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Intertie OC meeting Sep 1993
Fy i677 =a FB Ack Yurbe > extice PR ToC W\ edu ALASKA INTERTIE OPERATING COMMITTEE MEETING AGENDA WEDNESDAY, SEPTEMBER 8, 1993 BEGIN AT 9:30 A.M. I. Adoption of prior meeting minutes I. Approval/modification of agenda III. | Committee correspondence and reports Dispatch Subcommittee Reliability/Protection Subcommittee Machine/Rating Subcommittee SCADA/Communication Correspondence Received Intertie Status Report 1. Record of IOC Decisions aAMOOW > HO FERC Notice of Intent (NOI) Coordination/Regulation Subcommittee IV. Visitors comments related to items on agenda V. Work Session A. Recess and work session B. Dispatch C. Reliability/Protection D. SCADA/Communication E. Machine/Rating 1. Project List ' F. — Intertie O&M FY94 Budget G. Stevens Substation VI. Formal Operating Committee action/recommendation VII. Subcommittee assignments VIII Determine agenda for next meeting IX. | Adjournment Meeting location: Golden Valley Electric Association Board Room 758 Illinois Fairbanks, Alaska 99707 (907) 452-1151 ALASKA INTERTIE OPERATING COMMITTEE WEDNESDAY, JULY 14, 1993 (MATANUSKA ELECTRIC ASSOCIATION BOARD ROOM) MEETING MINUTES Present: James Hall Alaska Electric Generation & Transmission (AEG&T)/Matanuska Electric Association (MEA) Sam Matthews Alaska Electric Generation & Transmission (AEG&T)/Homer Electric Association (HEA) Afzal Khan Alaska Energy Authority (AEA) Tim McConnell Anchorage Municipal Light & Power (AML&P) Hank Nikkels Anchorage Municipal Light & Power (AML&P) Tom Lovas Chugach Electric Association (CEA) John Cooley Chugach Electric Association (CEA David Burlingame — Chugach Electric Association (CEA) Bradley Evans Golden Valley Electric Association (GVEA) The meeting was called to order by Chairman Brad Evans at 10:00 a.m. at the Matanuska Electric Association Board Room, Palmer, Alaska. 1. Adoption of Prior Meeting Minutes _ Tom Lovas moved that the May 17, 1993, revised meeting minutes be adopted. Brad Evans seconded the motion. The motion was adopted unanimously. Tom Lovas moved that the May 28, 1993, meeting minutes be adopted with the correction on page 6, Item VII - Reliability/Protection, add "Review AML&P's and CEA's SILOS schemes." Tim McConnell seconded the motion. The motion was adopted unanimously. Ul. Approval/Modification Of Agenda The July 14, 1993, meeting agenda was adopted unanimously. I. Committee Correspondence and Reports A. Dispatch Subcommittee: The Dispatch Subcommittee did not meet. B. _Reliability/Protection Subcommittee David Burlingame stated that the subcommittee did not meet but received a letter from AML&P on AML&P's SILOS scheme. C. Machine/Rating Subcommittee: The Machine/Rating Subcommittee did not meet. D. SCADA/Metering/Communications: This subcommittee did not meet. Page | Intertie Operating Committee Mecung July 14, 1993 E. Correspondence Received Under Correspondence, Afzal Khan distributed the following: 1. MEA letter, dated June 25, 1993, to IOC Chairman Brad Evans. Subject: Stevens Substation Ownership 2. IOC Chairman letter, dated June 2, 1993, to Ron Saxton. Subject: IOC Request for Legal Opinion. 3. AML&P letter, dated June 25, 1993, to IOC Chairman Brad Evans. Subject: Shed in Lieu of Spin 4. GVEA memorandum, dated June 2, 1993, to IOC Chairman Brad Evans. Subject: Alaska Intertie Structure #570 5. MEA letter, dated June 4, 1993, to IOC Chairman Brad Evans. Subject: Stevens Substation 6. | Ater Wynne Hewitt Dodson & Skerritt letter, datad July 6, 1993, to Mr. David Highers, Railbelt Utilities Group Chairman. Subject: Modification of the Duties of the Intertie Operating Committee. Intertie Status Update Under Intertie Status, Afzal Khan provided an update on the condition of structures #570. He distributed the following letters: 1. AEA letter, dated June 3, 1993, to GVEA. Subject: Alaska Intertie Structure #570. 2. GVEA memorandum, dated June 2, 1993, to IOC Chairman Brad Evans. Subject: Alaska Intertie Structure #570 3. GVEA letter, dated June 14, 1993, to Dryden & LaRue. Subject: Tower #570. 4. Dryden & LaRue letter, dated June 11, 1993, to GVEA. Subject: Proposal for Engineering Services for Foundation Remediation - Tower #570. ASCC Status There was a brief discussion of allocation formula. Tom Lovas stated that this subcommittee will meet on August 19, 1993. IV. Visitor comments related to items on Agenda: No visitors were present. V. Work Session A. B. The-Operating Committee went into work session. Dispatch There was a brief discussion of outage reporting and reporting by the controllers. The MEA letter, dated June 25, 1993, to IOC Chairman was discussed. The main issues addressed were technical and accounting procedures. There was also a discussion of AML&P's report on Spinning Reserves. The AML&P's correspondence on spinning reserves should be coordinated with the northern controller. The Dispatch subcommittee is to Page 2 Intertie Operating Committee Meeting July 14, 1993 review the Ron Saxton letter, dated July 6, 1993, to Railbelt Utilities Group Managers. Chairman Brad Evans would like to see that each participant shalt prepare a list of what duties that the northern and southern controllers should perform. The IOC Chairman Brad Evans also stated that the requirements be submitted to the Dispatch subcommittee. The Intertie Operating Committee took a lunch break from 12:05 p.m. to 12:25 p.m. C. Reliability/Protection David Burlingame stated that the subcommittee finally adopted the under frequency load shedding plan. The GVEA SILOS plan is in operation. This subcommittee will study AML&P and CEA requirements for the SILOS system. Jim Hall stated that he will provide final construction drawings for the Stevens substation for the Reliability/Protection subcommittee's review. D. SCADA/Metering/Communications Jim Hall stated that the fourth port at Stevens substation RTU is available for AML&P's use in the future. E. Machine/Rating The subcommittee Chairman Hank Nikkels stated that the project list did not change. F. _Intertie FY94 Budget Afzal Khan stated that starting July 1, 1993, GVEA and AML&P are to submit monthly invoices in accordance with Article 10.3.5, Alaska Intertie Agreement. G. Stevens Substation Jim Hall briefly discussed the MEA's letter, dated June 25, 1993, to IOC Chairman Brad Evans. : VI. Formal Operating Committee Action/Recommendation Tom Lovas' moved that the IOC requires that all participants develop and submit a list of controller responsibilities and duties for consideration by Dispatch subcommittee by August 1, 1993. Afzal Khan seconded the motion. The motion was adopted unanimously. Tom Lovas moved that the continued memoranda, Comments on Intertie Operations and Related Issues, identified by AML&P as Southern Controller is not sanctioned, are not in keeping with prior action (May 28) of the IOC, have not been verified and may be subject to factual errors, and should be discontinued, are not to be accepted as official Intertie correspondence-under the auspices of the Intertie Operating Committee; and should be discontinued until such time as IOC action is taken in the alternative. Brad Evans seconded the motion. Roll call resulted in the following: Brad Evans GVEA _ yea AfzalKhan AEA abstain Sam Matthews AEG&T yea Vince Mottola FMUS __ not present Tom Lovas CEA yea Tim McConnell AML&P no The motion failed. Page 3 Intertie Operating Committee Meeung July 14, 1993 VII. Subcommittee Assignments Dispatch Chairman Brad Evans directed the DISPATCH subcommittee to meet at the discretion of its Chairman to look into the following issues: 1) Dispatch Training Plan 2) NERC operating aspects 3) Switching and Tagging Procedures 4) MEA tap at Talkeetna Operating Procedure Construction Schedule and Methods SCADA Control Microwave Communications Control Point Issues 7 Ag TP 5) Joint meeting with Machines/Rating subcommittee regarding Testing Procedures and Verification 6) Joint meeting with Reliability/Protection subcommittee regarding under frequency load shedding 7) Revise Scheduling Procedures -- Douglas substation as a regulating point 8) Identify completion dates 9) Finalize the procedures for line patrol for IOC review including discussion with AEA and maintenance contractors 10) Outage Reporting. Reliability/Protection Chairman Brad Evans directed the RELIABILITY/PROTECTION Subcommittee to meet at the discretion of its Chairman to: continue work on under frequency load shedding study; monitor the Talkeetna substation design and construction; review the procedure for record drawings update and certification; and review AML&P's and CEA's SILOS schemes. David Burlingame stated that the next meeting of the Reliability/Protection subcommittee will be on July 22, 1993. Machine/Rating Chairman Brad Evans directed the Machines/Rating subcommittee to meet every month. Chairman Brad Evans also directed the Machine/Rating subcommittee Chairman to be present at the next IOC meeting. Chairman Brad Evans also directed the Machine/Rating Subcommittee Chairman to schedule a joint meeting with Dispatch subcommittee and complete assignments as requested. SCADA/Metering/Communications Chairman Brad Evans directed the SCADA/Metering/Communications subcommittee to meet at the discretion of its Chairman to revisit the subcommittee's agenda of February 18, 1993. Chairman Brad Evans also directed the subcommittee to: Elect a new Subcommittee Chairman; look into the SCADA coordination and development for Stevens substation; and determine status of the Alaska Intertie data network, initial general requirements for future resources and how they can be integrated into the existing system. Page 4 Intertie Operating Committee Meeting July 14, 1993 THE NEXT REGULAR MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON WEDNESDAY, SEPTEMBER 8, 1993 AT 9:30 A.M. AT THE GOLDEN VALLEY ELECTRIC ASSOCIATION BOARD ROOM, FAIRBANKS, ALASKA. VIII. Determine agenda for next meeting The Operating Committee set the agenda for the next meeting of the Operating Committee. IX. Adjournment Tim McConnell moved for the meeting to adjourn. Brad Evans seconded the motion. The Operating Committee unanimously adopted the motion to adjourn at 2:00 p.m. Respectfully submitted, ABM Dennis McCrohan Secretary, Intertie Operating Committee Attachments: 1. September 8, 1993, meeting agenda. 2. IOC July 14, 1993, meeting attendance sheet. The following were distributed at the July 14, 1993, meeting: 3. MEA letter, dated June 25, 1993, to IOC Chairman Brad Evans. Subject: Stevens Substation Ownership 4. IOC Chairman, letter, dated June 2, 1993, to Ron Saxton. Subject: IOC Request for Legal Opinion. 5. AML&P letter, ded June 25, 1993. , to IOC Chairman Brad Evans. Subject: Shed in Lieu of Spin 6. AEA letter, dated June 3, 1993, to GVEA. Subject: Alaska Intertie Structure #570. de GVEA memorandum, dated June 2, 1993, to IOC Chairman Brad Evans. Subject: Alaska Intertie Structure #570 8. GVEA letter, dated June 14, 1993, to Dryden & LaRue. Subject: Tower #570. 9. Dryden & LaRue letter, dated June 11, 1993, to GVEA. Subject: Proposal for Engineering Services for Foundation Remediation - #570. 10. MEA letter, dated June 4, 1993, to IOC Chairman Brad Evans. Subject: Stevens Substation 11. Ater Wynne Hewitt Dodson & Skerritt letter, datad July 6, 1993, to Mr. David Highers, Railbelt Utilities Group Chairman. Subject: Modification of the Duties of the Intertie Operating Committee. 12. Draft Formal Operating Committee Action/Recommendation. Page 5 ALASKA INTERTIE OPERATING COMMITTEE WINATES IOCATTEN.XLS MEETING 14-Jul-93 In Attendance: oan pe Had \SKELS QS\- sess IG@2=F73F PE2-V OG > Be Ys 263-533) 275-3307 | eos 7269 | S6/-7E77 AB3-T¥ 5k | Page 1 EXISTING Inrereres 3-), | . le a acd Packets S33, ALASKA INTERTIE OPERATING COMMITTEE .° WEDNESDAY, SEPTEMBER 8, 1993 fe 7" **& (GOLDEN VALLEY ELECTRIC ASSOCIATION BOARD ROOM) MEETING MINUTES SEP 16 1993 Present: James Hall Alaska Electric Generation & Transmission (AEG&T)/Matanuska Electric Association (MEA) Afzal Khan Alaska Industrial Development and Export Authority (AIDEA) Tim McConnell Anchorage Municipal Light & Power (AML&P) David Burlingame Chugach Electric Association (CEA) John Cooley Chugach Electric Association (CEA Vincent Mottola Fairbanks Municipal Utilities System (FMUS) Bradley Evans Golden Valley Electric Association (GVEA) Marvin Riddle Golden Valley Electric Association (GVEA) Steve Swift Golden Valley Electric Association (GVEA) Fred LeBau Golden Valley Electric Association (GVEA) The meeting was called to order by Chairman Brad Evans at 9:15 a.m. at the Golden Valley Electric Association Board Room, Fairbanks, Alaska. I. Adoption of Prior Meeting Minutes David Burlingame moved that the September 8, 1993, meeting minutes be adopted. Jim Hall seconded the motion. The motion was adopted unanimously. Il. Approval/Modification Of Agenda Afzal Khan moved that the September 8, 1993, IOC meeting agenda be adopted with the modifications. The modifications were as follows; added Item [II-F(2), Tower #570 Status; and III-I, Stevens Substation Contract Issues. Marvin Riddle seconded the motion. The motion was adopted unanimously. It. Committee Correspondence and Reports A. Dispatch Subcommittee: Brad Evans stated that the Dispatch Subcommittee met on August 31, 1993. At the meeting, the following items were discussed: 1) Control of Stevens Substation; 2) Metering of Stevens Substation; 3) Controller Duties; 4) Switching and Tagging; 5) Under Frequency Load Shed and SILOS; 6) Line Patrols; and 7) DecNet Scheduling. B. Reliability/Protection Subcommittee David Burlingame stated that the subcommittee met on July 22, 1993. He briefly discussed the recent under frequency load shedding operations. There were 5 or 6 operations. Two were first stage operations and the last operation worked correctly. AML&P and CEA SILOS schemes were discussed. David Burlingame also stated that AML&P intends to go with SILOS within 90 days with or without the approval of IOC. Machine/Rating Subcommittee: The Machine/Rating Subcommittee did not meet. D. SCADA/Metering/Communications: This subcommittee did not meet. Page | of 6 Intertie Operating Committee Meeting September 8, 1993 E. Correspondence Received Under Correspondence, Afzal Khan distributed the following: 1. GVEA letter, dated August 4, 1993, to IOC Chairman Brad Evans. Subject: GVEA IOC Representation 2. CEA letter, dated August 24, 1993, to IOC Chairman Brad Evans. Subject: CEA IOC Representation 3. AIDEA letter, dated September 1, 1993, to IOC Chairman Brad Evans. Subject: Intertie Committee Meeting September 8, 1993 4 AEA letter, dated August 12, 1993, to IOC Chairman Brad Evans. Subject: Controller Costs and Duties $ MEA letter, dated June 25, 1993, to IOC Chairman Brad Evans. Subject: MEA's Stevens Substation 6. GVEA letter, dated September 7, 1993, to IOC Chairman Brad Evans. Subject: Controller Duties 7. MEA letter, dated September 7, 1993, to IOC Chairman Brad Evans. Subject: Operator Duties 8. AML&P letter, dated September 8, 1993, to IOC Chairman Brad Evans. Subject: Negotiating Cost Reductions for Intertie (New and Old) Operations. 