ML20133F896
| ML20133F896 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon, Humboldt Bay |
| Issue date: | 01/09/1997 |
| From: | Allan R DUNCAN, WEINBERG, MILLER & PEMBROKE, P.C. (FORMERLY |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| Shared Package | |
| ML20133F876 | List: |
| References | |
| NUDOCS 9701150059 | |
| Download: ML20133F896 (506) | |
Text
{{#Wiki_filter:_ m_ _ _ . . _ ._... . .. - _ _-.-. _ -.. _ .- _..- - . --- -..--- - - - ~ . q % ,,/ K 9 A u % ,t s 2 4 bsAuACC L. DUNCAN EDWAT.O WCINSCRO (1913-49963 SUlTE 8OO M '-' N N DUNCAN, WCINSCRG, MILLER & PEMBROKE, P.C. sAMcao.pcMoRonC 1615 M STR EET, N. W. 1500 STANDARD PLAZA -
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KOIERT WEINSERO WASHINGTON D. C.2O036 PORTLAND, OREGON 97204
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JANICC L. LOWER (sO3)3457343 JEFFREY C. GENZER (202)467-6370 THOM/J L. RU BUSCH T ELECOPY (202) 467-6379 eaO McCANDLESS TOWERS ' SANTA C FORN 5054 (4041944-4404 , SARRY F. MGCARTHY c g, pg '
' M/JtOLD M. MGCOMBS, JR. 3700 BELLEVUE AVENUE TER3Y E. SINGER SYRACUSE, NEW YORK 13219 ,
(315)476-s318 1 11 ADMITTED IN WA ONLY THOMAS J. LYNCH
- . Ao iVTED iN NY MA . CT January 9,1997 , , , , , , , ,
BY HAND United States Nuclear Regulatory Commission Washington, DC 20555-0001 ATTN: Docket Control Department
SUBJECT:
CORPORATE RESTRUCTURING OF PACIFIC GAS AND ELECTRIC L COMPANY i
Dear Sirs:
This is in response to the Nuclear Regulatory Commission's letter of December 6,1996, received on December 10, to the Transmission Agency of N'orthern i California (TANC) and the Modesto Irrigation District (MID), requesting further i-information about Pacific Gas and Electric Company's (PG&E) violations of the i j conditions ofits nuclear licenses designed to promote and protect competition in the bulk power' market in Northern and Central California. TANC and MID called these t i
- violations to the Commission's attention in connection with PG&E's application to j- transfer certain licenses which are subject to the Commission's jurisdiction incident to a l- 9701150059 970109 PDR ADOCK 05000133 4
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- proposed restructuring of the Company. This response is on behalf of MID. TANC is responding separately saying that, while it fully supports MID's charges of i.
3 anticompetitive conduct against PG&E, it has little to add on its own account to the 1 comments it submitted on April 29,1996. In 1971, in connection with PG&E's application for a license to construct i-the then proposed Mendocino Power Plant, the Department of Justice advised the l Commission that certain conduct of PG&E designed to foreclose the development of i ! alternative bulk power supply sources in Northern and Central California had created a i l situation inconsistent with the antitrust laws and that the construction and operation of the 4 Mendocino Plant by PG&E would likely maintain the anticompetitive situation. See L l Pacific Gas and Electric Co., NRC Docket No. P-564-A,41 Fed. Reg. 20225 (May 17, - l 1976)(Receipt of Attorney General's Advice). Although PG&E subsequently withdrew .
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- the Mendocino application, the Department of Justice commenced a comprehensive i investigation of PG&E's activities with a view to instituting an antitrust action in district coun. Id.
Following another letter of advice to the Commission in November,1975, i i relative to PG&E's application to participate in the San Joaquin Nuclear Project, the ! Depadment of Justice and PG&E entered into negotiations involving PG&E's application j' . for a' license to construct the Stanislaus Nuclear Project and the antitrust concerns raised p ! by PG&E's activities affecting alternative bulk power supply sources in Northern and i Central California. Id. at 20226. I f 1'
As a result of these negotiations, PG&E issued a Statement of Commitments (Stanislaus Commitments), which the Department of Justice believed, if complied with, would obviate the antitrust problems posed by PG&E's activities and remedy the situation the Department deemed to be inconsistent with the antitrust laws that had been created by PG&E in Northern and Central California. Id. PG&E agreed to-the incorporation of the Statement of Commitments as conditions of the license for the Stanislaus Project. Id. The Department of Justice stated: In our opinion, the effectuation of the Commitments will moot the questions of anticompetitive conduct by PG&E which have come to our attention. . The implementation of these policies should provide competitors of[PG&E] with , reasonable opportunities to develop competitive bulk power supply sources. Id. The concern of the Department of Justice that precipitated the Stanislaus
' Commitments was precisely that PG&E was monopolizing the bulk power market in its service territory. The restoration and promotion of competition in this market was precisely the reason the Department insisted on conditioning PG&E's nuclear licenses on the commitments.
The primary and essential condition imposed by the Stanislaus Commitments is: [PG&E] shall not unreasonably refuse to interconnect and operate normally in parallel with any Neighboring Entity, or to interconnect with any Neighboring Distribution System.
' PG&E subsequently agreed to the inclusion of the commitments as conditions of the license to construct the Diablo Canyon Nuclear Plant.
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Id. i
" Neighboring Entity" and " Neighboring Distribution System" are defined, respectively, as:
[A] financially responsible private or public entity or ! lawful association thereof owning, or contractually controlling or operating, or in good faith proposing to own, to contractually control or to operate facilities for the generation, or transmission at 60 kilovolts or above, of electric power which meets each of the following criteria: (1) its existing or proposed facilities are or will be technically feasible of direct interconnection with those of [PG&E]; (2) all or part ofits existing or proposed facilities are or will be located within the Service Area;2 (3)its primary purpose for owning, contractually controlling or operating generation facilities is to sell in the Service Area the power generated; and (4) it is, or upon commencement of operations will be, a public utility regulated under applicable state law or the Federal Power Act, or exempted from regulation by virtue of the fact the it is a federal, state, municipal or other public entity; and n [A] financially responsible private or public entity which engages, or in good faith proposes to engage, in the i distribution of electric power at retail and which meets each 1 of the criteria numbered (1), (2), and (4) [] above. j
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2d. MID is an irrigation district organized and operated under the laws of the State of California. It is a public agency, a municipality under 3(7) of the Federal Power Act (FPA),16 U.S.C., f 796(7), and an electric utility under 3(22) of the FPA, 2 " Service Area"is defined as-that area within the exterior geographic boundaries of the several areas electrically served at retail, now or in the future, by [PG&E], and those areas in Northern and Central California adjacent thereto.
16 U.S.C., 796(22). Among other things,.MID owns and operates facilities for the generation, transmission, and distribution of electric power and energy and provides 1 i
- electric service at wholesale and retail to customers in Stanislaus and Tuolumne Counties.
i MID has engaged in the supply of electric power and energy since 1923. It currently serves over 89,000 customers with a peak load of over 500 megawatts. As more fully 4 i discussed below, upon securing the necessary interconnection with PG&E at MID's p. Linde Substation, which PG&E is attempting to deny, MID will commence providing l i retail electric service to customers in the City of Pittsburg, California, wii h is located in l Contra Costa Cobnty. j The authority under which MID and other irrigation districts provide l electric service is provided by Sections 22115 through 22124 of the CaliDrnia Water !O d Code. Under Section 22115 of the Code, irrigation districts may: ? [P]urchase or lease electric power from any agency or entity, l public or private, and may provide for the acquisition, j operation, leasing, and control of plants for the generation, j transmission, distribution, sale, and lease of electric power,- ! including sale to municipalities, public utility districts, or ( , persons. Section 22120 authorizes an irrigation district to " sell, dispose of, and distribute electric power for use outside ofits boundaries." [
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4 While irrigetion districts are subject to certain specific limitations on 1 outside electricity sales,' none of these restrictions applies to the service MID proposes to } J
$ See, e.g., California Water Code Section 22122 (electric power generation subject to certain i O" existing municipal appropriatinns); Section 22123 (district subject to local regulations, no different rates without consent); Section 22124 (compliance with Public Utility Code PCB use restrictions).
I
J provide from its Linde Substation in Pittsburg. MID proposes to purchase power at wholesale from a power marketer, Destec Power Services, Inc. (Destec), to be delivered by Destec over PG&E's lines to the Linde Substation from which MID will sell and l distribute it at retail to various customers pursuant to authority that irrigation districts i ! have had since 1919/ The right ofirrigation districts, including MID, to provide electric l 1 [ service throughout the State of California, including PG tE's service territory, was established even before the California Public Utilities Commission granted PG&E (or its predecessor) authority to provide service in the area. I The promotion of competition is a principal purpose of the Legislature in l granting irrigation districts the authority to provide electric service throughout the State of l California without reference to their geographic boundaries. The continued existence of l such authority is not attributable to legislative neglect or oversight. Indeed, on at least four occasions, the Legislature has considered and refused to approve proposals to limit l the authority ofirrigation districts or the geographic areas in which they may compete for 1 l and serve electric customers / 4 d See Act of May 21,1919, ch. 370, i 1,1919 Cal. Stat. 778. For a discussion of the Act's history and constitutionality, see Nev-Cal Electric Securities Co. v. ImperialIrr. Dist., 85 F.2d 886 (9th Cir.1936), cert. denied,300 U.S. 662 (1937). i 5 In fact the Legislature's revisits of the subject resulted in expanding the authority ofirrigation districts. In 1923, for example, the Legislature explicitly authorized irrigation districts to sell power outside of their territorial boundaries: [N]othing in [the California Irrigation District Act] shall be so construed as j to prevent the sale of power by any irrigation district for use outside of the
- boundaries of such district or to require the distribution of such power in accordance with any assessments levied by such district.
Act of June 2,1923, ch. 300, f 1,1923 Cal. Stat. 629-630. r~-- -- , - -.
i MID is a " Neighboring Entity" and a " Neighboring Distribution System"
.O U within the intendment of the conditions of PG&E's nuclear licenses that is authorized, i under California law, to provide electric service to customers anywhere in the state. The proposed purchase by MID of bulk power from Destec for delivery over PG&E's lines to l MID's Linde Substation at Pit'sburg t for resale by MID to Praxair, Inc. and other retail customers is precisely the kind of transaction that the conditions of PG&E's nuclear [
iicenses incorporating the Stanislaus Commitments are designed and intended to promote. Prior to the formulation of the commitments and their inciusion as conditions in PG&E's nuclear licenses, the Department of Justice had concluded that certain activities of PG&E to foreclose the development of bulk power supply sources in i
. Northern and Central California, which the Department described to the Commission, .
were in violation of the antitrust laws. 41 Fed. Reg..at 20225. The commitments were , designed for the express purpose of remedying PG&E's anticompetitive conduct and the Department intended the implementation of the commitments to " provide competitors of [PG&E] with reasonable opportunities to develop competitive bulk power supply sources." Id. at 20226. I'n short, the express objective of the Stanislaus Commitments and their incorporation as conditions of the licenses was ta proscribe precisely the kind of conduct The authority ofirrigation districts to sell electric power anywhere in the state has remained essentially unchanged since 1923. In 1941, the Legislature specifically expanded the rights ofirrigation districts to obtain power for resale. Act of May 24,1941, ch. 345,1941 Cal. Stat. 1600-1601. And,in 1943, it recodified the laws relating to irrigation districts into the current California Water Code sections I which, among other things, authorize irrigation districts to obtain and resell power throughout the State of California. Act of May 13,1943, ch. 372,1943 Cal. Stat.1897.
in which PG&E is now engaging to prevent MID from providing service to Praxair, Inc. d and other customers in Pittsburg. Destec is a power marketer and a public utility within the meaning of the Section 201(e) of the Federal Power Act,16 U.S.C. 824(e). Destec purchases power in bulk from various generators, aggregates it, and resells it at wholesale to other utilities pursuant to a rate schedule on file with the Federal Energy Regulatory Commission. - Destec's wholesale customers, in turn, supply power to consumers at retail. Destec and PG&E are parties to a Control Area and Transmission Service Agreement (CATSA) entered into on November 29,1994, Exhibit A herewith, under which PG&E is required
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to provide firm transmission service to Destec to enable Destec to deliver the power that it purchases from various generators to its wholesale customers. See Pacific Gas and Elec. 'Co., 71 FERC 161,045 (1995).~ MID has contracted to acquire the Linde Substation and related facilities in Pittsburg, California from Praxair, Inc. for the purpose of providing electric service at retail to Praxair and other consumers in Pittsburg. Praxair is a producer of manufactured gas products and an interruptible industrial retail customer of PG&E. It receives all ofits l electric service through the Linde Substation, which is connected to PG&E's transmission system by a tap of the Columbia Steel Line. Praxair had agreed to purchase its total requirements of power from MID commencing on August 1,1996. Physically, the Linde Substation is currently interconnected with PG&E and is used by PG&.E to deliver power ; to Praxair. The interconnection sought by MID will not entail any physical changes or O
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- construction of new facilities or expenditures of any kind by PG&E.6 MID's maximum O
O demand for power at the substation is within the capability of the current interconnection i f and the proposed interconnection (to accommodate the change in ownership of the i . . . substation and related facilities from Praxair to MID) will not impair the reliability of
' PG&E's electric system, require PG&E to add facilities, or affect PG&E's ability to serve its remaining load. See Affidavit of Christopher J. Mayer, Exhibit B herewith,113 and 4.
3 To facilitate the service that it intends to provide to Praxair and other retail i consumers in Pittsburg, MID entered into a wholesale Power Sales Agreement with ! f i Destec. Under this agreement, Exhibit C herewith, Destec was to have commenced the l delivery of power at wholesale on August 1,1996, at rates which would enable MID to provide service to Praxair and other customers in Pittsburg on terms substantially more favorable than those afforded by PG&E. See Mayer Aff., Exhibit B herewith,16. ! To ensure that it met all local requirements to engage in the sale and i
- distribution of electric power and energy in the City of Pittsburg, MID entered into a i Permission Agreement with the City. Exhibit D herewith. Under this agreement, the l City not only grants all necessary local authority to permit MID to engage in the retail i' electric business in the City, but positively encourages MID to do so.
[ l l !I
- MID has agreed and plans to upgrade and improve the substation and related facilities. To date, based on its agreements with Praxair and Destec and on the receipt of formal permission from the City of Pittsburg to provide electric service therein, MID has already invested over $100,000 in improvements to the i substation and proposes to make more in the future. These improvements will be strictly at the expense of
]g MID and will permit MID to extend service to other consumers in the Pittsburg area, many of whom have
[' applied for service from MID. i 4 y , , , , - , , . - . - - - - - , . - , - - n .
By letter dated January 29,1996, Exhibit E herewith, MID requested that PG&E enter into an interconnection agreement with MID to establish the terms and i conditions for the interconnection of their electric systems at MID's Linde Substation. ,
- MID submitted a draft agreement to PG&E closely patterned on the interconnection
- agreement between PG&E and the Port of Oakland under which their electric systems are 1
! interconnected.7 Destec delivers power to the Pon of Oakland over PG&E's lines I i '1 pursuant to the Control Area and Transmission Service Agreement between PG&E and Destec for resale by the Port to its retail customers. l 1 By letter of January 30,1996, Exhibit F herewith, Destec requested , transmission service under the CATSA from PG&E to deliver power to MID at Linde l i $ Substation in accordance with the Power Sales Agreement, Exhibit C herewith, between l .MID and Destec. On February 9, PG&E responded severally to MID's request for an 3 l interconnection agreement, Exhibit G herewith, and to Destec's request for transmission service under the CATSA, Exhibit H herewith, by posing questions and raising issues. i By letters dated February 16 and 21,1996, Exhibits I and J herewith, Destec and MID, l respectively, fully responded to PG&E. On February 26, PG&E formally denied
- 4 Destec's request for service under the CATSA, Exhibit K herewith, and commenced an ;
l action in the United States District Court for the Northern District of California for a [ declaratoryjudgment that its breach of the CATSA was not subject to resolution under !4
' The interconnection agreement between PG&E and the Port of Oakland was submitted by PG&E and accepted for filing by FERC in fact /ic Gas and Elec. Co., FERC Docket No. ER96-240-000.
5 7
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4
. the mandatory and exclusive arbitration provisions thereof. Pacific Gas and Elec. Co. v.
j Destec Power Services, Inc., Civil Action No. C96-0711. On February 28,1996, PG&E tendered a Petition for a Declaratory Order to i FERC seeking a determination that it is not obligated to interconnect and provide - t
- transmission service in connection with MID's purchase of wholesale power from Destec l
l and MID's resale of the power to Praxair and other retail customers in Pittsburg. Pacific i Gas and Elec Co., FERC Docket No. EL96-37-000. PG&E having made it unmistakably l i
- clear that it will not voluntarily interconnect with MID at Linde Substation to permit MID l j to serve customers in Pittsburg, MID submitted an application, on March 26,1996, to FERC for an order requiring PG&E to interconnect with MID at the Linde Substation. l
\
l l Modesto irrigation District, FERC Docket No. EL96-45-000.* i O i V FERC has taken no action on PG&E's Petition for a Declaratory Order, l MID's response thereto, or to MID's Application for an Interconnection Order. )' The principal sophism put forward by PG&E for refusing to interconnect l with MID at Linde is that the service MID proposes to provide to retail customers in Pittsburg would entail retail wheeling for Destec. This is transparent nonsense since it is , i MID, not Destec, that will supplant PG&E as the provider of retail electric service to the L consumers in Pittsburg (at their request) and that will have the utility responsibility to l serve them. Except by one bent on avoiding its obligations under the Stanislaus Commitments, the Power Sales Agreement between MID and Destec, Exhibit C herewith, 4
-O Q 8 In response to PG&E's petition for a declaratory order, MID filed a timely alternative motion to intervene, etc., or to consolidate PG&E's petition with MID's application for an interconnection order.
4 r-, _ _ -
is incapable of being construed as' masking a sale by Destec to the retail customers of PG&E in Pittsburg using MID as a straw man. I Although the focus here is on PG&E's breach of the conditions ofits , nuclear licenses stemming from the Stanislaus Commitments, it is beyond legitimate dispute that, under the plain language of Section 212(h) of the Federal Power Act,16 U.S.C. 824k(h), MID is entitled to transmission service because it is irrefutably an agency of the State that will utilize transmission or distribution facilities that it owns or l controls, i.e., the Linde Substation and related facilities, to deliver all the energy i i purchased from Destec transmitted by PG&E? l That PG&E knows full well that, under the plain language of Section
' 212(h) of the FPA, there is no way that the interconnection at Linde sought by MID and the transmission service requested by Destec under the CATSA to serve MID at Linde can be construed as retail wheeling or a sham wholesale transaction, is evidenced by the 4
i 4
- Section 212(h) provides:
(h) Prohibition on mandatory retail wheeling and sham wholesale i transactions ! No order issued under this Act shall be conditioned upon or require the , transmission of electric energy: (1) directly to an ultimate consumer, or j (2) to, or for the benefit of, an entity if such electric energy would i be sold by such entity directly to an ultimate consumer, unless: , (A) such entity is . . a State or any political subdivision of a State (or any agency, authority, or instrumentality of a State or a political subdivision) . . ; and p (B) such entity . . . would utilize transmission or
- i distribution facilities that it owns or controls to deliver all j such energy to such electric consumer.
ll '
proposed amendment of the CATSA that PG&E tendered for filing at FERC on October 31,1996. Following the tender by PG&E ofits Petition for a Declaratory Order and the submission of MID's response to the petition and MID's Application for for an . l Interconnection Order, PG&E engaged MID in discussions of various arrangements under which PG&E might agree, among other things, to MID providing electric service in Pittsburg to Praxair and other retail consumers. While these discussions were ongoing and without word or warning of any kind to MID, PG&E and Destec secretly entered into - a written Settlement Agreement, which they have refused to reveal, whereby they proposed to amend the CATSA specifically to prevent Destec from performing the Power i l Sales Agreement with MID. Exhibit C herewith. The proposed amendment ("Second ; Amendment to Control Area and Transmission Service Agreement between Destec Power Services, Inc. and Pacific Gas and Electric Company"), cover letter, and related ! documents are Exhibit L herewith. FERC noticed the tender of the proposed second amendment to the CATSA in Pacific Gas and Electric Company, FERC Docket No. EL97-320-000. Numbered 12 of PG&E's letter of October 31,1996, under cover of which the proposed second amendment to the CATSA was tendered for filing, states that: O
Section 6.8 [ sic] ' of the CATSA is further amended to _C' - provide that, prior to the Direct Access Implementation Date, , [Destec] may not use service under the CATSA'if[Destec's] sale to a wholesale customer at the Transaction Point is claimed to be of wholesale status on the ground that under Federal Power Act Section 212(h) the wholesale customer ,
"would utilize transmission or distribution facilities that it owns or controls to deliver all such electric energy to such ,
electric consumer" and the facilities used to serve the ultimate customer consist solely of substation-based facilities or of substation-based facilities which are remote from, and not directly connected by the wholesale customer's own facilities
- to, the wholesale customer's principal area of electric service.
The proposed amendment of the CATSA is aimed squarely at MID and only at MID. It seeks to nullify MID's status as an entity entitled to an interconnection y and transmission service regardless that it will distribute the power involved at retail and, of course, it constitutes clear recognition'by PG&E that MID is such an entity. The amendment is designed and intended precisely to prevent the effectuation of the Power Sales Agreement between Destec and MID." It is not a generic amendment to a filed i In fact it is Section 6.1.2 of the proposed amendment, rather than Section 6.8, to which 12 of the letter refers. See proposed Section 6.1.2(f). In so baldly setting forth the purpose of the proposed amendment, neither Destee nor PG&E appears to understand-or perhaps to care-that, in entering into it, Destee breached the covenants of good faith in the Power Sales Agreement with MID and PG&E tortiously interfered with that agreement.
" Section 205(a) of the Federal Power Act,16 U.S.C. ( 824d(a), mandates that all rates and charges for the transmission and sale of electric energy bejust and reasonable and declares any that are not to be unlawful. Section 205(b) of the Act,16 U.S.C. { 824d(b), provides:
No public utility shall, with respect to any transmission or sale subject to thejurisdiction of the [ Federal Energy Regulatory] Commission, (1) make or grant any undue preference or advantage to any person or subject any person to any undue prejudice of disadvantage, or (2) maintain any unreasonable difference in rates, charges, service, facilities, or in any other respect, either as between localities or as between classes of service. Thus, the Act makes illegalper se an agreement such as the proposed amendment of the CATSA that is specifically designed and intended to prejudice and disadvantage a particular person. Indeed, l
l tariff which would be applicable generally to all potential users of the services provided by PG&E to Destec under the CATSA. It is, rather, a rifle shot aimed at MID with the ! purpose of preventing Destec from fulfilling its obligations to MID under the Power Sales
- Agreement and has no application to any existing or future contractor with Destec other 4
than MID. i The Stanislaus Commitments, and their inclusion as conditions of PG&E's nuclear licenses, are expressly designed and intended to remedy anticompetitive activity in which PG&E has historically engaged and to open up competition in the bulk power
- market in PG&E's service territory. MID's undertaking to supplant PG&E as the supplier i
of retail electric service to Praxair and other consumers in Pittsburg, California, is a ! paradigm of the kind of competition the commitments are designed to promote. On the
- p lh other hand, PG&E's actions in the premises are a paradigm of the kind of conduct that was supposed to be eliminated by the imposition of the commitments.
. As discussed, as an irrigation district, MID is a public agency authorized under the law of California to provide electric service anywhere in the State. At the i
- request of Praxair and other retail consumers in Pittsburg, who are currently retail i
i customers of PG&E, MID arranged to acquire the Linde Substation and related facilities
- from Praxair to provide such service. The substation is currently interconnected with PG&E's transmission system and MID does not propose to change the physical
} interconnection in any way. MID contracted with Destec, a power marketer, for Destec ) we know of no other case involving the tender of an amendment to a rate schedule formulated precisely to
- destroy the rights of a third party under the third party's contract with one of the parties to the amendment.
to sell and deliver to Linde Substation at wholesale the power MID will require to serve 7-U the Pittsburg load. Destec has a contract with PG&E, the CATSA, under which Destec is entitled to transmission services from PG&E to deliver the power that Destec sells to its wholesale customers at points such as the Linde Substation. j PG&E refused on the flimsiest pretexts, see pp. I1-12 above, either to ) continue the interconnection with the Linde Substation after its acquisition by MID or to provide transmission service to Destec to enable Destec to deliver power to MID at the i . Linde Substation. PG&E is engaging in precisely the kind of conduct that called forth the i , Stanislaus Commitments in the first place. It should not be permitted to transfer the l l licenses to which the commitments are conditions except provision is made to remedy. such conduct currently and to guarantee that PG&E will not engage in such conduct in the future.
- Persons having knowledge of the events and conduct of PG&E set forth herein are
- Roger Van Hoy l Assistant General Manager, l Electric Resources Modesto Irrigation District P.O. Box 4060 Modesto, California 95352 (209) 526-7464 (209) 526-7575 (fax) 4 n
a
i i
- O Scott Steffen, Esq.
- V Assistant General Counsel i
Modesto Irrigation District P.O. Box 4060 Modesto, California 95352 (209) 526-7387 (209) 526-7383 (fax) Christopher J. Mayer Assistant General Manager Planning and Marketing Modesto Irrigation District 1231 Eleventh Street Modesto, California 95354 (209) 526-7430 (209) 526-7575 (fax) Please let us know if you have any questions or we can to of further help to ) you in any way. l 1 O I V Sincerely, ;
. A
\\ ace L. Duncan '
Riclun nd F. Allan i Duncan, Weinberg, Miller j
& Pembroke, P.C.
l Attorneys for Modesto Irrigation District enc. cc w/ enc.: PG&E Destec Praxair
]
Steven D. Bloom l
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Pacific Gas tnd E.. .;tric Comp:ny 77 Eea e 5"ee: h::t 3;;f .. 3-San Fran::s:: CA R- e 415'973-662E e , t a t g Tete:coter 415'973-9271 k<(,,e y ' f u.., Teie:00ie' 415'973-5520
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7 p& December 5, 1994 "
. ,, i a Msi . Lois D. Cashell, Secretary 445-222-00@ l Federal Energy Regulatory Commission j 825 North Capitol Street, N.E. '
Washington, DC 20426 Re: Initial Rate Filing for the Control Area and ! Transmission Service Agreement Between Pacific Gas and 1 Electric Comoany and Destec Power Services. Inc. '
. l
Dear Ms. Cashell:
)
Pacific Gas and Electric Company ("PG&E") hereby l submits for filing and acceptance, as an initial rate l schedule in accordance with Section 205 of the Federal Power < Act and Section 35.12 of the Federal Energy Regulatory )
, Commission's (" Commission" or "FERC") regulations (18 C.F.R. l t ,i 5 35.12), the Control Area and Transmission Service I
'wd Agreement (" Agreement"), dated November 29, 1994, between PG&E and Destec Power Services, Inc. ("DPS"). Summarv of Acreement The DPS-PG&E Agreement is a comorehensiva n a -t-transmim=4- ant contrM n-aa services agreement that alithorizes DPS, a power marketer, to purcnase power from a number of generation sources ("DPS Suppliers"), aggregate it under the "DPS Pool" and sell from the pool to a number of wholesale loads. Among the suppliers from which DPS intends to purchase power are Qualifying Facilities ("QFs") pursuant to the Public Utility Regulatory Policies Act of 1978 ("PURPA") located in PG&E's Control Area and which sell powar to PG&E under various power purchase agreements. Appendix E of the Agreement contains the " Enabling Agreement" which describes the priority and accounting for deliveries of power from these QFs to both PG&E and DPS. This Agreement: 1) identifies the types of suppliers from which DPS can purchase, describes the types loads it can serve, and provides the equations for accounting for balancing of such loads and resources; 2) establishes DPS control area reliability obligations, e.g., load following, spinning reserve and power deviation requirements, and gives (O)
Ms. Lois D. Cashell
- Page 2
N December 5, 1994 i
i DPS options to satisfy these obligations by purchasing ) services from PG&E, purchasing services from third parties, or satisfying these obligations using its own Is. sources; and
- 3) provides flexible network transmission service on both a - l 4
firm short term and annual basis among specifie6 generation i
" Input" points and load " Output" points.
4
- 1. Power Sales and Accountinc '
Section 3 of the Agreement identifies the' transactions DPS may conduct to deliver power to and from the DPS'. Pool and contains detailed power accounting formulas which-segregate power sold to DPS from that delivered to PG&E from QFs. This section also ensures that DPS re' sources match DPS' loads. The Agreement identifies different categories of potential DPS Suppliers to which different requirements may apply. All DPS Suppliers are categorized by contractual classification, i.e., where the resources are located or special contractual characteristics of the resource.1/ In addition, DPS Suppliers that are QFs selling to PG&E are 1 also categorized by function, i.e., the manner in which g-s power is delivered to the DPS Pool and PG&E. V) There are two types of resource " functions" under the Agreement; " Controlling Basis Resources" ("CBRs") and
" Allocation Basis Resources" ("ABRs"). For QFs that sell both to PG&E and the DPS Pool (i.e., "EA Resources"), there are three blocks of power available. These blocks are described on Exhibit 1 to this letter. As shown on Exhibit 1, the first block of power generated by an EA Resource is the firm capacity block committed to PG&E. For QFs with no firm contract capacity, this block is zero. The second block is a fixed quantity of excess power that is sold to PG&E in the case of a CBR and is sold to DPS in the 1/ For example, "DPS Control Area Resources" are resources within the PG&E Control Area, " Imports" consist of power imported from outside the PG&E Control Area, "EA Resources" are QFs who sell to PG&E and have been qualified to sell to the DPS Pool under the procedures in the Enabling Agreement (Appendix E of the Agreement), " Southern Zone DPS Resources" are suppliers subject to curtailment due to excess line loading on WSCC Path 15 in a south-to-north direction, and
" Northern Zone DPS Resources" are suppliers subject to curtailment due to excess line loading on WSCC Path 15
( in a north-to-south direction. I
Ms. Lois D. Cashell
- Page 3
[] December 5, 1994 V case of an ABR. The third block of power is a variable amount of power that fluctuates based upon the actual output of the generator. For a CBR, this top (variable) block is sold to DPS and for an ABR, the top (variable) block is sold to PG&E on an as-available basis. Thus, an ABR delivers flat, fixed quantities of power throughout the scheduling hour to the DPS Pool and a CBR delivers variable, changing quantities of power throughout the hour to the DPS Pool. Section.3 of the Agreement defines these categories and contains acco'unting protocols for separating the power sold to DPS from the power sold to PG&E. The protocols also address accounting for periods of curtailment on WSCC Path 15.. There are two types of DPS loads that DPS may serve. DPS may supply the entire power requirements of a DPS customer or the entire variable portion of a customer's load through Variable Transactions. Variable Transactions are akin to full requirements sales and partial requirements sales where DPS will vary power deliveries on a moment by f~s moment basis to match load variations. DPS may also supply ('~' ) a fixed quantity of power to a DPS customer to meet a portion of its load through Scheduled Transactions. Scheduled Transactions are typical sales of bulk power that are deemed flat throughout the hour, regardless of the customer's actual consumption. 2. J Control Area Recuirements and Services The Agreement specifies DPS's control area responsibilities to ensure system reliability, to regulate the matching of DPS' loads and resources and to eliminate the potettial tor feaning on otner utilities 1n ene control p . .c't h e A g r e e m e n c a l s o d e l i n e a t e s t h e t e r m s a n d conditions by which PG&E will provide all or a portion of each of these services. One unique feature of the Agreement is that DPS has available a " menu" of options for meeting each requirement; DPS may purchase services from PG&E, purchase _ services from third parties, satisfy any requirement on its own, or employ a combination of these alternatives. As described further below, there are four categories of obligations / services that DPS must satisfyf (i) AGC Regulation; (ii) Inter-Hour Load Balancing ( "! HLB," ) ; (iii) Spinning Heserve; and (iv) Energy Deviation requirements. 7_
- . .. - .. - -=- .
Ms. Lois D. Cashell
- Page 4
- (T December 5, 1994
, \ss/ , DPS must provide for the regulation of its loads and 2
resources on a moment by moment basis by satisfying the I Automatic Generation Control ("AGC") Regulation requirement. (Section 4.1) DPS may satisfy this requirement by buying service from PG&E, providing DPS resource capacity for j control by PG&E (Section J.3.1), or satisfying the obligation on its own as if it were operating its own - control area by matching loads and resources in accordance' . with NERC and WSCC criteria. (Section J.3.2) .DPS may l esta8Frsn a group or 9matchTng Loads" (for which it.will ' meet NERC and WSCC criteria) and a group of Non-Matching Loads, for which it will either buy AGC Regulation service or provide capacity for control to PG&E. Each day DPS, fails to satisfy its AGC Regulation requirements through one cr a combination of these options, it will be recuired to nav a . " shortfall rate" which._in af_fect, deamc arer h S "l =*-d o n
~ l service provided Ty PG&E f or that day. (Sections D.2 and l 4.1.6) Moreover, any failure by DFs to adequately match 4
resources and load can lead to the imposition of charges, as j discussed below, with regard to energy deviations.
.g s IHLB is a new service to address the unique situation of having QFs sell both to DPS and PG&E under this 4 , \"') arrangement. IHLB allows DPS to follow changes in load from one scheduling hour to the next by changing allocations in energy between an EA Resource's sales to PG&E and the EA Resource's sales to DPS, potentially requiring PG&E's generation to physically respond to changes in DPS load /PG&E supply. (Section 4.2.2) Thus, as an alternative to ramping its own generation to meet inter-hour load swings, DPS can purchase the right to make PG&E generation adjust by allocating more or less power from EA Resources to PG&E on an hourly basis. This service is only applicable to EA Resources since it is only for resources whose power is sold both to PG&E and the DPS Pool, and such PG&E purchases can te increased or reduced on an hourly basis. The rate for 1 HLB depends upon the ratio of Scheduled Transactions to Variable Transactions. Because the amount of IHLB is affected by the ratio of Variable to Scheduled Transactions, the higher the percentage of Variable Transactions that DPS conducts, the higher the rate. (Section D.3)
DPS' Spinning Reserve Requirement is the same as applied to PG&E; DPS must_ arrange f or_ soin in an amannn_ ecual to 7% of its 1rm transactions and 100% of its non-~
-tirm transa_c_tions. (Section 4.3I To meet this requirement, DPS may either buy Spinning Reserve service __from PG&E, 1
h,) provide its own Spinning Reserve, or purchase M ning i s_ 5
Ms. Lois D. Cashell
- Page 5 December 5, 1994 Reserve from a third party in the Control Area. If DPS fa11s to me c tuo 5pinulng Reserve Requirement in any hour, DPS will incur a daily disincentive charge equal to 115% of PG&E's daily Spinning Reserve rate. ,f,Section D.4)
DPS is obligated under the Agreement to match as closely as possible the energy usage of the DPS load with . energy deliveries from DPS Suppliers to the DPS Pool to attempt to achieve zero deviations. DPS may operate within ; an Energy. Exchange Band without charge by PG&E~. This band ' is set at +/- 1 MWh/ hour for loads of 100 MW
~
+/- 2 MWh/ hour for loads of 200 MW or less.2/or less'.and (Section 4.6.1) DPS may purchase a larger Energy Exchange Band.of up to +/- 7 MWh/ hour. (Section 4.6.7) Section 4.6, establishes a formula to determine if any positive or negative deviations have occurred. Deviations within the Energy Exchange Band are returned within a like period. Deviations outside the Energy Exchange Band fall either within the First Deviation Band (equal to +/- 7 MWh/ hour) or the Second Deviation Band (greater than +/- 7 MWh/ hour) . As a general matter, if DPS undergenerates, it will incur a charge. If DPS overgenerates, such power is lost to the system.
f-t However, if DPS overgenerates during a minimum load condition, it will incur disincentive charges-for overgeneration. (Section D.7.2) . l
- 3. Network Transmission Service 4e PG&E will provide flexible Network Transmiccion Service which wi_11 anable DPS to conduct transactions among multiole
- - @j$ genera 3 cn soup;;es. J "Inouts") and loads (" outputs 3 j
', cesignated by DPS, subject to approval by PG&E in accordance !
', f with the request process described below,;and specified on service tables in Appendix K. DPS may purchase Short-Term Firm Service (provided in mon,thly increments within a 12 month period) and Annual Firm Service (for periods a year or greater). DPS will purchase transmission service based upon its anticipated " Maximum Simultaneous Demand," rather than requirine a vaservn ion _on moint-to-point paths.
"T5ection 6.2) The single rate for transmission service is derived using t6e ro:2ea-i6 rate" method and in parTIcularly appropriate for this service since DPS may E/ For the initial three months in which DPS conducts transactions under the Agreement, the Energy Exchange Band shall be +/- 2 MWh/ hour for loads of 100 MW or less and +/- 4 MWh/ hour for loads greater than 100 MW.
)
l Ms. Lois D. Cashell 4 Page 6 f1 December 5, 1994 l (m_ l j l conduct transactions among any combination of approved Input l j and Output Points on PG&E's transmission system. ; (Section D.8) A rate for distribution service on voltage less than 60 kV but greater than 4.16 kV is also provided in l Section D.8. (Transmission service is not available to serve' !
} PG&E retail customers uuue; cae agreemenc. mes ivu o.ej PG&E is obligated to provide transmission service on -
)
I Available Transmission Capacity (defined in Section 1.10). I g W If upgrades are necessary, the Agreement incorporates the I Commission 's "or" pricinq model, i.e., DPS would pav the - g[ Y hIguez 02_cne_ incremental cost of the upgrade or the rolled-in cest.
~
(Section 6.2) vue to the relatively short initial j Lerm 6r the Agreement, PG&E is not obligated to constr6.ct h L upgrades if such upgrade would take more than two years to [ . construct or require a Certificate of Public Convenience and (, Necessity from the CPUC. (Section 6.l.2) On a portion of PG&E's transmission system (WSCC Path
- 15) that is currently constrained, DPS has the option to purchase curtailable firm service instead of requiring the
,s construction of costly system reinforcements. (Section 6.3)
Service will ie mrtailed cone =* ant _ with the oueue sDecified in the Armth of Tacia Principles (PG&E Rate , ! (chedule FERC No. 143) and with similar service provided to I l
"a numoer or otner utilities. In the event of south-to-north l curtailments of service on WSCC Path 15, replacement power ~
will be offered for sale by PG&E lexceDt for imports ffbm-
'?ne Southern California Edison Control Area). (sections '
6.a.3 and 6.3.4) DPS will request transmission service in accordance with a detailed request process which requires PG&E to promptly respond to DPS' requests. (Section 6. 6) Prior to
; making a formal request, DPS may request an informational 4
s review. (Section 6.7.5) If DPS disagrees with PG&E's study results or PG&E's conclusion that a study is necessary, DPS i may challenge the results before the Technical Arbitrator in accordance with Appendix C (described below). DPS has requested and PG&E pas agreed to provide an initial amount of Short Term Firm Transmission Service < beginning March 1, 1995. (See Appendix K). I 1 4. Effective Date And Term l The term of this Agreement is five years from the (\ Effective Date. The Agreement may be extended by agreement . \-)
l Ms. Lois D. Cashell
- l Page 7
(~N December 5, 1994 (. of the parties. As described in Section 2.1, the Effective j Date of the Agreement varies depending upon when the Commission accepts the filing and makes it effective. If the. Commission accepts this Agreement without conditions unacceptable to either party, service may commence on the first day of the following month (if the acceptance date is on the twentieth day of a month, service ma first day of the second following month)l/.y commence on the
- 5. Discute Resolution .
The parties have agreed to resolve disputes arising under this Agreement in accordance with mandatory dispute resolution procedures specified in Appendis.A, with two. exceptions. First, Appendix C contains an innovative technical dispute resolution procedure which is designed to quickly resolve technical disputes. 1 The " Technical Mediator" will be jointly selected by the parties soon after the Agreement is accepted by the Commission and will stand prepared to rule on four categories of disputes. DPS may challenge: 1) the results of PG&E's 60 day transmission studies; 2) PG&E's determination that a study is required; 73 i d 3) PG&E's determination that an existing interconnection
\'# agreement between PG&E and a proposed DPS load or supplier is inadequate and needs modification; and 4) PG&E's imposition of interim rules or of interim changes in the Spanning Reserve Requirement, as specified in Section 8.20.
Second, in accordance with Section 6.4.2.1, if PG&E decides not to designate a dispute regarding the adequacy of an existing interconnection agreement as appropriate for the Appendix C process, DPS may initiate a lawsuit.
- 6. Provision of Service Under PG&E's Upcominc Transmission Tariff PG&E recently announced that it will file a transmission service tariff that will provide comparable service as described in the Commission's recent transmission service pricing policy statement. DPS reserves the right in Section 8.28 to cease taking transmission service under this Agreement and to switch to the tariff.
1/ Section 2.5 describes the regulatory procedure for
! termination of this Agreement. Section 2.5 recuires a filing to effect termination- Pr1 ,a not ramissang ' ,y tnat the Commission pre-grant termination of its i 1 acceptance n' ema agreement. \m /
l l
'Ms. Lois D. Cashell * ! ~
Page 8 December 5, 1994 O i i
- 7. Monthlv Billina Charae and One-Time Set-Un Fee Section 4.5 provides that DPS shall pay a monthly.
administrative charge in each month it conducts transactions as specified in Section D.5 to compensate PG&E for monitoring compliance with this Agreement and preparing , billings. Additionally, PG&E may charge a one-time fee ; ! based on actual incremental labor.for computer programming' ' to set-up and administer the Agreement and for training on the new program. ,
- 8. Enablina Acreement Appendix E of the Agreement contains t'he Enabling.
Agreement which specifies how power generated by QFs selling both to PG&E and to the DPS Pool wil1 be separated and , accounted for. Under the Enabling Agreement, DPS will request qualification of QFs as "EA Resources" so that.they can be added as Transactions Points under this Agreement. If approved, the EA Resource will execute the attached
" Schedule A" letter agreement with PGEE, under which the QF agrees, among other matters, that once DPS schedules power from the QF to the.DPS Pool on a final basis,'the QFs' PURPA O. rights, with respect to that increment of power which has been scheduled for delivery to DPS for that one-hour schedule period, are extinguished and PGEE correspondingly has no obligation to purchase that power during that one-hour scheduling period.
Services Provides Under the Aareement As summarized above, Appendix D contains rates and charges for the following services provided by PG&E: Network Transmission Service 4 Transmission Rate D.8.2.1 l - Primary Distribution Rate D.8.2.2 Control Area Services l AGC Regulation Service D.2 2 AGC Regulation Shortfall Rate
- D.2.1 i i
Inter-Hour Load Balancing Service D.3 - Spinning Reserve Service D.4 Spinning Reserve Disincentive Rate
- D.4.1 1
lO , I L. 1
Ms. Lois D. Cashell
- Pace 9 December 5, 1994 f)/
\_
Other Charoes , Monthly Billing Charge D.5 Additional Energy Exchange Band D.6 Overgeneration Charge
- D.7 Undergeneration Charge
- D.7 Replacement Power D.9 e charges.
/
I Rolled-In Transmission Rate 1 DPS has agreed to single aggregated transmi.ssion (
- onth that was derived i:n a manner ~
=*ga nf <' -
consistent wllh the rolled-in rate method.
~
PG&E has used a subfunctionalized transmission rate method in other transmission service agreements. Under the subfunctionalized rate method, the transmission system is separated into five basic functions (area, backbone, generation-tie, system interconnect, and exclusive use) . A transmission customer pays a system average charge for each fN subfunction deemed used for specific transactions. When
! I transmission service is provided on a point-to-point basis, it is possible to deem specific portions of a transmission system used for a specific transaction and, therefore, determine the subfunctionalized charges applicable.
The uniquely flexible nature of the Network Transmission Service provided to DPS under this Agreement makes use of the subfunctionalized approach difficult b transactions amone_all_of Q,ecauseDPSisenabledtoconduct he Transaction _s Points designated in Appendix K. Because DF5 will make use of PG&E's entTfW transmission system. it fs appropriate to cnarge a rate based upon the embedded 1(cos;s 02 .ne entire system. DPS concurs with the application of a single transmission rate and the rate method used to derive it. Bv this filing PG&E does__not intend to create precedent with respect to existing transmission services nrovided to
~
dustomers under other transmission service acreements. ~'~~ This fl.ing aces noc commence a_ uniform change in PG&E's Msmission rate method f or all PG&E customers.~ The unique
-nature of the transmission services provided under this Agreement distinguishes it from the services provided on a subfunctionalized basis in other agreements.
p V
J 4 Ms. Lois D. Cashell Page 10 l I-December 5, 1994 Disincentive Rates There are a number of charges in the Agreement that will accrue if DPS fails to operate within the limits
- specified in Sections 3 and 4 and in Appendices D and J.
- For example, if DPS fails to satisfy its AGC Regulation or i Spinning Reserve requirement, service is deemed provided by PG&E for that day and a disincentive rate is applied. The" rates for these services are not necessarily cost based.
< The parties have agreed to use disincentive rates as a means ' - of encouraging DPS to prudently plan and operate rather than adopting more drastic measures, such as disconnecting DPS < from the PG&E system. (See, e.g., Section.,4.6.6.3) The Commission has repeatedly endorsed.the use of disincentive charges to encourage responsible operations and 2 d guard against unauthorized use of services by utilities. Cleveland Electric Illuminatina, 63 FERC i 61,244 at
- p. 62,677, Pacific Gas and Electric Comoanv, 53 FERC
$ 61,145 at p. 61,506, El Paso Natural Gas, 54 FERC i 61,316 i 1
at p. 61,966 ("the Commission finds the proposed penalties ("' ( are reasonable. The penalties . system's integrity.
. . will ensure the In order to justify a provision that will ensure system integrity in the future, a pipeline need not show that the problem which the penalty is intended to correct has occurred in the past, but only that the proposed penalty is reasonable, and necessary to discipline l operations on its system.")i/
The parties have negotiated and agreed upon disincentive rates attributable to DPS shortfalls in control area services (AGC Regulation and Spinning Reserve) and energy deviations beyond the Energy Exchange Band (i.e., deviations in the First Deviation Band and the Second Deviation Band). The " shortfall" rates for control area services necessarily exceed the rates DPS would pay had it reserved services in advance. This dichotomy provides DPS with an incentive to operate and plan reliably. Similarly, the disincentives rates for undergeneration (outside the Energy Exchange Band) and Overgeneration (during minimum load conditions) appropriately encourage DPS to operate prudently and in accordance with the Agreement. i' The Commission has expressed concern in the cases l approving disincentive charges that the penalties not Cleveland Illuminatina, be exorbitant or exploitative.
' suora, 63 FERC at p. 62,677.
1 Ms. Lois D. Cashell
- Page 11-December 5, 1994 ws ,
l Stranded Investment l 1 Under this Agreement, PG&E is not obligated to provide control area services, provided, that PG&E shall not i unreasonably withhold such services if such service is available from PG&E. Thus, PG&E is not required to dedicate resources, build new generation nor plan to be able to meet DPS' needs for Control Area Services. If such services are available based upon PG&E's then-current portfolio, it will provide them. Accordingly, there is no potential for j stranded generation-related costs under this Agreeme'nt. With respect to transmission services,. PG&E will provide transmission service on Available Transmission. Capability (defined in Section 1.10) and will build system ~ upgrades, if necessary, in limited circumstances._ (See l Section 6.1.2) If construction is requirec, PG&E is ' entitled to condition proceeding with the project on the/ parties negotiating provisions that provide PG&E with 4f reasonable protection from stranded investment. (Section 6.7.2) g (j Filine Recuirements In The Commission's Recent Transmissiqa Poliev Statement The Commission, in its recent Policy Statement (" Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities under the Federal Power Act"), enunciated five principles that will guide its approval of pricing for transmission services in the future and should be applied to the pricing of transmission service under Section 205 cf the Federal Power Act. Because PG&E's proposed transmission service rate is derived using the CtmHi'ssion's traditional " rolled-in" - approach, it is a "conro for purposes of4he iransmisTion policy statement. PG&E addresses the five principles as roikvws.
- 1) Transmission Pricino Must Meet the Traditional Revenue Recuirement The transmission rate of $1.65 per kilowatt-month proposed for DPS in the Agreement (See Section D.S.2.1) is based on PG&E's traditional revenue requirement as shown on page 118 of the work papers supporting this filing. The transmission service rate is priced within an embedded cost revenue reauirement.
^^
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Ms. Lois D. Cashell 4 Page 12
/ December 5, 1994
( s~ Transmission service follows the " corporate mostace stamp" model described in the Poficy Statement _. 3ecause the Tervice is " network" service, DPS may conduct transactions , among all Transaction Points on PG&E's system as long as its l usage does not exceed the " Maximum Simultaneous Demand" ; purchased by D9S on a take or pay basis. Thus, service :Us acco ed for on a " network maximum demand basis", not a power low" or " contract path" basis. In addition, the transm'ssion pricing policy for DPS follows the Commission's "or" ricino i a. DPS will pay _*he kd 7har _of 'either a
, er s_ mission rate or the c_o_st of any incremental upgrace if transmission system uograces are necessary to p2vvide DFS sEivice TSee Section J.e.4)
- 2) Transmission Pricina Must Reflect Comoarability j
/ l ,,/ PG&E's transmission pricing to DPS is comparable to the l pricing for other wholesale and PG&E retail users of the i PG&E transmission system. As described above, PG&E's transmission pricing methodology for wholesale customers has been done on a subfunctional basis, i.e., functional costs 7- of the transmission system facilities have been
(' subfunctionalized (or categorized) into five groups according to each transmission group's definition. Wholesale transmission customers have paid for transmission based on the subfunctions used, i.e., some wholesale customers are connected at higher voltages and others have built transmission facilities to avoid a certain subfunction, and thus not be charged for one or more of PG&E's transmission subfunctions when using PG&E's transmission services. Thus, wholesale customers also pay for one or more embedded cost " corporate postage stamp" transmission rates. 9ince its_netwprk services use the_ entire PGLE system. nps in the f un ~ i--C ~ agu iv_alent of a y Wnciesale customer that pays for all of the subfunctI3hs. if PG&E retail customers pay: rates whicn are tne equivalent of the sum of the charges for the five subfunctions. Thus, the single rate to be paid by DPS is comparable to that allocated to PG&E retail customers. As to comparable access, PG&E is providing DPS with Network Transmission Service (Section 6.0) which will allow DPS to flexibly move power from its designated generators to its designated loads over PG&E's system or into or out of the PG&E Control Area. DPS is entitled to reserve Available Transmission Capacity on PG&E's transmission system on an equal basis with other wholesale customers and wd.th PG&E On one transmission path the parties have ['G ] retail load.
_ - ..-~ .- - .- - . -. . Ms. Lois D. Cashell a Page 13 December 5, 1994 agreed that curtailable firm service would be made l available. (See Section 6.3) DPS has agreed to this approach rather than opting for expensive transmission upgrades to provide incremental service over this path. PG&B has agreed to supply replacement power whenever DPS power is curtailed _nn WSCC Parb 15 in a south-to-north direction (except for imports from the Rd' ann Control Area _ DPS gains transmission access under the Agreement which is comparable to transmission used by PG&E for its retail service access as well as the access to which other*. wholesale cust'omers are entitled. !
- 3) Transmission Pricina Should Promote Edonomic Efficiency Since PG&E has proposed transmission pricing for DPS , I which follows the Commission's transmission "or" policy and ;
provides equal access as discussed above, the Agreement ! allows for efficient expansion of transmission, efficient ! location of generators and load, efficient use of existing { transmission facilities and efficient dispatch of exi9 ting generation resources.
- 4) Transmission Pricino Should Promote Fairness As shown above, the Agreement provides equal transmission access and comparable transmission pricing. In addition, as to incremental upgrades discussed above, DPS will pay for only the portion of the upgrade which benefits it.
- 5) Transmission Pricine should be Practical Since there i; only a single rate for all uses of PG&E's system, the pricing is simple, practical and easy to administer.
Recuest for Waivers PG&E respectfully requests that the Commission grant any waivers of the Commission's rules and regulations necessary for acceptance of this filing and the Agreement under the Federal Power Act. In particular, PG&E requests that the Commission authorize PG&E to add, delete or modify delivery levels for Transactions Points listed in Appendix K and make changes in DPS' Maximum Simultaneous Demand without the need for filing s
Ms. Lois D. Cashell Page 14 i December 5, 1994 i such changes to Appendix K with the Commission. PG&E makes this request on the behalf of DPS. DPS takes the position , that the delays associated with prefiling each change in i transmission services (particularly Short-Term Firm Service) with the Commission 120 to 60 days before commencement will ; inhibit DPS from providing services in a responsive manner ;
~
and could limit its competitive effectiveness in the market. DPS desires the flexibility to quickly add and delete j Transaction Points and increase or decrease levels of i service to best respond to the needs of its customers. ;RE&E notes that the__. Commission has previously granted waivers of-the type requestec nere in conjunction witn cnanges to transmission services pzuvad=J uudet incezwvanection , agreemencs winn Lne Nortnern Lantornia Power agency (PGJsE REpe scneaule FERC No. 142), Moda=*o irricar,mn ndstric; (PG&E Kate Schedule FERC No. 116), and Turlock. Irrigation District (PG&E Rate Schedule FERC No. 115). ProDosed Acceotance Date PG&E hereby requests an' effective date for the Agreement 60 (~% days after the Agreement is filed with FERC and no later - than March 1, 1995, when initial transmission service begins. Abbrf-viated Filino Recuirements Aeolv Because this filing is an initial rate schedule, PG&E has submitted, in compliance with Section 35.12 of the Commission's regulations, 18 CFR S 12, only the information required in paragraphs (a) and (b) of Section 35.12. Concurrence By its execution of the Agreement, DPS demonstrates its concurrence. DPS will intervene in support of PGLT'e #iling and will recuest the Commission to approve PG&E's request ror waivers and to accept the Agreement witnouc , i modification. 7 Procosed Rate Sched h Dcrinna.tions Since thi .s an initial rat chedule to a new customer, PG&E request that the ssion assign a new rate schedule O l l l i l
i Ms. Lois D. Cashell * , ! Page 15 - December 5, 1994 ( to the Agreement and designate all appendices to the l ! Agreement as supplements to the Agreement as follows: ; I Desianation Descrintion Rate Schedule FERC No. Fully executed Control Area ] (Initial Rate Schedule) and Transmission Service, j i Agreement
- t j' Supplement No. 1 to Appendix A ~ Dispute l Rate Schedule ~FERC No. Resolution and Arbitration .l l
i Supplement No. 2 to Appendix:B - Scheduling ' Rate Schedule FERC No. Supplement No. 3 to Appendix C_- Expedited Rate Schedule FERC No. Procedures for Technical Disputes Supplement No. 4 to Appendix D'- Rates and Billing , Rate Schedule FERC No. Determinants. Supplement No. 5 to- Appendix E - Enabling Rate Schedule FERC No. Agreement Supplement No. 6 to Appendix F.- Metering Rate Schedule FERC No. Requirements Supplement No. 7 to Appendix G - South of Tesla Rate Schedule FERC No. Principles Supplement No. 8 to Appendix H - Time Periods Rate Schedule FERC No. Supplement No. 9 to Appendix I - Utility Rate Schedule FERC No. Identifiers and Transaction Codes ; Supplement No. 10 to Appendix J - DPS Requirements Rate Schedule FERC No. for AGC Regulation and l Spinning Reserve i l t Supplement No. 11 to Appendix K - Network l 2 Rate Schedule FERC No. Transmission Service Table iO
, Ms. Lois D. Cashell Page.16 ,
f () December 5,'1994 _ ! I Enclosures , Enclosed for filing are six copies of-each of the following documents: j l A. A Certificate of Service; . l B. AnoticesuitableforpublicationintheFederak l l Register; h ! -C. Attachment 1, Control Area and Transmission l . Service Agreement; and ; ! D. Supporting information as required pursuant'to , Section 35.12 of the Commission's regulations. Expenses 1
- No expenses or cost associated with this filing have been alleged or judged, in any judicial or administrative l proceeding, to be illegal, duplicative, or unnecessary costs ]
l /g that are demonstrably the product of discriminatory V I employment practices. Service Copies of.tba filing have been served upon DPS and.the California Public Utilities Commission. A copy of this filing is also available for public inspection at PG&E's principal office, located in San Francisco at 77 Beale Street. Corresoondence PG&E requests that all correspondence, pleadings, and other communications concerning this filing be served upon: William V. Manheim Attorney Pacific Gas and Electric Company P.O. Box 7442 i San Francisco, CA 94120 i 1 l I
_ . _ _ - .. _ - . . - . _ _ . ~- --- --- _- _ Ms. Lois D. Cashell Page 17 December 5, 1994 l PG&E also requests that an additional copy of any j correspondence and orders be sent to: Robert J. Doran Director, FERC Rates and Regulation Pacific Gas and Electric Company 77 Beale Street ' Post Office Box 770000 Room 2345, B23A San Francisco, CA 94177 . PG&E hereby submits an additional copy of the first page of this transmittal letter and respectfully requests that the Commission acknowledge receipt of this filing by returning the file-endorsed page in the enclosed stamped, pre-addressed envelope. Respectfully submitted, MICHAEL S. HINDUS' WILLIAM V. MANHEIM D k . By: h WILLIAM V. MANHEIM Attorneys for Pacific Gas and Electric Company 1 P.O. Box 7442 San Francisco, CA 94120 Telephone: (415) 973-6628 Enclosures
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CERTIFICATE OF SERVICE I hereby certify that I have this day served the foregoing document properly addressed to the following: Peter Arth, Jr., General Counsel California Public Utilities Commission State Building, Room 5138 505 Van Ness Avenue San Francisco, CA 94102 Christopher T. Ellison, Esq. , Ellison, Schneider & Lennihan 2311 Capitol Avenue Sacramento, CA 95816 Steven F. Greenwald, Esq. Davis Wright Tremaine , 235 Pine Street, Suite 1500 ". San Francisco, CA 94104 Destec' Energy, Inc. 1676 N. California Blvd. Suite 400 P.O. Drawer H Walnut Creek, CA 94596 Executed at San Francisco, California this 5th day of December, 1994. A)L - l?!) Joanne M. Myep 1 v.i
4 a 4 l L f i l l l i l i 3 4 l l i l 1 l, !. NOTICE SUITABLE FOR i PUBLICATION IN THE FEDERAL REGISTER i a k i k i 1 4 f i ) I
k _ UNITED STATES OF AMERICA O} BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION
. V
) i Pacific Gas and Electric Company ) Docket No. ER95-
) i NOTICE OF RATE FILING ,
Take notice that on , Pacific Gas and Electric' tendered for filing as an initial rate Company (PG&E) schedule, a Control Area and Transmission Service Agreement (Agreement) covering rates, terms and conditions for servic'es rendered by PG&E to Destec Power Services, Inc. (DPS). The Agreement: 1) identifies the types of suppliers from which DPS can purchase, describes the types loads it can serve, and provides the equations for accounting for . balancing of such ~ loads and resources; 2) establishes DPS control'- area reliability obligations, e.g., load following, spinning reserve and power deviation requirements, and gives DPS options to satisfy these obligations by purchasing services from PG&E, purchasing services from third parties, or satisfying these obligations using its own resources; and 3) provides flexible network transmission service on both a firm short term and annual basis among specified generation " Input" )
/N points and load " Output" points. .b PG&E is requesting any necessary waivers.
Copies of this filing were served upon DPS and the California Public Utilities Commission. Any person desiring to be heard or to protest said filing should file a motion to intervene or to protest with the Federal Energy Regulatory Commission, 825 North Capitol Street, N.E., Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's regulations (18 CFR SS385.211 and 3 8 5. 214 ) . All such motions or protests should be filed on or before . Protests will be considered by the Commission in determining the appropriate action to be taken, , but will not serve to make protestants parties to the ' proceeding. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection. i Lois D. Cashell Secretary s i
s
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4 TAB LE OF CONTENTS C\ V 1.0 DEFINITIONS . . . . . . . . . . . . . . . . . . . 3 1.1 AGC Control Load . . . . . . . . . . . . . 3 1.2 AGC Regulation-Load Effective . . . . . . 3 1.3 AGC Regulation Load Reserved . . . . . . . 3 1.4 AGC Regulation . . . . . . . . . . . . . . 3 1.5 Allocation Basis Resource ("ABR") . . . . 4' 1.6 Annual Firm Service . . . . . . . . . . . 4, 1.7 Appendix C Dispute . . . . . . . . . . . . 4 1.8 As-Available QF Power . . . . . . . . . . . 4 1.9 Automatic Generation Control ("AGC") . .. 4 1.10 Available Transmission Capacity . . . . '. 4 , 1.11 Billing Period . . . . . . . . . . . . . . 5 l 1.12 California-Oregon Border (" COB"), . . . . . 5 ! 1.13 California Power Pool . . . . . . . . . . - 5 1 1.14 Certificate of Public Convenience and ) Necessity ("CPCN") . . . . . . . . . . . . 5 1.15 Control Area . . . . . . . . . . . . . . . 5 J 1.16 Control Area Interchange Point . . . . . . 5 1.17 Control Area Services . . . . . . . . . . 6 1.18 Controlling Basis Resource ("CBR") . . . . 6 1.19 Costs . . . . . . . . . . . . . . . . . . 6 ( 1.20 1.21 Cost of Service . . . . . . . . . . . . . CPUC . . . . . . . . . . . . . . . . . . . 6 6 j 1.22 DPS Control Area Resource . . . . . . . . 6 , 1.23 DPS Load . . . . . . . . . . . . . . . . . 7 1.24 DPS Pool . . . . . . . . . . . . . . . . . 7 1.25 DPS Pool Energy . . . . . . . . . . . . . 7 1.26 DPS Power Control Center . . . . . . . . . 7 1.27 DPS Supplier . . . . . . . . . . . . . .. . 7 1.28 EA Resource . . . . . . . . . . . . . . . 7 1.29 Edison . . . . . . . . . . . . . . . . . . 7 1.30 Effective Date . . . . . . . . . . . . . . 7 1.31 Electric System . . . . . . . . . . . . . 7 1.32 Emergency . . . . . . . . . . . . . . . . 8 1.33 Enabling Agreement ("EA") . . . . . . . . 9 1.34 Energy Deviation . . . . . . . . . . . . . 9 1.35 Energy Exchange Band . . . . . . . . . . 9 1.36 Excess Power . . . . . . . . . . . . . . . 9 1.37 Exchange Energy . . . . . . . . . . . . . 9 1.38 FERC . . . . . . . . . . . . . . . . . . . 9 1.39 First Deviation Band . . . . . . . . . . . 10 9 1.40 Forced Outage . . . . . . . . . . . . . . 1.41 Half-Hour Period . . . . . . . . . . . . . 10 1.42 Import . . . . . . . . . . . . . . . . . . 10 1.43 Input Point . . . . . . . . . . . . . . . 10 1.44 Interconnection Agreement . . . . . . . . 10 i
.. - - . . _ . . - . - . - - - . - . _ ~ - .- _ _ _ --.-. .- -... .-_-.
i N.
-1.45 ' Inter-Hour Load Balancing ("IHLB") . . . . 11 l 1.46 Matching Loads . . . . . . . . . . . . . . -;
fd 1.47 Maximum Delivery Capability . . . . . . . 1 1.48 Maximum Receipt Capability . . . . . . . . 11 ! 1.49 Maximum Simultaneous Demand ("MSD") . . . 11 i 1.50 Minimum Load Conditions . . . . . . . . . 12 - 1.51 NERC . . . . . . . . . . . . . . . . . . . 12 1.52 Network Transmission Service . . . . . . . 12 1.53 Non-EA Resource . . . . . . . . . . . . . 12 + 1.54 Non-Matching Loads . . . . . . . . . . . . 12 1.55 Northern Zone DPS Resource . . . . . . . . 12 1.56 Output Point . . . . . . . . . . . . . . . 12 1.57 PG&E Energy . . . . . . . . . . . . . . .. 12, 1.58 PG&E Energy Control Center . '
. . . . . . . 13 1.59 PPA . . . . . . . . . . . . . . . . . . . 13 .;
PPA Firm Capacity . . . . . . . . . . . . 1.60 13 1,61 Prudent Utility Practice . . . . . . . . ' . 13 1.62 QF . . . . . . . . . . . . . . . . . . . . 13 1.63 Scheduled Transactions . . . . . . . . . . .- 13 1.64 Second Deviation Band . . . . .'. .... 13 1.65 Short-Run Avoided Cost ("SRAC") . . . . . 14 1.66 Short-Term Firm Service . . . . . . . . . 14 1.67 Southern Zone DPS Resource . . . . . . . . 14 1.68 Spin Service Effective . . . . . . . . . . 14 1.69 Spin Service Reserved . . . . . . . . . . 14 1.70 Spinning Reserve . . . . . . . . . . . . . 14 1.71 Spinning Reserve Requirement . . . . . . . 15 1.72 Transaction Points . . . . . . . . .. . . . 15 1.73 Transmission Capability on WSCC Pat'h 15 . 15 ; 1.74 Third Party . . . . . . . . . . . . . . . 16 1.75 Uncontrollable Force . . . . . . . . . . . 16 1.76 Variable Transactions . . . . . . . . . . 17 1.77 Western Systens Power Pool Agreement . . . 17 1.78 Work Day . . . . . . . . . . . . .. . . . 17 , 1.79 WSCC . . . . . . . . . . . . . . . . . . . 17 l 1.80 WSCC Path 15 . . . . . . . . . . . . . . . 17 I 2.0 EFFECTIVE DATE AND TERM . . . . . . . . . . . . . 17 2.1 Effective Date . . . . . . . . . . . . . . 17 2.2 Commencement of Service . . . . . . . . . 19 2.3 Term . . . . . . . . . . . . . . . . . . . 19 2.4 Extension of Term . . . . . . . . . . . . 19 2.5 Filing for Termination . . . . . . . . . . 20 22
- 3. 0 DPS POWER SALES AND ACCOUNTING . . . . . . . . . .
3.1 Curtailment . . . . . . . . . . . . . . . 23 3.1.1 South-to-North . . . . . . . . 23 3.1.2 North-to-South . . . . . . . . 24 DPS Suppliers . . . . . . . . . . . . . . 25 3.2 3.2.1 EA Resources . . . . . . . . . 25 3.2.2 Allocation Basis Resources ("ABRs") . . . . . . . . . . . 25
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4 3.2.3 Controlling Basis Resources of~g ("CBRs") . . . . . . . . . . . 27 ( j. 3.2.4 Initial 12-Month Period . . . . 2E 13.2.5 After Initial 12-Month Period . 28 3.2. 6' Non-Utility Resources Within-the PG&E Control Area . . . . . 29 3.2.7 Utility Resources Within the-PG&E Control Area . . . . . . . 29
-3.2.8 Imports . . . . . . . . . . . . 30 3.3 DPS Loads . . . . . . . . . . . . . . . . 31 3.3.1 Loads Met Th~ ugh Scheduled Transactions . . . . . . . . . 31 3.3.2 Loads Met Through variable ,
Transactions . . . . . . . . . 31 3.4 Scheduling . . . . . . . . . . . . . . . . 31 4.0 CONTROL AREA SERVICES AND REQUIREMENTS . . . . .'. 32 4.1 AGC Regulation . . . . . . . . . . . . . . '32 4.1.1 Description of Service / Requirement . . . . . 32 4.1.2 Monthly Division of Output Points . . . . . . . . . . . . 32 4.1.3 Matching Loads . . . . . . . . 33
<4 .1'. 4 Non-Matching Loads . . . . . . 33
'4.1.5 Capacity for Control by PG&E . 33 4.1.6 AGC Regulation Service from PG&E- . . . . . . . . . . . . . 34
( 4.1.7 AGC Regulation Service Provided by Third Parties . . . . . . . 34 4.1.8 Non-Binding Forecast . . . . . 34 4.2' Inter-Hour Load Balancing ("IELB") . . . . 35 4.2.1 Description of Service . . . . 35 4.2.2 IHLB Service Available From PG&E . . . . . . . . . . . . . 35 4.3 Spinning Reserve . . . . . . . . . . . . . .36 4.3.1 Description of Service / Requirements . . . . . 36 4.3.2 Spinning Reserve Requirement . 36 4.3.3 Spinning Reserve Provided by Third Party . . . . . . . . . . 37 4.3.4 PG&E Provides Spinning Reserve Service . . . . . . . . . . . . 37 4.3.5 Changes in Spinning Reserve Requirements . . . . . . . . . 37 4.3.6- PG&E Rights to Purchase Energy From DPS Spinning Reserve . . . 38 4.3.7 PG&E Payment for Energy Purchased From DPS Spinning Reserve . . . . . . . . . . . . 38 4.4 Mixture of Methods for Satisfying Control Area Service Requirements . . . . . . . . 36 iii
. . . - . - - . - - - - . - , - - . - - . . ~ . _ - - - - . . . - - .
h 4 4.5 Monthly Billing Charge and One-time Set-Up ; Fee . . . . . . . . . . . . . . . . . . . 39 4.6 Energy Deviations and Energy Exchange ! Band . .. . . . . . . . . . . . . . . . . 39 ,
.4.6.1 Size of~the Energy Exchange l Band . . . . . . . . . . . . . 39 4.6.2 Calculation of Energy Credit to ;
DPS Pool . . . . .. . . . . . 40-4.6.3 Calculation of Energy' Debit 'l ' from the DPS Pool . . . . . . . 40-4.6.4 Calculation of_ Load / Generation i Deviations . . . . . . . ... . 41 l 4.6.5 Hourly Energy Deviations Within ' the Energy Exchange Band . . . 42 4.6.6 Hourly Energy Deviations
. Outside of the Energy Exchange Band . . . . . . . . . . . . '. 43 4.6.7 Additional Energy Exchange Band . . . . . . . . . . . . . 45
- 4. 7 ' No Duplication of Control Area S'ervices . 45 4.8 Unscheduled Interruptions . . . . . . . . 45
. 1 5.O RESERVATION OF CONTROL AREA SERVICES AND l SHORTFALLS . . . . . . . . . . . . . . . . . . . . 46 !
5.1 Control Area Service Reservations . . . . 46 5.1.1 AGC Reservation . .. . . . . . 47 5.1.2 IHLB Reservation . . . . . . . 47 . I 5.1.3 Spinning Reserve Service. !
\ Reservation . . . . . . . . . . .47 5.2 Failure to Reserve Control Area-Services . 47 5.3 Shortfall in Control Area Services Reservations . . . . . . . . . . . . . . .- 48 5.3.1 AGC Regulation Shortfall . . . 48-5.3.2 IHLB Shortf all- . . . . . . . . 48 5.3.3 Spinning Reserve Shortfall . . 48 6.0 TRANSMISSION SERVICE . . . . . . . . . . . . . . . 48 6.1 Network Transmission Service . .. . . . . . 48 6.1.1 Characteristics of Network Transmission Service . . . . . 49 6.1.2 Limitations on Network Transmission Service . . . . . 49 6.1.3 Designation of Maximum Simultaneous Demand ("MSD") . . 51 6.1.4 Duration of Service . . . . . . 51 6.2 Rates and Charges . . . . . . . . . . . 53 6.3 Curtailment of Transmission Services . . . 55 6.3.1 Curtailments to Maintain Reliability . . . . . . . . . . 55
,,k iv
~ _ _ _ - - - _ - - - - = . - . - - .- -- = . . . -
J q 1 4
, 6.3.2 Curtailments to Mitigate Operating Problems Resulting
( ,s) from Excess Demand Over WSCC
-Path 15 . . . . . . . . . . . . 55 i
6.3.3 Notice of Curtailment . . . . . 57 6.3.4 Replacement Power . . . . . . . 58
- 6.4 Transaction Points . . . . . . . . . . . . 59 60
~
6.4.1 Imports and Exports . . . . . . 6.4.2 Interconnection Agreement . . . 60 6.5 Deletion of Transaction Points . . . . . . 62 , 6.6 Requests for Transaction Points and Establishing Levels of Maximum , Simultaneous Demand ("MSD") . . . . . . . 62. 6.6.1 Notification . . . . . . . . . 63 l 6.6.2 Ten-Day (10-Day) Response . . . 64 6.6.3 Service Available Based on Ten-l Day (10-Day) Response . . . . . 65 6.6.4 Sixty-Day (60-Day) Study i Required . . . . . . . . . . .- 66 4 6.7 Service Available Based on Sixty-Day (60-Day) Study . . . 67 Upgrade Study'. 67 6.7.1 . . . . . . . . 6.7.2 Construction Required . . . . . 67-1 6.7.3 Information Regarding Studies . 68 6.7.4 Network Transmission Service-j' Provided Under Special Conditions . . . . . . . . . . 68 g3 < 6.7.5 Informational Review . . . . . 69
\'- 6.7.6 Expedited Procedures for
- Disputes Regarding Unavailability of Network .
( < Transmission Service . . . . . 69 6.7.7 Costs of Studies . . . . . . . 70 . l l 6.7.8 Availability of Curtailable Service on WSCC Path 15 . . . . 70 ] 70 6.8 No Service to PG&E Retail' Customers . . .
- 6.9 Use Of Transmission Service By Third Parties . . . . . . . . . . . . . . . . . 71 i 6.10 Transmission and Distribution
- Losses . . . 71 4
72 7.0 BILLING AND PAYMENT . . . . . . . . . . . . . . . Billing . . . . . . . . . . . . . . . . . 72 7.1 Payments . . . . . . . . . . . . . . . . . 72 7.2 Disputed Bills . . . . . . . . . . . . . . 72 7.3 Notice of Dispute . . . . . . . 72 ' 7.3.1 7.3.2 Escrow Account . . . . . . . . 73 Applicable Interest Rate . . . . . . . . . 73 7.4 Effect of Non-Payment - Default . . . . . 74 1 7.5
. . . . . . . . . . . . . . 74 I E.0 GENERAL PROVISIONS .
74 8.1 Appendices Incorporated . . . . . . . . . 4 E w v
B.2 Default . . . . . . . , . . . . . . . . 75 8.2.1 Remedy for Default . . . . 75 7-~ Other Remedies for Default ( 8.2.2 . . 75 Assignment 8.3 . . . . . . . . . . . . . . 75 8.3.1 Assigument By Consent . . . . . 76 l 8.3.2 Assignee Cbligationc . . . . . 76 i 8.3.3 Assignor Obligations . . . . . 75 8.3.4 No Assignment of Transmission Service . . . . . . . . . . . . 76 8.4 Captions . . . . . . . . . . . . . . . . . 77 8.5 Construction of Agreement . . . . . . . . 77 8.6 Control And Ownership of Facilities . . . 77 8.6.1 Ownership . . . . . . . . . . . 77, 8.6.2 Parties' Obligation . . . . . . 77 8.7 Cooperation and Right of Access and Inspection . . . . . . . . . . . . . . .. 78 8.8 Dispute Resolution . . . . . . . . . . . . 78 8.9 Expansion of Obligations or Material , Modification . . . . . . . . . ( ... . . 78 8.10 Governing Law . . . . . . . . / . . . . . - 79 8.11 Information . . . . . . . . . . . . . . . 79 8.12 Judgments and Determinati;ons . . . . . . . 79 1B.13 Liability . . . . . . . . . . . . . . . . 80 8.13.1 To Third Parties . . . . . . . 80 8.13.2 Between the Parties . . . . . . 80 l 8.13.3 For Electric Disturbance . . . 80 8.13.4 For Interruptions . . . . . . . 81 8.14 Limited Service . . . . . . . . . . . . . 81 k- 8.15 No Agreement to Serve Others . . . . . . . 81 8.16 No Dedication of Facilities . . . . . . . 81 82 8.17 No Precedent . . . . . . . . . . . . . . . 8.18 No Third-Party Beneficiaries . . . . . . . 82 8.19 Notices . . . . . . . . . . . . . . . . . 82 8.19.1 Formal Notices . . . . . .. . . 82 8.19.2 Designation of Notice Requirements . . . . . . . . . 82 8.19.3 Routine Notices . . . . . . . . 83 8.19.4 Changes of Notice Recipient . . 83 8.20 Procedures, Rules, and Regulations . . . . 83 8.21 Proprietary or Confidential Information . 84 8.21.1 Information Release . . . . . . 84 8.21.2 Notice . . . . . . . . . . . . 84 8.21.3 Examination . . . . . . . . . . 84 8.21.4 Disclosure . . . . . . . . . . 84 8.22 Restricted Use of Confidential DPS 85 Information . . . . . . . . . . . . . . . Specificity of Power Calculations . . . . 85 8.23 56 8.24 References . . . . . . . . . . . . . . . . Severability . . . . . . . . . . . . . . . 86 8.25 87 8.26 Uncontrollable Force . . . . . . . . . . . Unilateral Rate Changes . . . . . . . . . 87 8.27 l vi
_ _ _ _ . _ _ _ _ _ _ _ . _ . _ . . _ _ _ ~ . _ _ _ _ . _ _ _ . _ _ . _ . _ _._ -._ _ _ _ _ _ _ ___ h . l i r ! 8.28 Transmission Tariffs and Third Party 1 Agreements . . . . . . . . . . . . . . . . EE
] ) 8.29 8.30 Waiver of. Rights .
Filing Agreement with FERC . . . .
. . . . . . . . . . . . 89
. . . . 89 8.31 Integration . . . . . . . . . . . . . . . 89
- 8.32 Signatures . . . . . . . . . . . . . . . . 90
'. Appendix A . DISPUTE RESOLUTION AND ARBITRATION . . . . . . . . . . A-1 1 . A.1 GENERAL . . . . . . . . . . . . . . . . . . . . . A-1 i A.2 SCOPE , . . . . . . . . . . . . . . . . . . . . . A-1 1 1 A.3 NEGOTIATION . . . . . . . . . . . . . . . . . . . A-2 i A.4 MEDIATION . . . . . . . . . . . . . . .' . . . . . 'A-2 A.4.1 Request for Mediation . . . . . . . . . . A-2 i A.4.2 Selection of Mediator . .. . . . . . . . . A-2 , Mediation Procedure . A.4.3 . . . . . . . . . . A-3 j A.5 ARBITRATION . . . . . . . . . . . . . . . . . . . A-4 A.5.1 Demand . . . . . . . . . . . . . . . . . . A-4 A.5.2 Selection of Arbitration Panel . . . . . . A-5 ,E 4 A.S.3 Discovery . . . . . . . . . . . . . . . . A-6 l~[\w- A.S.4 A.5.5 Pre-Hearing Conference . . . . . . . . . . Hearing Location and Time . . . . . . . . A-7 A-7 i ' A.5.6 Panel's Decision . . . . . . . . . . . . . A-8 A.5.7 Remedies . . . . . . . . . . . . . . . . . A-9 l A-9 A.5.8 Award of Costs . . . . . . . . . . . . . . i A.5.9 Settlement . . . . . . . . . . . . . . . . A-9 A.5.10 Confidentiality . . . . . . . . . . . . . A-10 A.5.11 Party Representative . . . . . . . . . . . A-10 l A.5.12 Costs Prior to Award . . . . . . . . . . . A-10 A.5.13 Enforcement . . . . . . . . . . . . . . . A-11 A.5.14 Effect of Noncompliance . . . . . . . . . A-12 A.5.15 Agreement to Oppose Third-Party Challenge A-12 j i 4 Appendix B 4 SCHEDULING . . . . . . . . . . . . . . . . . . . . . . B-1 GENERAL . . . . . . . . . . . . . . . . . . . . . B-1 B.1 B-2 B.2 DAILY PRESCHEDULE . . . . . . . . . . . . . . . . DPS Pool Schedule . . . . . . . . . . . . B-2 B.2.1 Schedules on the Intertie . . . . . . . . B-2 B.2.2 O V vii
4 B.2.3 All Schedules . . . . . . . . . . . . . . B-2 B.2.4 Changes to the Daily Preschedule . . . . . 53 B.3 SCHEDULE OF THE' DAY . . . . . . . . . . . . . . . B-3 B.3.1 Allocation Basis Resources ("ABRs") . . . B-5 B.3.2 . Controlling Basis Resources ("CBRs") . . . B-5 B.3.3 Non-EA Resources . . . . . . . . . . . . . B-5 B.3.4 Imports . . . . . . . . . . . . . . . . . B-6 B.4 DEVIATION ENERGY . . . . . . . . . . . . . . . . . B-6 B.5 CHANGES TO FINAL SCHEDULES-FOR EACH HOUR AFTER THE TWENTY MINUTE LOCKOUT-POINT . . . . . . . . . . . B-6. B.5.1 Conditions for Schedule Changes . . . . . B-6 B.5.2 Notification . . . . . . . . . . . . . . . B-7 B.6 BIWEEKLY'AND MONTHLY REPORTS . . . . . . . . . . '. B-8 B.7 RECONCILIATION OF. ACTUAL AND SCHEDULED DATA , . . ,B-8 B.8 INFORMATION TO BE SCHEDULED BY DPS . . . . . . . . B-9 B.8.1 General Information Requirements . . . . . B-9 B.8.2 Required Schedules . . . . . . . . . . . . B-9 B.9 CHANGES IN SCHEDULING PROCEDURES . . . . . . . . . B-11 Appendix C EXPEDITED PROCEDURES FOR TECHNICAL DISPUTES . . . . . . C-1 C.1 INTRODUCTION . . . . . . . . . . . . . . . . . . . . C-1 C.1.1 Appointment of Technical Mediator . . . . C-1 C.1.2 Scope of Disputes Subject to Resolution by the Technical Mediator . . . . . . . . . . C-2 C.1.3 Use of Technical Mediator to Resolve Appendix C Disputes . . . . . . . . . . . C-3 C.1.4 Decision by Technical Mediator: Relating to Transmission Services . . . . . . . . . C-4 C.1.5 Decision by Technical Mediator on a Section 8.20 Dispute . . . . . . . . . . C-6 C.1.6 Applicability of Appendix A Procedures . . C-6 Appendix D RATES AND BILLING DETERMINANTS . . . . . . . . . . . . D-1 D-1 D.1 INTRODUCTION . . . . . . . . . . . . . . . . . . . 5 viii
I 4 D.2 AGC REGULATION SERVICE . . . . . . . . . , . . . . D-1 D.2.1 Rate . . . . . . . . . . . . . . . . . . D-l\ ) D.2.2 Charge . . . . . . . . . . . . . . . . . . D-1
; D 2.3 AGC Regulation Shortfall Charge . . . . . D-2 1
- D.3 INTER-HOUR LOAD BALANCING ("IHLB") SERVICE . . . . D-2 -
D.3.1 Rates . . . . . . . . . . . . . . . . . . D-2 )
- D.3.2 Minimum IHLB Purchase . . . . . . . . . . D-3 !
- D.3.3 Charge . . . . . . . . . . . . . . . . . . D-3 D.4 SPINNING RESERVE SERVICE . . . . . . . . . . . . . D-3 3
D.4.1 Rate . . . . . . . . . . . . . . . . . . . D-3, D.4.2 Charges . . . . . . . . . . . . . . . . . D-4. D.5 MONTHLY BILLING CHARGE . . . . . . . . . . . . . . D-4
- D.5.1 Rate . . . . . . . . . . . . . . . . . . . D-5 j D.5.2 Charge . . . . . . . . . . . . . . . . . . . . D-5 D.6 ADDITIONAL ENERGY EXCHANGE BAND . . . . . . . . . .D-5
- D.6.1 Billing Determinant . . . . . . . . . . . D-5 D.6.2 Rate . . . . . . . . . . . . . . . . . . . D-5 D.6 3
. Charge . . . . . . . . . . . . . . . . . . D-5 D.7 OVERGENERATION AND UNDERGENERATION CHARGE . . . . D-6 D.7.1 Overgeneration Charge . . . . . . . . . . D-6
~ D.7.2 Undergeneration Charge . . . . . . . . . . D-7 D.7.3 Charges . . . . . . . . . . . . . . . . . .D-B 3 - ( 4
'-) D.8 NETWORK TRANSMISSION SERVICE . . . . . . . . . . . D-10 D-10 D.8.1 Applicability . . . . . . . . . . . . . .
D.8.2 Rates . . . . . . . . . . . . . . . . . . D-11 . D.8.3 Charges . . . . . . . . . . . . . . . . . D-11 D.B.4 Upgrade Charges . . . . . . . . . . . . . D-11 D.9 REPLACEMENT POWER . . . . . . . . . . . . . '. . . D-12 l D.9.1 Billing. Determinants . . . . . . . . . . . D-12 Rate . . . . . . . . . . . . . . . . . . . D-13 4 D.9.2 D.9.3 Charge . . . . . . . . . . . . . . . . . . D-13 8 i i Appendix E i E-1 ! ENABLING AGREEMENT . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . E-2 ENABLING AGREEMENT SCHEDULE A i
Appendix F F-1 METERING REQUIREMENTS . . . . . . . . . . . . . . . . . k( . lx
~ . _ _ . . _ _ ._- ___- _._____ .___- _ . . _ _ _ _ _ _ . _ .
i l a i F.1 GENERATION RESOURCES DIRECTLY CONNECTED WITH l PG&E'S ELECTRIC SYSTEM . . . . . . . . . . . . . . :_ j F.2 ' GENERATION RESOURCES WITHIN THE PG&E CONTROL AREA BUT NOT DIRECTLY CONNECTED WITH PG&E'S ELECTRIC SYSTEM . . . . . . . . . . . . . . . . . . . . . . F-1 F.3 DPS CUSTOMERS WITHIN THE PG&E CONTROL AREA . . . . F-1 F.4 RESOURCES AND LOADS OUTSIDE OF THE PG&E CONTROL AREA . . . . . . . . . . . . . . . . . . . . . . . F-2 Appendix G SOUTH OF TESLA PRINCIPLES . . . . . . . . . . . . . . . G-1 Appendix H TIME PERIODS . . . . . . . . . . . . . . . . . . . . . H-1 . l H.1 TIME PERIODS . . . . . . . . . . . . . . . . . . . H-1 Appendix I l UTILITY IDENTIFIERS AND TRANSACTION CODES . . . . . . . I-1 j Appendix J DPS REQUIREMENTS FOR AGC REGULATION AND SPINNING RESERVE J-1 J.1 PURPOSE . . . . . . . . . . . . . . . . . . . . - J-1 I J.2 OBLIGATION . . . . . . . . . . . . . . . . . . . . J-1 C.3 AGC REGULATION . . . . . . . . . . . . . . . . . . J-1 J.3.1 DPS Contributes to Control Area . . . . . J-1 J.3.2 DPS Provides AGC Regulation' Service Itself . . . . . . . . . . . . . . . . . . J-5 J.4 SPINNING RESERVE . . . . . . . . . . . . . . . . . J-6 J.4.1 Operating and Testing Requirements . . . . J-6 J 4.2 Non-Performance . . . . . . . . . . . . . J-7 x
g, -- .amem.a - .a --.4km & 4 mn .m4+.eaa e. $-L.,--a4-.& M & . a -- a- .s-mi. ~ a.~-a o sJm --- l 4 4 Appendix K NETWORK TRANSMISSION SERVICE TABLE . . . . . . . . . .,.. .. . ] a 1 e i i b i i i / e Xi
4
.i i ; 4 4
f a 4
.i i
1 1, 4 i s d 1 1 1 i i d 4 4 j i , e 1 e i ! Attachment 1 i ! CONTROL AREA AND TRANSMISSION SERVICE AGREEMENT i 4 L 4 I 1 i. k 4 i i 4 t } k j m t k A i i 4 e i l' { j j i J 4 d 1
i i 4 i( t i i 1 J 1 4 1 i i i j . J 1 4-4 CONTROL AREA li
; AND i
TRANShDSSION SERVICE AGRFIMENT 4 i 4 BrawtzN 1 1 1 - DESTEC POWER SERVICES, INC. i 1 4 ANT) PACIFIC GAS AND ELECTRIC CONTAhT a t 3 i i i d 1 4 d i
)
-,3
1 CONTROL AREA AND TRANSMISSION SERVICE AGREEMENT 2 BETWEEN 4
'v DESTEC POWER SERVICES, INC. '
3 g,p 4 . PACIFIC GAS AND ELECTRIC COMPAhT i 5 , 6 This Control Area and Transmission Service Agreement 7 (" Agreement") is made and entered into this 29th day of November, 4 8 1994, by and between Pacific Gas and Electric Company ("PG&E"), a i 9 California corporation, and Destec Power Services, Inc ("DPS"), 1 10 a Delaware corporation. (PG&E and DPS are sometimes referred to herein individually as " Party" and collective'ly as " Parties").
^
! 11 t 12 RECITALS 13 A. PG&E, a corporation organized under California law, is a 14 public utility engaged, among other things, in generating,
'O i
g 15 transmitting, and distributing electric power in northern and ^ 16 central California and is the Control Area Operator for such 17 region. 18 B. DPS, a corporation organized under Delaware law, is 19 engaged in the sale of electric energy and other energy services. , 20 DPS is not a public utility under California law and does not own 21 electric generation, transmission or distribution facilities as 22 defined by California law. 23 C. DPS intends to enter into contracts to purchase electric 24 power with entities located within and outside of PG&E's Control 25 Area and to aggregate or pool such power and market or broker 26 such power to Third Parties. 27 D. Among the entities from which DPS intends to purchase I J 28 power are QFs in PG&E's Control Area that provide electric power I 4
._. _ . . . . _ __ _. _ = _ _ -. _ _ _ _ . _ _ _ . _ .. _._-. _..
