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| document type = CORRESPONDENCE-LETTERS, INCOMING CORRESPONDENCE, OTHER U.S. GOVERNMENT AGENCY/DEPARTMENT TO NRC | | document type = CORRESPONDENCE-LETTERS, INCOMING CORRESPONDENCE, OTHER U.S. GOVERNMENT AGENCY/DEPARTMENT TO NRC | ||
| page count = 505 | | page count = 505 | ||
| project = | |||
| stage = Other | |||
}} | }} | ||
Latest revision as of 05:22, 5 October 2021
| ML20246D877 | |
| Person / Time | |
|---|---|
| Site: | Vogtle, 05000426, 05000000, 05000427 |
| Issue date: | 05/01/1974 |
| From: | Kauper T JUSTICE, DEPT. OF, ATTORNEY GENERAL, OFFICE OF |
| To: | Shapar H US ATOMIC ENERGY COMMISSION (AEC) |
| Shared Package | |
| ML20246B150 | List: |
| References | |
| NUDOCS 8908280310 | |
| Download: ML20246D877 (505) | |
Text
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, . Kulgington,p1 E5M i:
F
- j. .
MAY 1 1974 _,, v. 1 Howard K. Shapar, Esquire
. j Associate Gene.ral Counsel .
( U. S. Atomic Energy Cr 'ission Washington, D. C. 20s F
. Re: Georgia Power Company Hatch Nuclear Plant - Unic No. 2 -
AEC Docket No. 50-366A , Department of Justice File 60-415-37
' Georgia Power Company Vogele Nuclear Plant - Units 1-4 .
I AEC Docket Nos. 50-424A, 50-425A,
- 50-426A, 50-427A .
Department of Justice File 60-415-60 c -
Dear Mr. Shapari ,
This has further reference to your request for - antitruct advice purcuant to the provisions of Section 105 of the Atomic Energy Act of 1954, as amended, in r.
. regard to the above-captioned applications.
By letters dated August 2, 1972 for the Hatch unit and May 9, 1973 for the Vogtle units we advised you of our conclusion that Applicant's market power and use of that power indicated that a situation inconsistent with - the antitrust laws would be created or maintained by the issuance of unconditioned licenses for the construc-tion and operation of these units. Accordingly, we rec-
'ommended that' the applications be made the subj ect of evidentiary hearings. The Hatch application is the subject of an existing proceeding that has proceeded partially through prehearing discovery. The Vogtle ap-plication.is awaiting Co= mission action on an AEC staff ,
recommendation that it be consolidated for hearing with j the Hatch application. Sev(ral months ago negotiations looking to a possi-bic resolution of the antitrust issues wl:.hout hearing were commenced among the Applicant, the interveners, , , , _
~
, . . . . . . . -
- gusanunur 8908280310 e90 BOB ADOCK 050 PDR 1 M - -
- - . .---...-.. ._..-... }
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- ~
Commission staff and representatives.of the Department of Justice. As a result of these negotiations, the .., Applicant has agreed to the inclusion in the Ilatch and ~ Vogtle licenses _of conditions providing for, among other things, access to the IIntch and Vogele units and any other nucicar generating units scheduled to commence commercial. operation prior co January 1,1989; coordina-tion and sharing of reserves; transmission services over Applicant's facilities; sales of partial requirements; and sales of power at voltages appropriate for the load """* to be served. A copy of the proposed license conditions is attached. In our opinkon, these commitments should provide com-petitors and potential competitors of the Applicant with
' competitive, alternative, pouer supply sources, and should enable them to effectively compete with Georr,ia Power.
- On the strength of these com.niements and with the expecta- t- r.
tion that the Commission vill include them as conditions to the licenses involved here, we conclude that it will not be necessary to proceed with antitrust hearings on < 4 . the instant applications and that the existing proceeding may be terminated. Sincerely yours, 7
. If,fA.G
- T110 MAS)E. IMUPE
-- Assistant Attorney Gp'neral "~-
Antitrust Division l l
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v a- PROPOSED:11 CENSE CONDITIONS -
~'
- AEC DOCKET HOS.-50-366A, 50-424A, j 50-4251u 50-426A,'AND 50-427A y '- l'. LAs used herein:
(a). " Entity" means any financially responsible
~
~
e parson, private' or public corporation,. mttnicipall.ty, county , M cooperative, associat ion, . joint. stock' association or business
/*: trust,Jowning, operating or proposing to own or operate' equi.p-5 ment;or facilities within the State of Georgia (other than
/ Ch'ati1am, Effingham, Fannin, Towns:and Union Countics) for'the
; generation, transmission or distribution of electricity,' '"~~
provided that, cxcept for municipalities, countics, or rural s alectric cooperatives, " entity" is. restricted to'those which cre.or will'be public utilitics under the laws of the. State of- .... EGeorgia'or.under the laws of the United States,-and are'or will be providing [ctail electric service under a contract or rate' schedule on file with and subject to the regulation of the'Public Service Commission of the State of Georgia or any regulatory agency of the United States, and, provided further, ..
.that.as to municipalities, counties or rural electric co- ,
y operatives ,. '.' entity" 'is restricted to those which provide
- electricity to the-public at retail within the State of
. Georgia'(other than Chatham, Effingham,.Fannin, Towns and
[ Union Counties) or to responsible and Icgally qualified or- - - countics and/or coopera-
,ganizationn of such munic,palitics, i
~
'N_. --- - ... -. _ .. . __ . _ .
.a V __ _ _ . ____-___x____ __:_-
r,, 7 -- -. __ f N T- + ,,y,, Chatham, Effingham, 1 tivcsein theLState of Georgia-(other t han . Fcnnin, Towns and.' Union Countic's) to the extent they may bind . their me'mbers.
'Applicanc h means Georgia Power Company, any f .(b) '**-
- successor, assignee of this license, or assignee.of all'or , ..
substantially.all of Georgia Power Company's assets, and~any w cffiliate or subsidiary of-Georgia-Power Company'to the extent-f it engages in the; ownership.of any bulk power supply genera-tion or transmission resource in the State of Georgia (but .- t w specifically. not including _(1) flood rights and other land rights - r acquired in.the Stn~te of-Georgia incidental to hydroelectric - generation facilities located'in another stacc and (2) - facilitier. l located west of the thread of the. stream on that part of the
~Chattahoochec River serving as the' boundary between.the States p of Georgia'and Alabama), ~
- 2. Applicant recognizes that it is often in the' p
public interest for those engaging in bulk power supply and coordinate-for reliability and L purchases to interconnect,
'l economy, and engage in bulk power sup, ply transactions in order 1
to increase interconnected system reliability and reduce the i
- .v Such arrangements must provide for ,
costs of electric power. , Applicant's costs (including a reasonable return) in con-nection thercuith and allow other participating entitics full t access to the benefits available from interconuccted bulk
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'l W,, .powc'r! supply; operations and must; provide nct benefits =to '
m s If g Applicant. . 'In enteringLinto su,ch: arrangement' . neitiher Appli'-L ' cent'.noranyother'particihantLshouldbelrequiredTtoiviolate. 7
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s %q 2 the? principlAs , of. sound engineer'ing-. practice or forego.: a :
~ .
p)birdasonabl/contemporaneousalternativoarrangementwith; D - , q W , another,! developed:in good faith in.armsflength negotiations-i(butTnot including arrangements between Applicant and its ET 'offiliates or. subsidiaries;which impair entitics? rights: Thereunder more ithan?t hey w!>uld :be impaired were such ' arrange - L '
- ments'madelin(goodfaithbetweenApplicantand.acnon-affiliate- e, ,
.a Any.
;6rfnon-subsidiary)lwhich affords it greater. benefits.
s ,,
" ;such arrangement must provide for ado"quate notice and joint ij ; planning procedures. consistent with.soundLengineering practice, p- < . .
- and must relieve Applicant from obligations undertaken by it
^
inithe eventesuch' procedures are not followed,by any partici-4 b? pating entity.. - ._. Applicant recognizes that cach entity.may acquire some or-all'of its' bulk power supply from sources other than i Applicant. In thc'impicmentatio'n of the obligations stated in-4 the succeeding paragraphs, Applicant and entitics shall act in in accordance with the foregoing principles, and these principles i Larc conditions to each of Applicant's obligations herein -
'< undertaken. ~
- 3. Applicant shall interconnect with any. entity n---
5 a mmmm_m_m m .a____. _m.__ _ e- 2 _?_m. ___r _1. m m____
which provides, or which has undertaken firm contractual-7
;blfgations to provide, some or all of its' bulk power supply from sources other than Applicant on terms to be included in k'
cn interconnection nyrcement which shall provide for appro- , priate allocation of the. costs of interconnection facilitics; S provided, however, that if an entity undertakes to negotiate such a firm contractuni obligation, the Applicant shall, in . . . . good faith, negotiate with such entity concerning any proposed a interconnection. Such interconnection agreement shall pro-5 vide, without undue preference or discrimination, for the following among othcr things, insofar as consistent with the L. cperating necessities of Applicant's and any participating
~
cutity's systemc: (a) maintenance and coordination of reserves, including, where appropriate, the purchase and sale thereof,
)
(b) emergency support, _ (c) maintenance support, e (d) cconomy energy exchanges, (c) purchanc and sale of firm and non-firm capac.ity and energy, , (f) cconomic dispatch of power resources within the
- 4 State of Georgia, shall such arrangements _
provided, however, that in no event impone a higher percentage of rc:;crve requirements on the _ 4
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h - . op k _- a . - - ----- - - _ - - - - , - - - - _ . - - - - _ - . - - _ - - - - - _ _ - - - - - _N
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licant'for
; participating entity.than that' maintained by App T
i, . . similar' resources.