9. GVEA letter, dated August 5, 1993, to AEA. Subject: Alaskan Intertie Operating Budget 10. CEA letter, dated August 17, 1993, to AEA. Subject: Teeland Substation SVC Maintenance Budget 11. CEA letter, dated July 28, 1993, to AEA. Subject: Teeland Substation SVC Maintenance Budget 12. Jullie Simon, Ater Wynne Hewitt Dodson & Skerritt letter, datad July 23, 1993, to IOC Chairman Brad Evans. Subject: FERC Transmission Update 13. Anchorage-Fairbanks Intertie, Project Insurance Premiums and Fees FY94. F. _ Intertie Status Update Under Intertie Status, Steve Swift provided an update on the condition of structure #570. He distributed the Dryden & LaRue report, dated August 13, 1993, on Options for Tower #570 Foundations. This structure was having jacking problem for the last five years. GVEA is in the process of obtaining permission to cross track of land for access to Tower #570. GVEA is also working on a permanent solution for a year round access. Steve Swift stated that the structure #749 is under observation. The data shows movement and Steve Swift thinks it seems to be normal. Afzal Khan distributed the document titled "Alaska Intertie Operating Committee Actions/Recommendations to IOC members." G&Hu. ASCC Status John Cooley stated that he will keep IOC informed. I. Stevens Substation Contract Issues There was a brief discussion of the various issues concerning MEA Stevens Substation. Page 2 of 6 Intertie Operating Committee Meeting September 8, 1993 IV. Visitor comments related to items on Agenda: No visitors were present. The Intertie Operating Committee took a break from 10:50 a.m. to 11:00 a.m. V. Work Session A. The Operating Committee went into work session. Dispatch The IOC discussed in length the issue of Alaska Intertie Control Point. The Douglas Substation is still the Alaska Intertie control point. The metering at Stevens Substation was discussed. The Intertie Operating Committee took a lunch break from 12:05 p.m. to 12:30 p.m. The correspondence relating to controller duties was discussed in length. Marvin Riddle discussed the contents of GVEA letter, dated September 7, 1993, to IOC Chairman Brad Evans. The MEA stated their position on controllers' responsibilities in MEA letter, dated September 7, 1993. Tim McConnell discussed the ML&P's position on Controller Duties in a letter, dated September 8, 1993, to IOC Chairman and Participants. David Burlingame stated that the CEA submitted their position in May 28, 1993, letter to IOC. Reliability/Protection David Burlingame stated that the subcommittee is working on two areas, one is AML&P and CEA SILOS systems and the second one is the power restoration procedures incorporating Stevens Substation. There was a brief discussion of SILOS system restoration. Under first stage load shedding, there is not enough generation to cover the first stage load shedding. The IOC got to have a restoration procedure. SCADA/Metering/Communications The IOC decided that Fred LeBau be the interim SCADA Subcommittee Chairman until the SCADA Subcommittee selects a permanent Chairman. Machine/Rating This subcommittee will meet on September 16, 1993, at GVEA, Fairbanks. Intertie O&M FY94 Budget Afzal Khan distributed O&M budgets that he received from CEA and GVEA. Stevens Substation Jim Hall provided an update on the Stevens Substation. He stated that the SCADA would not be available until December 1993. MEA will provide hourly MW readings. Jim Hall and David Burlingame will work in the interim. Tim McConnell would like to see that Doug Hall be included. The MEA would provide an interim package for operating without communications. Page 3 of 6 Intertie Operating Committee Meeting September 8, 1993 The Intertie Operating Committee took a break from 2:05 p.m. to 2:15 p.m. VI. Formal Operating Committee Action/Recommendation Chairman Brad Evans moved that the IOC hold a special meeting to assess the duties and responsibilities of the State, its maintenance contractors and operators. Jim Hall seconded the motion. Roll call resulted in the following: Vince Mottola © FMUS yea Tim McConnell AML&P yea Dave Burlingame CEA yea Brad Evans GVEA yea Afzal Khan AIDEA yea Jim Hall AEG&T yea The motion passed. Tim McConnell moved that the IOC authorizes the energization of the in-line switches of the Stevens Substation with the understanding that the disconnecting switches isolating the Stevens Substation will remain open until authorization from IOC is obtain for the energization of the Stevens Substation. Roll call resulted in the following: Vince Mottola © FMUS yea Tim McConnell AML&P yea Dave Burlingame CEA yea Brad Evans GVEA yea Afzal Khan AIDEA yea Jim Hall AEG&T yea The motion passed. The IOC recommended that Fred LeBau be appointed temporary Chairman of the SCADA/ Metering/Communications Subcommittee until the Subcommittee meets to elect a new Chairman. Subcommittee Assignments Dispatch Chairman Brad Evans directed the DISPATCH subcommittee to meet at the discretion of its Chairman to look into the following issues: 1) Dispatch Training Plan 2) NERC operating aspects 3) Switching and Tagging Procedures 4) MEA tap at Talkeetna a. Operating Procedure b. Construction Schedule and Methods c. SCADA Control d. Microwave Communications e. Control Point Issues 5) Joint meeting with Machines/Rating subcommittee regarding Testing Procedures and Verification 6) Joint meeting with Reliability/Protection subcommittee regarding under frequency load shedding Page 4 of 6 Intertie Operating Committee Meeting September 8, 1993 7) Revise Scheduling Procedures -- Douglas substation as a regulating point 8) Identify completion dates 9) Finalize the procedures for line patrol for IOC review including discussion with AEA and maintenance contractors 10) Outage Reporting. 11) Under Frequency Load Shedding/SILOS Restoration. 12) Restoration Procedures for Stevens Substation. Reliability/Protection Chairman Brad Evans directed the RELIABILITY/PROTECTION Subcommittee to meet at the discretion of its Chairman to: continue work on under frequency load shedding study; monitor the Talkeetna substation design and construction; review the procedure for record drawings update and certification; work on load restoration; and review AML&P's and CEA's SILOS schemes. Machine/Rating Chairman Brad Evans directed the Machines/Rating subcommittee to meet every month. Chairman Brad Evans also directed the Machine/Rating subcommittee Chairman to be present at the next IOC meeting. Chairman Brad Evans also directed the Machine/Rating Subcommittee Chairman to schedule a joint meeting with Dispatch subcommittee and complete assignments as requested. SCADA/Metering/Communications Chairman Brad Evans directed the SCADA/Metering/Communications subcommittee to meet at the discretion of its Chairman to revisit the subcommittee's agenda of February 18, 1993. Chairman Brad Evans also directed the subcommittee to: Elect a new Chairman; look into the reliability of the Data link network; look into the SCADA coordination and development for Stevens substation; review specifications for communications by WSCC and others; and determine status of the Alaska Intertie data network, initial general requirements for new resources and how they can be integrated into the existing system. THE SPECIAL MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON WEDNESDAY, SEPTEMBER 22, 1993 AT 9:30 A.M. AT THE ALASKA ENERGY AUTHORITY CONFERENCE ROOM, ANCHORAGE, ALASKA. THE NEXT REGULAR MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON WEDNESDAY, NOVEMBER 10, 1993 AT 9:30 A.M. AT THE CHUGACH ELECTRIC ASSOCIATION ROOM, ANCHORAGE, ALASKA. VIII. Determine agenda for next meeting The Operating Committee set the agenda for the next meeting of the Operating Committee. IX. Adjournment Vince Mottola moved for the meeting to adjourn. Jim Hall seconded the motion. The Operating Committee unanimously adopted the motion to adjourn at 3:15 p.m. Respectfully submitted, Gee WV Me Caln Dennis McCrohan, Secretary, Intertie Operating Committee Page 5 of 6 Intertie Operating Committee Meeting September 8, 1993 Attachments: Le De 35 September 22, 1993, special meeting agenda. November 10, 1993, meeting agenda. IOC September 8, 1993, meeting attendance sheet. The following were distributed at the September 8, 1993, meeting: 4. oN a ne 10. 11. 12. 133 14. 15: 16. 17. 18. 19; 20. ahs 22. 23. 24. 25. GVEA letter, dated August 4, 1993, to IOC Chairman Brad Evans. Subject: GVEA IOC Representation CEA letter, dated August 24, 1993, to IOC Chairman Brad Evans. Subject: CEA IOC Representation AIDEA letter, dated September 1, 1993, to IOC Chairman Brad Evans. Subject: MEA Stevens Substation Addition AIDEA letter, dated September 1, 1993, to IOC Chairman Brad Evans. Subject: Intertie Committee Meeting September 8, 1993 AEA letter, dated August 12, 1993, to IOC Chairman Brad Evans. Subject: Controller Costs and Duties MEA letter, dated June 25, 1993, to IOC Chairman Brad Evans. Subject: MEA's Stevens Substation GVEA letter, dated September 7, 1993, to IOC Chairman Brad Evans. Subject: Controller Duties MEA letter, dated September 7, 1993, to IOC Chairman Brad Evans. Subject: Operator Duties AML&P letter, dated September 8, 1993, to IOC Chairman Brad Evans. Subject: Negotiating Cost Reductions for Intertie (New and Old) Operations. AML&P letter, dated April 16, 1993, to AEA. Subject: Alaska Intertie - Budget and Operations GVEA letter, dated May 7, 1992, to AML&P & CEA. Subject: Intertie Operations/Cost CEA letter, dated April 12, 1993, to AEA,. Subject: Alaska Intertie - Budget and Operations AEA letter, dated May 3, 1993, to GVEA. Subject: Alaska Intertie - Final Scope of Operations and Budget, FY 94. AEA letter, dated May 3, 1993, to CEA. Subject: Alaska Intertie - Final Scope of Operations and Budget, FY 94. GVEA letter, dated August 5, 1993, to AEA. Subject: Alaskan Intertie Operating Budget CEA letter, dated August 17, 1993, to AEA. Subject: Teeland Substation SVC Maintenance Budget CEA letter, dated July 28, 1993, to AEA. Subject: Teeland Substation SVC Maintenance Budget Jullie Simon, Ater Wynne Hewitt Dodson & Skerritt letter, datad July 23, 1993, to IOC Chairman Brad Evans. Subject: FERC Transmission Update Anchorage-Fairbanks Intertie, Project Insurance Premiums and Fees FY94. Dryden & LaRue letter, dated August 13, 1993, to GVEA. Subject: Anchorage-Fairbanks Intertie, Report on Options for Tower 570 Foundations AML&P meom, dated July 27, 1993. Subject: Stevens Substation Transmission Access: The Necessary Terms.And Conditions. Page 6 of 6 ALASKA INTERTIE OPERATING COMMITTEE SPECIAL MEETING AGENDA WEDNESDAY, SEPTEMBER 22, 1993 BEGIN AT 9:30 A.M. I. Duties and Responsibilities of the State, its maintenance contractors and operators. Il. Adjournment Meeting location: Alaska Energy Authority Conference Room 701 East Tudor Road Anchorage, Alaska 99519-0869 (907) 561-7877 ALASKA INTERTIE OPERATING COMMITTEE MEETING AGENDA WEDNESDAY, NOVEMBER 10, 1993 BEGIN AT 9:30 A.M. I. Adoption of prior meeting minutes Il. Approval/modification of agenda Ill. | Committee correspondence and reports Dispatch Subcommittee Reliability/Protection Subcommittee Machine/Rating Subcommittee SCADA/Communication Correspondence Received Intertie Status Report 1. Stevens Substation Contract Issues ASCC Status AMO > a IV. Visitors comments related to items on agenda V. Work Session Recess and work session Dispatch Reliability/Protection SCADA/Communication Machine/Rating 1. Project List Intertie O&M FY94 Budget Stevens Substation Review of IOC Decisions MOODS “am VI. Formal Operating Committee action/recommendation VII. Subcommittee assignments VIII Determine agenda for next meeting IX. Adjournment Meeting location: Chugach Electric Association Training Room 5601 Minnesota Drive Anchorage, Alaska 99519-6300 (907) 563-7494 IOCATTEN.XLS WU wtes ALASKA INTERTIE OPERATING COMMITTEE MEETING 8-Sep-93 In Attendance: Phone Number Page 1 fli' tw < mos =iVED AUG 09 1993 ALSSKA D7 7 tetu0 ITY GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Box 71249, Fairbanks, Alaska 99707-1249, Phone 907-452-1151 August 4, 1993 TO: FROM: Brad Evans IOC Chairman Mike Kelly General Manage GVEA IOC Representation I have selected Marvin Riddle as GVEA's alternate committee member on the Intertie Operating Committee. correspondence as representation. cc: Marvin Riddle IOC Members official notification Please consider this of our change in cc ‘Liat ; CHUGACH cLECTIRIC 7e¢ pe be ASSOCIATION, INC. prey DAVID L. HIGHERS General Manager Pr key SEN phe August 24, 1993 US oF an Bradley Evans, Chairman Intertie Operating Committee Golden Valley Electric Association, Inc. P.O. Box 1249 Fairbanks, Alaska 99707 Re: IOC Representation Dear Brad: As of this date, I have appointed David Burlingame to replace Tom Lovas as Chugach’s primary representative on the Intertie Operating Committee. Please consider this correspondence as Official notification of our change in representation. David L. Highers General Manager cc: IOC Representatives Utility General Managers 5601 Minnesota Drive « P.O. Box 196300 « Anchorage, Alaska 99519-6300 Phone 907-563-7494 ¢ FAX 907-562-0027 nunat @ ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY 480 WEST TUDOR + ANCHORAGE, ALASKA 99503-6690 + (907) 561-8050 + FAX (907) 561-8998 ' wren SEP 03 1993 ALASKA ENSR2Y AUTHORITY September 1, 1993 Mr. Eric E. Wohlforth, Esq. Wohlforth, Argetsinger Johnson & Brecht 900 West 5th Avenue, Suite 600 Anchorage, AK 99501-2048 SUBJECT: MEA Stevens Substation Addition Alaska Intertie Agreement ATTORNEY CLIENT CONFIDENTIAL Dear Eric: Attached is a May 19, 1993 letter to Ron Garzini from Brad Evans, Intertie Operating Committee Chairman, requesting a response to concerns about letting MEA directly utilize the Alaska Intertie. The concerns stem from the fact that MEA is not a participating utility under the Alaska Intertie Agreement, but along with HEA, is currently represented by AEG&T in that Agreement. As we understand it, the Intertie Operating Committee is amenable to MEA's proposal; however, the appropriate mechanism to allow for it is not readily ascertainable in the Intertie Agreement. Please review the questions raised below and the Agreement in light of the proposal and provide us with the guidance to proceed toward accomplishing the proposal. This issue has been outstanding for some period so your early response is appreciated. Please contact Mr. Jim Baldwin or me if additional information is required. Mr. Evans raises the two following issues in his letter: 1. Does MEA have participant status and rights through their association with AEG&T? MEA is not signatory to the AIA and the contract is silent on this question. 2. What impact does construction and operation of a substation by a non-participating utility have? Wer VG Mr. Eric Wohlforth, Esq. September 1, 1993 Page Two Additional AEA questions: 1. 2. Does section 7.4.2 allow AEA to add a substation to the Intertie? a. If so, must AEA own the substation, or can it be owned by either a participating or non-participating utility? b. If the Agreement must be modified, what provisions must be changed? Does section 7.4.3. allow AEG&T or another participating utility to add a substation to the Intertie (this section omits the AEA's 7.4.2 language “including taps to the line to provide electrical services at locations which it deems beneficial and reasonable.")