295,859 Actual $ Ex Base NTE Budget (Amend. #3) $2,547,047 | $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 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 DFI Contract Amend. #6 Budget $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 $11,400 DFI Contract Amend. #7 Budget $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 $3,502 Total Project NTE Budget $3,206,371 $3,295,859 | $3,295,859 | $3,295,859 | $3,295,859 | $3,295,859 $3,295,859 $3,295,859 $3,295,859 $3,295,859 $3,295,859 | $3,295,859 | $3,295,859 | $3,295,859 Actual Remaining |__| BASE PLANNED QUARTER TOTALS| |__| BASE PLANNED YEARLY TOTALS | | ___|REV. 1 PLANNED QUARTER TOTALS |__| REV. 1 PLANNED YEARLY TOTALS | |__| REV. 1+DFl PLANNED QTR TOTALS| Be ba Se $659,324 § EV. 1+DFl PLANNED YRLY TOTALS ACTUAL QUARTER TOTALS ACTUAL YEARLY TOTALS Rev. 1 updated as of 1/1/97; includes Contract Amendment #4. As of 6/1/97the DF Contract Amendment #5 is included in Task 5 and the Total. Page 8 Rate Impacts of the Southern Intertie Project Final Report Raloh Samuelson Stephen Haas November 12, 1997 Copyright © Decision Focus Incorporated Copyright © Aeronormics Incorporated $2947-02 1 Southern Intertie Rate Impacts 0.05 0+ -0.05 + - 205 Nees = aes -0.3 -0.35 2004 2009 2014 2019 2024 2029 2034 2039 Year -—— Enstar 2-3 Route = = Tesoro 4-1 Route sSx~ovr#300 Copipight © Decision Focus Incorporated Copyright © Aeronanics Incerporated What Will Be the Impact of the Southern Intertie on Ratepayers? + annual savings/KWH = (annual cost reductions due to Intertie- annual cost of Intertie)/total Railbelt electric energy demand + annual cost reductions due to Intertie will be the sum of - savings from avoided and deferred generation additions - savings in economy energy & transmission losses - savings due to operating reserve sharing - savings in maintenance expense on the existing line - savings from elimination of the minimum 25 MW Kenai CT generation requirement - savings from avoiding loss of transfer capability during adverse weather conditions and work adjacent to the existing line Copyright © Decision Focus Incorporated Copuright © Aeronamics Incerporated $2947-02 3 V@iat Will Be the In@oact of the e Southern Intertie on Ratepayers (continued)? + Annual cost of the Intertie will be sum of - bond interest - assignable margins - depreciation - maintenance expense + Ratepayers will also benefit from the higher reliability of service which the Intertie will allow the Railbelt utilities to provide; however, since these benefits do not affect rates, they will not be considered here Copyright © Decision Focus Incorporatecdt Copyright © Acronamics Incorporated What Were the Assumptions About I nflation? + Aconstant inflation rate of 3% per year was assumed for alll future years + Rate impacts are given in current dollars (that is, dollars applicable to each year) + All benefits and costs are assumed to rise with inflation except bond interest, assignable margins, and depreciation Copyright © Acronomics Incorporated Copyright © Decision Focus Incorporated What Did We Assume About Fuel Costs? + Fuel costs were assumed to rise 1% per year faster than inflation in the 1997-2020 period, and at the rate of inflation after 2020 + Fuel related benefits were assumed to rise at this higher rate; these are: - savings in economy energy & transmission losses - savings due to operating reserve sharing - savings from elimination of the minimum 25 MW Kenai CT generation requirement —- savings from avoiding loss of transfer capability during adverse weather conditions and work adjacent to the existing line Copyright © Decision Focus Incorporated Copyright © Acrorunnics Incerporated $2947-02 6 What Were the Assumptions About Interest Rates? + We assumed an interest rate of 6% on the bonds used to finance the Intertie + 6% is in the mid-range between rates prevailing today on high- grade taxable long-term bonds and short-term commercial paper + This 6% is a nominal interest rate, meaning that it must compensate investors for both inflation and the use of their capital Copyright © Decision Pocus Incorporatect Copyright © Aeronomics Incorporated $2947-02 7 What Were the Assumptions About Electric Energy Demand? + Our forecasts for Chugach Electric Association and its wholesale customers were obtained from Chugach’s 1997 Power Requirements Study; electric energy demand was assumed to be constant after 2021, the last year projected by that study + Our forecasts for Anchorage Municipal Light and Power were obtained from AML&P’s 1996 Electric System Load Forecast; electric energy demand was assumed to be constant after 2015, the last year projected by that study + Our forecasts for the Golden Valley Electric Association, including the former Fairbanks Municipal Utility System, were obtained from Golden Valley‘s draft 1997 Power Requirements Study; electric energy demand was assumed to be constant after 2016, the last year projected by that study Copyright © Decision Fours Incorporated Copyright © Aeronomice Incorporated How Is Bond Interest Expense Calculated? + bond interest = bonds outstanding *interest rate on bonds + bonds outstanding = net investment in Intertie - patronage capital accrued from operation + netinvestment in Intertie = construction costs + interest accrued during construction - state grant - interest accrued on state grant - accumulated depreciation Copyright © Aeronomics Incorporated $2947-02 9 Copyright © Decision Focus Incorporated How Are Assignable Margins Calculated? > ob} Copyright © Decision Focus Incorporated assignable margins = bond interest*(TIER- 1) TIER (Times Interest Earned Ratio) currently assumed to equal 1.25, consistent with Chugach’‘s requested rate-setting TIER The assignable margins are a source of the patronage capital (similar to stockholder equity in an investor-owned utility), which may be used to pay off the bonds We assumed that patronage capital is retained by