I 6 1 to PG&E pursuant to various power purchase agreements. DPS 4 1
/\ 2 intends to purchase from certain QFs in PG&E's service area some
(_) or all of the Excess Power, as defined below, which the QFs could 3 4 otherwise sell to PG&E pursuant to their respective power 5 purchase agreements. When DPS submits a final schedule in 6 accordance with Appendix B for the sale of such power, PG&E's ! l 7 obligation to purchase from the QF the amount of such power ]
\
8 scheduled by DPS is extinguished. Any amount of the Excess Power j 9 that is not scheduled for sale by DPS will continue to\be sold by ; 10 the QF to PG&E under the QF's power purchase agreement. l 11 Concurrent with the execution of this Agreement, PG&EanhDPSare 12 executing an Enabling Agreement which contains a protocol for l 13 accounting for the power generated by these QFs which is sold to 14 DPS separate from the power which would continue to be sold by j () 15 the QFs to PG&E pursuant to the QF's respective power purchase 16 agreements. 17 E. This Agreement specifies certain Control Area standards 18 which DPS has agreed to meet either through purchase of services 19 from PG&E (or a Third Party) and/or through the provision of such 20 services itself. By purchasing and/or providing these services, 21 DPS will ensure that its resources and loads are in balance; that 22 it provides for necessary Control Area Services; and that DPS'
^
23 transactions do not jeopardize the stability or safety of the 24 PG&E Control Area. 25 F. This Agreement further provides that PG&E will provide 26 to DPS Network Firm Transmission S_e;yipa *k=t permits DPS to 27 specify a number of generation Input Points and load Output N/ 28 Points (and Control Area Interchange Points for Imports and 2
t 1 exports) and to transmit electric energy from Input Points to di : I ; [~N 2 specified Output Points. This Network Transmission Service is l \s-3 not available for DPS to wheel electric energy to retail ] 4 customers located within PG&E's utility service territory. j 5 NOW, THEREFORE, in consideration of the mutual promises and l l 6 obligations stated herein, and other good and valuable 7 consideration, the receipt and sufficiency of'which are hereby 8 acknowledged, the Parties, intending to be legally bound, hereby 9 agree as follows: 10 , 11 1.0 DEFINITIONS 12 The following terms, when used in'this' Agreement with 13 initial capitalization, whether singular, plural or possessive, 14 shall have the following meanings. O ( ,/ 15 1.1 AGC Control Load: The amount of DPS' Load whose AGC 16 Regulation requirements DPS is satisfying by placing capacity 17 from DPS Resources under PG&E control in accordance with 18 Section 4.1.5. 19 1.2 AGC Reaulation Load Effective: The amount of DPS' 20 Load whose AGC Regulation requirements which are ultimately 21 deemed to be satisfied by PG&E as detennined in Section 4.1.6. 22 1.3 AGC Reaulation Load Reserved: The amount of DPS' 23 Load whose AGC Regulation requirements DPS reserved to be 24 provided by PG&E pursuant to Section 5.1.1. 25 1.4 AGC Reaulation: The use of generation capacity 26 reserves to perform Automatic Generation Control. PG&E provides 27 a Control Area Service to meet this requirement which is k 28 described in Section 4.1. 3
i 1 1.5 Allocation Basis Resource I"ABR"): An EA Resource as* i 2 defined in Section 3.2.2. {s 3 1.6 Annual Firm Service: Firm Network Transmission 4 Service offered for a term.of one year or more, as described in 5 Section 6.1.4.1. 1 6 1.7 Annendix C Discute: A dispute subject to assessme'nt 7 by the Technical Mediator and identified in Section C.1.2. 8 1.8 As-Available OF Power: Energy and/or as-delivered k 9 capacity sold to PG&E, under a PPA, which exceeds the. PPA Firm 10 Capacity level as defined in Section 1.60. , , 11 1.9 Automatic Generation Control ("AGC"): The regulation 12 and control of'the power output of ele'ctric generators within a-13 prescribed area typically in response to changes in system 14 frequency, net tie-line loading, and time. error correct' ion so as T 15 to maintain the scheduled system frequency and established ~ 16 interchange schedules with other Control Areas or other 17 prescribed .r.reas within predetermined limits. AGC is 18 accomplished by hardware and software equipment set to adjust 19 specific generation units automatically via an electronic error
~20 signal sent from a central location.
21 1.10 Available Transmission Cacacity: That amount of l 22 transmission capacity available to DPS which is not reasonably 23 required during the term of this Agreement to accommodate PG&E's: 24 (i) ex4 ,st6g'and re sonably forecasted customer load for which 25 PG& y statue, fr nchise, contract or federal or state 26 regu .ation, h the obligation to plan, construct or operate its 27 system to provide reliable service; (ii) existing contractual 28 commitments for firm wholesale. purchases, exchanges, deliveries 4
- -. ~- - - .~..-_.- . - .- .- - . . - ._~. -
1 and sales (where not included-in (i), above); (iii) existing , n e' 2 contractual, statutory and regulatory commitments for firm u' 3 transmission service (where not included in (i), above); and (iv) 4 reliability and safety needs in accordance with Prudent Utility l 5 Practice. l 6 1.11 Billino Period: 0001 hours of the first day to 2400 ] i 7 hours of the last day of each calendar month. i 8 1.12 California-Orecon Border (" COB"): The Control Nrea l 9 Interchange Points between Bonneville Power Administration's and l 10 PG&E's Control Areas. l I 11 1.13 California Power Pool: The power-sharing arrangement i
; 12 established among PG&E, Edison and San Diego Gas & Electric
- 13 Company by the California Power Pool Agreement dated July 20, 1 14 1964 and associated rulings.
1 15 1.14 Certificate of Public Convenience'and Necessity ([ 16 ( " CPCN") : A Certificate of Public Convenience and Necessity 17 issued by the CPUC pursuant to Section 1001 gi gl. of the 18 California Public Utilities Code. 19 1.15 Control Area: A balanced portion of an overall 20 electric power system, in which the electric generating resources 21 and net interchanges with other Electric Systems operating a 22 Control Area are controlled in order to meet the total load 23 responsibility in that portion of the overall electric power 24 system as set forth in NERC, WSCC, and California Power Pool 25 operating and reliability criteria. 26 1.16 Control Area Interchance Point: A Transaction Point 27 where power flows between PG&E's Control Area and another Control b
\/ 28 Area, currently Midway Substation (Edison), Malin Substation 5
I i 1 (Bonneville' Power Administration), Summit Substation (Sierra di 2 Pacific Power Company), and Delta Metering Station (Facific Power (~')i
\_ -
i 3 & Light). 4 1.17 Control Area Services: Necessary services that DPS
- i~
l 5 must either provide itself, and/or purchase from PG&E or other ! 6 in-area entities under this Agreement. These services are l 7 specified in Section 4. ) 8 1.18 Contro11ina Basis Resource'("CBR"): Jul EA Resource l 9 as defined in Section 3.2.3. '. 10 1.19 Coste: Costs shall l.nclude, as applicable, (a) all 11 capital expenditures, taxes, depreciation, and expenses of 12 operation, maintenance, engineering, a'dministration and general' 13 expenses, and any other applicable' costs, as determined in 14 accordance with the then-current FERC Uniform System of Accounts () 15 or its successor, and (b) if construction is required, cost of 16 canital. i 17 1.20 Cost of Service: PGEE's embedded costs, which among 18 other things, have been expressed as an annual revenue 19 requirement, and classified or functionalized (i.e., production, 20 transmission, distribution and customer) or any successor 21 expression of PG&E's embedded costs. The cost components include 22 maintenance, operation, administrative and general, taxes, 23 depreciation and recurn. C2HC: The Chlifornia Public Utilities Commission, or 24 1.21 25 its regulatory successor. 26 1.22 DPS Control Area Resource: Any entity supplying j (i . e. , 27 electric power to DPS located within PG&E's Control Area EA Resources and non-EA Resources). 28 f !
l 1 1.23 DPS Load: Electric load that is served by the DPS dli ( 2 Pool.
)
3 1.24 DPS Pool: A power pool comprised of power purchased 4 by DPS from DPS Suppliers and from which DPS sells power to Third 5 Parties. 6 11.25 DPS Pool Enerov: The amount of energy to be credited 7 to the DPS Pool for any Half-Hour Period pursuant to the 8 provisions of Section 3.2. I 9 1.26 DPS Power Control Center: DPS' central location for 10 scheduling and controlling power flows into and out of tile DPS 11 Pool. 12 1.27 DPS Sueolier: Any entity supplying electric power to 13 DPS, including DPS Control Area Resources (i.e., EA. Resources and 14 Non-EA Resources), and entities located outside PG&E's Control () 15 Area. EA Resource: Defined in Section 2.5 of the Enabling 16 1.28 17 Agreement as a PPA QF Supplier which has been approved pursuant 18 to Section 5.2 of the Enabling Agreement to sell Excess Power to 19 DPS. 20 1.29 Edison: Southern California Edison Company, or its 21 successor. 22 1.30 Effective Date: The date upon which this Agreement 23 first becomes effective, as specified in Section 2.1. 24 1.31 Electric System: All physically connected properties 25 and other assets, now or hereafter existing, owned or controlled
-26 by a single entity, used for, or pertaining to, the generation, 27 transmission, transformation, distribution, or sale of electric 28 power and energy, including all additions, extensions, 7
l l r , l _ 1 expansions, and improvements, but excluding affiliates, *!i l 2 subsidiaries and parents, and their properties and assets. 3 1.32 Emeroency: An unplanned or unexpected operational 4 event, series of operational events, or operational circumstance i j 5 that (a) causes a sudden or immediate loss or interruption of (1) 6 a Party's generating resources, (ii)-PG&E's' transmission ! 7 resources due to equipment failures, or (iii) a Third Party's j 8 ability to receive or deliver power as scheduled, and (b) in the l 9 judgment of.the affected Party's operator, consistent'.with 10 Prudent Utility Practice, requires the taking of immediate 11 action, (i) to preserve, maintain, or reestablish the safety, l 12 integrity, or operability of the facilities that have been 13 af f ected and -(:Li) to meet native load within PG&E's service area 14 (if applicable) or DPS' firm contractual commitments, as 15 applicable. Insufficient prime-mover energy shall be considered 16 an Emergency only when such insufficiency results from equipment 17 failure. Drought or insufficient geothermal steam, fossil fuel, 18 or other shortages of prime-mover energy shall not be considered 19 an Emergency unless caused by equipment failure. -In addition, 20 losses or interruptions resulting from the :following events shall j 21 no; be considered Emergencies: (a) recurring or chronic i 22 operational, maintenance,'or contractual problems, (b) failures i 23 of. generating resources to start up on demand for reasons other 24 than equipment failure, (c) pre-scheduled curtailments or pre-25 scheduled interruptions of power or transmission service, 26 (d) curtailments or interruptions of power or transmission
- 27 service that occur with advance notice of at least two hours, or 28 (e) curtailments or interruptions of power or transmission 8
-- r- .,m v --w,, w g
l l I 1 service that occur without notice where such curtailment o- ( , 3 2 interruptions can reasonably be expected and should be planned d 3 for consistent with Prudent Utility Practice. In determining ! 4 whether a Party has suffered a bona-fide Emergency, especially 2 5 regarding whether a particular curtailment or interruption of ! 6 service could reasonably have been anticipated by that Party, the 7 other Party shall give due consideration to the standards , , l 8 applicable to planning for contingencies in keeping with Prudent j 9 Utility Practice. . j 10 1.33 Enablina Aareement ("EA"): The agreement between 11 PG&E and DPS being concurrently executed and attached hereto as 12 Appendix F. l 13 1.34 Enerav Deviation: The energy deviation calculated in l 14 accordance with Section 4.6.4. () 15 16 1.35 Enerov Exchance Band: An energy ban'd within which hourly deviations are returned to each Party during the next 17 like-time period; provided that the Energy Deviation for that 18 hour is not greater than the width of the Energy Exchange Band. 19 1.36 Excess Power: Capacity and associated energy 20 available to be scheduled by DPS from an EA; Resource as defined 21 in Section 2.6 of the Enabling Agreement to the DPS Pool. 22 1.37 Exchance Enerav: Energy to compensate for the net 23 deviations within the Energy Exchange Band which is returned in a 24 like period in accordance with Appendix B. 25 1.38 FERC: The Federal Energy Regulatory Commission, or 26 its regulatory successor. 27 1.39 First Deviation Band: A :one between the Energy (m/ 28 Exchange Band and the Second Deviation Band which in combination 9
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b 1 1 with the Energy Exchange Band has a width of seven (7) MWh/ hours; . 2 within which DPS may incur penalties pursuant to Section 4.6.6 3 and its subsections, unless deviations are within the Energy 4 Exchange Band. t 5 1.40 Forced Outace: Any full or partial outage of a 6 Party's generating resource or PG&E's transmission facilities 7 that is caused by an Emergency. t 8 1.41 Half-Hour Period: A thirty-minute f30-minute) period , 9 beginning or ending on the hour. ', 10 1.42 Imoort: A scheduled purchase of power delivered ' 11 through a Control Area Interchange Point from'a source ou'tside 12 PG'4E's Control Area in accordance with\Section 3.2.2. I 13 1.43 Innut Point: A Transaction Point on PG&E's Electric 14 System at which DPS is authorized to have a specified amount of () 15 power from a DPS Supplier accepted for the DPS P' col, as listed in 16 Appendix K. 17 1.44 Interconnection Aareement: A contractual agreement 18 between PG&E and an electric generr ting f acility, utility, or 19 load within PG&E's Control Area which may be denominated by any 20 name and which specifies the terns and conditions of a specific 21 generating facility's, load's or utility's connection with PG&E's 22 Electric System, which may include, to the extent necessary or 23 l appropriate, but are not limited to, terms and conditions 24 concerning: (i) maximum rates of receipt and delivery at the 25 point of interconnection; (ii) spacial facilities which make up 26 the interconnection; (iii) scheduling requirements; (iv) metering 27 of :eal or reactive power for lead levels or power output over 28 specified units of time: (v) operational requirements, including 10
i c 1 curtailment rights, Emergencies, system jeopardy, unacceptable 4 ( 2 operating conditions, and minimum load; (vi) power accounting and 3 payment for deliveries; (vii) back-up and stand-by services; 4 (viii) responsibility for protective devices; and (ix) load 5 shedding. 6 1.45 Inter-Hour Load Balancine ("IHLB"): A Control Area 7 Service, described in Section 4.2, that provides for hourly, 8 matching of DPS resources with DPS Loads through changes in the 9 allocation of energy deliveries from an EA Resource t6,PG&E and 10 DPS.
'. I 11 1.46 Matchino Loads: The group of DPS' Loads that'DPS will )
I 12 match on a moment by moment basis in the manner described in : I 13 Section 4.1.2 and for purposes of complying with the AGC 14 Regulation requirements. () 15 1.47 Maximum Delivery Canability: The limit on the amount of power that DPS may have transmitted to any individual output. 16 17 Point, as set forth in Appendix K. 18 1.48 Maximum Receiet Carabilitv: The limit on the amount 19 of power which DPS may have transmitted from any individual Input 20 Point, as set forth in Appendix K. 21 1.49 Maximum Simultaneous Demand ("MSD"): The amount of 22 Network Transmission Service requested by DPS and designated by 23 PG&E as available for DPS' use as specified in Appendix K. The 1 24 Maximum Simultaneous Demand, which is further described in l 25 Section 6.1, establishes DPS' monthly obligation to pay for 26 transmission service and PG&E's monthly obligation to provide 27 transmission service. As specified in Appendix D, DPS shall 09 28 establish a separate MSD for transmission voltage service and 1 I 11 I
1 distribution voltage service. e l 2 1.50 Minimum Load Conditions: The condition that exists 3 when PG&E's on-line oil / gas-fired steam units aI all within I 4 their minimum operating ranges, subject to any constraints 5 requiring a unit or units to run above minimum to maintain system i 6 integrity, with due allowance for the need for Control Area i 7 regulation consistent with Prudent Utility Practice, and any 1 8 further reduction in generation would not be consistent with ! l 9 Prudent Utility Practice. . 10 1.51 NERC: The North American Electric Reliability 11 Council or its successor. 12 1.52 Network Transmission Service: Transmission service l l 13 provided to DPS under Section 6. i 14 1.53 Non-EA Resource: A DPS Control Area Resource that is () 15 not an EA Resource. 16 1.54 Non-Matchina Loads: Each DPS Load which is not - 17 included in the Matching Loads group as provided for in ; l 18 Section 4.1.2. I 19 1.55 Northern Zone DPS Resource: An EA Resource or Non-EA f
)
20 Resource located in PG&E's Control Area north of Tesla substation 21 which has the potential of physically contributing to excess line 22 loading on WSCC Path 15 in a north-to-south direction and which 23 is designated in Appendix K. 2 1.56 Outout Point: A Transaction Point on PG&E's Electric System at which DPS is authorized to have a specified amount of 1 6 power from the DPS Pool delivered to a Third Party, as listed in s 2 V Appendix K.
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28 1.57 PG&E Enerov: The amount of energy credited as 12
_____ ._ .. .. _ . _ . _ . _ _ _ _ . . _ - _ __ _ _ _ _=__ _ __ . _ _ _ _ . _ _ . . 1 delivered to PG&E for any Half-Hour Period pursuant to the 8 I l t 2 provisions of Section 3.2. ! l 3 '1.58 PG&E Enerav Control Center: PG&E's central system j 4 dispatch center for its Control Area. 5 1.59 EEA: A power purchase agreement between a QF and ; I l: 6 PG&E. t l 7 1.60 PPA Firm Cacacity: The contract or firm capacity i 8 level, if any, specified in the PPA between the EA Resource and l l 9 PG&E. . 10 l'.61 Prudent Utility Practice: Those practices, methods, 11 and acts, includingprovisions-forcontingendies,asmodkfied 12 from time-to-time, that are used (a) tb operate an Electric 13 System dependably, reliably, safely, efficiently, economically, 1 14 and in accordance with all applicable laws and governmental
~15 rules, regulations, and orders, -(b) to serve a titility's own 16 customers and, (c) to prevent adverse effects on neighboring 17 systens and Control Areas. Such practices, methods, and acts 18 shall consist of those (a) engaged in or approved by, and (b) 19 commonly used by utilities which: (1) are members of the WSCC; 20 and (2) . schedule across an interconnection;with another Third 21 Party utility. This standard shall govern all actions by either 22 Party under this Agreement.
23 1.62 QE: A cogeneration or small power producer that .i 1 24 meets the criteria set forth in 18 C.F.R. S 292.203. 25 1.63 Scheduled Transactions: Power transactions where the ! ! 26 quantity of power delivered is deemed constant throughout the 27 schedule period, regardless of the customer's actual consumption. 28 1.64 Second Deviation Band: An energy zone within which 1 13
1 DPS may pay a disincentive rate as described in Section 4.6.6.
/~N 2 1.65 Short-Run Avoided Cost I"SRAC"\: The then-current ~'
3 rate at which PG&E purchases QF power under certain PPAs. The 4 SRAC energy price is currently published each month f oi u.f ferent 5 time of day periods, and corresponds to the energy price paid to 6 EA Resources for as-available energy. 7 1.66 Short-Term Firm Servi,qt: Fimm Network Transmission 8 Service offered in monthly increments for a minimum of one month 9 and a maximum of twelve (12) months as described in 10 Section 6.1.4.2. 11 1.67 Southern Zone DPS Resource: An EA Resource or Non-EA 12 Resource located in PG&E's Control Area south of Tesla substation 13 which has the potential of physically contributing to excess line 14 loading on WSCC Path 15 in a south-to-north direction and which 15 is designated in Appendix K. (n) 16 1.68 Sein Service Effective: The amount of Spinning 17 Reserve deemed to have been provided by PG&E as provided for in 18 Section 4.3.4. 19 1.69 Sein Service Reserved: The amount of Spinning 20 Reserve service that DPS reserves for PG&E to provide in 21 accordance with Section 5.1.3. 22 1.70 Soinninc Reserve: Available, unloaded generating 23 capacity resources that are operating and synchronized to an 24 electric System, are able to take load on demand from Automatic 25 Generation Control equipment, supervisory control, or manual 26 control by an operator located on duty at the generating 27 resource, and are capable of assuming load up to the cited r~ Spinning Reserve magnitude within ten (10) minutes. Such k_)N 28 14
, . . _ - _ - - ~ _ _ _ _ . . _ . _-- .
I capacity shall be required to carry load for at least two (2)
- 2 hours. Spinning Reserve is provided from generation located 3 within PG&E's Control Area, and is required to meet the needs of 4 the Control Area when there is a sudden loss of generation, 5 misforecast load or other contingency on the System.
6 1.71 Soinnino Reserve Recuirement: Spinning Reserve that 7 DPS shall maintain at all times pursuant to Section 4.3. 8 1.72 Transaction Points: Input Points and Output Points 9 as described in Section 6.4 and Appendix K. Transaction Points 10 have the following characteristics: . . 11 (a) Points where power physical'ly enters PG&E's. I 12 Electric System from DPS Control Area 1 13 Resources; 14 (b) Points where power is physically taken off the 15 PG&E Electric System for consumption at a load; 16 (c) Control Area Interchange Points; 17 (d) Points contractually designated as transmission 18 service transfer points under existing 19 transmission service agreements to which PG&E j 20 is a party; j 21 (e) The California-Oregon Transmission Project for 22 purposes of exports and imports of power to the 23 Pacific Northwest; or _ 24 (f) Points for transactions as mutually agreed upon 25 by the Parties. 26 1.73 Transmission Carability on WSCC Path 15: The 27 transfer ability, expressed in megawatts, of PG&E's transmission 28 system to transmit electric energy between Midway Substation and 15
i 1 l Tesla Substation, which is determined by PG&E in its sole 2 judgment, consistent with Prudent Utility Practice, to be the gg,\ 3 maximum power transfer ability of the transmission system under 4 operating conditions existing at the time of determination. , 5 1.74 Third Party: Any entity other than'DPS or PG&E. 6 1.75 Uncontrollable Force: Any cause or causes beyond the 7 control of and without the fault or negligence of a Party which 8 renders it unable to perform an obligation, including,.but not 9 limited to, failure of or threat of failure of facilities caused 10 by flood, earthquake, volcanic activity,. tornado, storm, drought, 11 fire, pestilence, lightning and other natural catastrophhs, 12 epidemic, war, riot, civil disturbance'.or disobedience, ; 13 vandalism, strike, labor dispute, labor or material shortage, 14 sabotage, terrorism, governmental priorities or restraint by 15 court order or public authority, and ration or non-action by or 16 inability to obtain or maintain in effect any necessary 17 authorization or approval from any governmental agency or 18 authority, which by the exercise of due diligence such Party 19 could not reasonably have been expected to avoid and which by the 20 exercise of due diligence it has been unable to overcome. 21 Nothing contained in this Section 1.75 shall be construed as 22 requiring a Party to settle'any strike, lockout, or labor dispute 23 in which it may be involved, or to accept any permit, 24 certificate,-or other authorization that contains conditions or 25 terms the Party determines, in good faith, are unduly burdensome. 26 The term " Uncontrollable Forces" shall n21 mean Forced Outages, 27 scheduled curtailments or interruptions of power or transmission ( 28 service, curtailments or interruptions of power or transmission 16
1 services that occur with advance notice, or curtailments er 4 7"% 2 interruptions of power or transmission service without notice \ i x_/ , 3 that nevertheless can reasonably be expected to occur and should 4 be planned for consistent with Prudent Utility Practice. 5 Examples of curtailments or interruptions that may reasonably be 6 expected to occur are (a) single-line outages of transmission 7 facilities, (b) Forced Outages of at least one generating 8 facility, (c) drought at a hydroelectric facility, (d) loop flow 9 on the Pacific Northwest -- Southwest Intertie, and (e)l, loss or 1 10 reduction of the fossil fuel supply for a thermal unit. 11 1.76 Variable Transactions: Power transactions where the 12 quantity of power delivered varies with fluctuations in the load 13 and need not be constant throughout the schedule period. 14 1.77 Westerm Systems Power Pool Acreement: The governing e~ (x) 15. agreement that defines the marketing arrangement among members of 16 the Pool and was accepted by FERC as WSPP Rate Schedule FERC 17 No. 1. 18 1.78 Work Dav: All days except Saturday, Sunday, and i 19 WSCC-designated holidays. ! I I 20 1.79 WSGC: The Western Systems Coordinating Council, or j 21 its successor. 22 1.80 WSCC Path 15: The WSCC-designated transmission path 23 for loopflow mitigation located between PG&E's Tesla and Midway ! 24 Substations. I 25 i 26 2.0 EFFECTIVE DATE AND TERM
-s 27 2.1 Effective Date l 28 Depending upon the circumstances of FERC's 17
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I l l 1 acceptance of this Agreement, the Effective Date shall be one of 4 l
'N 2 three possible dates as specified in this Section 2.;. First, 3 the Effective Date for this Agreement shall be the date upon 4 which FERC accepts it for filing and allows it to become 1
l j 5 effective without material modification unacceptable to either 6 Party. Second, if in accepting the filing, the FERC imposes a 7 mat g oM g n, either Party may refuse to accept that 8 r material modification by providing written notige within fifteen 1 l 9 (15) days after the FERC has issued the order allowin~g the filing l l 10 to become effective. If neither Party provides such notice 11 within the fifteen (15) day period, the Parties shall be deemed i 12 to have accepted the Agreement as modified by the FERC and the 13 Effective Date shall be sixteen (16) days after the date of the 4 14 FERC order, or as agreed upon by the Parties. Third, if a Party I I l (/~^) 15 provides timely notification that it will not accept the 4 l. 16 Agreement as materially modified by FERC, the Parties shall l 17 immediately meet with the intent to revise the Agreement to be consistent with the FERC order and the Parties' re'spective 4 18 19 intents in executing this Agreement. Notwithstanding their good 20 faith. efforts, if the Parties are unable to reach agreement on 21 appropriate modification (s) and if the Party refusing to accept i - 22 the modification (s) imposed by FERC has timely filed a good faith 4 23 request for rehearing with the FERC requesting removal of the 24 unacceptable modification (s) and such request has been denied, 25 the refusing Party may provide the non-refusing Party notice to 26 terninate the Agreement thirty (30) days following the non-27 refusing Party's receipt of such notice. Such notice to 28 terminate shall include a form of modified agreement that the 18 t
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I 4 \ h 1 refusing Party would accept and if the non-refusing Party agrees 4: s f 2 to such modification, or if the Parties agree'to another ; l 3 mutually-acceptable modification of the agreement, the notice to i l 4 terminate shall be null and void, and the Effective Date shall be i 5 the date FERC~ accepts the modified agreement without material 6 modification. Absent the Parties so timely agreeing to a j 7 mutually-acceptable modification of the agreement, the Agreement 8 shall terminate thirty . (30) days after the'non-refusing Party's 9 receipt of the notice to terminate. - 10 2.2 Commencement of Service 11 Unless otherwise mutually agreed, the earliest 12 service may commence under this Agreement is on (i) the first 13 .(1st) day of the first month following the Effective Date if.it 14 is the first (1st) through nineteenth (19th) day of the month or g 15 (ii) the first (1st) day of the second month following the 16 Effective Date, if it is the twentieth (20th) day of the month or-17 later. 18 2.3 Term 19 The term of this Agreement i ive (5) years 20 commencing on the Effective Date. The Agree ent shal' _rminate 21 on midnight of the day five (5) calendar years after the ] 22 Effective Date, except as provided in Sections 2.1, 2.4, 2.5, 8.2 23 and 8.9. 24 2.4 Extension of Term 25 The term of this Agreement may be extended beyond 26 five (5) years in accordance with the following provisions: 27 (a) At least ninety (90) calendar days prior to the 28 third year after the Effective Date, either 19
1 Party provides the other Party with written 4, > ! /'N 2 notice that it desires to extend the term of l \--] this Agreement for a specified period of time; i 3 l 4 (b) Within ninety (90) calendar days of receipt of 5 such notice, the other Party responds in l 6 , writing stating whether it agrees to extend'the 7 term of this Agreement by the amount of time 8 specified by the requesting Party, or by a 9 lesser amount (" shorter extension"); Neither 10 Party is required to agree with the other 11 Party's request for extensi'on or to pr6 pose a 12 shorter extension. 11f the other Party agrees 13 to extend this Agreement by the amount 14 requested by the requesting Party, or the other () 15 Party agrees to the shorter extension, this Agreement shall continue in full force and 16 17 effect in all respects until the additional 18 amount of time agreed to by the Parties has 19 expired (subject to the early termination 20 provisions in Section 2.3); and 21 (c) Nothing in this Section 2.4 prohibits a Party 22 from requiring as a condition of extending the , 23 term of the Agreement that modifications, 24 amendments or deletions, however material, be 25 made to this Agreement; such changes to be 26 effective during the extension period. 27 j 2.5 Filine for Termination 28 # 2.5.1 Should FERC require a regulatory filing
=
s 20
i i to effectuate termination of this Agreement, such termination ej ( 2 shall be effective as of the date ordered by FERC or at the 3 expiration of the applicable suspension period set by FERC if 4 FERC has failed to act within the period. DPS hereby recognizes
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5 PG&E's right pursuant to this Section 2.5 to terminate this 6 Agreement and all rate schedules filed pursuant to this Agreement 7 and shall not oppose, directly or indirectly, the exercise of 8 such right. The Parties agree that neither Party shall be 9 required to continue to provide services based in whol,e or in 10 part on the existence of this Agreement beyond the maximum 11 statutory suspension period, if that period i's applicabls for any 12 reason, nor shall either Party attempt to defeat this intent by 13 opposing such termination or otherwise petitioning FERC for 1 14 relief in contradiction of the intent or express language of this l'h 15 Q Section 2.5. 16 2.5.2 After termination, all rights to services. 17 or rates, tenns and conditions of service provided under this 18 Agreement or any tariff or rate schedule that results from or 19 incorporates this Agreement shall cease, and neither Party shall 20 claim or assert any continuing right to such services or rates, 21 terms and conditions under this Agreement, or any richt to such 22 services or rates, terms and conditions based in whole or in part 23 on the existence of this Agreement, beyond the termination date. 24 However, any right to payment of money for transactions occurring 25 prior to the termination shall continue, and the provisions of 26 Section 7 of this Agreement and its subsections shall continue to 27 apply to such payments of money. 28 21
.1 3.0 DPS POWER SALES AND ACCOUNTING af
~( 2 DPS power transactions may involve numerous loads and ( 3 resources directly or indirectly connected with the PG&E Electric 4 System. This section discusses how PG&E will account for: (i) 5 purchases by DPS from DPS Suppliers i.e., credits of energy to 6 the DPS Pool; and (ii) sales by DPS to its customers i.e. , debits
.7 of energy from the DPS Pool. In accordance with Section 6,,DPS 8 may purchase Network Transmission Service from PG&E to 9 accommodate DPS transactions. Under Sections 4 and 5,:,DPS agrees 10 to purchase or provide for certain Control Area Services to _
11 support DPS transactions. 12 Under this Agreement, there are several classifications of 1 13 researces which may sell-to the DPS Pool. DPS Suppliers consist' 14 of the entire group of rescurces which sell to the DPS Pool. DPS 15 Control Area Resources are resources which are located within the 16 PG&E Control Area. EA Resources are QFs within the PG&E Control ! 17 Area selling to the DPS Pool in accordance with the Enabling l Non-EA Resources are resources selling to the DPS 18 Agreement. 19 Pool within the PG&E Control Area which are not EA Resources. 20 The accounting protocols in this Agreement address only 21 sales by DPS Control Area Resources: (i) to DPS; or (ii) to PG&E ] There are no accounting 22 and DPS in the case of an EA Resource. 23 protocols which address the situation where a DPS Control Area 24 Resource sells to a Third Party, DPS and PG&E where power is 25 measured through a single meter and transmitted to purchasers 26 ,using the PG&E Electric System. Accordingly, as a precondition 27 ftoDPSengagingintransactionsforwhichthisAgreementprovides O 2e =o acconnt1n, , roto =o1s. the Partses must f1rst ag,ee on any 22 i
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l 1 1 supplemental accounting procedures, if necessary, for such sales 4j t'S 2 and shall amend this Agreement accordingly, and to the exten-3 necessary, file it with FERC. The foregoing precondition does i 4 not apply to nor prevent transactions proceeding pursuant to this j 5 Agreement involving: (a) resources outside the PG&E Control Area; ] 6 (b) sales to a Third Party pursuant to Section 218 of the 7 California Public Utilities Code; and (c) any sales for which l
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8 existing metering or accounting procedures enable separation of ; 9 sales to'the Third Party from sales to PG&E and/or DP6 ' l 10 DPS' rights to receive power from DPS Suppliers at Input 11 Points or to deliver power to Output Points are subject to the 12 provisions of Section 6. 13 3.1 Curtailment 14 As specified in Section 6.3.2, Network Transmission () 15 . Service may be curtailed due to -excess line loading on WSCC Path ] 16 15. 1 17 3.1.1 South-to-North: During any period in l 18 which a WSCC Path 15 south-to-north curtailment ie issued and 19 becomes effective after DPS has submitted the final schedule for l 20 the scheduling period, PG&E shall notify the DPS Power Control i 21 Center of the total-generation (in MW) that must be curtailed 22 frcr Southern Zone DPS Resources and Imports from the Edison 23 Control Area. PG&E may issue a curtailment order up to the 24 amount of power generated by Southern Zone DPS Resources less ) 25 exports to the Edison Control Area. Upon receipt of a 26 curtailment order from PG&E, DPS, in its sole and unilateral I discretion, shall immediately notify one or more of the Southern
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27 28 Zone DPS Resources or Imports from the Edison Control Area that l 23 j
1 its sales to DPS are being reduced for the scheduling period. 4 r~ t 2 DPS will notify PG&E by the end of the next Work Day of the
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3 manner in which it allocated the reductions of its purchases 4 among the Southern Zone DPS Resources and Imports from the Edison i 1 5 Control Area and illustrate that the total MW of reductions in 1 6 DPS purchases equal the MW level of DPS curtailment ordered. If 7 DPS fails to curtail as ordered by PG&E, the provisions of 8 Section 4 may apply. . 1 9 3.1.2 North-to-South: During any pe'.iod r in l 10 which a WSCC Path 15 north-to-south curtailment is issued and l 11 becomes effective after DPS has submitted the final schedule for 12 the scheduling period. PG&E shall notify the DPS Power Control 13 Center of the total generation (in MW) that must be curtailed 14 from Northern Zone DPS Resources and Imports from COB which
/m 15 contribute to the excess line loading on WSCC Path 15 (" Curtailed (O) 16 Imports"). PG&E may issue a curtailment order up to the amount 17 of power transmitted in accordance with DPS' request on WSCC 18 Path 15 in a north-to-south direction from Northern Zone DPS 19 Resources and contributing Imports. Upon receipt of a 20 curtailment order from PG&E, DPS, in its sole and unilateral 21 discretion, shall immediately notify one or more of the Northern 22 Zone DPS Resources or Curtailed Imports that its sales to DPS are 23 being reduced for the scheduling period. DPS will notify PG&E by 24 i the end of the next Work Day of the manner in which it allocated
{ 25 lthe reductions of its purchases among the Northern Zone DPS 26 Resources and Curtailed Imports and illustrate that the total MW 27 of reductions in DPS purchases equal the MW level of DPS
/~ss k_ 28 curtailment ordered.
I 24 i 1
1 3.2 DPS Sucoliers (~' 2 3.2.1 EA Resources: DPS shall designate EA ( 3 Resources as either ABRs or CBRs, in accordance with 4 Sections 3.2.2 and 3.2.3; provided, that DPS may change its l l 5 designation of an ABR to become a CBR in the event of a 6 curtailment by PG&E pursuant to Section 6.3 and may redesignate : 7 such EA Resource as an ABR upon expiration of the curtailment. 8 Under the provisions of the PPAs, PG&E may purchase power at 9 different rates depending on the amount and time of poyer 10 delivery. PG&E will continue to segregate the types of power 11 purchased by PG&E for the purposes of administering PPAs'as (i) 12 power purchased on an as-available basis, and (ii) PPA Firm 13 Capacity. 14 3.2.2 Allocation Basis Resources ("ABRs"): The e (m) 15 energy from an ABR shall be separated into two blocks: (i) PG&E 16 Energy; and (ii) DPS Pool Energy. For the purpose of accounting 17 for DPS Pool Energy and for PG&E Energy, the Parties agree to the 18 following power accounting protocols for ABRs. Energy from ABRs 19 will be credited each Half-Hour Period as PG&E Energy and/or DPS 20 Pool Energy as follows: 21 If C=0, then 22 DPS Pool Energyngg = The lesser of: [DS] 2r [G - (the lesser of G QI F)] 23 PG&E Energy = [G) - DPS Pool Energyggg 24
- f C>0, then 25 DPS Pool Energyngg = The lesser of: [DS) 2r [G - (the 26 lesser of G 2r F)) calculated for the length of period up to the curtailment 27 becoming e#fective (less than one half
( hour)
\- 28 plus 25
_ . _ . - . -. _ _ __ _ ~ . _ . . . . _ . _ _ _._ _. _ _ _ _ . _ . - . _ _ _ _ - - . _ _ i 1 The lesser of: (DS - C) nr (G - (the s' lesser of G gr F)) calculated for the y- g 2 length of period following the (j curtailment becoming effective (less 3 than one half hour) 4 PG&E Energy = {[G) - [DPS Pool Energy]} calculated for the length of period up to the 5 curtailment becoming effective (less
- . than one half hour) 6 plus 7
{[G) - [DPS Energy)} calculated for the lesser of (i) = 8 the length of period. remaining in the half hour after the curtailment 9 becomes effective (less than one half
- hour)
!~ 10 N . i 11 (ii) = {If the.res.ource generating capacity 12 (rate of delivery) just prior to the i' curtailment is less than the sum of 13 the PPA Firm Capacity and the power scheduled to be delivered to the DPS 14 Pool (rate of delivery), then [R) less the power scheduled to be delivered to i I
- 15 the DPS Pool (rate of. delivery),
4
\ otherwise, the resource generating 16 capacity (rate of delivery) just prior to curtailment less the power i 17 scheduled to be delivered to the DPS Pool (rate of delivery)} multiplied by
- 18 the length of period remaining in the half hour after the curtailment 4
19 becomes effective (less than one half j hour) 20 i G = The resource's a'tual c metered energy l 21 generation over the length of tne period (one half hour) (net of hos 22 and station loads, if applicable, and applicable transformer or line losses ! 23 to the point of delivery to PG&E.) i 24 F = The product of the PPA Firm Capacity ' and the length of the period (one half
- 25 hour) i 26 DS = The product of the power scheduled to l the DPS Pool (rate of delivery) for l
27 the schedule period and the length of I l /~'\ the period (one half hour) ~ k/ u 28 C = The product of the amount of 26
l i 1 curtailment allocated to the resource a by DPS in accordance with Section 3.1 2 and the time remaining in the Half-O' 3 Hour Period when the curtailment went into effect. For all subsequent l hourly scheduling periods in which the. 4 curtailment continues, this value will be deemed to be zero for the remainder i 5 of the curtailment. l 6 R = The average capacity level, noticed'. pursuant to Section B.2.1, at which ! 7 DPS expected the resource to operate. I 8 . : 3.2.3 Contro11ina Basis Resources ("CBRs"): The ! 9 , ) energy from a CBR may be separated into two blocks: (i) PG&E j 10 Energy; and (ii) DPS Pool Energy. For the pd,rpose of acgounting 11 for DPS Pool Energy and PG&E Energy, the Part'ies agree to the 12 following accounting protocol for CBRs. Energy from CBRs shall 13 be credited each half hour as either PG&E Energy and/or DPS Pool 14 Energy as follows: f-s 0 Nsf 16 PG&E Energy = (The lesser of: G gr F) + (The lesser of: PS gr D) D= (G) - (The lesser of: G gr F) ; 17 If C=0, then 18 DPS Pool Energyg3g = [G) - [PG&E Energy) 19 If C>0, then 20 DPS Pool Energygga = { [G) - [PG&E Ene'gy]} r calculated for 21 the length of period up to the curtailment becoming effective (less 22 than one half hour) 23 plus 24 the lesser of (i) = { [G) - [PG&E Energy)} calculated for the length of period remaining in the 25 half hour after the curtailment becomes effective (less than one half 26 hour) DE 27 {[R) [ amount of curtailment O
= -
(ii) 28 allocated to resource by DPS in l accordance with Section 3.1) - [as-27
. ~ -~ .-
I 1 l l 1 available power scheduled to PG&E 4} l (rate of delivery)) - PPA Firm i
s 2 ' Capacity} multiplied by the length of ;
period remaining in the half hour i 3 after the curtailment becomes l effective (less than one half hour) 4 i G = The resource's actual metered energy 1 5 generation over the length of the - period (one half hour) (net of host 6 and station loads, if applicable, and , applicable transformer or lineLlosses. ! 7 to the point of delivery to PG&E..) j 8 F = The product of the PPA Firm Capacity ; and the length of theiperiod-(one half 9 hour). ', l 10 PS = The product of the As-Available QF Power scheduled to,PG&E r (rate *.of 11 delivery) for the schedule period and ; the length of the period (one half 1 12 hour). - 1 R 13 C = The product of the amount of curtailment allocated to the resource i 14 by DPS.in accordance with_Section.3.1 and the time remaining in the Half- i 15 Hour Period af ter the: curtailment l became effective. For all subsequent 16 hourly scheduling periods in which the , curtailment continues, this value will. l 17 be deemed to be zero for the remainder of the curtailment. 18 R = The average capacity level, noticed 19 pursuant to Section B.2.1, .at which DPS expected the resource to operate. 20 21 3.2.4 Initial 12-Month Period: Subject to 22 Section 3.2.1', for each month during the initial twelve (12) 23 months after the Effective Date, DPS shall notify PG&E, no later 24 than five'(5) Work Days prior to the start of the month, which EA 25 Resources shall be designated as CBRs and which EA Resources 26 shall be designated as ABRs for that month. 27 After Initial 12-Month Period: () 3.2.5 twelve (12) months from the Effective Date, DPS shall notify PG&E After 28
. . . _. ~- -- _ _ . - . _ - _ _ - . . ~ . . - _ _ _ . - . -- - _ . .
1 at least twenty (20) minutes before each hour scheduling period, 4; l I , i
- 2 in accordance with Section B.8.1, which EA Resources shall be
; 3 designated as CBRs and which shall be designated as ABRs for the 4 upcoming hour, subject to Section 3.2.1. Before hourly 5 designation commences pursuant to this Section 3.2.5, DPS, at its 6 own expense, shall establish a datalink with PG&E to notify PG&E j 7 on an electronic basis of hourly designations pursuant to Section 8 3.2.1 of EA Resource status as either a CBR or.an ABR.
9 3.2.6 Non-Utility Resources Within the PG&E 10 Control Area: A non-utility resource within the PG&E Control Area 11 (i.e., an IPP or QF not selling power to PG&$) may become a DPS 12 Control Area Resource under the provis' ions of this Agreement only 13 if the requirements of Section 6.4.2 are satisfied. If DPS is 14 the sole purchaser of net power produced by the non-utility () 15 16 resource and such power flows through the meter'.which measures deliveries into PG&E's Electric System, the entire output of such: 1
'1 17 non-utility producer shall be credited to the DPS Pool as j 18 follows:
19 DPS Pool EnergyNmt - Actual metered 20 energy generation (net of host and 21 station loads, if applicable, and 22 applicable transformer or line losses 23 to the point of delivery to PG&E) as 24 integrated by PG&E over the Half-Hour s 25 Period. 26 3.2.7 Utility Resources Within the PG&E Control Area: For Scheduled Transactions by DPS from Third Party 4 27 (") utilities in PG&E's Control Area, energy will be credited to the I 28 29
l ' 1 DPS Pool as follows: 4: 2 DPS Pool Energygg = The energy 3 scheduled to the DPS Pool for the Half-a 4 Hour Period (i.e., one half of the
- 5 energy scheduled during the 6 corresponding hourly scheduling li 7 period). Example
- The scheduled energy .
8 corresponding to a 5 MW power schedule' 9 would equal 2.5 MWh. ( !' 10 Subject to the development of appropriate accounting ! 11 protocols, DPS may also purchase variable pow'er from Third Party 12 utilities in PG&E's Control Area in or der to satisfy Control Area 13 Services requirements or for other purposes. Upon notification 14 that DPS intends to make such variable purchases, the Parties 1 ( 15 agree to negotiate in good faith to develop any.necessary 4 16 accounting protocols and, to the extent necessary, submit such \ 17 protocols to the FERC as amendments to this Agreement. 18 3.2.8 Imnorts: DPS shall schedule for import ] i 19 any energy to be delivered to the DPS Pool from outside the PG&E 20 Control Area. PG&E's current practice is not to permit " dynamic 4 21 scheduling" of variable amounts of power from or to other Control 22 Areas. Accordingly, DPS may currently only conduct Scheduled 23 Transactions from DPS Suppliers outside the PG&E Control Area for 24 deliveries to the DPS Pool and from the DPS Pool to DPS Loads , 25 outside the PG&E Control Area. If PG&E changes its practice, DPS 26 w511beallowedtomakeVariableTransactions. Power from f- 27 Imports shall be coordinated with the interconnected Control Area i
\ 28 operator delivering power on DPS' behalf.
30
1 Such Scheduled Transactions by DPS will be credited 4 l 2 as DPS Pool Energy as follows: 3 DPS Pool Energyz - The energy scheduled 4 to the DPS Pool for the Half-Hour 5 Period (i.e., one-half of the energy 6 scheduled during the cor esponding 7 hourly scheduling period). . , 1 8 3.3 DPS Loads j 9 DPS Loads may receive power from DPS either: (i) on j 10 a scheduled basis (Scheduled Transactions); or (ii) on a variable ! 11 basis (Variable Transactions). 12 3.3.1 Loads Met Throuch Scheduled Transactiong: l 13 DPS may use Scheduled Transactions to meet all or a portion of 14 the total load of a DPS Load. () 15 3.3.2 Loads Met Throuch Variable Transactions: DPS may supply the entire power requirements of a DPS customer 16 17 through Variable Transactions. DPS may also supply a portion of 18 an entity's total load through Variable Transactions, provided 19 the balance of the entity's remaining load is supplied solely 20 through either a single Scheduled Transaction or through a 21 combination of Scheduled Transactions from PG&E and/or Third 22 Party suppliers. ! 23 3.4 Schedulino 24 DPS shall schedule DPS Suppliers and DPS Loads in 25 accordance with the requirements and procedures described in 26 Appendix B. 27 28 31
-l 1 4.0 CONTROL AREA SERVICES AND REOUIREMENTS . a'
'2 This Agreement obligates DPS to satisfy specified Contrc; 3 Area requirements. .This Section 4 describes Control Area 4 requirements applicable to DPS, the terms and conditions of 5 Control Area Services offered _by PG&E and the alternative manners 6 in which DPS may satisfy all or portions of its Control Area 7 requirements. DPS may satisfy these requirements by: (i) buying 8 Control Area Services from PG&E; (ii) providing. Control Area-9 Services using DPS Control Area Resources and/or throngh Third 10 Parties; or (iii) through a combination of sourcer of Control 11 Area Services as provided in this Section 4.
12 4.1 AGC Reaulation 13 :4.1.1 Descrietion of Service /Recuirement: AGC 14 Regulation provides for the moment by moment matching of A 15 resources with loads by regulating and controlling the power ( f 16 output of electric generators. DPS must satisfy this requirement: 17 as followe: 18 4.1.2 Monthly Division'of Outout Points: In 19 accordance with Section 5.1.1, on a monthly basis, DPS shall 20 divide all of its Output Points into two groups: 21 (1) Matchine Loads: 22 a single group of DPS Loads within 23 the PG&E Control Area, of any number 24 which can be as many as all the 25 Output Points or as few as none of 26 the Output Points, for which DPS will 27 match the summation of those DPS 28 Loads on a moment by moment basis 32
I with a subset of DPS Suppliers al I () V 2 (specified on an hourly basis in 3 accordance with Sections B.8.2.1 and 4 B.8.2.2); and 5 (2) Non-Natchina Loads: 6 the Output Points that DPS does not 7 identify as within the Matching, Loads 8 group. 9 4.1.3 Matchina Loads: DPS will satikfy AGC 10 Regulation requirements for a single Matching Loads group in the
~
11 manner described in Section J.3.2. If DPS fails to meet the 12 performance criteria on a daily basis:as described in 13 Section J.3.2.2, then all the Output Points will be classified as 14 part of the Non-Matching Loads group for the purposes of ] t~ I 15 calculating AGC Regulation Load-Effective as defined in
\
16 Section 4.1.6. j 1 17 .4.1.4 Non-Matchina Loads: DPS will satisfy AGC ) 18 Regulation requirements for Non-Matching Loads.by one or both of 19 the following procedures: 20 (i) Provide capacity for control by 21 PG&E in accordance with Section 22 4.1.5. 23 (ii) Purchase AGC Regulation service 24 from PG&E in accordance with l 25 Section 4.1.6. 4.1.5 Cacacity for Control by PG&E: In 26
- 27 accordance with Section 5.1.1, DPS shall elect the amount of Non-
'- 28 Matching Loads with AGC to be satisfied by providing capacity for 33
1 control by PG&E as AGC Control Load. Section J.3.1 sets forth 4; 2 the requirements for DPS to satisfy its AGC Regulation 3 requirements in this manner. If DPS fails to meet the 4 requiremento on a daily basis as described in Section J.3.1.1.3, 5 then the AGC Control Load will be treated as if it were zero for 6 the ' day for purposes of calculating AGC Load Ef fective as defined 7 in Section 4.1.6. , 8 4.1.6 AGC Recrulation Service f rom PG&E: The 9 amount of Non-Matching Loads with AGC to be satisfied.by DPS 10 purchasing AGC Regulation se. vice from PGEE is defined as AGC ; 11 Regulation Load Effective, which equals the maximum of AGC 12 Regulation Load Reserved or the diffeience between the peak 13 demand from the Non Matching Loads for the day and AGC Control i 14 Load, i.e.: ) i 15 AGC Regulation Load Effective = Maximum of (AGC 16 Regulation Load Reserved) or (peak of Non-Matching I 17 Loads - AGC Control Load) 1 l 18 AGC Regulation Load Reserved is the level of AGC Regulation l 19 service DPS reserves from PG&E in accordance with Section 5.1.1. 20 The rate for AGC Regulation service is set;forth in Section D.2. 21 4.1.7 AGC Reculation Service Provided bv Third 22 Parties: DPS may satisfy all or a portion of the AGC Regulation 23 requirement using Third Parties pursuant.to Section J.3.1. 24 4.1.8 Non-Bindine Forecast: DPS shall submit to PG&E a non-binding forecast of AGC Regulation elections (i.e., a 25 26 monthly forecast of the DPS Load showing how DPS will satisfy AGC 27 Regulation requirements) for the six-month period January-June of l 28 a given year on November 1 of the previous year and for July-34
1 l r 1 December of a given year on May 1 of such year. 4 2 4.2 Inter-Hour Load Balancine ("THLBai l 3 4.2.1 Descriotion of Service: The DPS Load may I 4 vary from one hour scheduling period to the next. Purchasing 5 IHLB service gives DPS the right to offset changes in the DPS l 6 Load with hourly changes in the allocation of loaded capacity , 7 from EA Resources (i.e., follow a movement in schedule without 8 physically moving generation by increasing or decreasing the rate l 9 of energy' delivery from DPS to PG&E by changing the pre-l 10 designation (or schedule) of intended delivery between the DPS l 11 Pool and PG&E). 12 4.2.2 IFTR Service Available From PG&E: DPS may 1 13 purchase IHLB service from PGEE at the rates specified in 4 i 14 Section D.3.1. IHLB only applies to EA Resources (and not to any ;
/\
i () 15 - other DPS Supplier) where DPS seeks to follow load by allocating 16 energy between the EA Resource's sales to PG&E and the EA 17 Resource's sales to DPS causing PG&E's generation to physically 18 respond to changes in DPS Load /PG&E supply. For ABRs, such 19 changes in allocation include increases or decreases in the 20 amount of energy scheduled by DPS for delivery to the DPS Pool 21 each hour. For CBRs, such changes in allocation include 22 increases or decreases in the amount of power scheduled for 23 delivery to PG&E each hour. The quantity of IHLB service , 24 reserved by DPS, as established in Section 5.1.2 for each Billing 25 Period, sets an upper limit on the total net changes in the 26 allocation of EA Resources DPS may make under Section 3.2 from 27 one hourly scheduling period to the next. If DPS does not - 7-s ! r
# 28 purchase sufficient IHLB service to meet the maximum total change 35
l l i l i l 1 in DPS Load between any two hours in the month, then DPS shall $ l (~Ne 2 adjust the energy actually delive.ed to the DPS Pool on an as-
\J 3 delivered basis by CBRs and Non-EA Resources as necessary to 4 avoid charges for Energy Devic ions. If DPS changes the total 5 net allocation of EA Resources in excess of the amount of IHLB it 6 reserved for the Billing Period, PG&E shall charge DPS for IHLB 7 service in an amount equal to the actual maximum change in 8 allocation for any hour during the Billing Period, provided, that 9 for specific changes in load, PG&E may agree with DPS n.ot to 10 assess such a charge if the physical following of load by DPS 11 would cause, rather than alleviate, the ramping of resour6es by 12 PG&E.
13 4.3 Spinnino Reservg i 14 4.3.1 Descriotion of Service /Recuirements: PG&E
/~N
(,) 15 maintains a Spinning Reserve for the PG&E Control Area based on I 16 the combined requirements or guidelines of the California Power r_ 17 Pool (PG&E Rate Schedule FERC No. 27), the NERC and the WSCC. ; i l
~
18 4.3.2 Soinnine Reserve Reauirement: Except as 19 may be modified in accordance with Section 4.3.5, DPS ac ' -'+ h 20 meet a Spinning Reserve Requirement equal to no less than 7% o*/ l l 21 the total of its firm Scheduled Transactions and firm variable In addition, except as 22 Transactions in the PG&E Control Area. 23 may be modified in accordance with Section 4.3.5, DPS shall 24 provide Spinning Reserve equal to 100% of its non-firm purchases 25 of power (i.e., purchases which are interruptible at any time for l 26 any reason) to meet firm Scheduled Transactions and firm Variable 7-27 Transactions in the PG&E Control Area. To meet this requirement, l i
' ') 28 DPS may either purchase Spinning Reserve on a monthly basis from 36
f 1 PG&E in accordance with Section 4.3.4, and/or DPS may provide its" i [~') 2 own Spinning Reserve, in whole or in part, in accordance with
%j 3 Sections 4.3.3 and J.4.
4 4.3.3 Spinnino Reserve Provided by Third Party: 5 DPS shall be relieved of the Spinning Reserve Requirement set 6 forth in Section 4.3.2 to the extent it can demonstrate in 7 advance that a specific Third Party is providing or purchasing 8 the required Spinning Reserve in support of the transaction in a l 9 comparable quality and quantity of Spinning Reserve snpplied by a 10 resource (s) located within PG&E's Control Area. j 11 4.3.4 PG&E Provides Mpinnino Reserve Service: 12 DPS shall request Spinning Reserve service from PG&E as provided 13 for in Section 5.1.3. The amount of Spinning Reserve DPS 14 purchases as paid for in accordance with Section D.4 will be the p (_) 15 Spinning Reserve Service Effective which equals the maximmm of: 16 (i) Spin Service Reserved per Section 5.1.3; or (ii) the total 17 Spinning Reserve Requirement less the portion satisfied in 18 accordance with Section J.4. If the portion of the Spinning 19 Reserve Requirement provided by DPS fails to meet One criteria in 20 Section J.4.2, it will be treated as if it:were cero for each day i 21 that DPS fails for the purposes of calculating Spin Service 22 Effective. 23 Spin Service Effective = Maximum of (Spin Service 24 Reserved) or (Spinning Reserve Requirement - Spinning 25 Reserve provided by DPS pursuant to Section J.4) 26 4.3.5 Chances in Scinnino Reserve Recuirements: l 27 If (a) PGLE's obligations (as implemented by PG&E) change for (~]
%_) providing Spinning Reserve Requirement for the PG&E Control Area l 28 37
1 because of actions taken by the WSCC, NERC, the California Power ! 2 Pool or other successor organizations, and (b) such changed
)
3 obligations justify a revision to the Spinning Reserve 4 Requirement, the Parties shall discuss, agree, and/or resolve any f 5 disputes regarding any necessary changes to the requirements l 6 herein in accordance with Section 8.20. , 7 4.3.6 PG&E Richts to Purchase Enerov From.DPS 8 Soinnine Reserve: If DPS elects to provide its own Spinning 9 Reserve, PG&E may call upon DPS to provide Spinning Reserve at l 10 such time as PG&E deems it necessary to maintain reliability of' l, 11 the PG&E Control Area. PG&E may request DPSIto load its' Spinning . 1 12 Reserve up to the amount of the Spinning Reserve Requirement for j 13 up to two (2) hours per occurrence. i 14 Upon a request for Spinning Reserve by PG&E, DPS () 15 shall cause an increase in net generation from within the PG&E Control Area, within ten (10) minutes of PG&E's request, and, 16 , l 17 relative to DPS Load, in the amount of and for the duration of PG&E's request, provided that the amount of PG&E's request shall j 18 19 not exceed the Spinning Reserve Requirement. 20 4.3.7 PG&E Payment for Enerov Purchased From 21 DPS Soinninc Reserve: Whenever PG&E requires DPS to deliver 22 energy to PG&E from DPS' Spinning Reserve, PG&E shall pay for 25 such energy pursuant to Section D.4. 24 4.4 Mixture of Methods for Satisfvinc Control Area 25 Service Recuirements 26 DPS may elect to purchase from PG&E or from Third t 27 Parties all or a portion of each of the three Control Area O 28 Services described in this Section 4 pursuant to the conditions 4 38 1
l 1 of Appendix J. 4; l r l (~} 2 4.5 Monthlv Billine Charoe and One-time Se -Ur Fee
~
3 4.5.1 In any month in which DPS conducts 4 transactions under this Agreement, DPS shall pay PG&E a Monthly 5 Billing Charge in accordance with Section D.5. The Monthly 6 Billing Charge does not reimburse PG&E for scheduling Costs. 7 4.5.2 In addition to any applicable Monthly Billing-8 Charge, DPS shall pay to PG&E a one-time set-up. fee. The one-9 time set-up fee shall be based on PG&E's actual incremental labor 10 cost for computer programming specifically to administer this 11 Agreement and for training the personnel responsible for 12 implementing and administering this Agreement. PG&E shall 13 calculate the actual bill for DPS for the one-time set-up fee 14 after FERC has accepted this Agreement and initial training and (~%i
- 15 progranadng has been completed. The cost of PG&E's labor shall b/
16 be S40/ hour per person-hour. DPS has the right to pre-apnrove l 17 the workscope for this initial set-up, and to audit the invoices. 18 4.6 Enerov Deviations and Enerev Exchance Band 19 DPS shall have an affirmative obligation under this 20 Agreement to match as closely as possible the energy usage of the 21 I DPS Load with energy deliveries from DPS Suppliers to the DPS 22 Pool to attempt to achieve zero energy deviations. DPS may 23 operate within an Energy Exchange Band without charge by PG&E. 24 Load / resource deviations falling outside of the Energy Exchange 25 Band will result in charges to DPS and/or the loss of DPS energy. 26 DPS' deviations within each hourly scheduling period shall be
,_s 27 accounted for in accordance with this Section 4.6.
I I
\/ 28 4.6.1 Size of the Enerov Exchance Band: The 39 i
l l l 1 1 Energy Exchange Band shall have a width of e 1 MWh/ hour f or a MSD*[i () 2 3 of 100 MW or less. For a MSD greater than 100 MW, the Energy Exchange Band shall be 2 2 MWh/ hour. Provided, however, that. r j -4 during the three (3) months following DPS initial scheduling of 5 power pursuant to this Agreement, the Energy Exchange Band shall 6 be e:2 MWh/ hour for an MSD of 100 MW or less and 4 MWh/ hour for ( 7 an MSD of greater than 100 MW. T .e zero point reference for, 8 determining deviations is the aggregated actual energy load of 9 DPS' customers as calculated pursuant to Section 4.6.i. 10 4.6.2 Calculation of Enerav Credit to DPS Pool: 11 The amount of energy to be credited to the DPS Pool in any Half-12 Hour Period for purposes of the Energy Exchange Band shall equal: i 13 DPS Pool Energy Credit = DPS Pool Energy;ag + DPS Pool 14 Energyc3g + DPS Pool Energym + DPS Pool Energygg + DPS 15 Pool Energyz +/- Exchange Energy 16 Note: Terms are defined in Sections 1, 3.2, and 4.6.5. 17 4.6.3 Calculation of Enerav Debit from the DPS 18 Pool: The amount of energy to be debited from the BPS Pool in any 19 Half-Hour Period for purposes of the Energy Exchange Band shall 20 be calculated as follows: 21 DPS Pool Energy Debit = [I Scheduled Energy + E Variable Energy) + Losses + Ramp Adjustment - 22 Replacement Energy Where: 23 I Scheduled Energy = The sum of the. energy deliveries of each Scheduled Transaction (including 24 exports). The energy from a Scheduled Transaction equals the product of the 25 scheduled rate of delivery and the applicable duration (0.5 hour, except 26 as provided for in Section B.9.2). 27 I Variable Energy = The sum of all energy delivered through s, Variable Transactions as metered at the ' \ 28 individual Output Points by PG&E over the corresponding Half-Hour Period i ! 40 l.
i 1 (using PG&E revenue meter data). 4 ( 2 Losses = The product of 0.02850 and [I Scheduled \ Energy + I Variable Energy) 3 corresponding with Output Points of 4.16 kV or greater plus the product of 4 0.0125 and [I Scheduled Energy + I Variable Energy) corresponding with 5 Output Points of 4.16 kV or greater but-less than 60 kV. 6 Replacement Energy = The product of the sum of curtailment 7 (rate of delivery) allocated by DP,S to' individual Southern Zone DPS Resources 8 other than Imports and the duration of curtailment within the Half, Hour Period 9 pursuant to Section 6.3.4. ' Note: The sum of curtailment allocated by DPS to 10 individual DPS Suppliers (in MWs) shall equal the total amount of curtailment 11 ordered by PG&E. 12 Ramp Adjustment = The differen'ce in the actual energy associated with the duration of ramped. 13 changes in scheduled power deliveries and what the energy would have been for 14 those same durations had the scheduled changes been instantaneous. This
-) 15 adjustment is only made in the event that a ramp was made during the Half-16 Hour Period and without the adjustment, an Hourly Energy Deviation would be 17 outside the Energy Exchange Band pursuant to Section 4.6.6.
18 19 4.6.4 Calculation of Load / Generation 20 Deviations: PG&E will monitor DPS matching.the DPS Pool Energy 21 Credits with the DPS Pool Energy Debits over hourly scheduling 22 periods. PG&E will begin calculating hourly deviations for a j 23 Billing Period upon conclusion of the prior Billing Period. 24 Deviations shall be calcu]nted for each Half-Hour Period as 25 follows: 26 Deviationnalf Hour = [DPS Pool Energy Credit - DPS Pool Energy Debit) 27 O 28 The hourly net deviation shall be the sum of the two half hourly 41
. . . ~ . . _ . - . ~ . . - . _ - . . . _ - . - _ . - . . _ . _ . _ - -. _ - ..
1 periods corresponding with the hourly scheduling period as 8 2 described below: ( 3 Hourly' Energy Deviation = l j 4 [Deviationnalf-nour Period 1 + Deviationnalf-Hour Period 23 .- L5 Deliveries to the DPS Pool will be based j j 6 on PG&E recorded metered data and scheduled deliveries by DPS } ! 7 Suppliers at the Input Points, as applicable. Metering
- L j- 8 requirements are described in Appendix F. PG&E.shall integrate ,
j 9 recorded meter information within each Half-Hour Peribd to 2 10 determine actual metered deliveries. , 4
- 11 PG&E will provide DPS with continuous f
12 Remote Terminal Unit. access to instantaneous power values, and , j 13 revenue meter. pulse accurulator data for all metered Input Points , 14 and Output Points. 15 '4.6.5 Houriv Enerav Deviations Within the 16 Enerav Exchance Band: Hourly Energy Deviations (positive . or 17 negative) within the Energy Exchange Band shall be zeroed out, in 18 like time periods, at the earliest practicable time; however, 19 energy deviations shall not be zerced out later than one month 20 after the occurrence of the deviation. DPS:shall monitor its 21 Hourly Energy Deviations by time period (see Appendix H) and, for 22 /// 23 /// 24 /// 25 26 8 42
i l l l 1 Energy Deviations within the Energy Exchange Band, return any net *j () Q/ 2 negative Hourly Energy Deviations and receive any net positive 3 Hourly Energy Deviations by scheduling Exchange Energy in a like 4 time period in accordance with Section B.4. 5 4.6.6 Hourly Energy Deviations Outside of the 6 Enerov Exchance Band: Hourly Energy Deviations that are less than 7 or equal to 7 MWh/ hour, but greater than the applicable Ener,gy B Exchange Band, are within the First Deviation Band. Energy 9 Deviations greater than 7 MWh/ hour are within the Second 10 Deviation Band. Notwithstanding the provisions of this Section 11 4.6.6, DPS shall not be deemed to have incurred a deviation if 12 PG&E calls on DPS to deliver energy from its Spinning Reserve as 13 provided for in Section 4.3.6. If the PG&E metering 14 malfunctions, the Parties shall confer to mutually agree, based
/
(3,,/ 15 upon use of the best available data, whether or-not any deviation 16 occurred, and if so, the amount of the deviation, during the 17 period effected by the metering malfunction. If the Hourly 18 Energy Deviation is outside the Energy Exchange Band, then the 19 Hourly Energy Deviation will be revised to include the Ramp 20 Adjustment pursuant to Section 4.6.3, if applicable. 21 4.6.6.1 Positive Hourly Enerav 22 Deviations Within the First Deviation Band ("Overceneration"). 23 Positive Hourly Energy Deviations are deemed lost to the area. 24 The provisions of Section 4.6.5 do not apply (i.e., DPS will 25 receive no payment or exchange credit for such Overgeneration) 26 DPS will be charged for any Overgeneration occurring during , 27 Minimum Load Conditions pursuant to Section D.7.1. f-~
\ / 4.6.6.2 Neaative Hourly Enerov '"' 28 43
1 1 Deviations Within the First Deviation Band ("Underceneratior*1 d
'2 DPS will purchase energy from PG&E at the SRAC rate x 115%
3 applied to the entire Energy Deviation and will purchase capacity 4 from PG&E at the Undergeneration Capacity rate specified in 5 Section D.7.2 based on the' maximum kilowatt capacity devia". ion 6 for the day. PG&E will receive no return of Hourly Energy. 7 Deviations.from the applicable scheduling period'and the 8 provisions of Section 4.6.5 shall not apply.
'9 4.6.6.3 -Deviations Withit the 10 Second Deviation Band: For both Overgeneration and 11 Undergeneration, DPS shall pay PG&E at the disincentive rate 12 specified in Sections D.7.1 and D.7.2 'on the entire Energy 13 Deviation in addition to the provisions of Sections 4.6.6.1 or i
14 4.6.6.2, as applicable. The disincentive rate is intended by the ' 'N 15 Parties solely to be a disincentive to Overgener'ation or 16 Undergeneration and expressly is not intended to function at any-17 time as a cost-based rate for " service" voluntarily provided by 18 PG&E to DPS. The Parties agree that, in the event the 19 disincentive rate is incurred: (a) proof of actual loss or impact 20 on PG&E would be exceedingly difficult to determine because it is 21 impossible at this time to ascribe a dollar value to such loss; 22 (b) the legal and regulatory remedies available to PG&E would 23 make it infeasible or extremely inconvenient to obtain an 24 adequate remedy; and (c) the above disincentive rate is no: 25 intended to represent the actual Costs to PG&E of DPS' Over-26 generation or Undergeneration, but rather is intended to minimize 27 the economic incentive for DPS to plan to rely on Undergeneration 28 and Overgeneration to meet capacity or energy requirements and , l 44
I 1 shall constitute'PG&E's sole remedy for DPS' Overgeneration or 4 1 2 Undergeneration. t 3 4.6.7 Additional Enerov Exchance Band: DPS may i l j 4 purchase additional Energy Exchange Band width up to a maximum of 5 7 MWh/ hour (including the t 1 MWh/ hour _or 2 MWh/ hour Energy 6 Exchange Band as described in Section 4.6.1). Such additional 7 Energy Exchange Band amount shall increase both the poritive and 8 negative sides of the band. DPS shall pay for the additional 9 Energy Exchange Band at the rate specified in Section'D.6. If 10 DPS elects to purchase the additional Energy Exchange Band in a 11 Billing Period, DPS shall so notify PG&E in writing no later than 12 five (5) Work Days prior to the start of the Billing Period and i 13 DPS shall then have a take-or-pay obligation to purchase the 14 designated amount of additional Energy Exchange Band for the (~% q) 15 Billing Period. 16 4.7 No Dunlication of Control Area Services 17 To the extent any Third Party is obligated to pay' 18 PG&E for, or otherwise provide, any Control Area Service (s) 19 associated with transactions with DPS scheduled or accounted for 20 under such Third Party's existing Interconnection Agreement with 21 PG&E, DPS shall not be required to duplicate such services nor l
\
22 pay PG&E for duplicate Control Area Services under this 23 Agreement. 24 4.8 Unscheduled Interruntions 25 PG&E may temporarily interrupt or reduce any Control 26 Area Service, if PG&E determines at any time that the following 27 conditions exist or that the described action is necessary or 28 desirable (a) in case of an Emergency that directly affects 45
i 1 PG&E's ability to provide any such service to DPS, (b) to preven:d!, '
} 2 a hazard to life or property, (c) when the operation of PG&E's ,
3 System is suspended, interrupted or interfered with as a result I 4 of Uncontrollable Forces, including excessive loop flow or (d) if i l 5 PG&E determines that continuity of service within PG&E's Control j 6 Area is being jeopardized. In that event, the PG&E Energy 7 Control Center shall notify the DPS Power Control Center if;DPS j 8 action is required and DPS shall comply immediately. PG&E shall l 9 restore any Control Area Service so interrupted or interfered as 10 soon as practicable. PG&E shall notify the DPS Power Control 11 Center to review changes to DPS' schedules and coordinate plans , l ~ 12 to restore service or parallel facilities. 13 i 14 5.0 RESERVATION OF CONTROL AREA SERVICES AND SHORTFALLS j Q( j 15 5.1 Control Area Service Reservations j i 4
- 16 DPS shall notify PG&E in writing no later than one r
17 hundred and twenty (120) calendar days after this Agreement is 1 J 18 filed with FERC of any request (s) for Control Area Services. ] 4 i 19 PG&E shall respond to DPS within ten (10) Work Days specifying 20 whether the requested amount of each service is available. ; 21 Thereafter, DPS shall notify PG&E, no later than five (5) Work i 22 Days before the start of each Billing Period, of the amount of 4 23 each Control Area Service to be provided by PG&E (AGC Regulation, 24 l: HLB and Spinning Reserve) and reserved by DPS (if any) for that 25 Billing Period. PG&E is under no obligation to provide any 26 Control Area Services for DPS; provided, PG&E shall not 27 unreasonably withhold Control Area Services if such service is O 28 available from PG&E. If PG&E agrees to provide a Control Area 46 l
1 Service, then PG&E is obligated to provide the service for the * () %./ 2 duration of the request. 3 5.1.1 AGC Reservation: DPS shall notify PG&E 4 five (5) Work Days before the beginning of each Billing Period of 5 the specific Output Points, both location and estimated average 6 megawatts and kilowatts, that are included in the Matching Loads 7 group, if any, in accordance with Section 4.1. DPS shall also 8 specify the AGC Control Load in kilowatts, if any, in accordance 9 with Section 4.1.5, and the requested AGC Regulation Load j l 10 Reserved, also in kilowatts. The sum of the,AGC Control, Load and 1 1 11 the AGC Regulation Load Reserved shall not be.less than the sum ) i 12 of the estimated average loads for the Output Points included in 13 the Non-Matching Loads group. Once DPS makes these elections, l 14 they shall remain fixed for the entire following Billing Period. i ,a () 15 5.1.2 IHLB Reservation: DPS shall notify PG&E 16 five (5) Work Days before the beginning of the Billing Period of 17 the kilowatt amount of IHLB service it requests to reserve from 18 PG&E for the Billing Period. 19 5.1.3 Scinnino Reserve Service Reservation: DPS 20 shall notify PG&E five (5) Work Days before.the beginning of each 21 Billing Period of the amount of kilowatts of Spinning Reserve 22 Service it requests to reserve from PG&E for the Billing Period. 23 5.2 Failure to Reserve Control Area Services 24 In the event that DPS fails to notify PG&E within 25 five (5) Work Days before the start of any Billing Period of its 26 Control Area Service reservation for that Billing Period, DPS s 27 will be deemed to have reserved the same services (including / < i' '/ 28 additional Energy Exchange Band pursuant to Section 4.6.7) in the 47
1 same amounts that DPS reserved for the prior Billing Period. 8 , r~T 2 5.3 Shortfall in Control Area Services Reservations Ib
- 3 5.3.1 AGC Reculation Shortfall
- The AGC I 4 Regulation Shortfall shall be determined in accordance with 5 Section D.2.3.
6 5.3.2 IHLB Shortfall: The IHLB Shortfall shall 7 be determined in accordance with Sections 4.2.2 and D.3.3. 8 5.3.3 Soinnino Reserve Shortfall: The Spinning 9 Reserve Shortfall shall be determined in accordance wi'th Sections 10 4.3.4 and J.4.2. 11 12 6.0 TRANSMISSION SERVICE 13 PG&E shall provide Network Transmission Service to DPS, 14 subject to availability, in accordance with this section. l () 15 6.1 Network Transmission Service 1 16 DPS has the right to receive, and PG&E has an 17 obligation to provide, Network Transmission Service in accordance l 18 with this Section 6. The total mmount of Network Transmission 19 Service which PG&E must provide, and the amount of such service 20 which DPS shall be obligated to take-or-pay, shall be based upon 21 the total amount of such service requested by DPS and approved by 22 PG&E, designated as the " Maximum Simultaneous Demand" or MSD, 23 except for " Supplemental MSD" as provided in Section 6.2. The 24 MSD represents the maximum amount of Network Transmission Service 25 that DPS may schedule (stated separately for service at 26 transmission voltage and/or service at distribution voltage) and 27 use for any hour of any Billing Period, as set forth in 28 Appendix K. The MSD shall be independent of the number of 48 l d
1 Transaction Points or the individual or collective Maximum Demand" ( 2 Capability or Maximum Receipt Capability at such Transaction ( , 3 Points. Network Transmission Service under this Agreement shall 4 be available in all hours reserved of the Billing Period except 5 for curtailments as described in Section 6.3. No service shall 6 be provided under this Agreement to Output Points at voltage 7 levels less than 4.16 kV. - 8 6.1.1 Characteristics of Network Transmission 9 Service: DPS shall schedule power transactions using Network 10 Transmission Service only among the Transaction Points listed in 11 Appendix K. The request process by which DPS.may add, modify or 12 delete Transactions Points is describe'd in Sections 6.5 and 6.6. 13 The maximum rate of power deliveries which DPS may schedule to 14 any output Point is equal to_the applicable Maximum Delivery () 15 Capability set forth in Appendix K. The maximum' rate of power 16 deliveries which DPS may schedule from any Input Point is equal 17 to the applicable Maximum Receipt Capability set forth in 18 Appendix K. The sum of all DPS power schedules from the DPS Pool 19 in any hour, less losses, may not exceed the MSD listed in 20 Appendix K. DPS shall not be required to purchase transmission 21 service (MSD) for Spinning Reserve, provided however that DPS may 22 not submit a schedule which, including Spinning Reserve, would 23 exceed the Maximum Receipt Capability at any Input Point. 24 6.1.2 Limitations on Network Transmission 25 Service: DPS' purchLse of Network Transmission Service is a 26 purchase only of a specific service for a specific term. This 27 Agreement shall not create in DPS an entitlement to or property 28 interest in PG&E's Electric System, or any portion thereof. DPS 49
- . - . . .. . - . ~ - - - -- _- - - . - . - .. .- . _ . - - . - . . . _ . . . _ . _ - . .
1 I i l i sha'11 not have any right to transmission service beyond the term
- 1
(~} (/ 2 of this Agreement or in addition to the service requested by DPS . l 3 and provided by PG&E in accordance with the provisions of this 4 Section 6 (except as provided for in Section 8.28). PG&E shall 5 provide Network Transmission Service to DPS from: (1) Available ! 6 Transmission Capacity on existing facilities; or (2) capacicy 7 made available by upgrades pursuant to Section 6.6.7. PG&E;shall ! 8 determine, in its sole judgment, based on completion of the i 9 studies and procedures, described in Section 6.6, wheiher Network : 10 Transmission Service is available without upgrades, and, , if l 11 upgrades are needed, which reinforcements or ' additional
-12 transmission facilities would be required to provide such 13 service. PG&E has no obligation to provide Network Transmission 14 Service pursuant to this Agreement to the extent that upgrades or ;
() 15 reinforcements are needed: (i) which require a CPCN, (ii) which 16 require a construction period of greater than two (2) years, or 17 (iii) which require an upgrade that would not be operational 18 during the term of this Agreement. Nothing in this Agreement i l 19 shall obligate PG&E to provide Network Transmission Service to 20 DPS to the extent that: (a) PG&E would have to construct 21 transmission facilities to provide the Network Transmission 22 Service and (i) PG&E does not receive all necessary regulatory 23 approvals (with conditions acceptable to PG&E) or (ii) those 24 facilities would be inconsistent with Prudent Utility Practice; 25 (b) PG&E would have to construct transmission facilities outside 26 of PG&E's Control Area; (c) the designation of a Third Party as a 27 Transaction Point under this Agreement would enable that Third 28 Party to achieve objectives prohibited under its separate I 50 i
1 agreement with PG&E; or (d) the provision of Network Transmission 4 (" . L} - 2 Service would have the effect of transferring an existing retail 3 customer of PG&E to DPS. 4 6.1.3 Desienation of Maximum Simultaneous 5 Demand ("MSD"): The initial amount of MSD for this Agreement is 6 set forth in Appendix K. DPS may increase the MSD listed in 7 Appendix K at any time by making a written request to PG&E in 8 accordance with Section 6.6. DPS may also request a reduction in 9 the MSD at any time, provided that DPS gives PG&E not Iless than 10 one year's notice of such reduction. In such event, DPS,shall 11 par PG&E for transmission services based on the full, unreduced 12 MSD during that one-year notice periodi. 13 6.1.4 Duration of Service: DPS may request 14 Network Transmission Service, in the form of requests for MSD, on 'O qj 15 an annual or on a short-term firm basis, as desc'ribed in this i 16 Section 6.1.4. l 17 6.1.4.1 Annual Firm Service: PG&E 18 shall be obligated to provide Annual Firm Service among the ! 19 Transaction Points for any period requested by DPS that is within 20 the term of this Agreement and for a duration of not less than 21 one year. Such Annual Firm Service shall be firm transmission 22 service, subject to PG&E's right to study specific requests for 23 service as specifiec in Section 6.6. 24 6.1.4.2 Short-Term Firm Service: 25 DPS may request and pay for, and PG&E shall be obligated to 26 provide, Network Transmission Service in monthly increments for a 27 minimum of one month and a maximum of twelve (12) months in any f 1 N- ' 28 combination of contiguous or non-contiguous months within any 51
- . . -. - . _ . ~ _ . _ __ . . . . - - -- - - . . - _ . - - _ _ -
4 1 consecutive 12-month period. Such Short-Term Firm Service shall 8
/~j 2 be firm transmission service, subject to PG&E's right to study
(._/ 3 specific requests for service as specified in Section 6.6. The 4 rate for Short-Term Firm Service shall be the rate specified in 5 Section D.8.2 for Network Transmission Service. DPS may request 6 Short-Term Firm Service at any time during the term of this ) j 7 Agreement; provided, PG&E is not obligated to provide service ] 8 beyond the term of this Agreement. Short-Term Firm Service is
- 9 Network Transmission Service and the provisions of this Section 6 10 are applicable except as provided herein. The following ,
11 additional terms and conditions apply to Short-Term Firm Service: 12 (i) The period from the Notics Date'(specified in 13 Section 6.6.1) to the expiration of the term of the j 14 Short-Term Firm Service may not span more than 12 () 15 months. PG&E is not obligated to provide Short-Term Firm 16 (ii) 17 Service if providing such service would require any 1 I 18 system reinforcements or upgrades. I 19 (iii) DPS shall request Short-Term Firm Service in 1 20 accordance with Section 6.6 (except that an upgrade i 21 study under Section 6.6.6 would not be performed). , 22 (iv) DPS shall request Short-Term Firm Service in monthly 1 23 increments, not annual periods as described above t 24 for Annual Firm Service. Once PG&E has approved
- 25 Short-Term Firm Service requested by DPS, it shall 26 be provided on a take-or-pay monthly basis and there 2
27 will be no decreases in service permitted for the I 4
'- ) l' 28 term of the Short-Term Firm Service. Increases in 2 52
l 1 Short-Term Firm Service shall be made by separate 8 i (} 2 request in accordance with Section 6.1.4.2 (ill; . U 3 (v) The Transaction Points and MSD requested by DPS and 4 approved by PG&E in accordance with Section 6.6 , 5 shall be listed by month on Appendix K and shall be 6 added to any Annual Firm Service reserved for such H 1 l l 7 month on Appendix K. Such table shall also lis.t the~ l 8 Maximum Delivery Capability or Maximum Receipt 9 Capability of each Transaction Point. DPS shall 10 then have the right to transmit ,among Input Points 11 and Output Points listed on Appendix K in an amount 12 equal to the monthly MSD reserved for such service. 13 6.2 Rates and Charaes 14 Rates for Network Transmission Service shall be based on PG&E's Cost of Service for the term of'this Agreement. ( 15 16 For the initial three years of this Agreement, PG&E will provide 17 Network Transmission Service at the Transmission Rate set forth 18 in Section D.8.2.1. If DPS receives distribution level service 19 cither from an Input Point or to an Output Point at a primary 20 voltage level less than 60 kV but equal to .r o greater than 21 4.16 kV, DPS shall pay separately for such service at the Primary 22 Distribution Rate set forth in Section D.8.2.2. Where a 23 cransmission study (in accordance with Section 6.6) identifies 24 the need for system upgrades in order to provide requested 25 transmission service and the Parties agree to proceed with 26 construction, DPS shall pay, in accordance with Section D.8.4 the 27 higher of the following: i
- ('
i\ 28 (a) the Transmission Rate set forth in Section l 53 l
, . - . - . -_ = . . _ . --
1 D.8.2.1 (and/or Section D.8.2.2 for C (" 2 distribution service, if applicable), as (m,]/ ' 3 modified to reflect the Costs of construction 4 for any required system upgrades on a rolled-in , 5 basis as described in Section D.8.4; or 6 (b) a charge based on DPS' proportional share of' 7 the incremental Costs of any system upgrade j i l 8 that would not have been needed but for the l 1 9 transmission service requested by DPS as ) 1 10 described in Section D.B.4,. , I 11 If DPS pays all or a portion of the Costs of a system upgrade as 12 specified in subsection (b) above, DPS shall-be entitled to 13 transmission service on such incremental facility without any ; 14 additional charge for transmission service. In such event, the () 15 Parties shall agree upon a " Supplemental MSD" that may be 16 scheduled involving such system upgrade for which DPS shall not 17 be charged. Any such " Supplemental MSD" shall be specified on 18 Appendix K. PG&E reserves the right pursuant to Section 8.27 to 19 file with FERC requesting authority to revise the Transmission 20 Rate or the Primary Distribution Rate or the rate methodology by 21 which such rates are derived at any time beginning three (3) 22 years after the Effective Date of this Agreement, provided that 23 PG&E may earlier revise the Transmission Rate to reflect the 24 Costs of system upgrades needed to provide service to DPS and 25 paid for by DPS as part of the Transmission Rate on a rolled-in 26 basis (as described in subsection (a) above). 27 DPS shall pay for Network Transmission Service each 7_ s 28 Billing Period on a take-or-pay basis for the MSD as set forth in 54
1 Appendix K (exclusive of any " Supplemental MSD" as specified in 8 i
- 2 subsection 03) above), regardless of DPS' scheduled use of such
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3 Network Transmission Service during the Billing Period; provided, 4 however, that in any given Billing Period, if transmission 5 service is curtailed for greater than a 24 hour' period pursuant 6 to Section 6.3.1, DPS shall not be obligated to pay a propor- ] i 7 tional amount of the Monthly Billing Charge (i.e., 1/30 per) day) . 8 for each consecutive day of the curtailment. ! 9 6.3 Curtailment of Transmission Services 1 10 PG&E may curtail Network Transmission Service i 11 offered under this Agreement only in accordance with the' specific $ 12 provisions of this Section 6.3. l
, 13 6.3.1 Curtailments to Maintain Reliability:
J 14 PG&E may curtail Network Transmission Service: (a) in the case of O( j 15 Emergencies; Da) in order to install equipment or make repairs or 16 replacements co, make investigations and inspections of, or i 17 perform other work on PG&E's Electric System; (c) to prevent a . 18 hazard to life or property or unsatisfactory service to its , s l 19 customers' loads resulting from abnormal operating conditions, t 4 j 20 including excessive loop flow, which exist within PG&E's Electric
- 21 System or within the electric systems of others; and (d) where !
I ' 22 the operation of PG&E's Electric System is suspended, interrupted f 23 or interfered with as a result of Uncontrollable Forces. 24 6.3.2 Curtailments to Miticate Ooeratinc , 25 Problems Resultine from Excess Demand Over WSCC Path 15: In the
- 26 event that transmission line loading over WSCC Path 15 in either f 27 a north-to-south or south-to-north direction, based on daily I
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28 preschedules, hourly schedules, or real-time detemmination by 55 f
-1 PG&E dispatchers, and in PG&E's sole' judgement, is in excess of 8' /~ 2 Transmission Capability on WSCC Path 15, PG&E may curtail Netwcrk 3 Transmission Service in the sequence specified in Section 3.2 of f
4 the South of Tesla Principles reproduced in Appendix G. The j 5 amount and duration of such curtailment shall be consistent with 6 Prudent Utility Practice. For the purposes of this provision,~- f i 7 transmission service to DPS will be considered firm transmission j 8 service and will receive priority consistenc wi.th Section 3.2.2 9 of the South of Tesla Principles (Appendix G) for or on behalf of 10 Third Parties who have not contributed to the " initial - 11 reinforcements" or the:" South of Tesla Reinforcements" , 12 ("Section 3.2.2 Service") . Curtailments within a. curtailment. 13 block will be. allocated pro-rata among DPS and such other 14 recipients of Section 3.2.2 Service and-will be based upon DPS' ( 15 prescheduled or scheduled use (not the MSD) for'such period. The 16 South of Tesla Principles are appended to this Agreement only as- 1 17 a reference for establishing the curtailment priority of DPS 18 transmission uses relative to other transmission uses and serve 19 no other purpose relating to this Agreement. 20 6.3.2.1 Reduction of DPS Purchases 21 from Non-EA Resources and Imoorts: Subject to Section 3.1, in the 22 event of a curtailment order by PG&E pursuant to this f ( 23 Section 6.3, DPS shall physically curtail deliveries (i) from 24 curtailed Non-EA Resources which contribute to excess line l 1 ! 25 loading and (ii) of curtailed Imports from Control Area l I Interchange Points which contribute to excess line loading. l 26 ! Reduction of DPS Purchases ! 27 6.3.2.2 e t i 28 from EA Resources: If PG&E gives DPS notice of a curtailment in i ? i 56 l
l 1 i- i l 1 advance of DPS' submission of a final schedule ( i . e -. , 20 minutes di l (^% 2 before the hour), DPS shall submit its final schedule for l
\~- I 3 curtailed EA Resources as authorized by Section B.2.4 to reflect 1 4 the curtailment. The final. schedule for curtailed EA Resources 5 may differ from the preschedule in that DPS may reallocate the 6 amount of Excess Power to be purchased by PG&E or sold to DPS,-
7 provided that DPS purchases IHLB Service as specified in . 8 Section 4.2 for a change in allocation of EA Resources. After a l 9 final schedule is submitted by DPS to PG&E, such alloc.ation of l 10 curtailed EA Resource power to DPS is fixed for that hour and is 11 not subject to reallocation to PG&E for purc ase by PG&E'for that
- 12 hour. If PG&E orders a curtailment after a' final schedule is 13 submitted or within the active hour, DPS shall reduce its 14 purchases of energy from curtailed EA Resources in the manner (O) 15 prescribed in Section 3.1 such that, in accordance with the l l
16 formulas in Section 3.2, PG&E shall have no obligation to pay for. 17 any such curtailed power. l 18 6.3.3 Notice of Curtailment: PG&E shall use 19 good faith efforts to provide DPS two hours advance notice prior 20 to curtailing transmission service over WSCC Path 15, provided 21 further that with respect to any curtailment that PG&E canno 22 reasonably anticipate 2 hours in advance (e.g., loop flow-23 related), PG&E shall provide DPS advance notice of such 24 anticipated curtailment as soon as practicable. The Parties 25 acknowledge that PG&E may not be able to anticipate all 26 transmission curtailments in time to provide 2 hours notice. DPS , - 27 shall have the right to audit PG&E's operating records, including N/ 28 records of preschedules and schedules, to assess PG&E's good 57
. . . _ - . . - . - . - - - - ~ . - . - ~ . - _. .- .
c > jt . 1 faith and compliance with this'Section 6.3.3. 4 1 2 6.3.4 .Reclacement Power: Whenever PG&E curtails 3 DPS scheduled or pre-scheduled power in a south-to-north [ 4 direction on WSCC Path 15 from EA Resources or Non-EA Resources -i i 5 pursuant to Section 6.3.2, PGEE shall provide replacement power 6 to DPS; provided, however, PG&E has no obligation to provide 7 replacement power for a curtailment of an Import. DPS shall,be 8 entitled to replacement power for a time period. equal to, but not l 9 greater than, the full duration of the curtailment and.in an ; 10 amount equal to, but not greater.than, the amount of power that 11 is both qualified for replacement power and curtailed by'PG&E, j ! 12 based upon the preschedule or final schedule. submitted by DPS. ' l L 13 If DPS is selling power from EA Resources or Non-EA Resources 14 that is non-firm to a customer (i.e., that may be discontinued at ; l() 15 any time for any reason) using WSCC Path 15 in a. south-to-north ! 16 direction and such EA Resource or Non-EA Resource is curtailed by 17 DPS in response to PG&E's curtailmtut order in accordance with 18 Section 6.3.2, PGEE will provide non-firm replacement power, 19 provided, that such sale may be discontinued by PG&E at any time 20 for any reason. If DPS is making multiple sales which include 21 non-firm sales from both Southern Zone DPS Resources and Northern 22 Zone DPS Resources, the non-firm sales shall be presumed to have j 23 been made from Southern Zone DPS Resources for purposes of this 24 Section. PG&E is not obligated to provide replacement power for l 25 curtailments of WSCC Path 15 in a north-to-south direction. 26 6.3.4.1 Schedulino Reclacement j i to 27 Power: Upon notification by PG&E of a curtailment pursuant 1 Section 6.3.2, DPS shall notify PG&E of the amount of replacement 28 58
1 2 i j 1 power that DPS requires pursuant to Section 6.3.4, based upon 4 l 2 DPS' allocation of the curtailment among DPS Suppliers that are i 3 subject to curtailment pursuant to Section 3.1. For each hour of
- 4 the curtailment, PG&E shall provide replacement power based upon
[ 5 the latest request for such power submitted by DPS during such j 6 curtailment. In instances where PG&E is required to provide i 7 replacement power pursuant to Section 6.3.4, whenever PG&E i ' ? 8 requires that DPS curtail energy after submission of a final 9 schedule for the affected hour, PG&E shall provide, ahd DPS shall
.10 pay for, replacement power without notice by DPS or scheduling by 11 PG&EfortheentireportionofthathoursubecttocurtIilment 12 based upon the notice by DPS of the al' location of the 13 curtailment. In instances where PG&E is required to provide 14 replacement power pursuant to Section 6.3.4, DPS shall not.be
() 15 required to curtail energy during a scheduling hour except 16 insofar as PG&E provides real-time replacement of such power. 6.3.4.2 Payment for Reolacement 17 18 Power: DPS shall pay for replacement power provided by PG&E at 19 the rates and charges specified in Section D.9. The replacement -l i 20 energy for any Half-Hour Period shall be the product of the 21 replacement power (rate of delivery) and the length of time 22 within the Half-Hour Period that the curtailment is effective. 23 6.4 Transaction Points 24 The Transaction Points available for scheduling and 25 the applicable Maximum Delivery Capability or Maximum Receipt 26 Capability for each Transaction Point for purposes of providing 27 Annual and Short-Term Firm Service shall be listed in Appendix K, ( 28 as it may be amended from time to time to add or delete 59
l l 1 Transactions Points or to change the service available at each 4 /"' 2 Transaction Point in accordance with the process in Section E.E. V) Additionally, Appendix K shall designate all Input Points which l 3 4 are Southern Zone DPS Resources or Northern Zone DPS Resources. 5 6.4.1 Imoorts and Exocrts: Transaction Points 1 6 at Control Area Interchange Points may be used for both importing 7 to and exporting power from the PG&E Control Area; provided,, 8 however, that the full amount of simultaneous Imports and exports i 9 (and not the net difference between them) shall be thb. measure of l 10 DPS' use of its MSD for such Imports and exports. - 11 6.4.2 Interconnection Aareelment: As a ~ I 12 precondition to adding any new Transac' tion Point to Appendix K, 13 an Interconnection Agreement governing the interconnection of a 14 DPS Control Area Resource or DPS Load within the PG&E Control () 15 Area must be in existence, or be entered into, with PG&E pursuant 16 to this Section. If any entity located in PG&E's Control Area 17 but not directly connected to PG&E's Electric System agrees with 18 a Third Party (which is directly connected to PG&E's Electric l 19 System and has an Interconnection Agreement with PG&E) to deliver 20 or receive power to or from PG&E's Electric System, such Third 21 Par.y LMerconnection Agreement will be assessed by PG&E in 22 accordance with this Section 6.4 at DPS' request to determine 23 whether it satisfies the requirements of this Section 6.4.2. 24 6.4.2.1 Interconnection Acreement 25 Notice: Upon DPS requesting the addition of a new Transaction 26 Point to Appendix K pursuant to Section 6.6.1, PG&E shall respond 27 with respect to each proposed Transaction Point to DPS' request f-- i 28 in one of the following ways: (i) there is no Interconnection
, i 60 l
l I l 1 Agreement and one must be executed with PG&E; (ii) the existing di i i () l \J 2 Interconnection Agreement needs modification; or (1:1) the j 3 existing Interconnection Agreement is adequate. PG&E shall l l 4 respond to DPS' request no later than: (i) fifteen (15) days l 1 5 after receipt for a request pertaining 'to a municipal utility 6 with an existing Interconnection Agreement with PG&E; or (ii) 7 forty-five (45) days after receipt for all other entities. .3:f 8 PG&E notifies DPS that the existing Interconnection Agreement is 9 inadequate or needs further modification, PG&E shall further l l l 10 specify in its response the rationale for its determination and
' i 11 shall state whether the deficiency constitutes an Appendix C l l
12 issue or a non-Appendix C issue. If PG&E specifies the l l 13 deficiency is an Appendix C issue, and DPS disputes PG&E's ! 14 detennination, the dispute shall be deemed an Appendix C Dispute, r~N I ( ) 15 and DPS may initiate the dispute resolution procedures set forth ' l 16 in Appendix C. If PG&E specifies the deficiency is a non-17 Appendix C issue, and DPS disputes PG&E's determination, i l 18 notwithstanding any other provision of this Agreement, DPS may 19 either submit the dispute to arbitration in accordance with 20 Appendix A or may initiate a lawsuit in a court of competent 21 jurisdiction challenging PG&E's determination and requesting any 22 damages and/or other remedies which may be available at law or in l 23 equity. 24 6.4.2.2 No Existina Interconnection 25 Acreement: To the extent DPS requests to add a Transaction Point 26 to condu. a transaction with a Third Party resource or load j
,s 27 which does not have an Interconnection Agreement with PG&E, PG&E
( \
*2 28 may require such entity to execute an Interconnection Agreement l
61 1 1 1
4 q 1 with'PG&E, including the installation of tuetering equipment 45 l l 2 necessary to ensure' compliance with this Agreement. Appendix F ! 1 3 specifies the minimum metering requirements which nay be l 4 applicable to such new Interconnection Agreement. 5 6.4.2.3 Existine Interconnection , 6 Acreement Needs Modification: To the extent that DPS requests'to l
.7 af a Transaction Point for which PG&E has an existing j
. ?