? a. If so, must AEG&T own the substation, or can it be owned by a non-participating utility? b. If AEG&T is not required to own the substation, can it sell its Intertie Transfer Capability Rights without modifying the Agreement? c. If the Agreement must be modified, what provisions must be changed? Please copy Mr. Baldwin on your response. Very truly yours, Pat, Cashin Dennis V. McCrohan, P.E. Deputy Director (Energy) DVM:ec cc: R. D. A. J. Snell, AIDEA 1/1 Beardsley, AIDEA 1/0 Khan, AEA 1/0 — Baldwin, Dept. of Law 1/1 Attachment i, JDM OTE & @ ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY 480 WEST TUDOR + ANCHORAGE, ALASKA 99503-6690 + (907) 561-8050 + FAX (907) 561-8998 hicecIVED SEP 03 1993 Mr. Bradley Evans, Chairmap4SKA EMf°7V AUTHORITY Alaska Intertie Committee Golden Valley Electric Association P.O. Box 71249 Fairbanks, AK 99707 September 1, 1993 Subject: Intertie Committee Meeting September 8, 1993 Dear Mr. Evans: Due to other commitments, I will not be able to attend the September 8, 1993 meeting. Mr. Afzal Khan will attend and has been delegated authority to act on my behalf. I apologize for not attending. As you are aware, the objective of the recent legislation regarding AEA is to transfer duties and responsibilities provided by AEA to the utility facility operators or utility groups. The transfer, however, will occur only where consistent with prudent utility practice and AEA's fiduciary obligations, and where economic. In early September, I would like to arrange a meeting with you to identify the specific steps and timetable to implement this objective for the existing intertie. In the interim, it would be helpful if you could identify the specific utility parties designated for these discussions. I also wish to assure the Committee and you, that during the transition period, AEA will continue to provide all agreed services. Please contact me if you have any questions. Very truly yours, TOM Qh ___ Dennis V. McCrohan, P.E. Deputy Director (Energy) DVM: ec cc: A. Khan, AEA a R. Snell, AIDEA S. Sieczkowski, AEA S. Matthews, AEG&T T. Lovas, CEA V. Mottola, FMUS T. McConnell, AML&P Alaska Energy Authority A Public Corporation August 12, 1993 Mr. Bradley Evans, Chairman Intertie Operating Committee Golden Valley Electric Association P.O. Box 71249 Fairbanks, AK 99707-1249 Subject: Controller Costs and Duties Dear Mr. Evans: In your letter dated May 18, 1993, you asked that the Energy Authority examine and determine essential duties as the owner of the Anchorage-Fairbanks Intertie Project. As you know, because of the recently enacted legislation, the role of the Energy Authority concerning the Anchorage-Fairbanks Intertie is being transferred to the Alaska Industrial Development and Export Authority (AIDEA) effective August 12, 1993. AIDEA will be assessing their role and the manpower requirement necessary to protect the State's investment in the Anchorage-Fairbanks Intertie. In the meantime, the Intertie Operating Committee should assume that AIDEA's budget for FY94 is the same as that previously submitted by the Energy Authority. Please call me with any questions at 561-7877. Sincerely, lye A. KL Afzal H. Khan Manager of Engineering Support AKH:it cc: Dennis V. McCrohan, Alaska Industrial Development & Export Authority Stanley E. Sieczkowski, Alaska Energy Authority David R. Eberle, Alaska Energy Authority PO. Box 190869 704 East Tudor Road Anchorage, Alaska 99519-0869 (907) 561-7877 Fax: (907) 561-8584 93Q3/1T5249 a RECEIVED BY may 21 1993 ALASKA ENERGY AUTHORITY. GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Box 71249, Fairbanks, Alaska 99707-1249, Phone 907-452-1151 brn ¢ bot OF May 18, 1993 Ron Garzini Alaska Energy Authority P.O. Box 190869 Anchorage, AK 99519-0869 Subject: 1993 Controller Costs and Duties Dear Ron: 2) toy In response to recent correspondence regarding Alaska Intertie costs from various intertie participants, Golden Valley believes all participant members may be best served by considering the following. Historically, all participants came together to decide the appropriate duties of the Northern and Southern Controllers (NC,SC). It has now been eight years since commencement of intertie operations, and participant members have increased their knowledge of interconnected operations. Golden Valley perceives the recent inquiries as to appropriate costs and efficient operation as a healthy sign of this increased awareness. Dapeay yr FY Golden Valley has reviewed the Alaska Intertie Agreement (AIA) and tinds Section 10 to be the most appropriate to our recommendations. With minor variances, Golden Valley believes the duties and functions the NC and SC perform are done at the request of participant members. We interpret this to mean Golden Valley and AML&P may have their assigned duties modified if a majority of participants seek changes. Golden Valley invites all participant members to examine the NC and SC roles in operation of the Alaska Intertie. Golden Valley specifically recommends each participant member: * Examine and confirm duties which they believe are essential to operation of the Alaska Intertie and monitoring compliance to the AIA. GOLDEN VALLEY ELECTRIC ASSOCIATION INC Controller Costs and Duties May 18, 1993 Page 2 * Determine which of the current duties may be reduced in scope or eliminated. * Examine duties and determine which are redundant. * Determine which duties could be consolidated for efficiency. What naturally follows from a utility member's review of duties and costs is for the Alaska Intertie owner to also review its duties and costs. After eight years of ownership, we trust AEA has gained sufficient experience to discover ways to streamline its operations as owner. Golden Valley specifically recommends AEA: * Examine and determine essential duties of the owner. . Examine and determine the most efficient use of manpower required by AEA to protect its interests as owner. Our final recommendation is for CEA to suspend their request for monthly submittal as long as they believe adequate progress is made in this self-examination. At the conclusion of this process, if CEA remains dissatisfied, Golden Valley is prepared to submit monthly invoices if required. In closing, Golden Valley is committed to examining ways to eliminate waste, redundancy, and practices which may have outlived their useful life. As chairman of the Alaska Intertie Committee, I request all members be prepared to make specific recommendations and requests at the next IOC meeting on May 28, 1993. Bradley Evans Ioc Chairman cc: IOC Members Afzal Kahn Tom Lovas Tim McConnell Sam Matthews Vince Mottola Mike Kelly Steve Haagenson ce hod ) ~ > Cl f= Matanuska Electric minute Le Association, Inc. aot P.O. Box 2929 rire ee mee. RECEIVED Fax: (907) 745-9328 JUL 06 1993 June 25, 1993 GOLDEN VALLEY ELECTRIC £SSN., INC. OPERATIONS DEPT. Mr. Bradley Evans Chairman Intertie Operating Committee Golden Valley Electric Association, Inc. P. O. Box 71249 Fairbanks, AK 99707 Dear Brad: At the most recent Intertie Speetticn Committee (IOC) meeting there was a discussion concerning ownership of the Stevens substation. We understand the concern of the members of the IOC that only those organizations that are signatory to the Intertie agreement be allowed to tap the intertie. We have discussed this situation at MEA and have concluded that all of the interests involved can be protected by having the AEG&T own the point of connection between the Intertie and the station. The remaining portion of the station will remain the property of Matanuska Electric Association. This will allow the Intertie to be tapped by AEG&T which is signatory to the Intertie agreement and bound by its terms, thus affording other participants the same relationship as if AEG&T owned the station. AEG&T acting as our power supplier and as a signer of the Intertie agreement can require MEA to adhere to all terms and conditions of the Agreement. We hope that this arrangement is satisfactory to all concerned. If there are any questions concerning this matter, please contact me. incerely, 9 all James D. Hall ; Alternate representative AEG&T EDES699JDH eral { e | ~£ BV GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Box 71249, Fairbanks, Alaska 99707-1249, Phone 907-452-1151 September 7, 1993 Brad Evans, IOC Chairman Golden Valley Electric Assn. P.O. Box 71249 Fairbanks, AK 99707-1249 Subject: Controller Duties Golden Valley feels that the Alaska Intertie will be a more efficient operation if the following philosophy is followed: One of the controllers will actually operate the intertie facilities and schedule all transfers. The concept of two controllers for checks and balances is appropriate and healthy, and we strongly endorse this concept as long as it is accomplished in the most efficient manner. With these thoughts in mind, we submit what we feel should be the controller duties. Intertie Scheduling - This involves coordination with all affected utilities for reserves and energy to insure proper intertie loading. This also includes var scheduling as required to maintain adequate voltage levels, accounting for all schedules, and preparing a monthly billing for the utilities. (one controller) Auditing is to be done by the other controller or the State as required. Actual Intertie Operation - Scheduling outages for maintenance, restoration of intertie after forced outage, normal operation of intertie equipment. (one controller) The other controller to assist as required and audit performance of duties. GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Controller Duties September 7, 1993 Page 2 Time Error Correction - Coordination wetween all generating facilities to adjust time error as required. (one controller) Reserve Requirements - Monitoring reserve requirements for all participants, both spinning and operating reserves. Maintaining records of required vs. actual, preparing monthly report to the IOC for review and action as necessary. (one controller) Note: Due to the number of utilities involved, each utility should be responsible for maintaining spinning reserve records for comparison and action as required. he Lill Marvin Riddle anager of System Operations cc: IOC Members ALASKA ELECTRIC” GENERATION AND TRANSMISSION, INC. September 7, 1993 Mr. Brad Evans Chairman Intertie Operating Committee Golden Valley Electric Association, Inc. P. O. Box 71249 Fairbanks, AK 99707 Dear Brad: The Intertie Operating Committee (IOC) requested input with regard to Operator duties. Alaska Electric Generation and Transmission Cooperative, Inc. (AEG&T) supports Anchorage Municipal Light and Power (AML&P) to continue as the Southern Operator, and Golden Valley Electric Association, Inc. (GVEA) to continue as the Northern operator. We believe that both of these entities have acted in good faith to perform the duties of the Operators to the best of their abilities. The Intertie Agreement gives the IOC broad authority in defining the duties of the operators. The operators provide, and should continue to provide, a valuable service to the State of Alaska by providing safe and consistent day-to-day operation of the line and information needed by the State for accurate billing and record keeping. The detailed duties of the operators should be reviewed from time to time by the IOC. There is some duplication of effort that should be eliminated, with the associated reduction in costs. Monthly billing for wheeling should be based on actual meter information. This would help to eliminate disputes, and eliminate the need for some of the records now required. We look forward to working with the other IOC members to develop new duties and procedures to help streamline record keeping and eliminate unnecessary cost. The Stevens Substation should be included in the area operated by the Northern Operator. This is because the station is ae, located within the control area of GVEA, and will require close coordination with GVEA for control of the load at Stevens. It is logical that GVEA also provide electrical control of the in-line devices at Stevens. Jaa © Heal James D. Hall Alternate Member Intertie Operating Committee edes720jdh PHONE: (907) 745-3231 = P.O.BOX2929 ® PALMER, ALASKA 99645 PHONE: (907) 235-8167 = P.O.BOX169 #® HOMER, ALASKA 99603 Ayiaat@ VB \ NY =~ \ Municipality of Anchorage Municipal Light & Power / Tom Fink, Mayor 1200 East First Avenue SY Anchorage, Alaska 99501-1685 (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 September 8, 1993 TO: Ioc Chairman and Participants FROM: Tim McConnell, ML&P IOC Representative hhh) SUBJECT: Negotiating Cost Reductions For Intertie (New and Old) Operations ML&P's operative position on the current IOC discussion on Controller duties and costs was stated in Mr. Stahr's April 16th letter (Attachment 1) in response to Mr. Highers' letter of April 12th (Attachment 2). That is, ML&P has had a standing offer to discuss this issue in the context of other cost cutting measures related to Intertie operations. This offer has been on the table since receiving Mr. Kelly's letter of May 7th a year ago (Attachment 3). No response to ML&P's initiative has been forthcoming, despite the encouragement of the AEA that both Mr. Highers and Mr. Kelly do so (Attachments 4 and 5). Instead, the Controller initiatives are brought to the IOC by the CEA representative in the hopes that what ever contractual authority this body has can be rallied to support a piecemeal attack on the Controller duties and costs that have changed very little and have served us well for the last 8 years. In ML&P's opinion, this is a tactic that could benefit one or two participants, but is not in the long term best interests of most. In addition, the dogged persistence to single out this particular Controller issue portends juridical involvement in the "gray" areas of the Alaska Intertie Agreement (We have already found it necessary to obtain one legal opinion- -and there are others). This is a tactic that will be time consuming with perhaps no outcome that can be applied to the new agreements that are now under negotiation. As an alternative, ML&P proposes the course stated in Mr. Stahr's letter is the better one: The IOC recognize that the issues related to Controller duties are in fact already on the agenda of the General Managers as part of the issue package that will influence the outcome of negotiations for the implementing agreements of the New Interties. Putting Energy Into Anchorage Ny STi Municipality of Anchorage Municipal Light & Power Tom Fink, Mayor 1200 East First Avenue Anchorage, Alaska 99501-1685 Telephone: (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 April 16, 1993 Mr. Ron Garzini, Executive Director Alaska Energy Authority P.O. Box 190869 Anchorage Alaska 99519-0869 Dear Mr. Garzini: Reference Mr. Highers' April 12, 1993 letter to you, Subject "Alaska Intertie - Budget and Operations" In 1985 ML&P became Southern Operator of the Alaska Intertie with the signing of the Alaska Intertie Agreement by all Participants. Over the years, ML&P has faithfully performed and will continue to carry out the contractual duties associated with Southern Operator. A change in the delegation of Southern Operator, suggested by Mr. Highers, would require an Amendment agreed to by all Participants. ML&P is opposed to any such Amendment. The costs Mr. Highers refers to of Southern (and Northern) Operator have changed very little since 1985, and have been routinely adopted by the Participants through the years. Last year when Mr. Kelly suggested reducing Northern and Southern Operator costs to zero, I expressed my willingness to discuss the issue along with other cost cutting initiatives that I would bring to the table. I have received no response to date, and the offer still stands. The provision to audit the FY94 budget on a monthly basis as Mr. Highers' suggests we consider is certainly in the Agreement (and will need to be budgeted), but I believe we will benefit more (especially this year perhaps) by focusing on the value of Interties, and not on marginal cost reductions that may or may not be realized. Sincerely, Thomas R. Stahr General Manager, ML&P Putting Energy into Anchorage for 60 years "1932 - 1992" fi Pugeh CHUGACH 7 =CTRIC eugach \ ASSOCIAIION, INC. Circ aap DAVID L. HIGHERS General Manager April 12, 1993 Via Facsimile 907-561-8584 Mr. Ron Garzini, Executive Director Alaska Energy Authority P.O. Box 190869 Anchorage, Alaska 99519-0869 Subject: Alaska Intertie - Budget and Operations Dear Mr. Giarzini: In reviewing the attached request to authorize payment of the northern and southem operating budgets as fixed cost fecs, we are reminded again of the relatively high casts associated with operating tho Intertie. These operating costs result in higher rates for the access and use of @ jointly operated facility, thereby distorting the economics of transmission services and interchange transactions. The operating costs ars doubly disturbing to Chugach since all operating requirements of the Southern Operator are duplicated by Chugach in meeting Chugach's responsibilities for its own system and in providing required scrvicos tv other utilities (such as access to the Intertic). We do not currently provide the reporting services which ara the responsibility of the operator, but estimate that the annual incremental cost to Chugach of providing that service would be only about $10,000. Consequently, Chugach suggests that the Energy Authority and Iatertic participants consider the following: . The Intertle Operating committee should tke immediate action to revise tha Intertie Operating Budget to include no more than $10,000 for the activilies of the Southem Operator. . Chugach offers to pravide the services otherwise performed by the Southem Operator at a cost not to exceed $10,000 per annum, subject only to inflation as measured by an appropriate labor cost index. ’ Tf it Is determined that Chugach would provide the service, enter into an amendment to the Intertie Agreement reflecting that change in participant responsibilitics. 