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HomeMy WebLinkAboutIntertie Operating Committee Controller Duties 1993NY e ‘= \ Municipality of Anchorage Municipal Light & Power Ton Tele 1200 East First Avenue Anchorage, Alaska 99501-1685 Telephone: (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 DATE: November 8, 1993 TO: Brad Evans, IOC Chairman 4 ) / FROM: Tim McConnell, IOC Representative, MLEP-7 Mh (or SUBJECT: Controller Duties Ref: Vince Mattola October 6, 1993 letter to you, same subject Thank you for sending a copy of Vince Mattola's October 6, 1993 letter on Controller duties. The two themes in the letter relate to cost and to distribution of duties. The cost issue is probably the easier to deal with and ML&P is willing to discuss reducing charges to the Alaska Intertie in concert with corresponding Northern Operator cost reductions. At this time, the issue of distribution of duties and the role of the IOC in that process is less clear. Ron Saxton's July 6 1993 letter to the RUG Chairman in response to your request for a legal opinion as to I0C authority, and Tom Stahr's statement as one of the framers of the Agreement are clearly at odds (Stahr Ltr. attached). Given these diverse opinions, the issue of scope and distribution of duties is not likely to be settled in a formal motion. Even if a 75% vote were obtained by either side, it is likely to be challenged through the appeal process or other legal means. In view of the above, ML&P recommends that the IOC ask both Northern and Southern Controllers to agree on a percentage reduction in charges for the duties now performed by the Operators in their respective areas (effective for the FY95 budget), and that the issue of scope and distribution of duties be dealt with after the Participation Agreement for the New Interties is concluded. Attachment: Tom Stahr Letter Citing Framers' Intent to Narrowly Scope IOC Authority Putting Energy into Anchorage for 60 years "1932 - 1992" WY (ake Municipality of Anchorage Municipal Light & Power \ v4) Tom Fink, Mayor 1200 East First Avenue Anchorage, Alaska 99501-1685 (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 September 27, 1993 Mr. Ron Saxton Ater Wynne Hewitt Dodson & Skerritt Attomeys At Law 222 S.W. Columbia, Suite 1800 Portland Oregon 97201-6618 Dear Mr. Saxton: This letter is in response to the “Railbelt Reserve Issues" document you distributed at the last Bradley Lake PMC meeting. While I have not taken time to enumerate all of my concerns, I do want to mention a few which are critical as they relate to items in the subject document which are clearly incorrect and should not remain unrefuted. First, | do not believe the IOC was given broad latitude. In fact, I believe a great deal of effort was taken to narrowly restrict the IOC actions in other than operating matters which they were set up to attend to. Specifically, 9.1.2 of the agreement states "The Operating Committee has no authority to modify any of the provisions of this agreement or to modify or set rates unless expressly provided for herein". In Addendum No. | pif Section B-2.2 provides for the Operating Committee to modify or change criteria and even here they are restricted to either systemwide criteria or to narrowly defined actions. The reason for the latitude given was that the drafters of the agreement did not know what amount of reserves were required to avoid loadshed and more serious problems on the interconnected system and wanted to allow for necessary changes in this narrow area. The other latitude allowed to the Operating Committee in Paragraphs A-1.1.3, and B-2.4.2 are restricted in scope by other parts of the addendum which in most cases govern the allocation of the changes between utilities. In B-2.4.2 the criteria the Operating Committee must use is narrowly defined. Reserves is in complete variance with the clear meaning of the Agreement. Section B- 2.4.1 of the Agreement provides that “System Spinning Reserves shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective system and the integrated systems Demand of the system involved." When a non-firm sale is made from some of the generator capability that is dedicated to spin the integrated system demand will be increased by the amount of the sale and the system spinning reserves reduced by the same amount. Should this redce the spinning reserves below the spinning reserve requirement either system wide or for a particular utility a spinning reserve deficiency would exist. Since the Spinning Reserve Requirement is required at any given instant this of course means that spinning reserve is required at all times. Not even for an instant can the spin be removed by loading units to make non-firm sales if the capacity used is necessary for maintaining spin. Pragmatically from system dynamic studies we know the spin must be available within less than two seconds to avoid Stage | loadshed, but contractually Putting Energy Into Anchorage Question 9 of the subject issues paper about making non-firm sales from Spinning vA —- this capacity required for spin cannot be used for other purposes for even an instant. Clearly a participant is not allowed to make non-firm sales from Spinning Reserve which is required to meet the Spinning Reserve portion of their Operating Reserve Requirement. Paragraph B-2.4.5 allows a participant to arrange with other participants to supply all part of their Operating Reserve Requirement. Thus spin can be sold and purchased but clearly it must be sold or purchased as spin, i.e., unloaded generating capacity and or not transmogrified into firm or non-firm power. If participants want to make transactions and do not have, or choose to use, adequate capacity to provide the necessary spin (real spin) and do not want to follow the procedures of B-2.4.2 to obtain permission to use load shed in lieu of spin they can negotiate to purchase spin from other participants. , Question 10 of the subject issues paper regarding whether the selling or purchasing participant has the responsibility for supplying the required spin is misleading because the Intertie Agreement outlines Operating Reserve Requirements, Reserve Requirements with precision in Sections B-2.2 and B-2.3. It is clearly based on unit sizes of operating units owned by the respective parties and remains unchanged a non-firm transaction. The participants may negotiate something different as enabled by Paragraph B-2.4.5, but the underlying responsibility is clear. by I also disagree with the issues papers conclusion that only hence, Spinning the IOC has contractual responsibility for resolving the Reserve Issues because it is clear that many of the issues involve things the IOC is specifically precluded from addressing. It is becoming increasingly clear that the Administration of the Alaska Intertie desperately needs a higher level of decision makers so that the IOC will have the necessary supervision to allow them to concentrate their energies on operating issues. The structural changes’ taking place with the Alaska Energy Authority have made this problem acute. The obvious solution is to have the IOC Report to the Bradley Lake Project Management Committee and at the same time change the Bradley Lake Project Management Committee to the Railbelt Project Management Committee which should administer both old and new Interties and Bradley Lake. omas R. Stahr General Manager TRS/am ce; Dave Calvert, City of Seward Ken Ritchey, MEA David Higher, CEA Norm Story, HEA Mike Kelly, GVEA Bob Hufman, AEG&T Vince Mottola, FMUS NOS ZO J vires: sly Shoe \ Municipality of Anchorage Municipal Light & Power ror 1200 East First Avenue Anchorage, Alaska 99501-1685 Telephone: (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 DATE: November 8, 1993 TO: Brad Evans, IOC Chairman 4 | / FROM: Tim McConnell, IOC Representative, MLE py h (yor SUBJECT: Controller Duties Ref: Vince Mattola October 6, 1993 letter to you, same subject Thank you for sending a copy of Vince Mattola's October 6, 1993 letter on Controller duties. The two themes in the letter relate to cost and to distribution of duties. The cost issue is probably the easier to deal with and ML&P is willing to discuss reducing charges to the Alaska Intertie in concert with corresponding Northern Operator cost reductions. At this time, the issue of distribution of duties and the role of the Ioc in that process is less clear. Ron Saxton's July 6 1993 letter to the RUG Chairman in response to your request for a legal opinion as to IOC authority, and Tom Stahr's statement as one of the framers of the Agreement are clearly at odds (Stahr Ltr. attached). Given these diverse opinions, the issue of scope and distribution of duties is not likely to be settled in a formal motion. Even if a 75% vote were obtained by either side, it is likely to be challenged through the appeal process or other legal means. In view of the above, ML&P recommends that the IOC ask both Northern and Southern Controllers to agree on a percentage reduction in charges for the duties now performed by the Operators in their respective areas (effective for the FY95 budget), and that the issue of scope and distribution of duties be dealt with after the Participation Agreement for the New Interties is concluded. Attachment: Tom Stahr Letter Citing