the utilities to finance future investments, rather than refunded to ratepayers Copyright © Agronamnics Incorporated $2947-02 10 How Is Depreciation Expense Calculated? + A 40-year straight-line depreciation schedule is assumed, beginning when the Intertie goes into service in 2004 + Depreciation is applied to the net investment in the Intertie, so the portion of the costs paid for by the state grant is not depreciated + The depreciation charges become a source of cash flow which may be used to pay off the bonds Copyright © Decision Focus Incorporated Copuright © Aeronormics Incorporated $2947-02 11 How Is Maintenance Expense Calculated? + Both construction and maintenance expenses are taken from an updated version of Appendix H of the Draft Cost Summary Report prepared by Power Engineers, Inc. dated October 28, 1997 + Appendix H gives costs for the two base routes with two types of cable for each route; we calculated results for the Enstar Base Route with 2-3 Core Cable (the lowest cost alternative) and the Tesoro Base Route with 4-1 Core Cable (the highest cost alternative) Copyright © Decision Focus Incorporated Copyright © Aeronanics Incorporated $2947-02 12 Fw Were the Savi gs from Avoided | and Deferred Generation Additions Calculated? + We developed estimates of cumulative capacity additions which would be required in Anchorage each year with and without the Intertie; the difference represents avoided capacity each year + We assumed a $55/kW-year savings in 1997 dollars on all avoided capacity Copyright © Decision Fou 3 incorporated Copyright © Aeronamics Incorporated $2947-02 13 How Were Savings in Economy Energy and Transmission Losses Calculated? + We started with the savings in economy energy and transmission losses shown in Table 5-3 of DFI’s 1989 Economic Feasibility study + That table shows the savings in dollars per year in 1994, 2002, and 2010, assuming the Intertie opened in 1994 for two cases representing alternative views about the transfer capability of the existing line, and nine scenarios for each case representing fuel cost and load outcomes + We added 10 years to all dates to adjust for the planned opening of the Intertie in 2004 + We multiplied all costs by 1.205 to convert to 1997 dollars, then multiplied by .725 to adjust for lower fuel price forecasts Copyright © Decision Focus incorporated Copyright © Aeronamics Incorporated $2947-02 14 F" ww Were Savings ‘n Economy Ener y and Transmission Losses Calculated? (Continued) + We averaged results across all fuel cost and load outcome scenarios shown in the table for the 70 MW existing line transfer capability case + The original benefit estimates valued fuel savings net of royalties paid to the State of Alaska; since any savings in royalty payments do represent savings to electric ratepayers, we multiplied our benefit estimates by 1.104 to re-include these savings in our benefit estimates + We interpolated values for all years other than 2004, 2012, and 2020; values after 2020 values were increased at the rate of inflation Copyright © Decision Focus Incorporated Copyright © Acronomics Incorporated $2947-02 15 a How Were Savings Due to Operating Reserve Sharing Calculated? + We started with the projected $10.6 million in present value of savings (in 1990 dollars) from the 1989 DFI study + This value was multiplied by 1.205 to convert to 1997 dollars and by .725 to account for lower fuel price forecasts + Annual values in 1997 dollars were obtained by annuitizing this present value over 40 years at a 4.5% interest rate (the interest rate used to calculate the present value in the 1989 study) Copyright © Decision Forus Incorporatec Copyright © Aeronamics Incorporated $2947-02 16 How Were the Other Types of Savings Calculated? + The savings in maintenance expense on the existing line were assumed to be $.5 million per year in 1997 dollars during the period 2005-2012 when the existing line will be rebuilt + The savings from the elimination of the minimum 25 MW Kenai CT generation requirement was assumed to equal $490,000 per year in 1997 dollars + The savings from avoiding loss of transfer capability during adverse weather conditions and work adjacent to the existing line were assumed to equal $520,000 per year in 1997 dollars Copyright © Decision Focus Incorporated Copyright © Aeronomics Incorporated $2947-02 17 F’ ww Does the Sout’ ern Intertie Affec* Ratepayers If the Enstar 2-3 Route Is Built? + The Enstar 2-3 route, the least expensive of the routes under study, would produce a small savings starting in the first year of operation, and the savings would grow larger in later years + Savings grow over the years primarily because benefits rise with inflation, while bond interest, assignable margins and depreciation do not grow + In fact, bond interest expense actually declines over the years as the bonds used to finance the Intertie are paid off + Savings increase rapidly in the 2012-2022 period when the Intertie makes possible a deferral of new generation additions, however, these deferred generation savings shrink in the 2023- 2034 period when much of this deferred generation must finally be built Copyright © Decision Focus Incorporatect Copyright © Aeronomics Incorporated $2947-02 18 Hew Does the Sout&ern Intertie Affec? Ratepayers If the Tesoro 4-1 Route Is Built? + The Tesoro 4-1 route, the most expensive of the routes under study, would generally provide a small savings in the early years, and these savings would grow larger in later years + Tesoro 4-1] does, however, have a small cost to ratepayers in the first two years, and lower savings than Enstar 2-3 in subsequent years + Tesoro 4-1] would also require cable replacements in 2021 and 2038; these cable replacements would require the issuance of additional bonds and explain the sawtooth pattern of ratepayer savings Copyright © Decision Focus Incorporated Copyright 6 Aeronomics Incorporated $2947-02 19 FAFOL LATHE