8601 Minnesota Drive « RO. Box 196300 * Anchorage, Aluska 99519 6300 Phone 907-563-7494 « FAX 907-564-8406 or 907-662-0027 Mr. Ron Garaini April 12, 1993 Alaska Intertie - Budget and Operations 2 . The participants shall not authosize the fixed cost fee fur operation of the Intartla pending a budget revision or an Intertic Anendincnt designating Chugach a3 Southern Operator. This would result in a requirement for the currcat operators to submit invoices for payment, and supporting documentation, to ABA each month. In the past, Mike Kelly has notified me and Tom Stahy that GVEA is prepared to also submit a dramatically reduced budget for the Northern Operator that would be included in the IOC's budget revision. Slacercly, CHPGACH ELE ‘ASSOCIATION, INC. David L. Highers General Manager Attachment cc: = Intertle Participants AY-12-92 TUE 8:34 ML&P GENERAL WANAGER FAX NO. 907263520: Pr0l May 7, 1992 Mr. Thomas Stahr General Manager Anchorage Municipal Light & Power 1200 East First Avenue -- Anchorage AK 99501 Mr. Dave Highers General Manager Chugach Electric Association P. O. Box 196300 Anchorage AK 99519-6300 RE: Intertie Operation/Cost Dear Tom and Dave, the new fiscal year for intertie operation begins July 1. I think that we should agree to reduce operating costs to zero so the new budget can be adjusted right now. Tom, when you and I met briefly in the ARECA offices several months ago after receiving Dave's Intertie letter, you expressed willing- ness to consider relinquishing southern control as long as all operating costs went to zero and you could become comfortable with a method of oversight. I hope this fairly represents our very brief conservation. I propose the following for your joint consideration: GVEA would operate the intertie from Fairbanks to B-1 at Douglas beginning July 1, 1992, at zero cost. CEA would perform any intertie oper- ating south of Douglas B-1 beginning July 1, 1992, at zero cost. If this proposal looks agreeable, I could have Saxton draft a one- pager reflecting our agreement and we could promptly notify AEA. If we need to discuss this, I suggest we have lunch in Anchorage as soon as possible. Please give this some thought and call me. Best regards, Michael P. Kelly General Manager baie’ cifey Hl lance State at Alaska Ds Waiter J. Hickel, Governor Alaska Energy Authority A Puntic Conporation May 3, 1993 Mr. David L. Highers General Manager P.O. Box 196300 Anchorage, Alaska 99519-6300 Subject: Alaska Intertie - Final Scope of Operations and Budget, FY94 Dear Mr. Highers: Your letter dated April 12, 1993, states your disagreement with fixed cost fees under the proposed FY94 operating budget for the northern and southern operators. Golden Valley Electric Association (GVEA), Fairbanks Municipal Utilities System (FMUS) and Anchorage Municipal Light and Power (AML&P) have agreed to the fixed cost fees for operation of the Intertie. Pursuant to the Alaska Intertie Agreement, Article 10, Section 10.3.5, "If the Participants are unable to agree unanimously that the final scope of operations and budget is the fixed cost fees for operation of the Intertie, AML&P and GVEA shall each determine, using records and accounts maintained under Section 10.4 of this Article 10, the cost to its system to provide operation of the Intertie in accordance with this Agreement and shall bill AEA monthly for these services. The Alaska Energy Authority will then reimburse AML&P and GVEA under Section 10.4 of the Article 10." The Energy Authority will notify AML&P and GVEA to submit monthly invoices for operation of the Intertie beginning July 1, 1993 (FY94). The Energy Authority appreciates your offer to be the Southern Controller. Presently AML&P has the Contract responsibility for operations for the southern one-half of the Intertie and any change to the agreement requires mutual consent of all Participants. AML&P is opposed to any such amcndment to the Alaska Intertie Agreement. | have attached a letter from AML&P which denotes their willingness to discuss reduced costs. We encourage the participants to hold a mecting and resolve their differences. PO. Box 190869 701 Eas! Tudor Road = Anchorage Alaska 99519-0869 (907) 661-7877 Fax: (907) $61-8584 FIQTMAAT&AR(1) Page lof 1 In the interim, the Energy Authority recommends basing the energy rate and the capacity rate on the estimated budgets as submitted by the utilities. Sincerely, ot Executive Director AK:RAG:ma Attachment as stated. ce: Valaska Intertie Agreement Participants Stanley E. Sieczkowski, Alaska Energy Authority Afzal H. Khan, Alaska Energy Authority IOC Chairman 9302\MAA748.DOCI2) Pace ? State of Alaska DY Walter J. Hickel. Govern Alaska Energy Authority A Puolic Corporation May 3, 1993 Mr. Michael P. Kelly, General Manager Golden Valley Electric Association P.O. Box 1249 Fairbanks, Alaska 99707 Subject: Alaska Intertie - Final Scope of Operations and Budget, FY94_ Dear Mr. Kelly: The Chugach Electric Association letter dated April 12, 1993, to the Energy Authority states their disagreement with fixed cost fees for operation of the Intertie. The Anchorage Municipal Light & Power letter dated April 16, 1993, to the Energy Authority expressed willingness to discuss the issue with the Participants (see attached letter). We encourage the participants to hold a meeting and resolve their differences. Pursuant to the Alaska Intertie Agreement, Article 10, Section 10.3.5, the Anchorage Municipal Light & Power and Golden Valley Electric Association each will be required to submit monthly invoices in accordance with Section 10.4 of the Alaska Intertie Agreement beginning July 1993 (FY94). In the interim, the Energy Authority recommends basing the energy rate and the capacity rate on the estimated budgets as submitted by the utilities. Guth Ronald A. Executive Director AK:RAG:ma Attachments as stated. ce: Vitsien Setasila Dapiianens Puticiciions Stanley E. Sieczkowski, Alaska Energy Authority Afzal H. Khan, Alaska Energy Authority Chairman, Intertie Operating Committees PO, Box 190869 704 East Tudor Road = Anchorage Alaska 99519-0869 (907) 561-7877 Fax: (907) 561-8584 93QQ\MA47501) Pago lof 1 mounts papers adsetn 117) GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Box 71249, Fairbanks, Alaska 99707-1249, Phone 907-452-1151 RECEIVED AUG 25 1993 DATE: August 5, 1993 AL Lf: to rua pty Afzal Khan Director Engineering Support Alaska Energy Authority PO Box 190869 Anchorage AK 99519 Subject: Alaskan Intertie Operating Budget Per the current “Alaska Intertie Agreement," Section 10.6 and GVEA’s FY93 “Alaskan Intertie Operating Budget" submittal, GVEA submits he following invoice for payment within 30 days of receipt: Month: July, 1993 Period: July 1,1993 through July 31, 1993 Invoice Breakdown: Account Number Operation Category Amount 560 Labor $17,802.93 566 SCADA Debt Service 5,476.92 562 Maintenance 1,773.67 *Total $25,053.52 *This total is 1/12 of annual budget submitted. Refer to current budget for detailed breakdown. Please pay - July 1993 $25,053.52 Account #:142.31 Subsidiary # 7079.00 Patti Anderson Actountant ee gigih ALASKA Ennis en GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Box 71249, Fairbanks, Alaska 99707-1249, Phone 907-452-1151 7m August 3, 1993 Avy «v (993 ALASKA ENE®CY AUTHORITY. Subject: Operating Budget Billing - July 1993 Per request and the current "Alaska Intertie Operating Budget", GVEA submits the following labor breakdown as backup for the attached July Operating Budget billing. Operation Labor Account #561.00 Hours = Costs 1. Scheduling £2721 $ 8,294.55 2. Reserve Accounting and 2769 1,820.75 Monitoring Se Systen Regulation 34.1 2paeneal 4. AEA Equipment Monitoring 46.5 3,034.59 Si Interconnected System 6.2 404.61 Coordination (including outages and time error coordination) 6. Monthly Accounting and 31.0 2923.06 Reconciliation Totals 272.80 $17,802.93 Bradley Evans System Dispatch Supt. ry nuw¥€S August 17, 1993 AUG 19 1993 AL SKA E“ESCY AUTHORITY Mr. Afzal hen Alaska Energy Authority 701 East Tudor Road PO BOX 190869 Anchorage, AK 99519-0869 Subject: Intertie and Bradley Lake Maintenance Budgets - FY-1995 Attached is the estimated maintenance costs for the Teeland SVC and the Daves Creek/Soldotna SVC Relay/Controls maintenance for the period from June 30, 1994 - July 1, 1995. Budgeted maintenance includes scheduled, preventative maintenance only. No contingency or corrective maintenance items are budgeted for. This estimate does not include any monies for the substation equipment maintenance and monthly inspections. These estimates are being forwarded under separate cover by Mr. Brian Hickey. If you have any questions, please feel free to call me at 762-4610. Sincerely, eae Daniel C. Rogers, P.E. Manager, Facilities Engineering DCR/pna DCR-gy9Sbud.aea Attachment cc: D.Burlingame J. Cooley B. Hickey M. Massin File 5601 Minnesota Drive ¢ P.O. Box 196300 « Anchorage, Alaska 99519-6300 Phone 907-563-7494 ¢ FAX 907-562-0027 FY 95 Teeland/Daves Creek/Soldotna Maintenance Budget Teesland AEABDGT.XLS 18620/000/01 18620/000/03 18620/000/02 18620/000/03 18620/000/03 18620/000/01 18620/000/03 18620/000/02 18620/000/03 18620/000/03 18620/000/01 18620/000/03 18620/000/02 18620/000/03 18620/000/03 Work Order ~ 'W.0.0007 not assigned not assigned Relay Testing Relay Testing Relay Testing Comments Labor Transportationodging Prof. Services/drafting Materieiequipment Other/miac TOTAL TEELAND Labor Transportation/iodging Prof. Services/drafting Matenaiequiome% Other/miec TOTAL SOLDOTNA Labor Traneportationiodging Prof. Services/drafting AEE EQLADITON Other/miec TOTAL DAVES CREEK Labor Traneportationodging Prof. Services/drafting MABE SOIT RCE Other/miec TOTAL ACCOUNT $4,550 $3,622 $2,050 $1,500 $12,222 $10,400 $5,896 $1,367 $1,000 $18,906 $5,200 $2,948 $167 8/1793 9:04 AM wun ateg CHUGACH ELECTRIC “ ASSOCIATION, INC. paged ASSOCIATION, INC July 28, 1993 Mr. Afzal Khan ALASKA ENERGY AUTHORITY P.O. Box 190869 Anchorage, Alaska 99519-0869 SUBJECT: Alaska Intertie FY-1995 Teeland Substation Maintenance Budget Attached is the estimated maintenance budget for the Teeland SVS for the fiscal year 1995 beginning on June 30, 1994 and ending July 1, 1995. Per our conversation of June 14, 1993, please note that the FY-1995 budget includes the estimated cost for design and installation of a small chiller/air handling unit for the SVS Control Room. In addition, this budget contains funds for the initiation of major maintenance activities on the SVS substation equipment. Major Maintenance is scheduled to begin in late June and continue into August. June major maintenance will include the following items: the 125vdc battery bank and charger; the 13.8 kV metalclad breaker; and the Thyristor Air Handling Unit. The remainder of the station equipment will be maintained in July and August. | will keep you posted should any changes in the schedule occur. This estimate does not include labor and materials for relay and control wiring main- tenance. Estimates for this work should be obtained from Dan Rogers in the Facilities Engineering Department. If you have any questions or comments, please feel free to contact me at 762-7661. Sincerely, Brian # Hickey Manager of Substation Operations BJH/cak TLDFY95.bud Enclosure 5601 Minnesota Drive ¢ P.O. Box 196300 * Anchorage, Alaska 99519-6300 Phone 907-563-7494 ¢ FAX 907-562-0027 July 28, 1993 ALASKA INTERTIE FY-1995 TEELAND SUBSTATION MAINTENANCE BUDGET CHUGACH ELECTRIC ASSN. SUBSTA ASSN. SUBSTATION LABOR LABOR AND MATERIALS : - [voothiy Inpectione:_7o_mh €$ eo/He.—_—_____}s 210 | ieee eee le $6,600 sti tees dstemecns_100 sh 6s cofah ——___1 $ 18,000 1,100 | RHE CONTRACT LABOR & MATERIALS } Design, Procurement, and Installation of Chiller/Air Handling $ 50,000 | Unit for SVS Control Room | ___| $ 50,000 } 50,000 D-H. ATE: WYNNE 1225 19th Sereet, N.W. R Suite 200 HEWITT Washington, D.C. 20036 (202) 785-0303 DODSON Fax (202) 785-8676 & SKERRITT se ATTORNEYS AT LAW C: 6 ° SSE P Date: July 23, 1993 RECEIVED To: Brad Evans and Tom Lovas Intertie Operating Committee JUL 26 1993 From: Julie Sim adiSeiivalicy ELECTRIC ASSN., INC, Subject: FERC Transmission Update @PERATIONS DEPT. The Federal Energy Regulatory Commission has recently issued a Notice of Inquiry concerning transmission pricing and a policy statement on what constitutes a "good faith request" for transmis- sion services. Comments on transmission pricing issues, along with requests to participate in a technical conference on transmission issues, are due September 7, 1993 and comments on the good faith request policy are due August 20, 1993. This memo summarizes both documents. We need to discuss the extent to which the IOC should comment on the issues raised by the ‘Commission. Please let me know if you want copies of any of the documents discussed herein. i; Transmission Pricing On June 30, 1993, FERC issued a Notice of Technical Conference and Request for Comments on the issue of whether it is appropriate to revise the Commission’s present pricing policy for transmission services and possible alternative transmission pricing models. Under current Commission policy, a utility can choose between two rates for transmission services. The choices vary depending on whether or not new capacity is added to relieve a transmission constraint. If new capacity is added, the utility may charge the higher of an embedded cost rate or a rate based on the incremental cost of expansion. If new capacity is not added, the utility may charge the higher of an embedded cost rate or a rate based on opportunity costs, capped at the incremental cost of expansion. The Commission specifically invites comments on whether the present transmission pricing policy promotes or discourages efficiency and competition in the wholesale electric market. From those supporting revision to the current policy, the Commission Portland, Oregon ‘Seattle, Washington San Francisco, California Affiliated offices in (503) 226-1191 (206) 623-4711 (415) 421-4143 Anchorage, Fairbanks TAR eT Fax (206) 467-6406 Fax (415) 969-1263 and Juneau, Alaska ATER WYNNE invites comments on alternative transmission pricing models for both firm and non-firm transmission services. The Notice acknowl- edges that pricing is only one aspect of a competitive transmission market and recognizes that “non-price" terms and conditions, as well as reliability concerns, the provision of "related services" and other issues, are still open. In addition, the Commission invites comments on two legal issues: the scope of its discretion on transmission pricing under section 212 of the Federal Power Act and whether it should apply the same pricing under section 205 as it applies under section 212. Attached to the Notice is a Commission Discussion Paper on transmission pricing issues, addressing the “multiple policy dimensions" of the transmission pricing debate and spelling out some of the “important trade-offs" inherent in any transmission pricing policy. 