Framers' Intent to Narrowly Scope IOC Authority Putting Energy into Anchorage for 60 years "1932 - 1992" WY eS Municipality of Anchorage unicipal Light & Power \ f/ Tom Fink, Mayor 1200 East First Avenue Anchorage, Alaska 99501-1685 (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 September 27, 1993 Mr. Ron Saxton Ater Wynne Hewitt Dodson & Skerritt Attorneys At Law 222 S.W. Columbia, Suite 1800 Portland Oregon 97201-6618 Dear Mr. Saxton: This letter is in response to the “Railbelt Reserve Issues" document you distributed at the last Bradley Lake PMC meeting. While I have not taken time to enumerate all of my concerns, I do want to mention a few which are critical as they relate to items in the subject document which are clearly incorrect and should not remain unrefuted. First, I do not believe the IOC was given broad latitude. In fact, I believe a great deal of effort was taken to narrowly restrict the IOC actions in other than operating matters which they were set up to attend to. Specifically, 9.1.2 of the agreement states "The Operating Committee has no authority to modify any of the provisions of this agreement or to modify or set rates unless expressly provided for herein". In Addendum No. | only Section B-2.2 provides for the Operating Committee to modify or change criteria and even here they are restricted to either systemwide criteria or to narrowly defined actions. The reason for the latitude given was that the drafters of the agreement did not know what amount of reserves were required to avoid loadshed and more serious problems on the interconnected system and wanted to allow for necessary changes in this narrow area. The other latitude allowed to the Operating Committee in Paragraphs A-1.1.3, and B-2.4.2 are restricted in scope by other parts of the addendum which in most cases govern the allocation of the changes between utilities. In B-2.4.2 the criteria the Operating Committee must use is narrowly defined. Question 9 of the subject issues paper about making non-firm sales from Spinning Reserves is in complete variance with the clear meaning of the Agreement. Section B- 2.4.1 of the Agreement provides that “System Spinning Reserves shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective system and the integrated systems Demand of the system involved." When a non-firm sale is made from some of the generator capability that is dedicated to spin the integrated system demand will be increased by the amount of the sale and the system spinning reserves reduced by the same amount. Should this redce the spinning reserves below the spinning reserve requirement either system wide or for a particular utility a spinning reserve deficiency would exist. Since the Spinning Reserve Requirement is required at any given instant this of course means that spinning reserve is required at all times. Not even for an instant can the spin be temoved by loading units to make non-firm sales if the capacity used is necessary for maintaining spin. Pragmatically from system dynamic studies we know the spin must be available within less than two seconds to avoid Stage | loadshed, but contractually Putting Energy Into Anchorage this capacity required for spin cannot be used for other purposes for even an instant. Clearly a participant is not allowed to make non-firm sales from Spinning Reserve which is required to meet the Spinning Reserve portion of their Operating Reserve Requirement. Paragraph B-2.4.5 allows a participant to arrange with other participants to supply all or part of their Operating Reserve Requirement. Thus = 8 can be sold and purchased but clearly it must be sold or purchased as spin, i.e., unloaded generating capacity and not transmogrified into firm or non-firm power. If participants want to make transactions and do not have, or choose to use, adequate capacity to provide the necessary spin (real spin) and do not want to follow the procedures of B-2.4.2 to obtain permission to use load shed in lieu of spin they can negotiate to purchase spin from other participants. Question 10 of the subject issues paper regarding whether the selling or purchasing participant has the responsibility for supplying the required spin is misleading because the Intertie Agreement outlines Operating Reserve Requirements, hence, Spinning Reserve Requirements with precision in Sections B-2.2 and B-2.3. It is clearly based on unit sizes of operating units owned by the respective parties and remains unchanged by a non-firm transaction. The participants may negotiate something different as enabled by Paragraph B-2.4.5, but the underlying responsibility is clear. I also disagree with the issues papers conclusion that only the IOC has contractual 0 responsibility for resolving the Reserve Issues because it is clear that many of the issues a involve things the IOC is specifically precluded from addressing. It is becoming increasingly clear that the Administration of the Alaska Intertie desperately needs a higher level of decision makers so that the IOC will have the necessary supervision to allow them to concentrate their energies on operating issues. The structural changes taking place with the Alaska Energy Authority have made this problem acute. The obvious solution is to have the IOC Report to the Bradley Lake Project Management Committee and at the same time change the Bradley Lake Project Management Committee to the Railbelt Project Management Committee which should administer both old and new Interties and Bradley Lake. = Sincerely, 4am omas R. Stahr General Manager TRS/am cc: Dave Calvert, City of Seward Ken Ritchey, MEA David Higher, CEA Norm Story, HEA Mike Kelly, GVEA Bob Hufman, AEG&T Vince Mottola, FMUS NY STi) Municipality of Anchorage Municipal Light & Power re ey 1200 East First Avenue Anchorage, Alaska 99501-1685 Telephone: (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 DATE: November 10, 1993 TOs Brad Evans, IOC Chairman ) cc: IoC Representatives YP i FROM: Tim McConnell, ML&P IOC cacieeniabie st po. idems SUBJECT: Stevens Substation Issues In response to your request of July 14, 1993, John Cooley, Jim Hall and I met on July 23, 1993 to consolidate the contractual issues related to activating the Stevens Substation. The references used were the letters listed below and attached: MEA January 11, 1993 letter on communications options for Stevens Substation MEA March 25 letter on technical issues ML&P March 18, 1993 letter listing concerns regarding SCADA communications CEA March 23, 1993 letter of concerns/opinions GVEA May 19, 1993 letter of concerns Issues discussed at the July 23, 1993 meeting, in subsequent meetings and in additional correspondence to date are summarized below: Ae MEA is not a participant to the Alaska Intertie Agreement so could not tie in. Resolution of this contractual problem is probable since Jim Hall stated that AEG&T would become the owner of the tap portion of the substation. Putting Energy into Anchorage for 60 years "1932 - 1992" 2. The MEA proposal (March 25 letter) does cover ML&P's contractual requirement to monitor and control the tap and the energy schedule via SCADA. To accomplish this, ML&P will install an RTU in the Stevens Substation in November 1993. Note: ML&P understands Jim Hall's position (Jim Hall September 7, 1993 Operator Duties letter to Chairman I0C) that the Substation should be included in the area operated by the Northern Operator, however paragraphs 10.1.2 and 10.1.3 of the Agreement clearly define the Northern and Southern Boundries. This is not anticipated to be a contractual problem as ML&P’s RTU is scheduled to be fuljy in operation by November 30, 1993. Obyeck On hu ced No haere (eTU, 3. AEG&T does not have MITCR rights to purchase power from the Southern IOC group. , grou” Dopo? To avoid a contractual issue the participants could all agree that precedent permits MEA to feed the Stevens load from the South since power to this load has long been wheeled to Douglas on the Intertie (as defined by Exhibit A, definition 18 of the Agreement). Also, the bi-directional nature of MITCR, is clearly stated in paragraph 7.1.2 of the Agreement although Exhibit D of the Agreement does not make it clear how this would happen. 4. Wheeling charge, as proposed in MEA's March 25, 1993 letter, would have been a contractual issue if based upon MWH/Mile. Jim Hall has stated that MEA will pay the contract wheeling rate to avoid a contractual issue. The group (Jim Hall, John Cooley, and I) did not identify any other issues thought to be contractual in nature. However, AIDEA has yet to present the reply of its counsel to contractual issues raised by Dennis McCrohan in his September 1, 1993 letter (Attached). Interim and technical issues remain, of course, as discussed and assigned in the September 8, 1993 IOC meeting. 