- 4. . . Applicant shall' sell' full-requirements power to tcny entity. 'AppliEnt.shallsellpartialrequirementspower:
F .tof.any entity. . Su'ch sales shall be made pursuant to rates- on.
? file with the Federal Power Commission, or any successor- -
. regulatory. agency, and subject to reasonable terms and con-
~
'ditions.
l 4
- 5. (a)- Applicant shall transmit- (" transmission servico") bulk power over its system to any entity or entitics with which 'it Lis interconnected, pursuant to rate schedules on L. < file. with the' Feder41 Power Conunissio.n which will fully com-to the extent pensate Applicant for-the use of its sysf.cm, 1
that such arrangements can be acconunodated from a functional-l cugineeriIig standpoint and to the extent that Applicant has < surplus line~ capacity or reasonably available funds to finance ~ new construction for this purpose. To the extent the entity
~
'or' entities are able, they shall reciprocally provide trans-mission service to Applicant. Transmission service will be provided under this subparagraph for the delivery of power to
- an entity for its or its members' consumption and retail distribution or. for casual resale to another entity for (1) its' consumption or- (2) its retail distribution $. Mothing lk
- contained herein chall require the Applicant to transmit bu I
~O-O ht@ p y --i-.
- ..s._ __ ]
=-
s _.
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o _ ,- 9 2 c Tennessco ptwercso as to have tho'cffcet-of making ~._th s ' LValley Authority (','TVA'. ). or its distributors , directly_ or'
~ indirectly, a source-of: power supply outside'the area deter - '
W 6 mined by the TVA Board of Directors by resolution of May :1, (1966tobe'theareafor-wikichthcLTVAoritsdistributorswere ' 1957, the dato
.the primary source:5f power supplygon July;l, .
cpecified in the Revenue Bond Act of'1959, 16'USC 831 n-4. i'its' system from
.(b) ' Applicant:shall transm t ove i
LO any entity.or entitics.witfi which it is interconnected,-pur-suan't to rate' schedules on file with the for the use of its Federal Power " C sion which will fully compensate Applicant
** system, bulk power which results from any such' entity having cxcess' capacity availabic from self-owned generating re. sources
~
cessarily lin che State of Georgia, to the.cxtentosuch excess ne . c results from cconomic unit sizing or from failure to forecast-load accurately or'from such generading resources'becoming. opera- -- t tional: carlier: than the' planned in-service date, _ to. the exten functional
.that such arrangements can be accommodated from a and to the extent Applicant has engineering standpoint, ~~ ' '
surplus.line capacity availabic.~
- 6. Upon request, Applicant shall provide service full ,
to.any.cntity-purchasing partial requirements, service, requirements service or transmission service from Applicant at . Ja delivery voltage appropriate for loads served by such entity, - commanuurate with Applicant's available transmission facilit-ant to rates
'~ics.
- Sales:of such service shall be ma de pursu
---_-a - - - - - - - , - . . . . - - - ~ ~ - - - - - - - - - - - - - - - - - _ - - - - --_,--------.--_-------u ----_----.---.J-- a,- -__- ---_--.__.-------------,-----,----a---_,m .-A--------,--,----,-----.-.A-__--__n-a' '
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m_ _ on file with the Federal Power Commission dr any successor -- ret,ulatory agency, and subject ,to reasonable terms and condi- )
. . i tions. .
- 7. Upon reasonabic notice Applicant shall grant stny entity the opportunity to purchase an appropriate share in to purchase the ownership of, or, at the option of th'c entity, each of the follow-e cn appropriate share of unit power from, a
ing nuclear goncrating units at Applicant's costs, to the Hatch 2, Vogtle axtent the same are constructed and operated:
. (.J>
1, Vogtle 2, Vogtle 3, Vogtle 4, and any other nuclear genera-ting unit constructed by Applicant in the State of Georgia ubich, in the application filed with'the USAEC or its succes-sor agency, is scheduled for commercial operation prior te January 1- 1989. An entity's request for a share must have regard for the economic size of such nuclear unit (s), for the entity s load si c, growth and characteristics, and for demands upon Applicant's system from other entitics and Applicant's retail customers, all in accordance with sound engineering practice. Executory agreements to accomplish the foregoing shall contain provisions reasonably specified by Applicant requiring the entity to consummate and pay for such purchas*c by an early ' For purposes of this provision, " unit date or dates certain. power" shall mean capacity and acc.ociated energy from a - specified generating unit.
~. -
~ . . Toicffect the' foregoing conditions, the follow-
~
I ,' .8. ing;stcps shall be taken: w N (a): Applicant' shall' file'with the appropriate l regulatory *
.1 authoritici'and thereafter maintaint in force as needed an appro'priate transmission tariff availabic-to:any entity; , -,
(b) Applicant shall file with the appropriate regulatory authorities and thercafter maintain in. force as i needed an:sppropciate partial requirements-tariff available tofany entity; Applicant shall have its liability limited to the partial requirements service actually_ contracted for.and the entity shall be made - 3. responsible for the security of the bulk power supply resources acquired by the cntity from sources
~
other than the: Applicant; (c) Applicant shall an,1 cad the general terms. and condi- - tions of its' current Federal Power Commission 1 tariff ' I and thercafter maintain in force as needed provis-
' ions to enabic any entity to roccive bulk power at - tran'smission voltage at app,ropriate rates; (d) Applicant shall not have the unilateral right to defeat the intended access by each entity to alter-native sources of bulk power supply provided by the .
conditions to this License; but Applicant shall retain the right to sock regulatory approval of
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' changes;in its tariffs to the end that it be adequ--
accly. compensated;for, services it provides, specifi-C 3: cally' including,'but not-limited to,-the provisions
- of. Section 205.of the Federal Power Act; (c)' Applicant shall use its best efforts to amend any .
outstanding . contract to which it is_ a riarty ' that __ contains' provisions which.are inconsistent with the
.i-conditions of this license; (f) Applicant affirms that no consents arc or will be-como necessary from' Applicant's parent, affiliates e-se
~
or' subsidiaries to enable Applicant.to carry.out.its
~** obligntid5s horcunder or to' cnable the entitics to enjoy their rights hereunder;
~
- All provisions. of these conditions shall' be subject (g) _to and implemented in.accordance with the. laws of thoUnitedStatesandoftheState.ofhcorgia,as- .-
applicable, - and with rules - regulations and' orders of agencies of both, as applicable. 6 e* 6 9 t m , t 1 1 4 Q~ . _ . . - - _ _ _ - _ - _ _ _ _ ._
q UNITED STATES OF AMERICA ATOMIC ENERGY COM11SSION BEFORE THE COMMISSION . . . i, . In the Matter of
)) -
GEORGIA POWER COMPANY l AEC Docket Hos. 50-424A-
~50-425A-1 (Vogtle Nuclear Plant, p 50-426A Units 1, 2, 3 and 4) ) 50-427A u
CERTIFICATE OF SERVIC_E,E i I hereby certify that-copies of MOTION TO WITHORAW INTERVENTIONS AND JOINT MOTION TO DISHISS AND TERMINATE THIS PROCEEDING, dated June 3, 1974, in the captioned matter, have been served upon the following by deposit in the United States mail, first class or airmail, this
-3rd day of June 1974:
~
Michael L. Glaser. Esq. Mr. Harold C. McKenzie, Jr. Chairman, Atomic Safety and Vice President and Executive Licensing Board .__ Counsel 115017th Street, N. W. Georgia Power Company Washington, D. C. 20036 P. O. Box 4545 Atlanta, Georgia 30302 Carl W. Schwarz, Esq. Metzger, Noble Schwarz, Atomic Safety and Licensing McKenna-& Kempler Board Panel U. S. Atomic Energy Commission One Farragut. Square, South , Washington, D. C. 20006 Washington, D. C. 20545 l
~
Dr. Kenneth G. Elzinga Joseph J. Saunders. Esq. University of Chicago Law School Wallace E. Brand, Esq. , 1111. E. 60th Street U. S. Department.of Justice ! l Chicago, Illinois 60637 _ Post Office Box 7513 ' Washington, D. C. 20044 Milton A. Carlton, Jr. ,'Esq. James E. Joiner, Esq. L. Clifford Adams, Jr., Esq. Troutman, Sanders, Lockerman Heard, Leverett & Adams
& Ashmore- 25 Thomas Street 1500 Candler Building Elberton, Georgia 30635 Atlanta, Georgia 30303 William I. Crisp, Esq. .
. Donald R. Allen, Esq. Thomas J. Bolch, Esq.