8 Interconnection' Agreement, PGEE may require, as a precondition of l t 9 adding a Transaction Point, a modification to the Inte.rconnection ; i 10 Agreement subject to-the provisions of this Section 6.4.2. PG&E ( 11 shall~ negotiate in good faith to appropriatel'y modify the l 1 12 Interconnection Agreement and shall. limit the scope of such 13 negotiations and required modifications to only those specific 14 issues that must be addressed in order to add the Transaction 15 Point to Appendix K. 16 6.5 Deletion of Transaction Points 17 DPS may delete a Transaction Point (s) , or reduce 18 Maximum Receipt Capability or Maximum Delivery Capability, at any 19 time by providing written notice to PG&E. Su:h notices shall be l 20 ei'fective on the first (1st) day of the Billing Period following 21 the' Billing Period in which the notice is received by PG&E. 1 1
'22 6.6 Recuests for Transaction Points and Establishina 23 Levels of Maximum Simultaneous Demand I"MSD")
24 The Parties recognize that transmission capacity on i l PG&E's Electric System is limited. Therefore, the availability 25 26 of Network Transmission Service must be evaluated by PG&E on a 27 case-by-case basis whenever DPS seeks to: (i) add Transaction 28 Point (s); (ii) increase the Maximum Delivery Capability or 62
1 Maximum Receipt Capability at any Transaction Point; or (iti) 4 ("; 2 increase MSD. The procedure by which PG&E shall evaluate the (_s/ i 3 acceptability of additions or increases in Transaction Points and 4 increases to MSD is set forth in this Section 6.6. 5 6.6.1 Notification: Whenever DPS requests to 6 add a Transaction Point, or to increase the Maximum Delivery 7 Capability, Maximum Receipt Capability at any Transaction Point 8 or increase MSD, it shall do so by means of a written notice to 9 PG&E, which notice shall include the following information, if 10 available: s 11 (a) the Transaction ' Point (s) for which 12 the addit' ion or increase is 13 requested; 14 (b) the Maximum Delivery Capability, i es 1 Maximum Receipt Capability or MSD (-) 15 l 16 associated with the request; 17 (c) the transaction contemplated, 18 including the name of the Third 19 Party utility, if applicable; 20 (d) the amount of Spinning Reserve which 21 DPS may schedule at each Input 22 Point; 23 (e) monthly profiles of the energy to be 24 transmitted from a source, or to a 25 load, by on-peak, partial-peak, off-26 peak and super off-peak time periods 27 for each year;
> 28 (f) expected monthly and annual capacity 63
. . . . - -__ . - - . - . . - - - ~ . - - . . - - - - _ _ _ - - .
l l = 1 factors; 4' . l l j s 2 ( g ) '- the date upon which the addition er ( 3 increase is requested to become f l
; -4 effective-and to-terminate; and .;
- r 5 (h) other information which DPS elects J
} 6 to provide, or which PG&E reasonably J 3 7 requires, to determine the ., l 8 acceptability of the requested ;
. , t l-9 addition or modification.i. ;
i 10 The'" Notice Date" shall be the day on which PG&E 11 receives notice containing the information specified in subparts
~
12 .( a) through (h) where applicable and a'ailable. v j i ~13 With respect to.a PPA QF Supplier (as defined in # i 4 f 14 Section 2.10 of the Enabling Agreement), at the same'or at any-L() 15 later time that DPS provides PG&E written notice' in accordance I 16 with Section 5.2 (a) of the Enabling Agreement that it intends to l 4 t 17 submit a Schedule A Letter Agreement by which such PPA QF ]
- 18 Supplier will become an EA Resource, DPS may request to add the i
l 19 point at which power from such PPA QF Supplier will physically 1 I 20 enter.the PG&E Electric System as a Transaction Point in 4 e 21 accordance with this Section 6.6. PG&E shall consider the i ! 22 adequacy of'its Interconnection Agreement with the PPA QF 23 Supplier for purposes of adding a Transaction Point to accept ! 24 power from the PPA QF Supplier in accordance with the provisions and schedules and subject to the dispute resolution procedures 1 25
'26 set forth in Section 6.4.2.1.
I 27 6.6.2 Ten-Day (10-Dav) Resoonse: Within ten ; f ; 1 i 28 (10) calendar days from the Notice Date specified in l 7 ! 64 l
.. . . - . . . _ ~ - . . . - . - - _ - - - . . . - . - - ~ - . . . - - . - - -
1. l 1 Section 6.6.1, PG&E shall respond to DPS in writing whether 4 i l () V 2 (a) the requested addition or modification is available without , 3 further study and without conditions or limitations; (b) the ! 4 requested addition or modification is available without further 5 study subject to specific conditions or limitations; (c) the > i 6 requested addition or modification is unavailaD? e or (d) a sixty- l l 7 day (60-day) study will be required to determine 'i) the ,
. \
l l 8 availability of the requested addition or modificatl.on and 9 (ii) the need, if any, for the construction of reinforcements or 10 new transmission facilities necessary to accommodate the request. 11 Whenever possible, if PG&E cannot accommodate the addition or 12 modification unconditionally, it shall1 identify conditions or 13 limitations necessary to accommodate the addition or 14 modification. Whenever PG&E proposes conditions or limitations, () 15 it shall also specify whether, absent such conditions or 1 16 limitations, the requested addition or modification is ! 17 unavailable or whether further study is required to determine its 18 availability on an unconditional basis. Whenever a requested 19 addition or modification is unavailable, PG&E's response to DPS 20 shall state the reason therefore and shall include documentation 21 establishing the basis for PG&E's determination of I 22 unavailability. If a sixty-day (60-day) study is required and 23 PG&E shall require DPS to pay for the study (subject to 24 Sections C.1.2 (a) and C.1.4), PG&E's response shall also specify 25 the Costs of that study. ! 26 6.6.3 Service Available Based on Ten-Day (10-27 Dav) Resoonse: If the PG&E response states that the requested
' 28 addition or modification of a Transaction Point (s) and/or 65
i { 4 1 increase in MSD is available, DPS shall notify PG&E within thirty 4;I
- 2 (30) days whether it accepts the addition or modification tc
- 3 Appendix K, including any conditions or limitations required by 4 PG&E.
1 - 5 6.6.4 Sixty-Day (60-Dav) Study Recuired: If the
- 6 PG&E response states that a sixty-day (60-Day) study is required, 7 DPS shall notify PG&E of its decision to proceed with the st,udy
] 8 within ten (10) days after it receives PG&E's response. After 9 receipt of DPS' notice requesting PG&E to conduct the' sixty-day j 10 (60-day) study, PG&E and DPS shall agree on any additional
- i .
- 11 information needed and the assumptions that are reasonably
- 12 necessary to conduct the study. DPS may request that alternative 1-13 levels of service be considered as part of the study scope, i
i 14 provided that the Parties shall agree whether an extension of (n) 15 time to complete the study is necessary to accommodate such i 16 requests. PGEE shall commence the sixty-day (60-day) study upon
- 17 receipt of both the necessary information and DPS' payment for J
18 the study. Upon completion of the sixty-day (60-day) study, PG&E 19 shall notify DPS in writing whether (a) the requested addition (s) 20 or modification (s) of Transaction Point (s) .and/or increase in MSD 21 is acceptable without further study, or (b) an upgrade study is { j 22 necessary to determine the reinforcements or new transmission 23 facilities necessary to accommodate the request. If an upgrade i 24 study is necessary, PG&E may require up to ten (10) months to 25 conduct that study. PG&E's notice shall also specify the Costs 26 cf the upgrade study and DPS shall pay such Costs should it agree 27 to have PG&E conduct the upgrade study. O
\ ># Service Available Based on Sixtv-Day (60-Dav) 28 6.7 66
. - - ~ .. -. - - . - . - - -. -.- - .- - - - - -. . _ . -
1 i 1 Studv: If PG&E notifies DPS that the requestec addition (s) or
- l( 2 modification (s) of Transaction Point (s) or increase in MSD is
- 3 available, DPS shall notify PG&E in writing of its decision to
! 4 accept the service within thirty (30) calendar days of its l ! 5 receipt of the sixty-day (60-day) study results. l l 6 6.7.1 Ucarade Studv: If the upgrade study is I 7 required, DPS shall notify PG&E within thirty (30) calendar; days l 1 ; 8 of its receipt of the sixty-day (60-day) study results of its l ). 9 decision whether or not.to proceed. If DPS does not provide its 10 written notice within this thirty-day (30-day) period, PG&E's j i i l 11 agreement to conduct the study and continue the procedure in this l I 12 Section 6.6'is null and void. After receipt of DPS' notice 13 requesting PG&E to conduct the upgrade study and initial payment
- 14 for the study as required, PGEE shall conduct the study and DPS t
15 shall comply with any additional informational requirements for I 16 the study. 4 i Construction Recuired: Subject to the 17 6.7.2 18 limitations of Section 6.1.2, PG&E shall, upon request'by DPS, j 19 construct upgrades necessary to provide Network Transmission 20 Service. If PG&E and DPS agree to proceed:with construction, i I' 21 PG&E shall prepare and submit to DPS (a) the schedule for the s
- 22 detailed engineering design, regulatory filing (s) (if
{ 23 applicable), and construction period, and (b) the estimated Costs 24 of the design, engineering and construction. To the extent these R25 Costs would be paid for by PG&E, PG&E may condition proceeding j 26 with the project on the Parties negotiating provisions that 27 provide PG&E with reasonable protection from stranded investment. 28 The Parties shall agree in writing on the date when service will 67
i-l l ' 1 begin; provided the execution of the agreement to proceed with 4 ; 2 construction shall not extend the term of this Agreement. 3 6.7.3 Information Beaardinc Studies: PG&E shall ; i 4 provide DPS with all data reasonab',y necessary to analyze the i 5 results of PG&E's studies pertaining to DPS' requested addition 6 or modification of Transaction Point (s) or increase in MSD to , 1 7 enable DPS to independently verify the results of the study.and : I L - - l 8 to make an informed judgment whether to authorize PG&E to [ 9 proceed. If any study referred to in this Section 6.6,may 10 involve confidential or proprietary information, PG&E shall so- , 1 L . [ 11 notify DPS prior to DPS' authorization of the' studies, an'd the l
)
12 Parties shall follow the procedures de' scribed in Sections 8.21 13 and 8.22. To the extent DPS submits confidential or proprietary 9 14 information to PGEE to conduct any study, DPS shall so notify ( 15 PG&E, and the Parties shall follow the procedures described in I l ! 16 Sections 8.21 and 8.22. ; 17 6.7.4' Network Transmission Service Provided 18 Under Soecial Conditions: In certain cases, the Parties may agree l 19 in writing to special conditions associated with a particular 20 request made by DPS for Network Transmission Service. In those 21 cases, PG&E shall specify the additional terms and conditions, 22 pessibly including special curtailment provisions, that will 23 . apply to that request and, if DPS elects to accept those terms 24 and conditions, such transmission service shall qualify as 25 Network Transmission Service under this Agreement. Once 26 accepted, such terms and conditions may be changed only by ; i j s 27 subsequent written agreement of the Parties. If the terms and 28 conditions include special curtailment provisions, PG&E shall 68
=. . - - - . .. ._. .- . . .. - . _.
i I 1 curtail DPS* use of that Network Transmission Service pursuant tod 2 Section 6.3 in accordance with those special curtailment 3 provisions. l 4 6.7.5 Informational Review: In addition to its l l 5 rights to request to add a Transaction Point, to increase the 6 Maximum Delivery Capability or Maximum Receipt Capability at any 7 Transaction Point, or to increase MSD pursuant to this Section 8 6.6, DPS may at any time request that PG&E provide an 9 informational review of the capabilities of the PG&E system to 10 provide Network Transmission Service sufficient to accommodate a 11 contemplated DPS transaction. Such informational review will be 12 conducted at no cost to DPS. In requesting 'such an inf orn_tional 13 review, DPS shall provide PG&E information of the type required 14 by Section 6.6.1 in sufficient detail to enable PG&E to conduct () 15 an informational review. PG&E will provide DPS'its preliminary 26 appraisal as to availability of service within ten (10) calendar l 1 17 days of receiving all necessary information. If DPS ultimately l 18 makes a formal request pursuant to Section 6.6.1 to add or modify l 19 a Transaction Point or to increase MSD in order to proceed with ! l 20 the transaction which was the subject of the informational 21 review, the results of the informational review shall not be 22 binding upon PG&E. To the extent DPS submits confidential or 23 proprietary information to PG&E for the purposes of an 24 informational review pursuant to this Section 6.6.10, DPS shall 25 so notify PG&E, and the Parties shall follow the procedures 1 26 described in Sections 8.21 and 8.22. l l 27 6.7.6 Eroedited Procedures for Discutes
- 28 Recardine Unavailability of Network Transmission Service: In the 69
)
1 event of an Appendix C Dispute, DPS may initiate the dispute 8 2 resolution procedures set forth in Appendix C. 3 6.7.7 Costs of Studies: If required by PG&E, 4 and subject to Sections C.1.2 (a) and C.1.4, DPS shall reimburse 5 PG&E for any reasonable and actual additional Costs incurred by 6 PG&E'to perform the studies required by Section 6.6.4. In 7 performing any studies required by this Agreement, PG&E shal.1, to 8 the extent possible, use its previous studies and avoid 9 duplication or otherwise endeavor to avoid incurring tinnecessary 10 Costs in response to DPS' requests. DPS shall have the right to 11 inspect and audit PG&E's records to independ ntly verify the
~
12 Costs of any studies for which PGEE seeks reimbursement. 13 6.7.8 Availability of Curtailable Service on 14 WSCC Path 15: Notwithstanding the foregoing provisions of Section 15 6 and subject to Sections 8.17 and 8.18, wheneve'r DPS requests to 16 add or modify a Transaction Point, or increase MSD, PG&E shall 17 evaluate the availability of curtailable service (pursuant to 18 Section 6.3.2) in accordance with this Section 6. To the extent 19 DPS' request involves the transmission of power from EA Resources 20 which executed PPAs with PG&E prior to the Effective Date, PG&E 21 shall make the curtailable service on WSCC Path 15 available. To 22 the extent DPS' request involves the transmission of power from 23 DPS Suppliers other than these EA Resources, PG&E shall evaluate 24 the availability of curtailable service on WSCC Path 15 in 25 accordance with this Section 6. 26 6.8 No Service to PG&E Retail Customers DPS may not use service under this Agreement to sell 27 28 electricity to a retail customer located within the PG&E utility 70
-- - - .-- - - _ . ...~ .-.~ - - - - - - - - .-. - - - _ - .-.
i l i service territory. DPS may not designate retail loads within d' i 2 PG&E's . utility service territory as ' Transaction Points nor may j 3 DPS schedule to any retail loads within PG&E's. service territory ' 4 as DPS Loads. l 5 6.9 Use Of Transmission Service By Third Parties 6 Network Transmission Service is not assignable;
- 7 however, DPS may broker to any Third Party some or all of the 8 Network Transmission Service available to DPS under this '
9 Agreement in accordance with the following procedures:. 10 (i) In accordance with Section-6.6, DPS shall 11 request, and PG&E shall make, if available, any
~
12 changes in the Transaction-Points listed in 13 Appendix K needed to accanmodate the Third 14 Party transaction, to the extent such changes 15 are necessary;. 16 (ii) DPS shall schedule such Third Party 17 transactions with PG&E on the Third Party's 18 behalf in accordance with Appendix B; and 19 (iii) DPS shall make available such Network i 20 Transmission Service to the Third Party 21 pursuant to the terns and conditions for such 22 service set forth in Section 6 and subject to 23 rates that do not exceed DPS' cost of obtaining 2 <4 the service from PG&E, including payments to 25 PG&E and any additional costs incurred by DPS. 26 6.10 Transmission and Distribution Losses 27 All power debits by DPS from the DPS Pool using 28 Network Transmission Service provided by PG&E to DPS under this 71
-=ei--p- ,- g y- g - -
----ur e*-rr 4i-n rg-'-
1 Agreement shall be adjusted for transmission and, if applicable, j () 2 3 distribution losses, which are specified in Section 4.6.3. 4 7.0 BILLING AND PAYMENT j 5 7.1 Billina 6 The Parties shall prepare and submit bills, as . 7 necessary, to each other after the end of each Billing Perio,d for 8 any charges in that Billing Period arising under this Agreement. 9 7.2 Payments 10 A Party's payment for charges arising under. this 11 Agreement shall be made in full, either directly to the other. 12 Party (for undisputed amounts) or, at'the paying Party's 13 election, to an escrow account in accordance with Section 7.3.2 J 14 (for disputed amounts, only). Payment of any bill shall be due j () 15- upon delivery and must be received by the other Party or
- 16 deposited into the escrow account (if disputed) no later than l
l thirty (30) calendar days after delivery (" Payment Due Date"). l 17 18 Bills not paid in full by the Payment Due Date shall accrue , J 19 interest at the rate specified in Section 7.4. Interest shall 20 accrue on the unpaid amount from the Payment Due Date until the 21 date full payment is received by the billing Party. 22 7.3 Discuted Bills 23 7.3.1 Notice of Discute: If the paying Party 24 disputes all or a portion of a bill, it shall pay the full 25 undisputed amount, without offset or reduction, directly to the 26 billing Party; and on or before the Payment Due Date, both (a) 27 notify the billing Party in writing of the amount in dispute and 28 the basis for the dispute, and (b) pay the disputed portion 72 I
l , 1 directly to the billing Party or, at the disputing Party's *;
~T (d 2 election, pay the disputed amount into an escrow account in 3 accordance with Section 7.3.2. Under no circumstances may a 4 Party simply withhold payment either from the other Party or from 5 the escrow account. PG&E and DPS shall endeavor to resolve any l
6 disputed bill prior to the Payment Due Date. l 7 7.3.2 Escrow Account: If an escrow account,is 8 established, it shall be with an agent approved.in advance by 9 both Parties and in a form acceptable to both Parties
- The -
10 instructions given to the escrow agent shall. include an , express 11 obligation on the agent's part to release sufficient. funds from 12 the account, including interest that h'as accrued on the account, 13 to pay in full one of the following amounts (plus accumulated 14 interest on that amount) as applicable: (a) the disputed amount .~ 15 as originally billed; (b) an alternative amount agreed upon by 16 PG&E and DPS; or (c) the amount determined by FERC or another 17 tribunal of competent jurisdiction, or in accordance with dispute 18 resolution, as specified in Section 8.8, to be due but unpaid. 19 The disputing Party shall pay all costs and penalties that may be 20 associated with withdrawing funds to pay the other Party. Any 21 funds remaining in the escrow account after payment, including 22 accumulated interest on those remaining funds, shall be returned 23 to the disputing Party. 24 7.4 Acolicable Interest Rate 25 Interest shall be at the rate calculated in 26 accordance with the methodology for refunds pursuant to Section 35.19 of FERC's regulations (18 C.F.R. S 35.19), as such 27 O- 28 regulations may be changed or superseded. 73
1 7.5 Effect of Non-Pavment - Default *I l 1 1 2 Whenever a Party fails to receive a payment due (~J} l 3 under this Agreement by the Payment Due Date, such Party may I 4 issue a written notice of non-payment to the other Party stating i 5 with specificity the amount of, and basis for, the payment and 6 the provisions of this Section 7.5. A Party's failure to make' 7 any payment to the other Party (or, if applicable, to an esQrow 8 account) within 30 (thirty) days of receiving such notice, shall I 9 constitute a default for which a Party may seek termination in 10 accordance with Section 8.2 of this Agreement or such other 11 remedies as the Party may be entitled to under this Agreement and j 12 applicable law. If DPS fails to make payment to PG&E (or if i 13 applicable, to an escrow account) within thirty (30) days of 14 receipt of such notice, PG&E may send a notice to suspend service (n) v 15 to DPS. If DPS fails to pay the amount owed PG&E (or, if 16 applicable, to an escrow account) within thirty (30) days after j 17 receipt of said notice, PG&E may suspend providing services. ; 18 19 8.0 GENERAL PROVISIONS 20 8.1 ADoendices Incorocrated i I 21 The following documents, as they may be revised from 22 cime to time, are attached to this Agreement as Appendices and 23 are incorporated by reference as if fully set forth herein: 24 Appendix A: DISPUTE RESOLUTION AND ARBITPATION l 25 Appendix B: SCHEDULING 26 Appendix C: EXPEDITED PROCEDURES FOR TECHNICAL l l DISPUTES
,3 27 l j Appendix D: RATFS AND BILLING DETERMINANTS
(_/ 28 Appendix E: EN7 .. TREEMENT l [
1 1 Appendix F: METERING REQUIREMENTS dl 1
/~'t 2 Appendix G: SOUTH OF TESLA PRINCIPLES i V
3 Appendix H: TIME PERIODS 4 Appendix I: UTILITY IDENTIFIERS AND TRANSACTION l CODES l 5 Appendix J: DPS REQUIREMENTS FOR AGC REGULATION AND 6 SPINNING RESERVE l 7 Appendix K: NETWORK TRANSMISSION SERVICE TABLE. 8 9 8.2 Default 10 8.2.1 Remedy for Default: If either Party 11 defaults on this Agreement, the other Party may terminate this i 12 Agreement; provided, however, that prior to such termination the 13 Party must provide the defaulting Party with written notice j 14 stating: 1) the Party's intent to terminate; 2) the date of such l () 15 intended termination; 3) the specific grounds for termination; 4) 16 specific acticns which the defaulting Party must take to cure the 17 default; and 5) a reasonable period of time, which shall not be 18 less than sixty (60) days, within which the other Party may take I 19 action to cure the default and avoid termination. l 20 8.2.2 Other Remedies for Default: The remedy 21 under Section 8.2.1 is not exclusive, and either Party shall be 22 entitled, in addition, to pursue any other legal, equitable, or l 23 regulatory rights and remedies it may have in response to a 24 default by the other Party. 25 8.3 Assianment l 26 This Agreement is not subject to assignment by 27 either Party without the prior written consent of the non- ! 28 assigning Party; provided the other Party shall not unreasonably 75
1 withhold such written consent. This Section 8.3 shall not imoaire P
) 2 or inhibit DPS' rights to broker unused Network Transmission l (/
N-l 3 Service to any Third Party pursuant to Section 6.8. 4 8.3.1 Assianment Bv Consent: Neither Party may 5 sell, transfer or assign all or any part of this Agreement or any 6 rights, benefits, or duties under it without the prior written 7 consent of the other Party, which consent shall not be 8 unreasonably withheld; provided, that this Section 8.3.1 shall 9 not apply to interests that arise by reason of any dee'ds of : 10 trust, mortgages, indentures, or security agreements heretofore 11 granted or executed by a Party. 12 8.3.2 Assionee Oblications: Any successor to or 13 transferee or assignee of, the rights of either Party, whether by ; I 14 voluntary transfer, judicial sale, foreclosure sale, or j () 15 otherwise, shall be subject to all terns and conditions of this 16 Agreement to the same extent as the assigning Party. 17 8.3.3 Assioner Oblications: The transferor or 18 assignor of all or any part of this Agreement or any right or 19 benefit under it shall continue to be obligated by all of the 20 terms and conditions of this Agreement in the event its 21 successor, transferee or assignee fails to perform as required by l 22 this Agreement. 23 8.3.4 No Assianment of Transmission Service: 24 DPS may not assign Network Transmission Service except as part of an assignment of this entire Agreement. However, nothing in this 25 26 section is intended to modify or limit DPS' right to broker 27 Network Transmission Service pursuant to Section 6.8. 28 76
1 1 l-1 8.4- Caetions 4!
- i l 2 All indexes, titles, subject headings, section
) 3 titles, and similar items are provided only for the purpose of ! 4 reference and convenience and are not intended to affect the i 5 meaning of the contents or scope of this Agreement. 4 6 .8.5. Construction of Acreement 7 Both Parties have significantly contributed to yhe 8 drafting of this Agreement. However, ambiguities or , 9 uncertainties in the wording of this Agreement shall hot be 10 construed for or against either Party, but shall be construed in 11 a manner that most accurately reflects the intent of the Parties l 12 when this Agreement was executed and is consistent with.the I 13 nature of the rights and obligations of the Parties with respect l l 14 to the matter being construed. l I
, 15 8.6 Control And Ownershio of Facilities 1 16 8.6.1 Ownershio: PG&E's Electric System shall 17 at all times be and remain in the exclusive ownership, possession 18 and control of PG&E, and nothing in this Agreement shall be 19 construed to give to DPS any right of ownership, possession or 20 control of that Electric System. PG&E shall own, operate and 21 maintain all reinforcements to its Electric System installed in 22 connection with this Agreement at PG&E's expense. Ownership of 23 reinforcements installed.at DPS' expense.shall be as agreed by 24 the Parties. I 25 8.6.2 Parties' Oblication: The Parties, at 26 their own expense, shall have readily available any equipment and 27 facilities as are necessary to enable them to perform their l 28 respective obligations under this Agreement. l 1
77
! i 1 8.7 Cooperation and Richt of Access and Insoectier * [ ) 2 The Parties shall grant each other all necessary 3 permission to enable each other to carry out this Agreement. The 4 Parties shall have the right to have agents, employees and 5 representatives enter premises of the other Party at all 6 reasonable times and in accordance with reasonable rules and 7 regulations which shall be mutually agreed to and established by' 8 PG&E and DPS for assuring performance under this Agreement. PG&E 9 shall provide DPS access to its meters and other facilities, and 10 take (or permit DPS to take) such other actions as reasonably 11 necessary, to ensure that the real-time data. relied upon by DPS 12 for its operations is the same as the;information PG&E will use 13 to determine DPS' compliance with this Agreement generally and, 14 in particular, Sections 3 and 4 of this Agreement.
,O
( _,) 15 8.8 Discute Resolution 16 The Parties agree to make best efforts to settle all'. 17 disputes arising under this Agreement by mutual agreement. The 18 Parties intend and agree that all unsettled disputes arising 19 under this Agreement shall be resolved exclusively according to 20 the procedures set forth in Appendix A of this Agreement, such 21 procedures constituting the Parties' agreed upon, mandatory, 22 binding and exclusive remedy, provided that DPS has the 23 additional rights to initiate the dispute resolution procedures 24 set forth in Appendix C with respect to any Appendix C Dispute 25 and to initiate a lawsuit in any court of competent jurisdiction 26 pursuant to Section 6.4.2.1. ( 27 8.9 Excansion of Oblications or Material Modification C 28 If any branch of government or agency thereof, 78
l
- j. 'l including the CPUC, FERC or any other. regulatory body or agency, d{ :
2 or any court of competent jurisdiction determines, at any time 3 af ter FERC has accepted this: Agreement and made it not subject to 4 refund, that this Agreement, or any provision hereof, its j l 5 operation or effect, is unjust, unreasonable, unlawful, imprudent 6 or otherwise not in the public interest, or imposes a change or ! 7 modification unacceptable to either Party, including requiring 8 either Party to incur new or different obligations beyond those , 9 expressly provided herein, the Parties shall negotiats a revised 10 Agreement with the intent to preserve for each Party the, original 11 intended benefits of this Agreement. If the Parties.are unable ! l 12 to reach agreement on revisions to the' Agreement within one 13 hundred twenty (120) days, as may be extended by agreement of the 14 Parties, either Party may provide notice as provided for in 15 Section 8.19 to terminate this Agreement. 16 8.10 Governine Law 17 This Agreement shall be interpreted, governed by, 18 and construed under the laws of the State of Califernia or the 19 laws of the United States, as applicable, as if it were executed 20 and to be performed wholly within the State of California. 21 8.11 Information 22 Either Party shall provide the other, upon request, j 23 the appropriate information and documentation reasonably ! 24 necessary to fulfill the obligations the other Party has agreed 25 to undertake under this Agreement. 26 8.12 Judoments and Determinations 27 When the terms of this Agreement provide that an L 28 action may or must be taken, or that the existence of a condition 79
1 1 may be established, based on a judgment or determination of a * (') V 2 Party, such action or judgment shall be exercised er such 3 determination shall be made in good faith and, where applicable, ! 4 in accordance with Prudent Utility Practice, and shall not be 5 arbitrary or capricious. 6 8.13 Liability l 7 8.13.1 To Third Parties: Except as otherwise ' 8 expressly provided herein, nothing in this Agreement shall be 9 construed or deemed to confer any right or benefit on', or to i 10 create any duty to, any standard of care with reference.to, or j 11 any liability or obligation, contractual or otherwise, on the 12 part of PG&E, or on the part of DPS, to anyLParty other than the 13 other Party. 14 8.13.2 Between the Parties: The Parties' duties
/~'N
( ,) 15 and obligations are set forth in this Agreementi The Parties' 16 duty and standard of care with respect to each other, and the 17 benefits and rights conferred on each other shall be no greater 18 than as explicitly stated herein. Neither Party, its directors 19 or members of its governing board, officers, employees or agents, 20 shall be liable to the other Party for any;1oss, damage, claim, 21 cost, charge or expense, whether direct, indirect or 22 consequential, arising f rom the Party's perf ommance or j 23 nonperformance under this Agreement, except for a Party's gross l 24 negligence or willful misconduct. l 25 8.13.3 For Electric Disturbance: PG&E shall be l 26 responsible for protecting its facilities from possible damage by 27 reason of electric disturbances or faults caused by the 7~ U 28 operation, faulty operation or non-operation of its facilities, i 80 l l
~ i 1 and DPS shall not be liable to PG&E for any damage so caused.
- 1 4 2 8.13.4 For Interruotions: Neither Party shall be 3 liable to the other Party for any claim, demand, liability, loss,
- 4 or damage, whether direct, indirect, or consequential, incurred 5 by the Parties or their respective customers, which results from 6 the interruption or curtailment of electric services provided a
7 under this Agreement; provided that, such interruption or , } 8 curtailment occurs in accordance with the provisions of this 9 Agreement. 10 8.14 Limited Service 11 By providing the specific services limited to the ) 12 express uses specified hereunder, PG&E does not offer or agree to 13 provide other, additional, or more broadly-defined services to i 14 DPS, or to any Third Party, whether under this Agreement or 15 otherwise. . l 16 8.15 No Acreement to Serve Others 17 PG&E, by filing this Agreement with FERC, does not 18 hold itself out to furnish like or similar service to any other ) 19 person or entity. : ' \ 20 8.16 No Dedication of Facilities 1 21 Any undertaking by either Party to the other under 22 any provision of this Agreement is rendered strictly as an 23 accommodation and shall not constitute the dedication of its 24 Electric System or any portion thereof by PG&E to the public, to l 25 DPS or to any Third Party. Any such undertaking under any 1 26 provision of, or resulting from, this Agreement by PG&E to DPS - 27 shall cease upon the termination of this Agreement. 28 1 81
1 i j I 1 8.17 No Precedent si l 4 )\(~ 2 3 This Agreement establishes no precedent with regard to any other entity or agreement. Nothing contained in this 4 Agreement shall establish any precedent for other arrangements j
- 5 between PG&E and DPS for interconnection and operations or for 6 the' transmission, purchase or sale of any electric capacity or- I 7 energy.
$ 8 8.18 No Third-Party Beneficiaries 9 No right or obligation contained in this Agreement
, 10 shall be applied or used for the benefit of any person or entity
~
11 not a Party. l < l j 12 8.19 Notices 4 13 8.19.1 Formal Notices: With the exception of 14 notice requirements specified in Appendix B, any notice, () r 15 declaration, request, demand, information, report, or item otherwise required, authorized or provided for in this Agreement 16 17 shall be given in writing, except as otherwise provided in l 18 Section 8.19.3, and shall.be deemed properly given if delivered 19 personally or sent by first class United States Mail or its 20 equivalent, postage prepaid, or by other means agreed to in 21 advance and in writing by the Parties, to each of the persons i 22 specified in Section 8.19.2. 23 8.19.2 Desionation of Notice Recuirements: 24 To PG&E: Manager - Grid Customer Service 25 Mail: Mail Code B23A P.O. Box 770000 26 San Francisco, CA 94177 27 Hand Deliver: Room 2319 77 Beale Street ( ) 28 San Francisco, CA 94177 82
)
i l 1 To DPS: Manager - Western Operations ej Destec Power Services, Inc. I ! /"' 2 1676 N. California Blvd., Suite 400 lk - Walnut Creek, CA-94596 : ! 3 ! - and - 4 l President 5 Destec Power Services, Inc. ! 2500 CityWest-Blvd., Suite 150 l 6 Houston, TX 77042 1 7 l 8.19.3 Routine Notices: Notices of a routin'e 8 character, either in connection with this Agreement, including 9 ' billing statements and scheduling, or in connection with the 10 operation of facilities, shall be given in s0.ch a manner ^,as_PG&E 11 may determine is appropriate from time to time, unless otherwise 12 provided in this Agreement. 13 8.19.4 Chances of Notice Recioient: Either PG&E 14 s or DPS may change its designation of the person.who is to receive s 15 notices on its behalf by giving the other Party notice thereof in 16 the manner provided in Section 8.19.1. Formal notices shall be 17 limited to two (2) names per Party. 18 8.20 Procedures. Rules, and Reaulations 19 PG&E and DPS shall mutually agree upon and put 20 into effect,_from time to time, such procedures, rules and 21 regulations as may be required in order to establish the methods 22 of-operation to be followed in the performance of this Agreement. ! 23 If the-Parties cannot agree upon such procedures, rules and 24 regulations within a reasonable time, and/or cannot agree , 25 , J pursuant to Section 4.3.5 to any changes in the Spinning Reserve 26 Requirement, either Party may demand arbitration of the dispute ! 27 pursuant to Appendix A. To the extent the Parties cannot agree l( i
).
28 upon interim procedures, rules and regulations or interim changes 83
I l i i i 1 in the Spinning Reserve Requirement, for the period of 8{ 2 arbitration, PG&E shall determine such interim procedures, rules, ()T
\_ , l 3 regulations and the interim Spinning Reserve Requirement l l
l 4 (" Interim Rules), provided that DPS has the right to initiate the l
.9 dispute resolution procedures set forth in Appendix C with t
respect to any Interim Rules established by PGEE without DPS' ! 7 concurrence. et; 8.21 Proerietarv or Confidential Information 91; 8.21.1 Information Release: Except as explicitly i 3"/'provided in this Section 8.21, nothing in this Agreement shall 11 require either Party to make proprietary or confidential. 12 information available to the other Pa'rty, or to any Third Party. 13 8.21.2 Notice: Each Party shall notify the other 14 Party when information requested is considered proprietary or O(,/ 15 confidential. 16 8.21.3 Eymmination: To the extent information is 17 not shared pursuant to this Section 8.21, the Party not providing 18 the information may afford the other Party the right to examine, 19 in the Party's office, documents that contain proprietary or 20 confidential information. In such case, the requesting Party 21 shall not have the right either to obtain or to make copies of j 22 all or any part of such documents. 23 8.21.4 Disclosure: Before a Party examines 24 proprietary or confidential information, its representatives, 25 agents, employees, attorneys, or consultants shall agree, to the 26 extent permitted by law, (1) to treat such information as 27 confidential, (2) not to disclose any such information it 28 receives to any Third Party, (3) not to use such information for 84
i l l any purpose other than the enforcement or performance of this 8
. 1 D 2 Agreement, and (4) to comply with any protective order applicable b
3 to such information. 4 8.22 Restricted Use of Confidential DPS Information 5 PG&E acknowledges that information it may receive 6 from DPS (such as possible uses of transmission services, l 7 requests pursuant to Section 6 for additions or modification of Transaction Points or increases to MSD and other indications of 8 , 9 possible or pending transactions) is confidential and'; 10 proprietary. PG&E agrees that it will not disclose any 11 information designated by DPS as confidential or proprietary to ; 12 any Third Party or to PGEE marketing personnel. PGEE further l l l 13 agrees that it will use such information for no purpose other l 14 than to discharge its obligations and exercise its rights j A b 15 pursuant to this Agreement and,.if applicable, pursuant to the 16 Enabling Agreement, that it will limit distribution of such 17 information solely to PGEE personnel that are required to have 18 such information for such purposes, and that it will not release 19 such confidential information to a Third Party without having first provided reasonable notice to DPS. Unless required by law, 20 l 21 PG&E will not release such confidential information without 22 obtaining DPS' prior express written consent. 23 8.23 Specificity of Power Calculations 24 Unless expressly stated otherwise in this 25 Agreement or its Appendices, all power calculations, schedules, 26 deviation calculations and similar information required under 27 this Agreement shall be rounded to the nearest one hundred (100) l 28 kilowatts; provided that all schedules to Control Area 85
.-.. .. -- -._ .- - - . . - - . - - . = - . -. _ ~ - - -.
l 1 Interchange Points will be rounded to the nearest one (1) MW. 8;
/ 2 8.24 References 3 The following reference materials, as revised from 4 time, to time are available for use by DPS, the DPS Power Control 5 Center, and DPS' cperating personnel and may be requested from 6 the designated PG&E switching center or the regional PG&E 7 electric operations manager: .
8 (a) General Operating Instructions - A booklet 9 listing in general terms all the standard 10 operating orders to be fpilowed by PGEE 11 system operators; 12 (b) PGEE Standard Practice No. 403 Switching 13 Procedures, applicable forms and their use; . 14 (c) PGEE Standard Practice No. 403 l 15 Instructions for obtaining clearances on i 16 lines; 17 (d) Western Systems Power Pool Agreement; and 18 (e) PG&E's Power Producer's Interconnection 19 Handbook. 20 8.25 Severability 21 To the extent that any term, covenant, or condition 22 of this Agreement or the application of any such term, covenant, 23 or condition is held to be invalid as to any person, entity, or 24 circumstance, by FERC or by any other regulatory body or agency 25 or court of competent jurisdiction, such term, covenant or 26 condition shall cease to have force and effect; in that event, 27 however, all other tenns , covenants and conditions of this 28 Agreement and their application shall not be affected thereby, 86
l l 1 but shall remain in force and effect unless an agency or court of8 2 competent jurisdiction finds that such provision is not separable ' (} 3 from the affected provisions of this Agreement. 4 8.26 Uncontrollable Force l 5 8.26.1 No Party shall be considered to be in l 6 default in the performance of any obligation under this I 7 Agreement, other than an obligation to make payment in accordance 8 with this Agreement, when a failure of performance is the result - 9 of an Uncontrollable Force. 10 8.26.2 Nothing in this Agreement shall be 11 construed to require a Party to settle any strike or labor 12 dispute in which it may be involved. 13 .8.26.3 In the event a Party is rendered unable 14 to fulfill any obligation under this Agreement by reason of an 15 Uncontrollable Force, such Party shall give prompt written notice 16 of such fact to the other Party and shall seek to remove such 17 inability with all reasonable dispatch. 18 8.27 Unilateral Rate Chances _ 19 8.27.1 Except as expressly provided in 20 Section B.27.2, nothing contained in this Agreement shall be 21 construed as affecting in any way the right of PGLE under this 22 Agreement to unilaterally make application to FERC for a change 23 in any rates, terms and conditions contained herein under 24 Section 205 of the Federal Power Act or its successor and 25 pursuant to FERC's Rules and Regulations promulgated thereunder. 26 For purposes of this Section 8.27, the term " rates" shall be
- 27 deemed to include any and all terms and conditions, rules, l
i 28 charges, classifications, rate principles, rate methodology, 87
I 8 1 accounting principles and practices, and all other matters. () 2 Nothing contained herein shall be construed as affecting in any 3 way DPS' rights to intervene, protest, or otherwise oppose any 4 unilateral filing which may affect this Agreement. Except as 5 expressly provided in Section 8.27.2, DPS expressly reserves its 6 rights to file with FERC under Section 206 of the Federal Power 7 Act to change rates, terms and conditions of this Agreement: 8 8.27.2 Section 205/206 waivers: PGEE hereby 9 waives for the term of this Agreement its rights under Federal 10 Power Act Section 205 to modify unilaterally.the energy, loss 11 factors specified in Section 4.6.3. Except as provided in 12 Sections J.4.2.2 and 6.2, PGEE further waives all' rights under 13 Section 205 of the Federal Power Act to unilaterally request 14 changes in rates, term or conditions to the Agreement for the 15 first three (3) years following.the Effective Date of the 16 Agreement. DPS waives all rights under Federal Power Act 17 Section 206 to make application for a change in rates in the 18 Agreement or otherwise challenge the operation of this Agreement 19 for the first three (3) years following the Effective Date of 20 this Agreement. DPS further waives its rights under Federal 21 Power Act Sections 211, 212 and 213 to apply to FERC for_an order 22 compelling PG&E, during the term of this Agreement, to provide 23 transmission service if such transmission service is intended to 24 be made available by the provisions of this Agreement. 25 8.28 Transmission Tariffs and Third Party Acreements , 26 Nothing in this Agreement shall affect or limit DPS' 27 rights to obtain transmission service: (a) pursuant to any PG&E 28 tariff providing transmission service, provided that DPS shall 88
i 1 take transmission service exclusively under either this Agreement
- or such tariff; or (b)~ under the Western Systems Power Pool. f
) 2 3 Nothing in this Agreement shall affect or limit any Third Party's 1
4 rights to have DPS power delivered over PG&E's Electric System in i 5 accordance with any transmission service agreement (including 6 service provided to a Third Party under a tariff) between PG&E' 7 and a Third Party. , 8 8.29 Waiver of Richts 9 Any waiver at any time by any Party of its rights 10 with respect to a default by the other Party,under this
- 11 Agreement, or with respect to any other matter arising in 12 connection with this Agreement, shall'not constitute or be deemed 13 a waiver with respect to any subsequent default or other matter 14 arising in connection with this Agreement. Except as expressly provided herein, any delay by any Party, short of any applicable
? I (\ /") 15 if statutory period of limitations, in asserting or enforcing any 17 right hereunder, shall not constitute or be deemed a waiver of 18 that right. 19 8.30 Filine Acreement with FERC 20 PGEE shall submit this Agreement to FERC for 21 acceptance; provided DPS shall have a prior opportunity to review and comment upon such application. The Parties shall fully 22 23 support FERC acceptance of this Agreement and shall take all 24 reasonable actions necessary to secure an expeditious acceptance. 25 8.31 Intecration 4 26 The Parties agree that the provisions of this . constitute the entire agreement between the Parties and 27 Agreement fs d - 28 the Parties' rights and obligations with respect thereto. No 89
1 representation, covenant or other matter, oral or written, not ,' t J (] V 2 expressly set forth, incorporated, or referenced in thi6 ' 3 Agreement shall be a part of, modify, or affect this Agreement: 4 provided, however, that this Agreement may be modified by 5 subsequent writings signed by both Parties. 6 8.32 Sicnatures 7 In witness whereof, the Parties have caused this ) . 8 Agreement to be executed by their duly authorized represet.tatives 1 9 and effective as of this date. ~ 10 11 DESrEC POWER SERVICES, INC., PACmC GAS AND ELECTRIC COMPANY, a Delaware corporation a California corporation 12 13 av: Y ih sw M~ ' 14 n NAME: Walter G. Homan v v NAME: Robert J. Haywood 1 7 15 Trra Vice President and General Trra: Vice President - Power ! Manager - Western System l 16 Operations 17 part or nourums: November 29, 1994 Dan or mouAmt: November 29, 1994 18 19 20 21 22 I 23 24 ; 25 26 27 28 90 1
d i 1 4 1 1 1 1
\
l 1 1 f i i l i 2 l 1 Appendix A i d i DISPUTE RESOLUTION AND ARBITRATION 1 J I I t h d
l l 1 j 1 . Appendix A 4l
- 2 DISPUTE RESOLUTION AND ARBITRATION 3
4 A.1 . GENERAL 5 The Parties shall make best efforts to resolve all disputes 6 arising under this Agreement expeditiously and by good faith 7 negotiation. The Parties may resolve their dispute through. , 8 Negotiation, Mediation, and/or Arbitration pursuant to the 9 procedures set forth in this Appendix A, may resolve an 10 " Appendix C Dispute" in accordance with Appendix C, may resolve a 11 non-Appendix C issue in accordance with Section 6.4.2.1 cr may, 12 upon mutual agreement, agree upon additional dispute resolution 13 mechanisns and/or agree upon additional or different procedures 14 for the dispute resolution mechanisms set forth in this 15 Appendix A. 16 17 A.2 SCOPE 18 Except as specified in Section 6.4.2.1 with respect to a l 19 non-Appendix C issue, this Appendix A shall apply to any dispute, 20 disagreement or claim between the Parties arising out of or i 21 relating to this Agreement, or to its breach, termination or 22 validity (" Dispute"); provided, however, the Parties have 23 authorized the Technical Mediator to assess and resolve certain < 24 disputes designated as Appendix C Disputes and such Appendix C 25 Disputes may additionally be resolved in accordance with the 26 procedures in Appendix C. 27 r 28 A-1 1
i 1 A.3 NEGOTIATION e' 2 In the event of a Dispute, either Party may serve on the 3 other Party a written request for negotiation specifying the 4 issues in dispute. Within five (5) calendar days after service 5 of the negotiation request, the matter shall be referred for 6 resolution to management representatives of the Parties who are 7 authorized to settle the Dispute. The management representatives 8 shall promptly meet in a good faith effort to resolve the 9 Dispute. No document discovery of any kind or depositions shall 10 be required during negotiation. Document exc.hange shall,be 11 voluntary. The negotiation and all documents exchanged in j f 12 connection with the negotiation shall be confidential and subject , l 13 to California Evidence Code Section 1152.5. No statement made 14 during the negotiation phase shall be admissible as evidence in l 15 any subsequent arbitration or judicial proceeding. 16 17 A.4 MEDIATION 18 A.4.1 Recuest for Mediation - 19 If the management representatives do not reach a 20 decision within thirty (30) calendar days after service of the 21 negotiation request under Section A.3 " Negotiation", either Party 22 may at any time thereafter (i) request mediation by so notifying 23 the other Party in writing or (ii) request arbitration pursuant 24 to Section A.5. 25 A.4.2 Selection of Mediator 26 If the Parties are unable to agree upon a mediator 27 within fifteen (15) calendar days after service of the written request for mediation, they shall jointly request the American ^' 28 A-2
h l l 1 l 1 Arbitration Association ("AAA") to provide a list of potentia; *!
)
(V 2 mediators with experience in mediating complex disputes invciving 3 the issues of the specific Dispute between the Parties. Within i 4 fifteen (15) calendar days after receipt of the list, each Party 5 shall eliminate from the list the names of any unacceptable 6 mediators and rank the remaining names in order of preference. 7 The AAA administrator shall be instructed either to nominate the , 8 Parties' preferred mediator, or if no names remain on the AAA 9 list after both sides have stricken certain names, to'. provide 10 another list of potential mediators. The Parties shall. designate 11 a mediator from the second list, using the procedures set forth 12 in this Section A.4.2. I I 13 A.4.3 Mediation Procedure 14 Within ten (10) calendar days after the mediator is () 15 appointed, the Parties shall provide the mediator with their 16 respective recommendation for the mediation procedure. Within 17 twe,nty (20) calendar days atter receipt of the Parties' 18 recommendations, the mediator shall issue a written procedure, 19 including: (a) a schedule for exchange of narrative statements 20 summaricing each Party's position on the Dispute; (b) the format j 21 of the mediation; and (c) the time period for completion of the 22 mediation, not to exceed one hundred and twenty (120) days from 23 service of the mediaticn request. No document discovery or ; 24 depositions shall be required as part of the mediation. All , i 25 document exchange shall be voluntary. The mediation shall be 26 held in San Francisco unless otherwise agreed to by the Parties. 27 The result of the mediation shall be nonbinding, except as 28 mutually agreed. The mediation and all documents produced in A-3
1 1 connection with the mediation shall be confidential andLsubject * () l 2 to. California Evidence Code Section 1152.5. No-statement'made by ,' 3 a Party in'the mediation shall be admissible as evidence against 4 that Party in any subsequent arbitration or judicial proceeding. 5 6 A.5 . ARBITRATION . .7 A.5.1 Demand l 8 If (i) the Parties agree to terminate the mediation, 9 (ii) the Parties are unable to resolve the Dispute within one 10 hundred and twenty (120) days after service of the mediation 11 request, or (iii) either Party decides unilaterally to commence 12 arbitration in lieu of mediation, eitNer Party may serve on the 13 other Party a request for arbitration. Any Dispute shall be 14 subject to arbitration under the Commercial Arbitration Rules of 15 the AAA, as'those rules exist at the time of execution of the 16 Agreement, as amended and supplemented by the terms of this 17 Section A.5 except as otherwise agreed to by the Parties prior to 18 the selection of the Panel. The request shall set forth the i 19 nature of the Dispute, the amount involved, and the remedy 20 sought. Any demand on a counter-claim by the other Party shall 21 be served within fifteen (15) calendar days after service of the I 22 request for arbitration, and shall contain the same information l l 23 required for a claim by this Section A.5.1. 24 Within twenty (20) calendar days after the later of: 25 (i) the date of the tnmplaining Party's request initiating 26 arbitration; or (ii) the date of the responding Party's counter- l f l 27 claim, the Parties shall exchange written statements of the l 28 issues (s) in dispute, including a specific proposal to settle the A-4
I ! 1 Dispute (s), and each shall also deliver a copy of its statement 8; 2 to the Panel, as defined in Section A.5.2. 3 A.5.2 Selection of Arbitration Panel > 4 The panel of arbitrators (the " Panel") shall be l 5 selected as follows. Within twenty (20) days after service of 6 the demand for arbitration, or after service of any counter-7 claim, whichever is later, each Party shall serve on the other l l 8 Party a notice setting forth that Party's selected arbitrator 9 (" Party arbitrator"). The qualifications of each Party 10 arbitrator shall be entirely at the selecting Party's discretion, ) 11 crovided, that each Party's arbitrator shall-not be a current 12 employee or board member of that Party. Within twenty (20) days l 13 after service of the notices of selection of Party arbitrators, 14 the two (2) Party arbitrators shall choose a third (3 rd) I 15 arbitrator (the " neutral arbitrator"). If the two (2) Party i v) 16 arbitrators cannot agree on a neutral arbitrator, they shall I l 17 select the neutral arbitrator from a list of arbitrators 18 experienced in disputes of the kind at issue, to be submitted to 19 the Parties by the AAA. If the two (2) Party arbitrators are
- 20 still unable to agree on a neutral arbitrator, the Parties shall j 21 jointly request that another list of potential arbitrators be 22 supplied by the AAA and shall select a neutral arbitrator from i 23 this list. If the Parties are still not able to agree on a )
24 neutral arbitrator, an arbitrator shall be selected pursuant to i 25 Rule 13 of the AAA rules. Any Party may request the AAA to j 26 disqualify the neutral arbitrator for bias, personal or financial i interest, or relationship with any Party, pursuant to the rules 27 O 28 of the AAA. A-5 l J l
- - _ - - - ~- _ -. -. . _ . . - . - --.. .
l l 1 A.5.3 Discovery a 2 A.5.3.1 Each Party shall have the right to ; 3 limited discovery from the other Party, and: 4 (i) either Party shall be entitled to demand the j 5 production, no later than thirty (30) days before the hearing, of 1 [ 6 any documents the other Party intends to rely upon at the hearing l 7 for its case-in-chief, and any documents which directly relate to 8 the specific facts and issues in dispute in the arbitration. 9 Unless otherwise agreed, a Party shall have thirty (30) days to 10 respond to document production requests. In no event shall 11 either Party be required to produce documents merely on the 12 grounds that those documents relate to the subject matter of the ; 13 dispute, relate indirectly to the specific facts and issues in 14 dispute, or which could lead to the discovery of directly 15 relevant documents; 16 (ii) either Party may demand production, no later 17 than thirty (30) days before the hearing, of the list of 18 witnesses the other Party intends to call at the. hearing for its 19 case-in-chief, together with a brief subject matter description 20 of the testimony of each witness; and 21 (iii) either Party shall be entitled to take a 22 total of forty (40) hours of depositions for all deponents 23 combined of the other Party's employees (current or prior) or 24 other witnesses, which time limit may be extended only for good 25 cause. 26 A.5.3.2 Any dispute over discovery shall be 3 27 submitted to the Panel for decision. 28 A-6
l 1 A.5.4 Pre-Hearina Conference e l (} 2 3 Within ten (10) days after its selection, the Pane; shall convene a-pre-hearing conference to determine procedures , l 4 for the hearing, including-evidence to be submitted, evidentiary I l 5 objections, discovery and length of the hearing and to develop a , I + 6 statement of issues. To the extent necessary to define and limit i 7 the facts and issues in dispute at the hearing, the Panel nay use 8 this pre-hearing conference as a mini-hearing at which each Party 9 may present its statement of issues and the reasons why its l 10 statement should be used as the basis for hearing. The Panel may 11 request the Parties to agree on a joint statement of issues as an ; 12 alternative to either Party's separate i statement. If there is no 13 joint statement, the Panel shall, by majority vote, choose one 4 14 Party's statement for use in the hearing based on its judgement () 15 as to which Party's statement presents the issues to be decided 16 in the most reasonable and intelligible manner consistent with 17 the provisions of this Agreement. 18 A.5.5 Hearina Location and Time 19 The hearing shall begin not later than one hundrad 20 and twenty (120) days after service of the demand or cross-demand 21 for arbitration, whichever is later. Each Party shall, ten (10) 22 days prior to the hearing, complete discovery subject to l 23 Section A.5.3 and deliver to the other Party and to the Panel a 24 revised proposal (or the same proposal) to resolve the Dispute. ! 25 If either Party does not deliver.a proposal prior to such 26 deadline, that Party shall have waived its right to participate 27 in the arbitration and shall be bound by the terms of the other ; 28 Party's proposal. The hearing shall be held in San Francisco A-7
l i i unless otherwise agreed. The hearing shall proceed under the
- 2 rules and procedures of the AAA or as mutually agreed by the 3 Parties. I 4 A.5.6 Panel's Decision l
5 Within thirty (30) calendar days after the hearing ! l 6 concludes.(or longer, if extended by agreement of the Parties), i l 7 the Panel shall, by majority vote, accept the proposal of on.e of 8 the Parties,.without modification, based, to the extent possible, l i 9 on the criteria specified in this Section A.5.6. The Panel shall l 10 adopt the Party's proposal which more reasonably applies,the 11 standard and express intent of this Agreement. applicable to the , 1 1 12 Dispute, or , absent such applicable standards and intent, which 13 Party's proposal more reasonably represents Prudent Utility ) 14 Practice. To determine which Party's proposal is the more () 15 reasonable, the Panel shall specifically conside'r all factors 16 relevant to the reasonableness of each Party's proposal, 17 including, but not limited to, (a) the facts known and the facts l 18 that should have been known to each Party at the time of the 19 action or inaction giving rise to the Dispute, (b) the time 20 available in which to act, and (c) other factors relevant under 21 the circumstances. In arriving at a decision, the Panel 22 necessarily must interpret and construe this Agreement; however, 23 nothing contained in this Section A.S.6 shall be deemed to permit 24 the Panel to waive or change any of the express provisions of 25 this Agreement. The Panel's decision shall be in writing, 26 stating the grounds for arriving at the decision. The decision , l l 27 of the Panel shall be binding upon both Parties, except as j 28 expressly set forth in Sections 1286.2 and 1286.6 of the A-B
. _. - - - . . . __ . . - . . . _ ~ . _ . _-- -. - .. .. ..
l l 1 California Code of Civil Procedure. 4! l 2 A.5.7 Remedies
)
3 The Panel may direct specific performance and may l l 4 award other equitable relief, but it is not empowered to award 5 punitive damages, treble damages or other damages in excess of 6 actual damages. Except as provided in Section 6.4.2, the Parties 7 agree that they hereby waive the right to recover damages in 8 excess.of actual damages and agree that they wi.ll not seek 9 damages in excess of actual damages in any other forum. The l 10 prevailing Party shall be entitled to interest at the rate and '
- 11 calculated in accordance with the methodology for refunds 12 pursuant to Section 35.19 of FERC's re'gulations (18 C.F.R.
13 535.19), as such regulations may be changed or superseded, plus 14 three (3) percentage points. The interest shall accrue from the k 15 date on which the negotiation request pursuant to Section A.3 is 16 served through the date the award is paid. 17 A.5.8 Award of Costs l 18 The losing Party on each claim in dispute shall 19 reimburse the prevailing Party for all reasonable attorneys' 20 fees, including the costs of in-house counsel, attributable to 21 that claim incurred by that Party in the arbitration as 22 determined by the Panel. 23 A.5.9 Settlement 24 If at any time prior to final award the Parties 25 present the Panel with a written settlement of some or all the 26 claims before the Panel, duly executed by authorized 27 representatives of each Party, the Panel shall adopt the 28 settlement, without change, as its award with respect to the A-9
i 1 settled claim. 4 I
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/i 'T/ 2 A.5.10 Confidentiality
'J 3 Notwithstanding anything to the contrary contained 4 in this Appendix A, the Parties shall execute an agreement with 5 the mediator or the arbitrators on the Panel, which shall (a) 6 require the mediator or the arbitrators to treat any information 7 conveyed to them as confidential and prohibit disclosure of.any 8 confidential er trade secret information; (b) make California 9 Evidence Code Section 1152.5 applicable to the mediation or 10 arbitration; and (c) for the arbitration, prohibit any ex parte 11 contacts with the neutral arbitrator, including by a Party 12 arbitrator, without the explicit consent of the other Party, i 1
13 unless the neutral arbitrator initiates the contact (s) and they l 14 are made part of the record. Any information provided pursuant l ps (,) 15 to negotiation, mediation or arbitration under this Appendix A 16 shall be neither admissible nor discoverable in any regulatory or: 17 judicial proceeding or in any other action or forum, as provided 18 in Section 1152.5 of the Evidence Code. - 19 A.5.11 Party Reoresentative 20 Each Party shall have in attendance throughout the 21 mediation and arbitration proceedings a designated representative 22 who has sufficient authority to negotiate and recommend 23 compromise within the full monetary range of the Dispute. j i 24 A.5.12 Costs Prior to Award 25 Prior to the Panel's award and the award of costs, 26 the Parties shall bear their respective costs incurred in gS 27 connection with the procedures described in this Appendix A, j t i
' ~' 28 including the costs of their respective Party arbitrator, except j i
A-10
t .-.~.._.._...__._-..__.-.__._._.___.___._._.__ L that the Parties shall share equally the fees and expenses of the*
~
l 1 i i /) 2 mediator and the neutral arbitrator and the costs of any lD 3 facilities owned by Third Parties that.are used for meetings, 4 negotiations or hearings under this Section A.5. 5 A.5.13- Enforcement 6 The decision of the Panel may be enforced by any 7 court or agency having jurisdiction over the Party against which 8 the decision is rendered. In addition, if PG&E, fails to comply with an Panel's decision and the relevant compliance schedule !
.9 10 requiring a payment to DPS by PG&E, DPS may withhold (offset) an 11 equivalent amount from the payment of bills under any agreement 1 12 between DPS and PGEE (i.e., not bills'already past the Payment j 13 Due Date), but only by giving PGEE notice of its intent to 14 withhold such sums on or before the Payment Due Date for the
() 15 af fected bill (s) . DPS' failure.to give such notice in accordance i 16 with this Section A.5.13 shall disable DPS from using this offset'. 17 remedy for that bill. If DPS fails to comply with the' Panel's' l 18 decision and the relevant compliance schedule requiring a payment 19 to PG&E by DPS, PG&E may withhold (offset) an equivalent amount 20 from the payment of bills under any agreement between the Parties 21 (i.e., not bills already past the Payment Due Date), but only by 22 giving DPS notice of its intent to withhold such sums on or 23 before the Payment Due Date for the affected bill (s). PG&E's 24 failure to give notice in accordance with this Section A.5.13 25 shall disable PGEE from using this offset remedy for that bill. 26 All agreements between the Parties shall be subject to this self-27 help offset remedy unless expressly excepted herefrom. O 28 A-11
- - _ . - - . . ~ . . . . . - . . - . - - . - - - - _ - . _ . - . . . _ _ . - . . . . . - - - .
i l 1 A.5.14 Effect of Noncomoliance 4 I 2 In addition to any other remedies available to 3 either Party under this Agreement, for any Dispute arising under 4 this Agreement if either Party fails or refuses to utilize the 5 procedures of this Appendix A as the exclusive remedy for all l 6 disputes arising under this Agreement (except as provided in 7 Section 6.2.4.1 and for Appendix C Disputes subject to the , 8 procedures in Appendix C), or if either Party fails or refuses to 9 comply with the Panel's final decision, such Party sh'all be in 10 default and the other Party shall have the right to terminate
~
11 this Agreement in accordance with Section 8.2. 12 A.S.15 'Acreement to Occose Third-Party Challence ; 13 The Parties agree jointly to oppose any challenge by 1 14 a Third Party to the provisions of this Appendix A, the f(,j)f 15 application of these provisions.End the provisions of 16 Section 6.4.2 and Appendix C to any specific dispute arising 17 under this Agreement, or a decision by the Panel issued 18 hereunder. Such opposition shall, upon request by the other 19 Party, include a written statement of opposition to be filed as ! 20 part of the record in any administrative or judicial proceeding
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21 and the appearance of witnesses as may be necessary and 22 reasonable. 23 24 25 26 . 27 5 28 A-12
4 4 4 r 1 1 i r i j e i i 4 1 h i 9 4 i a f I 9 s 1 1 Appendix B 3 4 I .i SCHEDULING t l I I i e I t , i 1 l i 4, 1 s l 1
- .- .. . _ _ ~ _ -- . - _. -- ..
Appendix B
- 1 2 SCHEDULING
( 3 ! 4 B.1 GENERAL l <. 5 DPS shall separately schedule at the Control Area 6 Interchange Points, Output Points and Input Points for DPS l
)
-7 Control Area Resources. All schedules are to the nearest te,nths j 8 of a MW unless otherwise specified. At the Control Area 9 Interchange Points, DPS shall schedule Imports and exports from 10 PG&E's Control Area rounded to the nearest whole megawatt. At 11 the Input Points for DPS Control Area Resources, DPS shal'l 12 schedule deliveries to PG&E and to the DPS Pool in accordance 13 with Sections B.3.1, B.3.2, B.3.3 and B.3.4. For CBRs and Non-EA i
14 Resources delivering power over WSCC Path 15, DPS shall provide l ( 15 hourly maximum power deliveries.in accordance with Sections B.3.3 16 and B.3.4. Schedules shall be required whenever DPS sells power . 17 to a Third Party. DPS' hourly schedules at the Control Area 18 Interchange Points shall be transmitted by voice communication to 19 the PG&E Energy Control Center and transmitted via datalink to 20 PG&E. DPS' hourly schedules at other Transaction Points shall be 21 transmitted by a datalink to PG&E. DPS is responsible for 22 installing and maintaining such datalink (including payment for 23 associated costs). Such data shall be in a i unutt compatible 24 with PG&E's scheduling computer system. In the event of a 25 failure of the datalink, DPS shall send data to PG&E by telecopy 26 or use any other mutually agreed upon method of data transfer. l l 27
- O i 28 B-1
1 B . 2. DAILY PRESCHEDULE 4 ! 2 B.2.1 DPS Pool Schedule 3 For the daily preschedule, DPS schedules all
'4 information required in Section B.3. In addition, DPS shall 5 provide a notice of the capacity level at which each EA Resource 6 is e'xpected to operate for each hour of the following day.
7 B.2.2 Schedules on the Intertie 8 For schedules on the Intertie through Midway 9 Substation, DPS shall use best efforts to notify PG&E by voice 10 communication by 10:00 am and shall notify PGEE by voice, 9 11 communication no later than noon on each Work Day of.its 12 schedules'for each following day. Fori schedules on the Pacific 13 AC Intertie or California-Oregon Transmission Project through the 14 California-Oregon Border (" COB"), DPS shall notify PG&E by voice () 15 communication no later than noon of its schedule's for each 16 following day, up to and including the following Work Day. For 17 example, the schedule for Tuesday is provided on Monday; the 18 schedule for Monday is provided on Friday. The Parties may agree 19 that scheduling notification may be different than described 20 above. These preschedules shall include, but not be limited to: 21 DPS Loads (including the identity of the receiving Party for 22 exports), type of transaction, hourly amounts, and daily totals. 23 In addition, if applicable, DPS shall notify PG&E of the Output 24 Point if different than the DPS Load and the type of transmission 25 arrangements made with intervening Control Areas to conduct the 26 transactions. 27 B.2.3 All Schedules f-s V 28 By 2:00 pm of each Work Day, DPS shall transmit via B-2
1 i datalink to PG&E its hourly preschedules, containing the 8 4 1 information listed in Section B.3, in a format agreed upon by (~) 2 3 both Parties. I 4 B.2.4 Chances to the Daily Preschedule 5 DPS may update the preschedules before midnight as 6 more current information becomes available so that the 7 preschedules can reflect the most current conditions. At , 8 8 midnight, the preschedule becomes the schedule of the day subject 9 to changes by the submission of final schedules no later than 20 i 10 minutes before each hour. In the event that,DPS anticipates that 4 11 the sum of the final schedules to Third Parties will change more l ! 12 than 75 MW from the amount that it prescheduled, DPS shall first
~
13 notify PG&E to determine if Electric System conditions will allow such a change without a charge. PG&E will have the right to 14
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15' charge DPS for verifiable costs as actually incurred by PG&E if a , l 16 schedule change greater than 75 MW will result in cost to PG&E; 17 provided that any change in the preschedule occasioned by a l 18 curtailment ordered by PG&E pursuant to Section 6.3.2, shall not 19 be included in the calculation of the 75 MW. Charges under this 20 Section B.2.4 (if any) shall be based on PG&E's actual Costs due 21 to uneconomic dispatch attributable to DPS' schedule change. 22 l 23 B.3 SCHEDULE OF THE DAY 24 DPS shall separately specify schedules for individual DPS 25 Suppliers. For each hour, the total power scheduled to the DPS 26 Pool for Scheduled Transactions (e.g., ABRs, scheduled utility l l 27 resources, and Imports), plus power estimated to be delivered to l f-Ng (/ 28 the DPS Pool for Variable Transactions (e.g., CBRs), less B-3
. -. .. - _ _ - - - . - - - _- . _ - -.. - .. _ - . _- ~ __ - . -
1 replacement power, shall equal the total power scheduled to <! ( ) 2 Scheduled Transactions plus power forecasted to variable
- 3 Transactions plus losses from the DPS Pool. -
) 4 DPS will specify for each hour the resource group that is 5 following the Matching Load group in accordance with 6 Sections 4.1.2 and 4.1.3. DPS shall make any changes to the l l'T 7 schedule of the day no later than 20 minutes before the 8 scheduling hour for the next hour except as provided for in 9 Section B.S. For scheduling changes totaling 75 MW or more, DPS ) 10 shall make such changes by notifying the PG&E Energy Control 5 11 Center by voice communication. DPS shall also notify the PG&E 1 12 Energy Control Center by voice communication no later than 20 4 13 minutes before the hour to confirm or change schedules for any I 14 Control Area Interchange Points or transactions involving the
! 15 California Department of Water Resources ("DWR"5 for the next f_
16 hour, unless otherwise agreed. After this twenty-minute (20-s 17 minute) lockout period, except as provided in Section B.5, no 18 additional changes to the schedule shall be accepted and the I 19 schedule of the day for that hour shall become the final schedule
- 20 for the hour.
21 If the scheduling datalink between PG&E and DPS fails, DPS 22 shall change the schedule by voice communication or telecopier. I 23 In addition to the schedule changes, the telecopied information J 24 shall have the date and time indicated and shall be received by 25 PG&E before the same twenty-minute (20-minute) lockout period. 26 PG&E shall not accept changes via datalink after the
% 27 twenty-minute (20-minute) lockout period unless otherwise agreed.
28 After the twenty-minute (20-minute) lockout period PG&E shall no s B-4
.I
1 longer be obligated to purchase power scheduled by DPS for 4 2 delivery to the DPS Pool for the following hour. ) 3 B.3.1 Allocation Basis Resources ("ABRs") 4 For each ABR, DPS shall submit a binding hourly 5 schedule, subject to the provisions of Section B.5, for the DPS 6 Pool Energy to be delivered to the DPS Pool. For each ABR with 7 PPA Firm Capacity, DPS shall acknowledge the PPA Firm Capacity 8 level by listing it on all applicable schedules as a constant for 9 all hours. In no case shall DPS submit, and in no case shall it 10 be deemed that PG&E accepted, a schedule that would result in 11 PG&E receiving less than the PPA Firm Capacity level from an ABR.
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12 B.3.2 Contro11ine Basis Resources ("CBRs") 13 For each CBR, DPS shall submit a binding hourly 14 schedule subject to the provisions of Section B.5, for the amount 15 of DPS Pool Energy, if any, to be delivered to the DPS Pool on a 16 scheduled basis. For each CBR, DPS shall submit an hourly 17 estimate for the amount of DPS Pool Energy to be delivered to the 18 DPS Pool on an as-delivered basis. For each CBR, DPS shall 19 submit a binding hourly schedule subject to the provisions of 20 Section B.5 which fixes the amount of PG&E Energy to be delivered 21 to PG&E. For each CBR with PPA Firm Capacity, DPS shall 22 acknowledge the PPA Firm Capacity level by listing it on all 23 applicable schedules as a constant for all hours. In no case 24 shall DPS submit, and in no case shall it be deemed that PG&E 25 accepted, a schedule that would result in PG&E receiving less 26 than the PPA Firm Capacity from a CBR. 27 B.3.3 Non-EA Resources 28 B.3.3.1 For each Non-EA Resource being used by B-5
i 1 DPS for Variable Transactions, DPS shall submit an hourly * () 2 3 estimate of the expected delivery to the DPS Pool. B.3.3.2 For each Non-EA Resource being used by 4 DPS for Scheduled Transactions, DPS shall submit an hourly 5 binding schedule subject to the provisions of Section B.5 for the 6 DPS Pool Energy to be delivered to the DPS Pool. 7 B.3.4 Imnorts ., 8 For each Import, DPS shall submit an hourly binding 9 schedule' subject to the provisions of Section B.5 fori.the DPS 10 Pool Energy to be delivered to the DPS Pool.
- 11 12 B.4 DEVIATION ENERGY 13 After each scheduling hour, when the actual integrated half
'14 hourly DPS transactions are available, DPS shall deterrine the
. %_O) 15 amount of the hourly deviation calculated pursuant to 16 Section 4.6. After determining and verifying the amount of the-17 deviation with PG&E, DPS shall accumulate any on-peak, partial peak, off-peak and super off-peak deviations within the hourly j 18 1 I 19 Energy Exchange Band and correct such deviations in the next 20 like-time period or at a time agreed by the Parties and in 21 accordance with Section 4.6. Such correction shall be scheduled 22 pursuant to Sections B.2 and B.3. 23 24 B.5 CHANGES TO FINAL SCHEDULES FOR EACH HOUR AFTER THE TWENTY 25 MINUTE LOCKOUT POIh"T 26 B.5.1 Conditions for Schedule Chances 27 DPS may change the final schedule in the current 28 scheduling hour in the event of one of the following: B-6
. . - - . . - ~_ . - - . _ - - .- .. . _ . - - . .- -
4 1 (1) An Emergency; 4' t
)
2 (2) A Curtailment of WSCC Path 15 transmissior. 3 service that occurs in accordance with Section 6.3.2 without at 4 least twenty (20) minutes notice in which case DPS may change
- 5 schedules for the purposes of replacing (but not exceeding) the ;
6 curtailed power and DPS' controlling capability of, consisten
- 7 with Section 6.3, DPS Suppliers affected by the curtailmentq ;
8 including changing the designation of an ABR to a CBR-(provided i 9 such change would not result in incremental sales of As-Available i 10 Power to PG&E from EA Resources); or , 4 - PG&E calls upon energy from DPS Spinning 11 (3) i 12 Reserve as provided for in Section 4.3.6 in which case DPS can 2 i 13 add a schedule for such energy. 14 In any of the above events, PG&E shall accept . O( ,/ 15 schedule changes after the 20-minute lockout pesiod; after the 16 scheduling hour has passed, the schedule, so changed, becomes the: I 17 final schedule of the hour and DPS may no longer change the final i. 18 schedule. 19 B.5.2 Notification l l 4 20 If during the current scheduling hour, DPS suffers an Emergency or other event described in Section B.5.1, DPS shall l 21 l 22 notify the PG&E Energy Control Center of the interruption. DPS 23 shall notify PG&E of the necessary adjustments to the schedules
; 24 for the scheduling hour by voice communication with the PG&E 25 Energy Control Center within the first 10 minutes after the event 26 occurs. If the event extends beyond the current scheduling hour, 27 DPS shall adjust subsequent hourly schedules to reflect the then-28 current DPS facility conditions.
l B-7
I i 1 B.6 BIWEEKLY AND MONTHLY REPORTS e! , 2 Unless otherwise agreed by the Parties, DPS shall provide
)
PG&E with daily reports transmitted in a mutually agreed-upon 3 4 manner at-least twice a week throughout the month, and with 5 monthly reports, within five Work Days after the end of each ( 6 calendar month, in a format to be agreed to by both Parties 7 consisting of: 8 (a) Actual daily and hourly final schedu. led transactions l 9 with daily totals and on-peak, partial peak, off-peak';. and super i l 10 off-peak subtotals; l 11 (b) Actual daily and hourly generation of DPS' Control 12 Area Resources with on-peak, partial peak, off-peak, and super 13 off-peak subtotals; 14 (c) Recorded on-peak, partial peak, off-peak, and super ( 15 off-peak Energy Deviation, and deviation energy 1 exchanges made in 16 accordance with Section'B.4; 17 (d) Summary of residual Energy Deviation by on-peak, 18 partial peak, off-peak, and super off-peak periods that DPS was 19 unable to offset; and 20 (e) Monthly summary of the final schedules for items (a) 21 through (d). 22 23 E.7 RECONCILIATION OF ACTUAL AND SCHEDULED DATA ; 24 Except as otherwise provided in this Agreement, the 25 integrated half hourly metered data for each Half-Hour Period for 26 the Transaction Points specified in Appendix K shall serve as the 27 normal basis for deviation accounting. O 28 B-B
. . . - _ _ . . _ , _ . _ . _ _ . . _ _ . _ _ - . _ . _ . . _ _ . - . _ _ _ . - ~ . _ _ _ _ _ . . . . .
1 B.8 INFORMATION TO BE SCHEDULED BY DPS ~a ? i 2 B.B.1' General Inf erration Recuirements
}
3 The hourly preschedules and the hourly final. , 4 schedules shall include the following information: j l 5 For transactions via.the datalink,' schedules shall 6 include, but not be limited to, the following: the designation of 1 7 an EA Resource as an ABR or CBR in accordance with Section 3.2;
-l 8 estimated: hourly deliveries pursuant to Sections B.3.2 and ;
f 9 B.3.3.1; buyer, seller, transaction code, hourly amounts, and ; 10 daily summation of hourly amounts. Schedules shall be submitted. l 11 in numerical format using existing WSCC-recommended codes for- ! 12 buyers and sellers. - DPS, .if necessary, shall apply to the WSCC i Existing utility : 13 for valid utility identifier-(ID) numbers. 14 identifiers are shown in Attachment 1 to Appendix I. PGEE's ! (k 15 transaction codes are specified.in Attachment 2;to Appendix I. 16 In addition, if new transaction codes should be required, PG&E ! 17 shall provide such codes to DPS. All schedules for DPS Suppliers l t 18 shall be in hourly increments within each hour. . , 19 B.8.2 Recuired Schedules , 20 DPS shall be required to provide preschedules and 21 schedules for the following: , 22 B.S.2.1 Allocation Basis Resources ("ABRs"):
^
23 (1) An acknowledgement of the PPA Firm 24 Capacity level (if any), pursuant to Section B.3.1, which is t 25 constant in all hours. 26 (2) Separate DPS Pool Energy scheduled } ! 27 for each hour from each ABR to the DPS Pool. . [ f- 28 : l B-9
i 1 B.B.2.2 Contro11ino Basis Resources I*CERs"' d /~'i 2 (1) An acknowledgement of the PPA Firr V 3 Capacity level (if applicable) pursuant to Section B.3.2, which 4 is constant in all hours. j 5 (2) PG&E Energy scheduled each hour from 6 each CBR for sale to PG&E. i 7 (3) DPS Pool Energy scheduled each, hour . I 8 from each CBR to the DPS Pool. 9 (4) Separate non-binding DPS P'ool Energy 10 scheduled each hour from each CBR to the DPS, Pool beyond that 11 which is scheduled as DPS Pool Energy in 3) above, including 12 whether this will serve the Matching Loads pursuant to 13 Sections 3.2.3, 4.1.2 and 4.1.3. 14 B.B.2.3 Non-EA Resource: For Variable /~N (,) 15 Transactions, separate non-binding schedules from each Non-EA 16 Resource to the DPS Pool including whether this will serve the 17 Matching Loads pursuant to Section 4.1.3. For Scheduled 18 Transactions, a separate binding schedule from each Non-EA 19 Resource to the DPS Pool. 20 B.B.2.4 Soinnino Reserves: A schedule for 21 Spinning Reserve from Input Points listed in Appendix K plus 22 separate schedules for each hour for each other provider of 23 fSpinningReservenot listed in Appendix K. 24 [B. B . 2. 5] DELErED 25 B.8.2.6 DPS Pool Schedules to Buyers: Separate 26 schedules of each hour power sales to each customer indicating 7-~g 27 whether the sales are firm; provided, that (1) for Scheduled L I 28 Transactions, DPS shall submit schedules of energy sales, and (2) i B-10 l
i l l i l 1 for Variable Transactions, DPS shall submit a forecast of enerev 8,
/D 2 sales.
l LJ l l 3 B.8.2.7 Deviation Enerav Exchance Pursuant to 4 Section B.4: For deviations pursuant to Section B.4, a separate 5 schedule for each hour where DPS is the receiver of deviation 6 exchange energy and a separate schedule for each hour where PG&E 7 is the receiver of deviation exchange energy. If no deviation l 8 energy is to be exchanged in any given hour, nousuch schedule is ! l 9 required for that hour. I i 10 B.8.2.8 Other Information: 0.ther information, as i 11 agreed to by the Parties from time to time. 12 13 B.9 CHANGES IN SCHEPULING PROCEDURES 14 B.9.1 PG&E may modify these procedures at any time and i 1 l' \ (v/ 15 shall notify DPS of the changed procedure at lea'st thirty (30) 16 days in advance of their scheduled implementation; provided, 17 however, that any such modification (s) shall be reasonable, 18 nondiscriminatory, consistent with Prudent Utility Practice, and 19 the same as those required by PG&E at that time for others in the 20 PG&E Control Area. DPS shall, at its own expense, comply with 21 such changed procedure. Unless otherwise ordered by FERC, these 22 changed procedures shall become effective under this Agreement 23 upon such notification and without pre-filing with FERC. 24 3.9.2 If DPS sells to a municipal utility in PG&E's 25 Control Area which is a party to an Interconnection Agreement l 26 with PG&E in existence as of the Effective Date, and such l l s 27 Interconnection Agreement authorizes the municipal utility to (, \, i
28 schedule transactions on a basis different than those set forth B-11
i . 1 1 in this Appendix B (e.g. half hourly basis), DPS shall be 8: r l 2 entitled to sell to such municipal utility under this Agreemen; 3 using modified scheduling protocols which are consistent with 4 those in the municipal utility Interconnection Agreements. In l l 5 such event, the Parties shall agree upon necessary changes in 6 scheduling protocols for this Agreement for the limited purpose 7 of accommodating DPS' sales to such municipal utilitiies, , 8 9 10 , 11 12 13 14 (Qj ' 15 16 - 17 i i 18 - 19 20 21 22 23 24 25 26 27
-s 28 B-12
- . . .- . . . . . =. . - . _... . _ _ _ _ .- . . -
4 5 l 4 4 1 J ; i i Appendix C EXPEDITED PROCEDURES FOR TECHNICAL DISPUTES 1 l l l
1 Appendix C 4 /'N 2 EXPEDITED PROCEDURES FOR TECHNICAL DISPUTES 3 ! 4 C.1 INTRODUCTION 5 In the event of a Sixty Day (60-Day) Study Dispute, of an 6 Interconnection Agreement Dispute, of a Transmission Service 7 Dispute, or a Section 8.20 Dispute as each is defined below.and 8 for purpose of this Appendix C (collectively the " Appendix C 9 Disputes"), and DPS has a good faith belief that PG&E:should be 10 able to accept the added or modified Transaction Point or provide 11 c Network Transmission Service sufficient to a'commodate t'he 12 intended transaction or, with respect'to a Section S.20 Dispute, 13 that PG&E should adopt the interim procedure, rule or regulation 14 or Spinning Reserve Requirement as proposed by DPS, DPS may j'~'h ( ,) 15 initiate the expedited technical mediation procedures set forth l 16 herein. DPS may elect to seek to resolve an Appendix C Dispute i 17 in accordance with this Appendix C or pursuant to the procedures l
)
18 set forth in Appendix A. The decision by the Technical Mediator 19 pursuant to Sections C.1.4 and C.1.5 shall be final and not 20 subject to appeal. l 21 C.1.1 Annointment of Technical Mediator 22 As soon as possible, but no later than one hundred j 23 and eighty (180) days after this Agreement is filed with FERC, 24 the Parties shall make good faith efforts to jointly select a 25 qualified person to serve for the term of this Agreement (or some 26 lesser appropriate length) as the Technical Mediator for purposes
- 27 of this provision. The Parties shall agree to share the costs of \# such Technical Mediator on an equal basis. Provided, however, 28 C-1
1 1 that if the Parties fail to select a Technical Mediator within 4 t 2 such time period, this Appendix C shall be null and void; b(~N 3 provided, further, that during this one hundred and eighty (180) l 4 day period, each Party shall nominate at a minimum three (3) J 5 qualified people to serve as the Technical Mediator. i 1 6 C.1.2 Scone of Discutes Subiect to Resolution by the ; 7 Technical Mediator 8 The Parties agree that the Technical Mediator shall l l 9 have authority to resolve the following type of disputes in 10 accordance with the provisions of this Appendix C: 11 (a) Sixtv-Day Studv Discute: I the event that in 12 its ten-day response pursuant to Section 6.6.2 with respect to a 13 request by DPS for an addition to, or modification of,-a 14 Transaction Point or to increase the MSD, PG&E replies that a () 15 sixty-day study will be required as provided for in Section 6.6.4 to determine the availability of the requested addition, 16 17 modification or increase, at any time following completion of 18 PG&E's sixty-day study, DPS may request the Technical Mediator to 19 assess whether the sixty-day study was, in fact, necessary for 20 PG&E to determine its ability to provide the requested addition, 21 modification or increase; 22 (b) Transmission Service Discute: In the event that 23 in responding to a sixty-day study in the manner specified in 24 Section 6.6.4 in response to a request by DPS to increase the MSD 25 or to be provided the transmission service necessary to conduct a l 26 particular transaction, PG&E states it can not increase the MSD 27 or cannot provide the transmission service necessary to conduct a l O- 28 carticular transaction, DPS may request the Technical Mediator to C-2
I 1 assess whether PG&E has the capability to increase the MSD or to e' 2 provide Network Transmission Service for the particular , 3 transaction; 4 (c) Interconnection Acreement Discute: In the event
*5 that in response to a request by DPS pursuant to Section 6.6 for 6 an addition of, or f or a modification to, a Transaction Point,-
7 PG&E denies the request on the grounds that the applicable ' 8 Transaction Point does not satisfy the Interconnection Agreement 9 precondition set forth in Section 6.4.2 and represents,to DPS as 10 provided for in Section 6.4.2.1 that such deficiency of the 11 Interconnection Agreement is an Appendix C issue,-DPS ma request 12 that the Technical Mediator assess the' appropriateness of PGEE's 13 determination that the existing Interconnection Agreement does 14 not satisfy the precondition set forth in Section 6.4.2. to add 15 or to modify a Transaction Point; and 16 (d) Section 8.20 Discute: In the event that the 17 Parties cannot agree upon interim procedures, rules, or l 18 regulations in accordance with Section 8.20, and/or cannot agree 19 pursuant to Section 4.3.5 to interim changes in the Spinning 20 Reserve Requirement, and, in accordance with these respective 21 sections, PG&E establishes interim procedures, rules, and l l 22 regulations or an interim changed' Spinning Reserve Requirement, 23 (" Interim Rules"), DPS may request the Technical Mediator to
.24 assess the reasonableness and appropriateness of, and the 25 necessity for, the Interim Rules.