6 Attachments, Cited above. a> Matanuska Electric GB Association, Inc. P.O. Box 2929 Palmer, Alaska 99645 Telephone: (907) 745-3231 Fax: (907) 745-9328 January 11, 1993 Larry Hembree Intertie Operating Committee Anchorage Municipal Light and Power 1200 East First Avenue Anchorage, AK 99501 Dear Larry: This letter is to discuss communication options for the Matanuska Electric Association, Inc. (MEA) Stevens Substation. This substation will tap the Intertie near Talkeetna. Permission for MEA to install this facility is contingent on a number of items to be addressed by the appropriate subcommittees of the Intertie Operating Committee. MEA has offered to provide communication channels between the MEA Douglas Substation and the MEA Stevens Substation. These channels were to be provided to any utility who needed them, and at no charge. MEA made this offer based on the installation of a microwave link between Douglas and Stevens. We believed that such a direct link could be installed. Further investigation has shown that such a link would require towers in excess of 200 feet in height at both ends or that an intermediate site with two links be used. Either of these options substantially change the scope of the project and result in budget problems. We offer, for your consideration, an alternative that we believe will meet the needs of the utilities without the installation of the microwave link. MEA would install two 960 megahertz radio links from a high site near Douglas to the Stevens substation. These links would provide communication for an MEA RTU at Stevens, and for a dial up phone line to Stevens. MEA would use its Douglas RTU to emulate both analog and pulse data on the Stevens load. This data would be available to any utility that wanted it. Further, MEA would configure the Douglas RTU to provide the Southern Area Controller the control of the high side devices at Stevens. As previously discussed, this would mean that the southern area controller would have exclusive control of the in-line motor operated disconnect switch at all times and exclusive control of the S&C series 2000 circuit switchers when the in-line motor operated disconnect switch was in the open position. Position indication on both the in-line motor operated disconnect switch and the series 2000 circuit switcher would also be available to any utility who wanted it. thtattie Operating Committee Members »' Page 2° Janunty i 1993 ‘2 Suel aft atrangernént has advantages and disadvantages. A cleat Advantage is that it vy. + Would @liminate the feed fot installation and mairitehahce of an additional RTU at Stevens by those who desité to teceive data. Status indicatioti on thé devices at Stevens would be delayéd by 48 tritch a thirty secotids dué to the scAti taté of thé MEA SCADA 2 systettl: sities these devices até hot used fot liné relaying, this does tiot seetn ee Pulse data ffom the RTU wotlld be litiited to 4 pulse fate of about otie by pef fintite. This is again due to.the scat tate of the MEA system. Selection of Se 7] cmbetin equipment at Stevens can assure A fulse Fate of abo GE Per Minute fot Pes ~ nofinal load. “THIS édtild fesuit in a rate BF Perhaps one pulsé in four minutes at every Hohe: load,“ Analog load information éaf bé Ptolided eile ofl a 4 through 20 nf amp Basis, Sf 6H another base through thé Usd of A tratisducét. As fat as reliability ar Rue eondseried/ the MEA SCADA system has been very feliable With, pérhaps, He RTU., < failue pet yeaf fot twerity RTUs and absut ofe systéfi bf éotittitntication failuté pet ay year.” ‘Thesé are typically tep aired in ond Of to days. MBA gives maintenaricé of its EOCADA systertt hig tigh P priority ' sitd this systéth Would bé an integral part of thé MEA y= SCADA syste é dial ap phone line would be tséd for interrogation of thé pulse : eootders At Stavens by CEA A MBA for Wholesale billing putposes and by the Intertie or Controllers fof true-up of schedules. We believe that this § eyatont could provide the hecessary infottiation in 4 Very usable fori afid at 4 feasottablé cost to all Eoncbatiod If You have any questions tegatding this System please cohtact tne. Yotif consideration of this systeni is appteciatéd. inderély, . At wl p/ fat ; Jattiés D. Hall- Staff Engineét- BDESOMIDIP Pe LE) FRE! adh Association, Inc. S j Matanuska Electric P.O. Box 2929 Palmer, Alaska 99645 Telephone: (907) 745-3231 Fax: (907) 745-9328 March 25, 1993 Mr. Brad Evans Chairman, Intertie Operating Committee c/o Golden Valley Electric Association, Inc. (GVEA) P. O. Box 71249 Fairbanks, AK 99707 Dear Brad: SUBJECT: STEVENS SUBSTATION TECHNICAL ISSUES Alaska Energy Authority (AEA) in their letter approving the Stevens Substation tap of the Anchorage- Sarvenky Intertie listed a number of technical and contractual issues. These issues were identified by the Intertie Operating Committee (IOC) in their motion approving the tap. This letter will state Matanuska Electric Association's (MEA) intended resolution of each of the issues. The issues identified are as follows: Operating procedures Review of Final Design Construction Practices and Schedules SCADA control SCADA microwave communications Control area load following/tieline bias metering control point MITCR ramifications Contract compliance Payment eee eo eo eo eo + 4 Opera ting proced ures - We intend to operate the 24.9 KV distribution side of this station in the same manner as we would any distribution station on our system. Automatic reclosing will be used on feeder breakers, and feeder breakers will typically oe eee or closed as needed for proper operation of our system without notice to other utilities. Operation of the 138 KV side of the station will be performed by the eat controller for the control area that the station is located within. If manual operations are required on the 138 KV side of the station, they will be performed by MEA personnel under the direction of the appropriate area controller. + Review of Final ie oi A complete set of design drawings will be made available for review prior to the May TOC 1 meeting. Their have been no changes in the design since the preliminary drawings were presented to the IOC. Y STEVENS SUBSTATION TECHNICAL ISSUES Page 3 March 25, 1993 ¢SCADA Microwave communications - We have offered to provide a six channel 960 megahertz link from Douglas to Stevens. We will connect this link to the multiport RTU and individual RTUs at Stevens if requested to do so. We do not intend to connect to the existing communication systems at the Douglas end, because these are active systems, and we are not in the best position to coordinate the work. ¢Control area load (following / tieline bias metering control point - Stevens is located within the GVEA control area, and as such, pulse information must be available to GVEA for control purposes. CEA is our wholesale supplier, and as such, they must provide load following for the Stevens load. In order to provide this, and to — operate their control area, CEA must receive pulse information from Stevens. e intend to provide pulse information as required to fuifii these needs. ¢MITCR ramifications - MEA will attempt to identify the effect of the relocation of the actual load of the Stevens Substation from Douglas to Stevens. If a reduction in intertie capacity can be identified, and if it is sufficient to require a reduction in maximum south to north transfers, then MEA will negotiate in good faith to obtain the necessary MITCR from one of the northern utilities. Unused capacity is always available to other participants; therefore the only time that MEA should required to purchase MITCR is when the entire capacity of the line is scheduled for use. ¢Contract compliance - MEA intends to comply with the Alaska Intertie Agreement to which it is signatory through Alaska Electric Generation and Transmission. 4 Payment - MEA anticipates payment of wheeling charges in the same manner as other utilities under the terms of the agreement. The amount of this payment would be prorated to reflect the actual amount of the line used. We believe a 26/175 share would be an equitable approach because it represents the portion of the line used on a milage basis. Sincerely, am elf James D. Hall Staff Engineer EDES.658 ce: gh Meco Sam Matthews i Anchorage Municipal Light & Power Homer Electric Association 1200 East First Avenue 3977 Lake Street - Anchorage, AK 99501 Homer, AK 99603 Tom Lovas WZ = \ Municipality of Anchorage Municipal Light & Power ao es ne 1200 East First Avenue Anchorage, Alaska 99501-1685 18 March 1993 Telephone: (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 David Burlingame, Chairman hee Intertie Operating Committee\, QR c/o Chugach Electric Association P.O. Box 196330 Anchorage, Alaska 99519-6300 Dear Mr. Chairman: Municipal Light and Power has serious reservations with regard to the MEA SCADA communications to the new Stevens Substation. We understand that MEA is ready to remedy problems with the proposed system to the satisfaction of the Reliability Subcommittee. The difficulty arises from the fact that the proposed system has not been engineered at this point. Unsatisfactory performance could jeopardize the reliable sales of power over the tie line. We request MEA complete further studies on transmission path availability and alternatives to the 960 Mhz communications system which they propose. Our preference for communication is the existing DivCom State owned microwave system. To save on installation costs of a new RTU at Stevens for the southern controller, we would like to explore the possibility of having the MEA RTU serve multiple masters. The cost of the protocol emulation would be weighed against the cost of a ML&P RTU in the Substation, and its space requirements. ML&P requires control and indication of the MOD switch