C. Emerson Duncan, II, Esq. Crisp & Bolch ' - Duncan, Allen and liitchell P. O. Box 1549 1775 K Street, N.11 Raleigh, North Carolina 27602 Washington, D. C. 20006 -
^~
78 ' 4..
. 2..
Chairman, Atomic Safety and-Mr. Frank W. ' Karas . Licensing Appeals Board Chief, Public Proceedings Staff Office of the Secretary U. S. Atomic Energy Commission Washington, D. C. 20545
- of the Commission - -
U.-- S. Atomic Energy Commission -
' Washington D.'.C. 20545 3
v4nch ft ..
*yau:4
~~
Benjamin H. Vogler Assistant Antitrust Counsel for AEC Regulatory Staff Dd. m 11 M* i 0 b.. N 4
~L-------2.-_....__.2
y y g; f L_. UNITED STATES Cr AMERICA: 'e A
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ATOMIC ENERGY LoMMISSION J.
-3 5513':19 e . COMMISSIONERS:7 ,, _
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. ,,,,g JUL 11974> t~
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.Dixy Lee Ray, Chairman ,,g ,
- ...; c e
% Clarence E. Larson+ ,- ,.t.a.
William A. Anders g J.
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-In the Matter of. lI --
C I Docket Nos. 50-424A h 50-425A bri
~
. GEORGIA POWER COMPANY 50-426A-50-427A d
j.
'(Vogtle Nuclear Plant. -
Units 1, 2,.3, and 4)' . ,F
., d -
5 ORDER GPANTING MOTION TO WITHDRAW INTERVENTION i[;c:-.. AND JOINT t 0T10N TO DISMISS A!40 TERMINATE THIS PROCEEDING k.9,i On consideration of the Motion to Withdraw Intervention and the Joint - t: Motion' to' Dismiss 'and Terminate This Proceeding, it is4.ereby ordered that: k
~ 1. The Motion'to Withdraw Intervention of.the Georgia Municipal' t Association and the cities of Acworth, g a,,1., is hereby 4 granted; and g
.p w m
? ~2. This antiirusi proceeding is hereby dismissed and terminated.- It'is:so ORDERED.-
. t. ~
. t..
By the Coimission. t
- 2. TLC- l N r-
- PAUL C. BENDEk'
~ Secretary of the Commission ,
. Dated 'at Connantown. Maryland 'L ,
.this 28th day of June 1974, ,
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$W 2 bbMjhNY b) b[.Lbt. d. *hW).t P.o coa .s,e p, a rewzpv 4 270 PE AcHTREE STftEET attaura ca 3esa
,ccre.,r.S s.:t po w osur A71A3ITA .
January 7, 1975 Mr. F. F. Stacy e Director of Power _ Supply Oglethorpe Electric Me=bership Corporation Suite 845 148 Cain Street Atlanta, Georgia 30303 Re: Southern Engineering Company of Georgia Document SUGGESTED RATIO?. ALE DISCRIBIEG COST RESPONSIBILITY ANILPOWER A3D ENERGY ENTITLEMENT FROM 'C01GINED SYSTDIS OF GPC AND ODIC
Dear Bud:
You have asked us to state whether we agree with the rationale
, That rationale incorporates basic, expressed in the captioned docu=ent.
general concepts which we feel to be sound, and weItagree to its use for. is understood, the purposes described in the captioned document. however, that the specific figures used in the document are based on judg=ent and are therefore subject to appropriate adjust =ent. Our agreement hereto is also subject to the following principles:
- 1. The subject rationale may be modified upon mutual consent of the parties.
- 2. If the parties cannot agree on either's fixed cost of owning and operating generation capacity, or any other catter which is subject to the approval of any regulatory agency, such catter will be submitted to the appropriate
') agency for resolution.
- 3. If i=pir.n:ntation of the agreement works an undue economic hardship on either party or results in rates and charges uhich arc no just and ressonabic, a neu rationale for desc ribi:q cc:t responsibility and power and energy entitle-cent uilt be developed.
i l I
v , - -- _ -_ g L GNnI; t.i 3'Drt:3tIOP:Im?f Y U Mr. F. F. Stacy' Page'2' January 7, 1975-5
- 4' . It.'is the intent of the parties that implementation of the agreement will not adversely affect the participation of Georgia' Power Company in the' Southern Company Pover Pool. .
5.- The parties have entered into a Settlement Agree: rent, i including Proposed License Conditions, relating to Atomic Energy Cc==Lssion Docket Mos. 50-366A, 50-424A, 50-425A, . 50-426A and 50-427A. This agreement will be entered into by the parties 'in partial imple=entation of and. is to be construed within the boundaries of said' Settlement Agree-ment, including Proposed License Conditions, and nothing contained in the proposed agreement shall be in violation of said Settlement ' Agreement, including Proposed License Conditions. .
' If the foregoing represents a satisfactory basis ' for nego-tiations'between Georgia Power Co pany and Oglethorpe' Electric Mechership.
-Corporation relating to the furnishing of Oglethorpe's capacity and energy requirenants over and above Oglethorpe's o'm resources by Georgia Power Company, please indicate by signing one copy of this letter in the space provided and returning it to ce.
Sincerely, h/// R.11. Scherer uJ jl APPROVED: U oglethorpe Electric Membership Corporation by: W k > .- d '
}p 14:J.
.Stuth:rn Enginr. ring
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Comp cy cf Georgia. 4 e 12/31/74
- / .
' SUGGESTED RATIONALE DESCRIBING COST' RESPONSIBILITY AND POWER' AND ENERGY '
- ENTITLEMENT FROM COMBINED SYSTEMS OF GPC AND OEMC .
- Determination of Annual Fixed'Ceneration' cost:per fira kW and per reserve
' kW by category (Base Load, Intermediate Load,1 Peaking Load and reserve for.
each)..
-Excluding Transmission Costs-R '
Example I G.P.C. System with 0EMC ownership of capacity;= "0" w r ,. Assume Annual Combined GPC - e and OEMC Load Duration- 1.20 _ __ _ _ _ _ ,, __ Curve'- (.20) Reserves
.1.00 - - - -- - - - -
(.25) Peaking Load
.75 -- - . . - - - - - -
(.32) Intermediate Lead l- .50 1+ l 1 .43 _ _ __ _ _ _ _ _
'I I
(.43) Base Lead I 4 l 1 . l l- l
- 0 7,000 Hrs. ,
l l . 1 _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ . _ _ l
Example 1 (Cont.) l Gb = GPC Fixed Annual Cost of Ovning and Operating Generating Capacity in Base load category (.43 x kW) k Gi = GPC Fixed Annual Cost of Ovning and Operating Generating Capacity l in Intermediate Load category (Next .32 x kW) Cp = GPC . Fixed Annual Cost of Owning and Operating Generation Capacity in Peaking Load Category (Next. 25 x kW) Gr .= GPC Fixed Annual Cost of Owning and Operating Generation Capacity in Reserve Capacity Category (Next .20 x kW) Gt = Gb + Gi + Cp + Gr W = GPC & OEMC combined annual peak load kW Annual Cost of firm base load kW in $/kw/ year
/ s
$/kW/ year = Gb '+ .20 Gi + Cp + Cr 43 W g.75 W W j, W
Basic Cost Reserve Cost Annual Cost of firm intermediate load kW in $/kW/ year
/ % / %
$/kW/ year = Gi -
.43x.20 Gi___ + .20 Gp + Gr
.32 W .32 g.75 W j g W j W Basic Cost Reserve Cost Annual cost of firm peaking load kW in S/kW/ year
/ % ./ %
$/kW/ year = Cp - .43x.20 Gp -
.32_ x .20 ' Gp
.25 W .25 g W j .25 (W j Basic Cost
+ Gr W
Reserve Cost i 1 Annual Cosc of Reserve kW in each category in $/kW/ year would be 0 as indicated in each category above. 2 j
s 7 .5 p' Example I (Continued) . CHECK: EXAMPLE I ki
~
' GPC total annual cost of fire pover ir. all categories is:
GC .
= Base Load + In::ermediate Load.+ Peaking Load.-
? ,
~
~
/ %
= .43 W Gb- +' .20 G1 +- Go ~+ Cr ~
W W-43 W -
\.75.W
/
-- % / % .- ~
+- 'cr 43 . 20~ / - Gi + .20 G, s + .32 W G1 -
7
.32 W 3 A
.75 W / s W
/ ,
- - , 9 ,
Cp' 43 .20 Go - .32 .20 Go + Or
+ .25 W -
w
.25 W' .25 W .25 s W-
/
N / _ ..- s Gt' . = ' Gb + Gi + Gp + Gr Example II , R .GPC system costs with OEMC ownership of: (Assume: OEMC Load =.15%.of each category)
- 1. 30% base load (.30 x 15% = 4.5% W)
'2. 20% hydro peaking (.20 x 15% = 3% W)
- 3. 4% reserve (.04 x 15% = 0.6% W) 3
- - - - ,-. --is-- o. -a -.-----,,--sw - - . - _ . . - - - . - . - . - - - - , - 1.- - - - _- , - - - - - - - - - - - - - - - - - -u-- . - - , . - - - - - - . - - - ----.-,-.--,_------,s._ -. --------_..~.--L-----------s-xk_-_--.
f
,r lr , :
- v. - . ,
' Assume 5.: .. . ~~.