2% "Good Faith Request" for Transmission Services On July 14, 1993 the Federal Energy Regulatory Commission issued a policy statement adopting guidelines for what constitutes a “good faith request" for transmission services, and reply to that request, under the Energy Policy Act of 1992. The policy statement is effective July 14, although written comments will be accepted until August 20. Under the Energy Policy Act, FERC may not issue an order requiring the provisions of transmission services unless the applicant has first made a good faith request to the transmitting utility at least sixty days prior to filing an application with the Commission. The transmitting utility is required to either provide transmission services at rates, charges, and terms and conditions acceptable to the requestor or to respond in writing to the request within thirty days. This policy statement is intended to provide guidance as to what the Commission considers an acceptable transmission request and reply. The Commission also clarifies that transmission requests can include network services and need not be limited to point-to-point services. Neither the Energy Policy Act or the Federal Power Act define a "good faith request" for transmission services. The Commission posits that Congress intended each party to provide the other with "as much information as [is] reasonably available" concerning transmission requests before seeking Commission involvement. The exchange of detailed information will “help encourage constructive . business transactions through negotiated agreements." Permitting perfunctory requests and responses will render the “request and response" process a nullity and allow parties to avoid or circun- vent attempts at negotiation. ATER WYNNE In adopting the policy statement the Commission sets four goals: * * * * identify the type of information that will facilitate a request for transmission services; foster greater competition in wholesale electric markets; encourage coordination and cooperation; and encourage negotiated agreements where possible. The Commission also encourages those engaged in transmission transactions to devise their own creative ways of addressing transmission needs, without Commission involvement. The policy statement spells out twelve components of a good faith transmission request. These components represent the minimum information necessary to allow a transmitting utility to analyze a request for services. A good faith request must include: Identity of the prospective purchaser. Assurance that the prospective purchaser is eligible to request services. Assurances that the Commission is authorized to order the type of services requested. A specific, technical description of the character and nature of requested services in sufficient detail to permit the transmitting utility to model the additional services on its transmission system. Parties can request any type of transmission services, including network services. The issue of network services is a complicated and controversial one and the Commission asks interested parties to address how best to balance the desire for maximum flexibility with the transmitting utility’s need for sufficient information to model the request. The names of other parties expected to be delivering or receiving power from the transmitting utility. The dates for initiating and terminating the proposed services. The total amount of transmission capacity being request- ed. To the extent it can be known or estimated, a description of the "expected transaction profile," including hourly load factor data. ATER WYNNE 9. 10. it. 12. Whether firm or non-firm service is being requested. A statement as to whether the request is being made in response to a solicitation for generating resources. The rates, terms and conditions requested. Specific, detailed information is not required, but a rate method- ology, tariff or contract must be referenced. Any additional information that enhances the transmitting utility’s ability to evaluate the request. : A reply to a good faith request must include five components: 1. Acknowledgment of receipt of the request must be sent within ten days. The acknowledgement must include a date by which a response on the transmission request will be sent and a statement of any fees associated with respond- ing to the request. Any requests for clarification of the information provided, to the extent needed to evaluate the requested services. The response to the transmission request must be sent within 60 days, unless an alternative schedule is agreed to by both parties, in writing and signed. If the transmitting utility can provide the services requested from its existing capacity, it must offer the requesting party an executable service agreement contain- ing at least the following information: * Description of the proposed transmission rate and any other costs. * Description of all applicable terms and conditions. * A clear statement of the time during which the offer to provide services will remain open. If the transmitting utility must construct additional facilities or modify existing facilities to provide all or part of the requested services, it must: * Identify the specific constraints and their dura- tion and explain how these constraints prevent the provision of the services requested. * Provide all studies, computer input and output data, planning, operating and other documents, work 4 ATER WYNNE papers, assumptions and other materials which form the basis for determining the constraints. Offer an executable agreement under which the applicant will reimburse the transmitting utility for all costs of performing any studies necessary to determine what changes are necessary to overcome the constraint, the estimated cost of the studies, and the estimated time to complete the studies. If part, but not all, of the requested services can be provided without building new facilities, the transmitting utility may treat the request as two separate transactions. The transmitting utility must also consider alter- natives short of construction for removing capacity constraints. The Energy: Policy Act does not address how transmission service requests should be prioritized. The Commission will accept prioritization based on first-come, first-served or any other reasonable allocation method. cc: Ron Saxton mirnnu tes VE ANCHORAGE-FAIRBANKS INTERTIE PROJECT INSURANCE PREMIUMS AND FEES FY94 OWNER'S RISK $1 M Line of Credit Fee (4) $ 1,800 Boiler and Machinery (b) 18,542 General Liability (C) 1,600 Watercraft and Aviation (4) ___400 $ 22,342 INTERTIE OPERATING COMMITTEE'S RISK General Liability 7,500 * Aviation _9,000 A $ 16,500 Total Premium & Fees $38,842 Notes: A The premium is for six months, 7/1/93 through 1/1/94. The carrier has raised the deductible from $1,000 to $25,000 for FY94, but has extended the prior fiscal year's terms for six months. The broker is exploring different markets to determine if a more reasonable deductible is available for the remainder of FY94. 93Q3/AH5215(1) Page | of 3 SELF-INSURED RETENTIONS AND LOSS LIMITS (a) (b) (c) (d) Notes: CARRIERS: Property*: Covered by Insurance Reserve Business Plan $ 1,000,000 Boiler and Machinery*: SIR, Transformers 100,000 kva or more $ 100,000 SIR, Turbine Generators, Power Distribution Transformers and all objects at Substation and Switchyards $ 50,000 SIR, All Other Objects $ 25,000 Loss limit per Accident: $ 15,000,060 Sub-limits: Expediting Expense $ 250,000 Ammonia Contamination $ 75,000 Water Damage $ 75,000 PBC Clean-up $ 75,000 Additional - $ 5,000 General Liability ** SIR $ 5,000,000 Loss Limit $ 75,000,000 Watercraft and Aviation ** $ 1,000,000 Loss Limit $ 200,000,000 Proj and Boiler Machine self-insured retention are a Intertie Operating Committee (IOC) responsibility. General Liability, Watercraft and Aviation self-insured retention are a State responsibility for the duration of the catastrophic loss fund. BROKER: Corroon & Black, Inc. ° 93Q3/AHS5215(2) Property - (Exhibit 5) Boiler & Machinery - Chubb/Pacific Indemnity (Exhibit 2) Best Rating: A+XII General Liability Watercraft & Aviation - Part of overall state policy for the duration of the state catastrophic loss fund Page 2 of 3 NOTES: . Property and Boiler Machine self-insured retention are a Project Management Committee (PMC) responsibility. oe General Liability, Watercraft and Aviation self-insured retention are a State responsibility for the duration of the catastrophic loss fund 93Q3/AHS5215(3) Page 3 of 3 BOILER & MACHINERY EXCLUSIONS THIS POLICY DOES NOT APPLY: 1) 2) 3) 4) To loss from an accident caused directly or indirectly by: a) A hostile or warlike action, including action in hindering, combating or defending against an actual, impending or expected attach, by (i) any government or sovereign power (de jure or de facto) or any authority maintaining or using military, naval or air forces, (ii) —_— military, naval or air forces, or (iii) an agent of any such government, power, authority or forces. b) Insurrection, rebellion, revolution, civil war or usurped power, including any action in hindering, combating or defending against such an occurrence, or by confiscation by order of any government or public authority. To loss, whether it be direct or indirect, proximate or remote. a) - From an accident caused directly or indirectly by nuclear reaction, nuclear radiation or radioactive contamination, all whether controlled or uncontrolled; or b) From nuclear reaction, nuclear radiation or radioactive contamination, all whether controlled or uncontrolled, caused directly or indirectly by, contributed to or aggravated by an accident; Nor shall the Company be liable for any loss covered in whole or in part by any contract of insurance, carried by the Insured, which also covers any hazard or peril of nuclear reaction or nuclear radiation. To any increase in the loss necessitated by any ordinance, law or regulation, tule or ruling regulating or restricting repair, alteration, use, operation, construction or installation. Under Sections I, II, and III to loss: a) from fire concomitant with or following an accident or from the use of water or other means to extinguish fire, +04 b) 8) h) from an accident caused directly or indirectly by fire or from the use of water or other means to extinguish fire, from a combustion explosion outside the Object concomitant with or following an accident. from an accident caused directly or indirectly by a combustion explosion outside the Object, from flood unless an accident ensues and the Company shall then be liable only for loss from such ensuing accident, from an accident caused directly or indirectly by earth movement, including, but not limited to earthquake, landslide, mud slide, subsidence or volcanic eruption. from delay or interruption of business or manufacturing or process, from lack of power, light, heat, steam or refrigerations, and from any other indirect result of an accident. ALASKA ENERGY AUTHORITY ANCHORAGE/FAIRBANKS INTERTIE Original Constructional Estimated Value Description/F.E.R.C, Acct. Procurement Cost duly, 1986 Cantwell Substation (353) $ 2,250,000 $ 2,259,000 Gold Hill Substation (353) 3,350,000 3,363,400 Healy Substation (353) 4,050,000 4,066,200 Tee Land Substation (353) 4,150,000 4,166,600 General Property - Misc. 1.650.000 —L.656,600 $15,450,000 $15,511,800 Note: Intertie Completed - 1984 To increase the July 1986 values of 415,512,000 to 1993 replacement, a 1.162 factor was used resulting in an estimated 1993 value of $18,023,782. EXHIBIT 1 ALASKA ENERGY AUTHORITY SYNOPSIS OF BOILER & MACHINERY INSURANCE COVERAGE COVERAGE: Utility Comprehensive (Broad Form) Repair or Replacement Coverage Included Breakdown Coverage on all Turbine Generators LIMITS: Limit per Accident of $15,000,000 Expediting Expense Sublimit of $250,000 Ammonia Contamination Sublimit of $75,000 Water Damage Sublimit of $75,000 PCB Clean-up Sublimit of $75,000 Additional Expenses Sublimit of $5,000 SPECIAL FEATURES: Coverage for Computer Process Control Equipment Explosion Elimination Endorsement to avoid duplication with the Fire and Extended Coverage perils Contractual Acceptance Provision Annual Property Damage aggregate deductible of $300,000. Any property damage loss in excess of $10,000 and up to the applicable deductible per loss shall be accrued until the annual aggregate is reached. Thereafter, each future loss shall be subject to a $10,000 deductible. this is applicable to the following locations: Solomon Gulch Hydro Electric Plant Swan Lake Hydro Electric Plant Tyee Lake Hydro Electric Plant Terror Lake Hydro Electric Plant Anchorage-Fairbanks Intertie Coverage for Computer Process Control Equipment located at the following locations: Copper Valley Electric Diesel Plant, Valdez, AK Bailey Diesel Plant, Ketchikan, AK Wrangell Diesel Plant, Wrangell, AK Kodiak Diesel Plant, Kodiak Island, AK ALASKA ENERGY AUTHORITY DEDUCTIBLES Property Damage Deductible of $25,000 per occurrence for all object except: Property Damage Deductible of $50,000,000 per occurrence for all Turbine Generators. Property Damage Deductible of $100,000 per occurrence for any Transformer having a capacity of 100,000 KVA or more. IDRYDEN f ILaAlRvuE, INC. CONSULTING / ENGINEERS 6436 Homer Drive. Anchorage. AK 99518 Mailing Address: P.O. BOX 111008, ANCHORAGE, AK 99511-1008 (907) 349-6653 @ FAX 522-2534 August 13, 1993 Mr. Steve Swift GOLDEN VALLEY ELECTRIC ASSOCIATION Box 71249 Fairbanks, Alaska 99707-1249 Reference: Anchorage-Fairbanks Intertie Report on Options for Tower 570 Foundations This letter reports our findings and recommendations concerning the pile foundations and anchors for Structure 570 of the Anchorage-Fairbanks Intertie. We have broken our discussion into the following: ¢ Recommendations @ New Foundations and Anchors # Budget @ Summary @ Background Information Recommendations Due to the reduced embedment of the existing piles, we recommend that you replace the foundations and anchors at Structure 570. If the replacement cannot be made in the next six