and circuit switchers, as well as metering data for the Stevens load. We are providing you with the following list of points that would be needed. KwH pulses for the Stevens load. Kw & Kvar analog (+/- 1 ma.) for Stevens load. Circuit Switcher status ("a" contact) for both circuit switchers. MOD status ("a" contact). Voltage relay contacts for north and south lines. Local/Remote control switch position indication, circuit switchers and MOD control switchers. Voltage transducers for north and south lines. * Communication failure alarm. Battery charger failure alarm. Control of MOD and circuit switchers. ~ ve * We suggest that P.T. replacement for the two line P.T.'s be on different phases to give dispatchers the best picture of system conditions. $o-"*neg. Lf Panne Larry bree Station Design Supervisor, ML&P - Putting Energy into Anchorage for 60 years "1932 - 1992" See AVaYNE o: Sut bt -¥8-ws GLUS40AM }— CHUGACH BLECIRIC? BU 72695204;# 2/ 3 CHUGACH ELECTRIC ASSOCIATION, Ic. Anchorage, Alaska March 23, 1993 T01 Rélaying Reliability Subcommittee he FROM: David W. Burlingame, Manager, Power contra 7 SUBJECT: stevens Bubstation Chugach has reviewed the proposal from MEA and has thé following concerns/ opinions: Back-to-Back RTU Data - Chugach does not hava any direct experience with any such prescribed syatens, Although wé ordered hardware to install a similar system, it was not installed. Wé understand other utilities concerns on the system’s reliability. We do not beliéve the system as configured will jé¢opardize the operation of the intertia as thé control points aré only operated during system disturbances when either the Intertie is separated or MBA‘’s bypass . bwitch is open. He do believe the failure could lead to book keeping nightmares in terms of tracking wheeling costs and Intértie usage attributed to each utility. We do not bélieve thé proposal jé@opardizes the control of the intertia so long as both controlling partias control off the same data. In réality, prior to the implementation of Douglas as a control point, thé logsées@ on the héavily loaded tie which aré not in anybodies control ar4a constitute a greatér source of error than the MEA load. However, we also understand and agréé that the GVEA RTU at Dougla# was recantly installed to eliminate problems such as these. In summary, we really don't have any strong feelings oné way or the other, MBA has guaranteed to fix any problens with reliability encountered, which i@ moré than other utilities are doing on other issues, yet the station could sét An @xanmplé for future délivery points on the line. One area that avérybody has méantioned but has not addressed is the cost of the RTU/Communication aquipment at Stevéns Sub. As I ‘understand it, MBA i# willing to pay for any upgradés required to multi-port their RTU up to a point, and réquired communications up to some point also. I understand MEA i# not willing to pay for the installation of other utilitie’s RTUs if that is the déesired option. From a systen control point of view, once the tié-line control point is movad to Douglas, wouldn't it ba better to have the information and control be the responsibility of the northern Controller 48 it is within their control aréa? This would eliminate the need for an RTU for the Southern Controller. we ee U-éU-UU LU UKM + U1UUAU ELELIRIC? BU (Z6d0ZUF iF OS Wa aiso believe the Pfs were installed to provide future synchronizing capability and would recomménd they be connected to the same phasé. I baliava all utilities need to réspond to thé cost issue and that avery utility éxcept GVHA has responded to the initial request for information. Chugach beliévés the installation of its own RTU if required if an RTU required to serve its wholesale consumer and to account for all tie points in thé ti@-liné bias mode. Chugach will assume these costs if required. Wea believe the supplying of required communication paths from the 8tavens Sub to a point within the Chugach system or some other point to be the responsibility. of MBA. Pleasa respond to the issue of coa#te and who is to béar what costs ete by March 30, 1993 and we will schedule a méaAting for thé first week of April. 6YVY GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Box 71249, Fairbanks, Alaska 99707-1249, Phone 907-452-1151 May 19, 1993 Ron Garzini Alaska Energy Authority P.O. Box 190869 Anchorage, AK 99519-0869 Subject: GVEA Concerns - Stevens Substation Dear Ron: After review of the Alaska Intertie Agreement (AIA), little guidance has been obtained regarding the operation and incorporation of MEA's proposed Stevens Substation. Golden Valley supports MEA's direct utilization of the Alaska Intertie, and to date, we have worked well with MEA in resolving many issues. What remains are issues which Golden Valley feels would be best coordinated and resolved by the owner of the Alaskan Intertie. There are three issues and one task Golden Valley desires AEA to find resolution to, and accomplish. The final resolution to these issues may lead to other concerns and if necessary, we wish to reserve the right to bring these additional concerns to your attention. MEA ALASKA INTERTIE PARTICIPANT STATUS 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. WHEELING MEA has requested a wheeling rate which is not specified in the contract. What is the appropriate wheeling rate? MITCR Depending on the determination of MEA's participant status, what MITCR arrangement should be allowed for the Steven's load? The load may be served from either north or south, and the final arrangement should allow for MITCR's in each direction. How should MITCR be modified in the event of load growth? GOLDEN VALLEY ELECTRIC ASSOCIATION INC. GVEA Concerns - Stevens Substation May 19, 1993 Page 2 CONTRACT The largest remaining task is amending the Intertie Contract itself. The construction and operation of a substation tapped into the intertie by a non-participant (?) has numerous contract consequences. In the event this request raises significant concern among other participant members, a special called meeting to discuss the Stevens issue in more detail may be appropriate. To date, the members have solved mostly technical issues and have left contractual impacts unaddressed. Golden Valley desires to have all issues, technical and _ contractual, resolved to everyone's satisfaction before energization of Stevens Substation. We would appreciate your support and assistance in meeting this goal. Brodlep Evang Bradley Evans Ioc Chairman cc: IOC Members Afzal Kahn Tom Lovas ‘Tim McConnell’ Sam Matthews Vince Mottola Mike Kelly Steve Haagenson @ ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY 480 WEST TUDOR + ANCHORAGE, ALASKA 99503-6690 = (907) 561-8050 » FAX (907) 561-8998 . ere nN SEP 03 1993 ALASKA ENERSY 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? Mr. Eric Wohlforth, Esq. September 1, 1993 Page Two Additional AEA questions: I. 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, Poe Chey Dennis V. McCrohan, P.E. Deputy Director (Energy) DVM:ec cc: R. Snell, AIDEA 1/1 D. Beardsley, AIDEA 1/0 A. Khan, AEA 1/0 — J. Baldwin, Dept. of Law 1/1 Attachment Ile \ Fae WZ Yi 7 Municipality of Anchomee Municipal Light & Pome ees a 1200 East First Avenue Anchorage, Alaska 99501-1685 Telephone: (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 DATE: December 2, 1993 TOs Brad Evans, Chairman, I0c IOC Representatives FROM: Tim McConnell, IOC Representative, ML&P Subject: Controller Duties Ref. 1 Vince Mattola Letter of October 6, 1993 to I0C Chairman, Same Subject (Attach. 1) Ref. 2 Burlingame/Mottola/Hall Letter of November 9, 1993, "Working Group Recommendations" (Attach. 2) Golden Valley and ML&P are in agreement that a reduction in AEA reimbursable costs for current Intertie Operator duties is apropriate and will lower the cost to $100,000 per operator in the next three years. The reductions will occur over three years in the following increments for each Operator: January-—December 1994 $100,000; Jan-Dec 95 $50,000; Jan-Dec 96 $50,000. As for the recommendations in the two References listed ahove, We will give ML&P's thoughts on the Ten Motions proposed by the Working Group in Reference 2. Our over-riding concern on this issue is however, that the checks and balances (Two Operators when one would be "more efficient", the unanimity clause for modifying the contract and the appeal clause when even one Participant has a visceral concern) built into the Agreement by the framers to discourage cabals or other forms of conflict of interest do not seem important to the Working Group. We conclude from the Group's recommendations that operational efficiency appears to be the cardinal virtue, and mutual trust the given. But when we read the contract again, it is very clear that it wasn't always a perfect world. There are many areas where we agree with the Working Group and we will go through the Motions now one at a time. I Cease all duties other than: 1. Audit the records of the previous year--to ML&P ML&P rasponsa--Could not have a timely impact. Putting Energy into Anchorage for 60 years "1932 - 1992" \ 2 I Cease all duties other than (contd.): 2. Spot check operating reserves ML&P Reaponse--More effective to report all deviations 3. Maintain outage and disturbance data and publish Quarterly