26 C.1.3 Use of Technical Mediator to Resolve l 27 Accendix C Discutes l' O 28 In the event of an Appendix C Dispute, DPS may C-3
i 1 request that the Technical Mediator provide an independent di i
/ 2 technical assessment of PG&E's capabilities to authorize the V} 3 requested increase in transmission service capabilities or to 4 provide the specific transmission service in the manner requested 5 by DPS and/or the appropriateness of or necessity for the Interim i
6 Rules. DPS shall initiate this process by providing PG&E notice 7 that the Technical Mediator shall assess the particular l 8 Appendix C Dispute. DPS' notice shall state the service it i 9 requested or the Interim Rules at issue, the type of Appendix C 10 Dispute at issue, and the reasons it believes,PG&E is capable of 11 accommodating DPS' request with respect to either transmission 12 service or the Interim Rules. Within thirty- (30) days af ter 13 receipt of DPS' notice pursuant to this section, DPS and PG&E 14 shall provide the Technical Mediator their respective analyses D f 15 (including system simulation studies and underlying data) on 16 which they base their respective conclusions. The Technical 17 Mediator may request additional information from either Party 18 and/or may convene a conference with the Parties to discuss the 19 Appendix C Dispute. Upon request by the Technical Mediator, the 20 Parties shall send to any such conference officers with the full 21 authority to resolve the Appendix C Dispute. 22 C.1.4 Decision bv Technical Mediator Relatinc 4 23 to Transmission Services 24 As soon as practicable, and no later than sixty (60) the 25 days after receiving DPS' notice pursuant to Section C.1.3, 26 Technical Mediator shall issue its technical assessment of PG&E's 27 capabilities to satisfy fully the request by DPS. The technical 28 assessment for a Sixty-Day Study Dispute shall state whether it C-4
j ! I was necessary for PG&E to require the conducting of a sixty-day a i j 2 study as a condition of providing DPS the transnission service 1 l 3 requested. In the event the technical assessment determines that
- 4 it was not necessary for PG&E to conduct such a sixty-day study, 1
5 the Technical Mediator shall order that DPS shall not be
- 6 obligated to pay PG&E for any costs associated with the sixty-day i
1 7 study and that PG&E shall reimburse DPS for any payments , 8 heretofore made. The technical assessment for an Interconnection j 9 Agreement Dispute and for a Transmission Service Dispute shall 10 determine, respectively, whether PG&E has properly determined . . i 7 I 11 that the Transaction Point does not satisfy the Interconnection l 12 Agreement precondition set forth in Section~6.4.2.to add, or to l l 13 modify, a Transaction Point and whether PG&E has properly a 14 concluded that it can not increase the MSD or can not provide 15 Network Transmission Service to. accommodate the particular 1 4 f - 16 request. In the event that the technical assessment determines 17 that PG&E should have d,etermined that the existing 18 Interconnection Agreement satisfies the precondition to add, or 19 to modify, a Transaction Point, within ten (10) _ days, PGhE shall 20 add the Transaction Point to Appendix K and/or increase as ' 21 appropriate its Maximum Delivery Capability or its Maximum 22 Receipt Capability. In the event the technical assessment 4 23 determines that PG&E could increase the MSD as requested, within 24 ten (10) days, after the issuance of the Technical Mediator's 25 assessment, the Parties shall agree to provisions consistent with 26 this Agreement and the. Technical Mediator's analysis by which ] 27 PG&E shall increase the MSD and provide the requested 28 transmission service for the term requested. C-5
.~ , . ...-.. .._ - - - . _ .- - -. . ~ - - - - - . . ~ - . . . - - - . - . - _ . .
r 6 I 1 C.1.5 Decision by Technical Mediator on 8 f _ I 2 a Section 8.20 Discute , 3 As soon as practicaDle and no later than sixty (60) , 4 days after its receipt of DPS* notice pursuant to Section C.1.3, L 5 the Technical Mediator shall issue its technical assessment 6 regarding the reasonableness and appropriateness of, and the , i 7 necessity for, the Interim Rules. In the event that the [ 8 technical assessment determines that the Interim Rules are not I 9 reasonable and appropriate, or are not necessary, in no more than 10 five (5) days, the Interim Rules shall be vacated and the interim , 11 rules, regulations, and procedures which.DPS proposed to the 12 Technical Mediator (including that the're be no interim rules, 13 regulations or procedures or that their be no interim change in { l 14 the Spinning Reserve Requirement) shall become, if-any are () 15 necessary, the new interim rules, regulations, and procedures or 16 Spinning Reserve Requirement for purposes of Section 8.20. . 17 C.1.6 Anolicability of Annendix A Procedures 18 The provisions in Appendix A relating to settlement-19 (Section A.5.9); and confidentiality (Section A.5.10) shall be 20 applicable to the procedures set forth in this Appendix C. 21 22 23 24 25 1 26 27 . O>. 28 , C-6 l-l
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=
M 1 I 4 g .? i i i i i 1 l 4 a ) i i, i i } . . i i Appendix D ! RATES AND BILLING DETERMINANTS.
I 1 Appendix D 4! 2 RATES AND BILLING DETERMINANTS 3 l l 4 D.1 INTRODUCTION l 5 This Appendix D sets forth the rates and methods to 6 calculate the charge for services provided by PG&E to DPS and by 7 DPS to PG&E under this Agreement for a Billing Period. Should 8 any of the provisions of this Appendix D be in conflict with the 9 other terms or conditions of this Agreement, those other terms or I 10 conditions shall govern. Nothing contained herein shall be 11 construed as affecting in any way the respective rights of PG&E 12 or DPS under this Appendix D to unilaterally make. application to t 13 FERC, or to oppose such application, for a change in rates, 14 charges or rate methodologies pursuant to Section B.27. The f ( 15 rates and methods for calculating payments due in this Appendix D i 16 shall remain in effect and unchanged until the earlier of (a) l 17 PG&E or DPS filing with FERC to supersede those rates and methods 18 for calculating payments due or (b) the termination of this 19 Agreement, and shall not otherwise be subject to change. 20 21 D.2 AGC REGULATION SERVICE 22 D.2.1 Rate 23 The rate for AGC Regulation service reserved by DPS 24 in advance is $0.156/kW-month ("AGC Regulation Reservation 25 Rate"). The AGC Regulation Shortfall rate is 50.0104/kW-day 26 ("AGC Reservation Shortfall Rate"). 27 D.2.2 Charce 28 The charge for AGC Regulation service shall be the D-1 I l
- . - . - - . . - . . . - . . . ~ -
1 1 product of the AGC Regulation Reservation Rate and the AGC 8 { 1 2 Regulation Load Reserved as established in Sectio" " - ' Once
- 3 DPS reserves AGC Regulation service for the Billing Period, DPS 4
- 4 shall be obligated to pay for such service regardless of whether 1 5 or not DPS conducts sales transactions through the DPS Pool 4
\ 6 during the Billing Period.
. 7 D.2.3 AGC Reculation Shortfall Charce ,
8 For each day, if the AGC Regulation Load Effective 9 is greater than the AGC Regulation Load Reserved, then'.the AGC ) , 10 Reservation Shortf all Charge for the day shall be calculated as ) i . ) 11 follows: 4 12 AGC Reservation Shortfall Charge * (AGC. Regulation Load' l Effective - AGC Regulation Load Reserved) x AGC l
; 13 Regulation Shortfall Rate !
i l 14 l I D.3 INTER-HOUR LOAD BALANCING ("IHLB") SERVICE l 15 D.3.1 Rates i 16 i The rate for IHLB service is a function of the ratio 3 17 of the variable portion of the DPS Load to total DPS Load. For i 18 i the purpose of this Appendix D, variable load is the DPS Load { 19 corresponding with Variable Transactions and scheduled load is 20 3 the DPS Load corresponding to Scheduled Transactions. Rates as a
- - 21 i- function of the above ratio of variable load to total DPS Load i 22
, ("MW Ratio") are listed below: 23 f Rate MW Ratio 24
$0.26/kW-month up to 25%
25 S0.31/kW-month from 26% to 50%
, S0.36/kW-month over 50%
26 For any month, the MW Ratio shall be determined from the maximum 27 3 hourly Variable Transactions and the maximum hourly Scheduled
- 28 t
Transactions for the preceding month as recorded by PG&E. D-2
I 1 D.3.2 Minimum IHLB Purchase a 2 When DPS purchases any IHLB service from PG&E, DPS 3 shall purchase a kilowatt quantity of no less than ten percent 4 '(10%) of'the maximum load of the Non-Matching Loads as defined in l 5 Section 4.1.2. The loads in the Matching Loa,ds group shall not-l 6 be included'to calculate the minimum ten percent (10%) purchase r 7 requirement. Thus, a minimum charge for IHLB service will apply 1 8 in any Billing Period in which'DPS sells power using the DPS Pool 4 9 and purchases IHLB service from PG&E. The maximum of.the load of l 10 the-Non-Matching Loads group will be derived by examining the
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11 load history after the~ Billing Period. ) 12 D.3.3 Charae 13 The charge for IHLB service for the Billing Period 14 shall be the product of the applicable IHLB rate from 15 Section D.3.1 and the greater of (i) the amount of 1MLB Service t 16 reservation pursuant to Sections 4.2.2 or 5.1.2 or (ii) the 17 minimum purchase pursuant to Section D.3.2 above. H 18 19 D.4 SPINNING RESERVE SERVICE 20 D.4.1 Rate 21 The rate for DPS purchase of Spinning Reserve 22 service from PG&E is: 23
- PG&E. Spinning Reserve service rate . . . 54.07/kW-month 24 The disincentive rate for Spin Service Effective 25 being greater than Spin Service Reserved is:
115% x 50.134/kW-day 26
- Disincentive rate . . . . . . . . .
27 The disincentive rate is subject to the provisions of 28 Section J.4.2.2. 1 D-3 l
I i 1 The rate for PG&E purchase of Spinning Reserva *l (] 2 energy from DPS is: i V 3
- DPS Spinning Reserve service rate . . . . . 115% x (SRAC) 4 D.4.2 Charoes 5 D.4.2.1 Charoes Pavable to PG&E: The charges for 6 the Spinning Reserve services provided by PG&E for each Billing ,
7 Period shall be the sum of: (i) the product of the maximum spin 8 Service Effective as calculated in Section 4.3.4, for any day 9 during the Billing Period, and the PG&E Spinning Reserve service 10 rate; and (ii) the sum of the charges for eac,h day in the Billing 11 Period when Spin Service Effective is greater.than Spin Service 12 Reserved. The charge on any day that this occurs is the product 13 of the Spin Service Effective minus the Spin Service Reserved for I 14 that day and the disincentive rate pursuant to Section D.4.1. () 15 D.4.2.2 Charoes Pavable to DPS from PG&E: The 16 charges payable to DPS from PG&E for purchasing Spinning Reserve-17 energy equals the product of the amount of Spinning Reserve 18 service energy requested by PG&E and provided by DPS in 19 accordance with Section 4.3.6 and the DPS Spinning Reserve j l 20 service rate, al 21 22 D.5 MONTHLY BILLING CHARGE 23 The Monthly Billing Charge is to reimburse PG&E for its 24 ongoing monthly costs of labor and supervision for billing 25 services which PG&E provides to DPS under this Agreement, 26 including, but not limited to: (i) billing, (ii) accounting for 27 load / generation deviations and (iii) monitoring compliance with O 28 Control Area Service provisions to the extent DPS does not D-4
i i purchase Control Area Services from PG&E. The Monthly Billing *! [')' V 2 Charge does not include scheduling costs. 3 D.5.1 Rate 4 The rate for billing services shall be S40/per 5 person-hour. 6 D.5.2 Charce 7 The charge for billing services for the Billing. 8 Period shall equal the product of the rate for billing services ! 9 and the number of hours of direct PG&E labor time attributable to 10 DPS transactions during any Billing Period in which DPS conducts 11 transactions under this Agreement. 12 1 13 D.6 ADDITIONAL ENERGY EXCHANGE BAND 14 D 6.1 Billino Determinant (~T ( ,) 15 The billing determinant for DPS' pu'rchase of 16 additional Energy Exchange Band is determined by the magnitude of 17 DPS' request for additional Energy Exchange Band pursuant to 18 Section 4.6.7. The billing determinant equals the amount DPS 19 requests in increments of at least one hundred (100) KWh/ Hour not 20 to exceed a total band width of seven (7) MWh/ Hour, (i.e., 21 7,000 kW-Hour / Hour) (" Billing Demand"). ! 22 D.6.2 Rate 23 The rate for purchase of additional Energy Exchange 24 Band is S4.93/kW-month. l 25 D.6.3 Charce 26 The charge for additional Energy Exchange Band is 73 27 the product of the Billing Demand and the rate for purchase of e 4
28 additional Energy Exchange Band.
D-5
1 D.7 OVERGENERATION AND UNDERGENERATION CHARGE 8' 2 D.7.1 Qveraeneratier Charoe 3 This Overgeneration Charge is intended solely to be i 4 a disincentive and expressly is not intended to function at any 5 time as a cost-based rate for " service" voluntarily provided by 1 6 PG&E'to DPS. The Overgeneration Charge shall not be deemed a I 7 " service" either offered or provided by PG&E to DPS. This c.harge 8 represents damages to PG&E from reducing generation at Diablo 9 Canyon Nuclear Power Plant and/or spilling water at its 1 10 hydroelectric facilities, and will operate solely as an economic 11 disincentive to DPS, minimizing the economic incentive for DPS to 12 allow power to flow onto PG&E's Electric System without notice, 13 without scheduling that power, and with no contractual right to 4 14 allow that power to flow. DPS shall pay the Overgeneration i () 15 Charge as billed, in accordance with Section D.7.3. DPS agrees 16 that it shall not challenge, in any judicial or regulatory forum, 17 the following formula, the method of calculation under 18 Section 4.6, or any change in the charge properly calculated on 19 the basis of that formula. PG&E reserves the right to change 20 such formula and DPS reserves the right to. oppose such change. I 21 This charge is applicable to positive hourly energy deviation 22 within the First Deviation Band determined in accordance to 23 Sections 4.6.6.1 and 4.6.6.3. This charge does not apply except 24 when such positive energy deviations occur during Minimum Load 25 Conditions. 26 The Overgeneration Charge is derived from PG&E's f 27 CPUC rate settlement concerning the Diablo Canyon Nuclear Power 28 Plant as established in CPUC Dec. 88-12-083 or as such settlement D-6
1 may be modified (the "Diablo Canyon Rate"). The disincentive 8! 2 rates for the Overgeneration Charge within the First Deviation 6 3 Band are: 4 CURRENTLY APPLICABLE RATE 5 Fixed Variable Component Component Rate 6 Date Charge Is Applied (S/kWh) (S/kWh) (S/kWh) 7 1/1/94 - 12/31/94 0.0315 0.08735 0.1188.5 1/1/95 - 12/31/09 0.0315 Note 1 As Calcula'ted i 8 Note 1: Beginning on January 1, 1995, the escalating price (variable component) shall be increased by the sum of the change in the U.S. Bureau 9 of Labor Statistics' year-end national consumer price index (CPI) during the immediately concluded year and 2.5 percent divided by 2. For example, in 10 the year 2000, assuming a CPI increase of 5 percent annually, the rate is 50.14056/kWh. 11 Source: CPUC Decision 88-12-083, issued December"19, 1988, athage129. 12 To the extent the Diablo Canyon R' ate changes during the term. 13 of this Agreement, the Overgeneration rate shall equal the Diablo 14 Canyon Rate actually in effect at the time of any Overgeneration
- 15. during Minimum Load Conditions.
16 The Overgeneration Charge within the Second Energy Deviation 1 i 17 Band is: 18
- Second Energy Deviation Band Rate . . . . . . . S150/MWH 19 D.7.2 Underceneration Charce 20 This Undergeneration Charge is. applicable to 21 negative hourly energy deviations within the First Deviation Band 22 and Second Deviation Band which are determined in accordance to 23 Sections 4.6.6.2 and 4.6.6.3.
24 The disincentive rates for the Undergeneration Charge within 25 the First Deviation Band are: 26
- Undergeneration Capacity Rate . . . . . . . S0.164/kW-day 27
- Undergeneration Energy Rate . . . . . . . . 115% x SRAC.
28 D-7 I
1 The rate for the Undergeneration Charge within the Second 8 i 2 Energy Deviation Band is: ()N
\. .
, 3
- Second Energy Deviation Band Rate . . . . . . 50.150/kWh
! '4 D.7.3 Charoes i
; 5 The charges for Overgeneration and Undergeneration 6 are calculated as follows:
7 The entire hourly energy deviation for each-8 individual Scheduling Period is placed entirely into one of the i 9 following seven categories: '
)
10 (1) Deviations within the Energy Exchange Band per 1
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11 Section 4.6.5; 12 (2) Positive hourly energy deviations within the 13 First Deviation Band per Section 4.6.6.1 during 14 times other than Minimum Load Conditions; () 15 (3) Positive hourly energy deviations within the First Deviation Band per Section 4.6.6.1 during'. 16 17 times of Minimum Load Conditions; 1 18 (4) Negative hourly energy deviations within the 19 First Deviation Band per Section 4.6.6.2; ; 20 (5) Positive hourly energy deviations within the 21 Second Deviation Band per Section 4.6.6.3 22 during times other than Minimum Load j 23 Conditions; 24 (6) Positive hourly energy deviations within the 25 Second Deviation Band per Section 4.6.6.3 26 during times of Minimum Load Conditions; or 27 (7) Negative hourly energy deviations within the 28 Second Deviation Band per Section 4.6.6.3. D-8
. _ . _ _ __ .__._.__.-__...__.__._m__... _ _ _ __. _ _.
1 At the end of the Billing Period, a summation is 8l 2 made within each category of the hourly energy deviations-that
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3 were placed within that category to determine the total energy 4 for each of the seven categories referenced above. The charges ; I 5 (if any) due to PG&E from the seven categories are summed up for 6 each Billing Period to calculate the total charge due for f 7 deviations. . 8 Each of the above seven categories is treated l 9 differently for calculating charges due PG&E for the Billing 10 Period. The methodology for each category is as follows.: 11 (1) There are no charges associated with this first 12 category. Instead of a charge, the deviations 1 13 are scheduled to be returned per Section 4.6.5. 14 (2) There are no charges associated with this
) 15 category.
16 (3) The charge is the product of the energy and the. 17 Diablo Canyon Rate. 18 (4) Both a capacity charge and an energy charge may 19 apply. The capacity charge is calculated on a 20 daily basis by multiplying: (1) the maximum 21 hourly energy deviation for this category 22 within the day divided by the hour; and (2) the 23 Undergeneration Capacity Rate in Section D.7.2 24 provided, that the capacity charge does not 25 apply on days when there is also an hourly energy deviation in category seven. The 26 27 capacity charges for each day (if any) are 28 summed up to calculate the capacity charge for D-9
l 1 the month. The energy charge for the month is 4! 2 the product of the energy and the 3 Undergeneration Energy Rate in Section D.7.2. , 4 (5) .The charge'is the product of the energy and the 5 Second Deviation Band Rate in Section D.7.2. 6 (6) The charge is the product of the energy and the 7 sum of the Diablo Canyon Rate and the Second 8 Deviation Band Rate in Section D.7.2. 9 (7) Both a capacity charge and an energS charge , 10 apply. The capacity charge is calculated on a 11 daily basis by multiplying: 1) the maximum 12 hourly energy deviation for this category 13 within the day divided by the hour; and 2) the. 14 Undergeneration Capacity Rate in D.7.2. The ( 15 capacity charges for each day'.(if any) are 16 summed up to calculate the capacity charge for. 17 the month. The energy charge for the month is 18 the product of the energy and the sum of the 19 Undergeneration Energy Rate and the Second 20 Deviation Band Rate in Section D.7.2. 21 22 D.8 NETWORK TRANSMISSION SERVICE 23 D.8.1 Aeolicability 24 Network Transmission Service provided to DPS in 25 accordance with Section 6 and listed in Appendix K shall be 26 subject to different rates for transmission and distribution.
- 27 The Transmission Rate applies for delivery points of voltages of \- 28 60 kV and greater. The Primary Distribution Rate applies for D-10
1 1 delivery points of voltage greater than or equal to 4.16 kV and *! [3
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2 less than 60 kV. 3 D.8.2 Rates 4 D.8.2.1 Transmission Rate: The rate for Network 5 Transmission Service is $1.65 per kW per month. 6 D.8.2.2 Primary Distribution Rate: The rate for 7 distribution service is $3.37 per kW per month. 8 D.8.3 Charaes I 9 The charge for Network Transmission Service for a 10 Billing Period is the product of the MSD in kilowatts applicable ! 11 to transmission voltage service from Appendix K (i.e., th'e sum of i 12 Annual Firm Service and Short-Term Fism Service) corresponding to 13 the Billing Period and the Transmission Rate for service provided 14' at transmission voltage plus the product of the MSD in kilowatts (~% ( ,) 15 for primary distribution level service from Appendix K and the 16 Primary Distribution Rate. Pursuant to Section 6.1.1, DPS is not'. 17 required to purchase or to pay for Network Transmission Service 18 for losses or for Spinning Reserve. 19 D.8.4 Uoarade Charoes 20 As specified in Section 6.2, where a transmission 21 study (in accordance with Section 6.6) identifies the need for 22 system upgrades in order to provide requested transmission 23 service and the Parties agree to proceed with construction, DPS 24 shall pay the higher of the following two charges (but not both): l 25 (a) A charge consisting of the product of the 26 Transmission Rate set forth in Section D.8.2.1
,S 27 (as modified to reflect the Costs of b 28 construction that were added to plant in I
l l D-11 i
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l 1 service for any required system upgrades on a 8 f 2 rolled-in basis) and any " supplemental MSD"
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3 that may be scheduled involving such system 4 upgrade. l 5 03) A charge consisting of the product of the DPS 6 proportional share of the incremental Costs of 7 construction that were added to the plant in 8 service for any system upgrade that would not 9 have been needed but for the transmission 10 service requested by DPS and seventeen percent 4 11 (17%). If DPS pays all or-its proportional 12 share of the Costs of a system upgrade as a 13 contribution in aid of construction (including i 14 any taxes associated with DPS payment), DPS l () 15 shall be entitled to a reducti-on to four and a 16 half percent (4.5%) (from seventeen percent 17 (17%)) for the percent factor used to calculate 18 the charge. 19 If FERC requires a filing and acceptance before charging DPS 20 under (a) or 03) above, pending FERC acceptance, PG&E will charge 21 DPS the product of $1.65 per kW-month and any supplemental MSD in 22 kilowatts. 23 24 D.9 REPLACEMENT POWER 25 D.9.1 Billine Determinants 26 The billing determinants for replacement power 27 energy are the kilowatt hours of energy associated with all O '! 28 replacement power provided pursuant to Section 6.3.4 during the D-12
I 1 Billing Period. The billing determinant for any capacity 4 2 associated with replacement power shall equal the amount of as-
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3 available capacity that DPS' reallocation of its preschedule 4 causes PG&E to purchase from EA Resources. 5 D.9.2 Rate j 1 6 . The energy rate for replacement power shall equal-7 one hundred and five percent (105%) of the SRAC rate applicable 8 during the hours and period of curtailment. The rate for 9 replacement power capacity shall equal the rate PG&E it fact paid 10 for as-available capacity associated with the power reallocated 11 from the DPS Pool during a curtailment to an EA Resource and sold 12 to PG&E. 13 D.9.3 Charce 14 The charge for replacement power during the Billing
) 15 Period shall equal the product of the Section D.'9.2 energy rate 16 for replacement power and the quantity of Section D.9.1 kilowatt 17 hours of energy associated with that replacement power plus, if 18 applicable, the amount paid by PG&E for as-available capacity.
19 20 21 22 23 24 25 26 27 f-
~~' 28 D-13
4 l 1 1 l I l i { i 1 1 Appendix E ENABLING AGREEMENT l l l l I f l .-
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l l 1 l I l l i I l ENABLING AGREEMENT E-1
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4 L O 1 1 1 l i l 1 1 1 1 1 ENABLING AGREEMENT FOR - PPA QF SUPPLIERS BETWEEN DESTEC POWER SERVICES, INC. O - PACIFIC GAS AND ELECTRIC COMPAhT l l0 i 1
. - . -. - = ._ --_- - . - _ . - -
4 TABLE OF CONTENTS - n
- 1. RECITALS . . . . . . . . . . . . . . . . . . . . . 1 4
- 2. DEFINITIONS . . . . . . . . . . . . . . . . . . . 2 4 2.1 CPUC . . . . . . . . . . . . . . . . . . . 2 2.2 Control Area . . . . . . . . . . . . . . . 2 1 2.3 Control Area Agreement . . . . . . . . . . 2 2.4 DPS Supplier . . . . . . . . . . . . . . . 2 2.5 EA Resource . . . . . . . . . . . . . . . 3 2.6 Excess Power . . . . . . . . . . . . . . . 3 '. ,
2.7 FERC . . . . . . . . . . . . . . . . . . . 3 2.8 PPA . . . . . . . . . . . . . . . . . . . 3 ; 2.9 PPA Firm Capacity . . . . . . . . . . . . 3 l 2.10 PPA QF Supplier . . . . . . . . . . . . / 4 ' 2.11 Interconnection Agreement . . . . . . . . 4 2.12 QF . . . . . . . . . . . . . . . . . . . . . 4 2.13 Recognized Delivery Level . . .. . . . . - 4 1 2.14 WSPP . . . . . . . . . . . . . . . . . . . 4 2.15 Western Systens Power Pool Agreement i ("WSPPA") . . . . . . . . . . . . . . . . 4 l i
- 3. RELATIONSHIP OF ENABLING AGREEMENT WITH RELEVANT l AGREEMENTS GOVERNING THE SALE AND TRANSMISSION OF 4
ELECTRIC POWER . . . . . . . . . . . . . . . . . . 4
- 4. EFFECTIVE DATE AND TERMINATION OF AGREEMENT . . . 6 4.1 Effective Date . . . . . . . . . . . . . . 6 4.2 Termination . . . . . . . . . . . . . . . 6 4.3 Extension of Term . . . . . . . . . . . . 6
- 5. EA RESOURCE . . . . . . . . . . . . . . . . . . . 7 5.1 DPS Suppliers Required to Qualify as an EA Resource . . . . . . . . . . . . . . . . . 7 5.2 EA Resource Qualification Procedures . . . 7 5.3 Removal of EA Resource Status . . . . . . 12 5.4 Initial Limitation Upon Number of DPS Suppliers . . . . . . . . . . . . . . . . 12 5.5 Pre-1996 Limitation on Megawatts Deliverable by EA Resources . . . . . . . 12 l i
- 6. DPS POWER SALES . . . . . . . . . . . . . . . . . 13 !
6.1 DPS Sales . . . . . . . . . . . . . . . . 13 6.2 Scheduling . . . . . . . . . . . . . . . . 13 6.3 No Purchases of PPA Firm Capacity by DPS . 13
- 7. THIRD PARTY LIABILITY . . . . . . . . . . . . . . 14
- 8. CAPTIONS . . . . . . . . . . . . . . . . . . . . . 14 b)
% J-i
- 9. GOVERNING LAW . . . . . . . . . . . . . . . . . . 14
- O 10.
11. NOTICES . . . . - . . . . . . . . . . . INTEGRATION CLAUSE - . . . . . . . . . . . . . . .
. . . 14 15
- 12. REGULATORY CHANGES . . . . . . . . . . . . . . . . 16
- 13. CONSTRUCTION OF AGREEMENT . . . . . . . . . . . . 16 r
l P l 4
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1 ! ENABLING AGREEMENT 2 FOR [O L1 3 PPA QF SUPPLIERS I BETWEEN 4 DESTEC POWER SERVICES, INC. AND 5 PACIFIC GAS AND ELECTRIC COMPANT
.g 7
1 8 This Enabling Agreement (" Agreement") is entered into on 9 November 29, 1994, by and between Destec Power Services, Inc., 10 ("DPS"), a Delaware corporation, and Pacific Gas and Electric 11 Company ("PG&E"), a California corporation. DPSandPG& hare 12 sometimes referred to herein collectively as " parties" and . 1 1 13 individually as " party." 14 ' RECITALS. r"'N 15 1.1 DPS has filed an application (Docket No. ER94-1612-16 000) with the Federal Energy Regulatory Commission to be 17 authorized to be a power marketer and thereby purchase and sell 18 electric power. . 19 1.2 DPS will obtain electric power for resale from DPS 20 Suppliers, as defined in Section 2.4 and in Section 1.27 of the 21 Control Area Agreement, which is being executed concurrently. 22 1.3 DPS will execute Power Marketing Agreements ("PMAs") 23 with various DPS Suppliers which own and/or operate electric 24 generation facilities and will purchase power for resale through 25 these PMAs. 26 1.4 DPS will purchase power from one class of entities 27 which sells power to PG&E pursuant to a standard offer or other form of a power purchase agreement (" PPA"). This subset of DPS (n) 28
1 Suppliers is referred to as " PPA QF Suppliers". / l 73 2 1.5 The PPA OF Suppliers will continue to sell capacity 3 and/or energy to PG&E pursuant to the terms of their respective 4 PPAs and also desire to sell " Excess Power" (as defined in 5 Section 2.6) to DPS. 6 1.6 As a condition of selling Excess Power to DPS, the 7 PPA QF Suppliers are obligated to qualify as an EA Resource.in 8 accordance with the provisions of this Agreement. This Agreement 9 provides certain qualifications for and limitations upon, and 10 certain accounting and priority of delivery rules with respect to 11 DPS' purchase of power from EA Resources. DPS desires to' offer l l 12 to sell the Excess Power delivered by EA Resources (as defined in 13 Section 2.5) and to offer to sell the power delivered by all l l 14 other DPS Suppliers. ()
'v 15 1.7 The rules, protocols and procedures, set forth in 16 this Agreement are no' applicable to power supplied to DPS from 17 DPS Suppliers which are not a PPA QF Supplier.
18 2. DEFINITIONS. 19 2.1 CPUC: The California Public Utilities Commission, 20 or its regulatory successor. 21 2.2 Control Area: Defined in Section 1.15 of the 22 Control Area Agreement. 23 2.3 Control Area Acreement: The Control Area and 24 Transmission Service Agreement concurrently being executed by 25 PG&E and DPS. 26 2.4 DPS Sueolier: Defined in Section 1.27 of the 27 Control Area Agreement as ar., sutity supplying electric power or () 28 energy to DPS. 2
_~- . . .
- . - . - _ _ ~ - - - . - - - - -- . _ - . - . . - . _._ - - . - -
! i 1 2.5 EA Resource: A ppa QF Supplier which has been ,
1 f- 2 approved pursuant to Section 5 to sell Excess Power to DPS, 3 2.6 Excess Power: 4 (a) With respect to any EA Resource which has an .i 5 obligation to deliver PPA Firm Capacity to PG&E (as defined in i : , 6 Section 2.9), " Excess Power" represents the amount of capacity i 7 and associated energy produced which exceeds the PPA Firm 8 Capacity level specified in the EA Resource's PPA. The PPA Firm 9 Capacity level shall remain constant for the purpose o.f l
! 10 calculating the amount of Excess Power, even during periods in l
11 which PG&E may be exercising any right to curtail or lindt the EA 12 Resource's power deliveries, and with'the exception of: (1) I amendments to the PPA that change the PPA Firm Capacity level; i 13 I 14 and/or (2) a PPA Firm Capacity level deration implemented by PG&E l 1 : 15 in accordance with the provisions of the EA Resource's PPA. 16 (b) For EA Resources with no obligation to deliver' ' i 17 PPA Firm Capacity to PG&E, Excess Power represents the amount of l 18 capacity and associated energy that such EA Resource has 1 19 authorized DPS in its PMA to sell and which such EA Resource can l i 20 deliver or have delivered into the PG&E system, except to the j 21 extent that such capacity and energy is being physically l 22 curtailed by PG&E pursuant to the terms of the EA Resource's PPA. 23 '2.7 FERC: The Federal Energy Regulatory Commission, or ) 24 its regulatory successor. l 25 2.8 EPA: The power purchase agreement between.a QF and 26 PG&E, including any applicable amendments. 27 2.9 PPA Firm Caoacity: The level of firm or contract ) () 28 capacity, if any, specified in a PPA of a PPA QF Supplier. 3 ' l
i 1 2.10 PPA OF Sunolier: A QF which has executed a PMA with, i 1 73 2 DPS and is currently selling power to PG&E pursuant to a standard
) 'l 3 offer contract or other form of PPA.
l 4 2.11 Interconnection Acreement: As defined in Section i 5 1.44 of the Control Area Agreement and described in Section 6.4.2 6 of the Control Area Agreement. 7 2.12 QE: A cogenerator or small power producer that l 8 meets the criteria set forth in 18 C.F.R. 5 292.203. j 9 2.13 Recoenized Delivery Level: The maximum aggregate 10 amount of the rate of power that a PPA QF Supplier has a 11 contractual right to and is currently physically able to deliver 12 to PGLE, provided, that the Recognized. Delivery Level for a PPA 13 OF Supplier shall be no less than its historical deliveries in 14 accordance with its current contractual rights. rT 15 2.14 WSPP: The Western System Power Pool, as defined by
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16 the WSPPA. 17 2.15 Western Systems Power Pool Acreement ("WSPPA"): As 18 defined in Section 1.77 of the Control Area Agreement. 19 3. RELATIONSHIP OF ENABLING AGREEMENT WITH RELEVANT AGREEMENTS 20 GOVERNING THE SALE AND TRANSMISSION,OF ELECTRIC POWER. 21 3.1 This Agreement specifically does not set forth the 22 terms or conditions governing the sale of any electric power 23 between DPS, PG&E and/or any EA Resource. Except to the extent 24 that the Schedule A Letter Agreement attached hereto modifies an 25 EA Resource's PPA, the terms and conditions for the sale of all 26 power, including Excess Power, to PC'tE by an EA Resource shall 27 continue to be governed by the terms of the EA Resource's PPA. (n) uj 28 3.2 This Agreement specifically does not address DPS' 4
1 rights to schedule and transmit power deliveries within, into, cr e.i 2 out of PG&E's Control Area. Such rights are set forth in the 3 Control Area Agreement. 4 3.3 Nothing in'this Agreement shall be interpreted as 5 restricting or expanding the rights and obligations of PG&E or of 6 any EA Resource under a PPA, except as expressly set forth in the 7 Schedule A Letter Agreement attached hereto. Among other . 8 matters, nothing in this Agreement enhances or restricts PG&E's 9 rights to issue curtailment orders pursuant to the provisions of 10 its respective PPAs, nor enhances or restricts the EA Resource's 11 options pursuant to the PPA to respond to any'such curtailment 12 order. 13 3.4 PG&E's execution of this Agreement, and its approval' 14 thereby of the Schedule A Letter Agreement, constitutes PG&E's 15 agreement with any EA Resource to modify such EAiResource's PPA 16 in the manner set f orth in the Schedule A Letter Agreement ~(the 17 form of which is attached hereto), provided that the PPA QF 18 Supplier has qualified as an EA Resource pursuant to Section 5.2 19 herein. 20 3.5 DPS does not own or operate any electric generating 21 facilities and it is not a OF. DPS agrees that by it purchasing 22 power from an EA Resource, it does not attain OF status and that 23 the Public Utility Regulatory Policies Act of 1978 accordingly 24 does not obligate PG&E to purchase any energy or capacity from 25 DPS. 26 3.6 To the extent that DPS' ability or right to purchase 27 and resell Excess Power is, either within or outside the context ( 28 of this Agreement, subjected to or determined by federal and/or 5
l l l 1 state law, regulations or rules, this Agreement is not intended 4, ; 2 to define such ability or right nor waive DPS' or PG&E's O- 3 respective rights with respect to applicable federal and/or state 4 laws, regulations or rules. 5 4. EFFECTIVE DATE AND TERMINATION OF AGREEMENT. i 6 . ,4 .1 Effective Date 7 This Agreement shall become effective on the date it 8 is executed by the parties. 9 4.2 Termination i. 10 This Agreement shall terminate five (5) years from 11 the Effective Date of the Control Area Agreeme'nt or as mutually 12 agreed by the Parties. . 13 4.3 Extension of Term 14 Section 4.2 notwithstanding, the term of this 15 Agreement may be extended in accordance with the(following 16 provisions: i 17 (a) at least ninety (90) calendar days prior to the ' 18 third year after the. effective date, DPS or 19 PG&E (" notifying Party") provides the other 20 Party (" receiving Party") with written notice l 21 that it desires to extend the term of this 22 Agreement for a specified period of time; and 23 (b) within ninety (90) calendar days of receipt of 24 such notice, the notifying Party will respond 25 in writing stating whether it agrees to extend 26 the term of this Agreement by the amount of i 27 time specified by the notifying Party, or by a ( . 28 lesser amount (" shorter extension"). The 6
1 1 receiving Party is not required to agree with 4 r3 2 the notifying Party's request for extension or ('~') 3 to propose a shorter extension. If the i 4 receiving Party agrees to extend this Agreement j i 5 by the amount requested by the notifying Party, ! 6 or the notifying Party agrees to the shorter 7 extension, this Agreement shall continue in ) 8 full force and effect in all respects until the 9 additional amount of time agreed to $y the 10 parties has expired. Absent the parties l 11 agreeing to an extension pursuant to this
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12 Section 4.3, this Agreement shall terminate no 13 later than the date provided for in i 14 Section 4.2. (9
\ J' 15 5. EA RESOUI!CE.
[ 16 5.1 DPS Sunnliers Recuired to Oualifv as an EA Resource 17 A PPA QF Supplier must qualify as an EA Resource 18 pursuant to the provisions of Section 5.2 as a condition of 19 selling Excess Power to DPS. All other DPS Suppliers nay sell 20 power to DPS without qualifying as an EA Resource, and without 21 being subject to the limitations upon sales to DPS set forth in 22 Section 5.5. 23 5.2 EA Resource Oualification Procedures 24 A PPA QF Supplier shall qualify as an EA Resource in 25 accordance with the following procedures: 26 (a) At any time, DPS may provide PG&E with written l 27 notice that DPS intends to submit a Schedule A t <~, f_ 28 Letter Agreement for an EA Resource. Upon 7
1 I I 1 t 1 notification by DPS that its notice contains a 2 confidential or proprietary information, the 3 confidentiality provisions of Sections 8.21 and 4 8.22 of the Control Area Agreement shall be f I 5 applicable to such written notice. Such 6 written notice must include the name of the PPA 7 QF Supplier, the location of the project,,and-8 the PG&E project log number. Upon notification j i 9 by DPS that its notice contains confidential or 10 proprietary information, the. confidentiality 11 provisions of Sections 8.21 and 8.22 of'the j 12 Control Area Agreement shall be applicable to l 13 such written notice. DPS shall provide such 14 notice by certified United States mail, by a 15 nationally recognized overnigh't or express mail 16 service, or by facsimile which is confirmed by l 17 a subsequent facsimile from PG&E. 18 (b) Within thirty (30) calendar days of receiving 19 written notice from DPS pursuant to Section 20 5.2 (a) , PG&E shall provide DPS with a written 21 response stating whether PG&E has approved the 22 PPA QF Supplier as an EA Resource. If PG&E 23 does not approve a PPA QF Supplier as an EA 24 Resource, PG&E's written response shall specify 25 the reason (s) specified in Section 5.2(d) 26 herein for PGLE's disapproval. PG&E may also j l i I l ,_ 27 request, for good cause stated, an additional l
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l 28 fifteen (15) calendar days in which to provide l
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8 i
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l l l 1 a response. If PG&E properly requests such a 4l ) l 1 lgg 2 fifteen (15) day extension, PG&E shall provide (_ l DPS with a written response stating whether i 3 l i 4 PG&E has approved the PPA QF Supplier as an EA l 1 5 Resource within forty-five (45) calendar days l 6 after receiving the written notice.provided l 7 pursuant to Section 5.2 (a) . I 8 (c) If PG&E does not provide a written response i 1 9 within the initial thirty (30) days %nd has not l l 10 made a proper request for an extension, the PPA j 11 QFSuppliershallbeautomahicallyappr'ovedas 1 12 an EA Resource. In any event, if PG&E has not 13 provided a written response within forty-five 14 (45) days, the PPA QF Supplier shall be 15 automatically approved as an E'A Resource. ( 16 (d) PG&E may refuse to approve the PPA QF Supplier' 17 as an EA Resource for good cause. PGEE may not 18 unreasonably deny such approval. PG&E may ; I 19 refuse to approve any PPA QF Supplier if so 20 doing would cause the limitations in Sections l 21 5.4 and 5.5 to be exceeded. Good cause 22 sufficient for PG&E to deny approval of a PPA 23 QF Supplier as an EA Resource must be based 24 upon specific contractual, facility, or PG&E 25 system reliability issues of the following l 26 types: ; I l 27 (i) Terns in the PPA QF Supplier's PPA i () 28 prevent or conflict with the PPA QF 9
1 Supplier delivering Excess Power tos I i c', 2 DPS; or, e ) 3 (ii) The interconnection facilities 4 between PG&E and the PPA OF 5 Supplier are physically inadequate 6 to enable the PPA QF Supplier to-7 deliver both Excess Power and.the 8 PPA Firm Capacity to PG&E; or 9 (iii) Adequate metering, protegtion, and 10 data acquisition facilities
~
11 necessary for purposes of sales 12 from a PPA QF Supplier to DPS de 13 not exist. 14 With respect to a PPA 0F Supplier which [J L
') 15 16 has an existing Interconnection Agreement with PG&E, PG&E may not refuse to approve such PPA 17 QF Supplier as an EA Resource on the basis of 18 an inadequacy of the interconnection facilities 19 as provided for in Section 5.2 (d) (ii) if the 20 PPA QF Supplier seeks authority to deliver to 21 PG&E an aggregate amount of power (i.e., the 22 sum of the PPA Firm Capacity and an amount of 23 Excess Power) which is less than or equal to 24 the Recognized Delivery Level; provided DPS 25 must comply with the provisions of Section 6 of 26 the Control Area Agreement prior to obtaining 27 transmission service to deliver power from such
( 28 EA Resource. 10
I 1 With respect to a PPA QF Supplier which 4 1 2 seeks to sell an amount of Excess Power that ' 3 will cause its total aggregate power deliveries 4 to PG&E to exceed the Recognized Delivery 5 Level, PGEE shall approve the PPA QF Supplier 6 as an EA Resource and limit its level of Excess I l 7 Power so that the aggregate level of authorized j l 8 deliveries does not exceed the Recognized j 9 Delivery Level. If a PPA QF Supplie^r's 10 Recognized Delivery Level is subsequently 11 modified,DPSmaysubmitahevisedrequest 12 subject to this Secticn 5.2, and PGEE shall 13 process such request as expeditiously as 1 14 possible and otherwise in accordance with the 15 provisions of Sections 5.2 (b) , . (c) and (d). 16 (e) At any time within 180 calendar days rfter the ! i 17 requirements of this Section 5.2 hr.ve been 18 satisfied with respect to a PPA QF Supplier, 19 DPS may provide PG&E with a Schedule A Letter 20 Agreement completed and executed by the 21 approved EA Resource. 22 (f) Subject to the limitations and conditions 23 specified in this Agreement, DPS may commence 24 purchasing and reselling Excess Power delivered 25 by an EA Resource thirty (30) calendar days 26 after providing a completed and executed 27 Schedule A Letter Agreement to PGEE pursuant to ( '( 28 Section 5.2 (e) . 11
i l 1 5.3 Removal of EA Resource Status , 1 2 DPS may remove a PPA QF Supplier from EA-Resource 0'# 3 status by providing PG&E. thirty (30) calendar days written notice 4 of its intent to remove such a PPA QF-Supplier from EA Resource 1 5 status. 6 5.4 Initial Limitation Uoon Number of DPS Sucoliers 7 Notwithstanding any of the above, for the first.one 8 hundred and eighty (180) calendar days after the Effective Date 9 of this Agreement, the total number of DPS Suppliers shall be no 10 greater than fifteen (15). 11 (a) PG&E may extend this 180 calendar day ' 12 limitation period an. additional ninety (90) - 13 calendar days by notifying DPS of its need for 14 such an extension thirty (30) calendar days () 15 16 before the end of the initial'180 day limitation period. However, PG&E may only 17 invoke this extension provision if PGEE is 18 unable within the initial 180 days to develop 19 and/or implement the computer programs 20 necessary to accommodate more than fifteen (15) 21 DPS Suppliers. PG&E will use its good faith 22 efforts to develop and implement within the 23 initial 180 day limitation period the computer 24 programs necessary to accommodate more than 25 fifteen (15) DPS Suppliers. 26 5.5 Pre-1996 Limitation on Mecawatts Deliverable by EA I 27 Resources f 28 The aggregate number of megawatts ("MWs") of Excess l l 12 l
--. - - - . - - . . - . _ - . . _ - . - - _ _ ~ - . .-. _ - .
i
- 1 Power deliverable to DPS by EA Resources shall not exceed k I ,
r% 2 300 MWs. This limitation upon the aggregate number of MWs 3 deliverable by EA Resources shall be vacated and of no force or 4 effect as of January 1, 1996.
- 5 6. DPS POWER SALES.
6 , 6 .1 DPS Sales l 7 Subject to the limitations and conditions specified' 8 in this Agreement, DPS may offer to sell Excess Power from an EA 9 Resource; provided this Agreement does not authorize nor enable i ! 10 DPS to sell power to retail electric customers located within the 11 PG&E utility service territory. 12 6.2 Schedulina i 13 The Control Area Agreement requires DPS to submit a l 14 final schedule of energy deliveries twenty (20) minutes before
'() 15.
16 each hour in which DPS schedules a sale of Excess Power ("DPS Hourly Schedule"). With rerpect to any Excess Power which DPS 17 schedules in the DPS Hourly Schedule for sale by DPS, DPS ! 18 recognizes that PG&E shall be relieved of its obligation to the 19 EA Resource under the PPA to purchase such power. 20 6.3 No Purchases of PPA Firm Cacacity bv DPS 21 DPS has agreed in the Centrol Area Agreement that it 22 will not schedule for sale and delivery, and under no 23 circumstances will be deemed to have received or purchased 24 capacity and/or associated energy, from an EA Resource, except 25 during such periods when an EA Resource is delivering capacity to 26 PG&E above the PPA Firm Capacity. (For example, DPS has agreed 27 that it can neither schedule deliveries nor purchase from an EA O(_/ 28 Resource which has a PPA Firm Capacity of 25 MW, unless such EA 13
l 1 Resource is delivering at least 25 MW to PG&E). 4 ! l 2 7. THIRD PARTY LIABILITY. I t 3 7.1 Nothing in this Agreement shall be construed to i l ! 4 create on behalf of either DPS or PG&E any duty to, any standard 5 of care with reference to, or any liability or obligation, 6 contractual, or otherwise, to any third party. 7 7.2 Nothing in this Agreement shall be construed to mean ,
'. \
8 that DPS has become a third party beneficiary of any PPA held by 9 an EA Resource. 10 7.3 Nothing in this Agreement shall be construed to mean 11 that PG&E has become a third party beneficiary of any PMA 12 executed by DPS. I 13 8. CAPTIONS. 14 8.1 All indexes, titles, subject headings, section ( 15 titles, and similar items are provided only for'.the purpose of
)
16 reference and convenience and are not intended to affect the ! meaning of the contents or scope of this Agreement. I 17 18 9. GOVERNING LAW. 19 9.1 This Agreement shall be interpreted, governed by, ) 20 and construed under the laws of the State of California. 21 10. NOTICES. 22 10.1 Any notice, request, demand, information, report, or 23 item otherwise required, authorized or provided for in this 24 Agreement shall be given in writing and shall be deemed properly 25 given if delivered personally or sent by United States Mail or by 26 a nationally recognized overnight or express mail service, 27 postage prepaid, to each of the persons specified below: ( 28 (1) PG&E: 14
t 1
.\ l l i 1 Vice President -
Power System 4, , Pacific Gas and Electric Company , gs 2 77 Beale Street - Mail Code B23C ' () 3 San Francisco, CA 94177 and 4
- Manager - Grid Customer Services ,
5 Pacific Gas and Electric Company l 77 Beale Street - Mail Code B23C I 6 San Francisco, CA 94177 ; 7 (2) DPS: l 8 Vice President and General Manager - Western Operations . 9 Destec Power Services, Inc. l 1676 N. California Blvd., Suite 400 ; 10 Walnut Creek, CA 94596 ' 1 11 and 12 President . Destec Power Services, Inc. 13 2500 CityWest Blvd., Suite 150 j Houston, TX 77042 ! 14 () 15 16 The parties may change the identity'.of the person (s) designated to receive notice on their respective behalf by l 17 providing the other party written notice specifying the change of i 18 the person (s) designated. . 19 10.2 Any notice of a routine character in connection with j 20 this Agreement shall be given in such a manner as the parties may 21 determine from time-to-time, unless otherwise provided in this 22 Agreement. 23 10.3 Time is of the essence for notices and.the provision 24 of information to be provided under this Agreement. If either 25 party fails to notify the other party in a timely fashion, that l 26 party waives any rights dependent upon such notice. 27 11. INTEGRATION CLAUSE. , /~% i '\_,) 28 11.1 This Agreement contains the entire agreement between l , 1 15
- . . - - - - - ~ . - .
l 1 I
, 1 I j PG&E and DPS concerning certain accounting and priority protocols 4,-
1 r 2 and requirements and procedures for a PPA OF Supplier : qualify-3 as an EA Resource and to sell Excess Power to DPS. Any oral 4 representations or modifications of this Agreement shall be of no 5 force or effect, except for any subsequent written modification 6 of this Agreement which may be entered into by both parties. Any_ 7 subsequent modification of this Agreement must be in writing and 8 signed by both parties. l l 9 12. REGULATORY CHANGES. : 1 l 10 12.1 The parties recognize that PGEE's cost recovery j 11 under and administration of the PPAs are subject to CPUC ' 12 regulation and that the Control Area Agreement is subject to FERC 13 regulation. These agencies may initiate or adopt regulatory ] 14 changes which could impact the PPAs or the Control Area i 15 Agreement. Any potential and/or actual impacts of such 16 regulatory changes shall be addressed, if at all, by the parties. 17 to those agreements and in the context of those agreements. 18 Nothing in this Agreement should be interpreted by PG&E, DPS 19 and/or any PPA QF Supplier as a waiver of DPS' or PG&E's 20 respective rights pursuant to any current or future CPUC or FERC 21 regulations, proceedings, rulings or orders regarding the PPAs or 22 the Control Area Agreement. 23 13. CONSTRUCTION OF AGREEMENT. i 24 13.1 Both parties have significantly contributed to the 25 drafting of this Agreement. However, ambiguities or 26 uncertainties in the wording of this Agreement shall not be 27 construed for or against either party, but shall be construed in 28 a manner that most accurately reflects the intent of the parties 16
I l l 1 when this Agreement was executed and is consistent with the a 2 nature of the rights and obligations of the parties with respect (N) to the matter being construed. 3 4 5 IN WITNESS WHEREOF, the parties have caused this Agreement 6 to be executed by their authorized representatives, and it is 7 binding as between the parties as of this date. 8 9 DESTEC POWER SERVICES, INC., PACIFIC GAS AND ELECTRIC COMPANY, a Delaware corporation a California corporation 10 11 er y av: hM'
- g. v 12 saut Walter G. Homan Nat: Robert J. Haywood 13 Tnu. Vice President and General Tna: Vice President - Power Manager - Western System 14 Operations
( 15 04n- November 29, 1994 D4n: November 29I, 1994 l 16 . 17 18 19 20 21 22 23 24 25 26 27 A \ l (V 28 17
. - - a A A 4=A-m --am - em - -- me a emse 4 . -=.=4--4e- n-+A- a.-# 4 , -w A e L. e-msm4 # - -e-a a 4
& l l
4 2 .a 4 1 l i i t l l l 4 1 4 0 i l l ENABLING AGREEMENT SC3EDULE A s E-2
4 I) \s-i l 199__ l Vice President - Power System Pacific Gas and Electric Company ' 77 Beale Street - Mail Code B23C San Francisco, California 94177 Director - Power Finance Pacific Gas and Electric Company . l
' f 77 Beale Street - Aail Code B13D .
San Francisco, California 94177 ; i i Re: Schedule A I,etter Agreement
Dear :
Concurrently with the execution of this Letter Agreement, [QF NAME AND PGLE QF LOG NUMBER] ("QF") is executing a Power Marketing Agreement ("PMA") with Destec Power Services, Inc. ("DPS"), a FERC-regulated power marketer. OF currently holds a power purchase agreement , (" PPA") which it, its predecessor (s) in interest, and/or l assignor executed with Pacific Gas and Electric Company ("PG&E") on or about , 19,__. [1DENr:FY COhDITION 1 OR 2, DEPEhTING CPON hErTRER PPA HAS FIRM CAPAC:rY OBLIGAr10N] Condition 1 -- Firm Capacity QF represents that the PPA provides that QF shall sell and deliver to PG&E Contract Capacity or Firm Capacity in the OF further represents amount of __kW (" PPA Firm Capacity"). that it can produce and deliver into the PG&E system up to __ kW of capacity and associated energy above this PPA Firm Capacity level and such incremental power constitutes
" Excess Power." In the PMA, QF has authorized DPS to purchase and resell such Excess Power to parties other than PG&E and has warranted to DPS that it has the contractual rights to deliver such Excess Power into the PG&E electric system.
.i l
l L _, 199_ f- Page 2 l l l ' Condition 2 -- No. Firm Capacity J l l QF represents that the PPA inposes no Firm Capacity delivery l obligation upon QF. QF further represents that it can ' produce and deliver into the PGEE system up to kW of capacity and associated energy and that all such capacity and associated energy which the QF can produce and deliver
- l into the PG&E system constitutes " Excess Power." In the i PMA, QF has authorized DPS to purchase.and resell such Excess Power to parties other than~PG&E and has warranted to DPS that it has the contractual rights to deliver suchi Excess Power into the PG&E electric system.
OF understands that the Enabling Agreement executed between PGLE and DPS on November 29, 1994 (" Enabling Agreement") conditions DPS' ability to purchase and resell QF'.s Excess Power to parties other than PG&E upon QF executing'-this Letter Agreement with PG&E and thereby modifying its. PPA in certain respects. QF further understands that DPS' ability to transmit and resell QF's Excess Power is conditioned in part on additional agreements between DPS and/or a DPS customer and PG&E. QF further understands that PG&E has O _ agreed to the form and content of this Letter Agreement and that a standard form of this Letter Agreement is attached to and incorporated into the Enabling Agreement as Schedule A. Accordingly, QF agrees upon this Letter Agreement becoming effective as provided for herein to have its PPA modified as follows: 1 1.1 With respect to any Excess Power cannitted to DPS as set forth in DPS' final schedule for the upcoming hour ("DPS Hourly Schedule") on a fixed schedule.or variable basis, PG&E's obligation to purchase such Excess Power for the upcoming. hour shall be extinguished upon the submission of the final schedule 20 minutes prior to the hour. OF acknowledges that: , (a) PG&E shall have no obligation, throughout that one hour period, to purchase the Excess i Power committed to DPS; and (b) PG&E shall be relieved, throughout that one
..nur period, from any other obligation in. posed by the Public Utility Regulatory Policies Act of 1978, with respect to the Excess Power committed to DPS.
199_ Page 3 1.2 For purposes of the PPA, PG&E shall calculate the amount of deliveries QF has made to PG&E for the month pursuant to the following formulas: All P in month M E (m)
=
{ SP=1 E gp) E <p3 - ALEQUATgp) M DESIG gp) = "ALLOCATIO'N"; If not, then (CONEQUAT go .M DESIG gp) . -
" CONTROLLING"; if not th)e,n G)
E g,3 = energy delivered by QF to PG&E for month "m"
, E gp) = energy delivered to PG&E for the Period DESIG gp) = designation of QF by DPS for the DPS em Hourly Schedule as " Allocation Basis Q Resource" or " Controlling Basis Resource". Neither will apply for Period in which the QF is not scheduled to supply power to the DPS Pool.
ALEQUATgp) = (G) - (the lesser of: DS or D) CONEQUATgp), = (The lesser of: G gr F) + (the lesser of: PS or D) Where: G = The QF's total energy generation over the Period F = The product of the QF's PPA Firm Capacity and length of the Period PS = The energy scheduled to be delivered by the QF (if designated by DPS for that DPS Hourly Schedule as a Controlling Basis QF) to PG&E as As-Available QF Power for the Period DS = The energy scheduled to be delivered by the QF to DPS (if designated by DPS for that DPS v
199_
,, Page 4
( Hourly Schedule as an Allocation Basis OF) for the Period D = G- (the lesser of: G QI F) Period = Equals a period of time of 30 minutes beginning or ending on the hour except during a curtailment. The Periods do not overlap i and their summation shall equal the total number of hours in the month. During periods of curtailment when the OF is* designated as " Allocation Basis OF", the following shall apply:
- 1) Each half-hour shall be divided into two i Periods; the portion prior to the curtailment becoming effective, and'the remainder of the half-hour.
- 2) For the first Period of the half-hour, the amount of energy purchased by PG&E will be r~w . derived by the above equations, provided, l
( ,) that the Period used in the calculations shall be the length of the Period prior to l the curtailment becoming effective.
- 3) For the second Period of the half-hour, the l amount of energy purchased by PG&E shall be I the lesser of the amount calculated using the l above equations (provided that the Period used in the calculations shall equal the time remaining in the half-hour as of the time the curtailment became effective) and the amount of energy calculated pursuant to Paragraph 4.
- 4) If the OF generation output (rate of delivery) at the time that the curtailment goes into effect, is less than the sum of the PPA Firm Capacity and the. power scheduled to the DPS Pool (rate of delivery), then "i",
otherwise "ii": i) the product of the length of the Period l within the half-hour in which the I curtailment was effective and the l difference between the average QF
- generation output (rate of delivery) that was forecasted for the hour and
(~)-! l l w
l
)
199_ Page 5 i l reported to PGEE through the DPS ; schedules and the power scheduled to the l DPS Pool (rate of delivery); or ii) the product of the length of the Period' in the half-hour in which the curtailment.was effective and the difference between the QF generation \ output (rate of delivery) at the time that the curtailment becane effective and the power scheduled to the DPS Pool (rate of delivery). 1.3 PG&E shall calculate the capacity and energy payments payable to QF pursuant to the PPA based on the - amount of deliveries calculated in accordance'with paragraph 1.2 above. OF further agrees that: 2.1 This Letter Agreement and the modifications to the PPA agreed to herein shall.become effective upon QF being approved as an EA Resource in accordance with the provisions O of Section 5 of the Enabling Agreement and after' thirty (30) calendar days following DPS submitting an executed and completed copy of this Letter Agreement to PG&E pursuant to Section 5.2 (e) of the Enabling Agreement. 2.2 Except as expressly specified herein, all other terns and conditions of the PPA remain fully effective and are not to be altered in any way. Notwithstanding the , above, the California Public Utilities Commission ("CPUC") l may initiate or adopt regulatory changes which could impact the PPA. Any potential and/or actual impacts of such regulatory changes shall be addressed, if at all, by QF and i PG&E in the context of the PPA. Nothing in this Letter J Agreement constitutes a waiver of PG&E's or QF's respective rights with respect to any current, proposed or future CPUC l regulations, rulings, proceedings or orders regarding or impacting the PPA. j 2.3. In administering the PPA, PGEE uses its good faith efforts to mail the purchased power statement and the corresponding. payment within the specified period set forth in the PPA. However, its good taith efforts l notwithstanding, at times PG&E's mailing of the purchased power statement and of the corresponding payment has been j; delayed beyond the specified period provided for in the. PPA (" Deferred Payment"). In such Deferred Payment situations, [ (_ i i
d f
' ' 199 -
g) Page 6 V PG&E has used its good faith efforts to compute the amount due and to pay QF as soon as practicable. PG&E has advised DPS, and through this Letter Agreement is advising QF, and l OF acknowledges, that upon selling Excess Power to DPS pursuant to the PMA, it is possible that Deferred Payments may result. PG&E and QF agree that in the event of a
- Deferred Payment, PGEE will continue to use its good faith efforts to compute the amount due and to pay QF as soon as ,
practicable and QF will cooperate with PGkE to the fullest extent possible. 2.4 This Letter Agreement and the modifications t'o the PPA agreed to herein shall terminate, be vacated, and cease being of any force or effect upon the earlier.of the termination of the Enabling Agreement or thirt'y (30) - i calendar days after DPS has provided PG&E notice in , accordance with Section 5.3 of the Enabling Agreement of its , intent to remove OF's PMA from EA Resource status. Very truly yours, l ] (v'); lOF) ' cc: Destec Power Services, Inc. 4 1 4 i
4 l Appendix F METERING REQUIREMENTS I I i i l l
l i 1 Appendix F s. l 2 METERING REQUIREMENTS f
\ l 3
4 This Appendix F describes the general metering requirements 5 applicable to DPS Suppliers and the DPS Load. 6 7 F.1 GENERATION RESOURCES DIRECTLY CONNECTED WITH 8 PGLE'S ELECTRIC SYSTEM 9 PG&E'S metering and telemetering policies regarding 10 requirements for non-utility power producers.are specifi.ed in l 11 PG&E's Power Producer's Interconnection Handbook and in other l l l 12 technical standards internal to PG&E. These standards are j 1 r l 13 periodically updated by PG&E; for any potential DPS Supplier not l 14 interconnected with PG&E as of the Effective Date, the () 15 16 appropriate standards applicable at the time the potential DPS Supplier requests to be interconnected shall apply. 17 18 F.2 GENERATION RESOURCES WITHIN THE PG&E CONTROL AREA BUT NOT 19 DIRECTLY CONNECTED WITH PGAE'S ELECTRIC SYSTEM 20 For purchases by DPS from a Third Party utility, the 21 metering requirements specified in the applicable Interconnection Agreement between PG&E and the Third Party utility apply. For 22 23 purchases by DPS from a non-utility resource, PG&E's metering 24 requirements apply unless otherwise agreed by PG&E. l 25 i 26 F.3 DPS CUSTOMERS WITHIN THE PG&E CONTROL AREA Any DPS Load served through the PG&E Electric System must be 1 27 O 28 metered by PG&E with revenue metering meeting PG&E's then-current F-1
1.- _ _ _ _ _ _ . . . _ _ _ . _ - _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ . . _ . _ _ _ . _ _ . __.- _ _ _ i l I standards, regardless of the maximum demand. If adequate l
*{
2 metering equipment is not installed to enable PG&E to monitor the l 3 DPS customer's power consumption and calculate load / generation l 4 imbalances in accordance with Section 4, either DPS or the DPS 5 customer shall be responsible for paying all Costs to install the 6 required revenue metering. 7 ' ! 8 F.4 RESOURCES AND LOADS OUTSIDE OF THE PG&E CONTROL AREA 9 Metering requirements of the host Control Area o1erator, 5 t 10 transmitting utility and/or Third Party utility with which the 11 DPS Load or generator directly connects shall apply. 12 : 1 l 13 i 14 ) 15 - 1 v 16 17 f 18
- i 19 20 21 22 4 l- 23 I l
24 l 25 i
- 26 27 I
- )/)
28 l i l' F-2 l t _ _ . _ _
. - . . s.= - - -. - + -- .. - - - - - 1 + .-u x..a s.~ a. .n..+ n . ..- ,. -- --a --.. -.- - ..--,._.. . . . .__-.-n.._
l 4 Appendix G SOUTH OF TESLA PRINCIPLES l I 1 _ . -~. .
4 1 2 PRINCIPLES FOR TESLA-MIDWAY TRANSMISSION SERVICE 3 4 whereas, certain California utilities and agencies signed the 5 xamorandum of Understanding - California-Oregon Transnission 6 Project dated December 19, 1984 ("MOU") which relates to the 7 development of a nov 500 kV AC transmission facility ("COTP") 1 l l g between the California-Oregon border and the Tesla substation: 9 , 10 whereas, sections 2.2 and 2.3 of the MOD contemplate that pacific
}} Gas and Electric Company ("PGEE") will provide firm bidirectional 32 transmission _ service between Tesla and' Midway substations under reasonable rates, terms and conditions up to specified amounts 13 to: the Cities of Anaheim, Azusa, Banning, Colton, Riverside, l If i
O is * ' = - (" =* r ct*i "> =i ("soG&E"), southern California Edison Company (" Edison") and
=1 *=i= c>
the 16 j 17 Transnission Agancy of Northern California ("TANC") (collectively Ig "MOU Participants"); 19 whereas, certain MOU Participants and certain other Designated 20 21 Participants have executed the " Revised Principles", and TANC and PGEE have determined that the Revised Principles as modified for 22 23 TANC pursuant to the terms and conditions herein will form the 24 basis for negotiating a definitive transmission service ag.eement 25 under the terms and conditions contemplated by the MOU: 26 27 Now, therefore, these principles are agreed to as of M 2 f M !t7, I 28 1989 by and between PGEE and TANC. l I
i ) 1 1.0 DEFINITIONS I 4 2 : !([]) 3 1.1 CPPA Board of Control - The Board of Control ! 4 established under the July 20, 1964 acalifornia Power j 5 Fool Agreement" among PGEE, Edison, and EDGEE.
- 6 a
) i
, 7 1.2 COTP Terminus - The southernmost point of change in',
l 8 ownership of facilities between PGEE and the CCTP i j 9 Participants, or as otherwise agreed by the parties. I I , i 11 1.s CPoe - The Public Utilities Commission of the State of 12 California or its regulatory successor. 13 14 1.4 Designated Participants - The parties receiving 15 transmission service in accordance with the movised ( ]) 16 Principles or like agreements, including TAxe under 17 these principles. 18 19 1.5 Entitlaments - The firm and non-firm transmission 20 service to be provided to each Designated 2] Participant. Por TANC, three hundred (300) megawatts 22 of firm, bidirectional transmission service provided by 23 PCsz according to the terms and conditions of these 24 principles unless increased in accordance with Section 25 s.s. 26 27 1.s PERC - The Pederal Energy Regulatory Commission or its 28 regulatory successor.
. . _ = . - .- - . - - - . - . - .. -. - . _ . - . - .
i i d 1.7 Initial Reinforcements - Those transmission system 8 l 1 1 ~ 2 reinforcements, ,other than south or :ssis 1 3 Reinforcaments, installed by PGEE according to the ) 4 terms and conditions of sections 4.1 and 5.2 to i 5 increase the Transmission capability over PGEE's system ! g between Tesla substation /COTP Terminus and Midway
- 7 substation to meet the transmission requirements or .the 1
8 Designated Participants. l i 9 i j 10 1.s xitigation Measures - Changes by PGEE in its operations
~
! in order to avoid or eliminate transmission sarvice 1) curtailments even though 1 these changes may be 12 i ! 13 uneconomic to PGEE, provided that PGEE in its sole i 14 judgment determines that it can reasonably do so and is 15 fully compensated for such actions as provided herein. [} shall include but not be limited to i 16 such actions i curtailment of third party loads if appropriate, 17 4 uneconomic dispatch of hydro and pumped 18 1
- 19 storage / generation resources, operation of higher cost I generation and purchase of power from others. such 20 i operation i 21 actions shall not include any change in the i 22 of Diablo Canyon Nuclear Power Plant.
I i 23 l 24 1.9 Pre-specified Kitigation - Mitigation Measures ! 25 consisting of switching PGEE's AC Intertie schedules to l 26 PGEE's DC Intertie schedules when DC line capacity is i and increasing or decreasing Morro Bay 27 available f, _,_ 4 2 i
- l l \ l l l 1 <
f i 4 generation to the extent available, for which PGEE l } is{ l l l 2 compensated as provided in section 5.4.
- 3 l 4 1.1o Priority Commitments - PGEE's obligations to meet load i
j 5 and load growth of its customers in northern ! california, and to transmit electricity, by reason of . 6 4 its status as a public utility and its existin.g l ') ! to, its g contracts, including but not limited i 9 interconnection contracts with utilities in northern 10 california and the california Power. Pool Agreement, the Pacific Intertie Agreement and the PGEE-DWR 1] comprehensive Agreement, and excluding transmission 12 . service provided by PGEE to Third Parties, and to ( 13 ! 14 Designated Participants under these principles, Revised l j O. 15 Principles, and like agreements. 16 17 1.11 Prudent Utility Practice - Those practices, nothods, and equipment, including provisions for contingencies 18 and reserves, as modified from time to time, that are 19 commonly used to operate electric power facilities (a) 20 safaly to serve a utility's customers 21 reliably and with due regard for the 22 dependably and economically, 23 state of the art in the electric power industry, (b) by own 24 utilities which have at least zoo NW of peax load, 100 Nw of generation and are or operate at least 25 members of the Wsec, and which are located either in 26 27 the retail service areas of PG&E and TANC Members or in O 28 the state of california, whichever represents the 4
i j l } better application of the considerations in subsection g (a) above. The practices, methods, and equipment-3 examined under this definition are not limited to those \ . 4 of PG&E. I i' 5 1.12 Revised Principles - The " Revised Principles for f 6 ; 7 Tesia-Midway Transmission service," executed by PasE 8 and certain mod Participants or incorporated as part of , l l 9 agreements with other parties for such service'., as they l I 10 may be modified. l 11 , 12 1.13 south of Tesla Reinforcements - A new Los Banos-Gates line and directly associated facilities, unless PasE, i 13 14 in accordance with Prudent Utility Practica, identifies anotner set of reinforcements which are as cost 15
- 16 effective, comparable in scope with, and serve the same purpose as the Los Banos-Gates line and directly i
- 17 !
associated facilities, which may be installed by PGEE 18 19 in accordance with section 4.2 to increase Transmission capability to meet the transmission requirements of the ! 20 $ 21 Designated Participants and PGEE as set forth under the l 1 the Revised Principles, these j 22 terms and conditions of 23 principles, and like agreements. 4 24 25 1.14 Tauc member - Any of the cities of Alameda, siggs, 26 cridley, sealdsburg, Lodi, Lompoc, Palo Alto, medding, clara, and Uriah; the sacramento 27 Roseville, santa the Modesto Irrigation Municipal Utility District: 28 l
) a
- } District; the Turlock Irrigation District; or the
i () 2 Plumas-Biarra Rural Electric Cooperative, Inc.; 3 provided that such entity has not relinguished or 1 4 assigned its rights and interests in TANC's entitlament 5 in the COTP or, if the COTP is not constructed, has not j 6 relinguished or assigned its rights and interests in i 7 TANC's Entitlement under these principles or .the j g definitive successor transmission service agreement. 9 10 1.15ThirdParty-Anentity,totheartentthatitps 11 neither receiving services as a Designated Participant 12 BCr, served under Priority Commitments or PG&E8s 13 entitlements referred to in section s.2. Nothing in 14 these principles shall creats' any erpectation or () 15 obligation of PGEE to provide any service to a Third , i 16 Party. 17 18 1.16 Transmission capability - The transfer ability, 19 expressed in megawatts, of PGsE's transmission 20 facilities to transmit electric energy between Eidway 21 Substation and Tesla substation /COTP Terminus, which is 22 determined by PG&E in its sole judgment, consistant 23 with Prudent Utility Practice, to be the maximum power 24 transfer ability of the transmission facilities under 25 operating conditions aristing at the time of 26 determination. 27 () 28 6-
i i s
=
a i i 1 2.O GENEkAL TERMS g i
- 3 2.1 Effective Date of Principles - These principles shall i
j 4 become effective upon execution by PGEE and TANC and 5 shall rammin in effect until a definitive successor 6 transmission service agreament is executed by PGEE and f ! TANC. PGEE and TANC shall use best efforts to complet,e 7 i ! a definitive successor transmission service agreement 8 - by september 1, 1989. PGEE shall use good faith i g 1 efforts to file such agreament with rzac within . sixty 10 days after execution. TANC and PGEE . agree that such 11 transmission agreement
~
definitive successor service 1 12 and implament section 2.3 of the MOU 13 shall reflect i the I 14 fully, provided that any rights and obligations of l l O 15 parties under section 2.3 of the mod shall not be ' satisfied fully until the south of Tesla Reinforcements 16
- 17 are ecmpleted or such definitive successor transmission i
) service agreement terminates in accordance with section 18 s of these principles.
- 19 I 20 i 21 2.2 Provision of service - Beginning January 1, 1990, PG1E service I
22 shall provide firm bidirectional transmission amount of TANC's Entitlement betwees Midway 23 in the ^ 24 substation and points of receipt and delivery set forth to the definitive successor 25 in section 2.4 pursuant and 4 26 transmission service agreement embodying the terms subject to the conditions of these principles, j 27 28 conditions in section 2.s. a
4 4 ! 1 2.3 Effect on Other Agreements - PGEE and TANC agree that i 2 the present interconnection agreements and future
- 3 similar agreements between PGEE And TANC Members and 4 between PGEE and the Marthern California Power Agency
- 5 vill be amended or will provide for receipt and 6 delivery of power transmitted hereunder at the backbone
) 7 level at no additional cost to TANC xambers cons i s't.ent 8 with Section 5.1. 9 l 10 24 Points of neceipt and Delivery - The points of receipt - y l 11 and delivery by PGEE shall be: 12 l 13 241 xidwa'y substation to each TANC xamber, to j 14 provide a complete transmission path from 15 xidway substation over system interconneet and f l ' 16 backbone subfunction transmission facilities } t 17 of PGEE's electric systan; provided that for a { 18 given TANC Member, transmission service 19 between PGEE8s backbone facilities and that 20 TANC Member shall be pursuant to an amendment j ! 21 to the existing agreement between PGEE and l 22 that TANC Member, if necessary, or a nov 23 agreement if that TANC Member does not have am 24 existing agreement with PGEE. Por purposes of 25 Tesia-xidway transmission service for TANC and 26 TANC Members related to Sections 2.2 and 2.3 27 of the Moc, prior to January 1, itse, or such 28 earlier date- as may be applies.ble in t
l - i i I
} accordance with Section 5.6, if PGEE changes 4 g the definition of backbone facilities, PGEE will only charge TAxe whatever its charges
! 3 4 would have been with the definition of l 4 backbone facilities in use as of January 1, l 5
- any changes in i 6 lost. PGEE also agrees that j 7 its current definition of backbone facilities t
8 prior to January 1, itss, or such earlier date as may be applicable in accordance with l 9 6 section s.s, will not be used to require any 10 TANC Member to obtain transmission service l 1) i between PGEEs s backbone facilities and that 12 l 13 TAxe member which it would not have had to obtain without the change in definition of 14 () 15 backbone facilities. 16 2.4.2 Each TANC Member to Midway Substation, to 17 18 provide a complete transmission path from each , TAsc Member's electric system over system 19 interconnect and backbone subrunction 20 transmission facilities 'o f PG&E8s electric 21 22 system; provided that for a given TANC xamber, 23 transmission service between that TAxe xa=her backbone facilities shall be 24 and PGEE's to an amendment to the aristing 25 pursuant agreement between PGEE and that TANC Member, 26 if necessary, or a new agreament if that TANC 27 not have an aristing agreasant Member does ( 28
t
} with PGEE. Por purposes of Tesla-Midway g transmission service for TANC and TANC Me=bers 3 related to sections 2.2 and 2.s of the xco, 4 prior to January 1, 1999, or such earlier date 5 as may be applicable in accordance with 6 Section s.s, if PGEE changes the definition of 7 backbone facilities, PGEE will only charge 8 TANC whatever its charges would have been with g the definition of backbone facilities in use 10 as of January 1, 19st. PGEE also agrees that 11 any changes in its current definition of 12 backbone f acilities prior to January 1, 1999, 13 or such earlier date as may be applicable in 14 accordance with section 5.s, will not be used 15 to require any TANC Member to obtain 16 transmission service between PG&E's backbone 1
17 facilities and that TANC Member which it would l 18 not have had to obtain without the change in 19 definition of backbone facilities. 20 21 2.4.3 Midway substation to the COTP Terminus / Tesla 22 Substation, only for delivery onto the COTP. 23 It is TANC's intent to transmit power 24 delivered onto the COTP to various points, 25 including, but not limited to Tracy substation, Olinda substation, and xalin 26 Substation utilizing TANC's CCTP espacity. 27 28 Since TANC's rights to use its CCTP i I i 4
} entitlement, like the rights of all 'COTPj 2 Participants, will be defined in the COTP 3 Participation Agreement and perhaps other 1
j ( project agreements, these principles do not l 5 address the issue of rights to use the COTP. i 6 ! 7 2.4.4 COTP Terminus / Tesla substation to Midway , l l g substation only for receipt from the CCTP. It i { g is TMC's intent to transmit power received 10 from various points on the .COTP including, but not limited to Malin substation, Clinda l 11 12 , substation, and Tracy substation to Midway 13 substation utilising TMC's CCTP capacity. ! If since TANC's rights to use its COTP O 25 *i 1 - 1**- - 1 *- t 11 ===> l 16 Participants, will be defined in the COTP Participation Agreement and perhaps other l 17 i j 18 project agressants, these principles do not i 19 address the issue of rights to use the COTP. l 20 1 21 2 . !i TANC Members, acting through TANC, and PGEE agree to i
- 3. 22 use best efforts to amend or enter into the agreements
! 23 described in sections 2.3, 2.4.1 and 2.4.2 by september i 24 1, isso, and not to condition such amendments or agreements on the inclusion of any other terms and l 25 ! 26 conditions which are unrelated to or inconsistent with i 27 these Principles. !O j 2. p --- w. -g--.. -- 9
. ! l i i I 4 j
1 2.s Regulatory Approvals - Implamentation of these l () 2 principles and the definitive successor transmission 3 service agreement is subject to and conditioned upon i
)
- 4 PGEE obtaining in a form and manner satisf actory to it, 5 which determination shall be made in good faith and 6 shall not be arbitrary or capricious, all governmental l t
j 7 approvals, including rate filings, permits and i l 8 certificates required to carry out these principles and 9
- 9 such transmission service agreement. These pIinciples l 10 and the definitive successor transmission service I
! 11 agreement will be reexamined and reconsidered by PGsE t ] 12 and TANc to the extent either is found by any court or i 13 regulatory agency or body having conpetent ] 14 jurisdiction, to be unlawful, unjust, unreasonable, () 15 imprudent or otherwise not in the public interest. i 16 mothing in this section 2.s shall be construed to i ) 17 conflict with the time period specified in section 6.3 4 1 18 during which transmission service hereundar is deemed ! 19 firm following PG&E8s inability to install South of 20 Tesla mainforcaments. l i 21 I 22 2.7 These principles represent a compromise between PG&E 23 and TAxe concerning the meaning and impiamentation of 5 l 24 section 2.3 of the MOU. The parties agree that these 25 principles establish no precedent with regard to any 26 other entity or agreament, or to the massing and i the MOU if the 1 27 implamentation of section 2.3 'of 28 l; i
i , i - l 1 l 4 f I definitive successor transmission service agreement. l () 2 does not become effective. l 3 . I 4 3.O CONTINUITY OF SERVICE i j 5 { 6 3.1 General - PGEE shall maintain continuity of l 7 transmission service for Tame subject to PGEE's use of i j 8 Transmission capability between Midway ~ substation and j 9 the points of receipt and delivery set forth in section 10 2.4 and transfer capability between. scar and xdison's 11 system (including PG&Eis share of the Kidway-Vincent $3 i 12 line) for its Priority commitments, provided that PGEE i
- l. 13 may as it determines necessary in its sole judgment t
j 14 enrtail service to TANC pursuant to this section 3 to () 15 maintain reliability continuity and of stability service and to to avoid loads, system or remedy 16 l conditions which may jeopardize its electric system or [ 17 18 service thereon, or as is otherwise required for 19 maintenance or Prudent Utility Practice. Any 20 curtailment pursuant to this section 3.1 shall be made J I 21 in accordance with the priorities set forth in section 22 3.2, except as modified below. It is recognized that j 23 under system jeopardy conditions PGEE's priority will ! 24 be to maintain the integrity of its electric system and i 25 there may be instances where it is not possible to lt j 26 curtail strictly in accordance with the priorities set section 3.2. In such cases, PGst's system 27 forth in l() 28 l 1 l l 1
~
s ] j 1 operators shall use good faith efforts to curtail * ! l 2 consistent with the priorities set forth in section!
! 3 2-3 i 4 i
5 3.1.1 In conjunction with maintaining continuity of I 6 service, PGEE shall coordinate with TAmc its s 7 schedules for planned outages which would l, 8 affect service to TANC. j 9 l 10 3.1.2 Prior to completion of the south of Tesla i 1] Reinforcements, PGEE shall implement' Pre-specified Mitigation.to the extent available 12 13 up to a total of 200 MW south-to-north and 706 MW north-to-south for TANC and other 14 Designated Participants under the terms and 15 conditions of these principles. Subsequent to 16 the completion of the south of Tesla 17 Reinforcements, the charges in Section 5.4 18 19 shall cease, and service to TAxe shall not be curtailed if eurtailments can be mitigated or ; 20 21 eliminated by PG&E implementing Mitigation 22 xeasures for which PGEE shall bear the costs. 23 24 3.2 Curtailment Priorities - In the event that 25 transmission line loading, based on daily preschedules, determination by PGEE 26 hourly schedules, or real time 27 dispatchers, is in excess of the amount of Transmission excess loading may be curtailed by 28 Capability, such i 4 } } PG&E under the terms and conditions of these principles 2 for TANO and like agreements for Designated l 3 Participants and Third Parties in the following
- 4 sequence
i
- 5 l 6 21 won-firm and interruptible transmission
! 7 service commitments except as otherwise i { 8 specified below. l 9 - i l 10 3.2.2 Any firm transmission serv. ice for or on behalf l 11 of Third Parties who have not contributed to 4 i j 12 the Initial Reinforcements or the south of l l 4 13 Tesla mainforcements. i 14 O Is 2.= > ar e er >= in e f f ! 16 reserved Transmission capability and Priority i 17 commitments which also exceeds the amount of i l 18 additional Transmission capability PGER has i i 19 obtained through its contribution to the south 1 l 20 of Tesla Reinforcemants in accordance with 21 Section 5.3. ! 22 23 3.2.4 Non-fira Entitlements of the Designated 24 Participants and any interruptible 25 transmission service for or on behalf of Third i j 26 Parties who have contributed to the Initial j 27 mainforcements. iO 28
-1s-l i
i 4
. ._~
I i 4 4 l 1 3.2.5 Any use by PGEE of its 500 MW of reserved 2 Transmission capability, the fira Entitlements i 3 of the Designated Participants, and any fira l 4 transmission service for or on behalf of Third ! 5 PErti'8 'han such entities (i) have ) t ! 6 contributed to the Initial Reinforcements, i 7 (ii) have not contributed to south of Tesla g Reinforcements and (iii) do not request , } ! 9 xitigation Measures. ! 10 l 3.2.6 The fira Entitlements of Designated. l 1
}}
12 Participants and any' firm transmission service for or on beh41f of Third Parties when such ) 13 entities (i) have contributed to Initial f 14 Reinforcements, (ii) have not; contributed to 15 the south of Tesla Reinforcements and (iii) dj l 16 17 request Mitigation Measures or have agreed to 18 Pre-specified Mitigation according to sections l 3.1.2 and 5.4; and, prior to completion of the 19 south of Tesla Reinforcements, any use by PGEE 20 21 of its 500 MW of reserved Transmission 22 capability for which it implsments Mitigation 23 xeasures. 24 25 3.2.7 Transmission service for Designated Participants and Third Parties who have 26 Reinforcements, 27 contributed to south of Tesla any use by PGEE in ' excess of its 500 MW of 28 I i 1 '_ sa 1 reserved Transmission capability for which it'. j 2 has contributed to south of I Tesla' ! 3 Reinforcaments, and any use by PGEE of its 500 4 MW of reserved Transmission capability. 4 5 6 3.2.8 Priority Commitments 4
- 7 1 -
l i 8 Curtailments in accordance with any of the foregoing j 9 categories shall be pro-rata among all entitie's in that 10 category based on Entitlements, contract rights of ; 4 ] 11 Third Parties, and the uses reserved to PGEE in this 4 12 Section 3.2. l
- 13 I l
l 14 3.3 PG&E shall give TANC reasonable advance notice prior to d j (} 15 16 curtailing transmission service pursuant to section 3.1 or 3.2. Provisions for determination of transmission 17 line loading in excess of Transmission capability shall I l 18 be included in the definitive successor transmission i 4 19 service agreement. 20 21 4.0 REINFORCEMENTS 22 23 4.1 Initial Reinforcements - PG&B shall promptly complete 24 its study and propose a plan of service pursuant to the 25 terms and conditions of these principles for Initial 26 Reinforcaments to its transmission system between Tesla 27 and Kidway substations. PGEE will meet with TANC and () 28 the other Designated Participants in order to discuss
l any comments # 1 they may have on the proposed plan of l 2 service and thereafter, giving due consideration tot 3 their comments, adopt a plan of, service and install 4 reinforcements necessary to implement it. TANC shall 5 accept its share of the cost responsibility for these I 6 Initial Reinforcements in accordance with Baction 5.2.' 7 j 8 4.2 South of Tesla Reinforcements - PGEE and TANC recognize 9 that reinforcements to PGEE8s system may be- required , 10 to maintain the adequacy of PGEE8s transmission service 11 for TANC and other Designated Participants. When PCEE l 12 determines that South of Tesla Reinforcements are 13 necessary, PGEE shall give notice to the Designated 14 Participants at least six years in advance of the time 15 when such reinforcaments are to be completed. Once 16 such determination is made, PGEE shall study and 17 propose a plan of service for the south of Tesla 18 Reinforcements. PGEE shall meet with the Designated i 19 Participants in order to discuss any comments they may have on the proposed plan of service and thereafter, 20 1 giving due consideration to their comments, adopt a ! 21 22 plan of service and install facilities and equipment 23 necessary to implement it. TANC shall accept its share i of the cost responsibility for South of Tesla
! 24 Reinforcements in accordance with section s.3, unless 25 ; 26 (i) it elects not to contribute its share of the costs l
27 in accordance with section s.2.1 or (ii) the definitive 28 successor transmission service agreement terminates in I.
i 4 ' i 1 accordance with section s.2.2, 8.2.3 or s.2.4 before t 2 TANC has made its election in accordance with section [ i 3 a.2.1 or contributed to the south of Tesla i f Reinforcements. TANC shall not be required to 5 contribute to the cost of the south of Tesla } 6 Reinforcaments prior to the time that the CPPA Board of } 7 Control, as presently constituted, deter =ines .by l 8 affirmative vote of at least PGEE and Edison that such 9 reinforcements are necessary. In the event that PGEE
- 10 has already initiated tha south of Tesla Reinfore. aments t
l 11 when such determination is made by the CPPA Board of l - 12 Control, the timing of TANC's' cost contribution shall
- 13 be the same as if PG&z had initiated such i
! 14 reinforcements after such determination was made by the 15 CPPA Board of Control.
- 16 17 4.3 Beneficial use - To the extent TANC can demonstrate I
- 18 that PGEE or a Third Party is mahing beneficial use of 19 the additional Transmission capability created by the l
20 Initial Reinforcements, or that a Third Party is making f i 21 beneficial use of the Transmission capability created i 22 by the south of Tesla Reinforcements, and has not 23 contributed to the cost of such reinforcements, PGEE
- 1 3
24 or, if after PG&E's use of best efforts that Third 25 Party agrees, that Third Party shall contribute a just 26 and reasonable share of the costs of such j 27 reinforcements. To the extent TANC can demonstrate 1 28 that PGEE is making beneficial use of the additional j (} _1,_
l_______ I I i 1 Transmission Capability created by the South of Tesla.4 i 2 Reinforcements beyond the 300 MW or more of additional i Os Transmission capability PGEE has paid for pursuant to j 3 4 section 5.3, PGEE shall contribute a just and j 5 reasonable share of the cost of the South of Tesla ! 6 Reinforcements in addition to the contribution already i l made pursuant to section s.3. If agreament on such l 7 cost sharing cannot be reached, then the matter s' hall 8 [. g be submitted to arbitration. Bene'icial use,shall not include PGEE's use "for its 500 MW of reserved 10 l 1) Transmission capability or for Prio'rity Commitments. ! 12 13 4.4 ownership - PGEE shall own, operate and maintain all t reinforcaments to its electric system in connection i
- 14 t
i (} 15 16 with these principles. i i 17 4.5 Diligence - After the South of Tesla Reinforcements are 6' 18 determined by the CPPA Board of control to be necessary { with Section 4.2, PGEE shall use due I 19 in accordance ! 20 diligence to install such reinforcaments. In the event required that PGEE is unable to obtain any approvals i !, 2] ,i 22 for PGEE to install the South of Tesla Reinforcements, i J 23 PG&E shall make such proposals as are, in its judgment, alternatives to installing such 24 reasonable itself, including giving due 25 reinforcaments permitting TANC to install such 26 consideration to
- 27 reinforcaments.
28 lC) ~20-4
l i
'd 1 4.6 TANC Alternative Project - In the event that TAN i (f 2 terminates the successor definitive transmission >
- 3 service agreement pursuant to section s.2.1 because t
4 TANC elects to construct facilities in lieu of 1 5 contributing to the cost of south of Tesla l ! 6 Reinforcements, TANc shall offer PGEE the opportunity l 7 for joint ownership of a substantial portion of 'the ) 1 l 8 amount of transmission capability from such facilities 9 in excess of TANes s needs provided that (i) regulatory i . l 10 or other approvals required for PGEE!s participation in 6 l 1] TANC's facilities do not result' in a delay 'in i i 12 construction unsatisfactory to TANc, (ii) such 13 participation by PGsE does not impair TANc's ability to 14 finance such facilities or increase TANC's financing ( ]) 15 costs, and (iii) such . opportunity does- not preclude 16 TANc from giving other utilities and agencies the opp-17 artunity to participate in ownership of such 18 facilities. In the event that PGEE receives permission 19 from the CPUC to participate once construction of such 20 facilities has begun, TANc shall afford PG&E the 21 opportunity to participate to the extent that there is 22 rammining capacity in azeess of TANCe s and other 23 Participants' needs, provided that such participation 24 by PGaz does not adversely impact TANe's existing, 25 pending, or future financing for such facilities. 26 27 4.7 Refund of Contribution to Reinforcaments - In the event () 28
.-- - _ r _ - _ -_ . _ _ _- _ _ _ _ _ _ _ .
_ - - . - _ - _. _ . _ _ _ . . . . - .-. - - . _ . . . _ - . - . ~ - - . - _ . _ . . - . - i < 1 4
- I that the successor definitive transmission se rvice
() 2 agreement terminates pursuant to section a after TAN 0' 3 has contributed to the cost of the south of Tesle ] j 4 Reinforcaments, PG&E shall refund to TANC its 1 5 contribution as follows: ! 6 l 7 4.7.1 TANC shall receive no refund until ten l ) 8 years after the commercial operation date of 9 the south of Tesla Reinforcements,'except to l 10 the artent that TANc demonstrates beneficial 1] use of the south of Tesla Reinforcaments by 12 PGEE or a Third P' arty in accordance with i 13 section 4.s. j 14 l() 15 4.7.2 After the first ten years of commercial ~ 16 operation, or to the artent the damonstration J l 17 is made in accordance with sections 4.3 and ] 18 4.7.1, PGEE shall pay TANC that portion of 19 TAnc's contribution toward the cost of south 20 of Tesla Reinforcements equal to the booh 21 value of TANC's contribution, not including ! 22 any adjustment for applicable taxes, I l 23 depreciated using a useful life of thirty i 24 years. 4 4 25 i
; 26 s.o RATES Axo exARGEs 1
27 Transmission service Charge - For transmission service ( 28 5.1
= .~- . .-- . . . - . - _ - . . - - - - -. _ . - - - . --.-. __. -_-.
i 1 4 I pursuant to Section 2.2, TANC shall pay PG&r's current l 2 rates on file with the FERC. The co=bined rates i 3 (system interconnect and backbone) for each of the 1 j 4 years 1990 and 1991 shall be $0.74 per kW-month applied 4 5 to TANC's Entitlement. L'Ecept as provided in Section 4 6 5.1.1, rates for subsequent periods shall be as
- 7 autually agreed or as may be unilaterally filed by Pasz g with the FERC under Section 205 of the Federal Power
! 9 Act. TANC shall have the right to intervene, . protest, t 10 or otherwise oppose any such unilateral filing. In addition, after 1991 TANc retains all rights 'it may 11 ! 12 have under Section 206 of tha' Federal Power Act. Firn I i 13 transmission service vill be billed on a contract 14 demand, take-or-pay basis for TANc's Entitlement. The parties acknowledge that PG&E and individual TANC 15 ( ]) separate agreements which I 16 xambers have or may have 4 i backbone, and system interconnect 17 provide for area, transmission charges. PG&E agrees , to provide I 4 18 bidirectional transmission service between Midway 19 Substation and the points of receipt and delivery as l 20 l set forth in Section 2.4 for the charges under these ) 21 22 principles and not to impose additional backbone or I . 23 system interconnect charges in connectiva with service i under these principles and under such separate i 24 25 agreements. charges for area transmission service, t
- 26 where applicable, will be provided in accordance with 27 such separate agreements between PGEE and TANC Mambers.