to nine months, we recommend that the tower and anchor attachments be lowered + closer to the ground and the tower be leveled up on the existing foundations. This will reduce the overturning moment on the piles until the foundations and anchors are replaced. This site is quite different from nearby sites where soil borings were taken either before or during construction. We recommend making a soil boring at this site before final design of the foundations. A thermistor string should be installed in the bore hole to determine the soil temperature profile. Applicable tests of samples obtained from the boring should also be performed. After new foundations and anchors with adequate embedment to resist the frost heaving forces have been installed, the thermoprobes presently at the site can be removed for use elsewhere. Flactric Crwar Tranamiasion. Distribution. Substations. Control Systems, Generation, System Studies Golden valley Electric Assn. August 13, 1993 Mr. Steve Swift Page 2 New Foundations and Anchors After reviewing the options, we believe piling are still appropriate for the foundations. The new piling will need to be installed much deeper than the deepest of the existing piles, which were driven to refusal, to resist the jacking forces. In order to accomplish this, at a minimum preaugering before pile driving will be required. It may be necessary to auger a hole large enough for the pile to drop into and to grout the section of pile below the active layer. Figures 1 and 2 show conceptually how four piles can be driven and framing provided to pick up the tower at its present location. Although H-Piles are shown, pipe piles could also be used. The piles have been located a minimum of 1 foot from the face of the tower legs and the existing piles to provide room for the leads of the pile driver. After the piles are installed and all of the new framing, except the plate on which the tower is pinned, are in place, a second clamp can be placed below the one supporting the tower leg. A hydraulic jack placed on the new clamp can be used to support the leg clamp as it is loosened. The tower leg can then be lowered by alternately letting the leg down with the jack, tightening the leg clamp and sliding the second clamp down until the leg is close to its final position. During this process the two legs of the tower need to be tied together to relieve the thrust from the leg against the pile. Also, as the leg is lowered, the top of the pile will have to be periodically cut off because there is not sufficient clearance for the leg tube to pass on the inside of the pile. An alternative to cutting the pile off would be to support the existing clamp with a second clamp and shim below it. Then to replace the clamp bolts one by one with longer bolts. A shim, the width of the pile, could be slid between the clamp and the pile and fillet welded to the clamp. The leg could then be lowered as described above. The leg will need to be supported either by a boom, a crane, or a trunnion and jacks while the pile clamp is removed and the new support plate is installed. Figure 3 shows a system of two piles connected together with a rectangular tube to support the tower in its present location. This foundation would require less piling, but the support beam is much longer. It may also be more difficult to transfer the tower leg without using a boom or crane to lower the leg after the new foundation is completed. Figure 4 shows a method of framing which picks up the existing piling and clamp in place. It would require large amounts of field welding and would probably need larger piles due the eccentricity of load application. It does have the advantage of requiring the clamps to be moved only to level the tower. It also is possible to move the tower to the South onto new single pile foundations of the type used on the existing East foundation. The new piling would be installed 6 feet South of Golden Valley Electric Assn. August 13, 1993 Mr. Steve Swift Page 3 the existing location. This is 3 feet South of the West foundation’s South lateral and also 3 feet South of an abandoned pile for the East leg. The new anchor piles would also be installed 6 feet South of the existing anchor piles. Pils clamps would be bolted onto the South lateral, and both new pile foundations. New guys would be installed to the new anchor piles and left in the hoists without the yoke assembly. The shield wire would be placed in travelers. The new guys would be used to lean the top of the tower about 3 feet to the South (this would put the insulators out of plumb by an angle of about 15° for the outside phases and somewhat more on the center phase). The two legs would be connected together with chokers and a hoist. The West leg would be tied off with hoists and chokers to equipment or temporary anchors North and South. A boom or small crane would be needed to pick up the leg. The leg could then be swung to the clamp on the South lateral. The East leg would be similarly moved all the way to its new foundation. The first leg would then be moved the rest of the way onto its new foundation. This method of rigging was used to change the base connections between the legs and foundations on several X-towers in Thompson Pass. These towers are part of the Solomon Gulch to Glennallen 138 kV line. Attached is a picture showing the rigging used in Thompson Pass. The insulators and shield wire would be reclipped 6 feet to the South. The tower would be plumbed and the yokes installed in the guys. Budget Our estimate of the costs to replace the foundations at Structure 570 are: Soils Exploration & Testing $ 8,000 Final Design & Specifications 15,000 Construction 90,000 Total 113,000 The construction cost is based on installing foundations like the one shown in figure 1. Summary All of the pile foundations and anchors at Structure 570 have experienced substantial frost jacking since installation was completed nine years ago in February 1984 (See Table 1). Table 1 Frost Jacking at Structure 570 Distance —lecation .. § $sacked (ft) East Foundation 2.8 West Foundation 5.5 North Anchor 38 South Anchor 4.1 Golden Valley Electric Assn. August 13, 1993 Mr. Steve Swift Page 4 Approximately the top 5 feet of soil is very loose and cannot be relied upon for supporting the foundations and anchors. The pile driving records indicate that the soil from 5 feet to about 12.5 feet can provide some support, but is still fairly weak. Table 2 shows the present total embedment of each pile, the effective embedment discounting the top 5 feet of soil, the present attachment height, and the effective attachment height. The effective attachment height is the distance from the top of the first effective soil layer to the point where the tower leg or guy is attached (ie: distance from ground plus 5 feet). For example, the West foundation piles are embedded 4.45 to 7.1 feet into the soil layer which begins 5 feet below the ground surface. The distance from the top of this layer to the pin bolt attaching the tower to the pile clamp is 15.65 feet. Table 2 Embedment and Effective Attachment Heights Effective Total Effective Attachment Attachment Embed Embed Height Height Location = ft CEE EE East Foundation 16.90 11.90 8.20 13.20 West Foundation North Lateral 12.20 WaO 10.65 15.65 Center Pile 9.45 4.45 10.65 15.65 South Lateral 10.00 5.00 10.65 15.65 North Anchor 25550 20.50 Zists T2145 South Anchor 14.90 9.90 5.35 10.35 In our opinion the foundations no longer have sufficient embedment in good soil to support the tower under the design high wind loads. Background Information Geological Inf ; Availab] As part of the geotechnical investigation from the design phase of the project, one boring was made nearby. Boring B-49 (log attached), was made to a depth of 13.5 feet. Boring B-49 is approximately 700 feet East of centerline between Structures 573 and 574. It was taken in April 1982 and reported frozen ground from the surface to approximately 2 feet. The first 1.5 feet were silty sandy peat and the rest was very dense silty sandy gravel. Blow counts were extremely high. Drawing 1001 sheet 5 indicates that soil in the area near the boring is "G" and in the vicinity of 570 is "D" or "G" which are described as: + "D" Till: Predominantly very dense, clayey, silty, sand and/or gravel with cobbles, and boulders. Predominantly in the form of ground moraines can have up to 5 feet of surficial cover such as peat, silt gravel, or talus. Golden Valley Electric Assn. August 13, 1993 Mr. Steve Swift Page 5 + "G" Gravel: Predominately gravel, but contains sand and silt with cobbles and boulders, can have up to 5 feet of surficial cover such as peat or silt. Includes undifferentiated glacial outwash, terrace and alluvial deposits, and some till. No permafrost is reported in the design phase borings South of the Jack River which is between Structures 575 and 577. In all but one boring North of the Jack River permafrost was observed. During construction borings were made at Structure 562 and 571 (logs attached). Frozen ground was logged at a depth of 23 feet at Structure 562. origina) tia’ lati The two planned foundation piles and two anchor piles were driven with a Hy-Ram 88 on August, 26 1983. All four piles met refusal at between 12 and 13 feet. A heavier hammer, a Hy-Ram "770" was brought in to continue driving the piles in February 1984. The East leg pile was driven on February 7, 1984 to 15'8" with the "770". It was abandoned, and a new pile was driven 3 feet North with the "770" on February 12, 1984. It was driven to 19'8". The original West pile (now the South lateral) was redriven on February 7, 1984 to 15’6". The present center pile was driven 3 feet North on February 12, 1984 to 1410". The present North lateral was driven to 17'8" on February 13, 1984. The guy piles were both redriven with the Hy-Ram 770. The North guy was driven to 17 feet on February 7, 1984 and the South guy to 19 feet on February 7, 1984. Table 3 (attached) shows the pile driving times in seconds/ft of pile penetration. The piles typically were pushed 4 to 5 feet. Resistance increased gradually to 11 feet and increased steeply to between 12 and 13 feet where the "88" met refusal. The "770" was able to continue driving 15 to 20 feet. The driving was extremely hard. Field Observations 7/24/93 The original marks used during pile driving to track the installation depth are still visible on the East and West foundation piles. We measured the distance from one of the marks to the ground to determine the present embedment. We measured from the ground to the top of the pile or to the bottom of the cap plate to determine the reveal. The amount of pile jacking was determined by taking the difference between the record embedment and the field measurements. The embedments and reveals were added to arrive at an overall length of pile. The record Golden Valley Electric Assn. August 13, 1993 Mr. Steve Swift Page 6 embedments and record reveals were added to get a record length for comparison. These figures are tabulated in Table 4. The discrepancy between these overall lengths is also shown. For the East leg, we measured 5 feet from the 20 feet mark on the pile to top of pile. The piles are noted in the records as being 25 feet long at the start of driving. The East pile was probably never cut off at the record elevation. The length discrepancies for the West foundation of less than .3 feet (4 inches) are small enough to have confidence that the pile embedments are correct. The difference in jacking between the two foundations was also compared with the differences in elevation of GVEA’s last survey of the foundations. They agree to within 2-1/2". At the site on July 24, 1993, there was standing water in places between the hummocks. The wet area extends South of tower 570 and North to about 200 feet South of tower 571. To the east of tower 570, the ground rises and was dry with moss and black spruce trees the predominant vegetation. Pictures of the two foundations and the south anchor are attached. A test hole to 1-1/2 feet depth, 4’6" South of the tower center, and 7 feet East of the face of the West foundation found coarse silt with roots and other organics to the bottom of the hole. At the bottom there were 2 to 3 inch gray square sharp edged rocks. Probing with a Chance Probe in the bottom of the hole yielded no measurable torque until between 4 and 5 feet when the torque came up to 150 in-lbs, at 6 feet the torque was 500 in-lb and refusal was reached just after 6 feet. After two moves, due to rocks close to the surface a second probe was made 4 feet West of the North lateral of the West foundation, torque was not measurable until 100 in-lb at 4 feet depth, 250 in-lb at 5 feet and 300 in- lb at 6 feet with refusal at just past 6 feet. At 1 foot North of the tower center and 4’6" East of the West foundation, the probe was pushed 4 feet, resistance picked up between 4 and 5 feet with 150 in-lb at 5 feet. The probe spun on a rock at 5’6". The West center pile was plumb in the plane of the tower. The East pile was out of plumb 5/16" in 3 feet. At the bottom of the East clamp, the piles measured 34‘4" face to face. This compares to the tower plan dimension of 34'2". The outside edge of the leg tube of the East leg overlapped the inside edge of the pile by 1-1/8". The outside edge of the West leg tube was even with the inside edge of the pile cap plate. Table 5 shows the pile reveals (top of pile to ground surface) measured at the other X-towers between Structure 570 and the Denali Highway. The measured reveals for the foundations agree with the record reveals. No reveals were in the records for the anchors, but the plans show 1.5 feet. In general the center of the pin bolt for the tower is at the top of pile (the east pin at 575 was .35 feet below top of pile). Golden Valley Electric Assn. August 13, 1993 Mr. Steve Swift Page 7 Table 5 Pile Reveals West West East East South Fdn Fdn Fdn Fdn North Anchor Measrd Record Measrd Record Anchor 572 1.59 sew 3.98 3.25 3.25 1.80 573 1.70 3.65 3.66 Soke 3425 1.65 574 1.50 3.20 3.25 4.00 4.07 1.40 575 3.10 4.15 4.15 4.05 3.92 2.85 576 1.60 3.65 3.50 1355 No frost jacking appears to be taking place at any of these towers. In conclusion, the foundations and anchors at Structure 570 need to be replaced. The local soil conditions at this tower are different from those for which design information is available. Drilling and testing of the soils and securing a temperature profile will provide data needed for final design of the foundations. If you have any questions, please give me a call. DRYDEN & LaRUE, INC. i bbe Alan B. Peabody, PYE. ABP: db/gv570.rpt Enclosures Table 3 PILE DRIVING RESISTANCE, SECONDS/FOOT West West West West East East East South South North North Fdn Fdn Fdn Fdn Fdn Fdn Fdn Guy Guy Guy Guy 8 Pile s Pile Center N Pile Abandoned Abandoned Pile Anchor Anchor Anchor’ Anchor SU Na "sg" °7 78" eT Tee 8770" "88" "770" "770" "gg" eee "gg" "770" 0 a 3 0 4 0 0 0 17 0 0 85 0 0 0 26 0 0 15 0 0 0 5 3 0 4 0 2 3 3 3 3 0 6 3 0 2 3 0 2 6 4 5 3 6 5 3 2 4 3 4 a 4 6 9 9 10 6 7 9 7 5 5 10 31 6 8 31 8 10 27 11 23 5 6 113 7 35 230 12 189 13 az 427 17 32 550 13 1272 42 36 1235 70 863 924 72 14 2 392 69 190 a71 1068 355 15 580 1644 330 427 93 617 228 16 1626 668 1471 138 1384 132 17 614 244 817 760 18 338 547 450 19 739 512 20 714 Table 4 EMBEDMENT MEASUREMENTS Measured Measured Dscrpncy Elev. Measured 1993 1993 Total Record Record Record in Amount Diff Elev Location _Reveal_ Embedment Length Embedment