,, Annual' Combined CPC 1.20 - . - - - . . - -- _ -- ,
e and ' 0DiC Load ' Duration Curve J. 0.6% Reserves *
'~ %)
E' , 1.00 .. - - - - - -- 3% Peaking Load
..v g . .75 - - - - - - - -. - -. - - . - - .
Intermediate Load L'
.50
.43 -- --- - -
1 i I ss s N\ssssssss ss 5\' Base Load
- O 4.5%
I I 0 7,000 Hrs. Same formula except (.43 .045 = .385), (.32 - 0 = .32), (.25 .03 -- .22) , (.20 .006 = .194) IM GPC Annual Cost of Firm Base Load kW in S/kW/ year:
/ %
$/kW/ year = Gb + .20 1 G1 + -Cp + C2
.385W .75W W W
\ /
Basic Cost Reserve Cost 8 4 _ - - - _ _ _ - ~ _ w___~.. .__.__:_-___-A
8 1 [ s i *. lGPC Annual Cost of Fira Intermediate Load kW in $/kW/ year: , g
# Cp S/kW/ year '= Gi' .385 x'.20 (Gi + .20 + Gr -
s.
.32W .32 .75W W W
\ / \ /
Basic Cost Reserve Cost ' s. GPC Annual Cost of Fira Peaking Load kW in $/kW/ year:
.385 x .20 'Go
$/kW/ year = Gp - Go .32 x .20
.22W .22 W .22 W
\ ' \ /
Basic Cost
+ Gr W
Reserve Cost H Ob = 0EMC Fixed Annual Cost of Owning and Operating Generating Capacity L in Base-Load Category (.045 x W) 01 = OEMC Fixed Annual Cost of Owning and Operating Generating Capacity in Intermediate Load Category (.00 x w) Op = OEMC. Fixed Annual Cost of owning and Operating Generating Capacity-
* ' in Peaking Load Category (.03 x W)
Or- = 'OEMC Fixed Annual Cost of Owning and Operating Generating Capacity in Reserve Category (.006 x W) Ot = Ob + Oi + Op + Or W = GPC and OEMC Combined Annual Peak Load kW i 5
- y. .
+ -
4 F:L (L 1-
- l
Example II , DEMC Annual Cost of. Firm Base Load kW in $/kW/ year.
. p %
$/kW/ year = Ob- + .20 01 +- Op + or
.045W .75W W W
/.
7= - Basic Cost Reserve Cost i -> OEMC Annual Cost of Firm Intermediate Load kW in $/kW/ year
/ / %
.$/kW/ year = 01 - .045 x .20 01 3- + .20 AW + Or
.00 W
.00W <75W / \ /
Basic Cost Reserve Cost 4 OEMC Annual Cost of Firm Peaking Load kW in $/kW/ year
/N /%
op .045 x .20 _og -
.00 x .20 1 + Or
$/kW/ year' = -
W W
.03W .03 W .03 ,
\/ \ /
Basic Cost Reserve Cost O. 6
. u ___ _ x_ . _ :___ _ _ = . . x_ _ _ _ . .. x. .
l. h'..+ g c.
< Check: ~ Example II g.
.GPC Total Annual Cost'of Firm Power in All Categories ist
~
r /
= .385 W Gb + .20 Gi + Cp% + Gr%~
ct-
.385W W W A.75W / \ /
N'
~
/ % 7% T
+ .32W -
.385 x .20 Gi + .20 AW + './ Gr'
_G i__
.32 NW./
.32W 75W ,
%. / \ /
~
/% /N / %'"
.385 x .20 W1 .32 x .20 Gy .+ Gr
+ .22W A '
,22W .22-
.22 W W l
l
\ /
A/ $ /_ Gt = Gb + Gi + GF + Gr i. .by ODIC Total Annual Cost of Firm Power in All Categories is: Oc = .045W Ob + .20 /01 + d '+ or
.045W -
.75W W : W
. ,/ ,
+ . COW 01 - .045 x .20 01 + .20 ' + or 00W .00 .W -
W
. \. 75 \ / .. .
- r - /5 /s
+ .03W Op - .045 x .20 - .00 x .20 AW + 0 2
.03W .03 ( j. .03 ,
W Oc = Ob + Oi + Op + Or 7
l .
- p. ~ ,.
^
EXAMPLE II'- BILLING GPC BILLS ODIC ,. . Base Load 61 . . IL -(a) Partial Requirements.- (Firm)
~ .
$/ year := ( .15 X .43) _ - .045 V Gb + .20'Gi + Cp + Gr
.385W .75W W , W x.,
- s / _
Plus: (b) Reserves on ODIC Base Load Ownership provided by GPC 1 ,
.045W .20 Gi + G2 + G_r, s.75W Wj W s . . ,
Less (c) Base Load Reserve Credit for 01 + Op + Or
/ 5
$/ year = (.43 .045) W .20 01 +AW + or
- W
- %.75W / ,
Intermediate Load
- (a) . Partial Requirements (Firs)
/ N rs
$/ year..= (.15 x .32) W Gi -
.385 x .20 Gi + .20 g + Gr-
.32W .32 W W
- <75W/ s) .
. Less:
(b) Intermediate Load Reserve Credit for Op + Or
~
/S
+ og P:
$/ year = .32 W .20 3W W
- \/ .
Peaking Load, (a) Partial Requirements (Firm) -
/S /s
$/ year- = (.15 x .25) .03 W Gp .385 x .20 g- .32 x .20 G_p, + c_r_
W
.22W .22 ( W, .22 W j ~
Plus: ., l (b) Reserves on ODIC Peaking Load Ownership provided by GPC 1
$/ year = .03W G_r_
W l Less: . (c) Peaking Load Reserve Credit for or 1
$/ year = .22 W O_ r, W
t
+
8 L iw- _ _ a_ . _ _ . . _ .
l *f .. Eneray (Fuel and Other Variable Costs) r , Base Load: The kWh produced by generating units (or pro rata kWh produced by partial L. ' generating' units) categorized as Base Load units for the contract yes; will be credited.co the owner of such unit. Back-up (or replacement) energy for all Base Load units -(or partial units) will be accounted for as to amount, source and cost. The cost of all such back-up energy for all Base Load units (or partial units) for the contract year will be averaged and'each owner shall be responsible for his share of such cost determined as the amount of such back-up energy required by his Base Load units for his use multiplied by such
-average cost per.kWh. This averaga cost will be estimated at the beginning of the contract year with adjustments af ter actual average cost is determined.
Intermediate Load: The kWh produced by generating units (or pro rata produced by partial units) categorized as Intermediate units for the contract year less the kWh produced by such Intermediate Load units accounted for as back-up energy for Base Lead units will be credited to the owner of such unit. Back-up (or , replacement) energy for all such Intermediate Load units (or partial units) will'be accounted for as to amount, source and cost. The cost of all such back-up energy for all Intermediate Load units (or partial units) for the
~
contract year will be averaged and each owner shall be responsible for his share of such cost determined as the amount of such back-up energy required by his Intermediate Load units for his use multiplied by such average cost per kWh. This average cost will be estimated at the beginning of the contract year _ with adjustments ef ter actual average cost is determined. 9
. I Peaking Load:
The kWh produced by generating units (or pro rata kWh produced by partial a. 4 generating units) categorized as Peaking load units for the contract year less
.the kWh produced by such Peaking Load units accounted for as back-up energy
- for' Base' Load units or Intermediate Ioad units will be credited to the owner of such Peaking Ioad unit. Back-up (or replacement) energy for all such Peaking ; Load units (o'r partial units) will be accounted for as to amount, source and L cost. The cost of all such back-up energy for all Panking load units (or partial units) for the contract year will be averaged and each owner shall be responsible for his share of such cost determined as the amount of such back-up energy i i , required by his Peaking Ioad units for his use multiplied by such average cost per kWh. This average cost will be estimated at the beginning of the contract year with adjustments after the actual average cost is determined. < Economic Dispatch i All units will be tnder the control of economic dispatch equipment. As j
\
a result of economic dispatch, whenever the energy produced hourly by an owner's I total units (or partial units) in a category, less kWh accounted for as back-up i energy, is greater than that owner's energy needs in that category and another l j party uses such energy, the receiving party shall pay the producing owner for ! l such energy on a split-the-savings basis. j Hydro Energy: j Since Hydro Energy will be dispatched on an availability basis, any kWh i dispatched from hydro units of an owner in excess of the kWh needs of that owner from that unit in its assigned category such kWh shall be credited to the owner as either (1) energy displacing the most expensive energy being simul-taneously generated by otlyer generating units of that owner, (2) economy 4 W 10 1
p . [. L 1 energy exchange with another party's most expensive energy.otherwise simul-h' taneously generated priced on a split-the-savings basis, whichever is the , most advantageous for the owner of such hydro energy. ) Partial Requirements Energy Purchases: kWh associated with Pira Partial Requirements capacity purchases by OEMC from GPC in each category shall be determined by computer analysis
,after the fact,of metered OEMC hourly' load (with transmission losses taken into account). OENC shall pay for such kWh at the average cost per kWh of all kWh associated with GPC's units or partial units in each category for Such the contract year including back-up energy requirements for such units.
average cost per kWh shall be estimated at the beginning of the contract year with adjustaanc after the actual average cost per kWh is determined. . Transmission Responsibility for Partial Requirements Purchases Tirm Partial Requirements purchases by OEMC may be either (1) input purchases with Odic taking transmission responsibility under the Integrated Transmission System Agreement (considered included in OEMC's Peak laad) or (2) delivered purchases with GPC taking transmission responsibility under the Integrated Transmission System Agreement (considered included in GPC's Peak Load). In the (2) case GPC would include transmission costs in its
" delivered" Partial Requirements Rate filing.