() 28 l e
4 j 1 5.1.1 Except as provided in section 5.5, the rates 1 2 applicable from January 1, 1992 through
- 3 December si, Issa shall be Pa&z's bachbone and
) l- 4 system interconnect charges reflecting i 5 system-average cost based functionalized l l 6 rates, changed based only on changes in Pasz's i j 7 costs. 8 t 9 5.2 Initial Reinforcament charge - TANC shall pay,'as } l 10 further defined in the definitive successor
- 11 transmission service agreement, its proportionate ' share l 12 of the costs of the Initial Reinforcaments, adjusted' 2
! 13 for applicable taxes, and associated annual ownership' 4 14 charges. Such costs shall include the study costs, not l exceed $2.s million, associated. with such l (]) 15 to i 16 reinfercaments and the Los Banos-Gates Project. Such i 17 costs for Initial Reinforcaments are estimated to be 18 approximately $7.2 million before taxes. This
- 19 estimate is based on transmission studies and subject 20 to revision following completion of such 21 reinforcaments. Such total costs shall be shared 1 22 proportionately among the Designated Participants and 3
23 Third Parties based an total subscriptions for such
- 24 i 25 1
1 26 This estimate is subject to modification for, { among other things, the installation of additional 2,4 shunt capacitors at Tesla substation to the extent these costs are not covered under separate projects. k 1
I 4 1 service. Designated Participants and Third Parties who 2 contribute to the cost of the Initial Reinforcements 3 shall receive appropriate reimbursement subsequent to 4 similar contributions made at a later date by other 5 Designated Participants or Third Parties. The annual 6 ownership charge for the Initial Reinforcements is 7 estimated to be $385,400 in 1990 allocated j I 8 proportionately to all contributing Designated 9 Participants and Third Parties. l 10 l 11 s.3 south of Tesla Reinforcement charge - The parties 12 anticipate that the south of Tesla Reinforcements v'111 13 increase the Transmission capability by approximately 14 1100 to 1200 MW. subject to section 8, TANC, PG&E and, 15 subject to separate agreement with PGEE, Edison, each 16 agree to pay for a share of the cost of the south of 17 Tesla Reinforcements, adjusted as to TANC and Edison 18 for applicable taxes, and associated annual ownership 19 charges, as follows: TANC - 300 MW, PG&E - 300 MW, 20 Edison - 281 MW. such shares shall be divided by the 21 total shares allocated to TANC, PGEE, Edison, other 22 Designated Participants and Third Parties (e.g., for 23 Tame, 200/ total allocation), whether or not the total 24 shares allocated to TANC, PGEE, Edison, other 25 Designated Participants and Third Parties exceed the 26 increased Transmission capability resulting from the 1 27 south of Tesla Reinforcements. To the extent that any 28 portion of the cost of such reinforcements is not
- - . - . - - - - . . . . - . . . - . - . - . - . - - . - . . - . ~
T j 1 allocated to other Designated Participants or Third, () 2 Parties in accordance with Section 5.3.3, TANC, PGEE 3 and Edison shall each pay its proportionate share of f such amount and receive a corresponding increase in 5 Entitlament or transmission use. TANC, PG&E, and l 6 Edison also shall each pay its proportionate share of j 7 PGEE8s associated annual ownership charges for 'the . ) 8 south of Tesla Reinforcements. PG&E 'shall amend the i j g October 12, 1987 Revised Principles with Edison to i - reflect the provisions of this section 5.3. ) 10 1 j 11 1 ] 12 5.3.1 In the event that Edison is relieved of its } ! 13 obligation to contribute to the cost of the s l' 14 South of Tesla Reinforcements pursuant to l ( ]) 15 separate agreement with PG&E, PG&E and TANC l 16 shall remain obligated to pay for 3co ww j 17 shares each; however, PG&E .shall not be 1 l 18 obligated to install the South of Tesla i j 19 Reinforcaments until and unless Edison's l 20 previous share of such reinforcements is i l 21 assumed by PG&E, TANC, other Designated ! 22 Participants or Third Parties. i ! 23 l 24 5.3.2 In the event that PG&E's participation in the 25 cOTP terminates, PG&E shall be relieved of its 26 obligation to contribute to the cost of the 27 South of Tesla Reinforcaments. In such event, () 28 TANC and, subject to separate agreement with
~26~
. t 4 1
} PGEE, Edison, shall remain obligated to pay 2 for 300 MW and 281 MW shares, respectively; i
3 however, PGEE shall not be obligated to l 4 install the south of Tesla Reinforcements 5 until and unless PGEE's previous share of the 6 cost of such reinforcements is assumed by 7 Edison, TANC, other Designated Participants'or 3 Third Parties. 9 10 s.3.3 Unless ordered'otherwise by:.a court or: 11 regulatory agency of competent jurisdiction, 12 PGEE agrees to condition any agreements for 13 new firm transmission service longer than 10 14 years, including contract renewals, between 15 Tesla substation /ccTP Terminus and Midway 16 substation to Designated Partipipants or Third 17 Parties on agreement to pay a corresponding 18 share of the costs of the Initial 19 Reinforcements and the south of Tesla 20 Reinforcements. Pirm transmissian service 21 provided by PGEE to Third Parties for 10 years i 22 or less between Tesla substation /ceTP Terminus 23 and midway substation may be subject to j 24 payment of an appropriate share of the costs 25 of such reinforcements in accordance with 26 section 4.3. Transmission service provided by 27 PGEE which does not include a requirement to 28 pay for Initial Reinforcements and south of
-27~
i ! } Tesla Reinforcements shall not be considered 8 f g by the CPPA Board of Control in determining
- 3 the need fr the south of Tesla 4 Reinforcements. PG&E and TANC also agree to
! 5 use their best efforts to obtain agreement by 1 ! 6 D*81958t*d Participants and Third Parties to 7 whom PGEE has ciready committed, after j g execution of the NOU, to provide fira ) g Tesla-Midway transmission service to pay a ! corresponding share of the costs of the 10 - i Initial Reinforcements and,'for service'beyond II l 1999, the south of Tesla Reinforcements. 12 ! 13 ? j 14 5.4 Pre-specified Mitigation Charge - In accordance with 15 section 3.1.2, TANC shall pay PGEE as full compensation 16 for Pre-specified Mitigation as follows: 17 Ig 5.4.1 January 1, 1990 through December 31, 1993 - Ig $0.10/kW-months - 20 21 5.4.2 January 1, 1994 through December 31, 1998 - 22 $0.20/kW-month; 23 24 5.4.3 January 1, 1999 through December 31, 2004 - 25 So 30/xW-month. 26 27 O 28
i 4 i 1 Except as provided in section s.6, the foregoing rates 2 shall be applied to TANC8s Entitlement and shall not be i l 3 subject to change before January 1, zoos. ! 4 i ) 5 s.s Losses - PGEE shall be compensated for transnission
- 6 losses by an appropriate reduction to TAxcis power i
7 deliveries based on functionalized system-average loss 8 factors or as otherwise mutually agreed. The parties l 9 acknowledge that PGEE and individual TANC Members have 10 or may have separate agreements whickhprovide for. area, 1] backbone, and system interconnect transmission losses. 12 PGEE agrees to provide bidirectional transmission. 13 servies between Midway substation and the points of 14 receipt and delivery as set forth in section 2.4 with 15 losses as set forth in these principles and not to 16 impose additional backbone or system interconneet 17 losses in connection with service under these 18 principles under such separate agreements. Losses for 19 area transmission service, where applicable, will be 20 assessed in accordance with such separate agreenents 21 between PGEE and TANC Members. The loss factors for 22 the system interconnect and backbone subfunctions are 23 currently o.999534 and o.ssis47., respectively. The 24 combined loss factor is o.ssloss6 (e.g., deliveries 25 over the system interconnect and backbone are reduced 26 to an amount equal to the amount of power scheduled at 27 the contract point of origin within PGEE's system 28 multiplied by 0.ssloss6). PGEE may revise these loss
-2s-
l j i 4 l 1 factors from time to time, as appropriate, and aball 4 I submit an analysis to TANC supporting those ( 2 revisions.
! 3 If the parties agree on those revisions, they shall 4
! 4 sign a separate letter agreement accepting those 1 i 5 revisions which shall become effective immediately ! 6 thereafter. If the parties cannot agree, PGEZ shall i 7 have the right to file a revision with the FERC and ) 8 such revision shall become effective on the date it is i 9 accepted for filing by FERC. 4 10 1] s.6 Early Termination of Rates - In the event that the l 1 12 COTP is terminated or there is' not substantial progress l 3 ! 13 towards its completion by January 1, 1sts, or PG&E's or 14 TANC's participation in the CCTP terminates, Sections l ()
~
15 s.1.1 and s.4.3 shall no longer be in effect. l 16 1 1 1" 6.0 FIRMNESS OF TRANSMISSION SERVICE PRIOR TO SOUTE OF TEELA 1 . 18 REINFORCEMZNTS ! 19 20 6.1 General - Transmission service provided hereunder shall be deemed firm by PGEE and, subject to separate 21 J 22 agreement with TANC, by Edison, for purposes of imports i 23 to or arports from their respective control areas. 4 24 [ 25 6.2 Replacement Power - Replacement power pursuant to these i i 26 principles is provided as an accommodation and in order i terms and to reach agreement on the package of j - 27 conditions for Tesla-Midway transmission service in 28 f() ! i a a
,m
1
'I i
1 these principles. In accordance with section 2.7, by 8 2 agreeing to these principles the parties do not intend- ! 3 that anything in these principles requires, or may be l' 4 used as a basis for requiring, that any replacement ! 5 Power or similar service be made available or supplied 6 (1) to any Tuc Member other than under the definitive 7 successor transmission service agreement, or (2) to.any i 8 other entity. The parties acknowledge that PGEE is i
! 9 able to provide replacement power under the '. terms in 1
10 these principles only because': (1) this service is 1] expected to be needed only occasion ~ ally in oi'f-peak 12 Periods and infrequently, if at all, in on-peak periods 13 based on Tuc 's anticipated use of south-to-north 14 transmission service; (2) this service will be provided 15 only to Tuc Members and only in accordance with the 16 conditions and limitations of these principles; (3) 17 this service is to be provided in connection with curtailment of Tesla-Midway transmission service and 18 19 not for unavailability of any power resource or other 20 transmission service; and (4) PGEE will not be required to add or purchase power to its system, or reduce the 21 integrity and reliability of service to Priority 22 23 commitments in order to supply replacement power to 24 Tue. 25 service shall be deemed 26 south-to-north transmission for all purposes under the various 27 firm by PG&E interconnection, integration,' and sales and service 28
j 4
- I agreements between TANC Members and PG&E; however, 2 before the south of Tesla Reinforcements are installed, 3 to the extent that Pre-specified Mitigation for i
,( south-to-north service is insufficient and TANC's l
1 5 Entitlement is curtailed in accordance with section 3.1 l 6 or 3.2, PG&E shall provide replacement power, to th's ! 7 extent available and up to the amount of TANC's 8 Entitlement, if requested by a TANC Member. 9 Replacement power under this section 6.2 shall not be I 10 provided by PG&E to the extent that curtailments are l ! }} required and implemented by PGEE during on-peak periods i 12 as a result of: (1) emergency conditions, including i 13 Tesla-xidway transmission facility eutages and partial s 14 outages; or (2) actions taken by PGEE during system I
'O 25 $
shall be designated
> >== =* *-
by PGEE,
** - = *- -*
consistent with general
=* *-
16 17 industry definitions and the load characteristics of 18 PGEE's electric system, and shall include So% of the 19 hours in a weeh. Initially, on-peak periods shall be 20 Monday-Friday 7 a.m. to lo p.m. , saturdays 1 p.m. to 10 21 p.m., subject to change with adequate notice given to 22 TANC. 23 24 The price formula used in any given month through 25 December si, 2004 shall be the quantity of replacement 26 power provided in kWh in a given month times 10,500 27 Btu /kWh times PGEE's monthly average fuel cost 28 (weighted average of oil and gas) for electric
r - 1 i 1 generation at PGEE's conventional steam plants. PGEZ's: 8 i 2 average fuel cost,for electric generation is currently, i 3 defined as the sum of: . I q 4 (i) The annual average G-UEG transportation rate 1
- 5 calculated based on the currently effective 1
6 G-UEG gas transportation tariff or its ! 7 successor. (The annual average G-rEa 4 transportation rate is the current 8 I 9 CPUC-adopted annual revenues for' utility 4 10 generation divided by the current CPUC-adopted l
~
annual utility electric generation volumes); l ! 11 12 and l i 13 (ii) The c' era and/or non-core gas procurement rates (G-PC and/or G-PN, or their successor rates, l 14 15 as applicable based on the gasiprocurament for - l() conearned) , axcept when PGEE uses i 16 the month 17 oil rather than gas for some or all of its I power plants. In the latter case, PG&E may l 18 use its weighted average price of oil and gas l 19 a instead~ of the applicable gas procuranent
- 20 I 21 rate.
31, 2004, replacement power shall be o 22 After December the 23 priced as agreed by PGEE and TANC or as filed with pursuant to Section 205 of the Pederal i 24 FERC by PGEE {* 25 Power Act. 26 ] ~ 27 6.3 Term of Pirmness - Por purposes of Sections 6.1 and l ({} 28
~33-4
i j i. 4 h 1 6.2, transmission service hereunder shall be de emed ( 2 firm prior to the completion date of the south of Tesla 1 3 Reinforcements; it, however, after the south of tesla 4 Reinforeaments are determined by the CPPA Board of 5 control to be necessary in accordance with section 4.2, l ! PGEE is unable to install such reinforcements after 6 exercising due diligence in accordance with section 7 4.5, transmission service hereunder shall be deamed 8 9 firm only until the later of (i) January 1) 2004 or years following the date .the cPPA Board of 10 (ii) a 11 control makes such determination. 12 . 13 6.4 Limited Effect on Nature of Power Resources - Nothing 14 in these principles shall be construed to define or (} 15 determine that any power resource is fira except to the firm transmission is an element of such 16 extent that 17 definition or determination. 18 19 7.o UNCONTROLLABLE FORCES 20 21 The obligations of any party under these Principles and successor for payment obligations, shall be 22 agreements thereto, except forces. Further, such obligations 23 subject to uncontrollable in allocating time and 24 shall be subject to PGEE8s discretion 25 materials during periods of shortage in order to avoid jeopardy 26 to its retail customers. 27 () 28 1 4 . I a.0 TERM OF SUCCESSOR DEFINITIYZ TRANSKIssION SERVICE AGREEMINT 2 ! 3 a.1 ceneral - The successor definitive transmission service ! 4 agreement shall become effective when permitted to do 5 so by FERC and shall remain in effect for the longer of j 6 (i) the term of the cOTP Participation Agreement or unigin s 7 (ii) the date specified in section s.2.3, i 8 terminated in accordance with section s.2. 9 10 a.2 Early Termination - The successor definitive 11 transmission service agreement shall terminate upon the 12 earliest of the following even'ts or dates: 13 14 8.2.1 The later of (i) the completion of the south of Tesla Reinforcements or (ii) three years 15 after the CPPA Board of Control makes the 16 determination that such reinforcements are 17 necessary in accordance with section 4.2; 18 19 provided that south of Tesla Reinfor= aments the CPPA 20 are determined to be necessary by Board of control pursuant to section 4.2 and 21 22 TANC gives written notice to PGEE within 23 ninety (so) days of such determination that it thereof 24 elects not to contribute to the cost 25 in accordance with section s.s. 26 27 a.2.2 The termination data specified in a written O = t 1 a notice given by TANC to PGEE at least sixty } } () 2 (60) days in advance of termination, following a change by PGEE, accepted or approved by 3 FERC, in its methodology for computing or , 4 5 developi ng transmission service charg s, rates 6 or prices under section 5.1 if such change in methodology is reasonably estimated , to 7 l charges, rates or prices for l 8 increase transmission service under section $.1 by 35 l 9 i ! percent over four years or. lass from the date 10 such changed methodology becomes effective. 11
- south If TANC has contributed to the cost of 12 of Tesla mainforcanents in accordance with 13 TANC shall have the option to section s.3, 14 15 continue service until the date on which TANC
- 16 receives a refund in accordance with section.
period when the 4.7, or any shorter 17 termination date specified in written notice 18 i to PG&E is at least 180 days
- 19 given by TANC after such notice is given, in which case PGEE 20
- agrees not to increase the transmission 21 service charges, rates or prices under section
, 22 23 s.1 by more than 25 percent in any four year 24 period prior to the arpiration of the ten year section 4.7: providee, 25 period described in however, for purposes of section 4.7, TANC 26 e 27 shall be entitled to receive its refund at th 28
i l
. I I
1 same time as it would have if TANc had not' l () 2 elected to continue service. l , 3 s.2.3 The later of (i) January 1, 2010 or (ii) 1o 4 l 5 years after completion of the south of Tesla ! ! 6 Reinforcaments if TANc contributes to the cost of such reinforcements in accordance with j 7 section 5.3; provided that the COTP is f 8 - i 9 terminated or is not in commercial : operation by January 1, 2000, or PGEE's or TANC's j ! 10 l 11 participation in the COTP ' terminates. PG&E 12 shall not unreasonably withhold its consent to , l s 4 13 extend for up to one year the above January 1, j 2000 trigger date if substantial progress v 14 () 15 toward completion of and is then underway. the COTP:. has been made i 16 4 ) 17 18 S.2.4 The termination date specified in.a written notice given by TANC to PGEE at least ninety
- 19 (90) days in advance of termination; provided
? l 20 i . 21 that PGEE does not initiate installation of the South of Tesla Reinforeaments within two
~
I 22 23 years of the determination by the cPPA soard a that such reinforeaments are l 24 of control 1 25 mee ssary in accordance with section 4.2, 1: because (i) either PGEE or Edison has been 26 relieved of its obligation to contribute to 27 of such reinforcaments pursuant to () 28 the cost
~37-1 i
._._.7 I
\
} Section 5.3.1 or Section 5.3.2 and (ii) PG&E's 2 or Edison's previous share of the cost of such reinforcements is not as'sumed by PGEE, Edison, l
3 4 Designated Participants or Third Parties. 4 I 5 i 6 9.0 SIGNATURES J 7 8 The signatories to these principles represent that they have been appropriately authorized to enter into this agreement on behalf 9 i 10 of the party for whom they sign. , l . 11 4 j 12 13 Pacific Gas and Electric Company 14 15 sy: f_':W 16 vice Pr side l 17 Power Planning and Contracts 18 i 19 l 20 q 21 Transmission Agency of Northern California 22 23 sy:
/
~8 /
24 ch raan 25 26 27 O1 gg
-se-
i 1 1 4 J s 4 l 1 4 1 4 4 1 a 1 i 4 i t 4 i i 4 i 4 Appendix H i TIME PERIODS 1 I i t I i 4 4 I i 1 1 + 4 l E 1 l a 1 i 4 \ s l M 4 4 I
l 1 Appendix H
- l J.
( 2 TIME PERIODS
\
3 H.1 TIME PERIODS 4 The following time periods may be changed from time-to-time 5 consistent with PG&E's administration of the PPAs. l 6 7 TIME PERIODS MAY 1 - OCTOBER 31 NOVEMBER 1 - APRIL 3 0 8 (Period A) (Period.B) PEAK Noon - 6:00 p.m. Weekdays 9 except d*Y' 10 l PARTIAL-PEAK B:30 a.m. - Noon Weekdays 11 except Holidays 12 6:00 p.m. - 9:30 p.m. 8:30 a.m. - 9:30 p.m. Weekdays except 13 Holidays OFF-PEAK 9:30 p.m. - 1:00 a.m. 9:30 p.m. 1:00 a.m. Weekdays 14 except
"*1'd*Y" d 15 5:00 a.m. - 8:30 a.m. 5:00 a.m. - 8:30 a.m. Weekdays except 16 Holidays 17 5:00 a.m. 1:00 a.m. 5:00 a.m. - 1:00 a.m. weekends and Holidays 18 1:00 a.m. 5:00 a.m. 1:00 a.m. - 5:00 a.m. All days yg SUPER OFF-PEAK -
20 21 1994 Holidays: New Year's Day (1/1), Presidents Day (2/21), 22 Memorial Day (5/30), Independence Day (7/4), Labor Day (9/5), 23 Veterans Day (11/11), Thanksgiving Day (11/24) and Christmas Day 24 (12/26). 25 l 26 1 l 27 V -) s 28 H-1
i j 4 1 I Appendix I UTILITY IDENTIFIERS AND TMANSACTION CODES Attachment 1 Utility Identifiers (Two Copies: One Sorted in 4 O Numerical Order and the Other in Alphabetical Order) ~ Attachment 2 Interconnection Agreement , Transacti,on Codes ' 1 1 O>
*s 4/07/94
- Attachment 2 - Numerical Order 4
leader bedertueer Sener6escription SeneerInDutledicator 4 O ~ l j Q 3 RIS: He nascellaneous Estner OPA 001 loaneville Poser Aealaistration out ] nuPP 902 NhPP teoretuting Office Ost USCt 004 W$ttteorsiutingOfface Out BOP M7 U.S. bureas of Reclamation Ost l ACE 008 U.S. Army.CorpsofEngsents but TSET 010 Ira-State Gen & 1rans Assoc lac. Ost CEC 011 Cente! Electric - Colorado Ost PSC 012 Pallic Service toasany of Coloraec Oct CCS 013 City of tolerado Sarangs Oct 1 C11EA 014 tolerato-Ute Electric Assoc., Inc. Out ' i PE;T 01: Plaint Electric 5 & 1 teos lic, ht EP! 016 El Paso Electr y to Ost NEVP 017 nevesa Powr toneasy ht . , BH*L 018 l' ace Mills Poser & Light to. Det AEP: 019 art:s u Electric Peeer tarp. But D08D 0:0 3o.91 45 teset. Put Out CHPD 021 Pn no. 1 of D elas teuety, est CCPC 023 trant toenty PUB 12 ht , IEPC 024 lastsElectricPseerto but i PD: 025 Pene Dreille toesty Put Ost I CDPt 027 Putno.1ofCaelittCounty Ost tratash talentia hyers & Pow' Aett but l KHA 030 WKPL 031 West Lecteur Power & Light Company But EME) 032 Essene Bater & Electric lears Out I IP 033 !sterconeasyPsol est
- IPC 034 !aanoPosertaapany Out CPU
- 035 tallforsas Pacific Ut. Co. Out MFC 036 Acntau Powr Consany Oct CPU: 037 Dianogan c.Pn Dut
. CPn 039 Clars toesty Pt4 Ost ! P;E 040 Fortland General Electric to. Ost KPU) 041 titt:tas County Pp Cut PPLC 042 Pacitte Po wr & Lieht to. Out
$;PC j 043 $nonomisa tomaty PH Out j 3PUI 043 Snotontsn toenty. PUD Dvt i PSP; Osa Pseet Sound Poser & tapt to. Ost I CIT 045 tity of Ifano Falls Elec Liont best Out WP: 04s Washingter, bater Powr (c. Out l
SCL 05: Seattle City Lipt Det T:i 09 14cona City Lignt Out TAC 055 TransAlta Utilities Corporation Out l Mi 060 harsant Public Service het Out l PASA 042 City of Pasasena Out WAUR 043 bestern Area Poser Aants (Dooer RD) Dat GLEN 064 Elessale Punlic Service Dept Out PS 064 Art:ou Punlic Service to. Out SPF 067 Sierra Pacific Poser to. , Ost LDP 066 Los Angeles Dept of hater & Powr Det j PFL 069 Pacific Poser & Lignt tc., Wyoning Ost ' WAC 07C bestern Area Power Aen:n (0pper CD) Dut WALC 071 Westers area Pseer Aenin (Lowr to) Oct [ SMt 072 Sacranesto nunicipal Utility list. la j SkP 073 Salt River Prosect Out TEP 074 lucsonElectricPowrto. Out i
4/07/94 4 . i Seneer Seneerhunner Seneernescriptisi leider!noutladicator I, Pu -f75 Pdite Serytte to, of we histo 1
\ Det
- b4LR 077 bestern Area Peeer hans (Loser 30) ht
{ 4 Ill 078 laperial Irrigattee hstrict kt MD 071 ktropolitan hter httrtet Out PGAE NO Pacific Gas & Electrat to. la F4an til City of Farnington Out TWP H2 Texas-hee h atte Peeer to. Out SPSC N3 Soutteest Publit Service to Ost SHE 084 54a hego Gas & Electric Co. But CFE 085 Centstes Feteral se Electitetsad Det WMra 066 prontag nemicisal Peeer Asency Ost WAMP 087 best tres Peser tenta-sacramento,tA in CMt Mt best of hter-Jesearces, CA in l Tit 090 *erlock Irrigaties h strict la l i RVS) Of1 City of tiversise Out SCE ff2 5estners tal:f.rsta Es son Co. But Am Of? City of Anasein Out ! ICLA 094 incorporated Es. of Los Alanos (CAI Gut l NCPA ff5 hertlert Califerais Peoer Agency la CSC M6 City of Santa Clara la All M7 noseste irrigatsee httract la ! l KT 098 beseret Generation 4 Trans Co-op ht UMPA 099 litan Asancipal Poser Agency Ost GM 110 Grars h t6er tausty. M Ost CM !!! Csty of Port negles (WA) Det s PPU: 11: Pactfac Caesty.PUI il kt LM !!a Lees toenty PUI ht
\ Ctd 116 Clallen County. M Qut CLPU3 !!! teatral Lanceln M Ost ECI 120 Dosglas Electric Coop,. Inc. Out CDA 121 City of Azusa Du' liOEC 122 best DE Electric toon., Inc. Det CGI 123 City of hening Out ECI 124 hste Electric Coon., Inc. ht CC: 1:5 City of tolton Out CCE: 12i teos-Curry Electric toon., Inc. ht SHi~ 127 $nasta M in vita 127 City of vernon Qat 6Pa 128 Artrona Po.er Autnerity Os*
MESA 129 Catt of pesa Dut CP: 130 Consumers Foser tonesav Okt SAM: 131 San Carlos Irrigatten Project - IIA Dut CLP: 13: Clearsiter Peoer Consan? Out LEC1 134 Lincoln ElectTsc tooc., Inc. ht RE: 135 kocty Roentals Generating toop Dut KLC* 136 thetitat Co. M hi LCE: 138 Lane to-Electric taos. M Dut REC! 140 hastate Electric Caos., in: Oct IIA 142 U.S. hreas of Indian Af f airs Out CIEC 14a talantaa lasin Electric toes Out CPCa 146 telsneta Power Coop Association Out CEt! 148 Central Electric toon., Inc. Out ( IRE 15C tatt taver taral Electric Coop, lac Det
\ SR: 11: Salaen River Electric toes., lac. Ost LRE: 154 Lost tiver Electric toos., loc. Out
1 I 4/07/94 e Seneer Sessernunser Senderbescristros Senderin0stladicator l O b r.1 156 nortners Lights, Inc. ht i HEC 158 nattas tiver Elutric tasp. Ost l Ftti 160 Fall taver aural Electric tasp, Inc ht UECA 142 unatilla Elutric coop Assectation Det ) MEA i 164 bestee hral Eintric Associatten Ost ' CAHE 166 Centralia Rusicipal nyers Elutric est FEtt 168 Ferges Electric tasp., Inc. Ost FCPI 170 Ferry tasaty.PUI Ost i FLEC 172 FlatneadElutrictoon., lac. But GEt! 174 Glacier Electric teos., Inc. ht ILPC 176 loano to Lynt & P m t Coop Assa Ost 1 IPL 178 ! alans Po er & Laget Ost i DEP 179 ,osis treyfus Entric Peeer Out n:Cl 130 nctone Electric Coop., Inc ht REC 18: eissoula Eintric taos., Inc. Ost I NEC 184 asttners Electric taop ht SREC lie sen tiver Eintric Caos., lac. Det WPut 118 Waatcsa tarst1. PUI Sut LAUS 109 Lanes assicipal Utility listrict le LSt 190 Lincola Service terp Ost MS: 172 het $prings to REA, lac. Out LYPL le4 Leser Valley. Poser & Light, Inc. kt CFL 196 Carson Peeer & Laget Ost RLtt !?8 Ilactly-Laer ta, toop Electric Assa Ost CC$r 199 tity 4 tausty of San Francises la gs VEtt 200 V1;ilanteElectrictoop.,in:. Out i HEC 1 212 marney Eintric Caos., lac. Out RVE4 214 tivertonValley.EletricAssa Gut HEt 216 Nill to Electric teos., Inc. Out . IEC! 2:8 leartoothElectrictaop.,Inc. But l PEtt 220 Fart Electric Coop., Inc. Ost ! VV; 222 felloestone Valley.Esoc. ht SYE: 224 Surprise valley Elect Core ht - NVE: 22e messeleaValley.ElectricCoco,Inc Dat DUI 22P Frantlas Co. PU) Dat GPAl 230 Gartate Peser Association, lac. Out MLEA 232 Roon Lake Eln tric Association Ost IVEA 234 3rteger valley Eint te Asin., Inc. Det BPUt 236 benton to. PU) Det IPUI 238 illlanoot PLlD Out PIE: 240 lie lend Electric toco. Det SM 242 Springfield nunicipal District Out T; 243 Forest Grove ht nca 244 Rentneville Out MF 245 Rilton Freeester Ost CPN 246 California Pacific kattosal Out 3 E. 248 Dent. of Energy Lernce Lvraore Lat la RED; 24f tity of ledesag in PAtV 742 Pacific Corp., Electric Ops - best Out PE0W 742 Pactitt Corp., Electric Ops best Out DCE B00 Separtnest of Energy in PACE 842 Pactt:c Corp., Electric Des - East out
) '
PE0! 642 Pacific Corp.,Eint Operations East ont RH; 900 tity of Redcast In PALC 901 City of Palo Alto in
- - - .-.-_ - . . . . - _ . -. .. . - _... - . __.- - . . - _. - .__ - = . - . - - . - - - ~ .
i 4/07/94, i 4 Stater Seesernunter Seneerlettriotten SeneerInostled:cator -l LU1 fl0 Lanar Utilttles leard-City of Lanar Det i NTUA til Navajo it:641 Utility,estnerity, But CIC 912 Calerade taver Cennissten, hevda Out i SCPA 913 Seethern Cal Public Peser agency, est l SCPC 914 Sestners Celerado Poser-Centel Corp tut ! STCt f15 City of St. George But ! SCIP 731 SanCarlesIrrapationPro;ect Out { ppt 942 Pacific Peeer & Light Co. But j NCAL 996 horthers Califersta la BPA) 998 TENP IPA Ost CES) til -) (UTILITT IRMKt !$ NOT VALII) <- Det - WPC 999 teas WPC Out i ' i 4 k i i 1 O.
- 4/07/94 Attachrnent 1 - Alphabetical Order j l 4
ileeder leaders uber Sendernestristsee Senderis0stladicator
/ ACE 008 U.S. Army Corps of Engineers Ost l AEPC 019 Artzesa Dutric Poser Corp but Alert ef3 City, of Amateta APA Artrona Peeer Asttority ht )
12 est APS Du Artzena Petlic 5erette Co. But SEC 240 ligtendElectricCasp. Ist i ICHA 030 Brittsa Calentia leydro & Peeer Astt Ost I BEC1 219 hartostaElectricCamp., lac. Ist KPC 024 hsia Dectitt Peeer to Get BMPL 018 Ilatt Nills Peerr & Light Ca. Ost RIA 142 U.S. tareas of lesian Affatrs Ost SLCC !?8 IlattlP-Lane to, Caos Dectric Assi Out 30R 007 ) U.S. Bureas et teclamatten est ' j IPA 941 leserville Paser eeninistration est IPAD 998 TEF SPA let I IM 234 lentes Co. PLS Ost l i IREA 164 lestos taral Dectric Associaties est I MI 040 hrsant Paths Service test est l IVEA 234 tridger Valley Electrat Assa., Inc. k t CIEC 144 Coluntia h sis Electric Cao, but I
- CCEC 126 Caes-Carty. Orctric Ceep , Inc. Ost
- CCN 116 Clallen Casaty PUI Ost
! CCS 013 C:ty of Calerade Springs Ost a CCSF !?? City & Casety of San Francisco le CDWR 088 het of gater lessettes, CA la 1 , , . CEC 011 Centel Electrit - Colorado est I ( CEC 1 148 Central Dectric Coop.,1s:. Ost CTE 081 Censsies Federal de B ertratadad Out CHP) 021 M he. I of Chelan Coasty, Ost CIF 045 City of Idaho Ealls Det Light kpt est i CLPC 132 Clearsater Peeer Caspany. Ost CL M 118 Central Lincoln M Out i CMKE lu Centralia as*icipal hydro Electric Oct CDA 121 Cary of Aresa Ost C03 123 City. of hening Det i CCC 125 City of Celten Out 4 CDPD 027 m ko.1 of Cosht: County ht CPA 111 City of Port Angles (WA) Ost l CPC 13C Conseners Power Consany Out CPCA 146 Calentia Poser Coop Association Ost CPL 196 Carson Poser & Light Out CPP 246 California Patzfat Natsonal Out CPUC 035 Califerata Paciftt Ut. Co. Out CPUI 039 Clart Causty M Out CRC 712 Colorado tiver Cannission, hevada Ost CIS) fft -> 15TILITT NLWER !$ NOT VAllt) H Det CSC 096 City of Santa Clara la CUEA 014 Colorade-ute Doctric Assoc., lat. Ost l DECI 120 heglas Dectric toep,. Inc. Ost ICT 098 Deseret Ceseraties & Trans Co-op Out DOE 800 hpartnest of Energy, la l DOEL 248 hat of Energy Lerate Lernere Lab In l O DON EFE EWD 020 016 032 losglas Ceesty, M D Paso D ettric to Oct Det Out Estene Water & Dectric leard I
. _ . - . _ _ - ___-___ - . .-. - . - .- ._. . - ~ _ - . _ .-
~
4/07/94 4 Senser Seesernin6er Senderlestription $esterisktledicator b I Fann 001 City of Farntagten ht. ' FCP) 170 Ferry Casaty M Get FEC1 168 Ferges Electric Casp , lac. kt F5 241 Forest Grove Out l FLIC 172 Flathead Electric Caep , Inc. est FPul 228 Frantlas Ca. PW Out FitE 160 Fall 1:wr hral Electric Coop, lac est CCPI 023 Erant County PW f2 ht l l GECI 174 GlacierElktricCoop., leg. Ort
\
i l GLEh 044 Glendale Petlic Service left Out
, i l GPA! 230 Lattane Powf hsectation, Inc. '
Out i GPn 110 trays harter Casety Put Out NCEC tie nall Ca Electric Coop , lac. Ost l NEC1 212 marary Electric Caos., Inc. But l HSC 192 het Sertogs Ca ILA, lac. ht Ma { ICLA laceroorated Ca. of Los Alanos (CA) Dut ' III 078 laser:41 Irrigatsee hstrtet Ost ILPC i 17e laane Ca Laget & Peser Coop assa but ' IP 033 latercampsey Peel let IFC 034 1sato Poser Campany Ost IPL 178 !aland Peeer & Ltgt! kt j KLCP 136 Kitchitat Ca. PW But KPUI 641 LattitasCasstyPW Out l LCEC 138 Lane Co-Electric Caos. Pul Out LIEP !?? Lests k ey.fas Electric Peerr but l LDWP 068 Les Angeles left of hater & Poser Ost ! LEC1 134 Lancels Electric Casp., lac. Ost LRd lit Lasses Assicipal Utility listrict is l LPUI 114 Leels Catsty.PW Out LIEC 154 Lost taver Electric Coop., lac. Out LSC 190 L:scels Service Crep. But LUI 110 Lamar utilities 74ard-City of Lanar Dst LVPL 194 Leser Valley Por,er & Light, Inc. Det RCCI 180 ScCase Electist. Coop., lac Dut MEC 182 atssesta Electric Caos., lac. Out MECI 140 niestate Electric Coos., Inc Det MES4 121 City. of Resa Oct lli 245 Ritten Freesater Det RIP 017 hodesto Irrigation 31 strict la RISC 000 Riscellaneras Ettler RLEA 232 noon Late Electric Associatsen Out I MPC 036 Acetana Poser Company out niiEC 158 narsas t2vir Electric Coos. ht MH 079 hetropolttan Water hstrict Out RCM 244 RcRanoville Det NCAL 988 horthers Califersta it l NCPA 095 hertners (alifersta Peoer Agency. Is l NEC 184 hortters flectric Cao, Det NEVP c17 pevada Peier Campany. Ost ! NL1 156 hortters Ltthts, lac. Det l NTUA til Nava;c 1rwal utiltty.6stnority Out l l NVEC 226 mespelen falley Electric Coop, Inc Det NWPP OC2 NWPP Coordinattag Office Out
\ OPUC 037 Otanogas Co. PW But PACE 842 Paciftc tarp Electric Des - h st Out l
l
i 4
,, 4N7/,94 I
. o j Sender Seneerneneer Sensertescriptise Seneerin0stledicator
,o (j
PA W PALO 742 Pacitte torp., Electric bps - best Ost C ty of Palo Alto 901 la PASA 942 City. of Pasacesa est PEC1 220 Park Electric toep., Inc. But PECT 015 Plates Electric E & T Ceep. Inc. Ost PEOC 042 Pacific Corp., Elect Operatises East but PEDW 742 Pacif tc Corp., Elntric Ops best est PLAE Deo Pacific Las & Electric to. la PGE Dao Portland General Electric to. Ost PH 07; Pablic Service Co. of hee Retico Ost PD: 025 Pend Dreille Ceesty PUB But PFL 942 Pacific Peeer & Light Co. But PPLC 042 Pacific Peser 1 Light Co. Ost PPUI 112 Pacific tasety M 41 Dut l PPE 049 Paciftc Poser & Light to., byening Out PSC 012 Petlic Service Casesey of Coloraae Det PSPL 044 Peget Sesed Peoer & Light to. Out RE 900 City of todding le - i REN 249 Cityefteettet
. la '
RR;C 135 tocky Rosstate Generating Coop Det ttRE 150 Batt tiver taral Electric Coop, Inc est l RVEA 214 tivertes talley Electric Assa Det RYS1 091 City, of Riverstee est SAN: 131 San Carles Irrigation Pre 3ect - IIA Det SCE 092 Seettere Califerais Esises Co. Ost
$;IP 731 Sao Carles Irrigation Pro;ect Ost l S;L 0".2 Seattle City, Light Oct
[V] SOPa f13 Souttern tal Pe6lic Pseer Agency Out SP: 914 Sestners Colorate Peeer-testel torp. Ost SCP) 043 Snonentsh Ceesty M Ost 53;E 064 Sai liege Gas & Electric to. Ost SHST 127 Shasta PUI in SR; 242 Springfield Asticipal listTset Ost SRS 072 Sacranesto Ausicipal Utility list. la SPP 067 Sierra Pacific Power to. Ost SPSC 0$3 Sourneest Pablic Service to Dst SPUI 43 SeonantsA County PU) Det SR; 152 Salmon River Elutric teos., Inc. Out SEE 156 Sen River Electric toes., Inc. Ost
$9P 073 Salt River Project Det ST&k 91: City of St. George Det SVEt 224 Sorprise Valler Elect Corp Out TAU: 055 transAlta utilities CorPoratten Out Ttt 054 Tacona City Light Ost TEP 074 Tutsen Electric Peeer to. Out ilD 090 isrlect Irrasation hstrtet la TNP 082 Texas-hes nestco Peeer to. Out TPUt 238 Tillanoot M Dit TS;T 010 Tri-State Gen & Trans Assoc. Inc. Oct UECA 142 unatilla Electric toon. Assoc:stion out pePA 099 Utan Aasicasal Poser Agency. But VE:1 200 Vigilante Electric "coc., lac. Ost
/~% Vitu 127 City of Vernon Det h #ALC
#ALA 071 077 Destern Area Peeer Aenin (Loser CD) Ost bestern Art. Poser Asnin (Leser RO) Ost
. 4/07/94 4
Sewer Senderkneer Senderlesertption Seneerin0stleticator i'
. WAMP 087 best Area Peser NRieSacrentrato,CA li, HUC 070 besters Area Peser Adnas (upper CD) Ost Wun 043 besters Area Peeer Mate (upper RO) Det . HEC 1 124 Easco Electfit Ceep., lac. Ost
- NPL 031 best Esotenay,Peser & Light Campany, est
; MAPA 004 byenseg hencipal Poser Agency Ost l 90EC 122 best It Electric Ceep., lac. Out
- UPC 999 tene NWPC est i WPUD 188 unatten Cosety PUD 8et WSCC 004 kSCC Coordtaating Of fice Ost WPC 044 basategtet mater Power Co. Ost felleestone valler Ceep.
- tVC 222 But i '
1 1 e l l l 1 i l l l 1 1
. .. _ - . .. _- _ . - .. ~. - . .- . . - . . . . . - - .
. _ - ~ __ - ..
j' p m I i INTERCONNECTION AGREEMENT TRANSACTION CODES EFFECTIVE 2/19/94
~
C66Ei __i__ ._ DESCRIPitON LMUD DOEL[WAPA[CCSr MID TIE ' H3 C SUUD
~ 9' EIrr~n Ir~5th to ironi fioriii oi PG&E Service Area wie DC _ _ ,
X X X. X
-{X
]'X~
X X X i t
. __ 9 . __ Flem Enggy ,p'f,rpen,_Np!!h_ of PG&E Service Aree _ _ _ _ _ _ _ ,
11 Flem Energy in POS E Service Ares X e X X X X X
! X X X X X 12 Firm Energy tottrom East of PGSE Servlee Ares WSPP Unft Commitment to/from North oI PG&E Service Aree g X X X X X X 20 WSPP Unit Commitment in PG&E Service Aree X X X X X X 21 22 WSPP Unit Commitment to/from East of PG&E Service Aree X X X X X X i X X X X X X 30 WSPP Firm Cepecity tottrom North of PGB E Service Anen WSPP Flem Cepectly in PG&E Service Aree X X X X X X 31 X X X X X X 32 WSPP Firm Cepecity to/from East of PG&E Service Aree X X X X X X 40 WSPP Firm Energy to/from North of PGRE Service Ares X X X X X X 41 WSPP Firm Energy in POSE Service Ares l
WSPP Firm Energy to/from East of POSE Service Ares X X X X X X 42 X X X X X 51 Firm Energy.to/from South of PG&E Seev!ce Ares X X X X X X 52 WSPP Unft Commitment to'from South of PGSE Service Ares
,__53_._ WSPP [ lim Cepecity_to/from South of PG&E Service Aree __. _ . . _
_, X_ _X_ X X X X_ 54 WSPP Firm Energy to/from South of PG&E Service Ares . _ _ _ _ X X X X X _X_ X__ X X X X X X X l 71 fn-Ares _ Spinning Reserve X X X X X X 72 Out-of-Area Spinning Reserve X X X X X X X 73 in-Aree Cepecity_ _ _ _ _ _ _ _ _ . __ __ X X X X X X 74 Out-of Area Cepeelty __ , X 75 NCPA Surplus Cepecity_ , _ _ ,_ . _ _ _ _ _ _ _ _ _ . _ _ _ X X 77 Support Power Spinning fteserve X X X X X j09 Hon-Fhm Energy to/ from North of PG&E Service Aree via DC X X X X X X 110 Non-Fkm (Intert.) Energy to/from North of PG&E Service Aree X X X X X X X X _Ill Non-Fkm (Interr.) Energy ln PG&E Service Ares X X X X X X 112 Non-Fkm (Inte_rt.) Energy to/from East of PG&E Servlee Aree X X X X X X y 13l Non-Fkmlinterr.) Energy to/from South of PG&E Service Aree 140 WSPP Non-Firm (Interr.) Energy _tolleom North of PG&E Service Aree X X X X X X N W 141 WSPP Hon-Firm (Intert.) Ene_rgy in PG&E Service Ares .X X X X X X y2 WSPP Non-Firm (Interr.) Energy to/from East of PG&E Servlee Aree X X X X X X g 154 WSPP Non-Firm (Interr.) Fnergy to/from South of PG&E Servlee Ares X X X ,X X X r, 220 Inadvertent Return On-Peek X X 3' 221 Inedvertent Return Off-Peek , _ _ _. _ X 230 Energy Exchange Peybeck on-Peak a, X ; 231 Energy Exchange Peyback Off-Peek _ _ _ ____ . _ _ _ _ ._ _ ,X_ , X _X X ,_X_ X X 370 Schedule Energy from_WAP_A___ _ _ _ _ _ _ _ _ _ _ _ , _ . X X 371 WAPA to SMUD McC Scheduled X X 372 WAPA to SMUD MCC Actuel _ i 1
I V \ w INTERCONNECTION AGREEMENT TRANSACTION CODES EFFECTIVE 2/19/94 ! CODEe DESCftlP floN LMUD DOEL WAPA CCSF mfd TID NCPA CSC SMUD [Nj . W I'A to UUND Losses . X 374 WAPA Penking Cepecify to Othere ' X
~ ~ ~ ' ' ~ ~X
_!!9_ ??!'*m !m*'9'ncy Po.w.*r x , - --
..!!i _ *$!'m ??P'oc* man'!o**r _ _ __. _ _ . _ ,
X X
.. Z_
__ @!2_ Wp_st ? m 5,fandby Powor 383 llNL lood Curtollment X __.601 , CO{-IA/WAPA Firm Enejgy to/from North of PG&E Servlee Ares X X X X X X 602 COT Firm Energy torerom_ North o1 P_G&E Service _Aree (Flow thru) _ ,, X X X X X 603 COT-IAfWAPA Hon-Firm Energy to/from North of PG,&E Service Aree__ __ X, __ . , , X, X X X _X_ 604 COT Non-Firm Energy toffrom North oI PG&E Service Ares (Flow-thru X X X X X , 855 - Cof-iATViAP5 ii 5PP Fir'en 5nergy to/frorn Notth oi PG5Es Service kre)' ~ ' X X X X X 606- COT WSPP Firm Energy,toffrom North of PGEE Sorwice Aree (Flow-thru) _ _ _ _ _ __ X X X X X 607 COT.IA/WAPA WSPP Non-Firm Energy torfrom North of PGRE Seevice Aree X X X X X
$98_, Cg! WSPP_Non: Firm Energy torfrom North of POSE Service Aree (Flow-thru) __ _ _, , _ _
X X X X X 609 COT . IA/WAPA Copecity to/from North oI PG&E Service Ares X X X X X _ ( 10_,._., C,O] , WSPP Firm _ Capacity torfrom Notth of PG&E Service Aree X X X X X _65{,_ M{g Om pergy jw_ horn South of POSE Service Area (System Use) _, ,_. _, X X X X X 652 MTS Flen Energy to/frorn South of PGSE Service Area (Flow; thru) , . . _ _ _ __ ___ X X X X X 653 MTS Nygir,rn Energy !oijrom pou!h of PG&E Service Aree (System Uso) , _ _ _ _ _ _ _ X X X X X 654 84TS Non-Firm Energy to/from South of PG&E Service Aree (Flow-thru), , _ _ _ , _ _ _ ,__ X X X X X 655 MTS WSPP Firm Energy torfrom South of PGRE Servlee Aree (System Use)_. X X X X X 656 MTS WSPP Firm Energy tortrom South of POSE 3ervice Aree [ Flow-thru) __ X X X X X 657 MTS WSPP Non Firm Energy to/from South of PG&E Servlee Area (System Use) X X X X X 658 MTS WSPP Non Firm Energy tortrom South of PG&E Service Ares { Flow _thru) X X X X X 659 MT S Replacement Power X X X X X 660 MTS Firm Energy in PG&E Service Ares X X X X X 661 MTS Non- Firm Energyin PG&E Service Ares X X X X X 662 MTS WSPP Firm Energy in PG&E Service Ares X X X X X 663 MTS WSPP Non- Firm Energy In PG&E Service Ares X X X X X 700 NCPA Economy Energy X
, 701 Partfel Requirement Power X X 702 Emergency Power X X X X 703 Melntenance Power X X X 704 ShorI Term Firm Power X X X X Emergen_cy Payback X X
_ 705 706 Curtellment Power _ _ _X _ _X 707 Devletion Exchange Power _ __ _ __ _ , , _ _ _ , _
,,X_ X X ,
708 Controct Flem Power .. ~ X ~ 709 Obtigetton Power E Fil Supplement Power X X Pope 2 m
g p G G O I
. _ _ _ _ _ INT _E_RC.O_.NNECTI.ON . AGREEMENT TRANSACTION CODES EFFEC, TIVE,2/19/94 s _
; l . . .
CODEe_. DESCRIPTION ! LMUD ' DOEL , WAPA, CCSF mfd T1D_ NCPA CSC SMUD
~-
x x EP_I'!I*' *ct1Y N.*inisFnes _ P *
?
x x
._l!! S."PPo't Cepecity Short. Term , ' ' ' ~
115 Midway POD Support Service - X
'~ ~~' ~ ' ~~ ^' ' - ~~- - ~ ~
l i6~ Suppori Copicity Curisiim5ni Powst X X 717 1993 Coordinellon Firm Power Sole Flow!P= X x 718 Coordinetton Non-Firen Power X X r 719 1993 Coordinetton Firm Power Sole Hourly _ _ _ ,_, __ _ _ _ _ _ _ 720 Unforecasted Power (SM_U,D) __ X 721 IO-Minute Emergency _(SMUD) X 730 Coordinetton Firm Power X X Hgn-Peek Fl_rm Energy Purchase (NCPA) x ___Ml_ 732 Emergency Power 7 Deys _ __ _ X_ X i __ !N _ Emngency PgpLp 3 Daye_ .__, _ _ __ _ . _ _ _ , _ _ _ _ _ X _._ l$ $ _ PS.E,,5t_o_ndby Powet X 750 50 MW Firm Power (CSC) ~ Power Solo PS - I ^^' X 781 . i 782 Power Solo Contract Cepeelty to load Following , ,, _ _ ,_ _, Power Seh Opcoting Copeelty es Emergency Power ,_ ~i IO3 _._ _ __
'i -
184 Power Sale Oper.eting Copecify se Spinning Reserve ~ 785 Power Solo Contract Copecity es Ernetgency Power -X 786 Powet Sole Operating Cepeelty to Reduc,e Nogetive Devletions i~ Power Sete OperetIng Copecify Reduce Spinning Reserves '-~ i 787 X 788 Power Sole Operating _CopecIty . _ _ _ _ _ _ _ __ _ ,,, X 810 Power Sete PSA - 1 Losses _ X Sil Transmission Rete Schedule Losses X 812 South of Tesla Trensmission Losses _ 813 _ Northwest Losses _ X_ X 814 _ COTP Losses X 815 Western Delivery Losses _ X 816 COTIMTS Flow Through Losses . X X 900 NCPA Plant sI and #2 GeothermellEllective totII931 X. X 901 NCPA Plant t Preject Generotton (Historical date thru 9/30/93)_ - 902 Sente Clers Co Gen Generation x X_ X 903- HCPI Plent 2 Projeci Generation (Historteel dets thru 9/3693) __ _ _. __ __ _ _ _ X 904 Sente Clare Stony Go,rge Generation Sente Clars Block Butte Generetton x 905 ' X 906 Container Corp of Amerles Co-Generetton X y 907 Sente Clare City combustion Turbine #2 X X 908 NCPA Combustion Turbine- Alamede el and #2 X X 910 NCPA Combustion Turblne - Rosevtlle eI and #2 ___ i an Poge 3
O O O INTERCONNECTION AGREEMENT TRANSACTION CODES EFFECTIVE 2/19194 . ... -- DESCRIPTION ,tMUD.DOEL WAP A CCSF MtD TtD NCPA CSC SMUD CO_DE s
' 5i2' ~ UUPA Combustion Turbine - Lodi . '
X X ~ ' - j
~5d^ Sente Utere Combustion Turbine et [
i'~
~ 5i5 UUPd Generellen Units at and #2 l X 'i
' l x x
'5if ' Uon Pedro Firm Entitlement Eschenge
~
* ' -~ ~
~iii- 6en Pedro Non-Flrm Entitlement Enchenge ~
~
j l *
- x . X ~
t
~556~~ UU~ P k Eosevitto Combustion Turbino Copecity Credit f X X
_.!2!. K,l]kwoodf2 _ ., . ; , , , , __ 922 NCPA Lodi combustion Turbine Copecify credit ; , , X 923 Holm 1 X X __ 924 NCPA OggtheIni,al Capselty Credll 925 X NCPA Hydro C_epecity Crodit . P X _ I20_ U.C__3 3t_smgde Combustion Torbtne Copecity Credit 927 mfd Generetton Woodiend ~ X ~
.h h hretion(future) _ ___ _ __
~E~,
X
))
_9H .__ M19 9?n?'et!on t'utu's).. . . _ . _ _ x 930 , Mig oenersoon Don Pedro ___ _ . _ . _ . __ X _ 931 _ MtD Generation Sto_no Drop X 932 mfd Oenerellon McClure CT 933 MID Generation Hsdwood Food Peching X X 934 MID Generellon (future) . X 935 M10 Generellon (tut,ure) , X 936 McMays Mtere Turbine X 936 Ortraly Power Solo 939 X Gitarty_ Hydro Generotton 940 Colltervitte Generetton X X
..- X 941 Spicer Meadows _ _ _ _ . , _ _ . _ _____.
942 X Greegle_{QF)__ . _ , . _ _ _ _ _ _ _ , _ _ _ _ _ _ _ , , , , _ _ . , , _ _ _ 943 110 Generation Don Pedro X X 944 _ ED Generation Le Gronge _ _ _ _ _ , _ _ _ _ _ _ _ _ _ _ _ X 945 TID Generation Hickman 946 TfD Oenerallon Turlock Lake . X X 947 T10 Genermiton Upper Dewson TfD Generetton Weinut CT X 948 X 949 HI Line Canal ' X 950 SMUD Rescuces GeothermsI(Net) __ __ _ _ _ _ _ _ _ __ __ __ ,_ X 951 SMUD Resources UARP X , 952 SMUD Resources Gas Turbine ___ x 953 SMUD Resources Rancho Seco Diesets x _ !54 _ SMuD Reggurce Comp rar wesi 955 SMUD Resources Photo Volletc _x_ Page 4 ,
f r V (/ \
~
INTERCONNECTION AGREEMENT TRANSACTION CODES EFFECTIVE 2/19/94 .I __ - __ __ CODEe DESCRIPilot8 , LMUD ; woEL , w APA, CCSF , mfd TID NCPA _CSC SMUD
- t
' -~~ ~ ~ -~
0 huh hhs}uhes htsb(thih Hydro ! i 957 SMUD Resources Soleno Wind Project ~ '
- X 958 X SMUD Resources (future) 959 X SMUD Resources (future) ' ~
960 X SMUD Resources (future)- [ 961 X SMUD Resoveces (t'utute) _I02 ._ SMUD Rggpurc99 (My_ty) _ _ _ . . _ _ . ._ __ , _ _ ,_ __ X 963 ; X SMUD Resources (future) _ _ _ _ _ _ _ _ _. .. _ , 964 X SMUD Resources (future 965 SMUD Resources (t'uiuTe}) X X 966 SMUD Resources (tuiud) ._ . _ 967 X SMUD Resources (future) _ 968 X SMUD Resources (tuture) _ . _ _ _ _ _ _ . _ _ ._ _ _ _ __ _ 969 WAPA Recoveces - Lewiston X 970 W AP A Resources - Cett X 971 WAPA Resources - Folsom X 972 WAPA Resources -Keswick X 973 WAPA Resources - Nimbus X 974 WAPA Resources -O'Netft X 975 WAPA Resources - Sen tulo X -~ 976 WAPA Rescuteos - Shosts X WAPA Resoutees - Spring Creek X 977 978 WAPA Rescutees - Telnf ty _ _ _ X 979 WAPA Resources - New Melones X __ X 980 CCSF Oeneretton X 981 Moccasin #1 X 982 Moccasin #2 X 983 Moccasin #3 X 984 Supported Seles to MID _ X 985 Supported Seles to 110 X 986_ Non-Supported Seles to ilD 987 Firm Seles to Airport Tenants .X X 988 West Ford Flat (NCPA) 990 X X X X System Demond X 991 MunicIpsi toed X 992 Munlefgel Load Devletion Account _ _ _ _ _ _ __ , _ . __ __ _ _ _, X 993 Assigned Customer Sales X 994 Riverbank Seles Popa5 , a...-- _ . _ --__.. _ _ _ .-__-- - - - -
__ _u, e _ mn_e.k...a - . . . ._u_s.. .M,-1 eA e & ...A.s ,am,J..,_4_..a.A AJmm4 .A Am2.u__ an---. 4J.6 4 Jw. ._ _ ,4L m. a a-eh_ aA,,,.Jm .e _u. .d.m m a j j i 4 3 i f i I 1 l i ia i ) ' l i l t i 1 i f J t i Appendix J 4 i l t .l DPS REQUIREMENTS FOR AGC REGULATION AND SPINNING RESERVE 4 I i Y )
+
t i f r 4 4 i 4 4 1 . l .
i l 1 Appendix J 8 ' 2 DPS REQUIREMENTS FOR AGC REGULATION AND SPINNING RESERVE 3 4 J.1 PURPOSE 5 This Appendix J specifies the requirements that DPS must 6 meet'to fulfill the Control Area obligations specified in 7 Section 4, in lieu of purchasing all required Control Area , 8 Services from PG&E. ] 9 j l l 10 J.2 OBLIGATIG?( 1 11 DPS shall continuously and consistently fulfill all 12 requirements specified for each Contro'l Area' obligation it elects ) I 13 to meet pursuant to this Appendix J. If DPS elects to purchase a ; 14 service from a Third Party to meet a particular Control Area r (_)\ 15 obligation, the Third Party shall continuously and consistently j 16 fulfill all specified requirements contained herein as if that 17 Third Party were DPS. l 18 . 19 J.3 AGC REGULATION 20 J.3.1 DPS Contributes to Control Area 21 If DPS elects this option pursuant to Section 4.1.5. 22 DPS shall connect control systems at DPS Control Area Resource (s) 23 and/or in-area Third Party generation resource (s) ("AGC 24 Regulation Resources") to control signals from PG&E's AGC 25 Regulation equipment. 26 J.3.1.1 Connectino and Doeratine AGC Reculation 27 Resources: Each AGC Regulation Resource shall meet the following 28 requirements: J-1
1 l l 1 J.3.1.1.1 Establishine AGC *li l 2 Control: DPS shall pay all direct Costs to establish an 3 electronic control link between the PG&E Energy Control Center 4 through the DPS Power Control Center and to each AGC Regulation 5 Resource (s); provided, that such arrangement must meet PG&E's AGC 1 6 Regulation requirements in a manner satisfactory to PG&E in its 7 sole discretion, exercised consistent with Section 8.12. If PG&E 8 does not approve such arrangement, as a fall-back, DPS shall pay 9 all direct Costs to establish an electronic control link between 10 the PG&E Energy Control Center and DPS' designated AGC Regulation l 11 Resource (s). PGLE shall own, operate and maintain the equipment 12 at the PG&E Energy Control Center nece'ssary to control the AGC 13 Regulation Resource (s). An AGC Regulation Resource must have l 14 free operating governors that respond to system frequency changes )
- 15. and meet other standard PG&E interconnection requirements 16 appropriate for its size of generator.
17 CBRs are not eligible for 18 simultaneous designation as AGC Regulation Resource (s). Such a 19 resource might otherwise receive conflicting signals if subject l 20 to control by both the PG&E and DPS Power Control Centers. 21 Upon its initial 22 designation of each particular AGC Regulation Resource, DPS shall 23 provide PG&E with sufficient lead time required by PG&E to 24 establish control systems and modify software as necessary for 25 each particular AGC Regulation Resource. Before allowing DPS to 26 provide AGC Regulation, PG&E will test the communication link, 27 resource (s) and control systems to verify their performance as O 28 required. J-2
I i 1 DPS shall coordinate with * /~'} 2 the PG&E Energy Control Center to establish a redundant telemetry :I kJ 3 link between PG&E's Energy Management System (" EMS") and DPS' AGC 4 Regulation Resource (s). The telemetry link is installed to 5 enable the AGC Regulation Resource (s) to respond automatically to 6 electronic pulses from the area EMS. 7 J.3.1.1.2 Ouantity and Ooerational i 8 Recuirements: The quantity of generating capacity DPS shall 9 dedicate shall be calculated as follows: 10 AGC Regulation Requirement (MW) *.= . 11 400 MW x [AGC Control Load /the average of PGEE's 12-monthly peak. loads in a 12 calendar year) 13 14 The minimum quantity shall be two (2) MW for each individual 15 generating unit. [) s- . j 16 The entire AGC Regulation 17 requirement must be available within ten (10) minutes after PG&E 18 calls on it and be provided at a continuous, steady ramp rate. 19 If the AGC Regulation Resources cannot meet this standard, DPS is 20 obligated to designate additional generation for AGC Regulation 21 to meet this standard and to seek PG&E's concurrence, in advance, 22 of the amount of additional generation required. 23 The time constant of AGC 24 Regulation Resources must be no more than thirty (30) seconds. 25 The governor of the AGC 26 Regulation Resources must respond in the range of two to five (2 27 to 5) times faster on average than the ramp. rate specified above C)
\- 28 for the ten-minute (10-minute) period, which assumed a steady, J-3
l i I continuous ramping of generation. * -
)
2 As part of the 3 qualification process described above, DPS will work with the 4 PG&E Energy Control Center to set up an automatic system that 5 will notify PG&E's EMS in four-second (4-second) intervals: (i) 6 which units are AGC Regulation Resources; (ii) the actual 7 generation for the unit; (iii) the AGC Regulation range (in $W) 8 for each; and (iv) which units will respond immediately to l l 9 electronic pulses sent every four (4) seconds to eithe'r raise or j l 10 lower generation by specific amounts. 11 J.3.1.1.3 Noncerformance: PG&E will 12 periodically test the availability and response of the AGC i 13 Regulation Resource. DPS has a continuing obligation to i 14 demonstrate that the standards of this Section J.3.1 are being ( 15 met. PG&E nay test without notification at any time. 16 DPS' overall performance 17 for the day for this Section J.3.1 is acceptable if the group of 18 AGC Regulation Resources is available and fully meeting the 19 operational requirements set forth in this Section J.3.1 for the 20 full capacity required f or all hours in the: day. In the event 21 that PG&E, through testing or use, determines that an AGC 22 Regulation Resource is not in. compliance with the above 23 standards, PG&E may require that, for the purposes of calculating 24 AGC Regulation Load Effective pursuant to Section 4.1.6, the AGC 25 Control Load will be treated as if it were zero for the day. If 26 an AGC Regulation Resource exhibits gross non-compliance, defined 27 as at least four failures to meet the requirements of this 7-s 28 Section J.3.1.1.3 (over any 12-month period), that resource will J-4
~
1 be disqualified as an AGC Regulation Resource until such time as # ( 2 it is requalified by PG&E as an AGC Regulation Resource.
}
3 J.3.2 REE_Frovides AGC Reculation Service Itself 4 For the loads in the Matching Loads group in 5 accordance with Sections 4.1.2 and 4.1.3, DPS shall be obligated 6 to operate its selected generation to continually match actual 7 load moment-to-moment to minimize Energy Deviations. , 8 J.3.2.1 Performance and Measurement: DPS will 9 measure its performance using all applicable NERC and NSCC 10 requirements, as they may be amended from time-to-time, as if DPS 11 were operating its own control area within PG&E's Control Area in 12 accordance with this Section J.3.2. 13 DPS will perform the NERC Al and A2 14 criteria calculations for all the ten-ndnute (10-minute) time
'Tj 15 intervals in each day. The " Delta L" used in the A2 Criterion 16 for each day will be developed for the Matching Loads group by.
17 establishing " Delta Ls" for the loads individually and then 18 summing them up. Other means of calculating " Delta L" may be 19 agreed upon between the Parties. 20 DPS will calculate overall performance by 21 averaging the results of the Al and A2 criteria calculations for 22 each day. 23 DPS is obligated..to cooperate with PG&E 24 in advance of implementing this option and to agree on a system 25 of monitoring comy'.icnce with this Section J.3.2.1. DPS may 26 commence operation under this Section J.3.2.1 fifteen (15) days fs 27 after such a monitoring system is designed, agreed to, installed ( 28 and tested (but commencing only on the first (1st) day of a J-5 l
._..___.__._.m_
i l 1 E i
- 1 Billing Period). + 1
() 2 J.3.2.2 Criteria: DPS overall performance for 'd 3 this Section J.3.2 is acceptable if the average of the Al and A2 j i 4 Criterion for each day is at least ninety percent (90%) . i 5 f 6 J.4 SPINNING RESERVE l 7 DPS shall use its generation resources located within PG&E's 8 Control Area to provide adequate quality and quantity of Spinning 9 Reserve to meet DPS' Spinning'ReserveRequirementpursbantto 10 Section 4.3. Each such DPS generation resource shall either be ' 11 physically interconnected with the PGEE Electric System or shall 12 have associated, firm transmission to the PGEE Electric System in 13 an amount at least equal to the MWs of reserves'provided by the 14 resource and'either unloaded or otherwise available to DPS on () 15 notice consistent with DPS' Spinning. Reserve obligation. To the 16 extent DPS uses DPS Suppliers to meet the Spinning Reserve i 17 Requirement, DPS' combined transmission service usage and 18 Spinning Reserve designation shall not exceed the Maximum 19 Delivary Capability of each DPS Supplier as listed in Appendix'K. 20 If DPS is only meeting a portion of the Spinning Reserve 21 Requirement through this option (and is purchasing the remainder 22 of its needs from PG&E) the minimum MW amount of Spinning Reserve 23 to be provided by DPS shall be five (5) MW. 24 J.4.1 Ooeratine and Testine Recuirements 25 DPS shall schedule its resources being used to meet 26 the Spinning Reserve Requirement in accordance with Appendix B. l
.f s 27 PG&E may test DPS' resources at any reasonable time l 28 to ensure that they are capable of taking on load as required to l J-6 l
l
i qualify as Spinning Reserves. # T^'., 2 PG&E may call on DPS' Spinning Reserve pursuant to u-3 Section 4.3.6. In that event, DPS shall have one (1) hour from 4 when PG&E ceases to call upon the Spinning Reserve to restore its 5 full Spinning Reserve Requirement. 6 DPS is obligated to provide the telemetry and hourly 7 metered data necessary to monitor its compliance with the 8 Spinning Reserve Requirement. DPS shall submit. reports within 9 ten (10) calendar days following the end of the Billin'g Period 10 demonstrating the megawatt amount of Spinning. Reserve, by 11 generation resource, for each hour of the month. 12 J.4.? Non-Performance 13 J.4.2.1 DPS will be considered to have performed 14 its obligations if it provides at least the required amount of (,) 15 spin energy: (a) within ten (10).ndnutes of a request from PG&E 16 in accordance with Section 4.3.6; or (b) pursuant to a test under 17 this Section J.4.2. 18 J.4.2.2 Should DPS fail to schedule or provide 19 at least ninety percent (90%) of its Spinning Reserve Requirement 20 on each of three (3) or more days in any calendar year, PG&E 21 shall have the right to seek a change in the Disincentive rate in 22 Section D.4.1 from FERC pursuant to Section 205 of the FPA, 23 notwithstanding Section 8.27. 24 25 26
,3 27 < J) j) 28 J-7
i 1 Il 1 4 i l l 1 5 t 4 i l I k 1 1 \ 1 4 1 J l i t, i 4 Appendix K i l NETWORK TRANSMISSION SERVICE TABLE 3 p v 1 , s 3 4 i A d T k I 1 4 4 l -. ) 1
i l 1 Appendix K c 2 l NETWORK TRANSMISSION SERVICE TABLE , 3 Inout Points 1 Shuumum REctri SouTutam Zostl - DPs summa tarviPowT vetTAst cAramtm 5 montaina2emi 6 6. ort Mwwey BookV 1 MW southem 7 8 10 Outout Points , 11 i DPS LOAD DUTrut PowT .VoLTACE MAIIMUM DELNERY CArABILM ) 12 Medesta irnestien Dutnet Westley 23tkV 1 MW 14 l y 15 4 1 16 17 ggj 18 Mom 1995 1996 1997 1998 1999 January February 20 Mch 1 MW April 21 u,y 22 July 23 August september 24 Octeher 25 December 26 27 28 K-1
- . . - . . . . . . . . . .--.-..- .-.~. - .__- - .- . . -.. . . - .- ~ -. -._... - - .~ - ~ . _ _ - _
.1 j' 1 I DISTRIBUTION LEVEL SERVICE TABLE ,
i InDut Points 3 J DPS SuPPtwa luruf Peart VOLTAGE kPAEILiff 2 4 Gl0GTRERN ZONE
- 5 i
i 6 4 7 i 8 t i 9
- OutDut Points l 10 DPS LaA0 OUTPUT Peuff VOLTAGE kggg gggggg 12 13 14 15 16 g M083 1996 '1996 Igg 7 tagg gggg 18 February 19 March April 20 u,y 21 July 22 August seeweher 23 oci her November December l 25 x
26 27 i
/ 28 K-2
1 i UNITED STATES OF AMERICA I i j BEFORE THE
; FEDERAL ENERGY REGULATORY COMMISSION i
Pacific Gas and Electric Company ) Docket No. EL96-37-000 1 i AFFIDAVIT OF CHRIETOPHER J. MAYER . J I, Christopher J. Mayer, declare as follows: i .
- 1. I am the Assistant General Manageri Planning and q
j Marketing, for the Modesto Irrigation District. My business l 4
$ address is 1231 Eleventh Street, Modesto, California 95354.
i 1 -
- 2. In my capacity, I am responsible among other things for 1
that the District is meeting' the needs of .ts major i ensuring commercial and industrial customers, and for developing long-range business plans to ensure that the District w:l.' remain competitive. l In carrying out those tasks, I am also responsible for business i development, which includes reponses to requests ' for service to new customers. 4 4 O
d s
- 3. Linde Substation is presently interconnected with the l Pacific Gas & Electric Company (PGEE) transmission system at a nom!.nal voltage of 115,000 volts. The Modesto Irrigation District j (MID) seeks no change in PG&E's transmission facilities at the physical interconnection or the way in which PG&E operates the
- physical interconnection. MID proposes to install 115,000 volt instrument transformers and revenue metering equipment at MID's expense and remove and return to PG&E existing 12,000 volt instrument transformers and revenue metering equipment. -MID will 3
operate and maintain Linde Substation and MID's Pittsburg electric system in accordance with the same high reliability standards presently utilized throughout MID's existing electricf system. MID's interconnection at Linde substation will not impose an operational ; 1 burden on PGEE.
- 4. MID's interconnection with the PG&E transmission system at Linde substation will not require the enlargement of PG&E or MID facilities. MID has entered into an agreement with generation Destec Power Services (DPS) which provides that DPS will supply MID's full Linde Substation wholesale power requirements. DPS is a federally licensed power marketer that obtains its power supply from existing independent power producers and the wholesale power market. MID proposes to purchase residual Linde Substation reactive from PG&E, which, PG&E presently supplies at power requirements Linde Substation, and no enlargement of PG&E generation facilities
is required as a result of this continuing PG&E reactive power supply function.
- 5. MID's interconnection with the PGEE transmission system at Linde Substation will not require PGEE to sell or exchange energy in a manner that would impair PG&E's ability to render adequate service to its cust'omers. MID has entered into an agreement with DPS which provides that DPS will supply MID's full Linde Substation wholesale power requirements. MID is seeking a transmission interconnection and a residual react [ive power s'upply from PG&E at the Linde Substation interconnection. MID is not seeking a continuing energy purchase agreement or an energy exchange agreement with PG&E related to the interconnection at Linde Substation.
- 6. MID's interconnection with the PG&E transmission system at Linde Substation will be in the public interest. On January 16, 1996, the City of Pittsburg granted MID permission to construct, maintain and operate electric lines within the City, which will allow MID to serve electric customers in competition with PG&E. MID will sell electricity to retail' customers in Pittsburg at standard MID tariff rates that average 30% below rates presently charged by PG&E. Lower electric costs are expected to improve the City of Pittsburg's ability to retain and attract businesses in an existing industrial area that is presently underutilized. Improved business activity due to lower electric power costs should result in
-3
)
improved employment opportunities for residents of Pittsburg and i o
[ l 1 ( ('} V surrounding communities.
- 7. MID's interconnection with the PGEE transmission system at Linde substation will optimize the efficient use of facilities and resources and improve the reliability of the electric utility system.
The interconnection at Linde Substation will utilize existing PG&E transmission facilities in an area ' that has a ' very high density of existing PG&E transmission:~ lines due to proximity 1 I to PG&E's Pittsburg Power Plant. If the Linde interconnection is denied, MID's alternative 'wot. ld be the construction of a new f
,es transmission line into Pittsburg from MID's nearest' transmission 'iv) facilities in the Tracy area, a distance of approximately 20 miles.
The new MID line would parallel existing PG&E lines for most of its length, and would have an estimated cost in range of $4,000,000 to S8,000,000. The use of the existing interconnection would be more efficient than the construction of a new line. In addition, the l continued use of the PG&E transmission system will enable it to optimize the use of its transmission facilities. The interconnection at Linde Substation will improve the reliability of the electric utility system through MID's physical improvements to Linde substation and the maintenance of Linde
,_ Substation in accordance with MID's high reliability standards. \ Linde Substation appears to have received minimal preventive
1 l l maintenance during the time period that it was under customer ownership. MID intends to improve the grounding grid, upgrade the l J l perimeter fencing, and install a fire suppression / oil retention j basin at Linde. Substation. MID will install supervisory control ) equipment to monitor Linde Substation from the MID Control Center ; in Modesto. The transformer, circuit breaker, protective relays, and other substation equipment will be maintained in accordanhe ] with MID's written substation maintenance program. These actions by MID will reduce both the probability of an electrical ' malfunction I at Linde Substation and the. probability thaf. an electiical malfunction at Linde Substation would impact other customers served from the PG&E transmission system connected to Linde Substation. , : l l
- 8. MID's interconnection ~ to the PG&E transmission system at
)
Linde substation will not be used for a direct sale to a retail , customer. MID has been a electric utility since 1923, and presently serves over 89,000 customers with a peak -load of over 500 megawatts. MID will use the Linde Substation interconnection solely for the purpose of making wholesale power purchases necessary for its retail sales. All MID customers in the ' Pittsburg service area will be served at the same existing tariffed rates of fered in MID's Modesto service area. \
I t
- 9. MID will use its distribution facilities to deliver at retail, all of the electricity that it will receive pursuant to the interconnection agreement that it seeks with PG&E. MID will own or control distribution facilities in the Pittsburg area including Linde substation and distribution-- lines. extending from Linde MID is a l
Substation to the locations of MID electric customers. public agency and has authority to construct, maintain and operatb an electric distribution system in Pittsburg in accordance with California law and the permission granted by the City of ! Pittsburg. Dated: March 25, 1996 f 8 - [ML
/
CHRISTOPldR J. @ ER l0
l l Modesto, California ) ss: l 1 ( s I, CHRISTOPHER J. MAYER, certify that the attached affidavit in this proceeding was prepared by me or under my direct supervision and that the statements contained in such af fidavit are true and correct to the best of my information, knowledge and J l belief. I d b M 0 9 1of a V . CHRISTOPHER J. MAYER i e Susbscribed and sworn to before me this 25th day of March, 1996 O V j rAi iMLUWtLL MILLS ft COMM. #1000023 E NOTARY PUBUC.CAURNAA 3 STMSLAUS COUNTY Wy Comm. Emm July 1.1000 l l 7;-f s
, Jc ., f , ,-
Notary Public My commission expires July 1. 1999 1 a
. _ _ _ _ . _ _ . _ _ . _ _ . . . _ _ _ _ _ _ _ _ _ _ . _ _ . . . . . _ . . . . _ _ . . _ . _ _ _ _ . . . . _ _ . . . . ~ . _ . . . _ . _ _ _ . . _ . _ . _ . _
i iO ! i i i i i 1 POWER SALES AGREEMENT l BETWEEN 2 DESTEC POWER SERVICES, INC.
^"" ~
O MODESTO IRRIGATION DISTRICT : FOR FULL MID LINDE SUBSTATION WHOLESALE ELECTRIC POWER REQUIREMENTS O
i TABLE OF CONTENTS O V Page 4 2
- 1. DEFINITIONS . . . . . . . . . . . . . . . . . . . . . .
2 1.1 Agreement . . . . . . . . . . . . . . . . . . . . . 2 1.2 Calendar Day . . . . . . . . . . . . . . . . . . . 4 1.3 Control Area and Transmission Services Agreement . 2 2 1.4 CATSA Successor . . . . . . . . . . . . . . . . . . 2 1.5 CPUC . . . . . . . . . . . . . . . . . . . . . . . 2 1.6 Delivery Point . . . . . . . . . . . . . . . . . . 1.7 Destec Energy, Inc. (" DEI") . . . . . . . . . . . .
.3 DEI Guarantee Agreement . . . . . . . . . . . . . . 3 1.8 3 1.9 DPS . . . . . . . . . . . . . . . . . . . . . . . .
3 1.10 Effective Date . . . . . . . . . . . . . . . . . . 3 1.11 Firm Power . . . . . . . . . . . . . . . . . . . .
.' . 3 1.12 FERC . . . . . . . . . . . . . . . . . . . . . 3 1.13 Hour . . . . . . . . . . . . . . . . . . . . . . .
1.14 Full MID Linde Substation Wholesale Electric Power - 3 Requirements . . . . . . . . . . . . . . . . . . . 4 1.15 MID Linde Substation . . . . . . . . . . . . . . . 4 1.16 MID . . . . . . . . . . . . . . . . . . . . . . . . 4 1.17 MID Meter (s) . . . . . . . . . . . . . . . . . . . 4 1.18 Monthly Peak Demand . . . . . . . . . . . . . . . . 4 1.19 PG&E . . . . . . . . . . . . . . . . . . . . . . . 4 1.20 PG&E Linde Substation Interconnection Agreement . . 5 1.21 Solid State Recorder ("SSR") . . . . . . . . .. ... .. 5 [/)
\- 1.22 Third Party . . . . . . . . . . . . . . . ,
5 1.23 Wholesale . . . . . . . . . . . . . . . . . . . . . 5
- 2. TERM . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . 6
- 3. CONDITIONS PRECEDENT . . . . . . . . . . . . . .
- 4. SALE AND PURCHASE OF FULL MID LINDE SUBSTATION . . . . . . . . . 6 WHOLESALE ELECTRIC POWER REQUIREMENTS . . . . . . . . . . 6 4.1 DPS Firm Delivery Obligations . 2 4.2 MID's Wholesale Electric Requirements Purchase ., . 7 Obligations . . . . . . . . . . . . . . . . .. . 7 4.3 MID's Obligations Regarding DPS Facilities 4.4 MID's Obligations Regarding Notification of Load 8 Variances . . . . . . . . . . . . . . . . . . . . .
4.5 No Obligation to Add Transmission or Distribution 8 Facilities . . . . . . . . . . . . . . . . . . . . 8 5- WARRANTIES AND REPRESENTAT73NS . . . . . . . . 8 5.1 DPS Warranties and Representations 10 5.2 MID Warranties and Representations 10
- 6. DETERMINATIONS OF AMOUNTS SOLD A i 10
/ \- / 7. RATES AND CHARGES i
11 k- 8. DELIVERIES . . . . . . . . . . . . . . . . . . . . . . . 11 8.1 Delivery Point . . . . . . . . . . . . . . . . . . Delivery Voltage . . . . . . . . . . . . . . . . . 11 8.2 DELIVERY, TITLE AND TRANSMISSION . . . . . . . . . . . . 11
- 9. 11 9.1 Passage of Title . . . . . . . . . . . . . . . . .
11 9.2 Control . . . . . . . . . . . . . . . . . . . . .. .. 11 9.3 Transmission and Distribution Responsibilities 12
- 10. METERING AND TELECOMMUNICATION . . . . . . . . ... .. .. . .. . 12 10.1 Equipment Installation and Maintenance 12 10.2 Meter Testing and Meter Errors . . . . . . . . . .
13 10.3 Metered Data Adjustments . . . . . . . . . . . . . 13 10.4 Removal of DPS Equipment . . . . . . . . . . . . . 13
- 11. BILLING AND PAYMENT . . . . . . . . . . . . . . . . . .
13 11.1 DPS Monthly Invoice . . . . . . . . . . . . . . . < 14 11.2 Estimated Billings . . . . . . . . . . . . . . . : 14 11.3 Payment Disputes . . . . . . . . . . . . . . . . . 15 11.4 Interest . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . 15
- 12. ADVERSE REGULATORY DECISION 17
- 13. NOTICES . . . . . . . . . . . . . . . . . . . . . . . . 17
/~ ' 13.1 Formal Notices . . . . . . . . . . . . . . . . . . 18 13.2 Routine Notices . . . . . . .. .. .. .. .. .
. 18 13.3 Change of Notice Recipient l
18
- 14. FORCE MAJEURE . . . . . . . . . . . . . . . . . . . . .
19 l
- 15. DEFAULT . . . . . . . . . . . . . . . . . . . . . . . . 19 15.1 Default by MID for Non-Payment . . . . . . . . . .
15.2 Default by MID for Breach of Full Wholesale 20 Requirements Purchase Obligation . . . . . . . . . 15.3 Default by DPS of CATSA or CATSA Successor 20 Obligations . . . . . . . . . . . . . . . . . . . . 21 15.4 Termination for Default 22
- 16. TERMINATION . . . . . . . . . . .. .. .. ... .. .. .. .. .. .. .. . . 22 16.1 Grounds for Termination .
16.2 Termination for Negligible Electricity 22 Requirements . . . . . . . . . . . . . . . . . . . 22 16.3 Additional Remedies . . . . . . . . . . . . . . . . 23
- 17. INDEMNIFICATION . . . . . . . . . . . . . . . . . . . . 23 17.1 Indemnification by DPS . . . . . . . . . . . . . . 23 17.2 Indemnification by MID . . . . . . . . . . . . . .
17.3 MID's Indemnification of DPS for Interruption or 24 Curtailment of Service . . . . . . . . . . . . . . 24 s/
) 18. LIABILITY .......................
ii
_ . - . . - ~ ~ . . - - . _ _ _ . _ _ _ . . _ - - - . . . . - . . . . . . .- ---. . 24 18.1 To Third Parties . . . . . . . . . . . . . . . . . 24 I' 18.2 Between Parties . . . . . . . . . . . . . . . . . .
\ 24 18.3 Protection of Facilities . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . 25 l 19. GOVERNING LAW l 25
- 20. ASSIGNMENT . . . . . . . . . . . . . . . . . . . . . . . 25 l
20.1 Assignment by Consent . . . . . . . . . . . . . . . 25 20.2 Assignor Obligations . . . . . . . . . . . . . . . 25 20.3 Assignee Obligations . . . . . . . . . . . . . . . 26
- 21. MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . 26 21.1 Amendments . . . . . . . . . . . . . . . . . . .. . . 26 21.2 Amendments Related to PG&E Linde Substation IA 26 ,
21.3 Captions . . . . . . . . . . . . . . . . . . . . . 26 21.4 Confidentiality . . . . . . . . . . . . . . . . . * . 27 l 21.5 Construction of Agreement . . . . . . . . . . . . . 27 l 21.6 Information . . . . . . . . . . . . . . . . . . . . 27 i 21.7 Integration . . . . . . . . . . . . . .. . . . . .
.- 27 21.8 No Partnership . . . . . . . . . . . . . . . . . l 27 21.9 No Third-Party Beneficiaries . . . . . . .;
28 21.10 Operating Procedures . . . . 28 21.11 Waiver of Rights . . . . . . . . . . . . . . . . . 28 21.12 Compliance with Applicable Laws and Regulations . O o 1 e v . iii
l i 1 POWER SALES AG'tEEMENT i (-)2 Between i 3 DESTEC POWER SERVICES, INC. 4 And The 5 MODESTO IRRIGATION DISTRICT 6 For Full MID Linde Substation 7 Wholesale Electric Power Requirements , l 8 9 This Power Sales Agreement, dated March 21, 1996, is between 10 Modesto Irrigation District, a California legislatively-created 11 irrigation district ("MID"), and Destec Power Services, Inc., a 12 Delaware corporation authorized to do and doing business within 13 the State of California ("DPS") (DPS and MID shall be referenced
~' 14
' individually as a " Party" and collectively as the " Parties");
(O15 WHEREAS, DPS has been certificated by the Federal Energy l l 16 Regulatory Commission ("FERC") as a power marketer, is engaged in l 17 the business of power marketing, and purchases and resells 18 electric power; 19 WHEREAS, MID is authorized by the California Water Code to f 20 sell, dispose of, and distribute electric power for use outside ) 21 of its boundary; 22 10EEREAS, MID desires to purchase its Full MID Linde 23 Substation Wholesale Electric Power Requirements as defined 24 herein from DPS under the terms and conditions set forth in this 25 Agreement; and n
\_ 1
(
i f i 1 WHEREAS, DPS desires to sell to MID its Full MID Linde O 2 Substation Wholesale Electric Power Requirements as defined 3 herein under the terms and conditions set forth in this i 4 Agreement. I 5 Now therefore, in consideration of the Parties' mutual 6 promises set forth in this Agreement, DPS agrees to sell to MID, 7 and-MID agrees to purchase from DPS,-the Full MID Linde ; 8 Substation Wholesale Electric Power Requirements on'a firm and 9 interruptible delivery basis under the terms and provisio$s set 10 forth in this Agreement as follows: .- , 11 1. DEFINITIONS. j
1.1 Acreement
This Power Sales Agreement by and between l 12 13- MID and DPS. 1.2 Calendar Dav: Hour ending 0100 through hour ending I ()14 15 2400 for any given day. ' 16 1.3 Control Area and Transmission Services Acreement 17 ( " CATS A" L : The Agreement entered into between DPS and PG&E on 18 November 29, 1994, as amended. 19 1.4 CATSA Successor: An agreement analogous to the CATSA 20 Successor agreement described in Section 4.3 of the PG&E IA with 21 the Port of Oakland. 22- 1.5 CEHC: California Public Utilities Commission or its 23 successor agency. Delivery Point: The physical connection of electric 24 1.6 25 systems where PG&E's conductors connect with MID's conductors l l 26 within the MID Linde Substation. O 2
Destec Enercy, Inc. (" DEI") : The parent company of DPS 1.7 (-~1)
"'2 and holder of 100% of the common equity of DPS.
3 1.8 DEI Guarantee Acreement: The agreement to be executed 4 concurrently with this Agreement by which DEI agrees to guarantee 5 to MID all the obligations of DPS pursuant to this Agreement. 6 1.9 REE: Destec Power Services, Inc. The earliest date by which the Partie.s 1.10 Effective Date:
- 7 8 have each executed this Agreement.
1.11 Firm Power: Electric power which, consistent wi'th 9 l 10 prudent utility practice, is (a) intended to be available at.the j 11 time, capacity factors and rates of delivery to satisfy the Full (b) j 12 MID Linde Substation Wholesale Electric Power Requirements; (c) backed ! 13 backed by adequate and appropriate operating reserves; with sufficient fuel supply; (d) backed with sufficient ( 14 transmission to deliver such power to the Delivery Point; and (e) l 15 16 not subject to interruption, except as allowed by Sections 14 and f ! 17 A.1.c and A.1.d. 1.12 FERC: The Federal Energy Regulatory Commission or its , 18 19 successor, as applicable. f 1.13 Hour: A period of sixty (60) consecutive minutes 20 ' 21 beginning at xx00 minutes (top of the hour) and continuing 22 through xx60 minutes until the top of the next hour. 4 23 1.14 Full MID Linde Substation Wholesale Electric Power All energy and capacity MID must purchase on a 24 Recuirements: 25 wholesale basis to satisfy the demands of MID's retail customers 26 whom it serves through the MID Linde Substation; provided that f-b 3
1 these requirements shall be at a level at which DPS shall have no 2 obligation to satisfy its obligations hereunder to be financially 3 responsible for a modification or addition to any transmission or i j 4 distribution facilities. l 5 1.15 MID Linde Substation: MID's substation located at 2000 l l 6 Loveridge Road, Pittsburg, California. 1.16 MID: The Modesto Irrigation District, a California l 7 , 8 legislatively-created irrigation district. 9 1.17 MID Meter (s) : The metering equipment which MID shall 10 procure and install at the MID Linde Substation for purposes.of 11 metering the receipt of electricity at the Delivery Point. 12 1.18 Monthly Peak Demand: MID's maximum demand for 13 electricity in any billing month which shall be calculated based
/ 14 on the average kW delivery of electric power in any fifteen 15 minute interval in which such delivery is greater than in any 16 other fifteen minute interval in the month; provided, that if the 17 load is intermittent or subject to violent fluctuations a five-l 18 minute interval may be used.
1.19 PGEE: Pacific Gas and Electric Company. 19 l ("PG&E l 20 1.20 PG&E Linde Substation Interconnection Aareement 21' Linde Substation IA"): The agreement between PG&E and MID or the 22 FERC order which shall provide the terms and conditions for the 23 interconnection between PGEE and MID's respective electric 24 facilities at the MID Linde Substation. 1 I t O 4
1 1.21 Solid State Recorder ("SSR"): A solid state recorder 2 which records, accumulates and stores data from an' electric ; 3 . meter. 4 1.22 Third Party: A person or entity other than DPS or MID. 1.23 Wholesale: A sale for resale of electricity to a 5 6 customer "at wholesale in interstate commerce" as that term has 7 been construed in 16 U.S.C. S 824 (d) , and which sale is subject . 8 to the exclusive jurisdiction of the FERC. 9 2. TERM. lof This Agreement shall become effective and binding as between 11 the' Parties on the Effective Date. Subject to the other terms 12 and conditions of this Agreement, the term (" Term") of this 1 13 Agreement shall commence, and DPS shall initiate deliveries to 14 MID under this Agreement, on the later of' August 1, 1996 and the l 15 date by which each of the conditions precedent set forth in i The Term of this Agreement shall 16 'Section 3 have been satisfied. 17 commence on the day of initial deliveries and terminate the 18 earlier of hour ending 2400, December 31, 2001, or the date MID 19 ceases to provide service pursuant to the GS-4 rate. 20 Notwithstanding any of the foregoing, this Agreement shall 21 terminate if DPS does not commence power deliveries to the MID 22
-Linde Substation of 8 MW or greater on or before December 31, 23 1996. The Term of this Agreement and the above deadline to 24 commence power deliveries may each be extended upon the mutual 25 agreement of both Parties. ;
26 l O 5 I
- . _- _- = .. . - . - - . . ._ - - - - .- .. ..
l l 1
- 1 I 3. CONDITIONS PRECEDENT.