Reveal Length Lengths Jacked WtoeE Diff East Foundation 8.10 16.90 25.00 19.67 4.92 24.59 0.41 2.77 West Foundation North Lateral 10.85* 12.10 22.95 17.67 5.18 22.85 0.10 S57 2.80 2.81 Center Pile 10.85 9.45 20.30 14.83 5.18 20.01 0.29 5.38 2.61 2.81 South Lateral 10.85 10.00 20.85 15.50 5.18 20.68 0.17 5.50 2.73 2.81 North Anchor 3.00 15.50 18.50 17.00 1.50 18.50 NA 1.50 South Anchor 5.60 14.90 20.50 19.00 1.50 20.50 NA 4.10 * Field measurement of 11.55 ft assumed in error PROPOSED WEU? FON a 4° FACE Fo FACE MIM. MIG A sence FEL” ELEVATION ELEVAT Iof/ BLAIR AAReEeeaseaeaseseee= SOIL DESCRIF =| \ Surface Elevation: | Unknown Dark brown to gray, silty v sandy PEAT, Nbe S'S Very dense, silty sandy GRAVEL NOTE: Subsurface conditions from 2 2.2 feet to 13.5 feet interpreted k from drilling action Bottom of Exploration Completed 4/23/82 japervieus seat [a Water level Prezometer tip Thermeceusioe I 3° 0.0. sptst spoon sanpie IL 37 0.0. tnim-eatt sompie @ Sample net recovered Atterverg tists: Liquid limit Organic Sen content Content Plastic tient PENETRATION RESISTANCE (340 1b, wergnt, 30° drop) A Blows oer foot a ad > [4 he 8 et = So = @" Wate? content * Weote: The stratification tines represent tne eporeximate Ceundaries cetween sor! types and the transition asy ce gradual. Commonwealth Associates Anchorage-Fairbanks Intertie LOG OF BORING NO. 8-49 August 1982 K-9417-09 SHANNON & WILSON, INC. CEOteCHmrca: ComsuLtaurs 4 r westzZ 3° ‘Be M82 TEE FIELD BOREHOLE LOG NO. | ee ~ COLD | i1ONS CONSULTING ENGINEE MMI: . FpnouegT: TTR ANSTHSS (On Doeerie; © SUS ITA ConTBACTORS caste: 7- 12-8 . c Cn ee | eeaiahio: 562 CoLe IONS CONSULTING ENGINE... mI | ' Sh 6682 +B FIELD BOREHOLE LOG NO 2s 3" ue prosect: TZANSIMISSIOM TAICETIE | j SUS ContTRACTIES ur: F-/2- 83 ; "e. : a" a setae : SAMPLE OESCRIPTION a DRILLING OBSERVATION es ca 4 os 3 et. GRAPHIC Los > eee ay COLO REGIONS CONSULTING ENGINEERS | Tw S'ij muir | _ om Ome 62 ceo BOREHOLE LOG NO. Ve" Cet, _ PROMECT! iy INSRNE} SUSTIIA COMTRETOAS eate: -8 [set] ; ea ea Neon (a 1€1: au _ Slo Lig cteeis w/a 52 ( d | ? . on ° eee TL ear aye SAMPLE DESCRIPTION @ ORILLING OBSERVATION J er tat | df pa D dia e Eacr) eT ma Mh meee 1 | we Geo > poAcK PEAT Ce Res : | 3 de et eee ee (Pe eee 5 lend | : Gogy sis can, fo titre herd. ard : eae | Baw siz fing, un A ae _s, herd sind. at ok | 3 |: mG? WY sme Cewel, Gpaiel fro toed sSitore -b site -! een Brown anol Genus Iw Sut, sukerd fA eae tine 4p Coorg Gz El fing ty @ —_ <2rd Cae i “el VU td + ena. eanoot peauer.” 3 ees Us he Broo’ Geavéllu: SAND Wr Suez. mus! sibend I a slid ive" well geoded Sa 1th & eh | Ib ete | | : nee , me i oc erst aac COLD REGIONS CONSULTING ENGINEERS : te 39 fl | sm: 6741 +672 FIELD BOREHOLE LOG NO iin al ea TT eg | tle" CRAG, prosect: TRANS MISSION DVTERTE; SUS TNA CONTRACTDES L “ur_7- -31- -33 | Cocet i SAMPLE DESCRIPTION & ORILLING OBSERVATION ae Dea eo te aa be Gees SIU me ond ait aed 4 ond hn TELE be OY dors. Gl. i, ina Geiss ene Ss 5195 MCCONNELL ,TIM 7 POWMGR/01 - HPDesk orir ' “ec 7 . " > lo Subiect: MEA Stevens Sudstation Issues ; _ qn Creator: Tim MCCONNELL 7 POWNGR/01 Dated: 07727793 at 1431. J On July 14, 10C Chairman Grad Evans asked Jonn Cooley, Jim Hall, and myself Pi to provide the IOC with a summary of issues related to operation of the Stevens Substation, and to recommend ways they might be resolved. The three of us met on the 23rd of July and I then discussed the issues with ML&P people. I'd like your comments on the issues as they now stand for my next session with John and Jim. Issues follow: 1. MEA is not 8 participant to the Intertie agreement so could not tie in (Ref. Paragraph 7.4.3). Probable resolution: AEG&T would be owners of the tap portion of the substation, and would be responsible for obtaining AEA permission, and complying with cost and design es prescribed in Section 7.4. 2. The current MEA cost proposal does not cover ML&P's need (obligation) to be able to monitor and control the proposed tap via SCADA. (Communication protocal to link MEA and ML&P SCADA not available--would have to be developed at considerable expense). Note 1 : Protocols for CEA and GUEA SCADA systems are available and would be paid for by GUEA. Note 2 : ML&P control of the Intertie can not be compromised by the tap--AEG&T obligated to make that happen and IOC has no jurisdiction to dilute that control (Ref. para. 9.1.2). Possible Resolution: MEA proposes that ML&P control can be maintained if MEA provides transducer inputs for an ML&P RTU (which MEA chooses not to pay for), provides a dedicated channel on a proposed 960Mhz radio which is routed from the Div/Com Chulitna relay tower (20 miles from Stevens) to Peak Summit to Anchorage. Note 1 : The microwave path described above is part of the Div/Com communication backbone. GVEA uses Div/Com microwave facilities to control the Cantwell tie. I have a call in to determine if GUEA is using 960Mhz radio out of Cantwell to tie into Div/Com Microwave. Note 2: I informally suggested that payment for the RTU should at least be an Intertie expense if MEA did not pick up tag. 3. The Minimum Intertie Transfer Capability Rights (MITCR) issue. (Ref. Sections 7.1 & 7.2). Discussion in the IOC and with John, Jim and me assumed AEG&T had transfer rights for power flowing south only, and power which fed Stevens Sub from the South would intrude upon FMUS or GUEA MITCR's. How then to accomodate the normal normal flow from CEA? Note 1. The same situation exists at Cantwell where GUEA feeds from the North Cless than .5Mw). But in this c » Section 7.5 says the servicing utility shell have the right to use intertie capacity to serve Cantwell. It goes on to say that the required capacity will be provided from that utilities MITCR. Note 2. Precident to allow MEA to feed from the South may exist with their distribution load at Douglas. Douglas Sub has been fed from Teeland with no objections, yet the power (2Mw) is wheeled across AEA line (Teeland to Hollywood Rd)--which is part of the Intertie (Exhibit Definition 18) and from Hollywood road to Douglas over MEA lines. Possible Resolution: Allow the 7Mw load to be fed from the South since /{ the Intertie transfer capacity is limited by the Healy to Gold Hill line, not the portion of the line from Teeland to Stevens. With the Stevens load, the combined FMUS and GVEA MITCR of 70Mw could still be delivered at Healy. (Interim until broader MITCR concept for all new Intert is developed?). 4. Wheeling charge--Jim Hall proposed in his 25 March letter on Stevens issues that wheeling be prorated on milage 26/175 of the energy rate per Mw. Possible Resolution: Short of contract ammendment, I have no other suggestions. 5. Reference Larry Hembree letter of 18 March 1993, on technical issues: 1. through 6. no problem 7. Line P. T.'s will be on same phase 8. Jim Hall needs more information from Larry H. 9. Can have either battery voltage motitor or alarm (Our choice) I'd like to discuss these issue soon as possible and any others that you have. MEA would like to be operational by fall so will press for quick answers. tt entative Frid American Public Power Association 2301 M Street. NW. TRANSMISSION ACCESS: THE NECESSARY TERMS AND CONDITIONS A REPORT BY THE AMERICAN PUBLIC POWER ASSOCIATION JUNE, 1993 American Public Power Association June 3, 1993 TRANSMISSION ACCESS: THE NECESSARY TERMS AND CONDITIONS Effective transmission can be thought of as a three-legged stool. In equation form, access equals capacity plus price plus "terms and conditions" of service. The efforts to date by Congress and FERC have concentrated on capacity and price questions. However, anticipating its specific implementation of Energy Policy Act provisions, FERC is beginning to turn its attention to the terms and conditions' leg of the stool. Having access to 100 megawatts of transmission capacity at a favorable price is meaningless if use is stymied by unnecessarily restrictive, or otherwise anticompetitive, terms and conditions of service. After some introductory material, this paper outlines the major items in a transmission service agreement that would result in substantially equal terms and conditions of service. The paper then describes the information requirements necessary for competitors to exercise fairly the terms and conditions of an appropriate transmission service agreement. It concludes with an extended discussion on scheduling and control area flexibility. For questions or further information, please contact Dave Penn, APPA director of policy analysis, 202/467-2933. ## # ATTACHMENT mos CONTROL AREA CONCEPTS AND OBLIGATIONS JULY 1992 “All systems share the benefits of interconnected systems operation and, by their voluntary association in NERC, they recognize the need and accept the responsibility to operate in a manner that will enhance interconnected operation and not burden other interconnected Systems.” ‘ Excerpt from NERC Reliability Criteria - for Interconnected Systems Operation Balancing Actual and Scheduled Interchange OVERVIEW OF CONTROL AREA OBLIGATIONS In the strictest terms: A control area is an electrical system bounded by interconnection (tie line) metering and telemetry. It controls its generation directly to maintain its interchange schedule with other control areas and contrib- utes to frequency regulation of the Interconnection. This means that a control area is an electric system that meets the following two requirements. It can: © Directly control its generation to continuously balance its actual interchange and scheduled interchange, and ¢ Help the entire Interconnection regulate and stabilize the Inter- connection’s alternating-current frequency. A control area is connected to other control areas with tie lines. The control areas on either end of a tie both know how much energy is flowing from one to the other because they meter the tie at a common point. (See Figure 2.) By adding the tie line meter readings (with energy flowing out as positive and flowing in as negative), the control area can calculate its net actual interchange with the rest of the Inter- connection. A control area controls its actual interchange and contrib- utes to Interconnection frequency regulation by adjusting its generation through its automatic generation control system, or AGC. A control area’s scheduled interchange is the sum of all the interchange schedules the control area has with all other control areas. This sum is the control area’s net scheduled interchange with the rest of the Interconnec- tion. The control area is obligated to con- trol its generation to attempt to match its net actual interchange to its net scheduled inter- change.’ The Interconnection supplies or absorbs the difference between the actual and scheduled interchange. This difference is called inadvertent interchange. Figure 2 — Control area metering ' Ivis impossible to control generation so precisely to keep these two exactly equal. A control area is obligated to keep the difference between its actual and scheduled interchange within limits that NERC specifies in its Control Performance Criteria. CONTROL AREA CONCEPTS AND OBLIGATIONS Nerc SEM Recognition as Control Area Compliance With Operating Criteria and Guides Reporting REQUIREMENTS To be recognized as a NERC control area, a system must be re- viewed and confirmed by the Region and NERC Performance Sub- committee representative that the system meets the following basic requirements: © Operates generation. ¢ Has metered connections (ties) with other control areas and the necessary contracts to use those connections. © Has the ability to control generation and match its net actual inter- change to its net scheduled interchange. ¢ Has generator governors that are allowed to respond properly to Interconnection frequency changes. © Uses tie-line bias control (unless doing so would be adverse to its or the Interconnection’s reliability). © Has a control center with 24-hour-per-day staffing. A control area is obligated to adhere to all NERC Reliabil- ity Criteria and Operating Guide Requirements and to follow, where applicable, all NERC Operating Guide Recommendations. (See Appendix 1, Summary of Operating Criteria and Guides.) When a control area determines that an Operating Criterion or Guide does not apply to its circumstances, it may ask the NERC Operating Committee for a waiver. The control area must show that waiving the Criterion or Guide will not burden other control areas in the Intercon- nection. Regional Councils, power pools, or other associations also may impose their own criteria and guides. Inadvertent Interchange Accounting — Each control area shall manage inadvertent interchange in accordance with NERC Operating Guide I.F. — Inadvertent Interchange Management. Monthly summaries are tequired as detailed in Appendix I.F. — Inadvertent Interchange Energy Accounting Practices. The NERC Operating Manual contains more information on inadvertent accounting and reporting in the Inadvertent Accounting Training Document. CONTROL AREA CONCEPTS AND OBLIGATIONS nerc [iE INTRODUCTION After some introductory material on equal access conditions for all competitors, this paper outlines the major items in a transmission service agreement that would result in substantially equal terms and conditions of service. The paper then describes the information requirements necessary for competitors to exercise fairly the terms and conditions of an appropriate transmission service agreement. It concludes with an extended discussion on scheduling and control areas as they relate to the case where transmission service agreements are requested by municipal electric and other utilities as opposed to other nonutility entities. As former Chairman Martin Allday warned in a recent speech, the Federal Energy Regulatory Commission (FERC) is facing a “major new challenge. That is to decide what terms and conditions are needed to make open access a reality. To put it differently, what [electricity transmission] service must a transmitter offer so we can be sure it is not exercising market power.”! This major new challenge comes not only from FERC’s case law decisions in recent years to promote competition in generation in part through increased transmission access, but also most directly from the Title 7 provisions of the October 24, 1992, enactment of Public Law 102-486, the Energy Policy Act of 1992 (EPACT92). These provisions give FERC the authority to mandate just and reasonable, nondiscriminatory transmission access. They apply to existing transmission capacity as well as enlargements. Transmission access in the electric utility industry is a rallying cry that was answered with the passage of EPACT92. However, as chief legislative architect, Energy and Power Subcommittee Chairman Phil Sharp, has reminded us recently, FERC must now carry out Congress’ wishes and implement the transmission provisions in an aggressive way. Transmission access must be effective. It must be nondiscriminatory. We are only at the beginning, not the end of this quest. Effective transmission access can be thought of as a three-legged stool. In equation form, access equals capacity plus price plus “terms and conditions” of service. The efforts to date by Congress and FERC have concentrated on capacity and price questions. Although transmission pricing matters have been addressed, many-areas.of.contention-remain.to-be resolved. Even though these pricing issues will continue to occupy FERC for some time and even though one needs all three legs to sit on the stool, we will set pricing aside for the purposes of this paper. 