Report ML&P Response--Good idea 4. Interconnected utilities would perform deleted duties ML&P Response--Would require changes to many paragraphs in contract, and would eliminate carefully crafted checks and balances II AEA revise budget consistent with Motion I ML&P Response--Not necessary to realign duties to reduce cost TET Only Golden Valley submit its wheeling report for the purpose of Intertie usage ML&P Response--For now, with today's uncomplicated flows, one Operator could prepare the report and the other release it as agreed to by the Operators and the AEA IV GVEA control 138KV equipment at Stevens at no cost to Ioc ML&P Response--Requires contract change and ML&P would be opposed Vv GVEA 8V8 and all equipment at Gold Btation be operated at no cost to Ioc ML&P Response~-May well be within the GVEA cost reduction plan described in paragraph 1 above. VI CEA operate monitor and control ABA equipment at Douglas and Teeland at no control to I0c ML&P Response--Would require a contract change which we would oppose. Further, ML&P has agreed to cost reductions of $200,000 in paragraph 1. operation of the SVC at Teeland may be negotiable however. a VII Intertie loss calculations be performed by CEA MLE&P Response--Would require a contract change which we would oppose; these are part of the checks and balances we feel are important VIII GVEA keep all records of lina outages and all problems affecting restoration as part of its interconnected system ML&P Response--Intertie is part of all Participants interconnected system; Outages and Restoration fall under Operator responsibilities and the Operators should ensure that their respective problems are well documented. ML&P against Motion IX ML&P monitor reserves and report on such to IOC, format and frequency to be determined by Iroc ML&P Rasponse-~Good idea X ML&P establish a data base for all system disturbances and issue reports as directed by the Ioc MLEP Response--Good idea When the IOC meeting is called back into session, we hope the above information will prove helpful HECEIVEBirbanks Municipal OCT 12 1993 DIVISION OF ENEAGY/OCRA TO; BRAD EVANS, IOC CHAIRMAN FROM: SUBJECT: CONTROLLER DUTIES DATE: OCTOBER 6, 1993 The subcommittes was given the task of reviewin Utilitias System VINCE MOTTOLA, SUBCOMMITYEE CHAIRMAN-CONTROLLER DUTIES the charges to the Alaska Intertic by the Northem and Souther Controllers to determine if the duties may be trimmed or streamlined to reduce overall operating costs of the line. The subfommittes met in Anchorage on September 29 to this end. Both the Intertie Agreement ard NERC Guides were checked for duty requirements. It was determined that many of the pr done by any interconnected utility without com; The following descriptions itemize common inter 1: Intortin Scheduling - Thik involveo coordinati gnorgy to insure proper intertie loading. Thi maintain adequate voltage levels. (Since i facilities, they as a utility check this no matt Actual Intertio Operation . Scheduling outage forced oytage, normal operation of intertio directly affected by maintenance, usad to dis! clearances, and vested interest in restoration. Time error correction - Coordination betwoon Opsrate the Intertio Equipment - in accor substation would be oporated by interconnect SVC now not billed by CEA, Teeland SVC free, Douglas could be operated for frea by C Perform All Loss Calculations - required for i this as a wheeling utility, not as the controll | a Monit of the controller.) + Fairbanks, 845 Fifth Avenue » P.O, Box 72215 I. intertice. (It is the responsibility of GVEA and i lines leaving and entering their systems as part of interconnected utilities, not as a duty ntly done and charged duties are routinely tion, ected utility tasks: mn with all affected ulililics for reserves and also includes var scheduling as required to ertie overloading critically affects GVEA r who would officially "control”.) for maintenance, restoration of intertie after quipment. (Task for GVEA as a utility ant operation of system, including tag-out all generating facilities to adjust time error as required, (Task for each utility respectively.) cs with the Intertie Agresment each utility with their other equipment. (Kenai 1 breaker would be operated by CEA for or by "Controller" at no cost to Intertie.) tertie schedules. (GVEA is required to do .) inate = the powor flaws aver ¢ha ineartia wectleta Mee vapabltley of thu CEA to monitor the power flow of the tio laaka 99707-2215 + (807) 459-6000 Subcommittee Meeting-Controllor Dutics October 6, 1993, Page 2 7, Hourly Transaction Maintenance » records accurately all Intertie transactions, operations, and activities involving tho Inteystio. Publish and distribute records showing the daily summary of all hourly transactions to all participants at weekly intervals. (Since this must be performed anyway by the wheoling utility, they should not bo # cost item.) The following items should be done by a "Controller": A. AURITING - is to be done by the Controlleg or the State as specified. (On rotating basis on a frequency requested by the IOC.) B. RESERVE REQUIREMENTS - monitoring for all participants, both spinning and operating reserve with records of actual vs réquired, preparing monthly report to the JOC for review and action as necessary. (Since utilities are doing this anyway, the controller task would be to spot check two to three times daily. Stipulated by IOC would be whether @ tep-of-hour or integration of ten minute demands/generation system is used. The Controller would be rotated at yearly intervals.) c QUTAGE RECORD MAINTENANCE - on|a quarterly basis published to Participants. Keep up a database of why Intertic had an joutage and problems of restoration. (On a rotating basis.) Discussion proceeded that these new task items should cost a small fraction of today's cost, but that the assigned Controllers be requested to present, similar to past Intertio Budget submintals showing hourly and yoarly time by itemized subtask) their costs for Budget amendment. It was further suggested that the State could reduce its oversight costs tremendously with similar transfer of existing duplicating tasks to respective utilities, Wa alsn discuseed the State (AIDBA) involveuséut if io Inicilig, This 1s not a recommendation but rather a report of the subcommittee members pn this issue. It is my feeling that I am © expressing Chugach Electric Association, Matanuska Electric Association, and Fairbanks Municipal Utilities System intention that as far as wo know it will be beneficial to all the Utilities if the State will keep ownership of the Intertie, with) other issues being resolved privately such as: secretarial duties, budget preparation, maintenanre, engineering, and accounting. All these tasks should be privately handled by the Utilitics. As previously stated, this is reported only as discussion and not as recommendation. cc: David Burlingame, CEA Jim Hall, MEA Dennis McCrohan, AIDEA Stan Sieczkowski, AIDEA Afzal Khan, AIDBA November 9, 1993 TO: IoC FROM: David Burlingame, CEA Vince Mottola, FMUS Jim Hall, MEA SUBJECT: Working Group Recommendations Discussion - A working group appointed by the IOC, consisting of three Intertie members met to discuss the operation of the Intertie and to reyiew the methods and duties used by the Controllers in operation of the Intertie. In an effort to operate the intertie in a responsible manner in accordance with Prudent utility Practices as required in section 10.1.4.9 of the Intertie Agreement, the working group recommends the IOC reassess the duties of the Northem & Southem Controllers as outlined below. MOTION - Move that AEA order as outlined in section 10.2.1 of the Alaska Intertie Agreement, the Northern and Southem Controllers to cease performance of all duties except those duties as outlined below: Souther Controller (AML&P) - Audit the records of the utility (The IOC will use the records Golden Valley utilizes for recording the wheeling in its control area) keeping the hourly, weekly and monthly records for the previous year, at intervals and by methods approved and requested by the IOC. Norther/Southern Controller - Perform spot check calculations on utilities reserve requirements and obligations vs their actual reserves by a method and at intervals approved by the IOC. This duty would be rotated on a yearly basis. Norther/Southern Controller - Publish on a quarterly basis all system outages and disturbances affecting the operation of the Intertie. Keep on a computer data base approved by the IOC, all outages, system disturbances, restoration problems etc. This duty would be rotated on a yearly basis. All other duties presently performed by the Controllers would be performed by the interconnected utilities. The change in controller duties shall be effective December 1, 1993. MOTION - Move the AEA, in the best interest of the Intertie as allowed for in section 10.2.2 of the AIA and as required under section 10.1.4.9, establish a scope of operations and budget consistent with the revised controller duties MOTION - In as much as the present format for reporting usage of the Intertie has never been approved by the IOC, move that Golden Valley prepare and submit to the IOC the wheeling reports used in its control area which will be used to report Intertie