11 xx_ _=____--_u_=_:__.
- .x . . _ , ___: -_ t
3;3 = y = , n: - - -
~-
g., . .n y, 5 Og ::+ ' y
'hi..}
'?., .
1 g' . f T;; L, GEORGIA POWER COMPANY
- .s ' 'FPC Electric Tariff Original volume No.
Wholesale for Resale PARTIAL REQUIREMENTS SERVICE 4 I .. i o ' 9 4 'D r L. L-;---..____--._-.._.--_ _ _ . _ _ . _ . - - - . - -- ._ - - - - _ _ . . _ - - . . . . - . . . - - _ _ .- - . - _ ._ _-- - _ _ -_. - _ _ _ - - _ . - _ _ _
m ,
- - - -- r p:~ g .n; . , e o -
t *U~ ' :,l j "
\p j ,
1 g (( , i r *
. Georgia Power' Company i .
E , FPC Electric, Tariff:
' Original Volume No.
~
y < PARTIAL REQUIREMENTS SERVICE
- ' Electric: service,for partial require-ments of Customers for' Customer use
.and redistribution at retail comple-- mentary to other bulk power supply _
. resources"of;a Customer.
]
-File'd With The 6 -Federal' Power Commission Communications concerning this Tariff should be addressed to:
Mr. Harold C. McKenzie, Jr.. Executive Vice President I , Georgia Power Company ! P. O. Box 4545 . J
' Atlanta,. Georgia 30302 and Mesars. Troutman, Sanders,.Lockerman & Ashmore 1400 Candler Building <
Atlanta', Georgia 30303 4 Y l i =_:=:u : - _ . - _ + . . _ _ _ - _ _ _ - .- _ -- _ _ - . _ _ _ -- .- --
ng=r; , -
?
y ;; Georgia' Power Company F : FPC Electris Tc. riff-E TOriginallValume-No. . Original Shcat No; '.1
;l , .
TABLE OF CONTENTS If
-Sheet No.
1 Table of Contents 2 Preliminary Statement' 3 Index'of Purchasers 4- Wholesale,for. Resale Service Rate "PR-1" Partial Requirements Service 12 Terms and Conditions a 21 Formsof Wholesale Partial. Requirements Electr': Service Contract
-~
Throug.. May 31, 1985 24 Form of Wholesale-Partial Requirements .
. Electric Service Contract For Year Beginning on or after June 1,.1985
,7 i$ Issued'by_ Harold C. McKenzie, Jr. j Executive Vice President Issued on' June 30, 1975 Effective July 1, 1975
-m_,__. _- - _ - - .m_. - .A _ m ..__.&.L __-. .m:2 ...2 __,..__h. __ 2. _m____ __._m_.____m._L____m_m__.__.__
Georgio Power Company FPC Elcctric Tariff
' Original Valutu No. Original Sh =t No. 2 PRELIMINARY STATEMENT Georgia Power Company is an electric utility operating y' within the State of Georgia. In addition to serving more than 1,000,000 customers at retail, on the date of issue of this tariff, the Company provided full requirements wholesale for resale service to 50 municipalities and Oglethorpe Electric Membership Corporation, the bulk power supplier for 39 electric membership cooperatives.
Georgia Power Company's common stock is wholly-owned by The Southern Company. The Company's electric operations are coordinated with those of the other operating subsid-iaries of The Southern Company. Pursuant to this tariff, the Company will provide base load capacity, intermediate load capacity, peaking load capacity, reserves for such capacity and associated energy, complementary to other bulk power supply resources of a ^ Customer. In addition, the Company will provide reserves for Customer-owned resources which result from. joint plan-ning with the Company. Simultaneously with the issuance hereof, the Company is issuing a transmission service tariff which will prov'ide for integration of the transmis-sion systems of the Company and Customers taking partial requirements under this tariff. Both tariffs contemplate significant joint planning between the Company and any Customer to maximize the economy and reliability of electric service on their com-bined systems. I i i l Issued by Harold C. McKenzie, Jr. ! Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 ; - - - _ _ _ _ . _ - _ _ - _ _ _=__. - _ .-. - _
LGeorgia Power Company.. I '; , :-FPC Elcceric Tcriff No. Original Shast No. 3
- i. A INDEX OF PURCHASERS UNDER THIS TARIFF s, ~Date of Purchaser Service Contract Effective Date-Oglethorpe Electric Membership Corporation 7/1/75 7/1/75-148 Cain Street E Atlanta, Georgia 30303
.\ t Issued by Harold C. McKenzie, Jr.
Executive- Vice President Issued on June 30, 1975 Effective July 1, 1975
- - _ _ _ _ = _ _ _ _ _ - _ - - _ _ _ _ - - _ _ _ - - - . __ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ - _ - _ - _ _ _ _ . _ - _ _ - _ _ _ _ _ =
O G:orgia Pow:r Comp ny
'FPC Electric Tcriff Original Volume No. _ Original Sheet No. 4 i
GEORGIA POWER COMPANY Wholesale for Resale Service Rate "PR-1" Partial Requirements Service 4 AVAILABILITY > Three-phase electric service available to Customers at the bus bar of the Company's step-up substations at its sev-eral generating plants at a frequency of approximately 60 hertz, but metered at the Customer's actual delivery point . and adjusted for losses. The Customer shall be required to accommodate its system to the characteristics (grounded or ungrounded) of the Company's system. Availability of this service shall be conditioned upon satisfaction of the contract and notice requirements contained in the " Terms and Conditions for the Purchase of Electric Power for Resale Pursuant to Partial Requirements Tariff" (" Terms and Con-ditions") in the Company's FPC Electric Tariff on file with the Federal Power Commission. APPLICABILITY Electric service for partial requirements of Customers for Customer use and redistribution at retail complementary to service, if any, from the United States through the Southeastern Power Administration ("SEPA") and complementary to other bulk power power supply owned by the Customer or furnished by other than the Company. As used herein,
" Customer" means any financially responsible person, private or public corporation, municipality, county, cooperative, association, joint stock association or business trust, own-
- ing, operating or proposing to own or operate equipment or facilities within the State of Georgia (other than Chatham, Effingham, Fannin, Towns and Union Counties) for the gener-ation, transmission or distribution of electricity, provided Issued by Harold C. McKenzie, Jr. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 _ _ _ _ - - _ _ _ _ _ - - _o
LGeorgic Pow r Company _ tFPC Electric. Tariff-
,0riginal Volume No. _ Original Sheet No. 5 I .~
that, except for-municipalities, counties, or rural, electric , cooperatives, " Customer" is restricted to those which are or will be public utilities under the laws of the State of Georgia or under the laws of the United States, and are or will be providing retail electric service under a contract or rate schedule on file with-and' subject to the regulation. L of the-Public Service Commission of-the State of Georgia-or any regulatory agency of the United States, and,-provided
~further, that as to municipalities, counties or ru al elec-l tric cooperatives, " Customer" is restricted to those which k provide electricity to the public at retail within the Stace of Georgia (other than Chatham, Effingham, Fannin, Towns and Union Counties) or to responsible and legally. qualified organizations of such municipalities, counties and/or coop-eratives in the State.of_ Georgia (other than Chatham, Effing-
. ham,'Fannin, Towns and Union Counties) to the extent they may bind their members. Whenever the words " Customer",
" Customers" or similar words appear herein or in any related tariff' documents, they shall refer to an individual Customer, an organ.ization of Customers, or both, as the context reason-ably requires. This schedule does not apply to any Customer who purchases its full requirements, other than SEPA, from the Company pursuant to any other tariff. Should the Customer require service at more than one delivery point,.this schedule shall apply to the composite of such delivery points.
l DESCRIPTION OF SERVICE 8 Electric service under this rate shall consist of base l capacity, intermediate capacity and peaking capacity, as {
' hereinafter defined; reserves for such capacity; and asso- )
ciated energy. Additionally, the Company will provide re-serves for Customer-owned generating resources which result i from joint planning with the Company at the cost and in the j manner hereinafter set forth. ] DEFINITIONS : For the purposes of this tariff, capacity requirements by category shall be defined as follows: , i
. Issued by Harold C. McKenzie, Jr.