1 Martin Allday, “Prepared Remarks,” Energy Daily Conference, Arlington, Virginia, December 10, 1992, p. 4. that firms could use their control of transmission facilities to reduce competition in wholesale markets...."4 Serious logicians will point out that truly equal transmission access could come to the US. electricity supply industry only if there were changes in transmission ownership, not just changes in tariff conditions. Such a result has two possible forms—joint ownership or third-party ownership. Proportionate joint ownership or equivalent joint use arrangements are attractive to transmission users. The advantage of transmission ownership is that the owners are able to engage in transactions at will, subject only to real technical constraints. They have the decided advantage in a competitive situation of direct access to information about the system and the power to decide (subject only to regulatory review or contractual constraint) all matters related to the use of the system. Perhaps the biggest advantage is the removal of uncertainty associated with not knowing if access will be available for a particular transaction. Such joint transmission ownership arrangements are not new or lacking a history of success. They are in place in Georgia, Indiana, Minnesota, western Wisconsin, Iowa, South Dakota, and New England to an extent. Mention of the possibility of third-party ownership, the other form of ownership change, seems to be escalating, if slowly. Nearly 20 years ago mainstream academic Leonard Weiss saw the need to divorce transmission ownership from generation utilities if competition was not to be stymied by self-interested control of bottleneck transmission facilities.5 In the 1980s former Illinois Commerce Commission Chairman Philip O’Connor spoke of “devolvement” of the transmission function from the corporate structure of traditional integrated electric utilities. The CEO of Public Service of New Mexico, Jerry Geist, popularized the term “transco” for transmission company. At a recent news conference, William Berry, now retired CEO of Dominion Resources (Virginia Power), told participants in a question-and-answer session following his presentation that the ultimate solution to this country’s conflicts over transmission access, though one fraught with problems of getting from here to there, lay in separate ownership by third parties.6 At about the same time, a high-ranking FERC staffer identified separate “Electricity Transmission Access,” National Energy Strategy, Technical Annex 3 (Washington, D.C.: Department of Energy, 1991/1992), p. 5. Leonard W. Weiss, “Antitrust in the Electric Power Industry,” Promoting Competition in Regulated Markets, ed. Almarin Phillips (Washington, D.C.: Brookings Institution, 1975), pp. 135-173. TAPS (Transmission Access Policy Study Group) Conference, Arlington, Virginia, January 7, 1993. Host Utility finds a low-cost energy source and interrupts Party’s transaction in progress in order to effect its own transaction). Firm Capacity Reservation I Party shall be able to purchase (reserve) a block of capacity on the transmission system for transactions between or among multiple specified receipt and delivery points in order to enable: ® Two-way transactions back and forth along the same transmission line or corridor, where technically feasible, without additional transmission charges. © Multiple transactions including economic dispatch of multiple resources from receipt points to delivery points. As long as the total capacity of the reserved block of transmission is not exceeded, no additional charges would be imposed. © Coordinated purchases from other utilities outside of the Host Utility’s control area. « Transactions would be subject to reasonable hourly scheduling requirements that are the same ones used by the transmission owner to schedule and dispatch its transactions. Notice Requirements The Party shall be able to obtain both short-term (down to one hour) access and longer- term access (up to the life of a generation resource) on reasonable notice. Approval or denial of access should be immediate for hourly transactions, within a few hours for daily transactions, and within a day for weekly transactions. Usually requests for short-term service (one month or less) are made to, and approval is obtained from, the system operators of the Host Utility. For longer term requests, especially multiyear transactions, the approval of the planning department is likely to be required. The Host Utility should provide timely preliminary and final responses to the requests for longer term service on a best efforts basis within the constraints of the provisions of the Energy Policy Act of 1992. Longer term requests for service may take time to evaluate fully and may involve a need to construct facilities. The following schedule seems reasonable if construction of new facilities is not required: ‘TRANSACTION DURATION PRELIMINARY RESPONSE FINAL RESPONSE a [imonthtotyear | iweek | 2weeks I Schedules for daily transactions should have to be submitted to the Host Utility no earlier than 24 hours in advance, but prior to noon on the previous day, with the ability to modify schedules in progress on one-hour notice for any reason, and with no notice in case of emergencies. Schedule changes for nonemergency reasons may be subject to reasonable limits to prevent operating problems for the Host Utility. Regulation I Utilities use an ACE (area control error) or a load following band of reasonableness to match resources with load for their own scheduling and dispatch operations. The Party should not be held to a higher standard. The Host Utility shall file with FERC a tariff to provide frequency and voltage regulation services for the proposed transaction if the Party requests such services within 60 days of the transmission service tariff filing. The regulation services rate shall be cost based, and the terms and conditions shall be comparable to any other such services provided by the Host Utility to other entities under any agreement, schedule, or tariff. The Party shall have the option of providing this service itself. Control Area fl The Party shall have the ability to establish a control area using a firm transmission capacity reservation(s) purchased from the Host Utility. This may be either a regulating or a “scheduling” control area based on the circumstances. (See the final section of this paper for a more detailed explanation.) Information Access i The Host Utility shall make available to the Party, promptly upon request, copies of all studies and reports relating to the capability of the transmission system to accommodate anticipated transmission service transactions. Further, the Host Utility shall provide basic data about the transmission system to allow the Party to conduct its own studies of the system. The data shall be provided in both printed and computer-readable form, suitable for use in transmission system analysis programs, e.g., power flow, stability programs. (See the following section of this paper for an elaboration of these vital information requirements.) Planning i The Host Utility shall allow the Party to participate in joint planning studies and discussions involving the future development of the regional transmission system. Such said elsewhere on the related matter of transmission plans, information is power and must be shared equitably. FERC’s responsibilities to regulate an electric utility industry “affected with the public interest,” as stated by the Federal Power Act, require no less.9 Congress recognized this by including §723 in EPACT92 on “Information Requirements.” There it amended Part II of the Federal Power Act by adding a new §213 whose relevant subsection states: (b) TRANSMISSION CAPACITY AND CONSTRAINTS.—Not later than 1 year after the enactment of this section, the Commission shall promulgate a rule requiring that information be submitted annually to the Commission by transmitting utilities which is adequate to inform potential transmission customers, State regulatory authorities, and the public of potentially available transmission capacity and known constraints. While FERC must promulgate a rule and decide what information is necessary to meet this specific legislative mandate, the annually submitted information will largely provide a snapshot. FERC’s responsibility is broader. It must consider the availability of the transmission information necessary to realize effective transmission access and the generation competition it is to facilitate. Going further, all parties including the transmission owners will benefit if FERC does this in a way that assures competitors, state regulators, and the public alike that market power is not being exercised. This implies participation and verifiability throughout the year, rather than on an annual snapshot basis. The rest of this section outlines the information requirements to effect nondiscriminatory transmission access—the information required for equal terms and conditions of service, the information necessary for transmission-dependent utilities such as the vast majority of APPA members to be able to compete fairly. An entity desiring use of another utility’s transmission system on a nondiscriminatory access basis needs to be able to do the following: i participate in the planning that will lead to decisions concerning the utilization and expansion of the system; accurately model the operation of the affected utility’s existing transmission system under any reasonable operating or contingency scenarios; — accurately model the effect that its proposed transaction will have on the transmitting utility’s system; 9 See “Comments of the American Public Power Association on the Consensus RTG Plan,” Docket No. RM 93- 3-000, January 25, 1993. i Generator data (continued): e Addition/retirement dates for generating units. © Operating limitations (to provide insight into expected operation). © Voltage regulation information (e.g., regulated bus, target voltage). Transformer data (nonimpedance data): © Minimum and maximum tap settings. © Normal voltage control settings (e.g., regulated bus and desired voltage). © Normal phase shift settings and limitations. 8 Other system component information: © Capabilities and operating characteristics of any synchronous reactors. © Capabilities and operating characteristics of any switchable capacitors and inductors and static VAR generators. © Detail on relays/breakers that would affect system operation after a system disturbance—settings, switching times, coordinated operations, etc. ® Technical characteristics of any AC/DC converters on the system. i Power sales and purchases information: © Scheduled interchanges. © Capacity entitlement/reservations. I System operation information (operating guides): © Descriptions of how possible or probable operational problems will be handled. For example, certain system overloads can be acceptable (to the owner) under certain contingencies or can be removed by operator action, such as removing facilities from service or redispatching generation. Other system contingencies may require special treatment such as the loss of a large nuclear unit which may appear as a large load immediately following the outage. Furthermore, information on unit response characteristics may be necessary to model power flow accurately immediately following a large disturbance. An important point about _necessary-access_to information-to-evaluate-transmission capacity and constraints is that it is not sufficient to have access to the information itself. It will be paramount to have access in one way or another to the load flow model used by the transmitting utility. “Base” and “transfer” or change cases, as well as their determining assumptions, need to be analyzed. Recent developments in desktop computing power and analytic software make it more widely possible that this access can be independent of the company’s data processing 11 As another example, Dairyland Power Cooperative, a 700-MW generation and transmission cooperative operating in western Wisconsin, Minnesota, and northeastern Iowa, operates a joint transmission network in western Wisconsin with Northern States Power Company (a 7,000-MW utility). Power serving the two systems flows over each other’s lines, but each has its own independent control area. This arrangement is possible because each utility monitors its own loads and interconnections electronically and dispatches generation to meet its own loads and interchange obligations. In the same way, a municipal utility or municipal power supply agency operates within the control area of another larger utility by electronically monitoring its loads and interchanges at individual delivery and interconnection points, bringing the information back to its dispatch center, and then dispatching its generation to meet the power requirements of its delivery points and transfer obligations at the interchange points. To the extent that a municipal entity’s generation does not match its loads and scheduled interchanges at any given moment, there is an inadvertent flow, either positive or negative, between the municipal and the larger control area entity. The two utilities would maintain an inadvertent energy account, just as would two utilities operating control areas on two adjacent transmission networks. As long as the municipal entity meets all of the other North American Electric Reliability Council (NERC) requirements for a control area, it can operate on the same transmission network as the larger entity. A municipal utility can also dispatch or schedule its resources without being a formal regulating control area. Such municipal entities will typically schedule the power output from their resources on an hourly basis and, to the extent that the hourly schedules deviate from the actual power deliveries, inadvertent accounts are maintained with the larger utility or utilities involved. In this case, the scheduling municipal entity is operating what can be referred to as a “scheduling” control area. Generally, the interchange between either a regulating control area or a scheduling control area and the larger control area(s) within which or next to which it might operate is governed by interconnection agreements. In the past, the guidelines and interconnection contracts governing the operation of the different types of control areas have not always been rigorously delineated or enforced. The recent efforts of NERC and its regional reliability councils to define more specifically the requirements and obligations of different utilities under these definitions is indicative of the perception that the NERC operating guides for control performance must be clearly spelled out and adhered to by all utilities. 13 r- CONCLUSION This paper has addressed the major new challenge embodied in the transmission access provisions of the new energy law and articulated most clearly by Martin Allday. That is, it has outlined the equal terms and conditions of a transmission service agreement that are necessary to prevent the exercise of market power. Key among the terms of any effective service agreement is the requirement for appropriate information on transmission capacity and constraints. The discussion put forth the elements necessary to meet that information requirement, as well as explained how municipal utility dispatch centers can and do operate reliably within larger utility control areas. 15°