usage. MOTION - Move that GVEA, in the best interest of the intertie, control and monitor the 138 kV equipment to be installed at Stevens Substation as part of their utility control area at no cost to the other participants. MOTION - Move that Golden Valley, in the best interest of the Intertie, operate, monitor and control the SVS systems and other AEA equipment at Gold Hill and Healy as part of their utility system at no cost to the other participants. MOTION - Move that Chugach Electric, in the best interest of the Intertie, operate, monitor and contro! the AEA equipment at Douglas and Teeland as part of their utility system at no cost to the other participants. MOTION - Move that in the best interest of the Intertie, Golden Valley perform all loss calculations which occur in its Control Area and Chugach Electric perform all loss calculations which occur in its control area due to Intertie transfers at no cost to the other participants. MOTION - Move that Golden Valley keep all records of line outages on the Intertie and all problems effecting its restoration as part of its interconnected system. MOTION - Move that the Southern Controller (AML&P) monitor reserves and issue reports to the Intertie Members. Reserves shall be monitored on a frequency and by a method approved by the IOC. Reports shall be issued in a manner and format approved by the IOC. MOTION - Move that AML&P establish a computer data base approved by the IOC and record all system disturbances on the interconnected system. Reports shall be issued in a manner and in a format approved by the IOC. . MER wer actce Sli \s at Kime vwhuls- ae a 2, St CSW, NY .. pu dobi2 Cer Ud Municipality of Anchorage es Municipal Light Power —oe 1200 East First Avenue Anchorage, Alaska 99501-1685 Telephone: (907) 279-7671, Telecoplers: (907) 263-6204, 277-9272 DATE; December 2, 1993 TOs IoC Representative, Dennis McCrohan, P.E. AIDA/AEA FROM: ML&P, Southern Operator, Alaska Intertie SUBJECT: Proposal for Expediting the Stevens Substation As we are all aware, MEA is seeking a way to bring their Stevens Substation on line before winter sets in. We believe this could be accomplished prudently even though: 1. Some technical details are yet to be completed and 2. Contractual issues have yet to be resolved. Request your support for the motion described below. It may be a workable way to avoid penalizing MEA ratepayers for the current I0c gridlock. In the interest of those MEA customers who would be better served this winter if the station were to come on line early, ML&P will propose the following motion to the I0c: Move that in the interest of MEA'’s ratepayers, the I0c recommend to the Authority that interim approval of the operation of the Stevens Substation be granted (per Paragraph 7.4.2 of the Agreement) on a temporary basis until the contract and technical issues are resolved or until March 31, 1994 whichever occurs first, and under the following prudent utility practices: 1.. During the present period while remote operation of the high side switches and disconnect is not available and: £ the Southern Operator (a Participant). Until AEG&T owns the high side of the tap, MEA manually control the high side le ee a \ tor ated Saisconnect se ached diagram) at the Corer | rater After AEG&T becomes owner of the high side of the tap, MEA i tome control the circuit sw tahees coordinating “their operation with the Northern—and—southern—operators and other Utilities as required. The in line motor “Sperated disconnect will be operated by MEA at the direction of the Southern Operator. yw peo Putting Energy into Anchorage for 60 years "1932 - 1992" u Owrewep 1 | { | } ] WT2?62561 M&F DISPRTCE "1s FG2/64 DEC 63 ’°93 & L ive 2. As soon as remote operation of the high side switches and aisconnect is available (FCC license, RTU's and communication links could be in place as early as December and probably not later than February), and: Until AEG&T owns the high side of the tap, MEA remotely control the high side circuit switches at the direction of the Southern Operator (a Participant). The in line motor operated disconnect will he —_contronled—_and__peestery.. operated by the Southern Operator as authorize 'Y Paragraph 10.1.2 of the Agreement. After AEG&T, owns the high side cf the tap, MEA remotely control the circuit switchers coordinating their operation with the Northern and Southern Operators and other Utilities as required. The in line motor operated disconnect will be controlled and remotely operated by the Southern Operator as authorized by Paragraph 10.1.2 of the Agreement. 3. Intertie metering be accomplished as follows: Before communications are available to transmit meter readings. via RTU's: Stevens schedule is as proposed by David Burlingame/Jim Hall memo to Brad Evans (Attachment 2). MEA read the Stevens meter(s) via modem on an hourly basis and relay to the Southern Operator for verification of Intertie schedule and to utilities as required for energy accounting. Hourly intertie usage equation for power scheduled and wheeled North (PWy) OR South (PWs) and now in use by the Northern and Southern Operators be modified to include a Stevens Substation term: Ww FROM TO aot ah PWy = 1/2[ (H+C) + D] PWy = 1/2[ (D-8) + H+ C) +8 ( , x a PWS = 1/2[ (H-c) +D) PWS = 1/2[ (D-s) +H - Cc) +8 © Where H, C, D, and S are hourly meter readings at Healy, Cantwell, Douglas and stevens respectively. Contract wheeling rate applies to all. After communications are available to transmit meter readings via RTU's, MEA modem readings would be unnecessary. ML&EP believes this motion does minimum violence to the contract, does not harm any participant, and compresses MEA's timetable for improved service at Stevens. Will you support? P.373 SEP @9 '99 82:14PM MATANUSKA ELECTRIC S2IS/STEVENS BARD COFY BASE TIME: O4-aUG-1593 11:50:68 9-SEP-1893 14:86:29 & 13BKY 0C/RENGEE TS DOUGLAS PKU eke-eKKE on $TA 4261 ot oT 1 i wea a eek 0k % ® ™S s ji 2 nen £ Bax crx SOUTH tor | TS HOD $20 +s 190 Amok Arce Swe BrKk. & Bune CuK Coke. & Car NORTH K Wakao & BOT KUARS axa oc VOLTS *em LOCK WT332 POTENTIAL SHITCH ous @ ENGAGEO @ NORTH CIR. FEED 138K TD CANTWELL @ SOUTH CIR. FEED TOG7As py AE WIHSe TA ser cA NAT PAvcAa es AG:cT Sere feeybi Lor bIDFHILn fit res bd vel BS TO CHUGACH ELECTRIC ASSOCIATION, INC. Anchorage, Alaska October 18, 1993 TO; Brad Evans, GVEA FROM: David W, Burlingame, cent Jim Hal}, MEA SUBJECT; Proposed Metering Procedures for Stevens Substation During the time Stevens Substation ig energized, but analog ar pulse readings are not available, it {tp recommended the true-up between GVEA and Chugach be done in the Following manner. Chugach and GVEA will bias there Douglas readings hy 1.5 MW for 24 hra per day, This biag point is inrended te caver fhe load (1.4 MW) to be served at Stevens and the lossea (.03 MW far tig-ling and aa MW far the transformer) on the intertie caused by the Stevens ead, At the end of each month or at the time the Sreyens substation communicatiqng system is implemented, the meters wil] be read and the MWH will be multiplied by 102.5 cto accounce for the actual Stevens Substation load plua che estimated Stevens snberarion losses which occurred on the intertie. This number will he subtracted from the actual Douglas meter reads used to calculare the GVEA actual purchases including meter correction. It ia anticipated thea above system would not be used for longer than two hilling periods. Please adviaa if this is acceptable and we will forward it to other interested parties. Loinu @ COMPANY CONTRACT NO. LZWTEL TLE JJET LAT ERE HMUGE Joe TITLE A ‘oan DESCRIPTION SHEET NO. DATE /Z -J/S — Ve CHECKED BY. BY MADE H~+D,+e>D YC Ho +Drz -@)» STEVENS (4) ae DOUGLAS (Dp) (P20 Pos EP VIET NTER CAAA BE WF umn = @CQ-S. +H, +¢]+5 (UL sore = Vo (WDr-5)+ Ho-c] +5 \ NZ ai Municipality of Anchorage Municipal Light & Power Fone Cm aR 1200 East First Avenue Anchorage, Alaska 99501-1685 Telephone: (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 DATE: November 10, 1993 TOs Brad Evans, IOC Chairman CC: Ioc Representatives py / FROM: Tim McConnell, ML&P IOC Cee al SUBJECT: Stevens Substation Issues In response to your request of July 14, 1993, John Cooley, Jim Hall and I met on July 23, 1993 to consolidate the contractual issues related to activating the Stevens Substation. The references used were the letters listed below and attached: MEA January 11, 1993 letter on communications options for Stevens Substation MEA March 25 letter on technical issues ML&P March 18, 1993 letter listing concerns regarding SCADA communications CEA March 23, 1993 letter of concerns/opinions GVEA May 19, 1993 letter of concerns Issues discussed at the July 23, 1993 meeting, in subsequent meetings and in additional correspondence to date are summarized below: a, MEA is not a participant to the Alaska Intertie Agreement so could not tie in. Resolution of this contractual problem is probable since Jim Hall stated that AEG&T would become the owner of the tap portion of the substation. Putting Energy into Anchorage for 60 years "1932 - 1992" 2. The MEA proposal (March 25 letter) does cover ML&P's contractual requirement to monitor and control the tap and the energy schedule via SCADA. To accomplish this, ML&P will install an RTU in the Stevens Substation in November 