E,xecutive Vice President l Issued on June 30, 1975 Effective July 1, 1975
"G ;rgic pow;r Compcny
[, -FPC Elcctric Tariff , L0riginal Volume No. _ Original Shset No. 6 Base Load shall'be the-portion of the p annual load duration curve which lies below the kilowatt' load level with a duration of 80 percent of.the total' time. Peaking Load shall be the portion of the c annual load duration curve above the-kilowatt load level with a. duration of 10 percent of the total' time.
' Intermediate-Load shall be the intermediate portion of the load duration' curve which lies between the peaking load level and the base load level.
MONTHLY BILL The monthly bill shall consist of charges for contract capacity by category, reserve capacity by category, associated energy by. category, back-up energy'as used for reserving Customer-y owned generating resources which result.from joint pla.nning with the Company, and excess
. reactive capacity.
SCHEDULE OF MONTHLY CHARGES FOR CAPACITY Type of Service Monthly Charge Unreserved base' capacity $ 4. 32 per KW Unreserved intermediate capacity 2. 56 per KW Unreserved p5aking capacity 2,08 per KW Reserve capacity- 2. 46 per KW 3. Excess reactive capacity 0.20 per KVAR Issued by Harold C. McKenzie, Jr. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975
.E.__- -_________m.-..__mm_m. - . _ _-____2_.._ ______ -m ---__._.2. .._u_. _. _ _ .__._A
s
'Gr3rgio? Pow 0r Compcny
'TPC Elcctric Tcriff Original' Volume No. Original Sheet No. 7-DETERMINATION OF RESOURCE CLASSIFICATIONS r
Prior to the beginning of the contract year, the Company shall prepare a Resource Classification List com- d prised of its capacity. resources listed in order of ascend-ing variable incremental energy costs (as-determined I "Approximately as Scheduled" for the purposes of the l Southern System Power Pool) such that the capacity resource witn the lowest variable. incremental energy cost is at the bottom'of the list and the capacity resource with the
, highest variable incremental energy cost.is at the~ top of-g the list, except that those capacity resources whose oper-ating characteristics require that they be operated as base, intermediate, peaking or. reserve capacity resources shall be assigned to that category without regard to variable in-cremental energy costs. Starting at the bottom of the Resource Classification List, the capacity resources of the Company whose aggregate- sum of Summer System Peak Hour Capability (as determined for the purposes of the Southern o
' System Power Pool) to the next division l etween plants equals the Company's base load capacity requirements as hereinbefore defined shall be designated base resources of the Company. Those capacity resources of the Company next higher on the Resource, Classification List whose aggregate su'm of Summer System Peak Hour Capability to the next divi-sion between plants equals the Company's intermediate capac-ity requirements as hereinbefore defined shall be designated intermediate resources of the Company. Those capacity resources of the Company next higher on the Resource Classif-ication List whose aggregate sum of Summ' er System Peak Hour Capability to the next division between plants equals the Company's peaking load requirements as hereinbefore defined shall be designated as peaking resources of the Company.
All other capacity resources of the Company shall be desig-nated as reserve resources of the Company. 4 g DETERMINATION OF CAPACITY RESERVES Capacity purchased from the Company pursuant to this tariff and generating capacity resources of the Customer resulting from joint planning with the Company which the Customer contracts with the Company to reserve 1 Issued by Harold C. McKenzie, Jr. Executive Vice President g Issued on June 30, 1975 Effective July 1, 1975 _ 2 _ _ _ _ _ _ __ _ _ _____.____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .. __ _ _. .J
G argid PowsrLComp:ny
'FPC Electric. Tariff Original Volume No. _ Original Shsat No. 8 shall be reserved by the Company and a charge made therefor.
The Company shall furnish for each category of capacity a percentage. reserve determined by taking the difference be- . tween the maximum one-hour integrated coincident peak load on the combined systems of the Company and all Customers 4 receiving service under this rate schedule and the sum of. the Company's and the Customers' capacity resources, ex - pressed as a percentage of such load. The reserve capacity for each category'shall be deemed to be supplied by a pro rata share of the capacity in'each category above the cate-gory being reserved. Capacity in each category thus used for reserving a lo'wer category of capacity shall be deemed l' to be replaced by a like amount of capacity from'the next higher category. The percentage reserves calculated pursuant to the preceding paragraph;shall be based on the Company's estimate made prior to the beginning of the' contract year, of the annual coincident one-hour' integrated combined system peak demand. After occurrence of the coincident one-hour inte-grated combined system peak demand during the contract year, the. capacity required for reserving each category of capacity shall be recalculated using the reserves at the time of such actual peak demand; and charges that have been made for reserve capacity since the beginning of the contract year shall be adjusted accordingly. The charge for reserve capacity for the_ remainder of the year shall be based upon the reservesuat the time of such peak demand. DETERMINATION OF CUSTOMER CAPACITY REQUIREMENTS The Customer shall give the Company timely notice of its. requirements for capacity by category as provided in the " Terms and Conditions for the Purchase of Electric Power for Regale Pursuant to Partial Requirements Tariff". Additionally, at least thirty (30) days prior to the begin-ning of the contract year, the Customer shall furnish the H Company its best estimates of its annual load duration curve, monthly one-hour coincident integrated peak demands
.and monthly energy requirements for the contract year. The Customer shall furnish the Company a list of the types and i amounts of Customer-owned capacity resources available to the Customer at the beginning of the contract year and such resources as may be anticipated to be added or deleted Issued by Harold C. McKenzie, Jr.
' Executive Vice President 11ssued on June 30, 1975 Effective July 1, 1975 L--. . .
mg , ,- 7 q lG 3rgici.Powor; Ctspany; FPC'EltctricLTariff e 10riginal'Voluma No.l_ ' Original Sheet No. 9 - p i-during the contract year.- :j p
~
The Customer'shall: contract with the Company to take
~
oripayLmonthly for.its capacity. requirements by category,
'includingLthat capacity furnished as reserves for each:
category,jdetermined'in the~ manner. set forth herein,Lall' ! ( , as the:same shal1~be' adjusted for capacity losses. If:the total capacity actually. required by the Customer. .,' during-any; month should. exceed the' capacity which-the.Com-pany:has co'ntracted to furnish and the Customer has con- , ; y tracted to takeLor pay 1for,.and if the Company furnishes-such excess,;each category;of capacity:so contracted for shall befincreased' pro rata to equal the peak capacity actually furnished.by1 the Company. In such event, the
~
capacity requirements of.the' Customer, including reserve TeapacityTrequirements, shall' then be recalculated and any 7, charge forJcapacity which has.been made during_the contract:
- year shall be retroactively' increased accordingly. LFurther, the increased capacity requirements.shall be used as a basis for. billing during the remainder of the contract year.
DETERMINATION OF MONTHLY CAPACITY CHARGES
. Monthly capacity charges-shall be calculated by_ multi-plying Monthly Charges for Capacity by category by the . Customer's Capacity Requirements by category, including that capacity by category furnished as reserves,-all as.
determined pursuant to the provisions of this' rate schedule and as the . same may be- adjusted during the contract year as provided herein. DETERMINATION OF UNIT ENERGY CHARGES A de' termination shall-be made monthly from the Company load-duration curve of the amounts of base, intermediate D <
'and peaking energy-furnished by the ! Company to its total load.
1 Issued.by Harold C. McKenzie, Jr. Executive Vice President
. Issued on June 30,g1975 Effective July 1, 1975 9
.
- O
_~ - _ - _ - - _ - * . - _ . _ - - .: -- - L -- - -i
'Gncrg1T Pow r C:mpany j FPC Elcatric Tcriff l Original Volune N3. _ ,
Originni Shast No. 10 1 L 1Rus lowest cost energy from all resources in each cate-gory of the Company's Resource Classification List shall be p assigned to that category to the extent necessary to meet the l Company's total requirements in that category. Any energy ! generated by resources in a category in excess of that needed to meet the Company's requirements in that category shall be declared surplus to that category. The Company's energy s requirements in any category in excess of the energy from all [ L resources in a category shall be declared deficit to that category. Back-up energy furnished by the Company to reserve any Customer-owned generating resource shall be determined in the following manner. The normal energy expected from a Customer-owned generating resource shall be deemed to be the capacity of the resource, as determined by the Company, times the number of hours in the billing period times the load factor of the base, intermediate or peaking portion of the Customer's load duration curve, as appropriate. The back-up energy shall be deemed to be the expected kilowatt hours, thus calculated, less the actual generation by the Customer-owned generating resource. The back-up energy shall be deemed to have been supplied by a pro rata share of the surplus energy from each category above the category requiring the back-up energy. < The deficit energy in each category not generated by Company resources in that category shall be deemed to have been supplied by a pro rata share of the surplus energy remaining after provision for back-up energy for Customer-owned resources from each category above the category requiring the deficit energy. The weighted average cost of all energy thus assigned to each category, including back-up energy, shall be the Unit Energy Charge for energy in each category to be billed to the Customer. DETERMINATION OF CUSTOMER ENERGY REQUIREMENTS The Company shall determine the customer's monthly energy use by categories from the Customer's monthly load duration curve in the following manner. The base load energy use shall be the kilowatt hours represented by the t Issued by Harold C. McKenzie, Jr. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 _C _ _ _ - . .._2_. _ d ..m.