A)
"\'--2 Notwithstanding any other provision in this Agreement, DPS i 3 shall have no obligation to deliver any power to MID, and MID 1 I
shall have no obligation to purchase any power from DPS, pursuant d 4 l 5 to this Agreement until the following conditions have each been 1 6 met: 7 a) the PGEE Linde Substation IA has been accepted for filing S by the FERC and it has become effective as between P.G&E and MID, 9-and such PG&E Linde Substation IA has a provision analogous to j l 10 Section 6.1.2 of the PG&E IA with the Port of Oakland which l 11 obligates PG&E upon termination of the CATSA to provide by tariff [ i 12 or negotiate in good faith a CATSA successor; and
- 13 b) The MID Linde Substation has become an operative Output Point for DPS in accordance with Schedule K and the other f( A4 provisions of the CATSA.
15 ? 16 Both Parties agree to use their respective good faith best 17 efforts to timely negotiate and obtain the agreements and the regulatory and other approvals referenced above. 4 18 j 19 4. SALE AND PURCHASE OF ruuL MID LINDE SUBSTATION WH I i 20 ELECTRIC POWER REOUIREKENTS. DPS shall deliver on a 5 21 4.1 DPS Firm Deliverv Oblications: 22 firm delivery basis to the Delivery Point the Full MID Linde 23 Substation Wholesale Electric Power Requirements; provided that. 24 DPS' obligations pursuant to this Section 4.1 shall be at a level 25 which does not exceed the present capability of the existing PG&E i ; 26 facilities to deliver power to the Delivery Point or a maximum of 30 MW if the capability of the existing PG&E facilities is
. #'T 27 6
t i l~ 1 greater, on such a firm basis and which does not obligate DPS to 2 become financially responsible for a modification of or addition 3 to any transmission or distribution facilities. 4 '4.2 MID's Wholesale Electric Recuirements Purchase 5 'Oblications: MID shall purchase its Full MID Linde Substation 6 Wholesale Electric Power Requirements from DPS in accordance with the terms and conditions of this Agreement. Upon DPS commencing, 7 B electric deliveries. pursuant to this Agreement, MIDishall not 9 purchase any portion of its Full MID Linde Substation Wholesale 10 Electric Power Requirements from any Third Party;,.provided that 11 in response to a failure by DPS to have delivered all or any 12 portion of the Full MID Linde Substation Wholesale Electric Power 13 Requirements to the Delivery Point, MID may acquire such 14 replacement power from a Third Party. MID's right to purchase 15 such replacement power pursuant to this section 4.2'shall be l 16 limited'to the extent and duration of DPS' failure to deliver the 1 i 17 Full MID Linde Substation Wholesale Electric Power Requirements. l 18 4.3 MID's Oblications Recardina DPS Facilities: 19 (a) MID shall provide, maintain and preserve for DPS
- 20 throughout the Term of this Agreement access to and rights to use 21 property within and surrounding the MID Linde Substation 22 necessary to enable DPS to perform its obligations under this 23 Agreement.
24 (b) In the event that DPS can no longer adequately perform 25 its obligations under this Agreement due to MID's failure to 26 preserMe for DPS the necessary rights specified in Section O 7 ! 1
i
-1 4.3 (a) , DPS shall endeavor to the extent practicable to continue C)2 to deliver the Full MID Linde Substation Wholesale Electric Power 3 Requirements, but DPS shall be relieved of its firm delivery 4 obligations pursuant to Section 4.1 during any such period of 5 breach by MID to the extent of such breach.
6 4.4 MID's Oblications Recardina Notification of Load 7 variances: MID shall advise DPS on a best efforts basis and as ., 8 soon as practicable of anticipated changes from current or~ 9 historic levels and load factors in the Full MID Linde Substation
' 10 Wholesale Electric Power Requirements. ,MID's obligations under - :
l 11 this section shall include, but not be limited to, timely 12 advising.DPS when it has knowledge that the Monthly Peak Demand i 13 will increase or decrease by an amount equal to or greater than 500 kW (.5 MW) of-the prior month's Monthly Peak Demand. t 34 15 4.5 -No Oblication to Add Transmission or Distribution l 16 Facilities: Neither Party shall be obligated.to the'other for 17 purposes of satisfying its obligations pursuant to this Agreement 18- to construct, or to be financially responsible for, the 19 construction of any installations or modifications of or 20 additions to transmission or distribution facilities. 21 5. ]!g@tGTIES AND REPPERENTATIONS. 22 The Parties represent and warrant to.each other the 23 following: i 8 I w -
l l f - 1 5.1 DPS Warranties and Reoresentations: ! Is\ ')2 (a) It shall deliver all electricity to MID at the Delivery l 3 Point, with full and unencumbered title, free and clear of any l 4 adverse claims or encumbrances; it shall 5 (b) Throughout the Term of this Agreement, 6 maintain contractual arrangements providing it the rights to forth in 7 fully satisfy its firm delivery obligations as set 8 Section 4.1 of this Agreement; (c) The CATSA has been approved by the FERC and is i!n 9 10 force. If the CATSA is terminated prior to the termination of this Agreement, DPS shall negotiate in good faith with PG&E with 11 12 the intent to timely execute a CATSA Successor. 13 Notwithstanding the warranties and representations set forth in subsections (b) and (c) of this Section 5.1, DPS retains [/}14
\_
the operating discretion to decide whether to purchase firm 15 16 transmission service, energy, or capacity, and the amount of any 17 such firm transmission service, energy, or capacity it may 18 purchase, provided, and subject to the provisions of Section 14, 19 DPS' failure to purchase firm transmission servica, energy, or 20 capacity shall not excuse any failure by DPS to perform its 21 obligations pursuant to Section 4.1.; (d) It is authorized to do business and is doing business 22 23 within the State of California and has the full corporate to this 24 authority to execute and perform its obligations pursuant 25 Agreement; and (~% 9 l
i l 1 1
,.J1 (e) Its representative executing this Agreement has been -- duly authorized to execute such Agreement and to thereby obligate 1 2
3 DPS to perform its obligations hereunder. 4 5.2 MID Warranties and Reoresentations: 5 (a) It is a legislatively-created irrigation district 6 validly organized under the laws of the State of California and 7 is authorized to do business within the State of California; , 8 (b) Its representative executing this Agreement has been l 9 duly authorized to execute such Agreement and thereby to o'bligate I 10 MID to perform its obligations hereunder; and 11 (c) It is a Wholesale electric customer and it warrants it 12 shall maintain and preserve such Wholesale status throughout the 13 Term of this Agreement.
"14 6. DETERMINATIONS OF AMOUNTS SOLD. 'V The determination of the amount of electric capacity: sold to 15 16 MID shall be based on the Monthly Peak Demand as defined in 17 Section 1.18. The determination of the amount of electric energy 18 sold to MID shall be made on a monthly basis by use of the MID These 19 Meter or DPS Installed Equipment subject to Section 10.
20 determinations shall be made on the basis of a billing period 21 which constitutes a calendar month. 22 7. RATES AND CHARGES. 23 MID shall pay DPS the rates and charges provided in Appendix 24 A. 25 26 r~
' 10
1 8. DELIVERIES. l 5 l f~j2 (~ 8.1 Delivery Point: DPS shall deliver the Full MID Linde 3 Substation Wholesale Electric Power Requirements to the Delivery 4 Point, provided that the Parties may mutually agree to change the 5 Delivery Point and/or designate one or more additional points of 6 delivery. 7 8.2 Deliverv Voltace: The electricity to be delivered at 8 the Delivery Point shall be at a nominal voltage of'.115 kV. 9 9. DELIVERY, TITLE AND TRANSMISSION. Passace of
Title:
Title to the capacity and energy 10 9.1 11 shall pass to MID upon its receipt at the Delivery Point. 12 9.2 Control: DPS shall be in exclusive control and as 13 possession of the capacity and energy sold hereunder and, (~N14 between the Parties, shall be responsible for any loss, damage or N] 15 injury caused thereby until such capacity and energp is delivered 16 to MID at the Delivery Point. Upon and after the delivery of 17 such capacity and energy to the Delivery Point, MID shall be in 18 exclusive control and possession of such capacity and energy and, 19 as between the Parties, shall be responsible for any loss, damage 20 or injury caused thereby. As 21 9.3 Transmission and Distribution Responsibilities: 22 between the Parties, DPS shall be responsible for all costs and 23 arrangements necessary to deliver the electricity to the Delivery 24 Point. As between the Parties, MID shall be responsible for all 25 costs and arrangements necessary to deliver the electricity 26 beyond the Delivery Point. (3 V l
- . . -- - . . _-.._-_ .~ . _ - _ - . . p1 10. METERING AND TELECOMMUNICATION. MID shall 2 10.1 Ecuioment Installation and Maintenance: 3 procure and install the meters and other facilities, including 4 but not limited to electrical meters, RTUs and SSRs, necessary 5 and appropriate for accurately and efficiently metering the 6 receipt of electricity at the Delivery Point. 7 MID shall provide DPS and PGEE access to its meters and . 8 other facilities, and take (or permit DPS and PG&E to take) such other action as reasonably necessary to ensure that the real-time i 9 10 data relied upon by DPS for ie.s operations is the same , 11 information PGEE will use to determine DPS's compliance with the CATSA generally and, in particular, Sections 3 and 4 of the 12 l 13 CATSA. In the event the 14 10.2 Meter Testi_nc and Meter Errors: 15 metering equipment reliec' cpon by DPS to prepare a DPS Monthly 16 Invoice fails to properly register, or if the measurement made by 17 the metering equipment during a test varies by more than two 18 percent (2%) from the measurement made by the standard meter used in the test, the Parties shall determine and apply an adjustment 19 20 with the objective to best correct all measurements recorded by 21 the inaccurate metering equipment. make any 22 DPS shall promptly, with the concurrence of MID, 23 necessary correction in a DPS Monthly Invoice in accordance C th correction in the DPS Monthly Invoice shall 24 Section 11. Suc% 25 constitute full adjustment of all claims between the Parties 26 arising out of such inaccuracy of the metering equipment 12
1 l l l l measurement. No adjustment of a DPS Monthly Invoice for meter n N '2 l' error shall be for a period in excess of'six (6) months time nor ; for a DPS Monthly Invoice more than six (6) months past. DPS ; 3 4 shall maintain all measurement and metering information for a l 5 period of twelve (12) months, and shall provide MID with I
- 6 reasonable access to such data.
7 10.3 Metered Data Adiustments: If' applicable, metered data; 8 will be adjusted to include a mutually agreed upon loss factor. , 9 This' factor will compensate'for system losses between the
- 10. Delivery Point and the metering point. ;
11 10.4 Removal of DPS Ecuiement: At the termination of the 12 Agreement, DPS shall have the right, at DPS' discretion and at 13 its sole cost,,to remove all or any portion of the DPS Instelled
/~S$4 Equipa*r.t ; provided that DPS shall promptly repair any damage to
- b. other facilities resulting fr'om said removal.
15 , 16 11. BILLING m PAYlMNT. 11.1 DPS Monthly Invaice: DPS or its agent shall prepare , 17 P.O. Box 4060, 18 and submit an invoice to MID Accounts Payable, 19 Modesto, CA 95352, shortly after the first day of each calendar 20 month for electric power deliveries made under the Agreement MID shall 21 during the preceding month ("DPS Monthly Invoice") . 22 pay the amount due on each DPS Monthly Invoice by a wire transfer 23 within thirty (30) Calendar Days following MID's receipt of the
.24 DPS Monthly Invoice, or, if that 30th day is a Saturday, a 25 Sunday, or a legal Holiday, tne next working day (" Payment Due l
!O 13
1 1 Date"). If MID questions a DPS Monthly Invoice, it may review
\ 2 the back-up data used in preparation of the DPS Monthly Invoice.
3 11.2 Estimated Billinas: If charges under this Agreement 4 cannot be determined accurately for preparing a DPS Monthly 5 Invoice, DPS or its agent may estimate such DPS Monthly Invoice based on reasonably available information including, but not 7 limited to, records of historical usage, physical condition of , the metering facility, and available meter readings, Such 8 9 estimated DPS Monthly Invoice shall be paid by MID in acco'rdance 10 with section 11.1. When final and complete information becomes to the extent 11 available, DPS shall promptly prepare and submit, Any 12 necessary, an adjusted DPS Monthly Invoice to MID. 13 additional payment or refund, including any applicable interest 14 in accordance with Section 11.4, shall be made as appropriate. 11.3 Payment Discutes: If MID contests any portion of a DPS 15 16 Monthly Invoice, as soon as practicable, it shall provide DPS MID shall also, not 17 written notice of the charges it disputes. 18 later than the Payment Due Date,.either pay the DPS Monthly 19 Invoice in full "under protest" or pay the uncontested portion 20 and deposit the contested portion in an escrow account with an 21 escrow company to be agreed upon by the Parties; provided, 22 however, that a dispute between either DPS or MID and any Third any portion 23 Party shall not be a proper basis for MID to contest 24 of the DPS Monthly Invoice; and provided further that MID may withhold payment from DPS for any power which PG&E may deliver to 25 The Parties will 1 26 MID pursuant to the PGEE Linde Substation IA. O 14 1 l l
4 1 enter into an agreement for.the management of any such funds in 2 escrow. , 1 3 11.4 Interest: Any refund, or any amount due under this , 4 Agreement which is noe, paid by the Payment Due Date or when 5 otherwise due (collectively the " Payment Due Dates") shall accrue 6 interest from the Payment Due Dates, or in-the case of a refund, 7 the date of the initial payment, until the date at which the , applicable payment or refund is made. The interest: rate 8 I 9 applicable to any payments paid after the Payment Due Dates or to 10 any refund shal) be the lesser of the maximum rate permitted;by 11 law or the prime rate as published in the Wall St'reet Journal on 12 the first Monday of each month, as applicable, plus two percent i 13 (2%) per annum. The applicable interest rate shall be. prorated by days: (a) from the Payment Due Dates to the date payment is ( )14 in the case of a refund, from the date of the 15 received; or (b) 16 initial payment until the date the refund is received. 17 12. ADVERSE REGULATORY DECISION. 18 If the FERC or kr.y other regulatory body or agency or any court of competent jurisdiction (" Governmental Entity") orders or 19 20 decides that this Agreement be interpreted, modified, or extended 21 in a manner such that DPS would be adversely affected by being 22 required to extend its obligations under this Agreement to Third 23 Parties, or to incur new or different obligations to MID or Third i including, without l 24 Parties not contemplated by this Acreement, 25 limitation, any decision that DPS would be regulated as a. utility
~
26 in a mannar beyond its obligations as a FERC power marketer or to 15
l l I l t 1 charge MID at rates lower than set forth in Appendix A; or such l l 2 that MID would be adversely affected by the FERC ordering DPS to 3 charge MID at rates higher than as set forth in Appendix A or by 4 a Governmental Entity issuing an order or decision which restricts, reduces, or eliminates MID's authority to purchase j 5 ) 6 power on a Wholesale basis at the MID Linde Substation or to sell ! 7 power to MID customer taking service from the MID Linde i 8 Substation; then upon the adversely affected Party providing the l 9 other Party with prompt and timely notice of such adverse' order 10 or decision, and subject to the terms and provisions of this; 11 Section 12, both Parties shall be relieved of their respective 12 obligations hereunder to the extent necessary to eliminate the 13 effect of that adverse order or decision. l Upon the sending of a notice of any such adverse order or ( )14 15 decision, the Parties shall attempt to renegotiate the terms and 16 conditions of this Agreement with the intent to maintain DPS' 17 firm obligation to deliver the Full MID Linde Substation 18 Wholesale Electric Power Requirements in accordance with Section 19 4.1 and to restore the original balance of benefits and burdens 20 contemplated by the Parties as of the Effective Date. 21 In the event that MID is the adversely affected Party for 22 purposes of this Section 12 because a Governmental Entity issues 23 an order or decision relating to its Wholesale electric status 24 for its sales from the MID Linde Substation, the Parties agree to 25 revise this Agreement with the business objective to enable DPS 26 to sell to MID, and MID to purchase from DPS, MID's resulting 16 I
4-1 , i Full MID Linde Substation Wholesale Electric Power Requirements. 2 2 In the event that DPS is the adversely affected Party and 3 the Parties cannot renegotiate this Agreement to their. mutual i f 1 4 satisfaction and in accordance with the above guidelines, within 4 l -5 ninety (90) days after the date of DPS providing notice of such , i j 6- adverse order or decision, DPS may at any time thereafter give i 7 MID written notice of termination, which termination shall be 1 j 8 ef fective within thirty (30) days of such notice.
- a, . \
9 13. NOTICES. I f 10 13.1 Formal Notices: Any notice, request, demand, , l l 11 information, report er item otherwise requ. ired, authorized or l
- 12 provided for in this Agreement shall be given in writing, except i
13 as otherwise provided pursuant to Section 13.2, and shall be deemed' properly given if delivered in person, by recognized ( 14 15 overnight carrier, or sent by United States first class mail, 16 postage prepaid, to the persons specified below: 17 To DPS: 18 Destec Power Services, Inc. 19 1676 North California Blvd., Suite 400 20 Walnut Creek, CA 94596 21 Attn: General Manager, Western Operations 22 Telephone: (510) 746-5279 23 Facsimile: (510) 746-5240 24 25 With a copy to: 26 27 Destec Power Services, Inc. 28 2500 CityWest Bldg., Suite 150 29 Houston, TX 77042 30 Attn: DPS Legal Representative 31 Telephone: (713) 735-4000 32 Facsimile: (713) 735-4201 33 34 035 17
4 ? ,
^% To MID:
i
-(_,$ Modesto Irrigation District !
. 3
'4 P.O. Box 4060 1231 Eleventh Street 5 l 6 Modesto, CA 95354 7 Attn: Allen Short ;
'8 Telephone: (209) 526-7405 '
9 Facsimile: (209) 526-7315 10 11 . With a copy to: 12 , 13 Roger Van Hoy~ 14 P.O. Box 4060 15 1231 Eleventh Street i 16 Modesto, CA 95354 17 Telephone: (209) 526-7454 18 Facsimile: .(209) 526-7575 : 19 20 21, 13.2 Routine Notices: Any notice of.a routine character in 22 connection with service under this Agreement shall be given in 23 such a manner as the Parties may determine from time to time, such as facsimile or telephone, unless otherwise provided in this ( $4
-l 25 Agreement.
Any Party may change the 26 13.3 Chance of Notice Recioient: 27 designation of any person who is to receive a notice on its 28 behalf by giving the other Party notice thereof in the manner 29 provided in Section 13.1. 30 14. FORCE M TEURE. 31 No Party shall be considered to be in breach of, or in. 32 default in the performance of, any obligation under this or MID's 33 Agreement (other than an obligation to make payment,
- 34- obligations in Section 4.2 to purchase its Full MID Linde or MID's 35 Wholesale Electric Power Requirements from DPS, when a failure of performance shall
- 36 obligations in Section 4.3) 18
f-~g be the result of " force majeure," as defined herein. The term U2 " force majeure" for purposes of this Agreement shall mean any 3 cause or causes beyond the control of the Party unable to perform 4 such obligation, including, but not limited to, failure of 5 facilitieslof Third Parties (other than DPS suppliers), any 6 interruption or curtailment of transmission service by PG&E or a 7 Third Party of power to be delivered to MID under this Agreement 8 (provided that such' interruption or curtailment is not caused by 9 DPS' failure to obtain firm transmission service necessary to
.10 deliver the Full MID Linde Wholesale Electric Power Requirements 11 to the Delivery Point), any interruption or reduction of service 12 by PGEE as it may be authorized by the PGEE Linde Substation IA i 13 or the CATSA, or a CATSA Successor, flood, earthquake, storm,
( h4 drought, fire, pestilence, lightning and other natural 15 catastrophes, epidemic, war, riot, civil disturbance or ' 16 disobedience, sabotage, strike, lockout, labor disturbance, labor 17 or material shortage, government priorities and restraint by 18 court order or public authority, any of which by exercise of due 19 diligence such Party could not reasonably have been expected to 20 avoid and which by exercise of due diligence it has been unable to overcome. Nothing contained in this Section shall be i 21 lockout or 22 construed as requiring a Party to settle any strike, 23 labor dispute in which it may be involved. 24 15. DEFAULT. 15.1 Default by MID for Non-Pavment: Subject to the - 25 26 provisions of Section 11.3, MID's failure to pay to DPS any DPS I ( 19
Monthly Invoice (or, if applicable, to an escrow account) at any ,r si)
'2 time after the Payment Due Date and within ten (10) days after 3 DPS has provided MID a notice of late payment shall constitute a 4 default of this Agreement by MID for which DPS may, among other 5 remedies, terminate this Agreement in accordance with the 6 provisions of Section 15.4.
7 15.2 Default by MID for Breach of Full Wholesale . If MID breaches its obligation 8 Recuirements Purchase Oblication: 9 in Section 4.2 to purchase its Full MID Linde Substation 10 Wholesale Electric Power Requirements from DPS pyrsuant to this 11 Agreement and it fails to cease such conduct within five (5) 12 business days of receipt of a demand by DPS to cease such 13 unauthorized Wholesale purchases, MID shall be in default of this seek specific Agreement and DPS may, among other remedies, A)14 ( 15 performance of MID's obligation hereunder to purchase the Full 16 MID Linde Substation Wholesale Electric Power Requirements and/or 17 terminate this Agreement in accordance with the provisions of 18 Section 15.4. 19 15.3 Default by DPS of CATSA or_CATSA Successor Oblications: (" Suspension 20 (a) In the event that PG&E suspends service 21 Date") under the CATSA in accordance with Section 7.5 of the 22 CATSA or under an analogous provision of a CATSA Successor ("CATSA Suspension"), and MID is accordingly purchasing its Full 23 24 MID Linde Substation Wholesale Electric Power Requirements from and 25 PG&E pursuant to a provision in the PG&E Linde Substation IA, and 15.3 (c) of this 26 subject to the provisions of Sections 15.3 (b) 20
i 1 Agreement, DPS shall be in default of this Agreement and MID may, I 2 among other remedies, terminate this Agreement upon written
'3 notice to DPS.
4 (b) Section 15.3 (a) notwithstanding, in the event of a CATSA 5 Suspension, DPS shall not be in default of, and MID may not 6 terminate, this Agreement for a period of sixty (60) days after l the Suspension Date, provided PG&E has not at any such time 7 8 terminated the CATSA in accordance with Section 8.2.'1 of the CATSA or under an analogous provision of a CATSA Successor, j 9 10 (c) Section 15.3 (a) notwithstanding, in the svent of a CATSA l i 11 Suspension, DPS shall not be in default of., and MID may not; 1 12 terminate, this Agreement if PGEE provides notice to MID within j I 13 60 days after the Suspension Date that it has reinstated service 4 under the CATSA or the CATSA Successor. 15 15.4 Termination for Default: Except as otherwise expressly
)
16 provided herein, if either Party defaults in its obligations under this Agreement, the other Party may terminate this 17 18 Agreement by providing the defaulting Party with written notice 19 stating: i) the Party's intent to terminate; ii) the date of the 20 intended termination; iii) the specific grounds for termination; iv) the specific actions which the defaulting Party must take to 21 l l 22 cure the default; and v) a reasonable period of time within which 23 the defaulting Party may cure the default and avoid termination; 24 provided that in the context of a default by MID pursuant to Section 15.1, the reasonable period in which DPS may offer MID to 25 26 cure need not exceed five (5) calendar days; in the context of a 21
I f s1 default by MID, pursuant to Section 15.2, the reasonable period i 6
2 DPS may offer MID to cure need not exceed five (5) business days.
3 16. TERMINATION. 4 16.1 Grounds for Termination: This Agreement shall 5 terminate in'accordance with any of the following: 6 (a) the provisions of Section 2; or 7 8 (b) the provisions of Section 12; or . 9 10 (c) the provisions of Section 15.3 (a) ; or 11 12 (d) the provisions of Section 15.4; or i l 13 l 14 (e) the provisions of Section 16.2; of: l 15 in the event an act or omission by DPS has caused l 16 (f) 17 the PG&E Linde Substation IA to terminate, MID may 18 terminate this Agreement by providing DPS thirty , 19 (30) days written notice of its intent to l 20 terminate this Agreement pursuant to this Section l 16.1(f). In the event an act or omission by MID 7_s 21 has caused the PG&E Linde Substation IA to { 32 terminate, DPS may terminate this Agreement by , N -23 l 24 providing MID thirty (30) days written notice of to 25 its intent to terminate this Agreement pursuant 26 this Section 16.1(f) . 27 28 16.2 Termination for Neolicible Electricity Recuirements: 29 DPS may terminate this Agreement upon providing MID thirty (30) 30 days written notice in the event that the Full MID Linde l 31 Substation Wholesale Electric Power Requirements are less than 1 32 MWh for six (6) consecutive months or more. With respect to any grounds for 33 16.3 Additional Remedies: and with respect to 34 termination specified in Sections 15 or 16.1, the 35 any breach or default of this Agreement by either Party, 36 other Party shall be entitled to pursue any applicable legal, including the right
, 37 equitable, or regulatory rights and remedies, N] 22
f-s1 of each Party to seek specific performance or a declaration of b 2 the respective rights the Parties may have in response to a 3 breach or default by the other Party, or in response to a claim 4 of alleged breach or default upon a Party. 5 17. INDEMNIFICATIQ_N,. 17.1 Indemnification bv DPS: DPS shall indemnify and hold 6 7 harmless MID, its directors, officers, employees, agents, and 8 insurers from and against any and all costs, expenses, injuries, 9 damages, liabilities, claims, losses, and reasonable attorney 10 fees and court costs (altogether the " Costs"), in: curred or to be 11 incurred by MID and directly or indirectly. arising out of DPS' 12 ownership of power sold and delivered to MID hereunder, or DPS' 13 acts or omissions, or its breach of its representations, warranties, or obligations hereunder, except to the. extent that (K4 such Costs are attributable to the negligent or intentional acts 15 16 or omissions of, or the breach of this Agreement by, MID or its 17 representatives, employees, agents or contractors. 18 17.2 Indemnification by MID: MID shall indemnify and hold 19 harmless DPS, its successors and assigns, and its respective 20 directors, officers, affiliates, suppliers, employees, agents, 21 and insurers ("the DPS Indemnitees") from and against any and all 22 Costs, incurred or to be incurred by any DPS Indemnitee and ownership, 23 directly or indirectly arising out of MID's purchase, 24 receipt, sale, or use of power sold to MID hereunder, or MID's 25 acts or omissions, or its breach of its representations, that 26 warranties or obligations hereunder, except to the extent 23
. . . . - .- - - -. . - . - .. . ~ . - - - . - . -
i gyg1 such Costs are attributable to the negligent or intentional acts r
\m ,/ or omissions of, or the breach of this Agreement by, DPS or its i
2 : l 3 representatives, employees, agents or contractors. l 4 17.3 MID's Indemnification of DPS for Interruotion or 5 Curtailment of Serviqa: MID shall indemnify DPS for any claim, : l demand, liability, loss or damage asserted by a Third Party, { ! 6 j 7 whether direct, indirect or consequential, which results from the 8 interruption or curtailment of electric service to a Third Party. . 9 18. LIABILITY. 10 18.1 To Third Parties: Nothing in this Agreement shallfbe 11 construed to create any duty to, any standard oficare with j 12 reference to, or any liability to any Third Party. 18.2 Between Parties: Each Party is liable to the other for 13 any loss, damage,. claim, cost, charge or expense arising from a ( )14 15 failure to perform as specified under the terms provided in this l 16 Agreement, provided such failure is not excused as provided for 17 in Section 14, with full recourse to the Parties at law and 18 equity. Notwithstanding the preceding sentence, under no 19 circumstances shall DPS or MID be liable to the other for any l or 20 exemplary, indirect, consequential (direct or' indirect), 21 incidental damages under this. Agreement. As between the Parties, each 22 18.3 Protection of Facilities: 23 Party shall be responsible for protecting its electric facilities 24 from possible damage by. reason of electrical disturbances or 25 faults caused by the op'eration, faulty operation, or non-26 operation of any Third Party's facilities, and the other Party l i ! 24
1 ~,
,e shall not be responsible for, nor liable for, any such damages so
-1! caused.
3 19. GOVERNING LAW, 4 This Agreement shall be interpreted, governed by, and 5 construed under the laws of the State of California or the laws I 6 of the United States, as applicable. 7 20. ASSIGNMENT. ) 20.1 Assianment by Consent: No transfer or assignment of 8 9 all or any part of either Party's rights, benefits or duties 10 under this Agreement shall be effective without the prior written 11 consent of the other Party, provided such consent shall not be unreasonably withheld. Notwithstanding the above, DPS' 12 to 13 assignment of its rights and obligations under this Agreement , a parent company, the parent of a parent, or to an affiliated ( )4 15 company which is wholly owned by DPS' parent or a parent of a 16 parent shall not be subject to this provision. The transferor or assignor of 17 20.2 Assioner Oblications: i 18 all or any part of any right or benefit under this Agreement 19 shall continue to be obligated by its terms and conditions in the 20 event its successor, transferee or assignee fails to perform as 21 required by the Agreement. Any successor to or transferee f 22 20.3 Assionee Oblications: l 23 or assignee of the rights of a Party, whether by voluntary 24 transfer, judicial sale, foreclosure sale, or otherwise, shall be 25 subject to all terms and conditions of this Agreement to the same f
&/ 25
r >1 extent as though such successor, transferee, or assignee were an U 2 original Party. 3 21. MISCELLANEOUS. 4 21.1 Amendments: This Agreement may be amended only by a l 5 writing signed by both Parties hereto. The 6 21.2 Amendments Related to PG&E Linde Substation IA: 7 Parties recognize that the terms and conditions of the PG&E Linde Substation IA to be executed may require certain amendments be 4 8 9 made to this Agreement to appropriately coordinate this Agreement The Parties pgree to . 10 with the PG&E Linde Substation IA. 11 negotiate in good faith and execute any amendments necessary to 12 appropriately coordinate this Agreement and the PG&E Linde 13 Substation IA; provided neither Party shall be obligated to execute any such amendment which would materially alter the O ( )14 15 relative benefits and burdens agreed to by the Parties in this 16 Agreement. 21.3 Cautions: All indexes, titles, subject headings, 17 18 section titles and similar items are provided for the purpose of 19 reference and convenience and are not intended to affect the 20 meaning of the contents or scope of the Agreement. 21 21.4 Confidentiality: MID agrees in good faith to discuss if any, this 22 with DPS whether and under what circumstances, 23 Agreement, and/or any of the information contained herein and/or 24 generated and maintained during its administration, may be 25 disclosed by MID to any person. O 26
. _ _ 7
,-41 21.5 Construction of Aareement: Both Parties have significantly contributed to the drafting of this Agreement. Any 2
-3 ambiguities or uncertainties in the wording of this Agreement 4 shall not be ct.tstrued for or against either Party.
5 21.6 Information: Either Party shall provide the other, 6 upon request, the appropriate information and documentation 7 reasonably necessary to fulfill.the obligations that either Party 8 has agreed to undertake pursuant to this Agreement. 9 21.7 Intecration: The Parties agree that the provisions of 10 this Agreement and its Appendices constitute the pntire agreement 11 between the Parties regarding DPS' sale and delivery of the Full 12 MID Linde Substation Wholesale Electric Requirements, and the thereto. 13 Parties' respective rights and obligations with respect 14 No representations covenants, or other . natter, oral .or written, [~ % / f 15 not expressly set forth, incorporated, or referenced in this 16 Agreement shall be a part of, modify, or affect this Agreement; 17 provided, however, that this Agreement may be modified in 18 accordance with the provisions of Section 21.1. 19 21.8 No Partnershio: This Agreement does not create a 20 partnership or joint venture or a cooperative association between i 21 DPS and MID. 22 21.9 No Third-Party Beneficiaries: No right or obligation 23 contained in this Agreement shall be applied or used for the j 24 benefit of any person or entity not a Party except as i 25 specifically stated herein. 1 I O 27 i
The Parties shall cooperate 21.10 Coeratina Procedures: 2 in establishing such mutually agreeable operating procedures as 3 they shall both determine are necessary in the performance of 4 this Agreement. 21.11 Waiver of Richts: A waiver ef a Party's rights shall' 5. not be implied under this Agreement. Any waiver at any time by 6' any Party of its rights'with respect to a default under this' 7 8 Agreement, or with respect to any other matter arising in 9 connection with this Agreement, shall not constitute or be deemed 10 a waiver with respect to any subsequent, default qr other matter 11 arising'in connection with this Agreement. 12 21.12 Comoliance with Aeolicable Laws and Reculations: This Agreement, and the undertakings and obligations of the 13 14 Parties thereto, shall be subject to all applicable laws.and 15 regulations issued by authorities having' jurisdiction over the 16 Parties and the activities herein contemplated. O 28
l 1 2 -IN WITNESS WHEREOF, DPS and MID hereby enter into this 3 Agreement, as of the date set out above. 4 5 DESTEC POWER SERVICES, INC. MODESTO IRRIGATION DISTRICT 6 9 By: Uc - + ME By: I g 10 11 Name: Walter G. Homan W Name: Allen Short 12
Title:
General Manager 13
Title:
Vice President and i l 14 and General Manager . 15 Date: March 21 , 1996 16 -Date: March 1 , 1996 17 18 19 20 21 b V ! 29
i 1 Anoendix A U 2 3 A.1 MONTHLY PAYMENT 4 MID shall monthly pay DPS a Monthly Payment in an amount 5 equal to the sum of the Monthly Demand Charge and the Monthly 6 Energy Charge as applicable. The calculation for each celendar 7 year's rate shall be performed by the end of each January for 8 said year (notwithstanding the 1996 rate). 9 A.1.a Monthly Demand Charae shall be 10 The Monthly Demand Charge MID shall pay; DPS 11 calculated in accordance with the following formula: 12 l 13 Total Monthly Demand Charge = ((Minimum (Interruptible Nomination 14
- Interruptible Demand Rate 15 (kW), Monthly Peak Demand (kW)) j 16 ($/kW-mo.)) + (((Maximum (Monthly Peak Demand (kW), Interruptible (kW)))
- Non-Interruptible Nomination 17 Nomination (kW))) -
18 Interruptible Rate ($/kW-mo'.)) l 19 20 Where; f 21 Interruptible Nomination = Interruptible amount per 22 section A.1.d. 23 Monthly Peak Demand = Peak Demand as calculated per 24 section 1.18. 25 Interruptible Demand Rate = Interruptible Demand Rate as 26 calculated per section A.1.c. 27 Non-Interruptible Rate = Non-Interruptible Demand Rate 28 as calculated per section 29 A.1.b. 30 31 32 A.1.b Non-Interruptible Demand Rate shall be Non-Interruptible Demand Rate (S/kW-mc.) 33 The 34 calculated in accordance with the following formula: O == 1
1 l l' Non-Interruptible Demand Rate '($/kW-mo.) = Minimum (Non-2 Non-Interruptible Interruptible Cap Demand Rate ($/kW-mo.), 3 4 Ongoing Demand Rate ($/kW-mo.)) 1 5 6 Where; i 7 8 9 Non-Interruptible Cap Rate = j 10 s/kW-mo. i 11 1996 6.15 ! 12 1997 6.28 I 13 1998 6.41 I i 14 1999 6.53 , 15 2000 6.66 - 1 16 2001 6.80 , , 17 18 19 and; 20 21 = 22 Non-Interruptible Ongoing Demand Rate Year (X) ($/kW-mo.) l 23 Maximum (Non-Interruptible Basic Demand Rate Year (X) ($/kW-mo.), C$ 24 Non-Interruptible Market Demand Rate Year (X) ($/kU-mo.)) V 25 26 Where; 27 28 = 0.68 * ((2
- 29 Non-Interruptible Basic Demand Rate Year (X) 30 Excess Demand Charge Year (X)) + Firm Contract Demand Charge Year ;
31 (X) ) / 3.0825 32 ! 33 Where; 34 Excess Demand Charge Year (X) = The then current Excess Demand 35 Charge (in $/kW-mo.) in the 36 GS-4 tariff effective (e.g. 37 MID Board approved) as of 38 January 15 of Year (X). 39 40 Firm Contract Demand Charge The then current Firm Contract 41 Year (X) = Demand Charge (in $/kW-mo.) in 42 the GS-4 tariff effective 43 (e.g. MID Board approved) as 44 39196\?D0051.APA
,'% San Franamen/3.25 96 2 j
. . - = - .. _ . - - -- - - . . - . ~ . - - . . . -
5 of January 15 of Year (X). l (~. 3 3 and; 4 5 Non-Interruptible 6 Non-Interruptible Market Demand Rate (X)= 7 Market Demand. Rate Year (X-1) + ((Futures Price for Year (X)
- 8 Futures Price for Year (X-1))
- 196.24)).
9 10 Where; , 11 12 The Non-Interruptible Market 13 Demand Rate for Year (X=1996) = $5.69/kW-mo. , l 14 Non-Interruptible Market 15 Demand Rate for Year (X-1) = Year.(X-1) Non-Interruptible 16 - 17 Market Demand Rate. 18 Futures Price for Year (X) = Year (X-1) Futures. Price ~ 19 20 stated in units of'$/kWh
= Year (X-1) year's Futures 21 Futures Price for Year (X-1) Price stated in units of 1 22 1 23
$/kWh.
1 26 Where; 27 28 29 Futures Price shall be stated in $/kWh. 30 31 Futures Price f or Year (X=1996) shall be calculated in 32 accordance with the following formula: 33 34 Futures Price for Year (X=1996) = ($50.875/MWh + June + July 35 + August + September + October.+ November + December)/12,000 36 i 37 Where; 38 June through December = The April 3, 1996 settlement prices as 39 April 4, 1996 for the 40 published in the Wall Street Journal on l 0
' 7n"S 7*
3 i
l 1 NYMEX COB Electricity Futures Contracts for the months of June
\ 2 through December of 1996. Should a month not be available for 3 inclusion to complete the Futures Price for Year (X=1996) l 4 calculation, the first available settlement price for the month 5 shall be used.
6 7 The Futures Price for calendar years 1997, 1998, 1999, 2000; 8 and 2001 shall be calculated in the following manner: 9 of tne Futures Price for Year (X) = the simple average 10 11 settlement prices from the first Wednesday in November of; Year 12 (X-1) of the twelve NYMEX CCB Electricity Futur'es Contracts of 13 Year (X) as published in the Wall Street Journal on the first 14 Thursday in November of Year (X-1) . 15 16 17 Where; 18 York Mercantile Exchange or its 19 "NYMEX" is the New
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20 successor; 21 22 " COB Electricity Futures Contract" is the NYMEX contract for 23 firm electric energy bought and sold for future delivery on 24 the- exchange with delivery at the California Oregon Border Trading as approved by the Commodity Futures 25 (COB), ; 26 Commissior.. 27 28 In the event that NYMEX COB Electricity Futures Contract 29 settlement prices become unavailable, the Futures Price for Year 30 (X) shall be calculated in November of Year (X-1) based on the 31 simple average of the bid and offer prices of COB price postings 32 for on peak firm electric power for Year (X) by two recognized 33 brokers; each Party shall have the right to select one broker, 34 provided such broker-shall have received a significant portion of 39196200051 APA i San Franciscor315 96 4 l l
1 its revenues in the prior twelve (12) months from engaging in
2 such brokering of electric power activities. "On peak" means the 3 peak sixteen (16) hours of each day of the peak six (6) days of 4 each week. )
5 6 A.1.c. Interruotible Demand Rate 7 The Interruptible Demand Rate ($/kW-mo.) shall be calculated 8 in accordance with the following formula:
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9 10 Interruptible Demand Rate ($/kW-mo.) = Minimum (Interruptible Cap 11 Demand Rate ( 5, al-mo . ) , Interruptible Ongoing Demand Rate ($/kW-l 12 mo.)) ) 13 14 Where; 15 Interruptible Cap Demand Rate = ( ) 16 17 l 18 $/kW-mo. 19 Summer 1996 3.69 20 1997 3.81 21 1998 3.94 22 1999 4.07 23 24 2000 4.20 25 2001 4.34 26 27 28 and; 29 Interruptible ongoing Demand Rate Rate Year (X) ($/kW-mo.) = Maximum 30 Year (X) ($/kW-mo.), 31 (Interruptible Basic Demand 32 Interruptible Market Demand Rate Year (X) ($/kW-mo.)) 33 34 35 Where; 36 YOSu 5
1 1 Interruptible Basic Demand Rate Year (X) = 0. 68 * (((2
- Excess
,32 Demand Charge Year (X)) + Firm Contract Demand Charge Year ]
[V 3 (X))/3.0825 - Interruptible Credit Year (X)) 4 5 Where; , 6 l 7 Excess Demand Charge Year (X) = The then current Excess Demand 8 Charge (in $/kW-mo.) in the 9 GS-4 tariff effective (e.g. 10 MID Board approved) as of j 11 January 15 of Year (X). . 12 J 13 Firm Contract Demand Charge 14 Year (X) = The then current Firm Contract 15 Demand Charge (in S/kW-mo.) in 16 the GS-4 tariff effective 17 (e.g..MID Boardiapproved) as ( 18 of January 15 of Year (X). 19 Interruptible Credit Year (X) = The then: current Interruptible l 20 21 Credit (in $/kW-mo.) in the GS-4 Tariff effective (e.g. 22 MID Board approved) as of 23 January 15 of Year (X). 24 27 and; 28
= Non-Interruptible 29 Interruptible Market Demand Rate Year Interruptible (X) Credit Year (X)
- Market Demand Rate Year (X) 30 31 0.629.
32 33 34 Where; 35 36 = 37 Interruptible Market Demand Rate for Year (X=1996) 38 S3.42/kW-mo. A.1.d Interruptible Demand 39 will be equivalent to the DPS's interruptible rights 40 41 interruptible rights as described in Section 10 Interruptible 42 Demand of the MID GS-4 tariff. MID can not nominate more 39196200051 APA r\ San Francuco125 96 6
I interruptible demand than MID can equivalently interrupt at the 1 c 1 ( non-binding Substation. MID will provide DPS a 2 MID Linde 3 estimate of the expected MID interruptible demand nomination for 4 the Summer Period of each Year (X) by November of Year (X-1) MID will submit in writing by 5 during the term of this Agreement. 6 the end of the last business day of April of Year (X) its binding 7 Interruptible Nomination (in kW) for the Summer Period of Year 8 (X). The Winter Interruptible Nomination for each Winter Period 9 of this agreement shall be 0 kW. 10 A.1.e Monthly Enerav Charae 11 The Monthly Energy Charge shall equal. the sum of the Energy 12 Charges for each Time Period. The Monthly Energy Charge for each 13 Time Period shall be the product of the Energy Rate for each time d for each
, O 14 period and the sum of the energy delivered (in kWh) l Q 4 15 period per each month.
16 The applicable Energy Rate for each Time Period in 1996 . 17 shall be: 18 Winter Billina Months $0.0240 19 On Peak kWhs (per KWh) 20 Off Peak kWhs (per kWh) $0.0160
- 21 22 Summer Billina Months $0.0360 23 On Peak kWhs (per kWh) 24 Partial Peak kWhs (per kWh) $0.0307 25 Off Peak kWhs (per kWh) $0.0173 2d 27
[ 28 29 The applicable Energy Rate for each Time Period in calendar 30 years 1997, 1998, 1999, 2000, and 2001 shall be calculated in 31 accordance with the following formula: US$!*s 7
l \ \ l 1: 2 Energy Rate for each Time Period = Minimum (Cap Energy Rate, 3 Ongoing Energy Rate) , 4 1 5 Where; ' 6 7 Cap Energy ?. ate equals: ' 1229, 1999 2000 29.91 Winter Billina Months 1R22
$0.0254 $0.0259 $0.0264 On Peak kWhs (per kWh) $0.0245 $0.0250 t
Off Peak kWhs (per kWh) $0.0163 $0.0166 $0.0170 $0.0173 $0.0177 l . Summer Billina Months $0.0382 $0.039.0 $0.0398 On Peak kWhs (per kWh) $0.0367 $0.0374 ;
$0.0320 $0.0326 $0.0333 $0.0339 Partial Peak kWhs (per kWh) $0.0314 $0.0187 $0.0190 Off Peak kWhs (per kWh) $0.0176 $0.0181 $0.0183 l 8
! 9 10 and the ongoing Energy Rate is calculated follows: l O.11 Ongoing Energy Rate = Maximum (Basic Energy Rate, Market Energy 12 j 13 Rate) 14 15 16 Where; 17 18 Basic Energy Rate = Energy Charge
- 0.80 19 20 Where; 21 Energy Charge = Energy Charge in the GS-<. tarife effactive 22 23 (e.g. MID Board approved) as of January 15 of Year (X) for each 24 Time Period.
l 25 26 27 and; 28 I l 29 The Market Energy Rate for any Year (X) shall be stated in i l M19@@00051 APA San Francisco'37.5 96 8
.._.___._.._ ___ ~ _ ._ ._.__. ._.-.____ _ _____._ _ _
I 1 units of $/kWh and shall be calculated in accordance with the O 2 .following formula: 3 4 Market Energy Rte for Year (X) = Market Energy Rate for Year 5 (X-1) + (0.75 * (Futures Price for Year (X) - Futures Price for 6 Year (X-1)). 7 8 Where; .
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9 l
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10 Market Energy Rate for 1996 = l I 11 Winter Billina Months: 12 On Peak kWhs (per kWh) $0.0222 13 Off Peak kWhs (pe r kWh) $0.0148 , 14 15 sn==er Billina Months: 16 On Peak kWhs (per kWh) $0.0333 17 Partial Peak kWhs.(per kWh) $0.0284 18 Off Peak kWhs (per kWh) $0.0160 19 20 0 2122 A.1.f. Time Periods . l Time Periods are defined as follows: 23 24 Winter (Service from October 1 through April 30): 25 On Peak: 8:00 a.m. to 11:00 p.m. Monday through Friday 26 excluding holidays. 27 Off Peak: All other hours. 28 Summers (Service from May 1 through September 30): , 29 On Peak: 1:00 p.m. to 9:00 p.m. Monday through Friday 30 excluding holidays. l 31 Partial Peak: 8:00 a.m. to 1:00 p.m. and 9:00 p.m. to 32 11:00 p.m. Monday through Friday, excluding holidays. l lO == 9
i l 1 Off Peak: All other hours. 2 Holidays are: New Year's Day, President's Day, Memorial Day, 3 Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and 4 Christmas Day. l l l t e l 9 i b l O 39196@00051 APA San Frenesseor3.25 96 10
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- PEREISSIOg maam m wT BETWEEN TER CITY OF PITTs3ORG l AND MODESTO IRRIGkTION DISTRICT a
16th day l - This Agreement is made and entered into as of the i l-- og Januarr , 1996 by and between the City of Pittsburg, a l municipal corporation (the " City") and Modesto Irrigation [: District ("MID") a California irrigation district and is based upon the fallowing facts: ' } MID desires paraission from the city (1) to use, for A. i j transmitting and distributing ele:tricity, suited for lighting, for use by consumers for any and all lawful purposes other than j lighting, all poles, wires, conduits and appurtenances which may i i hereafter be lawfully placed and maintained by MID in the public j streets and places within the City, and (2) to construct, l maintain and use in said public streets and places all poles., j wires, conduits and appurtenances, including communication
' circuits, necessary to transmit and distribute electricity suited for, and for use by consumers for, any or all lawful purposes.
! 8. City desires to grant paraission to MID for the purposes stated in section A above and to offer City residents an j alternative for obtaining electricity at more competitive rates. , NOW, THEREFORE, the parties agree as follows: i 5 " saetion 1. Authority. ) !* The permission granted under this Agreement shall be l pursuant to Section.22476 of the Water Code. saetien 2. Dafinitions. Whenever in this Agreement the following words or phrases are used, they shall have the following meansng: A. "MID" shall mean Modesto Irrigation District. 1
- 5. " City" shall mean the City of Pittsburg.
j C, " streets" shall mean the public streets, ways, alleys and places as the same now or may hereafter exist within the ! City; including state highways, now or hereafter established within the City, and freeways now or hereafter established within the City. f i " Poles, wires, conduits and appurtenances" shall mean j D. conductors, cables, guys, stubs, {A-poles, towers, supports, wires, platforms, cros sarms, braces, tran j C/, , ducts, vaults, manholes, meters, cutouts, um1wa i pseussion umsomst t i j '
4 i L_ . circuits, appliances, attachments, appurtenances and any other l() property located or to be located in, upon, along, across, under or over the streets of the City, and used or useful in the transmitting and/or distributing of electricity. i l E. " Construct, maintain and use" shall mean to construct, erect, install, operate, maintain, use, repair or replace. i saetion 3. crant and scene of permiamien. l City hereby grants MID permission to and MID hereby accepts from City permission (1) to use, for transmitting and I distributing electricity, suited for lighting, for use by consumers for any and all lawful purposes other than lighting, all poles, wires, conduits, and appurtenances which may hereafter l ' j be lawfully placed and maintained by MID in the public streets and places within the City, and (2) to construct, maintain and use in said public streets and places all poles,. wires, conduits and appurtenances, including communication circuits, necessary to j ~~' transmit and distribute electricity suited for, and for use by l' consumers for, any or all lawful purposesi is hereby granted to l MID, its successors and assigns. i I Baetion 4. Indatarminata. l ' The permission granted under this Agreement shall be indeterminate, meaning said permission shall endure.in full force and effect until the same shall be voluntarily surrendered or abandoned by MID, or until the state or some municipal or public l corporation duly authorized by law shall purchade by voluntary ! agreement,of said permission and situated in the territorial limits of the l state, municipal or'public corporation purchasing such property, l or until said permission shall be forfeited for non-compliance with its terms by MID.- l section 5- ZaAA l l A. During the life of this Agreement, MID shall pay to (14) the City a sum annually which shall bs aquivalent to one percent j-
- of the gross annual receipts above the franchise rate paid to the derived by MID from the s or one-half percent (1/24)
City by PGEE pursuant to the terms (By of City wayFranchise Drdinance of example only, if No. 215CS, whichever is greater. PGEE pays the City an annual franchise rate of it of its gross l ! annual receipts derived from the sale of electricity w { derived from the sale of electricity with City limits.) 3. MID shall file with the City Clark, within three (3) months after expiration of the calendar year, or fractional l() I FEMIn\M kWitMG1
f f i i l omlandar year, following the date of granting this permission, and within three sonths after the exparation of each and every i omlandar year thereafter, a duly verified statement showing in detail the total gross receipts of MID during the preceding calendar year, or such fractional calendar year, from the sale of electricity within the city. MID shall pay to the city within l i fifteen (15) days after the time for filing such statement in lawful money of the United States, the aforesaid percentage of
, its gross receipts for such calendar year, Any or such fractional negloote omission calendar year, covered by such statement.
j, or refusal by MID to file such verified statement, or in pay said ' j percentage at the time and in the manner specified, shall be i grounds for the declaration of forfeiture of this Agreement and i of all rights of MID hereunder. i saetion 6, Non-evelusivitym } The permission granted under this Agreement:shall be non-i exclusive. ! Section 7. Valuction of Parmission. 1 j Th!r puraission shall never be given any value before any court or other public authority in any proceeding of any l character in excess of the cost to MID of the necessary i publicatio'n and any other sua paid by it to the city at the time i this permission is granted. j saetion 8. Reimburaement of costa. MID shall, within 30 days of the effective date of this
- Agreement, reimburse city for the reasonable costs of j
publication, administrative costs and legal fees incurred by the 4 City in connection with granting this permission. Acauisition of MID's Procerty. section 9. f j The permission granted under this Agreement shall in no way impair or affect the right of the City to acquire the property of M1D by purchase or condemnation, and nothing contained in this Agreement shall be construed to contract away, modify or abridge either for a ters or in perpetuity the city's right of eminent - domain in respect to any public utility. Section 10, Payment of Cost of Renairs. MID shall pay to the city on demand the cost of all repairs to public propertyhude necessary by any of the operations of MID under this Agreement. l
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([) RMt 3 W 6 M et!MION assitMsf we w
I i-- l Baction 11. Raincation and Removal of Pales. 1 A, MID shall relocate or remove, at NID's sole expense, 2 any poles, wires, conduits or appurtenances installed, maintained l or used under this Agreement, if and when necessary by any lawful l l obenge of grade, alignment or width of any street by the City, j including without limitation the construction of any subway or viaduct. B. MID shall underground all new facilities in areas properly designated by the City as an underground utility sone,'s J district or similar designation. In those areas in which MID he 4 above-ground facilities and the city later designates that area i i as an underground utility zone, district or similar designation, KID shall underground those facilities consistent with california l l Public Utilities commission Rule 20.
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ametion 12. Transfer of Aaremment. . MID shall not sell, transfer, assign:or lease this Agreament 1 l or any of the rights or privileges granted herein without the l __" ' city's prior written consent. ! Baction 13. ceasliance with Anolicable Lawa,_ () KID s' hall install, maintain and use all poles,, wires, conduits and appurtenances in accordance with applicable laws, j 2 ordinances and resolutions relating to its operation under this Agreement. l i Section 14, Viniation of Aaremment. l 4 I If MID failog neglects or refuses to comply with any of the provisions or conditions prescribed in this Agreement, and does ' not within ten (10) days after written demand for compliance l begin the work of compliance, or after such beginning does not by prosecute the work with due diligence to completion, the city,is its legislative body, may declare the permission granted by th 4 Agreement revoked entirely or partially. l ! neetion 11. yndamnification of city. MID shall defend, indemnify and hold harmless the City, its l officers, employees, and agents from and against liabilithes, anycharges, fines, and all l-l claims, demands, losses, damages, penalties, administrative and judicial proceedings and orders, judgments, remedial actions of any kind, all costs and expenses j incurred therewith, including without limitation, reasonable i attorneys' fees and costs of defenses arising, directly or j indirectly, in whole or in part, out of tbs activities or
; facilities described in this Agreement, except to the extent j
arising from or caused by the intentional or willful misconduct . MWE 4 W 4 P6el1981GI MstfuBWT l 1
i ) or solo negligence of the city, its officers, employees and agente. saaetan is. Effnetive nata. f This Agreement shall become offactive upon execution by the parties. section 17; chaies of 1.aw. This Agreement is governed by and to be construed in i socordance with the laws of the State of California.
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'- m eetion is, waiver.
Waiver of a breach or default under this Agressant shall not l constitute a continuing waiver of a subsequent breach of the same or any other provision of this Agreement. Modifiention,
~Baetion 19.
i No waiver or modification of this Agreement is valid unless l made in writing and signed by both parties. i Baction 20. Entire Acrramment. j This Agreement sets forth the entire understanding between 1 the parties. i Rection 21. Hamdinaa. are in no way intended to describe, interpret, definn the scope, extant to intent of this Agreement or any of its j ,. provisions. ametion 22. Attornav's Fees and Cents < l f In the event of a dispute, arbitration or litigation with f resp m to any of terms of this Agreement or a transa reasonable attorney's fees and costs.
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O i/ PttR!sstem Aarsomit i
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l ) 2 i l l I WHEREFORE, the parties have executed this Agreement as of w-the first date written above. MODSSTO ZERIGATION DISTRICT: Dated: 2./d4L sy: . General u===ner
- AFFROTBD AS TO FORN EdN Dated
- By: .-
- Scott stoffsh, Counse1 for MID l
1 ! CITY or 72TTs3Une Date / M' B se canciamilfa, Mayor f f' APPROTED AS TO FORMS lYYb if, aura J. Anddroon for Michael R. Woods, City Attorney AA - j ) TT T3 l' , i . Hw. , , b. ity Clark fiflan J. Pr i PITfsesmuttALWWusu.let (C.mL.111) ) i 1 i i , i j' --
'O .sentssteu .atteesf l '
l 1
I 1231 Elevenin S: P.O. Box 4060 r l g Modesto. CA 95352 (209)526-7773 and Power January 29,1996 Mr. Tun Macias - Vice President and General Manager, Electdc Transmission l Paci6c Gas & Electric Company l Room B23B l 77 Beale Street l San Francisco, California 94177 l 4 1
Dear Mr. Macias:
l The Modesto Irrigation District has recently purchased the Linde Substation, located 2000 Loveridge Road, Pittsburg, California, from Praxair, Inc. The purpose of this le request an Interconnection Agreement between the District and PG&E for that site. ' O Attached is a proposed form ofInterconnection Agreement to accomplish that g modeled after the Site Interconnection Agreement between PG&E and the Port of O Since we have kept the changes to a minimum, we hope that we can execute this agreem within the next tlurty days. I will be callmg you within the next week to set up a meeting so we can discuss any concerns you may have. Very truly yours, Christopher J. Mayer Assistant General Manager, Planning and Marketing lO di.dANIZED 1887
- 1RRIGATioN W ATER 1904
- POWER 1923
1 i iO i 4 4 4 i i, e d i i i 4 1 4 i
- INTERCONNECTION AGREEMENT
$. BETREEN i $ PACIFIC GAS AND ELECTRIC COMPANY i i AND THE MODESTO IRRIGATION DISTRICT O (REIATED TO WHOLESALE ELECTRIC REQUIREMENTS SE TO THE MODESTO IRRIGATION DISTRICT AT THE l ' LINDE SUBSTATION) i + 4 1 1 4 h
i i INTERCONNECTION AGREEMENT O 2
- E-PACIFIC GAS AND ELECTRIC COMPANY 3 AND THE M3DESTO IRRIGATION DISTRICT 4
(REIATED TO WaOLESALE ELECTRIC REgvuu.MENTS SERVICE ) 5 TO THE M3DESTO IRRIGATION DISTRICT AT TEE LINDE SUBSTATION) 6 l l 7 \ l s l 1 P N LE
- ' This Interconnection Agreement is made this ' day of ;
10 , 1996, by and between Pacific Gas and Electric 11 Company, a California corporation ("PGEE") , '.and the Modesto 12 Irrigation District, a California irrigation district (the 13 " District"). PG&E and the District are each referred to 14 individually as a " Party" and collectively as "the Parties". 15 16 2 RECITALS 17 2.1 Whereas, PG&E, a corporation organized and existing 18 under the laws of the State of California, is a public utility 19 engaged, among other things, in the business of generating, 20 transmitting, and distributing electric capacity and energy in 21 northern and central California; 22 2.2 Whereas, by a new Power Sales Agreement dated 23 January ,1996 between Destec Power Services, Inc. ("DPS") and 24 the District (which Agreement is hereinafter referred to as the 25 "MID-DPS Agreement") the District intends to obtain its Wholesale 26 Electric Power Requirements from DPS. 27 2.3 Whereas PG&E's Electric System currently is 28 connected to the District's Electric System at the Linde 1
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1 i-1 4 l 1 S ubstation by one transmission line at a nominal delivery voltage a j 2 o f 115 kV which has certain delivery capabilities, and the ). 3 P arties desire that these Electric Systems will remain 1 4 interconnected so.that PGEE will: (a) deliver to the District the l 5 contemplated Wholesale Electric Power Requirements from its Full i l 5 Requirements Wholesale Electric Supplier; and (b) will supply i ! 7 reactive power to the District and may provide certain default , a power deliveries to the District as set forth'in Section 6; i i 9 2.4 Whereas, the District has a maximum demand for 1 10 Wholesale Electric Power Requirements service which is within the h j 11 capability limits of the interconnection facilities PGEE has in and 12 place to deliver that Wholesale Electric Power Requirement; 13 the District does not intend to buy Wholesale Electric Power f 14 Requirements from a Full Requirements Wholesale Electric Supplier 15 other than DPS, except as is provided in Section 6; ( i 16 2.5 Whereas, the District understands that the Parties l t 17 would be required to supersede and replace this Agreement or i
- 1s negotiate additional terms and conditions applicable to it upon i
19 the occurrence of the following events: (a) the District seeks to i ! 20 interconnect its Electric System at the Linde SuP tation with I I 21 that of a Third Party as provided in Section 11, or (b) the ! 22 District seeks to meet some or all of its Wholesale Electric 23 Power Requirements at the Linde Substation with its own 24 generation equipment while remaining electrically connected with f 25 PG&E's Electric System in such a manner that the District's 26 electrical generators will operate electrically in parallel with l () 27 PGEE's Electric System; or (c) in the event that the District 2s would propose'to receive Wholesale Electric Power Requirements I ' 2 1
I ! 1 f rom a person or entity which is not a Full Requirements ! kJ 2 W holesale Electric Supplier as defined in this Agreement; all as f 3 described in Section 10; and 4
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5 3 AGREEMENT 6 NOW, therefore, in consideration of the mutual covenants 7 herein set forth, the Parties agree as follows: , s 9 4 DEFINITIONS 10 The following terms, when used in this. Agreement with the 11 initial letters capitalized, whether in the singular, p' lural or 12 possessive shall have the following meanings: i 13 4.1 Agreement This Interconnection Agreement between PGEE and the 14 l 15 District. 16 4.2 CATSA The Control Area and Transmission Service Agreement 17 18 Between PG&E and DPS, dated November 29, 1994, as amended. 19 4.3 CATSA Successor An agreement between PGEE and DPS, other than the 20 CATSA, or an agreement between PG&E and another Full Requirements 21 , 22 Wholesale Electric Supplier, which enables DPS or such other Full 23 Requirements Wholesale Electric Supplier, with respect to its 24 deliveries of Wholesale Electric Power Requirements to the obtain or supply transmission, distribution, and 25 District to: (i) (ii) match 26 all Control Area Services specified in Section 4.5; (iii) obtain or supply 27 its resources to its loads in real time; provide itself 28 appropriate metering of its deliveries; and (iv) 3
1 o r contract for 24-hour scheduling and dispatch services with a 2 datalink to PGEE's energy control center. An agreement between 3 t he aforementioned persons entered into pursuant to the authority 4 of a generally applicable open access electric tariff for 5 interstate service on the PG&E Electric System which is approved 6 by the FERC and which otherwise satisfies the standards of a~ 7 CATSA Successor as set forth above, shall also be deemed to be a a CATSA Successor. 9 4.4 Control Area 10 A balanced portion of an overa.ll electric , power 11 system in which the electric generating resources and not 12 interchanges with other Electric Systems operating a control Area ~ 13 are controlled in order to meet the total load responsibility in. 14 that portion of the overall electric power system. 15
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4.5 Control Area services l Those services necessary to support the transmission His 17 of energy from resources to loads while maintaining. reliable is operation of the transmission provider's transmission system in ' 19
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accordance with Prudent Utility Practice. Those services load 20 include, but are not limited to, compensation for losses, 21 following, AGC regulation, reserves, compensation for energy reactive power, voltage 22 imbalances, congestion management, 23 control, scheduling and dispatching, as approved by the FERC. 24 For purposes of this Agreement these services do not include the 25 provision of reactive power which will be supplied by PG&E. 26 4.6 Cost All just and reasonable, necessary and prudent () 27 2s expenses or capital expenditures, including operation, 4
I' - i 1 maintenance, engineering study, adverse impact identification, () 2 a dverse impact mitigation, contract modification, administrative 3 a nd general expenses, taxes, and depreciation, as determined in 4 accordance with the FERC Uniform System of Accounts as such may i 5 be amende'd or superseded from time to time, and costs of capital. ] l i 6 The appropriate components of Costs, as defined herein, shall be _ j 7 applicd for the particular service or transaction performed. ; a 4.7 DJ-COB Index 9 The index of the weighted average of firm energy the non-firm 10 prices, or if firm energy prices are not published, : j 11 energy prices of megawatt-hours sold at the California-Oregon and j the Nevada-Oregon borders. The DJ-COB Index energy price is ; 12 13 currently published each business day for different time-of-day If l 14 periods by Dow Jones and Company in the Wall Street Journal. ! O 15 the DJ-COB Index is no longer published the DJ-COB Index shall be ) l is a comparable measure of short-term prices for energy traded at 17 the California-oregon border interconnects with the PG&E Electric f is System, as agreed by the Parties. 19 4.8 DPS 20 Destec Power Services Inc. or its successor. 21 4.9 Effective Date 22 The date specified as the Effective Date in 4, 23 Section 5.1 hereof. 4.10 Electric System 24 25 All physically connected properties and other l 26 assets, now or hereafter existing, owned or controlled by a () 27 28 single person or entity, used for or directly pertaining to the generation, transmission, transformation, distribution or sale of 5
W 1 1 electric power, including all additions, extensions, expansions, 2 a nd improvements, but excluding the properties and assets of To the extent a person or s ubsidiaries of such. person or entity. i 3 4 e ntity is not the sole evner of an asset or property, only that 5 person's or that entity's ownership interest in such asset or f-1 4 6 property shall be considered to be part of its Electric System. 1 j 7 Any meters or recording devices owned or installed by DPS at the i l 3 Point of Interconnection shall not be considered an 4 9 interconnection with a Third Party for purposes of this 10 Agreement. - . 11 4.11 Emergency series i i 12 An unplanned or unexpected operational event, 13 of operational events, or' operational circumstance that causes'a f 1 l 14 loss or interruption of generating, transmission or distribution i 15 capabilities, in part or in whole, and in the judgment of the i 16 affected Party's operator and consistent with Prudent Utility l 17 Practice, requires the taking of immediate action: (i) to i l 18 preserve, maintain, or reestablish the safety, integrity, or to
^19 operation of the facilities that have been affected; or (ii) 20 protect the health' or safety of employees or the public; or (iii) 21 to prevent or minimize any significant adverse environmental 22 effects.
The inability of DPS to provide or deliver to PG&E j 1 j 23 sufficient electric power to meet the District's Wholesale t 24 Electric Power Requirements,is not an Emergency under this l' 25 Agreement. i 26 4.12 FERC 1 The Federal Energy Regulatory Commission or its 27 f() 23 regulatory successor. 6 i 4
l i ,1 1 4.13 Forced Outage l
- 4. 2 A full or partial outage of a Party's generating 3 r esource or transmission facilities that is caused by an 4
4 Energency. i 1 5 4.14 Full Requirements Wholesale Electric supplier ! s A single electric power supplier having requisite ! 7 authority from FERC to make sales of electricity at wholesale in ' S interstate commerce, who provides all the Wholesale Electric !. 9 Power Requirements to the District and who also has'a CATSA or a ! 10 CATSA Successor in place with PGEE. - . 1 l 11 4.15 KVAR Demand [ 12 The maximum reactive al'actrical demand in any month KVAR i 13 is determined for both on-peak and off-peak time periods. j (KVAR), l 14 Demand is measured as the average amount of kilovars l [~'\
\ sl delivered during the 30-minute on-peak or off-peak interval in
- 15 is which such delivery is greater than in any other 30-minute on-1 l
17 peak or off-peak interval in the month; provided, that if the a five-is load is intermittent or subject to violent fluctuations, i i 19 minute interval may be used. 20 4.16 KW Demand l 4 The maximum electrical power demand in any month is 21 KW Demand 22 determined for both on-peak and off-peak time periods. l delivered 4 23 is measured as the average amount of kilowatts (KW) i 24 during the 30-minute on-peak or off-peak interval in which such 25 delivery is greater than in any other 30-minute on-peak or off-i l 25 peak interval in the month; provided, that if the load is 27 intermittent or subject to violent fluctuations, a five-minute .f( interval may be used. 28 J 7
i 1 4.17 Linde substation 2 The substation, and all transformers, meters, and 3 e quipment associated therewith, along with any improvements, 4 b etterments, or modifications, whenever made owned by the l I 5 District, located at 2000 Loveridge Road, Pittsburg, California. 6 Point of Interconnection 7 4.18 s The physical connection of the Electric Systems of 9 the respective Parties where PGEE's conductors connei::t with the 10 District's conductors at the location known,as Linde. Substation 11 and geographically located on the premises known as 2300 12 Loveridge Road, Pittsburgh, California, which currently is and supplied by a. tap off that 13 operated at 115 kilovolts (kV) 14 transmission line of PG&E commonly known as the Columbia Steel 15 line. 4.19 3EID-DPS Agreement 16 The power sale agreement between the District and 17
-,1996, as it may be amended.
is DPS dated 19 4.20 Prudent Utility Practice including Those practices, methods, and acts, 20 that 21 provisions for contingencies, as modified from time to time, 22 are used (a) to operate an Electric System dependably, reliably, 23 safely, efficiently, economically and in accordance with all 24 applicable laws and government rules, regulations and orders, to prevent 25 (b) to serve a utility's own customers, and (c) 26 adverse effects on neighboring Electric Systems and control 27 Areas. Such practices, methods, and acts consist of those 2s commonly used and engaged in or approved by utilities which: 8
I i (1) are members of the Western Systems Coordination Council; and 1 ', 2 (2) schedule across an interconnection with a Third Party. 3 4.21 Service Area i 4 That area within the geographic boundaries of the 1 5 several areas electrically served at retail, now or in the 1
- 5 future, by PGEE.
t 7 4.22 Short-Run Avoided Cost ("SRAC") . s The then-current rate at which PG&E purchases as- .I 9 available Qualifying Facility ("QF") power under its'. Standard I i 10 offer power purchase agreements on a time-of-use basis.in . f 4 11 accordance with CPUC Investigation No. 89-07-004, as revised from time to time, and as currently filed'on an approximate monthly l 12 j 13 basis with the CPUC and approved by the CPUC. i l 14 4.23 Stanislaus commitments l 15 That statement of commitments embodied in that i 16 agreement entered into between PGEE and the United States j l 1976, and published at 41'End. f 17 Department of Justice on April 30, + 18 Eng 20225 (May 17, 1976). 4.24 Third Party 19 20 A person or entity other than PG&E or the District. 21 4.25 Uncontrollable Forces 22 Any cause or causes beyond the control of a Party l including, but l 23 which renders it unable to perform an obligation, i j 24 not limited to, failure of or threat of failure of facilities 25 caused by flood, earthquake, volcanic activity, tornado, storm, ] 25 drought, fire, pestilence, lightning and other natural civil disturbance or () 4 27 catastrophes, epidemic, war, riot, labor or material 23 disobedience, vandalism, strike, labor dispute, a 9 E r ,
sabotage, terrorism, governmental priorities or A ishortage, ( 2 r estraint by court order or public authority, and action or non-3 a ction by or intbility to obtain or maintain in effect any 4 n ecessary authorization or approval from any governmental agency 5 or authority, which by the exercise of due diligence such Party 6 could not reasonably have been expected to avoid and which by the 7 exercise of.due diligence it has been unable to overcome. 8 Nothing contained in this definition shall be construed as lockout, or labor dispute 9 requiring a Party to settle any strike, 10 in which it may be involved, or to accept any permit, , l 11 certificate, or other authorization that contains conditions or \ 12 terms the Party determines, in good faith,.are unduly burdensome. 13 The term " Uncontrollable Forces" shall not mean Forced Outages, j 14 scheduled curtailments or interruptions of power, transmission or ! 0t 15 distribution service, curtailments or interruptions of power, l l 16 transmission or distribution services that occur with advance ! i 17 notice, or curtailments or interruptions of power, transmission is or distribution service without notice that nevertheless can 19 reasonably be expected to occur and should be planned for Examples of l 20 consistent with Prudent Utility Practice. l l 21 curtallments or interruptions that may reasonably be expected to 22 occur are (a) single-line outages of transmission facilities, 23 (b) Forced Outages of at least one generating facility, 24 (c) drought at a hydroelectric facility, (d) loop flow on the 25 Pacific Northwest-Southwest Intertie, and (a) loss or reduction l 26 of the fossil fuel supply for a thermal unit. i Wholesale Electric Power Requirements () 27 2s 4.26 The District's electric capacity and energy 10 i
i ' 1 i i 1
! 1 r equirements at its Linde Substation only, served "at wholesale 1
2 in interstate commerce" as that term has been construed in 16 1 l 3 U.S.C. S 824(d), and which sale is subject to the exclusive 4 jurisdiction of the FERC under applicable law , and during the 4 5 term of this Agreement shall be served by a sale of electricity a ! 4 to.the District by a Full Requirements Wholesale Electric i f; 7 Supplier. ' 9 j 5 1 .
! 9 5 8 COPE AND TERM i .
10 5.1 Effective Date
- 11 The Parties shall be bound by the terms of this l
1 - 12 Agreement upon its execution._ The term Effective Date as used in-l j 13 this Agreement shall mean 0000 hours on the latest of August 1, ; i 1996, or the date on which FERC accepts this Agreement for filing 14 1 15 and permits it to be placed into effect without material change , I i 16 or material new condition unacceptable to either Party, or the If FERC enters into a ! 17 date on which FERC terminates the PSA. ! is hearing to determine whether this Agreement'is just and i ! 19 reasonable or otherwise lawful, then this Agreement shall become j 20 affective on the date it is permitted to be placed into effect f The ordering of ~ 21 and subject to any conditions imposed by FERC. i
- 22 such a hearing shall not be considered a material change.
23 However, in the event of any material change or material new i I 24 condition the Parties shall promptly enter into good faith j i 25 renegotiations to attempt to achieve a mutually agreeable 1
# 26 modification to this Agreement to address such material change or material new condition and shall undertake such renegotiations as
( 27 The Parties agree to work diligently to 2s provided in Section 17. 11 1 n -
'l t
1 o btain timely acceptance of this Agreement and all of its O 2 provisions by FERC, and agree that the District shall be entitled 3 to prior review and approval of any initial filing with FERC by 4 P G&E seeking approval of this Agreement and the submittals to ! 5 FERC related to it. 6 5.2 Tara 7 This Agreement shall terminate at the earliest of s the following: (a) 2400 hours on December 31, 2008; (b) the date l 9 on which the CATSA terminates without a CATSA Successor in force, 10 or on the date that the provision of default power to the 11 District by PGEE under Section 6 terminates; (c) termination in 10 (NEW 12 accordance with Sections 6.1.1 [MID-DPS Agreement), 13 INTERCONNECTION AGREEMENT), 11 [NEW INTERCONNECTION WITH A THIR 14 PARTY), 17 (ADVERSE DETERMINATIONS OR EXPANSION OF OBLIGA 15 or 23 (DEFAULT) or (d) upon mutual written agreement of the 16 Parties to so terminate it. 17 13 6 POWER SERVICES 6.1 Agreement conditioned on PGEE and District 19 Arrangements with Power suppl.iers 20 6.1.1 MID-DPS Agreement -- DPS will be the 22 lier 22 District's initial Full Requirements Wholesale Electric Supp In the event that the MID-DPS Agreement 23 under this Agreement. or in 24 terminates, or the CATSA terminates without a CATSA Success 25 force between PG&E and DPS, the District shall be obligated Wholesale 26 make arrangements for a replacement Full Requirements dr 27 Electric Supplier under the conditions outlined herein in or e As consideration for PGEE 28 for this Agreement to remain in place. 12
} . a,
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! 1 e ntering into this Agreement, at all times during the term of l 2 this Agreement the District agrees: (a) except as otherwise 3 provided in this Agreement, the District shall have a contract in 4 force and be supplied by one, and only one, Full Requirements to 5 Wholesale Electric Supplier, as defined in Section 4.14, 6 supply all the District's Wholesale Electric Power Requirements, i 7 subject only to any further provisions of this Section 6; and (b) s the District's Full Requirements Wholesale Electric Supplier shall have the CATSA, or a CATSA Successor, in force:with PG&E le 10 sufficient to enable such person or entity.to perform as a Full 11 Requirements Wholesale Electric Supplier as: defined in this 12 Agreement. The requirements by which a Full Requirements 13 Wholesale Electric Supplier is obligated to provide Control Area
/N 14 Services itself, buy them from a Third Party, or from PGEE in a 15 CATSA Successor shall be consistent with Prudent Utility Practice 16 and PGEE's obligations as a Control Area operator and as approved 17 by the FERC. If either condition (a) or (b) above is not met, is PG&E may, upon written notice to the District, file with FERC to 19 terminate this Agreement, or may seek any other applicable 20 remedies as provided in Section 6.2.4.
6.1.2 Upon termination of the CATSA or a CATSA 21 22 Successor for any reason, PG&E agrees that it shall either 23 provide by tariff or negotiate in good faith a CATSA Successor, 24 provided, however, nothing in this Agreement shall be construe ,o 25 to imply any obligation on PG&E to the extend the term of the 26 CATSA. 27 as 13 i I
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i ! l i 1 1 6.2 Default by DPS or Ot'aer Full Requirements Wholesale f 1 l ' 2 Electric supplier In the event of a termination of the 3 6.2.1' i 4 CATSA, or a CATSA Successor, between PGEE and the District's Full
.5 R equirements Wholesale Electric Supplier, or in'the event of 3
6 suspension of service by PGEE under the CATSA or a CATSA i 7 Successor, PG&E will not disconnect its Electric System from the District's Electric System. PGEE agrees that.in any such event j s I 9 the District will continue to receive power sufficient to satisfy l 10 its Wholesale Electric Power Requirements from PG&E's. Electric . . 11 System as default electric power deliveries.(" default power"). 12 PGEE shall be deemed to be providing' default power once it has i 4 13 provided both 30 days notice to the District of its intention to 14 as.?end service under the CATSA or a CATSA successor and 15 to the District of actual suspension of all service, or i is suspension of service to the District under the CATSA or CATSA Successor. PGEE shall be compensated by the District for such 17 is default power as stated herein, until such suspension is removed 19 or the supply of the Wholesale Electric Power Requirements by a 2 20 replacement Full Requirements Wholesale Electric Supplier has 21 begun. In no respect shall the District be liable to PGEE for , 22 the obligations of its Full Requirements Wholesale Electric 23 Supplier under the CATSA or a CATSA successor. 24 6.2.2 PG&E shall account for and bill the 25 District for such default power monthly beginning within 45 days PGEE shall measure and 26 after any PGEE delivery of default power.
) 27 assess the District for the kilowatthour deliveries fo 2s periods as are determined in accordance with Section 6.2.1 14
I i l i s hall charge the District for such default power at the rates 2 e stablished in Section 6.2.3 or, if applicable, the rates filed nd approved in accordance with Section 6.2.4. The District will 3 a 4 m ake payment to PGEE in accordance with Section 14 [ BILLING AND 5 PAYMENT) in the amount determined in accordance with this 1 l 6 Section 6.2.2. 6.2.3 In accordance with the procedures set 4 7 l 3 forth in this Section 6.2, the District shall'ba charged for the 9 amount of default power as determined in Section 6.2.'2 supplied 10 to the District by PGEE at a rate. equal toethe greater of: (a) 11 the SRAC price per kWh multiplied by a factor of 1.15, applying 12 the appropriate SRAC price according to the time of the power 13 deliveries, or (b) the DJ-COB Index price in mills /kWh multiplied 14 by a f. actor of 1.15, applying the appropriate DJ-COB Index price The cost support 15 according to the time of the power deliveries. 16 for any such District payment for default power shall be filed'by 17 PG&E with the FERC within sixty (60) days of the date payment is is made by the District to PG&E hereunder, and such payment shall be Any and all 19 subject to FERC acceptance of such cost support. 20 payment amounts not accepted by FERC shall be subject to refund 21 by PGEE to the District with interest computed in accordance with The 22 Section 35.19(a) of the FERC's Regulations, 18 CFR S 35.19a. 23 Parties have agreed to use these stipulated prices set forth 24 above in the event that default power is so supplied by PGEE 25 because: (a) proof of actual loss or impact on PGEE would be 26 exceedingly difficult to determine because it is impossible at to ascribe a dollar 27 the time of entering into this Agreement, 2s value to such loss; (b) the legal and regulatory remedies 15
_ _ , . _ . _ _ . . _ . _ _ _ _ _ . _ . . . . _ _ _ _ _ . _ _ . _ . . ~ . . 1 a vailable to PGEE would make it infeasible or extremely O 2 i nconvenient to obtain an adequats remedy; and (c) the above-3 d escribEd proxy charge is not intended to represent the actual l nor l 4 c osts to PG&E of providing such excess power to the District, but rather is 5 is it intended to be punitive to the District, 6 intended to serve as the stipulated' compensatory payment to PG&E, 7 reflecting short-term power costs plus an amount reflecting fixed a costs associated with unintentional power supply, delivery over 9 PG&E's transmission and distribution facilities and the provision 10 of Control Area Services by PG&E., This rat,e is subject to review
- ~. i 11 or renegotiation by PGEE and the District for deliveries 12 continuing beyond ninety (90) days after commencement of such 13 default power deliveries by PG&E.
l 14 6.2.4 If PG&E commences deliveries of default I PGEE N. 15 power to the District in accordance with this' Agreement, 16 will continue to deliver default power to the District for a or for such longer time which, in 17 period of ninety (90) days, is PG&E's discretion, it believes is necessary to enable the 19 District to obtain a replacement Full Requirements Wholesale 20 Electric Supplier, and during such period shall bill the District 21 for such power stated in Section 6.2.2. In the event that PG&E i- ' 22 commences such default power deliveries, the District shall use 23 its best reasonable efforts to promptly secure a replacement Full The District shall 24 Requirements Wholesale Electric Supplier. 25 report weekly to PGEE on the status of the date upon which 26 service to the District from such replacement Full Requirements Nothing.in 27 Wholesale Electric Supplier is expected to commence. 28 this Agreement shall be deemed to limit PG&E's right to file 16
l i j 1 u nilaterally for an interconnection agreement to supersede,
\ 2 replace, or terminate this Agreement or to file for revised rates i
! 2 for power services to the District, if, after ninety (90) days 4 f ollowing the commencement of such default power deliveries, the 4 1 5 D istrict has not commenced service from a replacement Full I k 6 Requirements Wholesale Electric Supplier. 1 7 6.2.5 The' District also shall provide PGEE with , i a a prompt notice of any default or material breach, or potential I 9 default or material breach under the District si agreement with its Full Requirements Wholesale Electric Supplier. Such notice i ! i l 10, , i l 11 shall be in writing with a copy sent to the District's Full ! 12 Requirements Wholesale Electric Supplier. 6.2.6 PG&E also shall provide the District with 13 I or 14 a prompt notice of any other default or material breach,
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- 15 potential default or material breach, by the District's Full p is Requirements Wholesale Electric Power Supplier, under that l i Such l 17 supplier's applicable CATSA or CATSA Successor with PG&E. l l I i
i is notice shall be in writing with a copy sent to the District's d 19 Full Requirements Wholesale Electric Supplier. 6.2.7 Notwithstanding the other provisions of 20 this Section 6.2, if the District and its Full Requirements
- 21 22 Wholesale Electric Supplier terminate their agreement by mutual j
- 23 agreement, which termination is not the result of the resolution i
24 of a dispute between the District and its Full Requirements the 25 Wholesa'le Electric Supplier (" voluntary termination"), days 26 District will provide PGEE with a minimum of sixty (60) i In the 27 prior written notice of any such voluntary termination. 1 2a event of such voluntary termination, and the substitution of 17
1 a nother N11 Requirements Wholesale Electric Supplier by the 2 District under this Agreement, the provisions of this Agreement 3 shall remain continuously in force between PG&E and the District, 4 subject however to the condition that PG&E may, in that event, 5 provide a written notice electing to renegotiate appropriate 6 changed or additional terms and provisions to this Agreement. 7 PGEE may request that this Agreement be amended to add new , a provisions or that existing provisions be revised to make this 9 agreement comparable with other apeements between Pd&E and entities receiving similar service. Such comparable agreements 10 11 may be those either then in force with others or those providing 12 for comparable service and approved by FERC, at the time of The modifications may also ) 13 notification from the District. 14 include any revisions necessary to accommodate the new supplier, l l 15 provided that such supplier must meet all the requirements of a l 16 Full Service Wholesale Electric Supplier, unless otherwise agreed 17 by PG&E. is 6.3 Reactive Power Requirements Each Party shall supply the reactive kilovolt-1 19 20 amperes (KVAR) requirements pursuant to Appendix A for its own 1 21 Electric System to maintain zero reactive power flow at the Point PG&E shall charge District for reactive 22 of Interconnection. 23 power, both leading and lagging, not supplied by the District. l 24 For each monthly billing period the District shall also be 25 subject to a Reactive Power Correction Charge as set forth in 26 Appendix A for excess KVAR Demand. 27 6.4 customer service charge PG&E shall charge the District a customer Service 28 18
. -. - . .- .- - -..- - - - - ~ . . . - - . - . . _ . - . _ - .
l l
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1 1 Charge as set forth in' Appendix A of $150 par month, fixed for 2 the Term of this Agreement for the costs of billing, and 3 a ccounting for reactive power and default power provided in 4 Sections 6.2 and 6.3. 5 6.5 Limited PGEE Obligation to Provide Wholesale 6 Electric Power Requirements ,' 7 Except as provided in this Section 6 for the . a provision by PGEE of default power to the District, the District 9 does not intend to, and will not, rely upon any PG&E' supply of l 10 Wholesale. Electric Power Requirements. . l i 11 , 12 7 INTERCONNECTION
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13 7.1 PGEE Represented Interconnection Facility Limit i 14 All deliveries of electric power shall be delivered ; t 15 by PGEE over PGEE's facilities to the District'at the Point of ' 16 Interconnection. All of-the representations set forth below, as. 17 to the capability of elements of PG&E's Electric System, are PG&E 18 applicable only as of the time this Agreement is executed. 19 represents that PGEE's transmission line which connects the PG&E 20 Electric System to the District's Linde Substation is rated at and 21 approximately amps for normal and emergency load levels, 22 establishes a maximum facility delivery limit at the Point of at a nominal delivery 23 Interconnection of not less than 30 MVA, 24 voltage of 115 kV. 25 7.2 Limited Duty to Preserve Facility Limit and Reserve 26 Capability Subject to the limitations set forth in Section 7.1, () 27 2a each Party shall-preserve the capability of its respective 19
l 1 facilities to be able, with respect to the District, to receive 2 a nd, with respect to PG&E, to deliver on behalf of the District's 3 Full Requirements Wholesale Electric Supplier, the amount of 4 transmission service that, for the time periods specified, has 5 been reserved by the District's Full Requirements Wholesale 6 Electric Supplier to supply the District in accordance with its 7 agreement with PG&E for such transmission. , s 9 7.3 No Fatility Preservation Obligation Afte'r 10 Termination 11 Subject to Section 40 [ TERMINATION), after the 12 termination of this Agreement PGEE shall have no obligation to 13 maintain the availability of its facilities serving the Point of 14 Interconnection. If the interconnection of the PG&E and District 15 Electric Systems is also terminated, any subsequent reconnection 16 shall be governed by the law and regulation governing electric 17 utility interconnection and as provided in Section 40 18 [ TERMINATION). 19 20 S MODIFICATION OF INTERCONNECTION 21 a.1 Changes at the Point of Interconnection s.l.1 Unless otherwise agreed by the Parties, 22 23 PG&E shall deliver electric power at the Point of Interconnection 24 at the transmission voltage level of 115 kV for the term of this ' 25 Agreement. The Parties understand and agree that at some future 26 date PGEE or the District may desire to change the transmission () 27 delivery voltage at the Point of Interconnection to some higher the Parties agree that they will 28 voltage. In this event, 20
1 l-1 c ooperate'in good faith to evaluate the feasibility of such an 2 increase in delivery voltage and will not object to such change 3 r equested by the other Party, except for good cause in accordance 4 with Prudent Utility Practice. 5 s.1.2 In the event that changes in delivery 6 volt' age, relocation of facilities, or other changes in facilities 7 are necessary on one Party's side of the Point of Interconnection such changes a because of changes on that Party's Electric System, shall be made by that Party at its own expense. Unless otherwise 9 10 agreed by the Parties, under such circumstances corresp,onding i, 11 changes on the other Party's side of the Point of Interc'onnection 12 shall be at the other Party's expense'unless those changes are 13 made solely for the first Party's benefit and at that first 14 Party's written request. If the Parties fail to agree on a Cost 15 allocation, the matter shall be put to arbitrat' ion, in which is event the arbitrators shall determine only which Party's proposed. 17 allocation is more consistent with the terms and purpose of this is Agreement. 19 8.2 Reinforcement 20 If the District requests that, or it becomes 21 necessary that, PGEE, in accordance with Prudent Utility to serve an 22 Practice, reinforce its Electric System either (a) 23 increase in the District's Wholesale Electric Power Requirements 24 beyond the facility capability limits described in Section 7.1, 25 or the capability of the interconnection facilities as determined 26 subsequently by the agreement of the Parties or through or arbitration of the plan and price under this section 8.2, () 27 to correct the power factor of the District's electric load 28 (b) ! 21 l
l' i ! 1 to operate at 0.99 to 1.00 lagging power factor during on-peak 2 periods and to operate between 0.9867 lagging power factor and
- l. 3 0.9984 leading power factor in off-peak periods, PG&E shall meet 4 and confer with the District as to a mutually acceptable means of f
l 5 serving such load or correcting the power factor. If, after s review of applicable power system studies, a dispute arises t j 7 regarding the actual capability of the transmission or-a interconnection facilities that support the Wholesale Electric i 9 Power Requirements, either Party may elect that the matter be resolved by arbitration. If PGEE and the District agree upon a 10 j 11 mutually acceptable plan, PG&E shall prcvide the District with a 12 firm price for the work required-on PG&E's Electric System for i 13 service to accommodate the District's increased load or correct 14 the District's power factor, and, if such price is acceptable to 1
,f ! 15 the District, the District shall pay PG&E such Costs as provided 4
16 in this Section 8.2; provided however, should the Parties fail to 17 agree upon a mutually acceptable plan of service or plan of l is payment of Costs for reinforcing PG&E's Electric System serving 3 19 the District's load or on the firm price for such work, then the 20 plan and price for the reinforcement under this Agreement shall f Unless otherwise agreed by the 21 be submitted to arbitration. 22 Parties, PG&E shall then perform the facility reinforcements in 23 accordance with the agreement of the Parties or the result of l 24 arbitration. The District shall make no claim under this i 25 Agreement for service of electric power or management of voltage 26 variations in excess of the facility capability limit described in Section 7.1 plus the additional capability paid for as a 7 () 27 2e reinforcement by the District in accordance with this Section 22 : 1 1 l
I I i 1 8 .2. 2 8.3 Advancing Costs If mutually agreed pursuant to i 3 S.3.1 l 4 Section 8.2, the District shall pay PG&E the Costs of 5 constructing or reinforcing facilities, including an advance in , 1 6 the manner prescribed below. For the purpose of this Section 8, 7 the Parties agree that the Costs shall be those Costs normally a included in PGGE's cost estimates for such work with respect to : 9 facilities designed in accordance with Prudent Utility Practice. s.3.2 At least 60 days prior to the date on 10 11 which PGEE will be required to commence payment of any Costs as a 12 result of construction or reinforcement of facilities pursuant to 13 Section 8.2, PGEE shall determine and provide to the District: 8.3.2.1 An estimate of all Costs, 14 15 broken down by major activities, which PG&E expects to incur; and 8.3.2.2 A schedule indicating the 16 17 approximate dates when PG&E expects to pay such Costs for each is major activity included in the estimate. 3.3.3 The Parties shall agree upon e.n estimate is 20 and schedule of Costs and payments as provided by section 8.3.2, 21 and the District shall advance such Costs to PG&E pursuant to 22 such schedule. s.3.4 The District's total payments to PGEE for 23 24 work performed under this Section 8.3 shall be for the actual 25 Costs incurred by PG&E. PG&E shall document to the District the 26 actual costs incurred upon completion, and shall refund any d or request any additional payment, with interest compute () 27 28 amount, pursuant to Section 35.19(a) of the FERC's Regulations, 18 CFR 23
i 4 f I ! 1 5 35.19a, relative to the Costs already advanced by the District. 2 S.3.5 The schedule described above in ; $ 3 Section 8.3.1, or as the schedule may have been revised, for each 4 m ajor activity shall be determined not less than 30 days before 1 ~ 5 the date on which PGEE expects to pay each such amount. i Should the District seek approval from ! j 6 S.3.6 l ,4 7 the Internal Revenue Service for the District's payments under ; 4 5 8 this subsection to be treated as non-taxable contributions-in-9 aid-of-construction, PGEE shall cooperate with the District in 10 the District's filing with the Internal Revenue Service. 11 S.3.7 The District shall have the right to 12 review the supporting documents upon'which PG&E bases its i j
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13 estimate of Costs of work to be advanced by_the District pursuant 14 to this Agreement, and all documents relating to the actual Costs 15 incurred by PGEE. 16 S.4 Associated FERC Filings 17 If required by FERC or requested by the District, 18 PG&E shall file with the FERC to document and seek approval of 19 any Costs charged by PG&E to the District which are associated 20 with any facility modifications, changes,; reinforcements or advances contemplated by this Section 8. The District shall 21 22 support this filing by an appropriate submittal to FERC stating 23 its agreement with the charges. 24 25 9 OPERATING PROVISIONS 26 9.1 Power Delivery Standard PGEE shall deliver power via what is commonly () 27 7:8 designated as three phase alternating current, at 60 HZ, and at a 24
l 1 n ormal voltage of 115 kilovolts (kV). Normal variations in f - 2 v oltage and frequency shall be permitted pursuant to Prudent i-3 Utility Practice. 4 9.2 No scheduling 5 Under this Agreement, the District's Full 6 Requirements Wholesale Electric Supplier will schedule all 7 deliveries of supplied Wholesale Electric Power Requirements to- , S PG&E's Electric System for delivery to the District. Except in 9 its capacity as a scheduling agent for Third Parties $he District 10 will neither be required nor permitted to schedule any power with 11 PGEE under this Agreement. 12 9.3 Coordination of Operations 13 9.3.1 The Parties shall coordinate their 14 switching operations on their respective facilities (1) as 15 requested by their respectise operators, or (2) in the event of 16 an Emergency, either pursuant to mutually agreed Emergency orders 17 or, in the absence of such orders, as necessary in the judgment of PG&E's operators at its Switching Center, or such is l 1'9 other PG&E substation or switching center as may be designated by i i ities 20 PG&E. .The Parties shall endeavor to coordinate the r act v 21 in the operation and maintenance of these facilities in order to 22 minimize any adverse effects of those activities on each other. The 9.3.2 Operation of Emergency Generators -- 23 24 District may, at its sole option, install emergency generators to The 25 maintain electric service during electric power outages. 26 District shall not operate any emergency generators in parallel 27 with the PG&E Electric System at any time. The District shal!. Switching Center, or such other 28 notify PGEE's 25
i i s ubstation or switching center as PG&E may designate, at any time 2 that these generators are operating. The District shall only
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3 o perate such emergency generators in isolation from that portion l I 4 o f the District's Electric System that remains connected or ready 5 to be reconnected to PGEE's Electric System by PGEE actions or.by 6 automatic devices. The emergency generators will be disconnected 7 from the District's Electric System prior to reconnection of the 8 isolated portion of the District's Electric System served by the l 9 emergency generators to the portion of the District's Electric 10 System which is connected to PGEE's Electric System. 11 9.4 Reporting Significant Events 12 Each Party shall promptly report to the other Party 13 any Emergency or other significant operating event reasonably For 14 likely to affect operation at the Point of Interconnection. 15 notice to PGEE such notice shall be by telephone to PG&E's 16 Switching Center or such other substation or switching center as may be designated by PGEE. For notice to the District, such 17 is notice shall be by telephone to the District's Control Center, or Each 19 such oth'er person as may be designated by the District. 20 Party, upon request and on a case by case basis for reasonable 21 cause related to operating conditions, shall provide to the other 22 Party Electric System operating information, such as loading on 23 lines and equipment and levels of operating voltages and electric power factors. In the event of interruptions of electric service 24 25 at the Point of Interconnection, the Party causing the 26 interruption shall report to the other Party the nature of the 27 avant, actions being taken to restore electric service, and the l() 28 estimated time of restoration of electric service. 26
1 9.5 Prudent Utility Practice () 2 Prudent Utility Practice shall be the general tandard for performance related to Electric System operation and 3 s 4 the supply and receipt of electric services by the Parties under 5 this Agreement. Each Party shall observe Prudent Utility 6 Practice in its operations, and no Party shall be obligated to 7 operate in a manner contrary to that standard. ' s 9.6 Protective Devices 9 The District shall install, set and adjust the 10 protective relaying equipment associated with the District's 11 facilities in a manner consistent with PGEE's settings bnd 12 adjustaants of PG&E's protective relaying equipment. 13 9.7 Continuity of Service 9.7.1 Unscheduled Interruptions -- PG&E may 14 15 temporarily interrupt or reduce any service, o'r temporarily 16 separate all or any part of the facilities of its Electric System 17 from the District's Electric System, if PG&E determines at any is time that the following conditions exist and that the described 19 action is necessary or desirable: (i) in case of an Emergency, where the 20 (ii) to prevent a hazard to life or property, or (iii) interrupted or 21 operation of PG&E's Electric System is suspended, In the 22 interfered with as a result of Uncontrollable Force. PG&E shall 23 event of such interruption or reduction in service, 24 restore full service to the District on a priority basis 25 comparable to the restoration of other major industrial as directed by the authorized 26 facilities, and, in any event, emergency response officials. Should the Parties determine that 27 ( such interruption or reduction in service will be of a prolonged 28 27 s
i 1 i i l- 1 nature, then the Parties shall confer and determine the extent to 2 w hich, and the timing with which, PGEE shall restore full service I
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3 to the District. ! 4 9.7.2 scheduled Interruptions -- All scheduled l l 5 interruptions of service shall be made as mutually agreed by the 6 Parties. Except in the case of Emergency or Uncontrollable 4 4 I 7 Force,'the Parties shall endeavor to give seventy-two hours 1 i 8 advance notice of any such interruption, reduction or separation, I 9 and its probable duration. i ' 10 9.7.3 Interruption by Protective Devices -- )
- l 11 PG&E utilizes automatic protective devices in order to assist in l 12 maintaining the integrity and reliability of its Electric System 13 and to protect its customers from damage, injury or prolonged 14 outages. Service under the Agreement is subject to interruption 15 in the event of operation of such devices.