1993. Note: ML&P understands Jim Hall's position (Jim Hall September 7, 1993 Operator Duties letter to Chairman IOC) that the Substation should be included in the area operated by the Northern Operator, however paragraphs 10.1.2 and 10.1.3 of the Agreement clearly define the Northern and Southern Boundries. This is not anticipated to be a contractual problem as ML&P’s RTU is scheduled to be fully in operation by November 30, 1993. ObiecL ion yy ced Mo wader (2TU. 3. AEG&T does not have MITCR rights to purchase power from the Southern IOC group. ., IFOUP- NoyoP To avoid a contractual issue the participants could all agree that precedent permits MEA to feed the stevens load from the South since power to this load has long been wheeled to Douglas on the Intertie (as defined by Exhibit A, definition 18 of the Agreement). Also, the bi-directional nature of MITCR, is clearly stated in paragraph 7.1.2 of the Agreement although Exhibit D of the Agreement does not make it clear how this would happen. Ar Wheeling charge, as proposed in MEA's March 25, 1993 letter, would have been a contractual issue if based upon MWH/Mile. Jim Hall has stated that MEA will pay the contract wheeling rate to avoid a contractual issue. The group (Jim Hall, John Cooley, and I) did not identify any other issues thought to be contractual in nature. However, AIDEA has yet to present the reply of its counsel to contractual issues raised by Dennis McCrohan in his September 1, 1993 letter (Attached). Interim and technical issues remain, of course, as discussed and assigned in the September 8, 1993 IOC meeting. 6 Attachments, Cited above. a> Matanuska Electric G Association, Inc. P.O. Box 2929 Palmer, Alaska 99645 Telephone: (907) 745-3231 Fax: (907) 745-9328 January 11, 1993 Larry Hembree : Intertie Operating Committee Anchorage Municipal Light and Power 1200 East First Avenue Anchorage, AK 99501 Dear Larry: This letter is to discuss communication options for the Matanuska Electric Association, Inc. (MEA) Stevens Substation. This substation will tap the Intertie near Talkeetna. Permission for MEA to install this facility is contingent on a number of items to be addressed by the appropriate subcommittees of the Intertie Operating Committee. MEA has offered to provide communication channels between the MEA Douglas Substation and the MEA Stevens Substation. These channels were to be provided to any utility who needed them, and at no charge. MEA made this offer based on the installation of a microwave link between Douglas and Stevens. We believed that such a direct link could be installed. Further investigation has shown that such a link would require towers in excess of 200 feet in height at both ends or that an intermediate site with two links be used. Either of these options substantially change the scope of the project and result in budget problems. We offer, for your consideration, an alternative that we believe will meet the needs of the utilities without the installation of the microwave link. MEA would install two 960 megahertz radio links from a high site near Douglas to the Stevens substation. These links would provide communication for an MEA RTU at Stevens, and for a dial up phone line to Stevens. MEA would use its Douglas RTU to emulate both analog and ulse data on the Stevens load. This data would be available to any utility that wanted it. Further, MEA would configure the Douglas RTU to provide the Southern Area Controller the control of the high side devices at Stevens. As previously discussed, this would mean that the southern area controller would have exclusive control of the in-line motor operated disconnect switch at all times and exclusive control of the S&C series 2000 circuit switchers when the in-line motor operated disconnect switch was in the open position. Position indication on both the in-line motor operated disconnect switch and the series 2000 circuit switcher would also be available to any utility who wanted it. fiteftid Opérating Committee Members Page 2 January U, 1993 vet) Such att atrangernent hag advantages and disadvantages. A cleat advantage is that it oi). + would @liminate the fi¢ed fot installation and maintenance of an additional RTU at ». Stevens by these whd desité to teceive data: Status indicatiott of thé devices at Stevens ¥" would Ge delayéd by 48 tnuch 48 thirty secotids due to the scat rate of thé MEA SCADA “gystetil: Sitidd these devices aré tot used for liné télaying, this does tiot seett * Ufeasofiabla: ° Pulse data ffom the RTU would be litiited to A pulse faté of about otié a ie por frintite. Thid is eit dué to.thée scah tate of the MEA system. Selection of wees ove thé Metering equipment at Stevens can sssufé A Pulse Fate of ALSUE BAG Per finite for Sage nofitial peak load. “This edtild fesuit in a rhte Bf PsFhAps One pulsé it fouF mintites at avery light: load, * Afialog load ififormation éaf be provided éithét ofl a 4 through 20 a amip Basis, OF On Another base through thé sé of A trati&duicét. Ag fat 48 teliability is Gonéarfied/ the MEA SCADA system has been very féliable With, perhaps, one RTU wed” Fallee Ba year fot twetity RTUS and abdut fe systéft bf Goftittiutication failure pet wun! year. “These até typically repaired in one Of to days. MEA gives tainténaricé of its ZOCADA syste High pridtity atid this systeth Would bé an iintegtal part of thé MEA ; gral pi =! SCADA systefi. “The dial up phone line wottld bé Used fot intetrogation of thé pulse ~, £OCOFdEFS At Stevens by CEA arid MBA for wholésale billing purposes and by the Intertie . Cotitrollers fof true-up of schedules. ory eT / ’ . . We believe that this systett could provide the tecessary infottiation in 4 vety sable fori afd at a Feasottablé cost to all concerned. If you have ary questiotis tegarding this System please cohtact tne. Your consideration of this systeri is appreciated. incerély, ) ays Jatiiés D. Hall- Staff Engineér- SS BDBSOIDIP oe Rg Association, Inc. S j Matanuska Electric P.O. Box 2929 Palmer, Alaska 99645 Telephone: (907) 745-3231 Fax: (907) 745-9328 March 25, 1993 Mr. Brad Evans Chairman, Intertie Operating Committee clo Golden Valley Electric Association, Inc. (GVEA) P. O. Box 71249 Fairbanks, AK 99707 Dear Brad: SUBJECT: STEVENS SUBSTATION TECHNICAL ISSUES Alaska Energy Authority (AEA) in their letter approving the Stevens Substation tap of the Anchorage-Fairbanks Intertie listed a number of technical and contractual issues. These issues were identified by the Intertie Operating Committee (IOC) in their motion approving the tap. This letter will state Matanuska Electric Association’s (MEA) intended resolution of each of the issues. The issues identified are as follows: Operating procedures Review of Final Design Construction Practices and Schedules SCADA control SCADA microwave communications Control area load following/tieline bias metering control point MITCR ramifications Contract compliance Payment eee eo eo eo oe 4 Operating sproced ures - We intend to operate the 24.9 KV distribution side of this station in the same manner as we would any distribution station on our system. Automatic reclosing will be used on feeder breakers, and feeder breakers will typically ee ee or closed as needed for proper operation of our system without notice to other utilities. Operation of the 138 KV side of the station will be performed by the appropriate controller for the control area that the station is located within. If omaitel operations are required on the 138 KV side of the station, they will be performed by MEA personnel under the direction of the appropriate area controller. + Review of Final Design - A complete set of design drawings will be made available for review prior to the May IOC meeting. Their have been no changes in the design since the preliminary drawings were presented to the IOC. Y STEVENS SUBSTATION TECHNICAL ISSUES Page 3 March 25, 1993 ¢+SCADA Microwave communications - We have offered to provide a six channel 960 megahertz link from Douglas to Stevens. We will connect this link to the multiport RTU and individual RTUs at Stevens if requested to do so. We do not intend to connect to the existing communication systems at the Douglas end, because these are active systems, and we are not in the best position to coordinate the work. ¢Control area load following / tieline bias metering control point - Stevens is located within the GVEA control area, and as such, pulse information must be available to GVEA for control purposes. CEA is our wholesale supplier, and as such, they must provide load following for the Stevens load. In order to provide this, and to roperly operate their control area, CEA must receive pulse information from Stevens. e intend to provide pulse information as required to fuifii these needs. ¢+MITCR ramifications - MEA will attempt to identify the effect of the relocation of the actual load of the Stevens Substation from Douglas to Stevens. If a reduction in intertie capacity can be identified, and if it is sufficient to require a reduction in maximum south to north transfers, then MEA will negotiate in good faith to obtain the necessary MITCR from one of the northern utilities. Unused capacity is always available to other participants; therefore the only time that MEA should required to purchase MITCR is when the entire capacity