I- :G =rgic? Pow;r Comp ny
'FPC Elcetric-Teriff 10riginal Volum'e No. _ Original Sheet No. ll
[ area of the monthly load duration curve which lies'below L the kilowatt. load' level designated as base load on the ' Customer's annual load duration curve. The peaking load energy use shall;be the kilowatt hours represented by the area of the monthly load duration curve.which lies above c .the kilowatt load level designated as peaking load on the Customer's annual load duration curve. The intermediate load energy use.shall be the kilowatt hours' represented-by the. area of the monthly load duration curve which lies
.between the kilowatt load level designated as base load L and the_ kilowatt level designated as peaking load on.the Customer's annual load duration curve.
' Energy supplied from Customer-owned generating resoure-es in each category shall be deducted from the Customer's energy use in like categories to determine the Customer's energy requirement in each category.
DETERMINATION OF MONTHLY ENERGY CHARGES Monthly energy charges shall be calculated by multi-plying' the Unit Energy Charges by category, as determined above, by the energy requirements by category. CIMRGES FOR EXCESS REACTIVE CAPACITY Excess Reactive Capacity shall be that reactive capac-ity in excess of 0.4 times the maximum KW demand during each month. The charges for such Excess Reactive Capacity shall be the product of the excess capacity thus determined and $0.20 TERMS AND CONDITIONS Service supplied hereunder shall be subject to the " Terms and Conditiora", and said Terms and Conditions are incorporated herein by reference. Issued.by Harold C. McKenzie, Jr. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 i __2_________._____.--___.-___.__-._- - ---
GJ;rgil Pow r Comp ny. FPC LElcetric Tariff Original Volume -No. _, Original Sh::t No, 12
- GEORGIA POWER COMPANY Terms and Conditions for the Purchase of Electric Power for Resale Pursuant to Partial Requirements Tariff
- 1. Billing and Payment The Company will bill the Customer for all service
~
rendered hereunder for each month, and the Customer will pay such bill to the Company within ten (10) days from date of bill. When all or part of any bill, other than an amount aris-ing from a dispute regarding a bill computation or the adminis-tration of this rate, shall remain unpaid at the end of any billing period, interest at the rate of 1-1/2% on the unpaid balance at the end of each such billing period shall be added to the bill thereafter. The monthly billing rate will be applied to all bills. Service periods of 25 to 36 days will normally be billed . on a regular monthly basis without proration. For irregu-lar billing periods or billing periods determined by a special meter reading, consumption will be prorated to a 30-day base (regardless of the actual number of days be-tween meter readings) with the appropriate monthly billing rate applied. 1 l
- 2. Deposit and Discontinuance J The Customer agrees that, should it be judicially established that the Customer's failure to pay any bill ;
for service is unjustified, it will immediately deposit I with the Company as collateral security for payment of j future bills for service such sum as may be requested j by the Company, not to exceed twice the highest monthly ! bill of the Customer during the preceding calendar year, j
. j Issued by Harold C. McKenzie, Jr.
Executive Vice President issued on June 30, 1975 Effective July 1, 1975
h LG drgi Powar Comprny - L
-FPCiElcctric Tcriff' Origina1JVelume No.;_ T original Sheet No.13 4
L . The' Company will. pay simple interest at the, rate of 5"/. j t per annum upon any deposit which is required under this 1
- , provision. If_the' Customer. fails to make such deposit -l when requested to-do v . service hereunder may be dis-continued after twenty J0) day's written notice.
a M
. The Company may discontinue all' service after twenty (20). days written notice whenever the Customer has violated e
.any provision of the Company's-FPC Electric Tariff,'except that notice need not be given where discontinuance'of ser-vice'.at any. delivery point is necessary due~to the' Custom-
- g. .er's-failure.to. operate in'a safe manner consistent with sound engineering principles.
Where all service'is discontinued for cause, the Company may. terminate the contract upon giving, the Custiomer thirty (30) daysJwritten_ notice. Resumption of service following any such termination shall be conditioned upon payment by.the Customer;of collateral security, as provided hereinbefore.- Upon such termination, the; Customer'shall pay the Company, in. addition to any unpaid charges.for service, such other damages as provided by law.
\
3.- Metering y The Customer shall be responsible for transmitting power from the bus bar of the Company's substations at its ) several generating plants to the actual delivery point of j Customer use, where it shall be metered and adjusted for losses. J1 The Company or the Customer shall install such meter-ing devices at each delivery point as the Company deter- i
. mines is necessary.to properly meter deliveries to Customer; provided however, that the Customer may at its own cost install additional metering equipment to check that of the Company. The Company shall operate, maintain and read all
. , - such metering equipment. The' Customer shall supply with-out cost to the Company a suitable place for installing the Company's metering equipment.
Issued by Harold C. McKenzie, Jr. Executive Vice President -
~1ssued on June 30, 1975 Effective July 1, 1975 i
___-- _ - . _ - - . . _ _ _ _ _ __ -- - _ J
,. n -- K iFPC Electric Tcriff I ! Origin 21; Volume No. _ Original Shoot No.14 If any meter'used for billing fails.to register or'is-found to be inaccurate, an appropriate billing, based on f the best information available, shall be agreed upon by the parties hereto. Any meter tested and found to be not more than two percent (2%) above or_below normal shall be l considered accurate insofar as correction of billings is concerned. If as a result of any test, a meter is found K to register in excess of two percent (2%) either above or below normal, then the reading of such meter previously-l taken for billing purposes shall be corrected for the o , period during which it is established the meter was inac-curate, but no correction shall be made forfany period c beyond sixty'(60) days prior to the day on which an inaccuracy is discovered by.such tests. In' addition to such tests as are deemed necessary_by the Company, the' Company shall have any meter tested at any time upon. written request of the Customer, and if such meter proves accurate within two percent (2%) above or below normal, the expense of the test shall be borne by the Customer.
- 4. Use of Service
- The Company and the Customer will-each exercise dili-gence11n the operation of its electric system with the view of securing efficiency on both systems in keeping with generally accepted engineering principles and operating standards, will. construct its facilities in accordance with specifications at least equal to.those prescribed by the National Electric Safety Code of the U. S. Bureau of Standards, will maintain its lines at all times in a safe operating condition, and will operate said lines in such manner as not to unduly interfere with the operation of the other. The Customer will use electric service equally from the three phases as nearly as possible and will main-tain a power factor of not less than 0.93 lagging.
Issued by Harold C. McKenzie, Jr. : Executive Vice President ; Issued on June 30, 1975 Effective July 1, 1975 1
., . -- __ ._ . . . _ . . i
G rrgib Powcr C1mp ny FPC Elcctric Tariff Original Volume No. _ Original Sheet No.15
- 5. Access l
)- l The Company and the Customer will give all necessary permission to enable the agents of the other to carry out the provisions of these Terms and Conditions and construct
^
and maintain lines and circuits in and at all places re- i quired. Each will give the other the right to enter the premises of the other at all reasonable times for the pur-f pose of keeping in repair or removing facilities, reading meters and performing other work incidental to delivery and receipt of power. w (
- 6. Availability (a) Prior to June 1, 1985. To receive partial require-ments service from the Company in any year (June 1 - May 31) through the year ending May 31, 1985, a Customer must exe-cute a contract at least thirty (30) days prior to commence-ment of the first such year in which it desires to receive partial requirements service, said contract to be effective from June 1 following through May 31, 1985, in which it binds itself to these Terms and Conditions (as the same may be amended pursuant to the Federal Power Act), agrees to take or pay for the quantities of power resulting therefrom, and relieves.the Company from any responsibility otherwise to provide service. Said contract shall contain provisions limiting the Company's obligation to provide partial require-ments service, including reserves where required, during the period ending May 31, 1985, on a first-notice-received-first-served basis, as follows:
(1) Upon notice received not less than two (2) years nor more than two (2) years and one (1) month prior to the beginning of any such year, the Company shall supply the full requirements of all Customers (less S$PA), less not more than 200 MW in composite total of all such notices; (2) upon notice received not less than three (3) years nor more than three (3) years and one (1) month prior to the beginning of any such year, the Company shall supply the full requirements of all Issued by Harold C. McKenz$c, Jr. Executive Vice President issued on June 30, 1975 Effective July 1, 1975
Gr:rgio Powcr Company FPC El ctric Tariff Original Volume No. _ Original Sheet No.16 Customers (less SEPA), less 20% of the notifying
- Customer's load or 500 MW in composite total of all such notices, whichever is smaller; (3) upon notice received not less than five (5) years nor more than five (5) years and one (1) month prior to the beginning of any such year, the Company shall supply the full requirements of all Customers (less SEPA), less 40% of the notifying Customer's load or 900 MW in composite total of all such notices, whichever is smaller; (4) upon notice received not less than seven (7) years nor more than seven (7) years and one (1) month prior to the beginning of any such year, the Company shall supply the full requirements of all Customers (less SEPA), less 60% of the notifying Customer's load or 1300 MW in composite total of all s'uch notices, whichever is smaller; and (5) upon notice received not less than nine (9) years nor more than nine (9) years and one (1) month prior to beginning of any such year, the I Company shall supply the full requirements of all Customers (less SEPA), less 100% of the notifying Customer's load, s
(b) After May 31, 1985. To receive partial require-ments service from the Company in any year (June 1 - May 31) beginning after May 31, 1985, a Customer must execute a con-tract at least nine (9) years, but not more than eleven (11) , years, in advance of su 3 a year, said contract to be effec- ] tive for such year, in which it binds itself to these Terms ! and Conditions (as the same may be amended pursuant to the 1 Federal Power Act), agrees to take or pay for the specific quantities of power set forth therein, and relieves the Com- i pany from any responsibility otherwise to provide service. i Said contract shall contain provisions limiting the Company's obligation to provide partial requirements service, includ-ing reserves where required, during the period after May 31, 1985, on a first-notice-received-first-served basis, as ; follows: l Issued by Harold C. McKenzie, Jr. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 l 8 m_ms..__ ___._.____..___.__m .,m.... _ . _ . _ _ .