16 9.7.4 Jeopardy -- If at any time continuity of. PG&E 17 service within the PGEE Control Area is being jeopardized, is may give reasonable notice of the need to curtail, and thereupon 19 the District shall temporarily reduce load; provided that such 20 reduction shall maintain, as far as practicable, the relative 21 sizes of load served by each Party in the same proportion as 22 existed before such reduction. 9.7.5 Underfrequency Load Shedding -- The 23 24 Parties recognize that Prudent Utility Practice requires that 25 automatic load shedding by underfrequency relays be provided in 26 the event load requirements of the Control Area exceed powel () 27 28 supplies instantaneously available to meet those requirements. The District has installed and shall continue to operate and 28
f 1 maintain in service high speed digital underfrequency load () 2 shedding equipment in accordance with Prudent Utility Practice. such load shedding equipment shall be designed to operate at l 3 f 4 levels compatible and coordinated with PG&E's load shedding , 1 1 arrangements and shall be set for the amount of load to be shed, 5 ] t 6 with frequency steps and tripping and reset times as shown in-1 l 7 PG&E's Supplement B to Standard Practica 441.56, as it may be ' I. a revised from time to time. The District shall shed or restore 4 j 9 load by such percentages, and at such frequencies, wh.ile PGEE is 10 simultaneously reducing or restoring the loads of its customers i I 11 in its Control Area pursuant to the procedures shown in~PGEE's i
- 12 Supplement B to Standard Practice 441.56, as it may be revised 1
from time to time. PGEE may revise its load shedding plan at any I, 13 i 14 time. The District shall modify its load shedding program so as 15 to remain consistent with changes made in PG&E's load shedding l\ 16 plan. PGEE and the District shall each provide a copy of its 17 revised plan to the other upon request. la 9.7.6 Proportional Shedding Policy -- If at any f i l's time the' Control Area load requirements exceed power sources t i 20 available to the Control Area to meet such requirements, thereby
- load 21' requir'ing either automatic or manual load shedding, or both, the 22 shedding shall be such as to maintain, as far as practicable, 23 relative size of load served by each Party in the same proportion 24 as existed before such load shedding unless a different degree or 25 amount of load shedding is directed by lawful authority, 26 occasioned by circumstances beyond PGEE's control, or determined This load shedding shall be conducted in
() 27 28 appropriate by PGEE. accordance with the underfrequency load she.dding plans as revised 29 .. es
i 1 by mutual agreement of the Parties from time to time, and such 2 mutual agreement shall not be unreasonably withheld. 3 4 10 CONDITIONS REQUIRING A NEW INTERCONNECTION AGREEMENT l 5 10.1 Notification 6 At any time during the term of this Agreement, if 7 the District anticipates the occurrence of any of the following a conditions or circumstances which affect the interconnection or 9 the operating relationchip between either PGEE and the District, t 10 or between the District and its Full Requirements Wholesale 11 Electric Supplier, then the District shall notify PGEE in writing i 12 promptly and in no event less than nine months before such. I and shall provide all relevant information s 13 anticipated event, 14 including expected time schedules: l 0 15 10.1.1 District's interconnection to a Third 16 Party supplier at Linde Substation, other than in an Emergency, 17 provided that such interconnection will be operated electrically is in parallel by the District with service by PG&E through the 19 Point of Interconnection; provided however that, if other than in
~
20 an Emergency, such.an interconnection with a Third Party at Linde 21 Substation shall be permitted so long as it results in the Full 22 Requirements Wholesale Electric Supplier not making power 23 deliveries through the Point of Interconnection for thirty (30) 24 days. In the event that period is exceeded, PG&E may open the 25 interconnection and file with the FERC to terminate this 26 Agreement; District's acquisition of control of, of () 27 28 10.1.2 rights to, generation resources to be delivered or used 30
_ - _ . _ . . . _ _ _ _ . . _ _ _ . _ _ . _ . . ._._ ___.-_ _ . _._____.______m. 1 1 e lectrically in parallel with the service by PGEE thorough the 2 Point of Interconnection; 3 10.1.3 The District requests transmission 4 service, distribution service, or both, from PGEE at the Point of 5 Interconnection; and 6 10.1.4 The District proposes to receive J 7 Wholesale Electric Power Requirements at the Linde Substat. ion s from a person or entity which is not a Full Requirements ; 9 Wholesale Electric Supplier. Time Frame For Negotiating a New Interconnection f 10 10.2 11 Agreement ) Pursuant to notification under Section 10.1, the 12 13 Parties shall meet and use good faith efforts to negotiate a If 14 revised interconnection agreement under this Section 10.2. days of
'15 the Parties have not reached agreement within;ninety (90) i 16 the date of the first meeting or within ninety (90) days before.
then PGEE may
.17 an event in Section 10.1 is expected to take place, is unilaterally file an interconnection agreement with the FERC which may pursuant to Section 205 of the Federal Power Act, 19 and the District 20 supersede this Agreement in whole or in part, 21 may exercise its rights under the Federal Power Act or other
.22 authority to protest or oppose such filing. Such interconnection 23 agreement may include, among other things, new or modified terms 24 and conditions regarding obligations for transmission and l
25 distribution services, Control Area Services, matching its 26 resources to its loads in real time, appropriately metering its 27 deliveries, providing itself or contracting for 24-hour 2s scheduling and dispatch services with a datalink to PGEE's energy
+ 31
I 1 c ontrol center, accounting and charges for scheduling deviations, 2 s tandards for operation and modification of the interconnection, 3 operating standards for protecting against contingencies within l 4 the PGEE Control Area, requirements for load shedding and other l l 5 contract terms typical of PGEE's interconnection or control area 6 and transmission service agreements with other electric resale 7 entities but shall in such event comply with any generally- . 8 applicable tariff provisions providing for the. operation of the 9 PGEE system on an unbundled, open access basis as may.be 10 required, or promulgated by FERC. . . 11 12 11 NEW INTERCONNECTION WITH A TRIRD PARTY 13 11.1 Notification, Study and Resolution of Adverse 14 Impacts O 15 If the District proposes a new interconnection with is a Third Party supplier to provide transmission services which may 17 reasonably affect the reliability of PG&E's system, the District is shall promptly notify PGEE of such event. PGEE may request a 19 study of'such new Third Party interconnection affecting the Point 20 of Interconnection to determine the potential for any adverse 21 impact to PG&E. In preparing the study, the Parties shall 22 cooperate in providing information for studies and in the 23 development and review of any studies that may be performed by 24 either Party related to identifying a potential adverse impact 25 and to assure that appropriate agreements among the District, 26 PGEE and any Third Party, including replacement or revision of this Agreement as provided in Section 10, are executed and made () 27 28 effective by the appropriate regulatory agencies. Such 32
I t 1 a greements shall include provisions for the mitigation of any 2 r esulting adverse impact to the reliability of PGEE's electric 3 s ystem, for the compensation for any such adverse impact to PG&E, 4 or both. Any Costs reasonally incurred by PG&E in its 5 cooperation with the District in connection with a new 6 interconnection shall be reimbursed by the District. Unless 7 otherwise agreed by the Parties, all avoidance or mitigation a measures or modifications shall be completed and any compensation 9 due to an unresolved adverse impact shall be agreed upon before 10 the interconnection with the Third Party is..made. , 11 11.2 Consequences of Interconnection Without Prior 12 Agreement and Mitigation 13 Under this Agreement, the Parties have a duty to 14 negotiate in good faith and to attempt to agree upon avoidance or 15 mitigation measures, compensation and the allocation of Costs 16 pursuant to this Section 11 or, if agreement is not reached, to-17 resolve these matters in accordance with Section 24 (DISPUTE 18 RESOLUTION), prior to the District undertaking a proposed new 19 interconnection. If the District proceeds with a new . 20 interconnection with a Third Party for the provision of l 21 transmission services without prior agreement or otherwise not in 22 accordance with all of the provisions of this Section 11 then: 23 (a) PGEE may open its interconnection with the District so as to 24 not operate in parallel with the Third Party Interconnection, or 25 (b) the District shall compensate PG&E fully for all adverse 26 electric system effects, resulting from remaining interconnected In the . 27 following the completion of the new interconnection. 28 event that PGEE remains interconnected, subject to the provisions I 33
. - - - . - . - - _ - . _ - . - . - - . ~ . - - . . . . . - . - . - - . . . . - - . - . . - . - . - . - - . . . . . 1 of Section 14 (BILLING AND PAYMENT), PG&E may bill and the 2 District shall pay for (a) all services, including transmission 3 service or distribution service, or Control Area Services, 4 inadvertently or involuntarily provided by PG&E, under such 5 rates, terms and conditions as PGEE may establish, file, (which I 6 are subject to suspension and modification by FERC), including 7 those filed unilaterally with )'ERC by PGEE pursuant to Section a 205 of the Federal Power Act, and (b) all other Costs incurred by 9 PGEE that result from the adverse effects, electrical and other, 10 resulting from the new interconnection. Further, PG&E.may file l 11 unilaterally with FERC for termination of this Agreement and 12 service hereunder, under Section 205 of the Federal Power Act and - 13 FERC regulations promulgated thereunder, subject to the rights of 14 the District, if any, under Section 40 (TERMINATION) to protest , 15 such termination before FERC. 16 , 17 12 INSTALLATION AND ACCESS is Where it is necessary for PGEE to install any of its 19 f acilitiins at the Linde Substation, the District will grant such j 20 access as it may have the power to-so grant, and shall utilize 21 its best efforts to assist PG&E to obtain any other access in 22 order to effectuate the interconnection to otherwise perform the the District, to the 23 duties contemplated by this Agreement, 24 extent its rights permit, hereby grants to PG&E: (i) the right to 25 make such installation along the shortest practicable route 26 thereon (subject to the District's right to protect its 27 operations at the Linde Substation) of sufficient width to provide full legal clearance from all structures now or hereafter 2s 34
J d 1 e rected on such property for any fa'cilities of PG&E required to (~) ake delivery of electricity hereunder and (ii) the rights of i () 2 m 3 ingress and egress from the District's premises at all reasonable 4 hours for any purposes reasonably connected with the furnishing 5 of electric service and the exercise of any and all rights 6 secured to it by law or its tariff schedules. PG&E shall not be l 7 obligated to install such facilities unless and until all 4 s necessary licenses, permits, certificates, or other governmental j 9 authorizations or approvals that may be necessary are obtained, 10 and any necessary permanent rights-of-way and easements.are I 11 granted without cost to PG&E at locations satisfactory to PG&E on 12 and over the District's property, or'the property of others, for Electric facilities 13 the installation of PG&E's facilities. i gs 14 belonging to PG&E which are installed on the District's premises
\) 15 will be relocated only with the agreement of PG&E, which shall
' 16 not be unreasonably withheld, and at the District's expense. 17 The District shall, at its expense, provide any required i is site, site improvement, and acceptable enclosure for the District's metering transformers, foundations or pads, fencing or 19 walls around same, and a metering house or cubicle in accordance 20 21 with Prudent Utility Practice and consistent both with both the 22 District's and PG&E's specifications and the District's 23 requirements. 24 25 13 KETERING 26 13.1 Delivery Meters All electric power deliveries by PG&E to the ? () 27 2s District under this Agreement shall be metered by the District a t 35
_ _ _ _ _ _ - - ~ _ _ - . - . - . - - . - . _ - . - . - _ . - - . - - . - - - - . . - . ~ _ _ _ _ - Deliveries 1 the Point of Interconnection with revenue meters. i 2 s hall be metered at delivery voltages. 3 13.2 Power Supply Metering Requirements 4 The Parties shall cooperate in the installation and p rovision of access to the meters, as necessary for the J 5 f 6 D is'trict's Full Requirements Wholesale Electric Supplier to l 7 obtain the information in the form and at the time needed for the t j s Full Requirements Wholesale Electric Supplier'.to perform in i 9 accordance with its agreements with the Parties and 'as 10 contemplated under this Agreement, and, in..the case of.DPS, to comply with its obligations under the CATSA, or the CATSA 11 l 12 Successor, if any. The District sha'11 cooperate with the Full to allow i 13 Requirements Wholesale Electric Supplier and PGEE, reasonable access to connect with the District's meter at the ! 14 j 15 Point of Interconnection to allow the connection and installation 1
- 16 of required recording devices or telemetering equipment provided c
4 17 by PG&E and/or the Full Requirements Wholesale Electric. Supplier i is to District's meter. Any initial or subsequent Costs associated 1 19 with metering and communications modifications required to 20 accommodate the delivery of power by a Full Requirements 21 Wholesale Electric Supplier during the term of this Agreement, 22 shall be paid for by such Full Requirem'ents Wholesale Electric 4 23 Supplier. 24 13.3 Requirements-for Meters and Meter Maintenance Power and reactive power delivered to the District 25 26 shall be measured by suitable electric revenue meters owned and j () 27 installed at the Point of Interconnection by the District. Unless otherwise agreed, the District and the respective Full 28 36
i 1 R equirements Wholesale Electric Supplier, shall provide, install, () 2 own, operate, test, service and maintain meters and associated ; l A 3 r ecording or telemetering equipment at the Point of I 4 Interconnection required for proper billing and accounting l 5 purposes with respect to meters, or other related equipment, each 6 of which the District or such Full Requirements Wholesale Electric Supplier shall own. The District's metering equipment 7 ' a located at the Point of Interconnection shall. measure and record 9 real and reactive power flows and shall be capable of recording 10 flows in both directions. Such "in" and "out" meters shall be 11 designed to prevent reverse registration and measure and 12 continuously record such deliveries. 13 13.4 Meter Reading and Access 14 PGEE and the District shall each be responsible for i
\ 15 reading all revenue meters at the Point of Interconnection on or 16 about the first working day of each month and at such other times 17 as may be mutually agreeable. The District shall ensure that is PG&E has such access to the District's facilities as may be 19 required for verifying the proper operation and maintenance of 20 all revenue metering facilities.
21 13.5 Meter Testing and Meter Errors 22 For the purpose of measuring real and reactive power 23 service to the District, all revenue meters at the Point of 24 Interconnection shall be installed, tested, serviced and 25 maintained by The District in accordance with Prudent Utility 26 Practice and shall be tested by the District at regular intervals Meters
/~% 27 and at any other reasonable time upon request by PG&E.
V 28 shall be sealed, and the seals shall be broken only upon i 37
1 o ccasions when the meters are to be inspected, tested or () 2 adjusted, and representatives of the Parties shall be afforded easonable opportunity to be present upon such occasions. Any 3 r 4 m etering equipment found to be defective or inaccurate shall be immediately repaired or readjusted or replaced. If such a meter 5 6 fails properly to register or if the measurement made by such a 7 meter during a test varies by more than two percent (2%) from the the a measurement made by the standard meter used in the test, d 9 Parties shall determine and apply an adjustment in or,er to 10 correct all meter records of measurements made by the inaccurate or 11 meter for (i) the period since the last preceding meter: test, 12 (ii) actual period during which inaccurate measurements were made If 13 if the Parties determine that this period can be established. 14 necessary, the corrections may be estimated by the Parties from 15 the best information available for the period'of defect or 16 inaccuracy. Any correction in billings resulting from such 17 correction in meter records shall be made promptly and in is accordance with Section 14, and such correction in billings when 19 made shall constitute full adjustment of all claims between the i 20 Parties arising out of such defect or inaccuracy of the meter. I 21 No adjustment of bills for meter error shall be for a period in i i months time nor for a billing period more 22 excess of twelve (12) 1 23 than twelve (12) months past nor for a billing period prior to 1 1 24 the previous test. 25 13.6 Unavailability of Data f In the event metering data is unavailable for any 26 27 reason, the Parties shall make an estimate of the amount of real i 2s and reactive power or default power delivered by PG&E to the 38 4
- = -
1 D istrict and shall utilize such estimate in preparing bills for l 2 payment by the District. PG&E also represents that it will 3 utilize such estimate in settlements and accounting with the l 1 The 4 District's Full Requirements Wholesale Electric Supplier. 5 estimate will be based on reasonably available information 6 including, but not limited to, records of historical usage, 7 physical condition of the metering facility, available meter a readings and general characteristics of the District's operation 9 and facilities. , 10 - , 11 14 BILLING AND PAYMENT 12 14.1 Determination of the amo'unt of PG&E-supplied real 13 and reactive power delivered to the District shall be made each' 14 half-hour on an integrated demand basis by use of the District's 15 meters at the Point of Interconnection. 16 14.2 The District shall pay PGEE the Customer Charge, the 17 Reactive Power Charge, and the Reactive Power Correction Charge is at the rates provided in Appendix A, as those rates may be 19 superseded or changed from time to time pursuant to Section 35 20 The District shall pay PG&E for " default power" [ RATE CHANGES). 21 at the charge prescribed in Section 6.2. 22 14.3 The District shall pay PG&E monthly for such 23 services hereunder at: 24 Pacific Gas and Electric Company ~ Payment Processing Center 25 Research Unit / BSA P.O. Box 770000' 26 San Francisco, CA 94177 14.4 PG&E shall prepara and submit bills to the District 27 2s on or after the first day of each calendar month for services or 39
i i i
- 1 o ther performance provided under the Agreement during the I
- 2 preceding month. The Payment of any bill shall be due and must i
i 3 b e received by PG&E not later than the 30th calendar day 4 f ollowing the day on which the District receives the bill or, if 5 t hat 30th day is a Saturday, Sunday or legal holiday, the next business day. Such date shall be referred to as the Payment Due s 7 Date. A bill shall be deemed delivered on the third Work Day ' f after the postmarked date unless a copy of the bill is sent by e i ; electronic facsimile, in which case it shall be deemed delivered 9 l on the same day. If the District has a question concerning a 4 10 11 bill, it may review the back up data used in preparation of the 12 bill to the extent that data is still;available. l 14.5 If charges under this Agreement cannot be determined 13 f 14 accurately for preparing a bill, PG&E may use its best estimates l i 15 in preparing the bill and such estimated bill shall be paid by the District. Any estimated charges shall be labeled as such and J l -15 1 document the, basis for the estimate 17 PG&E shall, upon request,
- f. Estimated bills shall be prepared and paid in the same is used.
19 manner as other bills under this Agreement.
~
i 14.s If the District disputes all or any portion of a 20 2 it nevertheless shall, 21 bill submitted by PG&E to the District, in 22 not later than the Payment Due Date of that bill, pay the bill A dispute between either PG&E or the District and any 23 full. billing . 24 Third Party shall not be a proper basis for contesting a this d 25 Payments to PG&E of the District's obligations arisingffset, un er 26 Agreement are not subject to any reduction, whether by o payments into escrow, or otherwise, except for routine
) () 27 adjustments or corrections as may be agreed to by the Par i r 28 40
, ~ . . . , .
- -- _ _. . ~. _ _ _ _ _ _ _ _ _ __
1 a s expressly provided in this Agreement. 14.7 When final and complete billing information becomes [~')
\~/
2 ; ! 3 a vailable and a charge is determined accurately or billing errors l I 4 are identified and corrected, PG&E shall promptly prepare and I 5 submit an adjusted bill to the District, and any additional 6 payments by the District shall be made in accordance with the 7 provisions of this Section 14. Refunds by PG&E shall be paid to the District not later than thirty (30) calendar days after'the f a 9 date of the adjusted bill. All adjustments or corrections of 10 bills under this Agreement shall be subject to the interest provisions of Section 14.8. 4 11 12 14.8 Interest on an additiona1 payment shall accrue from 13 the Payment Due Date of the applicable bill and interest on a 14 refund shall accrue from the date payment of the applicable bill 15 was received by PGEE. 16 14.9 Any amount due under this Agreement which is not 17 timely paid shall accrue interest from the date prescribed in Section 14.8 un'til the date payment is made. The interest amount is 19 shall be determined using the interest rate applicable to any 4 20 amount due during a given month and shall be calculated using the of the 21 methodology for refunds pursuant to Section 35.19(a) 22 FERC's Regulations, 18 CFR S 35.19a. This interest rate shall 23 not exceed the maximum interest rate permitted under California 24 law. Interest shall be calculated for the period during which 25 the payment is overdue or the period during which the refund is 26 accruing interest. 27 14.10 If any portion of a bill is disputed, the District rS U 2s shall pay the full amount, without offset or reduction, in 41
~ - . ~. - . - .-.- -.-... ..-----.-- -.-. -~.-- -- - -.-.
i l i 1 accordance with this Section 14, by the Payment Due Date. In () 2 addition, the District shall, on or before the Payment Due Date, notify PGEE in writing of the amount in dispute and the specific j 3
- 4 basis for the dispute. PG&E and the District shall endeavor to !
! 5 resolve any billing dispute prior to the Payment Due Date of the 6 disputed bill. Within thirty (30) days of PG&E's receipt of the a f 7 District's notice of a dispute (or such extended period as the i
- 8 Parties may agree upon), the Parties shall attempt to agree on i
9 any adjustments to the disputed portion of the bill that may be 10 appropriate. If the Parties do.not agree, either Party.may ' 11 initiate dispute resolution pursuant to Section 24. 1 ! 12 14.11 If, after the District has paid the: full amount of a 13 disputed bill directly to PG&E, the results of dispute resolution .l 14 before a court or agency of competent jurisdiction include a b
\/ 15 determination that the amount due was different: than the amount paid by the District, a refund by PG&E to the District shall 16 17 include interest for the period from the date District's I 18 overpayment was received by PG&E to the data the refund is paid i
i 19
~
to the District, or an additional payment by the District to PG&E 20 shall include interest for the period from the original Ptyment . i 21 Due Data to the date the District's additional payment is 22 received by PG&E. Interest paid pursuant to this Section 14.8 23 shall be at the rate specified in Section 14.9. l 24 14.12 The District's failure to make any payment to PGEE i ' 25 on or before the applicable Payment Due Data shall constitute a 26 material breach if that f ailure is not corrected within seven (7) work days after PG&E delivers written notice to the District to () 27 28 cure that failure. In such event, PG&E shall be entitled to 42
4 i i i pursue any legal, equitable and regulatory rights and remedies it ! 2 may have. 1 3 l 4 15 APPENDICES INCLUDED l ! 5 The following Appendices to this Agreement, as they may be l 6 revised from time-to-time by written agreement of the Parties', i
- 7 are attached hereto and are incorporated by reference as if fully
! a set forth herein: i ~ 9 Appendix A -- Rate Schedule 1996 : 20 Appendix B -- Time Periods . I 11 Appendix C -- Dispute Resolutio'n and Arbitration i 12 13 16 ACCOUNTING PROCEDURES 14 PG&E shall record its Costs and maintain its accounting L/ 15 records in accordance with the Uniform System'of Accounts as l 16 prescribed by the FERC for public utilities and licensees subject !l < 17 to the provisions of the Federal Power Act, supplemented by $ 18 PGEE's regular accounting practices, as such uniform system and 3 19 accounting practices may be modified from time-to-time. a, 20 21 17 ADVERSE DETERMINATION OR EXPANSION OF OBLIGATIONS ^ , 22 17.1 Adverse Determination S 1' 23 It FERC or any other regulatory body, agency or 24 court of competent jurisdiction determines that all or any part 4 25 of this Agreement, its operation or effect is unjust, i i
- 26 unreasonable, unlawful, impruda.nt or otherwise not in the public interest, each Party shall be relieved of any obligations 4
27
) hereunder to the extent necessary to comply with or eliminate 1 2a ' 43 4
a - - - , - - ,
t such adverse determination. The Parties promptly shall attempt f i 1 2 to renegotiate the terms and conditions of the Agreement to i' 3 restore the original balance of benefits and burdens contemplated ! 4 by the Parties at the time this Agreement was made, consistent with complying with or eliminating the adverse determination.
- 5 4
s 17.2 Expansion of obligations 1 7 If the FERC or any other regulatory body or agency s or any court of competent jurisdiction orders.or decides that j 9 this Agreement be interpreted, modified, or extended: in such a i 10 manner that PG&E or the District may be required to extend its i
- 11 obligations under this Agreement to a Third. Party, or to incur i
12 new or different obligations to the 'other Party.or to Third f i j 13 Parties not contemplated by this Agreement, then the Parties i 14 shall be relieved of their obligations to the extent lawful and I 15 necessary to eliminate the effect of that order or decision, and i j 16 the Parties shall attempt to renegotiate in good faith the terms ' 17 and conditions of this Agreement to restore the original balance l ,' is of benefits and burdens contemplated by the Parties at the time ,4 $ 19 this Agreement was made. l 3 20 17.3 Renegotiation !; l
- 21 In the event that the Parties either
- (i) cannot 22 agree that a renegotiation is infeasible or unnecessary, or 23 (ii) the Parties cannot agree to amend or supersede this Agreement within three months after that order or decision, then:
24
' 25 (a) either Party may initiate arbitration in accordance with 26 Section 24 [ DISPUTE RESOLUTION); (b) PGEE may unilaterally file or (c) either Party may
() 27 28 replacement interconnection agreement, give the other Party written notice of termination, which ( 44 a
1 t ermination shall be effective thirty days after receipt of the notice by the other Party. The effect of such termination, and 2 3 the rights of the Parties thereunder, shall be as provided in 4 Section 40 [ TERMINATION). As used in this Section the term 5 " Agreement" includes both this Agreement and any tariff, rate or 6 rate schedule that in whole or in part results from or 7 incorporates this Agreement. . 8 17 .4 Scope of Renegotiation 9 Any new interconnection agreement to be. renegotiated 10 or filed unilaterally pursuant to this Section 17 shall contain 11 terms and conditions substantially similar to this Agreement and including 12 othar interconnection agreements of' comparable scope, interconnection, modification, 13 provisions for operations, 14 reinforcement, new interconnection, reactive power, conditions 15 for a new agreement, and may include provisions for power, j 16 transmission and Control Area Servicap if needed to remedy the 17 adverse determination. 18 19 18 ASSIGNMENT 20 18.1 consent Required No transfer or assignment of all or any part of 21 22 either Party's rights, benefits or duties under this Agreement 23
' sha)1. be effective without the prior written consent of the other 24 party; provided, however, that this Section shall not apply to mortgage, 25 interests that arise by reason of any deed of trust, 26 indenture or security agreement heretofore granted or executed
/" 27 either Party. ( Assignor's Continuing obligation 28 18.2 45
_ _ _ . . _ _ _ _ _ _ _ _ ._._ _.__ __.__-___.m._ . - _ _ _ _ . m. I i 1 The transferor or assignor of all or any part of any j 2 right, benefit or duty under this Agreement shall continue to be i 3 o bligated by its terms and conditions in the event its successor, 3 4 t ransferee or assignee fails to perform as required by the 5 agreement. 6 1s.3 Assignee's Continuing Obligation i 7 Any successor to or transferee or assignee of the k a rights or obligations of a Party, whether by voluntary tra sfer, 9 judicial sale, foreclosure sale or otherwise, shall be subject to ' t as l 10 pill terms and conditions of this Agreement to the same exten or assignee were an briginal i 11 though such successor, transferee, l I 12 Party. 13 14 19 CAPTIONS O) 15 All indexes, titles, subject headings, section titles and is similar items are provided for the purpose of reference and 17 convanience and are not intended to affect the meaning of the , is contents or scope of the Agreement. 19 ) 20 20 CONSTRUCTION OF THE CONTRACT l 21 Ambiguities or uncertainties in the wording of the Agreement 22 shall not be construed for or against either Party, but shall be 23 construed in accordance with the intent of the Parties 24 time this Agreement was made. 25 26 21 CONTROL AND OWNERSHIP OF FACILITIES The Electric System of a Party shall at all times be and 27 2s remain in the exclusive ownership, possession and control 46
! i
< 1 Party, and nothing in the Agreement shall be construed to give 2 the other Party any right of ownership, possession or control of 3 that system. All facilities installed by PGEE to make delivery 4 of electricity hereunder shall at all times be and remain the 5 property of PG&E, notwithstanding that they may be affixed to 6 premises owned or leased by or under license to the District. '
l 7 8 22 COOPERATION AND RIGNT OF ACCESS AND INSPECTION 9 Each Party shall give to the other all necessary permission 10 within its authority to enable it to perform its obligations 11 under the Agreement. The District, to the extent its rights : 12 permit, shall give PG&E the right to# have PG&E agents and is employees, enter the District's premises at reasonable times and 14 in accordance with reasonable rules and regulations for the and for 15 purpose of inspecting the property and equipment of PG&E, is reading the District's meters and obtaining recorded data, all in 17 a manner which is reasonable for assuring performance of the is Parties under the Agreement. 19 20 23 DEFAULT 21 23.1 Remedy for Default ; 22 If either Party breaches its obligations under this l l If l 23 Agreement, such breach shall constitute an event of default. the other Party may 24 any Party defaults under this Agreement, 25 terminate this Agreement; provided that prior to such termination L i 26 the other Party must provide the defaulting Party with written 27 notice stating: 1) the Party's intent to terminate; 2) the date 2s of such intended termination; 3) the specific grounds for l 47 f i l
- - .. .-. i
{ l 1 termination; 4) specific actions which the defaulting Party must 2 take to cure the default; and 5) a reasonable period of time, 3 which shall not be less' than sixty (r,0) days, within thich the j 4 defaulting Party may take action to cure the default and avoid
/
5 termination. Application of Section 24 and Appendix c of this 6 Agreement shall not be deemed to limit the right to terminate 7 this Agreement under this Section 23.1 independent of the ! a procedures under those provisions. Other Remedies for Default 9 23.2 i The remedy under Section 23.1.is not exclusive, and I~ 10 11 subject to Section 24 either Party also shall be entitled to 12 pursue any other legal, equitable or' regulatory rights and remedies it may have in response to a default by the other Party, 13 i 14 1 O 15 24 DISPUTE RESOLUTION is To the extent not inconsistent with the requirements of, or 17 rights of, the Parties at law, the Parties may use the provisions is in Appendix C as the means of resolving issues of engineering or and with regard to f
'19 technicail interpretation under this Agreement, 20 such arbitration, shall be bound by the determinations of such l arbitrators in that regard. Where arbitration is specifically l 21 22 provided for in this Agreement the Parties shall resolve disputes The 23 in accordance with the provisions of this section 24. '
j 24 Parties specifically intend that the scope of the issues to be 25 determined by arbitration shall be narrowly construed. 26 27 25 GOVERNING LAN This Agreement shall be interpreted, governed by and l 2s ) 48 l
l l 1 c onstrued under the laws of the State of California, as if l 2 e xecuted and to be performed wholly within the State of
- 3 California.
4 5 26 Indemnity 6 26.1 Definitions l 7 As used in this Section, with initial letters ' a capitalized, whether in the singular or the plural, the following 9 terms hall have the following meanings: , 10 26.1.1 Accident -- Personal injury, death, 11 property damage, or economic loss which: 12
'(i) is sustained by a Third Party 13 (" Claimant"), which is an ultimate use customer of a Party; 14 (ii) arises out of delivery of or 15 curtailment of or interruption to electric service, including but l
and 16 not limited to abnormalities in frequency or voltage; I 17 (iii) results from either or both of the is following:
- e.igineering, design, 19 20 construction, repair, supervision, inspection, testing, replacement, reconstruction, 21 protection, operation, maintenance, 22 use, or ownership of either Party's electrical system; or
- the performance or non-23 24 performance of either Party's obligations under the Agreement.
26.1.2 Indemnitee -- A Party defined in 25 26 Section 26.2.2. Indemnitor -- A Party defined in () 27' 23 26.1.3 Section 26.2.2. 49
I ! 1 26.2 Indemnity Duty 2 If a claimant makes a claim or brings an action 3 a gainst a Party seeking recovery for loss, damage, costs or s 4 e xpenses resulting from or arising out of an Accident against a 4 5 Party, the following shall apply: l 6 26.2.1 That Party shall defend any such claim or l 7 action brought against it, except as otherwise provided in this a Section 26.2. 9 26.2.2 A Party (" Indemnitor") shall hold 10 harmless, defend and indemnify, to the fullest extent permitted 11 by law, the other Party, its directors or members of its i 12 governing board, officers and employees ("Indemnitees"), upon 13 request by the Indemnitee, for claims or actions brought against 14 the Indemnitee allegedly resulting from Accidents caused by acts 15 or omissions cf the Indemnitor. 26.2.3 No Party shall be obligated to defend, - 16 17 hold harmless or indemnify the other Party, its directors or 4 is members of its governing board, officers and employees for , 19 Accident's resulting from the latter's gross negligence or willful 20 misconduct. 26.2.4 If a Party successfully enforces this 21 22 indemnity, the Party against which enforcement is required shall 23 pay all costs, including reasonable attorneys fees and other 24 litigation expenses, incurred in such enforcement. 1 25 26 27 .7UDGMENTS AND DETERMINATIONS l When the terms of this Agreement provide that an action may () 27 23 or must be taken or that the existence of a condition may be 50
'1 e stablished based on a judgment or detarmination of a Party, such judgment shall be exercised or such determination shall be made f \s l 2 I
3 reasonably and in good faith, and where applicable in accordance , 4 with Prudent Utility Practice, and shall not be arbitrary or 5 capricious.
- 6 i 7 2s LIABILITY .
s 2s.1 To Third Parties 9 Nothing in this Agreement shall be construed to or 10 create any duty to, any standard of care with reference to, f i 11 any liability to any Third Party. 4 12 as.2 Between Parties 13 Except for its willful action or gross negligence, 14 or with respect to breach of this Agreement or with respect to O 15 the indemnity duty under Section 26.2, no Party, nor its 16 directors or members of its governing board, officers, employees 17 or agents shall be liable to another Party for any loss, damage, l , is claim, cost, charge or expense arising from or related to this I i neither 19 Agreemen't. In the event of breach of this Agreement, - 20 Party, nor its directors or members of its governing board, I 21 officers, employees or agents shall be liable to the other Party for any consequential, special or indirect damages. 22 ! 23 2s.3 Protection of a Party's Own Facilities 24 Each Party shall be responsible for protecting its 25 facilities from possible damage by reason of electrical 26 disturbances or faults caused by the operation, faulty operation, j () 27 or non-operation of another Party's facilities, and such other 28 Party shall not be liable for any such damages so caused. 51
1 2s.4 Liability for Interruptions 2 Neither Party shall be liable to the other, and each I 3 P arty hereby releases the other and its directors, officers, 4 employees and agents from and indemnifies them, to the fullest 5 extent permitted by law, for any claim, demand, liability, loss 6 or damage, whether direct, indirect or consequential, incurred by 7 either Party, which results from the interruption or curtailment ; i a of electric service made available by PGEE under this Agreement. 9 10 29 ACCESS TO INSTALL AND NAINTAIN FACILITIES 11 Either Party, upon request by the other Party and'to the 1 12 extent that its rights permit, shall'give to the other Party 13 access to construct, install, operate, maintain, inspect, test, 14 read, check, rsplace and repair, upon the property of said Party, 15 such facilities as are necessary for the performance of its is obligations under this Agreement or for performing any other work 17 incident to rendering the service provided under this Agreement. is 19 30 NO' DEDICATION OF FACILITIES 20 Any undertaking by PG&E to District under any provision of 21 this Agreement is rendered strictly as an accommodation and shall 22 not constitute the dedication by PG&E of any part or all of its 23 Electric System to the public or to the District or any Third 24 Party. Any such undert ning under a provision of, or resulting 25 from, this Agreement by PG&E shall cease upon the termination o : 26 PGEE's obligations under this Agreement. 21 7% 52
i t i 1 31 NO OBLIGATION TO OFFER SAME SERVICE TO OTHERS 2 By entering into this Agreement for service to District and , I ) 3 filing it with FERC, PGEE does not hold itself out to furnish 4 like or similar service to any other person or entity. 5 6 32 NO PRECEDENT l i 7 This Agreement establishes no precedent with regard to any a other entity or agreement. Nothing contained in this Agreement 9 shall establish any precedent for other arrangements.as may 10 exist, now or in future, between PG&E and the District.for the 11 provision of any electric service. 1 12 13 33 MO TRANSMISSION, DISTRIBUTION OR CONTROL AREA SERVICES 1 14 PROVIDED l Under this Agreement, PGEE does not undertake to provide or 15 ' is make available any transmission service, distribution service, or 17 Control Area Services using any part of its Electric System for is the District or any Third Party except as otherwise provided 19 herein. Nothing in this Agreement shall be construed to preclude ,ii 20 the District from seeking transmission, distribution and control
?,1 Area Services under a separate arrangement or a successor 22 arrangement with PG&E for a new interconnection agreement with 23 PGEE, or pursuant to any tariff for such service which PG&E may have on file with the FERC, or on the basis of other rights that 24 25 may exist in law or regulation.
26 27 34 NOTICES declaration, demand, information, 2s Any notice, request, 53
1 report, or iten otherwise required, authorized or provided for in f 2 t his Agreement shall be given in writing, except as otherwise l 3 p rovided in this Agreement and shall be deemed properly given if 4 d elivered personally or by electronic facsimile transmission with 5 confirmed recei?t, or sent by first class United States Mail or overnight or express mail service, postage or fees prepaid, to 6 7 each of the persons specified below:
- 1 s (1) To the District:
1 9 General Manager 1231 lith Street 10 P.O. Box 4060 Modesto, CA 95352 11 12 (2) To PGEE: 13 Vice President-Power System Pacific Gas and Electric Company 14 77 Beale Street, Room 2313, B23B ( P.O. Box 770000 15 San Francisco, CA 94177 a 16 Manager, Grid Customer Services Department Pacific Gas and Electric Company 17 77 Beale Street, Room 2319, B23B P.O. Box 770000 is San Francisco, CA 94177 19 34.1 Changes of Notice Recipient 20 Either Party may change its designation of the 21 person who is to receive notices on its behalf by giving the 22 other Party notice thereof in the manner provided in this No more than two persons shall be 23 Section 34 [ NOTICES]. 24 designated by a Party to receive notices. 25 34.2 Routine Notices 26 Any notice of a routine character in connection with l 27 service under this Agreement or in connection with the operation 2s of facilities shall be given in such a manner as the Parties may 54
i t i determine is appropriate from. time to time, unless otherwise - 2 provided in this Agreement. 3 34.3 Reliance on Motica 4 Each Party shall be entitled under this Agreement to 5 rely on the other Party's notice when given (or not given, when a 6 Party fails to provide notice within the time prescribed) as i 7 having all necessary approvals of that other Party's management a and Board of Directors, and any notice (cr failure to provide 9 timely notice) hereunder shall be binding on the noticing Party l 10 and shall obligate that Party to make such gayments or to perform 11 such duties as are necessary associated with the notice or, if a ! I' 12 Party fails to provide timely notice, that failure shall also 13 bind that Party to having waived any rights dependent upon such i 14 notice. 15 ; l 1
' 16 35 RATE CIANGES 17 Except with respect to the customer service charges provided I'
is in Section 6.4, nothing in this Agreement shall be construed as ;' ' is affacting in any way the right of PG&E to unilaterally make 20 application to the FERC for a change in rates under Section 205 21 of the Federal Power Act and pursuant to the FERC's rules and 22 regulations promulgated thereunder; provided that the District 23 shall also have the right to protest and object to the level or 24 form of such change in rates and otherwise to exercise any and 25 all rights it may have with respect thereto, including its rights The term " rates" as 25 under Section 206 of the Federal Power Act. 27 used herein shall mean a statement of rates and charges for or in A change 28 connection with the services covered by this Agreement. 55
1 i
- j. f -1 in rates may also include changes in the underlying methodology
- 2 by which such rates and charges are developed.
i !, 3 ) 4 36 REGULATORY AUTRORITY l 5 The Agreement is subject to the jurisdiction cf those j 6 regulatory and other authorities having jurisdiction over the I
- 7 Parties and the Agreement.-
t i 4 9 37 RESPONSIBILITY FOR PAYMENTS AND SECURITY 10 37.1 The District shall be fully responsible-and liable 11 to PGEE for payment for all of the District's obligations for the sale of goods and provision of services by PG&E. As used in the d . 12 and Agreement, the term " goods" shall have the same meaning as, I 13 be defined by, the term " goods" in the california commercial Code
~
14 i 15 as of the date this Agreement was made. The term " service" shall I is mean all of PGEE's obligations under the Agreement, including but 17 not limited to.the sale of or provision for the availability of is any reactive power service and any " default power" under is Sections 6.2 or 6.3, and shall include the utilization of 20 facilities owned or operated by PGEE to effect any of the 21 foregoing cales or services whether by leasing or other
- 22 arrangements. As defined herein, the term " service" is used 23 without regard to the form of payment or compensation for the 1
24 sales or services rendered, whether by purchase and sale or 25 otherwise. i 26 37.2 The Parties shall perform unconditionally and fully 1 d 27 each and every obligation which each has under this Agreement, to , including but not limited, in the case of the District, 4 28 56
- . - - . - - . .- . . . . . - - . - . - . ~ . - - . - - - - . - . - . _ . - . _ - -
I I i liability for payment to PGEE, provided, that this Agreement 2 s hall not restrict any right any Party may otherwise have to 3 p ledge any of its revenues, funds, assets, rights, property or 4 interests therein. The other Party's status as a creditor shall 5 n ot be subordinate to the interest of any creditor, subject to 6 any pledge or debt obligation, provision of law or existing 7 obligations of a arty. , l 3 37.3 If any Party fails to pay or perform unconditionally 9 any part of any debt, liability, or obligation incurred by it 10 under the Agreement within 30 days after receipt of a Aill or '
. ~
11 notice to it, such nonpayment shall constitute a default by such , 12 Party. 13 37.4 In the event of a default by any Party upon any 14 debt,. liability or obligation, the other Party shall give written 15 notice thereof to such Party. In the event of any default by a. Party which is not 16 37.5 ! non-17 cured within 30 days after service of notice of default, l l is defaulting Party may immediately avail itself of any of the 9 19 following remedies at its option: 37.5.1 A Party may by written notice to the 20 21 other Party terminate this Agreement insofar as it is a contract between them, and termination shall be effective thirty days 22 23 after the giving of notice, which termination shall not impair f 24 any claim which has accrued to one against the other prior to th 25 termination, except that PGEE will not so terminate this 26 Agreement under this Section so long as the provisions of 27 Section 14 [ BILLING AND PAYMENT) have been fully complied 2s District. ! 57
1 1 1 37.5.2 A Party may avail itself of any other i f-w emedies provided herein or by law with respect to any i
; (_/ 2 r 3 unsatisfied portion of the debt or the unfulfilled obligation.
4 4 37.5.3 A Party may bring a civil action in any ' 5 court of competent jurisdiction against the defaulting Party. 6 37.6 The District shall make payments in full 1 - 7 notwithstanding the suspension, interruption, interference,with, , - a or curtailment of the services contracted for in whole or in part, in accordance with this Agreement. Such payments are not s ! 9 10 subject to any reduction, whether.by offset or otherwise, and are not conditioned upon performance by District under this 4 11 i 12 Agreement, or upon performance by the District or by any Third i I 13 Party under any other rate schedule or agreement. 15 38 RULES AND REGIEkTIONS 'l . 16 PGEE and the District may each establish, and, from time to a
.17 time, change such procedure, rule, or regulation as they shall is determine are necessary in order to establish the methods of 19 operation to be followed in the performance of this Agreement; provided that any such procedure, rule, or regulation is not 20 If a Party 21 inconsistent with the provisions of this Agreement.
J 22 objects to a procedure, rule, or regulation established by the 23 other Party it will notify the other Party and the Parties will endeavor to modify the procedure, rule, or regulation in order to 24 ' 25 resolve the objection. 26 27 39 SEVERABILITY 28 If any term, covenant or condition of this Agreement or its 58
r=w4 .-%as+e i o { i l 1 a pplication is held to'be invalid as to any person, entity or 2 c ircumstance, by FERC or any other regulatory body or agency or < j 3 c ourt of competent jurisdiction, then such term, covenant or i 4 c ondition shall cease to have force and effect to the extent of 5 that holding; in that event, however, all other terms, covenants 6 and conditions of this Agreement and their application shall'not 7 be affected thereby but shall remain in full force and effect j s unless and to the extent that a regulatory agency or court of 9 competent jurisdiction finds that a provision is not' separable 10 from the invalid provision (s) of,this Agreement. l 11 12 40 TERMTuavIog 13 40.1 Termination 14 This Agreement shall terminate as provided in l
) The District hereby recognizes PGEE's right pursuant ;
15 Section 5. II ' is to section 5 to terminate this Agreement and all rate schedules; l directly 17 filed pursuant to this Agreement and shall not oppose, 3 1 18 or indirectly, the exercise of such right provided that such The f' 19 exercise is in accordance with the terms of this Agreement. 20 Parties agree that neither Party shall be required to continue to 21 provide services based in whole or in part on the existence of if 22 this Agreement beyond the maximum statutory suspension period, 23 that period is applicable for any reason, nor shall either Party 24 attempt to defeat this intent by opposing such termination or 25 otherwise petitioning FERC for relief in contradiction of the 26 intent or express language of this Agreement. () 27 40.2 continuing Rights of The District Upon Termination Upon termination of the Agreement, the District 28 59
1 shall continue to have such rights, if any, to be connected to 2 PGEE's Electric System that are provided at law or regulation, l 3 p rovided however that notwithstanding the foregoing the District may assert its rights, if any, to contest a termination of this 1 4 5 Agreement at FERC only with respect to the factual bases for l 6 termination stated in Sections 5.3(b) and (c) of this Agreement. 7 The existence of this Agreement, after its termination, shall not a be used by either Party to establish or defeat the existence of 9 any rights provided by law or regulation. Termination of this l 10 Agreement, if approved by FERC, also shall terminate any - : other ; 11 tariff or rate schedule which in whole or in part results from or l i 1 12 incorporates this Agreement, to the extent not inconsistent with 13 a Party's aforementioned rights at law. After termination of 14 this Agreement and any required FERC acceptance or approval of 15 such termination, all services, all rights to iservices provided is under this Agreement or such tariff or rate schedule shall cease, 17 and the District shall not claim or assert any continuing right is to such services other than as may be provided by law or 19 regulati'on. Such termination shall not affect rights and 20 obligations of a continuing nature or for. payment of money for 21 services provided prior to termination. This Section shall not 22 be construed as a bar to the assertion by the District of any 23 rights it may have to service following termination of this 24 Agreement, independent and exclusive of the Agreement or any 25 predecessor. 26 40.3 Rights of PGEE Upon Termination ' In no event shall PG&E be required under this 27 28 Agreement to continue to provide services based in whole or in 60
4 i 1 p art on the existence of this Agreement beyond a five-month i 2 s uspension period, should the FERC deny, condition, suspend or i 1 t 3 defer PG&E's notice of termination. i 4 40.4 Stanislaus Commitments l 5 The Parties agree that any termination of this if any, 6 A greement shall not affect those rights or obligations, 7 which the District and PG&E sach may have under the Stanislaus a Commitments. , 9 - 10 41 UNCOUTROLLABLE FORCES J 11 A Party shall not be considered to be in default in the 3 (other than an i 12 performance of any obligation under the Agreement 13 obligation to make payments for bills rendered pursuant to the 14 Agreement) when a f ailure of performance is the result of
- 15 Uncontrollable Forces, j 16 17 42 WAIVER OF. RIGHTS l
17 Any waiver at any time by any Party of its rights with or with respect to any 19 respect to a default under the Agreement, shall not 20 other matter arising in connection with the Agreement, 21 constitute or be deemed a vaiver with respect to any subsequent 22 default or other matter arising in connection with the Agreement. in ' 23 Any delay short of the statutory period of limitations, 24 asserting or enforcing any right, shall not constitute or be " 25 deemed a waiver. 1
! 26
- O l
27 43 ENTIRE AGREEMENT; AMENDMENTS 2s The Parties agree that the provisions of this Agreement 61
i I l 1 c onstitute the entire agreement between them regarding the l O 2 s ubject matter of the Agreement and the Parties' rights and l l 3 obligations with respect thereto. This Agreement is intended to l l 4 be the complete and exclusive statement of the terms of the i 5 Parties' agreement which supersedes all prior and contemporaneous ; i 6 offers, promises, representations, negotiations, discussions, 7 communications and contracts that may have been made in connection with the subject matter of this Agreement. No a 9 representation, covenant, or other matter, oral or written, which 10 is not expressly set forth, incorporated, or referenced.in this l shall be a 11 Agreement (except for applicable laws and regulations) This Agreement may be
~
12 part of, modify, or affect this Agreement. 13 modified by written agreement of the Parties. O 15 44 NO TEIRD PARTY RIGHTS OR OBLIGATION 16 The District's Full Requirements Wholesale Electric Supplier 17 is not a Party to this Agreement and nothing herein is intended is to expand, add to, modify or change in any way the rights or { a 19 obligations of such entity or Third Party under the CATSA, j 20 CATSA Successor, the MID-DPS Agreement or'any other separate l 21 agreements between such entities and either Party. l 22 23 45 EXECUTION day of 1996 but effective as Executed this 24 25 set forth above. 26 27 MontsTo InazaaTIou DIsraIcI, By A CaLIromuIA InazanTIon DIsTaIcT 28 AcTIsa zT aun Tsmoons ITs monan or DIREcToms 62
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4 s / s i a 4 d .I 4 I 1 o 3 Appendix A t 1 4 RATE SCHEDULE
}
s I A d a
J 1 Appendix A 2 RATE SCHEDULE 3 4 A.1 The Parties agree that the services provided by PG&E to MID 5 p ursuant to the terms and conditions of the Agreement shall be 6 provided to MID by PGEE at the rates and pursuant to the 7 additional terms and conditions in this Appendix A. Nothing a contained herein shall be construed as affecting in any way the 9 respective rights of PGLE or MID under this Appendix A to 10 unilaterally make application to FERC, or t'o oppose such 11 application, for a change in rates,. charges or rate methodologies 12 pursuant to Section 6. The rates and methods for calculating i 13 payments due in this Appendix A shall remain in effect and 14 unchanged until the earlier of (a) PG&E or MID filing with FERC (l 15 to supersede those rates and methods for calculating payments due 16 or (b) the termination of this Agreement, and shall not otherwis~e 17 be subject to change. 18 The Parties.have agreed to the initial rates and charges 19 under the Agreement as follows: 20
- $150 per month 21 Customer Service
- $0.001 per kVarh 22 Reactive Power Reactive Power Correction : to be filed 23
- as described in A.5 24 Default Power 25 26 A.2 CUSTOMER SERVICE CHARGE O 27 The Parties have agreed upon a Customer Service Charge of 2a $150 per month, fixed for the Term of this Agreement to reimburse A-1
4 l + l 1 1 P GEE for its costs of labor and supervision for billing services
)
2 w hich PGEE provides to MID including, accounting for reactive l 3 p ower and default power as provided in Sections 6.2 and 6.3. 4 l 1 5 A.3 REACTIVE POWER CHARGE ' Pursuant to Section 6.3 of the Agreement, MID shall ; 6 ) maintain zero reactive power flow at the Point of 7 1 Interconnection. The District shall meter reactive power flow at l a . I 9 that location. To the extent that the MID does not maintain zero 10 reactive power flow, PGEE shall charge the';MID monthly;at the 11 rate of S0.001 per kvarh for reactive power, both leading and A reactive power charge shall 12 lagging, not supplied by the MID. 13 be included in each month's bill and, unless otherwise agreed, () 14 15 shall apply at the Point of Interconnection. 16 A.4 REACTIVE POWER CORRECTION CEARGE 17 For each monthly billing period the MID shall also be
.18 subject,to a Reactive Power Correction Charge as set forth below I The Reactive Power Correction Charge 19 for excess KVAR Demand.
20 shall be based on the higher of the on-peak or off-peak excess 21 KVAR Demand in the monthly billing period multiplied by the During on-peak periods, as 22 Reactive Power Correction Rate. 23 defined in Appendix B, the excess KVAR Demand of the MID shall be 24 the amount of KVAR by which the KVAR Demand flowing from PG&E to 25 the MID oxceeds 14.25% of the KW Demand in any month (0.99 During off-peak periods as defined in 26 lagginr, power factor). 27 Appendix
- B, the excess XVAR Demand of the MID shall be the 28 greater of (a) the amount of KVAR by which the KVAR Demand ;
A-2
. . _ . . ~.. - - . - . . . . - . - . - - - - . . . _ - - . - . - - . . . - . . . . - - - - -
1 1 l 1 f lowing from PGEE to the MID exceeds 16.45% of the KW Demand 4 2 (0.9867 lagging power factor), or (b) the amount of KVAR by which j 3 t he KVAR Demand flowing from the District to PGEE exceeds 5.70% i 4 of the KW Demand (0.9989 leading power factor). At the time of - 5 e xecution of this Agreement, PG&E has not developed the Reactive Power Correction Rate. Prior to charging the Reactive Power 6 j
- 7 Correction Charge PGEE shall file with and obtain the acceptance ,
of the FERC for the Reactive Power Correction charge. 1 8 i , i 9 i
- 10 A.5 DEFAULT POWER CHARGE . .
a 11 The Parties have agreed upon the Default Power rates set j 12 forth in Section 6.2.3 which shall be the charge applied to the 13 amount of default power provided by PGEE in accordance with 14 Section 6.2.2, unless such charge has been modified as provided 1 15 in Section 6.2.4. 16 j 17 ! is 1 l 19 ! zo , 21 22 23 1 ~ 24 25 26 (k 27 28 A-3
j 4 i 4 4 n s I i 4 4 1 i s .l Appendix B i i TIME PERIODS a i t i i
.i
.d l
.m_.
l 1 Appendix 3 2 TIME PERIODS l 3 I 4 B.1 The on-peak and off-peak time periods applicable under this 5 agreement are: l On-Peak: 6:00 a.m. to 10:00 p.m. 6 7 Monday through Saturday, ' except holidays a p Off-Peak: 10:00 p.m. to 6:00 a.m. 10 Monday through Saturday; 11 all day Sunday and holidays 12 The holidays applicable to this section B.1 are as follows: 13 New Years Day; Memorial Day; Independence Day; Labor Day; 14 Thanksgiving Day; Christmas Day; and any other holidays 15 designated by the Western System Coordinating' council or its is successor from time to time. 17 1s 19 20 21 22 23 24 25 26 28 B-1 1,
- -, ._. . .. - .- ~ ~ . - - - - . - . ~ . . - . . . . - . . . . - . . - _ _ . . - . . . . . . - . . . . - . . _ _ . . _ . _
j !
? l i l t l 1
4 l l l 1 l l b d a Appendix C DISPUTE RESOLUTION AND ARBITRATION 4 f
. . - . . . . - . . - . . -. - - - _ ~ . - ~ . - - . . - . - - - . .- . . - - . - . - - - . -
1 Appendix C 2 DISPUTE RESOLUTION AND ARBITRATION
.3 4 c.1 DISPUTE RESOLUTION 5 The^ resolution of disputes under Section 24 of the 6 Interconnection Agreement between Pacific Gas and Electric l
I I 7 Company and the District dated - i a (" Agreement"), to which this document is attached as Appendix C 9 thereto and incorporated therein, shall be conducted: pursuant to 10 the following procedures, and any arbitration shall be. limited to those issues specified in Section 24 of the Agreement. Absent an l 11 12 agreement among the Parties to an arbitration convened under 13 these procedures, an arbitration panel convened pursuant to the 14 following procedures shall make an expedited threshold ruling
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15 upon its jurisdiction to consider a given issues or issues under 16 Section 24 of the Agreement. 17 18 C.2 NOTICES AND SELECTION OF ARBITRATORS 19 Wh'en a dispute arises which is subject to the dispute either 20 resolution procedures of Section 24 of the Agreement, 21 Party may commence arbitration by notifying the other Party in 22 writing of its desire to commence arbitration. Such notice shall 23 identify the name and address of an impartial person to act as an 24 arbitrator. Within ten (10) days after receipt of such notice, 25 the other Party shall give a similar written notice stating the 26 name and address of the second impartial person to act as an + Each Party then shall submit to the two named () 27 arbitrator. 28 arbitrators a list of the names and addresses of at least three C-1
1 i ' 4 i l- 1 p ersons for use by the two named arbitrators in the selection of 2 the third arbitrator. If the same name or names appear on both 3 lists, the two named arbitrators shall appoint one of the persons If no name appears i 4 named on both lists as the third arbitrator.
- 5 on both lists, the two named arbitrators shall select a third l 6 arbitrator from either list or independently of either list. If
- 7 the two named arbitrators cannot agree on the selection of the s third arbitrator, the third arbitrator shall be appointed by the i
, 9 Chief Judge any United States District Court in the Ninth Circuit i 10 upon the joint request of the two named arbitrators. Each 1 l 11 arbitrator selected under these procedures shall be a person i 12 experienced in the construction, design, operation or regulation is of electric power transmission and distribution facilities, as y 14 applicable to the issue (s) in dispute. 15 15 C.3 PROCEDURES 17 Within fifteen (15) days after the appointment of the third 18 arbitrator, or on such other date to which the parties may agree, 19 the arbitrators shall meet to determine the procedures that are 20 to be followed in conducting the arbitration, including, without 21 limitation, such procedures as may be necessary for the taking of 22 discovery, giving testimony and submission of written arguments Unless otherwise mutually agreed 23 and briefs to the arbitrators. 24 by the parties, the arbitrators shall determine such procedures 25 based upon the purpose of the Parties in conducting an cpecifically, the 26 arbitration under section 24 of the Agreement, least expensive and () 27 2s purpose of utilizing the least burdensome, most expeditious dispute resolution procedures consistent with C-2
..._m. _ _ _ _ _ _ _ . . _ _ _ _ _ _ _ _ . . _ _ _ . _ _ _ _ . _ _ . . _ ._.____ _
1 p roviding each Party with a fair and reasonable opportunity to be 2 heard. If the arbitrators are unable unanimously to agree to the 3 p rocedures to be used in the arbitration, the arbitration shall 4 be governed by the Commercial Arbitration Rules of the American 5 Arbitration Association. 6 7 C.4 REARING AND DECISION
- s After giving the Parties due notice of hearing and a s reasonable opportunity to be heard, the arbitrators shall hear 10 the dispute (s) submitted for arbitration and shall render their 11 decision with ninety (90) days after appointment of the' third 12 arbitrator or Lach other date selected upon the mutual agreement 13 of the Parties. The arbitrators' decision shall be made in 14 writing and signed by any two of the three arbitrators. The 15 decision shall be final and binding upon the parties; provided, 16 however, under no circumstances are the arbitrators authorized to 17 award any money damages in favor of either Party in rendering a is decision and award. Judgment may be entered on the decision in is any court of competent jurisdiction upon the application of 20 either Party.
21 22 C.5 EXPENSES 23 Each Party shall bear its own costs and the costs and ; l 24 expenses of the arbitrators shall be borne equally by the 25 parties. 26 ! O 28 ; C-3
$DESTEC OESTEC POWER SERVICES. INC.
DESTEC POWER SERVICES.1NC. O ~ A Suosiciary of Cestec Energy. Inc. 1676 N. California Bouievaro. Su.te 400 l January 30,1996 P.o. ora. r s I Walnut Crees. California 94596 (5101746 5279 Fax (5101746 5240 Manager - Grid Customer Service Pacific Gas & Electri Company Mail Code B23A P.O. Box 770000 San Francisco, CA 94177 . RE: MSD TRANSMISSION INCREASE Dear Sir. l Pursuant to Section 6.6 of the Control Area and Transmission Service Agreement ("CATSA") l between Destec Power Services, Inc. (DPS) and Pacific Gas and Electric Company, DPS hereby requests approval of an additional 10 MW of transtrussion level Marmmm Simultaneous Demand (MSD) for the month August,1996. This request is intended to accommodate full-requirements j service at Modesto Irrigation District's (MID's) Linde substation. p DPS appremm your cooperation in this regani. The following information is included for your l ( ,) review pursuant to Section 6.6.1 of the CATSA: 6.6.1 (a) the Transaction Points for which the addition or increase is requested: See Appendix K (attached hereto). 6.6.1 (b) the Mnim"m Delivery Capability, Maxinnnn Receipt Capability or MSD associated with the request: See Appendix K (=r'st hed hereto) for a complete list of Maximum Delivery Capability, Maximum Receipt Capability, and MSD. 6.6.1 (c) the transaction contemplated, including tb: name of a 71urd Party utility, if applicable: The transaction contemplated will be the delivery of energy through MID's Ltade substation required to satisfy the full energy requura of MID at that delivery point. MID has approximately 10 MW ofload at a high load factor at the Linde suostation. O DFSITC CONHDENHAL t
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. _ _ _ _ _ _ . _ . _ _ _ - _ _ . . _ _ _ . _ _ . . _ _ _ . _ _ _ _ _ _ _ . . _ . . _ _ _ ..m._
J PACIRC GAS & ELECTRIC CD. JANUARY 30,1996 .
- PAGE 2 j i
i . I l 6.6.1 (d) the amount of spinning reserve DPS may schedule at each Input Point: i
- The provision for spinmng reserve at each input point will be within the receipt capability .
4 of each input point as shown per AWir K. i i i j 6.6.1 (e) monthly profile of energy to be transminad frtun a source, or to a load, by on-peak, ! partial peak, off-peak ard super off-peak time penod for each year; i ! At each input point the load profile (for DPS energy) is not pred2ctable in graphical form j at this pomt in time. The amount of energy at each input point, for.this request, will not i exceed the " Excess MW approved amount" (if applicable);or the MSD (whichever is less). - l Additionally, the load profile for each " Schedule A" generator will not change due to this i request. The allocation of power from such resources may change, but the output of each'
- generator will not.
6.6.1 (f) expected monthly and annual capacity factors; i ~ Per the response to item 6.6.1 (e) above the monthly capacity factors for DPS can range
- from 0 - 100% at each input point. However, the capacity factor for each " Schedule A" generator will not change due to this request.
, 6.6.1 (g) the day upon which the addition or increase is requested to become effective and to f termmate: This request in MSD transmission is requested to begin on hour ending 0100, August 1, l 1996 and tertmnate on hour ending 2400, August 31,1996. t l 6.6.1 (h) other information which DPS elects to provide, or which PG&E reasonably requires, ! to determme the acceptability of the requested addition or modification. I I No other information is currently being included in this reqwst. j l l i i i !O j DEFTEC CONHDENTIAL i t d
i PACIFIC GAS & ELECTRIC CO. JANUARY 30,1996 . i PAGE3 i t Please note that 2 request is highly confidential and proprietary pursuant to Sections 8.21 and
- 8.22 of the CATSA. In accordance with these provisions, PG&E may use the information in this request for no purpose other than to discharge its obligations and exercise its rights pursuant to l the CATSA and may distribute this information only to PG&E personnel that are required to i have it for such purposes. Please note that these provisions stnctly prohibit PG&E from '
i disclosing information in this request to any third party or PG&E's met % personnel without the wriaen p;- nei= of DPS. Thank you for your %.Gon with respect to this request. I look forward to receiving your response per Section 6.6.2 of the CATSA. Cordially, ' DESTEC POWER SERVICES, INC. 4
. 7 ' l YT ?/
- Frnnthn F. Frkhart, Jr.
Manager, Power Control Western Operations l cc: Brian Haney, PG&E Robert Lambert, PG&E Anachments: (1) i e 4 t i 4 3 f A
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P.O.bs D0000 - February 9.1996 wrmamp wirr ) 41s5734s* :2 4154r3-9174 4 Mr. Chnstopher J. Mayer ) Assistant General Manager, Planning and Marketing Modesto Irrigation District { 1231 Eleventh Strect/ P.O. Box 4060 l Modesto.CA 95352
Subject:
Your Letter of January 29,1996
Dear Mr. Mayer:
On Febmary 1.1996. Mr. Macias received your January 29,1996 letter regarding the proposed Interconnection Agreement (Proposed Agreemem) between Modesto Ittigation District (Modesto) and PG&E st the Linde Substation, located as 2000 Loveridge Road, Pittsburg, CA. Mr. Macias forwarded your letter to me for a response. Before PG&E can
-3 negotiate such an agreement.1 would first appreciate answen to the following list of Q questions (this list is not intended to be comprehensive I may have more questions in the future):
. Your letter states Modesto recently purchased the Linde Substation. Please provide evidence of Modesto's ownership of the Linde Substation including:
a) A du'amt of tide showing date of acquisition. b) Evidence of any required local, state or federal permitting requirements of which Modesto is aware. c) A legal descripuon of the propeny owned.
. How is this Proposed Agreement related to the existing March 26,1988 Interconnection Agreement (IA), as amended, between Modesto and PGAE?
a) Does it relate in any way to the IA or any other existing Modesto-PG&E agreement? b) Does it modify or reopen any existing Modesto-PGAB agreement? c) Is it intended to be an amendment to any er.isting Modesto-PG&E agreement?
. Your letter mentions that the Proposed Agreement is modeled after PO&E's Site Interconnection Agreement witti the Port of Oakland (Port Agreement), and also states the changes were kept to a Dunimum. Would you please provide us with a table * '
of contents and a ted.line strite-out version of the Port Agreement and explain why any provisions from the Port Agreement have been eliminated or changed for the Proposed Agreement.
i i l 1 3 i
- i 1
1 i i- ) Mr. &**@r J. Mayer i February 9,1996 Page 2
. Since the customer served from Linda Substadon. Prasair, la cuersady a retal l customer of PGAE. how does Modesto determine in proposed arrangement at Linda Substation qualifies for legitimate wholesale electric power salast i.
. In the event Modesto's proposed Linde Sub arrangement does qualify for wholesale
- clectric power sales, please explain the exclusion of a compeutive transition charge.
i provision in your FieM Agreernent. i -
- Does Modesto intend to use the Proposed Agreement to supply any additional i
existing PGAE custorner(s) with power, and if so, please list those customers of whom it imends to relieve PGAE of any obligation to serve? a) Are these retail customers? ! b) Are these wholesale customers? c) Has Modesto rsached any agreement with any customers to take over their l ' current PO&E electrie serwas? If so, please provide copies of a!! such agreements and please specify whm Modesto's obligations to serve are set ' fod.
. Please explain whi this request does not fall within the prohibitions on sham wholesale transactions of Section 212(h) of the Energy Policy Act of 1992.
l Your expedient response to these questions is much appreciated. Since we are a] ready
- scheduled to tneet on February 22, perhaps you can provide me with a written response to these questions before that date so that we tnay discuss them at that time.
i 1 a I 1 SJM:ml l l ec: E. James Macias i 4 iO
Pacific Gas and Elecnic Casneasy F.chmw h myrna wom 7 Bene S'itet Rarr.2318 B23A Manage San Frarcoco. CA 94105 Ara,n,a awnar um caec 523A P o Bas Tr:Coc San FrancEn CA 94177 February 9.1996 4154 73 4545 4:415m3 9 N 1 Mr. Frank F. Eckhart. Jr. l Destec Power Services, Inc. 1676 N. California Blvd., Suite 400
- Wamut Creek Califomia 94696
Dear Mr. Eckhart:
t ! This letter will respond to your January 30,1996 letter that (a)"Modesto irrigation Distnct's (MID's) Unde substation" be added as a Transaction Point to Appendii K cf the Control Area and Transmission Service Agreement (CATSA) witn a maximum receipt capability of 10 MW and (b) tne transmission level MSD be increased to 16.9 MW for tne month of August,1996. Our present understand.ng o' your proposed transactio6 is that your reauested service is prohibitee under sections 6.1.2 and 6.8 of the CATSA, as the 1.inde substation does net appear to be a legitimate transaction point ier wholesale deirvery and there is no Interconnection Agreement in place as required by the CATSA. We nevertheless would appreciate DPS's views regarding the following issues with respect to your request to add the Unde substation as a Transacoon Point:
- 1. Conversien of a PGM Aetail Custome* to a DPS Aetail C'Jrger- Establishing Linde substation as a Transaction Point appears to "have th3 effect of transferring an existing retail customer of PG&E to OPS' which PG&E is not inquired to do under CATSA Section 6.1.2(d). Do you believe tnat service to Linde suostation is consistent with Section 6.1.2(d) and,if so, piease arctain.
- 2. " Sham Wholesale" Please exclain wny this transacton coes not fall within the pronibitions on sham wholesale transactions that Congrees sought to prevent when rt acopted Section 212(h) of the Federal Power Act.
- 3. Full Reavirements Service et Unde substation - Your statement that your reauest is necessary "to accommooste full requirements service" at Unde substaten implies that DPS and MID have in place an agreement specifying terms and conditions of suen service. Please provide details of your agreement with MID to help us determine whether your request is consistent with the intent of CATSA Section 8.1.2(d).
_ _ _ _ _ _ _ _ _ _ _ ~ . _ _ _ _ _ _ _ - - - - . - - - - - - - _ - i l
- Mr. Frank F. Eckhan. 't.
- Cebruary 9,1996
- Page 2 4 Califomia P'.bbe Uftrties Commission (CPUC) Restructurino Deesion Comneteive l
{ Transiren Casts (CTCs) and Other Charoes The CPUC's Decemoer 20.1995 l l decision regarding Eiectric industry Restructunng set forth the CPUC's vision of a l l restnJctureo .ndustry. The approacn you have suggested appears to us to be at odds ) with wnat the CPUC has ordered (which of course constrains wnat PG&E can ] voluntarily do). Piease navise us how you unoerstand that CTCs and other charges, i such as a oublic goods charge, would os handled under this proposed arrangement, j whether there would be a CTC clause as an amendment to the CATSA or in a site j mterconnection agreement slmitar to the Port of Oakland arrangement, whetner the retail customer would pay a flat fee now or provide a bond, or any other method by i which CTCs would be collected irorn departing utility retail customers. Please also
- esplain whether you believe that this proposed transaction is consistent with.the
, CPUC's December 20,1995 orders.
- 5. Ownersnic cf Unde Substation -Our review of Unce substation does notincicate that
' ~ MID is the currem owner. Please crovice evidence that Unde substation is owned by MID. ! l ) 6. Intereennec9en Acreernent CATSA Secticn 6.4 requires that an adequate i interconnection Agreement erst between a Third Party and PG&E as a preconoition , j to adding a Transaction Point owned by the Third Perry. PG&E already has an Interconnecton Agreement with MID, which does not address any customer i substations servmg toad located outside of MID's service territory. As such, an j agreement totween PG&E and MID addressing operaconal issues at Linde suestation , must be in place before Unde substation could be adced as a Transaction Peint. MID l has sent PG&E a site interconnection Agreement purportedly modeled after the j Interconnection Agreement with the Port of Oaklanc, but which does not include the provision on CTCs in tne Port ei Oskand Interconnection Agreement. Does DPS I have any position en the terms of the proposed PG&E-MID Interconnection Agreement? 4
, 7. Otyioation to Serve 11. as PG&E believes to be the case, this proposed transsetion is
< essentially for an ex'. sting PG&E retail customer, what, in DPS' opinion, happens to l PG&E's obligation to serve that customer? .i In regards to your request to increase MSD by 10 MW during the month of August, PG&E grants the increase subject to curtallments at Midway. Because of Path 15 constraints in the South to North airection. PG&E is wirr.ng to approve Midway as an input point under 1 CATSA Section 5.7.8 If DPS agrees that PQ&E can curtail DPS imports through Midway for South to North Path 15 ourtailrnents. We note that your need for this increase of MSD may not apply if the unde substation is not added as a Transaction Point. 9 1O
Mr. Panx F. Eckhart. Jr. O . February 9,1996 Page 3 . PG&E values its retadonshe with DPS anc would like to worx with you to resolve these issues in an expeditmus marner. Please let us know your oceitten on these items as , soon as possible. If you have any questions concereing this response, please contact me at (415) 973 6545. 1 incerely Yours. . 1 i L Vl> _ SJM:ml ec: Walt Hcman, DPS O i i O
. . - . . - . . . . . _ . - - . . - _ . - . - - . . . . - - . - - _ . . . . . . _ - . . - _ ~ . - . . . . - . - ~ ~ - . . - . -
l EMoesrec Dir57EC POWER SERVICES. INC. ~ y ,, S vvA.T 3. HONLAN A Suwe arv c' Gestec Ewav. 'c:
.ict *M$ttf.1 & GENf 8:4. va%8 0t* 1676 N 04 Jor44 floute=a'c. Suite 40 i, '
wa sr.s . OPE **f roNs 8.0. Drawer H
'.*,e nut ".ress. Catilomia 94596
{ .5'3.746 5279 Ear s510; 746-5260 i i l February 16,1996 1 i - l VIA FACSIMILE AND U.S. WJL i - . l Stephen J. Metagne ' Manager GridCustomerServices PACIHC GAS AND ELECTRIC COMPAST 77 Beale Street, Room 2319.B23A San Francisco, CA 94105 Tele: 415.973.6545 RE: PG&E RESPONSE TO DPS' REQUESTS TO ADD MID LINDE SUBSTATION O AS A CATSA TRANSACTION POINT AND TO LNCREASE MSD
Dear Steve:
This letter responds to your leuer of February 9.1996 regarding the January 30, 1996 requests by Destec Power Services, Inc. ("DPS") to add the Modesto Irrigation District ('MID") Linde Substation as a Transaction Point under the CATSA and to increase.the transmission level MSD to 16.9 MW for August 1996. We wish first to state DPS' understandings of PG&E'sIves to DPS' requests:
- 1. In accordance with CATSA section 6.6.2, PG&E gr.an.g DPS' request to increase the MSD by 10 MW for Aupst 1996, on the condition that any power received by PG&E at Midway would be subject to South to North Path 15 curtailments;
- 2. PG&E rsissig DPS' request to apprcwe the MID Linde Substadon as a CATSA Transaction Point on the grounds that DPS' proposed sale to MID *is prohibited under sections 6.1.2 and 6.8 of the CATSA, as the Linde Substation does not appear to be a legitimate transaction point for wholesale delivery."
O
..... _ ,,.. _ ._ ....Dsac a s e
1 G
, Stephen J. Metague
- February 16,1996 j Page 2
- 3. PG&E asserts that there is presently no Interconnection Agreement for the MID
! Linde Substation. CATSA section 6.4.2 provides that "a precondition to adding any
- new Transmeriot Point to Appendix K. [is that) an Interconnection Agreement ...
must be in existence, or be entered into, with PGAE pursuant to (CATSA section. ; 6.4.2]." Accordingly, we do as construe PG&E as stating that the present absence ' I of an Interconnection Agreement represents a permanent bar to adding the MID l 4 Linde Substation as a Transaction Point or as a refusal by PG&E to negotiate the J necessary Interconnection Agreement with MID in the manner provided by CATSA l section 6.4.2 ' 4 To the extent PG&Es intended responses are different than those set forth above, we would expect that you advise us immediately. Absent any such immediate clarification by ' l' PG&E, we necessarily will assume the above accurately states PG&Es responses to DPS' January 30 requests. ! DPS disputes PG&Es rejection of DPS' request to add the MID Linde Substation as a l O Transaction Point. In accordance with section A.3 of the CAT 3A, and without waiving its U other legal rights and remedies, this letter constitutes DPS' written request for Negotiation I of this Dispute.
- The issues in dispute for which Negotiation is requested are PG&Es rejection of DPS' request to add the MID Linde' Substation as a Transaction Point on the stated grounds that CATSA sections 6.1.2 and 6.8 prohibit its designation as a Transaction Point.
This will also advise you that DPS has designated me to be its management representative for purposes of the Negotiation. As required by CATSA section A.3,I am " authorized [by i DPS) to settle the Dispute." DPS' initiation of the CATSA dispute rc.chttion procedures is motivated by its customer's (i.e. MID) request to commence receipt of DPS' wholesale service as of August L 1996. We accordingly share PGAEs stated desire to " resolve these issues in an expeditious manner." Accordingly, we provide below responses to the questions you posed. We must caution, however, that DPS' rights, and PG&E's corresponding obligations, to add the MID Linde Substation as a Transaction Point are govemed exclusively by the CATSA and its terms and conditions, particularly its sections 1.44 and 6.4. DPS' willingness to respond to PG&Es questions which are unrelated to the CATSA criteria for the addition IO
, Stephen J. Metagne February 16,1996 '
Page 3 of a Transaction Point does not constitute any acknowledgment by DPS that PG&E's inquiries are relevant to its assessment of the MID Linde Substation as a CATSA Transaction Point.
- 1. No "DPS Retail" Canamer/CATSA Section 6.1.2fdl Adding the MID Linde' Substation as a CATSA Transaction Pomt will not "have the effect of transferring an l existing retail customer of PG&E to DPS" (emphasis added) within the meaning of section 6.L2(d) or otherwise. DPS will have B2 supplier / customer relationship of any kind with any existmg retail customer of PG&E at the MID Linde Substadon.
Specifically, there are a contracts, e payments. g services and a provision of any commodity between DPS and gy existing PG&E customer in Pittsburg. DPS'
- c. gly customer at the MID Linde Substation will be MID MID is unquestionably not an e::isting IggH customer of PGAE. MID will be purchasing power from DPS for resale to retail customers. Howeve:, this fact does not transform DPS' wholesale sales to MID into a retail transaction. To the contrary, as PG&E is aware, the definition of " wholesale" is " sale for resale." Thus, MID's intention to resell the power it purchases at wholesale to retail customers is not a legitimate basis for PG&E to reject the MID Linde Subsution as a CATSA Transaction Point nor to object to DPS' sale to MID. ,
The DPS sale to MID is a wholesale transaction conceptually and operationally indistinguishable from any other wholesale sale (e.g., the Port of Oakland). PG&E appears to object to MID's intent to compete with PG&E for retail sales in : Pittsburg. .It is unlawful, anticompedtive and inappropnate for PG&E to l I misconstrue section 6.1.2(d) to maintain its transmission monopoly in a manner which restricts DPS' wholesale sales under the CA'ISA to only those wholesale customers who agree not to compete with PG&E for retail sales.
- 2. No " Sham" Wholesale Transaction. PG&E's accusation that MID's business initiatives in Pittsburg constitutes " sham" transactions are best responded to by MID. DPS assumes the issue will be addressed in the context of MID's request for the Interconnection Agreement. DPS notes the following facts, however, which support MID's status as a legitimate wholesale entity at the MID Linde Substation:
- a. MID is clearly an entity independent from DPS; O
j. j 1 i ! !O
- Stephen J. Metague i
l February 16,1996 Page 4 ; l l i b. MID is a weU established wholesale (i.e. sale for resale) utility that is plainly ) not a " sham" organization conceived to facilitate this tranuction. Indeed, l MID has been a wholesale sales customer of PG&E; . 1 L c. MID wiD provide transformation, distribunon and metering services to its . retail customers in Pittsburg using its own facDities; l d. MID wG1 provide various utility services (billing, maintenance, customer i services, etc.) to its retail customers in Pittsburg using its own personnel; and
- e. MID wiu provide these value-added services consistent with its existing retail
- ram.
'Ibese facts demonstrate that MID's offer to serve customers load in Pittsburg
- evidenas legitimate wholesale purchaser /retaD seller activities. By no stretch of the imagination is MID a " sham" organintion fronting for DPS wnhin the meaning of Section 212(h).
l 3. Full Reauirements Service. DPS is prepared to respond to legitimate questions ! regarding the service it is requesting PG&E to provide under the CATSA. l However, the details of any power sales agreement between DPS and MID are, of
- course, proprietary and not necessary for PG&E to review for purposes of DPS'
! request to add a Transaction Point under the CADA. PG&E has not required such information with respect to DPS' prior requests to add other transaction points. For
- instance, in assessing whether to add the Port of Oakland's Edes Substation as a
- CATSA Transaenon Point, PG&E required no information regarding the power
! sales agreement other than that DPS intended to provide the Port of Oakland full requirements wholesale service. The service DPS will provide to MID at the MID Linde Substation using the ! CADA is a " full requirements" wholesale service no different from that which PG&E approved for, and DPS is providag, the Port of Oakland. DPS will follow , MID's load at the MID Linde Substation consistent with its rights under the CATSA and will provide all required anciDary services consistent with its obligations under
- the CAHA in exactly the name fashion as for the Pon of Oakland. As PG&E has O
1 .i i a iO Stephen J. Metague
- February 16,1996 Page5 i
already appropriately determmed that DPS' provision of full requirements }' wholesale service is allowable for one wholesale customer (Port of Oakland), DPS believes PG&E has no legitimate basis to deny DPS providing these servias to MID atits new MID Linde Substation. i
- 4. Elaewie Iad==* v Re.h -2=ina. DPS' request to add the MID Linde Substation as a i CATSA Transaction Point does not address, relate to, nor is' anyway conditioned i upon, any matter relating to, or any approval by, the California Public Utilities j Commission or any policy that agency is cutrendy considering or any proceeding i
presently before it. Nothmg in the CATSA, particularly nothing'in its sections 1.44 or 6.4, requires the CPUCs approval or concurrence in the addition of a CATSA Transaction Point. DPS' request to add the MID Linde Substation as a CATSA Transaction Point is a straightforward request for PG&E to deliver power in l accordance with the CABA, and as authomed by DPS' FERC power marketing j certifiste, to a DPS wholesale customer at an additional delivery point. It is not a statement of regulatory pokcy to be evaluated, debated, or approved. O DPS' contemplated service to MID at the MID Linde Substation does not impact nor prejudice in any way either the CPUCs or the State legislature's ongoing
- restructuring of the California electric industry.
i 5. Linde Ssbitation Ownershin. DPS has no ownership interest in the MID Linde
- Substation. Any questions PG&E has about the MID Linde Substation should be directed to MID.
i
- 6. Interconnection Aareement. PG&E requests DPS to state its ' position on the terms of the proposed PG&E-MID Intermanection Agreement." With respect to DPS' request to add the MID Linde Substation as a CAHA Transaction Point, DPS'
" position" is that the CABA sets forth the relevant and exclusive requirements and procedures for the negotiation and execution of an Interconnection Agreement between PG&E and MID regarding PG&E's delivery of power to the MID Linde i
Substation. Section 6.4.2 prescribes PG&E's rights and obligations with respect to a request by DPS to add a Transaction Point at which DPS' wholesale customer does not have an Interconnection Agreement with PG&E. CAEA section L44 defines ! an " Interconnection Agreeinent" for purposes of the CATSA. 4 O
i O Stephen J. Metague February 16,19% Page 6
- 7. PG&E's Public Udlity Oblirations. DPS is not requesting to, nor intending to, sell j power on a retail basis as assumed by PG&E's question. PG&E's obligations, whatever they are or may be, under California public utility law to serve retail ,
customers are not germane to a request by DPS to add a Transaction Point under i l the CATSA to sell power to a wholesale customer, and in accordance with its FERC power marketing certificate. . Steve, DPS values its cooperative relationship with PG&E embodied in the CATSA and sincerely hopes that PG&E will expeditiously reconsider its position and enable DPS' intended wholesale transaction to proceed in a timely manner. Please cab me if you have any questions regarding any of the above. Please also advise me cf FG&E's designated Inanagement representative so that we can, as required by CATSA section A.3, proceed "promptly" with the Negotiation. Ve truly yours, _.-+ ?:n ~ Walt G.Moman. P.E.