of the line is scheduled for use. ¢+Contract compliance - MEA intends to comply with the Alaska Intertie Agreement to which it is signatory through Alaska Electric Generation and Transmission. Payment - MEA anticipates payment of wheeling charges in the same manner as other utilities under the terms of the agreement. The amount of this payment would be prorated to reflect the actual amount of the line used. We believe a 26/175 share would be an equitable approach because it represents the portion of the line used on a milage basis. Sincerely, tm Ole James D. Hall Staff Engineer EDES.658 __. cc: og : Sam Matthews Anchorage Municipal Light & Power Homer Electric Association 1200 East First Avenue 3977 Lake Street - Anchorage, AK 99501 Homer, AK 99603 Tom Lovas WY =. \ Municipality of Anchorage Municipal Light & Power TomiFink, Mayor 1200 East First Avenue Anchorage, Alaska 99501-1685 18 March 1993 Telephone: (907) 279-7671, Telecopiers: (907) 263-5204, 277-9272 David Burlingame, Chairman Kee Intertie Operating Committee\, QR c/o Chugach Electric Association P.O. Box 196330 Anchorage, Alaska 99519-6300 Dear Mr. Chairman: Municipal Light and Power has serious reservations with regard to the MEA SCADA communications to the new Stevens Substation. We understand that MEA is ready to remedy problems with the proposed system to the satisfaction of the Reliability Subcommittee. The difficulty arises from the fact that the proposed system has not been engineered at this point. Unsatisfactory performance could jeopardize the reliable sales of power over the tie line. We request MEA complete further studies on transmission path availability and alternatives to the 960 Mhz communications system which they propose. Our preference for communication is the existing DivCom State owned microwave system. To save on installation costs of a new RTU at Stevens for the southern controller, we would like to explore the possibility of having the MEA RTU serve multiple masters. The cost of the protocol emulation would be weighed against the cost of a ML&P RTU in the Substation, and its space requirements. ML&P requires control and indication of the MOD switch and circuit switchers, as well as metering data for the Stevens load. We are providing you with the following list of points that would be needed. KwH pulses for the Stevens load. Kw & Kvar analog (+/- 1 ma.) for Stevens load. Circuit Switcher status ("a" contact) for both circuit switchers. MOD status ("a" contact). Voltage relay contacts for north and south lines. Local/Remote control switch position indication, circuit switchers and MOD control switchers. Voltage transducers for north and south lines. * Communication failure alarm. Battery charger failure alarm. 0. Control of MOD and circuit switchers. aa IVE * We suggest that P.T. replacement for the two line P.T.'s be on different phases to give dispatchers the best picture of system conditions. = $ @-4”~ 4. 4 ores Larry bree Station Design Supervisor, ML&P ' Putting Energy into Anchorage for 60 years "1932 - 1992" Sees SASS * OUI bie 4-Y9-US FLU 40AM 5 CHUGACH ELECIRIC+ 90 72635204;# 2/ 3 CHUGACH ELECTRIC ASSOCIATION, Inc. Anchorage, Alaska March 23, 1993 TO. Réalaying Reliability Subcommittee Ze FROM: David W. Burlingame, Hanager, Power contre? BUBJECT: stevens Bubstation Chugach has reviewed the proposal from MEA and has thé following concerns/ opinions: Back-to-Back RTU Data - Chugach doas not havé any direct experience with any such prescribed systens, Although wé ordered hardware to install a similar system, it was not installed. Wé understand other utilities concerns on the system’s reliability. We do not believe the system as configured will jeopardize the operation of the intertie as thé control points aré only operated during system disturbances when 4ithér the Intertie is separated or MBA‘’s bypass . bwitch is open. We do believe the failure could léad to book keeping nightmares in terms of tracking wheeling costs and Intértie usage attributed to each utility. We do not bélieve thé proposal jéopardizes the control of the intertie so long as both controlling partias control off the same data. In ré@Ality, prior to the implementation of Douglas as a control point, thé loanes& on the héavily loaded tie which aré not in anybodies control ar4a constituté a greatér source of error than thea MEA load. Howaver, we also understand and agréé that the GVEA RTU at Douglas wae recently installed to eliminate problems such as these. In summary, we really don’t have any strong feelings oné way or the other, MBA has guaranteed to fix any problens with reliability encountéréd, which ia moré than other utilities are doing on other issues, yet the station could sét An exanpléa for future delivery points on the line. One area that avérybody has mantioned but has not addressed is the cost of thé RTU/Comnmunication é¢equipment at Stevéns Sub. As I ‘understand it, MBA i8 willing to pay for any upgradés required to multi-port their RTU up to a point, and réquired communications up to some point also. I understand MEA ig not willing to pay for the installation of other utilitie’s RTUs if that is the desired option. From a systen control point of view, once the tié-line control point is moved to Douglas, wouldn’t it bé battér to have the information and control be the responsibility of the northern Controller 48 it is Within their control aréa? This would eliminate the need for an RTU for the Southern Controller. U-éU-UU rus tum > UIUUALIT ELEUIRIC? YU(Z0d0ZU4F D/A We also believe thé PTs were installed to provide future synchronizing capability and would recomménd they be connected to the same phase. I beliave all utilities need to respond to thé cost issué and that every utility except GVHA has responded to the initial request for infornation. Chugach beliévés the installation of its own RTU if required if an RTU required to serve its wholesale consumer and to account for all tie points in the ti@-liné bias mode. Chugach will assume these costs if required. We believé the supplying of required communication paths from the 8tavens Sub to a point within the Chugach system or some other point to be the responsibility. of MBA. Pléeasa respond to the isaue of co#te and who is to béar what costs ete by March 30, 1993 and we will schedule a méAting for thé first week of April. GY GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Box 71249, Fairbanks, Alaska 99707-1249, Phone 907-452-1151 May 19, 1993 Ron Garzini Alaska Energy Authority P.O. Box 190869 Anchorage, AK 99519-0869 Subject: GVEA Concerns - Stevens Substation Dear Ron: After review of the Alaska Intertie Agreement (AIA), little guidance has been obtained regarding the operation and incorporation of MEA's proposed Stevens Substation. Golden Valley supports MEA's direct utilization of the Alaska Intertie, and to date, we have worked well with MEA in resolving many issues. What remains are issues which Golden Valley feels would be best coordinated and resolved by the owner of the Alaskan Intertie. There are three issues and one task Golden Valley desires AEA to find resolution to, and accomplish. The final resolution to these issues may lead to other concerns and if necessary, we wish to reserve the right to bring these additional concerns to your attention. MEA ALASKA INTERTIE PARTICIPANT STATUS 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. WHEELING MEA has requested a wheeling rate which is not specified in the contract. What is the appropriate wheeling rate? MITCR Depending on the determination of MEA's participant status, what MITCR arrangement should be allowed for the Steven's load? The load may be served from either north or south, and the final arrangement should allow for MITCR's in each direction. How should MITCR be modified in the event of load growth? GOLDEN VALLEY ELECTRIC ASSOCIATION INC. GVEA Concerns - Stevens Substation May 19, 1993 Page 2 CONTRACT The largest remaining task is amending the Intertie Contract itself. The construction and operation of a substation tapped into the intertie by a non-participant (?) has numerous contract consequences. In the event this request raises significant concern among other participant members, a special called meeting to discuss the Stevens issue in more detail may be appropriate. To date, the members have solved mostly technical issues and have left contractual impacts unaddressed. Golden Valley desires to have all issues, technical and contractual, resolved to everyone's satisfaction before energization of Stevens Substation. We would appreciate your support and assistance in meeting this goal. Bradley Evang Bradley Evans Ioc Chairman cc: IOC Members Afzal Kahn Tom Lovas ‘tim McConnell’ Sam Matthews Vince Mottola Mike Kelly Steve Haagenson @ ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY 480 WEST TUDOR * ANCHORAGE, ALASKA 99503-6690 - (907) 561-8050 » FAX (907) 561-8998 . ‘wen SEP 03 1993 ALASKA ENERSY 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? Mr. Eric Wohlforth, Esq. September 1, 1993 Page Two Additional AEA questions: 1. 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, Pan. Gwhon Dennis V. McCrohan, P.E. Deputy Director (Energy) DVM:ec cc: R. Snell, AIDEA 1/1 D. Beardsley, AIDEA 1/0 A. Khan, AEA 1/0 — J. Baldwin, Dept. of Law 1/1 Attachment