/sma O
,i 1231 Osv:mtn St. i *
- P.O. Box 4060 Modemo. CA 95352
- (209) 526 7373 l
weser and Pe=or i 1 Febmary 21,1996 i i i Mr. Stephen J. Matague l Manager, Grid Customer Services l l Mail Code B23A 5 P. O. Box 770000 l SanFrancisco, California 94177 ' l l
Dear Mr. Metague:
l ) This letter will respond to your letter ofFebruary'9,1996, in which you asked l information. I l l 4 1. You have asked for evidence ofModesto's ownership of the Linde Sub i Mamas (a) a document of title showing date of acquisition, (b) eviden l permitung requemments and (c) a legal description of the picpT 1 In responac, please find a copy of the Equip"a=* Sales Agreem l Praxair transfers to MID its interest in dtheIJede Substation. hIhstrict is l permitting requirements relating to the transfer. A id% on of"theil extent that references substation property, is included in the agreement. M ' - == ant from Praxair for the realty upon which the =hanan sits. 1 2. You have asked about the interrelationships between the propose l Interconnection Agreement ("SIA"), a draft of which was forwarded l January 29,1996, and the Int n+d= Agreernant ("IA") dated - ,2 1988. l We believe that there is no intarrelationship between the SIA i dance area is remote from the Modesto area, where MIDd halances ctly from a fullits load with the IA. Under the SIA, MID will be recesving powerdag in loads the Pittsburg and ar
' requeaments wholesale power suppliar who will have the respo resources In addition to the foregoing, when the IA was negotiated, th i
4 deal of effort in order that Agreement between Pacine Gas and Electric Company the MID IA F coc..Li.as i f an I We bebeve that there is coa umble merit to maintaining that the IA for this tran==nian underminen that goal. 4 ORGANIZED iss7
- IRRIGAT1oM WATER is04
- POWER
i 4 i i i !O l 3. You have asked for a redhned venson of the SIA, and for a namitive description of the proposed changes from the Port of nakland agramment j ! We have separately sent you a red-knad verman of the SIA. We believe that the r for the changes is readily apparent, but we will he happy to elaborate on those l meeting onFebruary 22. 1 i 1 4. You have asked how the Distnct daannines that its proposed arrangement at i Linda hhmatiaa qualines for legitimate wholesale electric power sales. i i. The proposed arrangement is a clasac emunple of a wholesale power t District will be purchasing electric energy fron Destec4for (d). resale to Praxa i transaction falls squarely within the d=Anitian of wholesale found in 16 U.S.C. i 82 l 5. You have asked us to explam the avekulaa of a competitive transioon char piehla the SIA. i You have correedy noted that the SIA does not contain a competiave tra
- ("CTC") provision. h CTC provision in the Port of 0andand b applicable to agr j
to apply to the uraque - - .. . . - . of that transacnon, and did not appear to e hED's servicein Pittsburg l 6. You have asked if the District intends to supply any addaiaani exi cumornerr.with power, and for a list of such customers. i The District has been n===aad by a miah of customers in the j Linde Substatica who have expressed ilload at least some fromitsTlade internet i Substation. l i the Dwtrict. The District is interested in servmg add The Diarict has reached no agr====== with customers other than Prax 1., does not fd l
- 7. You have asked us why the Dismat's request fo i
The proposed tnmancoondaaisyouprohibitad may havethatwould bysuggest neither subd you have cited. We would be inserested in any int-p that our readmg of the sistuta is in error. Verytruly yours, A _ Planning _Marksting and iO: I
i Paeshc Gas and Eleetne Comoary ?e :.r: t sta. m M:t- :.
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l VIA FACSIMILE 1 p . .. I t-i f
,. , February 26.1996 Walter G. Homan Vice President and General Manager Westem Operations '
Destec Power Services. Inc. 1676 Northern Califomm Boulevard. Suite 400 P. O. Drawer H . Walnut Creek.CA 94596
Dear Walt:
As promised m my Febrvary 21.1996 letter. this letter responds to Destec Power Services' January 30.1996 request for service under the CATS A. as supplemented by the additional information provided in your February 16.19% letter and by Modesto p V 1rrigation District's February 21.1996 letter. For the reasons explained below. PG&E denies your request. Before explaimng why PG&E is denying your request. I would like to describe the transaction as PG&E presently understands it. Praxair is. and for many years has been. a PG&E retail customer. Praxair owns its own substation. Modesto is an imgation distnet l with a well def'med electric service temtory which is roughly coextensive with the boundanes of the distnct and is located enurely within Stanislaus County. Praxair's a Pittsburg facility is approximately 100 miles away from Modesto's retailload. Indeed. Modesto's own words, the Pittsburg area is " remote" from Modesto's electric service area. In DPS's January 30.1996 letter, it refers to "Modesto Imgation Distnet's Lmde Substation." As is clear from tne Equipment Sales Agreement provided by Modesto. the Linde Substation does not belong to Modesto. The Equipment Sales Agreement is highly contingent and may never happen. The sale is not expected to close until Augus nnd is subject to numerous conditions precedent. including: I J
= execution of a Power Sales Agreement between Modesto and DPS: !
1 e execution of a Site Interconnection Agreement between PG&E and Modesto; l l n i V l l l
4 4 J t i Mr. Walter Homan l l February 26.1996 D Page 2 i a that the Site Interconnecuon Agreement between PG&E and Modesto be accepted for l fihng by the Federal Energy Regulatory Commission m a manner which enables it to { become effective as between those panies and wnhout changes unacceptable to either l l PG&E or Modesto: { h > e execunon of an agreement between Modesto and Praxair providing for retail electne ' service from Modesto to Praxair's Pittsburg facility: 't 4. e an opponumty for Modesto to inspect the facilities which are the subject**of the
- Equipment Sales Agreement
4
= PG&E's approval of the Praxair substation as a valid output point for DPS irt' l accordance with the CATS A, and l
. a provision for revocation of the sale m the everit of a challenge to the transfer of facilities or involvement of DPS.
, i l DPS has refused PG&E's request to provide a copy of a Power Sales Agreement between DPS and Modesto, and has refused to indicate whether the parties have even entered mto any such agreement. However. our understanding of the proposed power sales agreement between DPS and Modesto indicates a sort of joint venture, with DPS and Modesto splittmg the amounts paid by Praxair on an 80/20 basis. i ' In short. Modesto does not own any distribution facilities whatsoever in the Pittsburg area. Modesto plans to acquire a mere substation. and it is highly speculative whether ! Modesto ever will acquire that substation much less any legitimate distribution facilities. This transaction is, in economic substance. designed to have the effect of transferring a 1 smgle. current PG&E retail customer to DPS. t I Based upon our understandmg of the facts. PG&E denies DPS's request to add Linde substation as a transaction pomt under the CATS A and to increase the transmission MSD to 16.9 MW for August 1996. PG&E believes that the requested service is not eligible m light of CATS A secuons 6.1.2(d). 6.1.2(c), and 6.8. In addiuon. the Lmde substanon is i not a legitimate Transaction Pomt for a wholesale delivery. and there is no mterconnecuon agreement m place as required by the CATSA. Although your February 16.1996 letter disagrees with our interpretation of section 6.1.2(d). you appear l to be ignonng that subsecuon's prohibition on transactions which "have the effect of transferring an existmg retail customer of PG&E to DPS." This transaction mvolves a jomt approach by DPS and Modesto to serve Praxair; the entire senes of transacuons is expressly conditioned upon DPS selling the power to that facility as well as on P ~ agreemg to designate the lande substauon as a transaction pomt under our con
, Mr. Walter Homan February 26.1996 Page 3 DPS. Although Modesto is not a sham orgamzation. that is not the test. Modesto's Pittsburg " presence". without the ownership of any distribution facilities whatsoever. or even with the ownership of facilities,is a sham wholesale transaction withm the meanmg of section 212(h). Indeed. if DPS and Modesto fail to sign a Power Sales Agreement,if' ' PG&E reiects the Praxair substation as a valid output point for DPS under the CATS A. or
- if any of the other conditions precedent fail to materialize. then Modesto's new retail,,
temtory vanishes. in addition. under section 6.1.2(c). "PG&E is not required to provide network : transmission service if the designation of a Third Pany [Modesto) as a Traisaction Pomt
. would enable that Third Party [Modesto) to achieve objectives prohibited under its i separate agreement with PG&E." Modesto's separate Interconnection Agreement with i' PG&E expressly prohibits Modesto from obtaining transmission service under that Interconnecuon Agreement which would have the effect of transfemng an existing i customer of PG&E outside Modesto's electric serv' ice area to Modesto or which would j provide transmission service to a retail customer of PG&E.
! The proposed transaction is also at odds with what the Califomia Public Utilities p Commission ordered in its December 20.1995 decision regarding Electric Industry Restructuring. The CPUC ordered that Competitive Transition Charges (CTC's) be non- ! bypassable, yet this transaction seems designed pnmarily to attempt to evade that i- regulatory mandue. This point is underscored by paragraph 13 of the Equipment Sales Agreement. which allows the entire transaction to be resemded if the CPUC or FERC issues any order or regulation which would frustrate the purpose of these Agreements ! insofar as a parties' benefits are concemed. Taken as a whole. the interrelated Modesto Equipment Sales Agreement and DPS request for service permits only one inference. j namely, that the pnmary purpose of this transaction is CTC avoidance and there is no transaction if the CTC avoidance scheme fails. Although your February 16.1996 attempt to invoke section A.3 of the CATSA was premature given that PG&E had not yet finally responded to your service request. that is now no longer the case. However. PG&E has three significant problems with your request. First. your request purponed to mvoke section A.3 "without waiving [DPS's) other legal rights and remedies! We do not believe that this constitutes an effective attempt to mvoke the attemative dispute resolution clause: one cannot enter bmdmg ~ alternative dispute resolution without waiving other rights and remedies. Second, and I l more fundamental, the dispute between PG&E and Destec is simply not susceptible of a i two-way bindmg arbitration between PG&E and DPS. Modesto is an important pany in
- this dispute you tacitly acknowledge as much when in your response to my February 9.
1996 letter you indicated that Modesto would be responding to certain questions. Any 3 l 4 arbitrator will simply be unable to resolve the issues in a meaningful way without iO
1 l Mr. Walter Homan f- February 26.1996 Page 4 Modesto s participation. Third. the issues raised by this transaction are extremely
- fundamental issues going to the core of both the federal and state restructuring of the electric industry. It is appropriate for this dispute to be resolved by the Federal Energy Regulatory Commission. not an arbitrator. and we do not believe that Appendix A applies.
As I mentioned m my February 9,1996 letter. PG&E values its relationship with DPsl ' hope our disagreement over your request does not damage that relationship. Sincerely yours.
.y w' I STEPHEN J.;METAGUE i
SLG.ewl l O i l O 4 l I
Pacific Gas a:.d Electric Company .m nticApoRESS t , y , ,,. PO B:n 7442 / ttCtnc, a ,o,.. San Franosco CA 94120 sTREETK01 RIER ADDRE55 O
\j La4 Dea" ment 77 Bea>e Street B30A San Franosco CA 94105 $q j 415/973 6628 r_ ,
f ai 415/973-9271 '. 6 . Fan 415/973 5520 i l October 31,1996 . ., Ms. Lois D. Cashell, Secretary 2R 97-320-0D0 kei1 u
?,
c2
~
1 Federal Energy Regulatory Commission 888 First Street, N.E. Washington, DC 20426 Re: Second Amendment to the Control Area and Transmission Services Agreement between Destec Power Services, Inc. and Pacific Gas and Electric Company. ( PG&E Rate Schedule FERC No.185)
Dear Ms. Cashell:
Pacific Gas and Electric Company ("PG&E") hereby submits for filing and acceptance, in accordance with Section 205 of the Federal Power Act and Section 35.13 of the Federal Energy Regulitory Commission's ("FERC" or " Commission") regulations (18 CFR r S 35.13), a Second Amendment to the Control Area and Transmission Service (' Agreement ("CATSA"), dated October 31,1996, between PG&E and Destec Power
. Services, Inc. ("DPS"), (su:h amendment hereinafter referred to as the "Second Amendment"). This letter further describes certain aspects of the Second Amendment in greater detail to assist the Commission in its review.
The Second Amendment Description
' By letter order dated April 14,1995 in FERC Docket No. ER95-262-000, the Commission accepted the CATSA, effective March 1,1995, and designated it PG&E Rate Schedule FERC No.185. The CATSA is a comprehensive network transmission and control area services agreement that authorizes DPS, a power marketer, to purchase power from a number of generation sources, aggregate it, and self it to a number of wholesale loads. DPS is currently selling power to customers in Califomia using services provided under the CATSA.
I in early 1996, a dispute arose between PG&E and DPS over the interpretation of Sections 6.2.1,6.4.2 and 6.8 of the CATSA. On February 28,1996, PG&E filed a Petition for Declaratory Order (Docket No. EL96-37-000) requesting, inter alia, a declaration from the Commission as to the respective rights of the parties under the
CATSA ' On August 6,1996, PG&E and DPS signed a Settlement Agreement
' On February 26,1996, PG&E also filed an action in the Federal Court (Northern District of Califomia, Docket No. 96-0711 CW), requesting an order relieving PG&E of e' its obligation to submit the dispute to arbitration in accordance with Section 8.8 of the
( CATSA. FM',PROPERT/OFTHE PUBLIC REFERENCE ROOM
^ DO NOT REMOVE
i 3 .
- Ms. Lois D. Cashell Page 2 October 31,1996 2
(" Settlement") resolving the dispute, subject to certain conditions Among other things, the Settlement provided that the parties would agree to amend certain sections of the CATSA. Those changes collectively make up the Second Amendment, which is appended as Attachment i hereto, and is summarized below. In accordance with this Settlement, DPS has agreed to withdraw its request for transmission service which is the subject of PG&E's Petition for a Declaratory Order.
- 1. Direct Access Section 6.8 of the CATSA is amended to enable DPS to use Network Transmission Service under the CATSA to sell electricity directly to retail customers when the..
Califomia Public Utilities Commission ('CPUC") begins a"owing power marketers to make direct sales of electricity within PG&E's service territory (" Direct Access
- Implementation Date"). As originally drafted, the CATSA prohibited the use of CATSA service to sell electricity directly to retail customers.
Amended Section 6.8 further specifies that distribution or
- delivery
- service for retail (or
- " direct access") transactions will be needed to complete deliveries to ultimate consumers and will be provided either under the appropriate PG&E CPUC Jurisdictional tariff or, in the event that the tariff's terms would inhibit DPS's exercise of the CATSA's load following features, a special contract based on the CPUC tariff.
Disputes over this matter will be resolved in accordance with the terms of Appendix C of , i the CATSA. l
- 2. Substation Transaction Limitation Section 6.8 of the CATSA is further amended to provide that, prior to the Direct Access Implementation Date, DPS may not use service under the CATSAif DPS's sale to a
' wholesale customer at the Transaction Point is daimed to be of wholesale status on the ground that under Federal Power Act Section 212(h) the wholesale customer "would utilize transmission or distribution facilities that it owns or controls to deliver all such electric energy to such electric consumer" and the facilities used to serve the ultimate -
customer consist solely of substation-based facilities or of substation-based facilities which are remote from, and not directly. connected by the wholesale customer's own facilities to, the wholesale customer's principal area of electric service. I
- 3. Term Extension Section 2.3 of the CATSA is amended to extend the term of the agreement through December 31,2003, subject to existing exceptions.
2 The Settlement is only between PG&E and DPS, and only pertains to issues in dispute Q' V between those two parties.
~
! Ms. Lois D. Cashell l Page 3 October 31,1996 s i ! 4. Competitive Transition Charge ! Section 6.1.2 of the CATSA is amended to require that any retail or wholesale customer 3 j that either (a) was a retail customer of PG&E on December 20,1995 ; or (b) is purchasing power for resale to a retail customer that was a PG&E retail customer on ! December 20,1995, must, as a condition of service from DPS using the CATSA, sign l- an agreement in which the customer agrees to pay all competition transition charges
- ('CTC").
Filing Requirementa The Commission has consistently encouraged voluntary settlements as benefici31 to the I j orderly and expeditious conduct of its business. Alabama Power Company,75 FERC [ . 61,233 (May 31,1996). ' The proposed amendments represent.a settlement thatjs i' fair, reasonable, and in the public interest. Adoption of the amendments would further J the Commission's interest in the settlement of disputes. The amen'dments reflect j
] compromises between the parties, and this should be accepted as a whole, without modification.
The proposed. amendments will not affect the pricing of transmission services under the l .. j CATSA. Because this Second Amendment deals only with modifications to contract ]
' language and proposes no change in rates, PG&E believes that the abbreviated filing requirements of Section 35.13(a)(2)(iii) are applicable and therefore is submitting only i
> the information required in paragraphs (b) and (c) of Section 35.13 of the Commission's rules and regulations (18 CFR g 35.13(a)(2)(iii)).
Effective Date - Request For Waivers PG&E respectfully requests that the Commission grant such waivers of the
' Commission's rules and regulations as may be necessary for acceptance of this filing and the Second Amendment under the Federal Power Act. PG&E requests this Second Amendment become effective as soon as possible but no later than December 31, 1996. It is important for DPS business purposes that the Second Amendment be effective prior to the end of the year.
3
\
3 December 20,1995 is the date upon which the CPUC issued Decision 95-12-063 (as revised in D.96-01-009), the restructuring policy decision authorizing the establishment
,i of a CTC mechanism.
' Citing Altemative Dispute Resolution,60 Fed. Reg.19494 (Ap' ril 19,1995), FERC Stats. & Rebs. Preambles 31,018 (April 12,1995) ( Order No. 578). Sam alan City of Seattle,71 FERC 161,159 (May 16,1995); JMC Power Proiects v. Tennessee Gas Pioeline Co. 69 FERC 161,162 (November 4,1994).
l l Ms. Lois D. Cashell Oco r 31,1996 Proposed Rate Schedule Designation PG&E proposes that the Second Amendment be designated as follows: Designation Description Supplement No.13 to PG&E Rate Schedule Second Amendment to the Control FERC No.185 Area and Transmission Service Agreement . l Concurrence i DPS has indicated its support for and concurrence with this filing through its exscution of the Second Amendment. i Propriety of Expenses 3 No expense or cost associated with this filing have been alleged or judged, in any ' l judicial or administrative proceeding, to be illegal, duplicative, or unnecessary costs that l are demonstrably the product of discriminatory employment practices.
' 4 Enclosures '
Enclosed for filing are six copies of the following documents:
' 1. A Certificate of Service:
- 2. A notice suitable for publication in the Federal Register, j
- 3. Attachment 1 - A signed Second Amendment between DPS and PG&E modifying various parts of Sections 1,2,6 and 8 of the Agreement; i
- 4. Attachment 2 - A redlined version of the proposed contract modifications; and
- 5. Supporting documents required pursuant to Section 35.13 of the Commission's Rules and Regulations. ..
Service Copies of this filing have been served upon DPS ahd the Califomia Public Utilities g Commission (CPUC). In addition, copies of this filing are available for public inspection in a convenient form and location during normal business hours at PG&E's General Office, located at 77 Beale Street in San Francisco.
,i t
-.~
l Ms. Lois D. Cashell Page5 O October 31,1996 Correspondence PG&E requests that all correspondence, pleadings, and other communications l conceming this filing be served upon the following: William V. Manheim Attomey Pacific Gas and Electric Company , Law Department Post Office Box 7442 San Francisco, Califomia 94120-7442 , PG&E also requests an additional copy of any correspondence and orders be sent to: Robert J. Doran . Director of FERC Rates and Regulation J Pacific Gas and Electric Company
;l 77 Beale Street, Room 2345, B23A Post Office Box 770000 San Francisco, Califomia 94177 PG&E hereby submits an additional copy of the first page of this transmittalletter and respectfully requests the Commission acknowledge receipt of this document by retuming a file-endorsed copy in the enclosed stamped, pre-addressed envelope.
Respectfully submitted, MICHAEL S. HINDUS WILLIAM V. MANHEIM 1 , By b William V. Manheim ,, Attorneys for Pacific Gas and Electric Company , 1 Post Office Box 7442 I San Francisco, Califomia 94120 . Telephone: (415) 973-6628
'i Enclosures t
n O .
I e 1 i
.2 1
i CERTIFICATE OF SERVICE l I i
. 6 9
e NE
CERTIFICATE OF SERVICE G k/ I hereby certify that I have this day caused a copy of the foregoing to be delivered by
. first class U.S. mail to the following:
Kenton L Erwin, Esq. Destec Power Services, Inc. 2500 City West Blvd., Suite 150 P.O. Box 4411 Houston, TX 77210-4411 Walt G. Homan Destec Power Services, Inc. - 1676 North Califomia Blvd., Suite 400 P.O. Drawer H
- Walnut Creek, CA 94596 -
Christopher T. Ellison
. Ellison, Schneider & Lennihan .
2311 Capitol Avenue
/ Sacramento,CA 95816 ,
J' Peter Arth Jr. Public Utilities Commission of the State of Califomia
, 505 Van Ness Avenue San Francisco, CA 94102 Dated at San Francisco, Califomia, this 31st day of October,1996.
- A/L -
ne M. Myers (/
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! l - 1 1 NOTICE SUITABLE FOR l . PUBLICATION IN THE FEDERAL REGISTER l I i 1 1
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UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION 4
)
Pacific Gas and Electne Company ) Docket No. ER
)
- NOTICE OF FILING
( 1996) Take notice that on October 1996, Pacific Gas and Electric Company (PG&E) tendered for filing an amendment (Second Amendment) to the Control Area and '- ! Transmission Service Agreement (Agreement) between PG&E and Destec Power - Services, Inc. (DPS) which was filed previously with the Commission on December 6, 1994 in FERC Docket No. ER95-262 000. J The purpose of the Second Amendment is to adopt new contract language which reflects settlement of various items which were previously issues between the Parties. [ Copies of this filing were served upon DPS and Califomia Public Utilities Commission.
. Any person desiring to be heard or to protest said filing should file a motion to intervene or to protest with the Federal Energy Regulatory Commission,888 First Street, N.E.,
Washington, DC 20426, in accordance with Rules 211 and 214 of the Commission's regulations (18 CFR $$ 385.211 and 385.214). All such motions or protests should be i i filed on or before . Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a motion to intervene. Copies of this filing are on file with the Commission and are available for public inspection. Lois D. Cashell Secretary i
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! ll Attachment 1 I SECOND AMENDMENT 4 i l i 1 I l 4
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i 1 1 1 i 1 1 r I i 4 i i i, 4 1 J . . 1 SECOND AMENDMENT TO L CONTROL AREA AND TRANSMISSION SERVICE AGREEMENT l BETWEEN ! DESTEC POWER SERVICES, INC. i 1 AND i . PACMC GAS AND ELECTRIC COMPANY 1 4 1
}
4 3 e i 1 l 3 i f i
t l 1 l SECOND AMENDMENT TO i ,q 2 ' u CONTROL AREA AND TRANSMISSION SERVICE AGREEMENT 3 BETWEEN DESTEC POWER SERVICES, INC. 4 AND 5 PACIFIC GAS AND ELECTRIC COMPANT 6 7 This second amendment to the control Area and Transmiss, ion 8 Service Agreement between Destec Power Services, Inc. ("DPS"), a 9 Delaware corporation, and Pacific Gas and Electric Company 10 ("PG&E"), a California corporation, dated November 29, 1994 (the l 11 "CATSA") is made and entered into this 3/SI day of October,
.I 12 1996. This agreement shall hereinafter be refe.rred to as the l
13 "Second Amendment". PG&E and DPS are herein individually ) 14 referred to as " Party" and collectively as " Parties."
/G b ,
15 NOW, THEREFORE, in consideration of the mutual promises and 16 obligations stated herein, and other good and valuable 17 consideration, the receipt and sufficiency of which are hereby 18 acknowledged, the Parties, intending to be legally bound, hereby i 19 agree as follows: 20 1. RECITALS
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21 The last sentence of CATSA, Section F, RECITALS, page 3, 22 line 2 shall be revised as follows,: 23 This Network Transmission Service is not available for DPS to wheel electric energy to 24 retail customers located within PG&E's utility service territory, except as provided 25 in Section 6.8.2. 26 2. DEFINITIONS O 27 Add to Section 1 of the CATSA, on page 17, line 25 the 28 following definitions (new sections 1.81 and 1.82):
i 1 1.81 Direct Access Imolementation Date: The first date upon which the CPUC allows the 2 sale of electricity'by sellers other than 7-~s PG&E directly to retail customers within () 3 PG&E's utility service territory pursuant to its direct access program in R.94-04-031 and 4 I.94-04-032. 5 1.82 Direct Access Retail Customer: A retail customer that is entitled, pursuant to 6 the CPUC's implementation of its direct access program in R.94-04-031 and I.94-040-32 7 to contract with power suppliers other than PG&E for the direct purchase of electricity. , 8 9 3. TERM 10 Section 2.3 of the CATSA, on page 19, line 19 shall be 11 revised as follows: J 12 This Agreement shall terminate at midnight of December 31, 2003, except as provided in l 13 Sections 2.5, 8.2 and 8.9.
, 14 The first sentence of Section 2.4 of the CATSA shall be 15 modified as follows:
(nL.-l' . 16 By mutual agreement and with no express or implied obligation to agree, this Agreement 17 may be extended in accordance with the following provisions: 18
- 4. AGREEMENT TO PAY COMPETITION TRANSITION COSTS / SUBSTATION 19 LIMITATION 20 Section 6.1.2 of the CATSA shall be revised by deleting "or" 21 on page 51, line 1, deleting the period on page 51, line 3, and 22 adding the following:
1 23 (e) FERC does not have authority to order such transmission service pursuant to 24 Sections 211 and 212 of the Federal Power Act as hereinafter amended;
.i 25 (f) DPS' sale to a wholesale customer at
, 26 the proposed Transaction Point is claimed to be of wholesale status on the grounds that 27 under Federal Power Act Section 212(h) the entity "would utilize transmission or
(~') x- 28 distribution facilities that it owns or controls to deliver all such electric energy 2
. . . . . _ - - . _ . - . - . - - . . _ - _ . ~ - . _ - - - - - - - . . - . - - - .
l
; i i to such electric consumer" and the facilities i L that would be used to serve the ultimate' l i 2 customer consist either solely of substation-l based facilities or substation-based j
. 3 facilities which are' remote from, and not :
. directly connected by the wholesale i 4 customer's own facilities to, the wholesale i customer's principal area of electric 5 service; 2
! 6 or (g)- the retail or wholesale customer
- j. purchasing service (s) from DPS either: i) was
+- 7 a retail customer of PG&E on or after l
- December 20, 1995; or ii) is purchasing -
8 service (s) in order to resell power to a !
- retail' customer that was a retail cust'omer of ,
t , 9 PG&E on or after December 20, 1995, and such. ; d- retail or wholesale customer has not signed . 10 an agreement containing the following or a b substantially similar statement: ,, _ 1 i 11 j ; "For the duration of any transaction l 1 12 involving a purchase of electricity or other
- I services from DPS using transmission or other 3- 13 services provided under the CATSA between 2 .PG&E and DPS, (name of customer] )
L 14 agrees to pay to PGEE all charges, rates and l f fees, including competition transition
- ( 15 charges, that any competent regulatory o-
- i i ,
legislative body deems appropriate as a l j 16 result of electric industry restructuring, ' including, but not limited to, pursuant to l . 17 FERC Order No. 888 or California'Public l Utilities Code Sections 360-379. Such
- 18 obligation to pay (subject to refund) does
! i not waive customer's right to challenge both ! 19 the amount and appropriateness of such ! charges, rates or fees in any appropriate ! 20 forum." i 21 The foregoing Sections 6.1.2 (d) and (e) shall in no event limit DPS' right to use Network Transmission Service for the
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22 i g transmission component oY a direct access 23 transaction following the Direct Access j Implementation Date pursuant to Section
- - 24 6.8.2.
1 i 25 5. DIRECT ACCESS TRANSACTIONS i j ' 26 CATSA Section 6.8, page 70, line 26, shall be revised to a 4 27 read as follows: l j' - 28 6.8 Service to PG&E Retail Customers 6.8.1 No Pre-Direct Access Retail 3 1 1
1 Sales: During the period prior to the Direct Access Implementation Date, DPS may not use t
-)
q j 2 service under this Agreement to sell electricity to a retail customer located 3 within the PG&E utility service territory. DPS may not designate retail loads within 4 PG&E's utility service territory as Transaction Points nor may DPS schedule to 5 any retail loads within PG&E's' service territory as DPS Loads. 6 6.8.2 Direct Access Retail Sales: l 7 Beginning on the Direct Access Implementation ' Date, and continuing until the termination of i 8 this Agreement, DPS may, at its sole i discretion, use Network Transmission Service
- 9 to deliver electricity solely over PG&E's transmission facilities (as defined by FERC 10 in Docket No. EL96-48-000) for ultimate delivery to any Direct Access Retai1 11 Customer, provided that PGEE distribution or
.J " delivery" service will be needed for D 12 complete access to a Direct Access Retail l 1
Customer located within PGEE's utility 13 service territory and such service will be
., .provided either: (1) under applicable PG&E i direct access tariffs filed and accepted by !
14 ! I~ the CPUC, or (2) under a special contract to 15 be negotiated between the Parties only in the i event that the applicable PG&E direct access 16 tariffs for distribution or delivery service 4 inhibit DPS' ability to use the load : 17 following features of this Agreement for direct access transactions. Whether the CPUC 18 tariffs " inhibit DPS' ability to use the load
' following features of this Agreement" shall 19 be an Appendix C issue. Any special distribution or delivery contract negotiated 20 under this section will permit DPS to use the load following features of this Agreement for 21 direct retail access and shall in all other respects be identical to the applicable PG&E 22 distribution or delivery, tariffs.
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23 In the event that amendments are required to this Agreement to establish new 24 scheduling protocols or other requirements necessary to implement direct secess 25 transmission service, the Parties shall negotiate in good faith to complete such 26 amendments 75 days prior to the Direct Access Implementaticn Date. If the Parties fail to ("'g ' 27 reach agreement on such supplemental ( ,/ protocols or other requirements, PG&E shall 28 unilaterally file such amendments with FERC 60 days prior to the Direct Access 4
l I 1 Implementation Date. 2 As an alternative to transmission service under this Agreement on facilities 3 owned by PGEE, DPS may at any time elect to-take such transmission service under the 4 Independent System operator (ISO) transmission tariffs, provided that: (1) DPS 5 shall take all transmission services for
. direct access retail transactions under 6 either the ISO direct access tariff or this )
Agreement; and (2) once DPS elects to take ' 7 transmission service on PG&E-owned facilities for direct access retail transactions under . 8 the ISO tariff it may not thereafter elect to take such service under this Agreement. 9 Nothing in this provision shall prevent DPS. ~ from continuing to use this Agreement for 10 wholesale transmission service while using the iso tariff for transmission service asscciated with direct access retail 11 transactions. d 12 , l
} The following shall be.added to the end of the third 13 sentence of CATSA Section 6.2, page 53, line 22:
. 14
, except that for direct access retail O '
15 transactions under Section 6.8.2, the rate for such distribution service shall be established by applicable PG&E direct access 16 tariffs filed at the CPUC or by special 17 contract, in accordance with.the provisions of Section 6.8.2. 18 19 CATSA Section 8.27.2, page 88, line 12, shall be modified as 20 follows. 21 Except as provided in Sections J.4.2.2, 6.2
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and 6.8.2, PG&E further waives all rights 22 under Section 205 of the Federal Power Act to unilaterally request changes in rates, term
.i 23 or conditions to the Agreement for the first three (3) years following the Effective Date 24 of the Agreement.
- 25 Appendix C, Section C.1.2, shall be modified by adding a new 26 subsection (e) on page C-3, line 26, as follows:
. 27 (e) Direct Access Neactiated Contract Pursuant to Section 6.8.2, whether O 28 Discute:
the CPUC distribution and " delivery" tariffs
" inhibit DPS' ability to use the load i
5 1
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1 following features of this Agreement" shall be an Appendix C issue. The Technical 2 Mediator shall decide the questica of whether O~ 3 a negotiated contract is warranted under section 6.8.2 but shall not have responsibility for resolving disputes over 4 the terms and conditions of s'ach negotiated contract. 5 6 6. TERMIl0LTIOgr OF AMENDMENT' 7 In the event the " Confidential Settlement Agreement" between l 8 PG&E and DPS, dated August 5, 1996 is terminated, t] tis second ; 3 n= nd-nt shall terminate as specified in the ' Confidential 10 settlement Agreement" and be of no further force or effect and 11 the terms and conditions of the CATSA that immediately preexisted ; a 12 the second ?-+ =t shall be fully restored. l 1 l 13 It is further agreed that the revised pages in the form l 14 attached berato, incorporating the foregoing == nA=d language, is shall be inserted immediately before the correspnnding original 16 pages in the executed originals as true and corrected copies of 17 the Agreement. Is In witness whereof, the Parties have caused this Second
, 19 Amendment to be duly executed by their authorized representatives 20 and effective as of this date.
21 22 DESTEC Powra SERVICES, INC., PAcmc Gas AND ELECUtIC COMPAhY, a Delaware corporation a California corporation
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23 gm -~^ ' QMW ff 24 at: :- / sv:
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3 25 Mm: Walter G. Roman Mme: E. James Macias
+4 26 Tnw Vice President and General tma: Vice President - Power Manager - Western System 27 Operations 28 omesumus. October 3J,1996 nc m e m a m es: October $,1996 6
1 exports) and to transmit electric energy from Input Points to () 2 specified Output Points. 7his Network Transmission Service is 3 not available for DPS to wheel electric energy to retail-4 customers located within PG&E's utility service territory, except 5 as provided in Section 6.8.2. 6 NOW, THEREFORE, in consideration of the mutual promises and 7 obligations stated herein, and other good and valuable r 8 consideration, the receipt and sufficiency of which are hereby 9 acknowledged, the Parties, intending to be legally bound, hereby 10 agree as follows: 11 J. 12 1.0 DEFINITIONS 13 The following terms, when used in this Agreement with
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14 initial capitalization, whether singular, plural or possessive, N) w 15 shall have the following meanings. ~ i AGC Control Load: The-amount of DPS' Load whose AGC 16 1.1 17 Regulation requirements DPS is satisfying by placing capacity 18 from DP3 Resources under PG&E control in accordance with i 19 Section 4.1.5. 20 1.2 AGC Reculation Load Effective: The amount of DPS' 21 Load whose AGC Regulation requirements which are ultimately ~ 22 deemed to be satisfied by PG&E as , determined in Section 4.1.6.
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23 1.3 AGC Reculation Load Reserved: The amount of DPS' 24 Load whose AGC Regulation requirements DPS reserved to be 25 provided by PG&E pursuant to'Section 5.1.1. 26 1.4 AGC Reculation: The use of generation capacity 27 . reserves.co perform Automatic Generation Control. PG&E provides 28 a Control Area Service to meet this requirement which is 3 Amendmenc #2 i
i 1 described in Section 4.1. l l [~) 2 l V 3 4 5 l 6 1 7 , l 8 !
. 9 10 11
.J 12 1 1
l 13
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14 15 . h 16 17 18 l i 19 20 21 22 3 4' 23 24 25 26 27
'" 28 3a Amendment #2
1 services that occur with advance notice, or curtailments or j
'O 2 interruptions of power or transmission service without notice '
3 that nevertheless can reascaably be expected to occur and should 4 be planned for consistent with Prudent Utility Practice. 5 Examples of curtailments or interruptions that may reasonably be 6 expe.cted to occur are (a) single-line outages of transmission ' 7 facilities, (b) Forced Outages of at least one generating ! 8 facility, (c) drought at a hydroelectric facility, (d) loop flow 9 on the Pacific Northwest - Southwest Intertie, and (e), loss or 10 reduction of the fossil fuel supply for a thermal unit. 11 1.76 Variable Transactions: Power transactions where the J 12 quantity of power delivered varies with fluctuations in the load 13 and need not be constant throughout the schedule period. !
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14 1.77 Western Systems Power Pool Aareement: The governing 15 agreement that defines the marketing arrangement-among members of i 16 the Pool and was accepted by FERC as WSPP Rate Schedule FERC 1 17 No. 1. 18 1.78 Work Dav: All days except Saturday, Sunday, and i 19 WSCC-designated holidays. 20 1.79 WjiLQ_C : The Western Systems Coordinating Council, or 21 its successor. 22 1.80 WSCC Path 15: The WSCC-designated transmission path 23 for loopflow mitigation located between PG&E's Tesla and Midway 24 Substations. 25 1.81 Direct Access Imolementation Date: The first date 26 upon which the CPUC allows the sale of electricity by sellers 27 other than PG&F directly to retail customers within PG&E's
\ 28 utility service territory pursuant to its direct access program 17 Amendment #2
- ,I 1 in R.94-04-031 and I.94-04-032.
(). 2 3 1.82 Direct Access Retail Customer: A retail customer that is entitled, pursuant to the CPUC's implementation of its 4 direct access program in R.94-04-031 and I.94-040-32 to contract 5 with power suppliers other than PG&E for the direct purchase of 6 electricity. 7 8 2.0 EFFECTIVE DATE AND TERM
, 9 2.1 Effective Date -
10 Depending upon the circumstances of FERC's 11 ///
.i 12 ///
l 13 /// 14 15 16 17 18 8 i 19 20 21 22 ,
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23 24 25 26 27 28 17a Amendment #2 j 4 l
i l i refusing Party would accept and if the non-refusing Party agrees 1 j i 2 to such modification, or if the Parties agree to another ; 3 mutually-acceptable modification of the agreement, the notice to i 4 terminate shall be null and void, and the Effective Date shall be-5 the date FERC accepts the modified agreement without material ; 6 modification. Absent the Parties so timely agreeing to a 7 mutually-acceptable modification of the agreement, the Agreement 8 shall terminate thirty (30) days-afterthenon-refusingParth's 9 receipt of the notice to terminate. . 10 2.2 Commencement of Service 11 Unless otherwise mutually agreed', the earlisst l
' 12 service may commence under this Agreement is on (i) the first ;
} !
13 (1st) day of the first month following the Effective Date if it l
, 14 is the first (1st) through nineteenth (19th) day of the month or
() ' 15 16 (ii) the first (1st) day of the second month following the Effective Date, if it'is the twentieth (20th) day of the month or
)
17 later. 18 2.3 Igm 19 This Agreement shall terminate at midnight of 20 December 31, 2003, except as provided in Sections 2.5, 8.2 and 21 8.9. 22 2.4 Extension of Term
- i. 23 By mutual agreement and with no express or implied ;
1 24 obligation to agree, this Agreement may be extended in accordance
. 25 with the following provisions:
i 26 (a) .At least ninety (90) calendar days prior to the ! 27 third year after the Effective Date, either O. 28 /// 19 Amendment #2
l i 1 agreement with PG&E; (d) the provision of Network Transmission () 2 3 Service would have the effect of transferring an existing retail customer of PGEE to DPS; (e) FERC does not have authority to 4 order such transmission service pursuant to Sections 211 and 212 l i 5 of the Federal Power Act as hereinafter amended; (f) DPS' sale to 6 a wholesale customer at the proposed Transaction Point is claimed ! 7 to be of wholesale status on the grounds that under Federal Power 8 Act section 212 (h) the entity "would utilize transmission or
. 9 distribution facilities that it. owns or controls to deliver all 10 such electric energy to such electric consumer" and the 11 facilities that would be used to serve the ultimate customer J
12 consist either solely of substation-based facilities or l 13 substation-based facilities which are remote from, and not
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14 directly connected by the wholesale customer's own facilities to, 15 the wholesale customer's principal area of electric service; or, 16 (g) the retail or wholesale customer purchasing service (s) from 17 DPS either: i) was a retail customer of PG&E on or after 18 December 20, 1995; or ii) is purchasing service (s) in order to i 19 resell power to a retail customer that was a retail customer of ) 1 20 PG&E on or'after December 20, 1995, and such retail or wholesale 21 customer has not signed an agreement containing the following or i 22 a substantially similar statement: , ! 1 23 "For the duration of any transaction involving a purchase of electricity or 24 other services from DPS using transmission or other services provided 25 under the CATSA between PG&E and DPS, (name of customer] agrees to 26 pay to PG&E all charges, rates and fees, including competition. transition 27 charges, that any competent regulatory 1 ( or legislative body deems appropriate i 28 as a result of electric industry I restructuring, including, but not 51 Amendmenc #2
l i i limited to, pursuant to FERC Order No. , 888 or California Public Utilities Code
"'s 2 Sections 360-379. Such obligation to ',
(Q 3 pay-(subject to refund) does not waive customer's right to challenge both the amount and appropriateness of such 4 charges, rates or fees in any-appropriate forum." 5 6 The foregoing Sections 6.1.2(d) and (e) shall in no 7 event' limit DPS' right to use Network Transmission Service for l 8 the transmission component of a direct access transaction 9 following the Direct Access Implementation Date pursuant to l 10 Section 6.8.2. 11 6.1.3 Desienation of Maximum Simultanedus J 12 Demand ("MSD"): The initial amount of MSD for this Agreement is 13 set forth in Appendix K. DPS may increase the MSD listed in
, 14 Appendix K at any time by making a written request to PG&E in
() ' 15 16 accordance with Section 6.6. DPS may also request a reduction in the MSD at any time, provided that DPS gives PG&E not less than 17 one year's notice of such reduction. In such event, DPS shall 18 pay PG&E for transmission services based on the full, unreduced 19 MSD during that one-year notice period. 20 6.1.4 Duration of Service: DPS may request 21 Network Transmission Service, in the form of requests for MSD, on 22 an annual or on a short-term firm basis, as described in this 4 23 Section 6.1.4. 12 4 6.1.4.1 Annual Firm Service: PG&E
.. 25 shall be obligated to provide Annual Firm Service among the 26 Transaction Points for any period requested by DPS that is within 27 the term of this Agreement and for a duration of not less than O(_/ 28 one year. Such Annual Firm Service shall be firm transmission 51a Amendment #2
l 1 ! 1 service, subject to PG&E's right to study specific requests for 2 service as specified in Section 6.6. (O~'i
- .3 6.1.4.2 Short-Term Firm Service
! 4 DPS may request and pay for, and PGEE shall be obligated to j i 5 provide, Network Transmission Service in monthly increments for a l 6 minimum of one month and a maximum of twelve (12) months in any { l l I 7 combination of contiguous or non-contiguous months within any , l s ///
- 9 ///
= l
- 10 /// l 1
l 11 ! .1 1 12 f ) 13
- i 14 ,
1 ("'y 1
- \s ,/ 15 i s
) 16 17 18 i 19 20 21 22 3
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23 24
' I 25 26 27 28 51b Amendmenc #2
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1 Short-Term Firm Service shall be made by separate l. f- 2 request in accordance with Section 6.1.4.2(i: 1). I
! I
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The Transaction Points and MSD requested by DPS and 3 (v) 4 approved by PG&E in accordance with Section 6.6 i l
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5 shall be listed by month on Appendix K and shall be i 6 added to any Annual Firm Service reserved for such 7 month on Appendix K. Such table shall also list the 8 Maximum Delivery Capability or Maximum Rece.' ~ 9 Capability of each Transaction Point. DPS shall l 10 then have the right to transmit among Input Points 11 and Output Points listed on App'e'ndix K in an amount J 12 equal to the monthly MSD reserved for such service. l 13 6.2 Rates and Charaes
. 14 -
Rates for Network Transmission Service shall be 15 based on PG&E's Cost of Service for the term of. .this Agreement. ( } 16 For the initial three years of this Agreement, PG&E will provide 17 Network Transmission Service at the Transmission Rate set forth 18 in Section D.B.2.1. If DPS receives distribution level service 19 either from an Input Point or to an. Output Point at a primary 20 voltage level less than 60 kV but equal to or greater than 21 4.16 kV, DPS shall pay separately for such service at the Primary 22 Distribution Rate set forth in Section D.8.2.2, except that for
*. 23 direct access retail transactions under Section 6.8.2, the rate 24 for such distribution service shall be established by applicable
.. 25 PG&E direct access tariffs filed at the CPUC or by special 26 contract, in accordance with the provisions of Section 6.8.2.
27 Where a transmission study (in accordance with Section 6.6) 28 identifies the need for system upgrades in order to provide 53 Amendment #2
1 requested transmission service and the Parties agree to proceed 2 with construction, DPS shall pay, in accordance with 3 Section D.8'.4 the higher of the following: 4 (a) the Transmission Rate set forth in Section 5 /// 6 /// 7 /// 8 9 , 10 31 4 12 13
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i 14 15 i 16 17 18 19 20 21 22 3 I 23 24
.6 25 i
26
. 27 28 53a Amendmenc #2 1
1 i 1 event of an Appendix C Dispute, DPS may initiate the dispute g 2 resolution procedures set forth in Appendix C. 3 6.7.7 Costs of Studies: If required by PG&E, 4 and subject to Sections C.1. 2 (a) and C.1.4, DPS shall reimburse 5 PG&E for any reasonable and actual additional Costs incurred by , i l l 6 PG&E to perform the studies required by Section 6.6.4. In l l 7 performing any studies required by this Agreement, PG&E shall, to 8 the extent possible, use its previous studies and avoid 9 duplication or otherwise endeavor to avoid incurring unnecessary 10 Costs in response to DPS' requests. DPS shall have the right to 11 inspect and audit PG&E's records to independently verify ~the
' 12 Costs of any studies for which PG&E seeks reimbursement.
l 13 6.7.8 Availability of Curtailable Service on
, 14 WSCC Path 15: Notwithstanding the foregoing provisions of Section
() 15 6 and subject to Sections 8.17 and 8.18, whenever DPS requests to 16 add or modify a Transaction Point, or increase MSD, PG&E shall 17 evaluate the availability of curtailable service (pursuant to 18 Section 6.3.2) in accordance with this Section 6. To the extent 19 DPS' request involves the transmission of power from EA Resources 20 which executed PPAs with PG&E prior to the Effective Date, PG&E
'21 shall make the curtailable service on WSCC Path 15 available. To 22 the extent DPS' request involves the transmission of power from
$ 23 DPS Suppliers other than these EA Resources, PG&E shall evaluate 24 the availability of curtailable service on WSCC Path 15 in 4 . 25 accordance with this Section 6.
26 6.8 Service to PG&E Retail Customers
. 27 6.8.1 No Pre-Direct Access Retail Sales: During 28 the period prior to the Direct Access Implementation Date, DPS 70 Amendment #2
- - - - _ --- .. .., = .-~ .- . . . - - .. -.
l i - 1 I l 1 may not use service under this Agreement to sell electricity to a 2 retail customer located within the PG&E utility service 3 territory. DPS may not designate retail loads within PG&E's 4 util'ity service territory as Transaction Points nor may DPS 5 schedule to any retail loads within PGEE's service territory as 6 DPS Loads. ! 7 6.8.2 Direct Access Retail Sales: Beginnin,g on 8 the Direct Access Implementation Date, and continuing until the 9 termination of this Agreement, DPS may, at its sole discretion, l 10 use Network Transmission Service to deliver electricity solely
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11 over PG&E's transmission facilities (as defined by FERC in Docket
.1 12 No. EL96-48-000) for ultimate delivery *to any Direct Access 13 Retail Customer, provided that PGEE distribution or " delivery" 1 14 service wi11 be needed for complete access to a Direct Access 15 Retail Customer located within PG&E's utility service territory 16 and such service will be provided either: (1) under applicable 17 PG&E direct access tariffs filed and accepted by the CPUC, or (2) 18 under a special contract to be negotiated between the Parties i
19 only in the event that the applicable PG&E direct access tariffs 20 for distribution or delivery service inhibit DPS' ability to use
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21 the load following features of this Agreement for direcc access 22 transactions. Whether the CPUC tariffs " inhibit DPS' ability to 23 use the load following features of this Agreement" shall be an 24 Appendix C issue. Any special distribution or delivery contract t 25 negotiated under this section will permit DPS to use the load 26 following features of this Agreement for direct retail access and 27 shall in all other respects be identical to the applicable PG&E
,O' 28 distribution or delivery tariffs.
71 Amendment #2
i 1 In the event that amendments are required lf-,g 2 to this Agreement to establish new scheduling protocols or other 3 requirements necessary to implement direct access transmission 4 service, the Parties shall negotiate in good faith to complete j 5 such amendments 75 days prior to the Direct Access Implementation } 6 Date.' If the Parties fail to reach agreement on such I J 7 supplemental protocols or other requirements, PGEE shall 8 unilaterally file such amendments with FERC 60 days prior t the 9 Direct Access Implementation Date. , i, 5 10 As an alternative to transmission service under this Agreement on facilities owned by P'EE, G DPS may at any l 11 4 2 ' 12 time elect to take such transmission service under the < } 13 Independent System operator (ISO) transmission tariffs, provided
. 14 that: (IT DPS shall take all transmission services for direct 2 i 15 access retail transactions under either the ISO direct access 16 tariff or this Agreement; and (2) once DPS elects to take l.
j 17 transmission service on PG&E-owned facilities for direct access i j 18 retail transaction:; under the ISO tariff it may not thereafter t 19 elect to take such service under this Agreement. Nothing in this 20 provision shall prevent DPS from continuing to use this Agreement
- 21 for wholesale transmission service while using the ISO tariff'for 22 transmission service associated with direct access retail
, s
-l 23 transactions.
24 6.9 Use Of Transmission Service Bv Third Parties - 4 .. 25 Network-Transmission Service is not assignable; i 26 however, DPS may broker to any Third Party some or all of the
, 27 Network Transmission Service available to DPS under this k 28 Agreement in accordance with the following procedures:
71a Amendment #2
. i 1 (i) In accordance with Section 6.6, DPS shall I l
, i s 2 request, and PG&E shall make, if available, anyl (} 3 changes in the Transaction Points listed in 4 4 Appendix K needed to accommodate the Third 1
- 5 Party transaction, to the extent such changes l
- 6 are necessary; l 7 (ii) DPS shall schedule such Third Party
- 8 transactions with PG&E on the Third Party's )
4 9 behalf in accordance with Appendix B; and 10 (iii) DPS shall make available such Network i 11 Transmission Service to the' Thirct Partp 3 12 pursuant to the terms and conditions for such 13 service set forth in Section 6 and subject to 14 I 3
. rates that do not exceed DPS' cost of obtaining I /~'i 15 the service from PG&E, including payments to i O '
4 16 PG&E and any additional costs incurred by DPS. 17 6.10 Transmission and Distribution Losses 18 All power debits by DPS from the DPS Pool using 19 Network Transmission Service provided by PG&E to DPS under this 20 ///- , 21 /// l 22
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< 24
.i 25 ,
i
' 26
' , 27 28 4 71b Amendment #2
1 accounting principles and practices, and all other matters. 2 Nothing contained herein shall be construed as affecting in any 3 way DPS' rights to intervene, protest, or otherwise oppose any 4 unilateral filing which may affect this Agreement. Except as 5 expressly provided in Section 8.27.2, DPS expressly reserves its 6 rights to file with FERC under Section 206 of the Federal Power 7 Act to change rates, terms and conditions of this Agreement. 8 8.27.2 Section 205/206 Waivers: PG&E hereby 9 waives for the term of this Agreement its rights under, Federal 10 Power Act Section 205 to modify unilaterally the energy loss 11 factors specified in Section 4.6.3. Except is provided in J 12 Sections J.4.2.2, 6.2 and 6.8.2, PGEE .further waives all rights 13 under Section 205 of the Federal Power Act to unilaterally
., 14 request changes in rates, term or conditions to the Agreement for
( 15 the first three .(3) years following the Effective Date of the 16 Agreement. DPS waives all rights under Federal Power Act l 17 Section 206 to make application for a change in rates in the 18 Agreement or otherwise challenge the operation of this Agreement
' 19 for the first three (3) years following the Effective Date of 20 this Agreement. DPS further waives its rights under Federal l l
21 Power Act Sections 211, 212 and 213 to apply to FERC for an order I l 22 compelling PG&E, during the term of this Agreement, to provide
) 22 transmission service if such transmission service is intended to 24 be made available by the provisions of this Agreement.
,; 25 8.28 Transmission Tariffs and Third Party Acreements j
, 26 Nothing in this Agreement shall affect or limit DPS' 27 rights to obtain transmission service: (a) pursuant to any PG&E A,
(s) 28 tariff providing transmission service, provided that DPS shall l J l 88 Amendment #2 l
.-. . . = .- .. - . _ . ~
1 assess whether PG&E has.the capability to increase the MSD or te l l f~N 2 provide Network Transmission Service for the particular l 3 transaction; i 4 (c) Interconnection Acreement Discute: In the event 5 that in response to a request by DPS pursuant to Section 6.6 for 6 an addition of, or for a modification to, a Transaction Point, 7 PG&E denies the request on the grounds that the applicable 8 Transaction Point does not satisfy the Interconnection Agreement i 1 9 precondition set forth in Section 6.4.2 and represents to DPS as j 10 provided for in Section 6.4.2.1 that such deficiency of the j 11 Interconnection Agreement is an Appendix C issue, DPS may request J 12 that the Technical Mediator assess the' appropriateness of PG&E's 13 determination that the existing Interconnection Agreement does 14 not satisfy the precondition set forth in Section 3.4.2. to add r 15. or to modify a Transaction Point; and . 4 16 (d) Section 8.20 Discute: In the event that the 17 Parties cannot agree upon interim procedures, rules, or 18 regulations in accordance with Section 8.20, and/or cannot agree i 19 pursuant to Section 4.3.5 to interim changes in the Spinning 20 Reserve Requirement, and, in accordance with these respective 21 sections, PG&E establishes interim procedures, rules, and 22 regulations or an interim changed Spinning Reserve Requirement, n 23 (" Interim Rules"), DPS may request the Technical Mediator to 24 assess the reasonableness and appropriateness of, and the 25 necessity for, the Interim Rules. 26 (e) Direct Access Necotiated Contract Discute: 27 Pursuant to Section 6.8.2, whether the CPUC distribution and O
\# 28 " delivery" tariffs " inhibit DPS' ability to use the load C-3 Amendment #2
.~._ _ __.-.__ _ .. _ ._. _ _ _ _ _ _ ..._.m_ . . . _ _ . ____. ._ _ _ _ .
i
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1 following features of this Agreement" shall be an Appendix C 2 issue. T ;* Technical Mediator shall decide the question of 3 whether a negotiated contract is warranted under section 6.8.2 4 but'shall not have responsibility for resolving disputes over the 5 terms and conditions of such negotiated contract. ! 6 C .1. 3. Use of Technical Mediator to Resolve ; 7 Accendix C Discutes 8 In the event of an Appendix C Dispute, DPS may , 9 /// ' 10 /// 11 /// J 12 , e 13 g 14 -
'! 16 17 18 ' 19 20 21 -
22
) 23 ,
l 24 ; l .1 25 1
, 26 27 28 C-3a Amendment #2
I l i l l l l l l l l 1 s J
- Attachment 2 1
REDLINED SECTIONS 1,2,6 and 8 I 1 l l l
' ' \
l 1
' l l
e e ~
i. 1 exports) and to transmit electric energy from Input Points to 2 specified Output Points. This Network Transmission Service is 3 not available for DPS to wheel electric energy to retail 4 customers located within PG&E's utility service territory, except 5 as provided in Section 6.8.2. 6 NOW, THEREFORE, in consideration of the mutual promises and ! 7 obligations stated herein, and other good and valuable l 8 consideration, the receipt and sufficiency of which are hereby 9 acknowledged, the Parties, intending to be legally bou,nd, hereby 10 agree as follows: 11 12 1.0 DEFINITIONS 13 The following terms, when used in this Agreement with (
. 14 initial capitalization, whether singular, plural or possessive, A shall have the following meanings.
15
-Q '
16 1.1 AGC Control Load: The amount of DPS' Load whose AGC 17 Regulation requirements DPS is satisfying by placing capacity 18 from DPS Resources under PG&E control in accordance with i 19 Section 4.1.5. 20 1.2 AGC Reculation Load Effective: The amount of DPS' 21 Load whose AGC Regulation requirements which are ultimately-22 deemed to be satisfied by PG&E as determined in Section 4.1.6. l 23 1.3 AGC Reculation Load Reserved: The amount of DPS' 24 Load whose AGC Regulation requirements DPS reserved to be
25 provided by PG&E pursuant to Section 5.1.1.
' 26 1.4 AGC Reculation: The use of generation capacity l
- 27 reserves to perform Automatic Generation Control. PG&E provides I . 28 a Control Area Service to meet this requirement which is 3 Amendment #2
l i l I ? ! 1 described in Section 4.1. l O 2 3 4 5 1 6 i 7 . l 8
- 9 )
i 10 j
. l 11 1 .J 12 13 14
() 15 16 17 18 l 19 20 l 21 22 ,
\
23 24
. 4 25 26 27 28 3a Amendmenc #2
1 services that occur with advance notice, or curtailments or I () 2 interruptions of power or transmission service without notice that nevertheless can reasonably be expected to occur and should 3 4 be planned for consistent with Prudent Utility Practice. I 5 Examples of curtailments or interruptions that may reasonably be 6 expected to occur are (a) single-line outages of transmission ) I 7 facilities, (b) Forced Outages of at least one generating - l 8 facility, (c) drought at a hydroelectric facility, (d) loop flow -j 9 on- the Pacific Northwest -- Southwest Intertie, and (e) loss or , 10 reduction of the fossil fuel supply for a thermal unit. ! 11 1.76 variable Transactions: Power transactions where the l
.1 -
l-12 quantity of power delivered varies with fluctuations in the load ; l 13 and need not be constant throughout the schedule period. 14, 1.77 Western Systems Power Pool Acreement: The governing 15 agreement that defines the marketing arrangement among members of , 16 the Pool and was accepted by FERC.as WSPP Rate Schedule FERC 17 No. 1. 18 1.78 Work Dav: All days except Saturday, Sunday, and i 19 WSCC-designated holidays. 20 1.79 WSCC: The Western Systems Coordinating Council, or 21 its successor. 22 1.80 WSCO Path 15: The WSCC-designated transmission path
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23 for loopflow mitigation located between PG&E's Tesla and Midway 24 Substations. Direct Access Imolementation Date: The firsc date. 25 1.81 26 uponwhichtheCPUCallowsthesaleofelectricity[by',sel'ers l 27 other than:PG&E directly to retail customers"within PGEE's 28 utility service'carritory pursuant to its direct access program 17 Amendmenc #2
a 1 in R.94-04-031 and I.94-04-032. 2 1.82 Direct Access Retail Customer: A retail customer 3 that is entitled, pursuant to the CPUC's implementation of its 4 direct access program in R.94-04-031 and I.94-040-32 to contract 5 with power suppliers other than PGEE for the direct purchase of 6 electricity. 7 8 2.0 EFFECTIVE DATE AND TERM 9 2.1 Effective Date . 10 Depending upon the circumstances of FERC's
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11 /// 12 ///
}
13 /// ' is 16 17 18 19 20 21 22 I 23 24 25 26 27 28 17a Amendment #2
1 i i refusing Party would accept and if the non-refusing Party agrees to such modification, or if the Parties agree to another I%.]\ 2 3 mutually-acceptable modification of the agreement, the notice to 4 terminate shall be null and void, and the Effective Date shall be l 5 the date FERC accepts the modified agreement without material l 6 modification. Absent the Parties so timely agreeing to a l 7 mutually-acceptable modification of the agreement, the Agree, men: 8 shall terminate thirty (30) days after the non-refusing Party's 9 receipt of the notice to terminate. 10 2.2 Commencement of Service i 11 Unless otherwise mutually agreed, the earliest
.1 12 service may commence under this Agreement is on (i) the first l
13 (1st) day of the first month following the Effective Date if it 14 is the first (1st) through nineteenth (19th) day of the month or
/,,s ' \--) 15 (ii) the first (1st) day of the second month following the 16 Effective Date, if it is the twentieth (20th) day of the month or 17 later.
18 2.3 T.323 ; i 19 . This' Agreement shalliterminate at midnight of f 20 December'31, 2003, except as providedfin-Sections 2.5, 8.2 and l 21 B.9. Th; t;;r f thic .'.gr :m:nt i; fic; ') y:::: : rm:n:ibh :n 22 th Off : _/ :::. Th: Agr;;;;ng chall t:rminst: cr midnigh: cf
\ aft:r th; Cff;;t:c 00t:, x::pt 23 th; day fic; 'C' ::1:ndar y:cr 24 :: p;cvid d in :: icn: 2.2, 2.', 2.5, 0.2 and 0.0
.i 25 2.4 Extension of Term Agr: m:nt m:y be cxtended b:y:nd 26 Th; terr f thi 27 fiv ::' y:Or By mutual agreement and'with~no express or implied l
28 obligation to agree, this Agreement may be extended in accordance 19 Amendment #2
-_ .. - . - _ - - . . - . . - - . - . - . - . . ~ . -. _ - ~ . --. .--.._.- .,
l I
!. i 1 . 1 with the following provisions: !;
- 2 .(a) At least ninety (90) calendar days prior to the j 3 third year after the Effective Date, either i 4 ///
s /// 1 i I i 6 /// i 7 i - I 8 I / . 9 10 i 11 2 e sb j 12 13 4 1 .
- l 14 i
! 15 4-16
- 17 4
1
- 18 1 s 19 I^
20 21 ! S 22 3 2 23 1 24
. I 25 s
i % i 26 27 3 l 28 19a AmendmenC #2
l 1 agreement with PG&E; ee-(d) the provision of Network Transmission Service would have the effect of transferring an existing retail ( ) 2
- 3 customer of PG&E to DPS-; (e) FERC does not have authority to e
4 order such transmission service pursuant to Sections 211 and 212 5 of-the Federal Power Act as hereinafter amended; (f) DPS' sale to ! 6 a wholesale customer at the proposed Transaction Point"is claimed I
- l l 7 to be of wholesale status on the grounds that~under Federal Power I
- 8 Act Section 212 (h) the entity "would' utilize transmission or i 9 distribution facilities that it owns or? controls to deliver all
- 10 such electric energy to such electric' consumer" and the i . .
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11 faciliti's(thatiwould e be'used toiservestbelultimate customer consist 'either ~s'olely of substation baisedi f acilities or
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) 12 substation-basedTfacilities'which are; remote 2from,';and not
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13
' ~
directly connected by the wholesaler customer's own' facilities to,
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14 15 the wholesaleicustomer's princi~pa11 area 'of electric service; or
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(g) the' retail or wholesale customer purchasing service (s)'from
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16 7 17 DPS either: ~i) was a retail customer of' PG&E on or af ter 18 December 20, '1995; or ii) is purchasing service (s) in order to i 19 resell power to a retail customer 'that was a : retail customer of 20 PG&E on or after December 20, 1995, and such retail or wholesale 21 customer has not signed an agreement containing the following-or 22 a substantially similar statement; t 23 "For the duration of any transaction involving a purchase of electricity or 24 other services from DPS using transmission or other services provided 25 under the CATSA between PGEE and DPS, (name of customer) agrees to 26 pay to PGEE all charges, rates and fees, including competition transition
27 charges, that any competent regulatory or legislative body deems appropriate 28 as a result of electric industry restructuring, including, but not 51 Amendmenc #2
1 limited to, pursuant to FERC Order No. l ,s 888 or California Public Utilities Code ! ) 2 Sections 360-379. Such obligation to l (\ / 3 pay (subject to refund) does not waive customer's right to challenge both the amount and appropriateness of such 4 charges, rates or fees in any appropriate forum." 5 6 The foregoing Sections 6{1.2 (d)[and;(e) shall in no 7 event limit DPS' right to use Network"Transmisslod/ Service-for 8 the transmission component of aDdirect? access / transaction 9 following the' Direct Access Implementation:Date; pursuant'to l 10 Section 6k8.2. 11 6.1.3 Desianation.of Maximum Simultaneous
' \
12 Demand ("MSD"): The initial amount of'MSD for this Agreement is l 13 set forth in Appendix K. DPS may increase the MSD listed in
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14 Appendix K at any time by making a written request to PG&E in 3 , (_-) 15 accordance with Section 6.6. DPS may also request a reduction in , 16 the MSD at any time, provided that DPS gives PG&E not less than 17 one year's notice of such reduction. In such event, DPS shall 18 pay PG&E for transmission services based on the full, unreduced f i 19 MSD during that one-year notice period. 20 6.1.4 Duration of Service: DPS may request 21 Network Transmission Service, in the form of requests for MSD, on 22 an annual or on a short-term firm, basis, as described in this 1 23 Section 6.1.4. 24 6.1.4.1 Annual Firm Service: PG&E 25 shall be obligated to provide Annual Firm Service among the 26 Transaction Points for any period requested by DPS that is within
s 27 the term of this Agreement and for a duration of not less than (b 28 one year. Such Annual Firm Service shall be firm transmission 51a Amendment #2
.. - ._. . - - . . - . - - . _ . _ - . _ - . = - . . - __ . . . _-.
1 service, subject to PG&E's right to otudy cpacific requests for 2 service as specified in Section 6.6. ("] V 6.1.4.2 Short-Term Firm Service : 3 4 DPS may' request and pay for, and PG&E shall be obligated to 5 provide, Network Transmission Service in monthly increments for a 6 minimum of one month and a maximum of twelve (12) months in any 7 combination of contiguous or non-contiguous months within any 8 ///
. 9 ///
10 ///
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11
'f 12 0
i 13
. 14
() , 15 16 17 18 l 19 20 21 22 l 23 24 3 25 26
- 27 28 51a Amendmenc #2
1 Short-Term Firm Service shall be made by separate request in accordance with Section 6.1.4.2 (iii) . 1 (~') 2
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3 (v) The Transaction Points and MSD requested by DPS and 4 approved by PGEE in accordance with Section 6.6 5 shall be listed by month on Appendix K and shall be 6 added to any Annual Firm Service reserved for such 7 month on Appendix K. Such table shall also list the 8 Maximum Delivery Capability or Maximum Receipt 1 9 Capability of each Transaction Point. DP.S shall 10 then have the right to transmit among Input Points i - 11 and Output Points listed on Appendix K in an amount J 12 equal to the monthly MSD' reserved for such service. 13 6.2 Rates and Charaes 14 Rates for Network Transmission Service shall be 4
/^
i (-)\ 15 based on PG&E's Cost of Service for the term of this Agreement. , 16 For the initial three years of this Agreement, PG&E will provide ( 17 Network Transmission Service at the Transmission Rate set forth 18 in Section D.8.2.1. If DPS receives distribution level service i 19 either from an Input Point or to an Output Point at a primary 20 voltage level less than 60 kV but equal to or greater than 21 4.16 kV, DPS shall pay separately for such service at the Primary 22 Distribution Rate set forth in Section D.8.2.2, except that for I. 23 direct access rutail transactions under Section 6.8.2, the rate 24 for such distribution service shall be established by applicable 25 PG&E direct access tariffs filed at the CPUC or by special 26 contract, in accordance with the provisions of Section 6.8.2. 27 Where a transmission study (in accordance with Section 6.6) 28 identifies the need for system upgrades in order to provide
, l 53 Amendment #2
i 1 requested transmission service and the Parties agree to proceed 2 with construction, DPS shall pay, in accordance with 3 Section D.8.4 the higher of the following: 4 (a) the Transmission Rate set forth in Section , 5 /// ! 6 /// 7 /// , 8
- 9 10 11
.J 12 l 13 j 14 -
O V 15 i 16 17 18 i 19 20 21 22 ,
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23 24
.i 25 26 27 28 53a Amendment #2
1 event of an Appendix C Dispute, DPS may initiate the dispute (h 2 resolution procedures set forth in Appendix C. ul 3 6.7.7 Costs of Studies: If required by PG&E, 4 and subject to Sections C.1.2 (a) and C.1.4, DPS shall reimburse 5 PG&E for any reasonable and actual additional Costs incurred by 6 PG&E.to perform the studies required by Section 6.6.4. In 7 performing any studies required by this Agreement, PG&E shall, to 8 the extent possible, use its previous studies and avoid 9 duplication or otherwise endeavor to avoid incurring unnecessary 10 Costs in response to DPS' requests. DPS shall have the right to 11 inspect and audit PG&E's records to independently verify the J 12 Costs of any studies for which PG&E se~eks reimbursement. l 13 6.7.8 Availability of Curtailable Service on 14 WSCC Path 15: Notwithstanding the foregoing provisions of Section ( \ -) 15 6 and subject to Sections 8.17 and 8.18, whenever DPS requests to i 16 add or modify a Transaction Point, or increase MSD, PG&E shall , 17 evaluate the availability of curtailable service (pursuant to To the extent 18 Section 6.3.2) in accordance with this Section 6. 1 DPS' request involves the transmission of power from EA Resources j 19 , 20 which executed PPAs with PG&E prior to the Effective Date, PG&E To 21 shall make the curtailable service on WSCC Path 15 available. l 22 the extent DPS' request involves t,he transmission of power from
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23 DPS Suppliers other than these EA Resources, PG&E shall evaluate 24 the availability of curtailable service on WSCC Path 15 in
,s 25 accordance with this Section 6.
1 26 0.0 "; C;rvi:: :: PCtC n tcil Cu;t;n:r;
'~
27 DPC m;y not u;; ;;rvic; und;r thi; 'gr;;m:nt ;; ;;11 28 Cl;;;ricity :: ; r;t;il custem;r 10;;ted within th: 2000 utility 70 Amendmenc #2
4 4 1 ecrci;; ;;rritory OPC m;y n;; d;;ign;;; I;;;il 10;d; within 2 = C'; utility ;;rc;;; ;rri;;ry ;; Tren;;;; ion P; int; nor may 3 000 ;;hedul; to ;ni r;;;il 10;d; aithin C C'; ;;rci;; t;rrit;ry 4 ;; 000 L;;d;. 5 6.8 Service to PGEE Retail Customers I 6 6 . 8 .' 1 No Pre-Direct < Access Retail Sales: During
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7 the period prior to the Direct- Access Implementat'idn Date, DPS 8 maynotuseserviceunderthis' Agreement.fto. sell} electric 1thtoa
- 9 retail customer located within"~thelPG&ETutilitpi' service 10 territory f DPSEmmy not de'signati]rstailfloads'within'PGEE's 11 utility / servic_e" territory ~ ais MTradsact.id.
- . .- - ~ --- n?P_oints
- no.r.E may :DPS . _ .
" 12 schedule 7to?anygretail loads.Within: PQ&E8sT,esrvice.' territory]as j
13 DPS(Loads".
. 14 6'.8;2E Direct 7 16dsas tReitall*Salesi.Beginning on 15 the ' Direct 3ccess' . Implementahi'6n}Date;; [and{cbnt.inuing; untili the 16 termination}f ithis AgreementMDPS jinayhat'itsisolef discretion [
17 use Networkn. 1T. ransmission Service't6?deliv.er31ec.tri. city Tsolely
.-~ .- . . . c ...
18 over PG&E'.sytransmission facilities 1(as.}Jefined.by7FERCin Docket i 19 No. EL96-48-000)?for.ultimateideliveryitofanytDirectfAccess 20 Retail Customer 7provided ' that.' PG&E.'di'stribution 'or' " delivery" service.will be"needed:for complete access toiaTDirect Access
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21 Retail Customer _ located within PGEE's utility service territory
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22 I 23 and such service will be'provided either: '(1)~under applicable 24 PG&E direct access tariffs ~ filed'andTaccepted'by the CPUC, or (2) 25 under a special contract to be negotiated'between the Parties 26 only in the event that the applicable'PG&E direct access tariffs 27 for distribution or delivery service? inhibit DPS'Eability to-use the load following features of'this Agreement.for direct access
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28 71 Amendmenc #2
,~ _ _ - .
i i 1 transactions. Whether the CPUC tariffs " inhibit DPS' ability to 2 u se the load following features of this Agreement" shall be an 3 Appendix C issue. Any special distribution or delivery contract 4 negotiated under this section will permit DPS to use the load l l 5 following features of this Agreement for direct retail access and 6 shall in all other respects be identical ~to the applicable PG&E l 7 distribution or delivery tariffs. . 8 In the event;that: amendments.are required l 9 to this Agreement to establish new scheduling protocols'or other 10 requirements"necessary'to implementidirectMaccess-transmission- l 11 service,i the Partiss! shall'.lnegotiatelizi[ good faithitoicoinplete 12 such" amendments;7Sidays' prior:toEthe]DirectiAccess' Implementation 13 Date. IfftheTPartiesffall2to reach;agreementionisuch 14 supplemenba17protoc61sEoricther.~ requirements,PGEEshall . 15 unilaterally l file'such amendments'with"FERC 60' days prior to the j l 16 DirectEAccess Implementation.Date. 17 As';an alternativefto transmission. service 18 under this'-Agreemention facilities owned _~by PG&E, DPS'may at any j 19 time elect:to:take such~ transmission' service under the i 20 Independent' System Operator' (ISO)' transmission' tariffs, provided
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21 that: -(1) - DPS . shall take all' transmi'ssion' services' for~ dirhet 22 access retail trarsactions under either the-ISO direct access 3-1 23 tariff or this Agreement:'and (2) once DPS elects to tske 24 transmission service on PG&E-owned facilities for direct access retail transactions under the ISO tariff it may not thereafter 25 elect to take such service under this Agreement. Nothing in this 26 l 27 provision shall prevent DPS from continuing to use this Agreement 28 for wholesale-transmission service while using the ISO tariff for 71a Amendmenc #2
4 1 transmission service associated with direct access retail
/~N i
2 transactions. () 3 6.9 Use Of Transmission Service Bv Third Parties 4 Network Transmission Service is not assignable; i 5 however, DPS may broker to any Third Party some or all of the 6 Network Transmission Service available to DPS under this j 7 Agreement in accordance with the following procedures: _ 8 (i) In accordance with Section 6.6, DPS shall l 9 request, and PG&E shall make, if ava.ilable, any 10 changes in the Transaction Points listed in 11 Appendix K needed to accommodate the Third
.J
- 12 Party. transaction, to the extent such changes
[
. 13 are necessary; 14 (ii) DPS shall schedule such Third Party . 15 transactions with PG&E on the' Third Party's I
16 behalf in accordance with Appendix B; and 17 (iii) DPS shall make available such Network 18 Transmission Service to the Third Party i 19 pursuant to the terms and conditions for such 20 service set forth in Section 6 and subject to i
. l 21 rates that do not exceed DPS' cost of obtaining l
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22 the service from PG&E, including payments to
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23 PG&E and any additional costs incurred by DPS. 24 6.10 Transmissien and Distribution Losses
.i 25 All power debits by DPS from the DPS Pool using Network Transmission Service provided by PG&E to DPS under this i
26 { 27 /// 28 ///
/' 71b Amendment #2
1 accounting principles and practices, and all other matters. 2 Nothing contained herein shall be construed as affecting in any 3 way DPS' rights to intervene, protest, or otherwise oppose any_ 4 unilateral filing which may affect this Agreement. Except as 5 expressly provided in Section 8.27.2, DPS expressly reserves its l 6 rights to file with FERC under Section 206 of the Federal Power ! 7 Act to change rates, terms and conditions of this' Agreement. , ! 8 8.27.2 Section 205/206 Waivers: PG&E'hereby
. 9 waives for the term of this Agreement its rights.under.. Federal 10 Power Act Section 205 to modify unilaterally the energy loss l 1
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11 factors specified in Section 4.6.3. Except as provided in ! I' J t 12 Sections J.4.2.2} end--6.2[a6d(({8p, PG&E further . waives all 13 rights under Section 205 of the Federal Power Act to unilaterally l
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14 request changes in rates,-term or conditions to the Agreement for () ' 15 the first three (3) years following the Effective Date of the t 16 Agreement. DPS waives all rights under Federal Power Act i 17 Section 206 to make application for a change in rates in the l l 18 Agreement or otherwise challenge the operation of this Agreement ; L 19 for the first three (3) years following the Effective Date of l l ! 20 this Agreement. DPS further waives its rights.under Federal 21 Power Act Sections 211, 212 and 213 to apply to FERC for an ' order 1 i 22 compelling PG&E, during the taunn of this Agreement, to provide l 4 23 transmission service if such transmission service is intended to 24 be made available by the provisions of this Agreement.
.6 25 8.28 Transmission Tariffs and Third Party Aareements ;
26 Nothing in this Agreement shall affect or limit DPS' l I j 27 rights to obtain transmission service: (a) pursuant to any PG&E l 28 tariff providing transmission service, provided that DPS shall 88 Amendmenc #2 l-l
. , _ _ -- . _ , _ , ~- ._.-., . - . , . . . . . _ . , _ ~ - ,
1 assess whether PGEE has the capability to increase the MSD or to () 2 provide Network Transmission Service for the particular 3 transaction; 4 (c) Interconnection Acreement Discute: In the event l 5 that in response to a request by DPS pursuant to Section 6.6 for i i 6 an addition-of, or for a modification to, a Transaction' Point, J 7 PG&E denies the request on the grounds that the applicable , 8 Transaction Point does not satisfy the Interconnection Agreement 9 precondition set forth in Section 6.4.2 and represents'to DPS as 10 provided for in Section 6.4.2.1 that such deficiency of the s . 11 Interconnection Agreement is an Appendix C issue, DPS may request J 12 that the' Technical Mediator assess the' appropriateness of PG&E's l
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13 determination that the existing Inter ;.onnection Agreement does 14 not ',atisfy the precondition set forth in Section 6.4.2. to add 15 or t o modify a Transaction Point; and 1 l 16 (d) Section 8.20 Discute: In the event that the s 17 Parties cannot agree upon interim procedures, rules, or 18 regulations in accordance with Section 8.20, and/or cannot agree ! I 19 pursuant to Section 4.3.5 to interim changes in the Spinning 20 Reserve Requirement', and, in accordance with these respective
~~
21 sections, PG&E establishes interim procedures, rules, and l 22 regulations or an interim changed , Spinning Reserve Requirement,
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23 (" Interim Rules"), DPS may request the Technical Mediator to 24 assess the reasonableness and appropriateness of, and the
., i 25 necessity for, the Interim Rules, i
26 (e) iDirect Access 'Neaotiated' Contract Discute: Pursuant to Section 6.8.2, whether the CPUC distilbution2 and
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27 28 adelivery"" tariffs ".inhibitlDPS' ability to use' the ' load C-3 Amendment #2
- - ' -,m -~ . , - _ __
- . - - - - _ - . _- _. .- -- . . - - - . . - . . . - . - - . . . _ . ~ . - . ._.
1 following features of this Agreement *!ishall be'an Appendix C 2 issue. The Jechnical' Mediator shall de' cide lLehe} question of 3 whether a negotiated contract is . warranted' under Section 6.8.2 4 but'shall'notshaveiresponsibility for? resolving disputes over the 5 terms'"and conditions of such negotiatedj' contract. l i 6 C.1.3 Use of Technical Mediator to Resolve 7 Accendix C Discutes ' 8 In the event of an Appendix C Dispute, DPS may
': 9 ///
10 /// * ' 1 11 /// ' J 12 [
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13 14 s 15
- l 16 17 18 i
19 20 21 22 , h 23 24
. 1 25 e
26 27 28 C-3a Arnendmen t #2
k i 1 I 1 i . O i i i t I i
't 4
i J j L 1 COST SUPPORT EXPLANATION REQUIRED l ' PURSUANT TO SECTION 35.13 OF THE COMMISSION'S RULES AND REGULATIONS i .i-i j ) I i
.i 4
e O
. . . - . . - - . - - - . - _ - . = - - - . _ . - - . . - - - . ..- - - .-. . -..-
4 {* COST SUPPORT EXPLANATION REQUIRED lp PURSUANT TO SECTION 35.13 OF THE
- \J COMMISSION'S RULES AND REGULATIONS l e i j PG&E is filing the Second Amendment under the abbreviated filing requirements of i Section 35.13(a)(2)(iii) and has provided the information requested in Section 35.13(b)
- of the Commission's regulations (18 CFR $ 35.13)in the body of the transmittalletter to i this filing. PG&E's responses to Section 35.13(c) of the Commission's regulations (CFR l j
$ 35.13(c)) are as follows:
i .
- 35.13(c)(1) Statement of Sales, Services and Revenues ,
- This filing proposes no change in rates and has no effect n revenues to PG&E or on )
costs of service to the customer. The purpose of the Second Amendment is to adopt
- new contract language to reflect negotiated settlements between the Parties. .
f 35.13(c)(2) Comparison to Other Wholesale Rates s . This filing proposes no change in rates. l j J l i 35.13(c)(3) Map or Diagram of Any Specifically Assignable Facilities [ There are no specifically assignable facilities associated with the proposed rate j schedule change. g 1
.i l
l
,i i
O' 1 ee es. b.
_ _ _ _ _ . . _ .__ . _ _ =__ -_ __ _ _ __ _ . _ _ 1 13 system run. Personnel are evaluating enhancements to the connector for long term reliability. At the end of the inspection period, the connector was scheduled for replacement in late December. The inspectors were concerned that inadequate maintenance may have caused the connector to become degraded due to overtightening. This issue will remain unresolved pending NRC review of any additional information obtained after the connector is replaced and the old one is inspected for indications of other damage or problems. (URI 50-352/96-09-02) IV. Plant SuGDort P1 Conduct of Emergency Preparedness (EP) Activities
- a. Inspection Scoce (82701)
The inspectors interviewed state and county representatives from the Commonwealth of Pennsylvania to assess PECO Energy's interface with offsite agencies.
- b. Observations and Findinas The inspectors conducted telephone interviews with representatives from the Pennsylvania Emergency Management Agency and the Chester Couity Department of Emergency Services to discuss PECO Energy's relationship with those cgencies. Representatives from both agencies stated that PECO Energy maintained a very good rapport with their agencies and that there were no outstanding issues. Also, PECO Energy participates in a
" coordination meeting" with county and state representatives on a bimonthly basis, to discuss such issues as, plant status, procedure / plan changes, EP program updates and v Emergency Action Level (EAL) changes.
- c. Conclusions PECO Energy maintained an excellent relationship with offsite agencies. Particularly noteworthy were the bimonthly coordination meetings which keep offsite agencies apprised of plant EP issues.
P2 Status of EP Facilities, Equipment, and Resources P2.1 Ooerational Readiness of Emeraency Facilities
- a. Insoection Scope (82701)
The inspectors toured the Control Room, Operations Support Center, Technical Support Center (TSC), and Emergency Operations Facility (EOF) to verify the operational readiness of those facilities, and perform random inventories of emergency supply lockers. The inspectors also reviewed facility equipment inventories conducted during the first three quarters of 1996 for completeness and accuracy.
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- b. Observations and Findinas On December 5, engineering personnel identified a condition where the primary containment instrument gas (PClG) supply to the SRVs might not meet its intended function, due to previously unaccounted for system leakage. The SRVs are expected to operate from the remote shutdown panel to bring the plants to a cold shutdown condition within 72 hours following a fire that renders the main control room inaccessible. The SRVs require gas pressure from the PClG system to operate, and normal system leakage would reduce the pressure in the system to a value where operation of the SRVs could not be assured when needed. This constituted a failure to meet the license condition for fire protection program implementation, and was properly reported. Compensatory actions included the existing fire watch and fire mitigation systems in the areas affected.
Shortly after identification of the issue, Unit 2 was shut down to make repairs to the EHC system; Unit 1 remained at power. Plant management decided early on to get both units into full compliance with the license condition prior to the startup of Unit 2. The license condition was met on December 12, after corrective actions were completed. These corrective actions included staging a hose jumper for each unit, for tying backup automatic depressurization system gas bottles to the PCIG system, revising procedures, and training operators. PORC approved these corrective actions on December 12.
- c. Conclusions The NRC concluded that the compensatory actions taken were adequate, and the corrective actions completed were appropriate and properly completed. The issue of the.
apparent non-compliance with a license condition will remain unresolved pending NRC review of the root cause and final corrective actions. (URI 50-352,353/96-09-01) E8 Miscellaneous Engineering issues E8.1 (Ocen) LER 1-96-018, Loose Soeed Sianal Cable Connector Renders the Sinale Train Hiah Pressure Coolant Iniection System inoperable (90712) This event was initially described in NRC Integrated Inspection Report 50-352/96-07, 50-353/96-07. During a quarterly surveillanca test on the Unit 1 high pressure coolant injection (HPCI) system, a loose speed sensor connection was identified which caused the turbine to overspeed and then restart repeatedly, causing the system to cycle. The inspectors reviewed the Licensee Event Report (LER), and discussed the event with engineering and l&C personnel. The LER reported the most likely root cause was a latching key on the connector became degraded when the connector was overtightened in February 1996, during reassembly of the system. The connector then loosened due to normal equipment vibration causing a loss of continuity at the connection. Corrective actions included informing technicians of the consequences of overtightening the connector, and adding a caution to the appropriate procedures concerning overtightening the connection. Additionally, the connector will be replaced during the next scheduled system outage; until replaced, continuity and tightness checks will be made prior to and immediately after each
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- b. Observations and Findinas I The inspectors checked one field monitoring team emergency equipment kit and various emergency supply lockers in the emergency facilities and found them to be stocked in accordance with procedures. The inspectors verified that facility survey meters were calibrated and operational and that telephones associated with the NRC FTS 2000 system were properly operating. Also, while touring the facilities, the inspectors spot-checked copies of the Emergency Plan (Plan) and Emergency Response Procedures (ERPs) and verified they were current. No deficiencies were noted.
l The inspectors reviewed a sampling of equipment inventories completed in 1996 and determined that they were conducted at the correct frequency and that inventory checklists were properly completed and reviewed.
- c. Conclusions The inspectors concluded that the emergency facilities and associated equipment were well-maintained and operationally ready, and that equipment inventories had been conducted.
P3 EP Procedures and Documentation
- a. inspection Scope (82701)
Prior to the inspection, the inspectors reviewed the Plan and ERPs, as well as revisions to those documents, in the regional office. While onsite, the inspectors reviewed the procedure for making Plan changes and reviewed documentation for the last two plan
-changes. A list of items reviewed is included as Attachment 2 to this report.
- b. Observations and Findinas The Plan was modified by removing specific information which often changes, to reduce the number of Plan changes. For example, the descriptions of several emergency response organization (ERO) positions were removed from the Plan and placed in the ERPs. Also, the names of support hospitals were removed, and now the Plan refers to letters of agreement which are on file for those hospitals. In addition, the Training Liaison position was eliminated from the EOF. This function is now accomplished by the security team leader in the TSC, which the inspectors concluded was an appropriate change.
The inspectors determined that ESP-101, Appendix 6, which is the EAL table for radiological releases, was unclear in that some initiating conditions refer to a dose rate, and then call that rate a total effective dose equivalent (TEOE) or a committed effective dose equivalent (CEDE). (TEDE and CEDE are both integrated doses, not dose rates). Personnel stated that these items would be clarified in the next change. Two open items from the June 1995 Peach Bottom inspection (Inspection Report 50-277, 278/95-14) concerning the discontinuance of emergency information brochures (item 95-14-01) and numerous
15 minor Plan errors (item 95-14-02), were closed (see inspection Report 50-277, 278/96-08). These items were also applicable to Limerick, as the Plan is common to both facilities.
- c. Conclusions The inspectors concluded that the Plan and ERPs were well-maintained, and that Plan revisions were completed in accordance with procedures and thoroughly documented.
Based on the determination that the changes do not decrease the overall effectiveness of the Plan, and that it continues to meet the standards of 10 CFR 50.47(b) and the requirements of Appendix E to Part 50, NRC approval is not required for those changes. Implementation of those changes will be subject to inspection in the future. P5 Staff Training and Qualification in EP
- a. Inspection Scope (82701)
The inspectors reviewed EP training records, training procedures, lesson plans, the Plan and ERPs to evaluate the effectiveness of the EP training program for both onsite personnel and offsite agencies.
- b. Observations and Findinas The inspectors reviewed the training attendance records for all Emergency Response Organization members and determined that they had received their annual training and .
were qualified to fill their assigned emergency response positions. During the June,1995 Peach Bottom inspection, the NRC found discrepancies in the corporate EOF training program (item 95-14-04). This item was also closed during this inspection .(see inspection Report 50-277, 278/96-08). The inspectors reviewed the corrective actions and found that PECO Energy had completely revised Procedure EPP No. 730, " Emergency Preparedness Training," to include a description of a restructured training program for ERO corporate responders. The inspectors reviewed this procedure and found that the procedure was very detailed and comprehensive. Training for ERO corporate responders included facility walkthroughs, classroom instruction, testing and a mini-drill. l Training for onsite personnel was similar with the exception of the mini-drills. Onsite { personnel were required to participate in the annual onsite drills (HP, fire, etc.). ! The inspectors reviewed the offsite support emergency training records (medical, fire, state and county personnel, and local media) for Limerick and Peach Bottom and found that the training plans were comprehensive, and that required drills had been conducted. Formal critiques were conducted and the findings tracked in the EP action item tracking system. Records indicated that annual EAL training for state and local officials had been conducted in 1995 and that the 1996 training was scheduled for the end of 1996. The Manager, EP stated that they were discontinuing the use of a contractor who provided training to offsite agencies and that the corporate EP staff would provide the training. He I l I i i
b 17 P7 Quality Assurance in EP Activities P7.1 Indeoendent Reviews and Audits
- a. Insoection Scope (82701)
The inspectors reviewed the audit plan, checklist, and report for the 1995 Nuclear Quality Assurance (NOA) audit of the EP program to assess the adequacy of the audit. They also interviewed the lead auditor and the Manager, Limerick Quality Division.
- b. Observations and Findinas The audit report was good and met the requirements of 10 CFR 50.54(t). Additionally, the surveillance were conducted throughout the year covering EP drills, other training events, and meetings with offsite officials. However, the report was weak on assessment and, thus, did not provide meaningful feedback to the EP group. There were no major findings and no recommendations. Also, the same auditors performed the last two audits (and will perform the one commencing in November,1996) using the same checklist, with minor modifications, and the teams contained no technical expertise. Management stated that these aspects of the audit program would be reviewed in an effort to increase the effectiveness of audits. The inspectors also pointed out two minor Plan items concerning ~
the conduct of audits that needed to be clarified. The inspectors verified that PECO Energy carried out the commitments made during the previous EP program inspection, i.e.,1) to revise the Master Audit Plan to include the - observation of EP-related drills and exercises as an essential element,2) to ensure that observations of drills and exercises are documented in independent surveillance reports while continuing to provide input to the drill critique report, and 3) to include a drill / exercise assessment section in the annual NQA audit report.
- c. Conclusions Overall, the 1995 EP audit was good, well-documented, and met NRC requirements.
However, the audit report was weak on assessment of EP program areas. P8 Miscellaneous EP lssues P8.1 Effectiveness of Licensee Controls
- a. Insoection Scope (82701)
The inspectors reviewed PECO Energy's action item tracking system, EP self-assessment efforts, and effectiveness in identifying, resolving and preventing problems.
- b. Observations and Findinas l
The inspectors reviewed the items that were entered into the Action item Tracking System I (AlTS) since January 1996. The items were appropriately prioritized and the items that T
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a l l 16 further stated that they believed that replacing the contractor would have little impact on - ] , the training program because of the experienced EP staff. '
- c. Conclusions I
, The inspectors concluded that PECO Energy maintained a very good training program. ! Response to NRC concerns regarding the corporate EP training program was thorough and : ) well-implemented. , ] P6 EP Organization and Administration ; i j P6.1 EP Oraanization and Manaaement 4 ) a. Insoection Scoce (82701)
- The inspectors interviewed the Director, Site Support Services (DSSS); the Manager, EP
- (corporate); the Manager, Security /EP (Sec/EP); and members of the EP staff to assess the '
organization and management of EP. i b. Observatioie and Findinas i j The present Manager, Sec/EP was previously the Manager of Security (since April,1993), l j and assumed responsibility for EP in November,1995. Although he had no direct EP l l experience, he ,vas an ERO member for the last 12 years, and appeared competent to j
- assume the EP responsibility.
l l The EP trainer left the company in June,1996 and his duties were assumed by one of the ! remaining two staff members. Management stated that they were interviewing candidates l to fill the open position. The two remaining staff members were experienced and appeared I to be able to handle the present workload. i Senior management support to EP was good. For example, EP routinely reported to the ! Senior Vice President's monthly meeting concerning EP action items and the status of ERO qualifications. In 1996, the Senior Vice President sent a letter to all ERO responders } informing them of management expectations regarding their roles, and the consequences i for inadequate performance. Additionally, the Manager, Sec/EP had regular meetings with ! the DSSS and Senior VP, and regularly discussed EP issues with the Plant Manager. i I
- c. Conclusions
[ The organization and management controls of EP were very good. There was continued excellent upper management support of EP. i , l 4 4 i i 3
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