Ge:rgio Powcr Comp ny FPC'Elcctric Tcriff Original Volume No. __ Original Shest No.17 (1) Upon notice received not less than two (2) D . years nor more than two (2) years and one (1) month prior to the beginning of any such year, the Company-shall supply the total of such quantities specified in contracts of all Customers, less not more than 200 MW in composite total of all such notices; (2) upon notice received not less than three (3) years nor more than three (3) years and one (1) month prior to the beginning of any such year, the Company shall supply the total of such quantities specified in contracts of all Customers, less 20% of the notify-ing Customer's load or 500 MW in composite total of all such notices, whichever is smaller; (3) upon notice received not less than five (5) years nor more than five (5) years and one (1) month prior to the beginning of any such year, the Company shall supply the total of such quantities specified in contracts of all Customers, less 40% of the notify-ing Customer's load or 900 MW in composite total of all such notices, whichever is smaller; (4) upon notice received not less than seven (7) -
- years nor more than seven (7) years and one (1) month prior to the beginning of any such . year, the Company shall supply the total of such quantities specified in contracts of all Customers, less 60% of the notify-ing Customer's load or 1300 MR in composite total of all such notices, whichever is smaller; and (5) upon notice received not less than nine (9) years nor more than nine (9) years and one (1) month prior to beginning of any such year, the Company shall supply the total of such quantities specified in con-tracts o,f all Customers, less 100% of notifying Customer's load.
H (c) The megawatt limits set forth in Paragraph (a) of this Section shall not apply.to Customer-owned capacity, if any, by way of participation in ownership of or unit i power purchases from the following nuclear generating units: Hatch 2, Vogtle 1 through 4. Issued by Harold C. McKenzie, Jr.. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975
Ge'rgia Power Company FPC Elcctric Tariff Original Voluma N2. __ Originel Sheet No.18
'7 . Interruption of Service J
The Company shall not be liable to die Customer for failure to deliver or curtailment of service if such failure or curtailment is due to:
> (a) Injunction or other governmental order, includ-ing allocation or curtailment of fuel sources, fire, light-ning, strike, riot, invasion, explosion, flood, snow or ice storm, accident, breakdown, acts of God or the public enemy, or any other cause beyond the control of the Company; or (b) The necessity or desirability in the discretion of the Company, exercised consistently with sound engineer-ing principles, to make system repairs, maintenance or improvements, provided the Company has given the Customer notice thereof as soon as reasonably practicable; or (c) Threatened loss of system integrity due to condi-tions on the Company's system, or on systems with which the Company is directly or indirectly interconnected.
8._ Liability Neither the Company nor the Customer shall be responsi- l H ble fo'r injury or damage to the personnel, machinery, lines, apparatus, appliances, or other property of the other caused _ I by lightning or by defects in or failure of the machinery, apparatus, or appliances of the one suffering such damage l from such causes, and the Company shall not be in any way l responsible for the transmission or control of said electric ! service beyond the point of delivery to the Customer, except ] where damage shall have been occasioned by the negligence of ) the Company, its agents or employees. a 9-. Billing Credits i The Customer shall be entitled to capacity and energy credits in each category of capacity and energy for Customer-owncd generation and/or purchases from other sources Issued by Harold C. McKenzie, Jr. 3xecutive Vice President Issued on June 30, 1975 Effective July 1, 1975 e
Georg2.3 Powcr Comp:ny FPCfElcctrie Texiff Original Volume No. _ Original Shast No. 19 provided the Customer has: b (a) made all necessary transmission arrangements for. such capacity and energy; (b) made all necessary arrangements with the Company p for dispatching.such capacity and energy; (c) provided for reserves for such capacity and energy; (d) complied with all contract and notice requirements g of Section 6, above. The KW of capability attributed to any Customer-owned generating resource will be based upon demonstrated plant operating characteristics which will be evaluated on a' basis sLnilar-to that utilized in the Southern System Power Pool, @ and -the Company or power pool representatives shall be enti-tied to inspect and test Customer generating resources to carry out this' provision. Capacity and' energy from Customer-owned resources shall be. classified by the company ac-ording to the same techniques utilized by the Company in classifying its own resources.
._ In the derivation of the Customer's reserve responsibil-ities, its individual- generation resources shall be_ judged on
- the same reliability standards as the Company applies _to its own resources (in the case of same-kind generation) or accord-ing to sound utility practice (in the case of different-kind generation). As long as all of the Customer's power require-ments are derived through joint planning with the Company and' are satisfied through any. combination of specific self-owned generating resources, partial requirements purchases from the Company and purchases of SEPA' hydropower, thereby resulting in ,a full contribution to total reserves, the reserve requ'irement for any and all specific resources shall be the same percentage amount to be maintained by the Company system wide each contract year.
Issued by Harold C. McKenzie, Jr. Executive Vice President '
. Issued on June 30, 1975 Effective July 1, 1975
I L 'G Irgic' Power Company I FPC Elcctric Teriff
. Original' Volume No. _ Original Sheet No. 20 If the Company is unable to meter or does not have ade-f / quate metering for Customer-owned resources, the Customer will certify to the. Company in writing within five (5) days of the end of each billing month the KW and KWH delivered to the Customer from each such resource during said month.
ry .
- 10. Amendments The Company shall, subject to Section -205 of the Federal Power Act and the Rules and Regulations of the
& Federal Power Commission, have the right at any time to amend these general Terms and Conditions and all.other pro-visions of its tariff by furnishing an appropriate statement of such amendment to the Customer and filing the same with the Federal Power Commission or other appropriate regulatory - agency. e 4 i
v' L G rgio P:wer Comprny FPC Elcctric Tcriff Original Voluma No. _ . Original Sheet No. 21 l b GEORGIA POWER COMPANY l Wholesale Partial Requirements Electric Service Contract Through May 31, 1985 THIS AGREEMENT, by and between GEORGIA POWER COMPANY i, (the Company) and (the Customer), an entity organized and existing under the laws of the State of Georgia. m WITNESSETH That in consideration of the mutual covenants and agree-ments hereinafter contained, the parties hereto for themselves, their sucessors and assigns, have mutually agreed with each other as follows: I. Service, For the period from executing this contract r.s through May 31, 1985, the Company will supply to the Customer, the Customer will take or pay for, and the Company shall be relieved from any obligations to supply more than, the follow-ing quantities of partial requirements electric service: The Customer's full requirements, less (A) hydro service, j if any, supplied to the Customer by the United States through 1 i the Southeastern Power Administration, as required by the contract between the United States and the Company executed June 19, 1970, as the same may be amended from time to time, i
- Issued by Harold C. McKenzie, Jr.
Executive Vice President Issued on June 30, 1975 Effective July 1, 1975
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.G orgia Powar Compr.ny'
,FPCLElectric Ta~ riff-Original Volume No._ . Original Sheet No.:22 b
L . Es 'the applicable provisions of which are made a part.of this-1
-contract, (B) service, if any, received by the Customer l^
from its ownership interest in Hatch 2 or Vogtle 1 through,4 nuclear units, and (C) such quantities as may be specified in notices given' pursuant to and in conformity with Paragraph 6(a) of the " Terms and Conditions for the Purchase of Electric
' Power for Resale. Pursuant to Partial Requirements Tariff" (Terms and' Conditions).
II. Payment. The Customer shall purchase and pay the Company for such service for each month in accordance with i the Wholesale Service Rate for Partial Requirements Service l b and Terms and Conditions in the Company's FPC Electric Tariff, as the same may be amended from time'to time or
~
superseded. The term " month" as used in this section desig-I. nates the period of approximately one month between successive i regular meter. readings. It is recognized that the said Wholesale Service Rate I L and other Tariff Provisions are subject to change pursuant to provisions of the Federal Power Act. III. Delivery. Service hereunder shall be delivered by E the Company to the Customer at the bus bars of the Company's step-up substations at its several generating plants. IV. Electric Tariff. The Terms and Conditions and the
~
Wholesale Service Rate for Partial Requirements Service set v l l L Issued by Harold C. McKenzie, Jr. _; "# Executive Vice President i
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Gdorgio Power Company-
!FPC:Elsetric Tariff Originsi Voluma No. _ Original Sheet No. 23-4..
Lforth in the Company's FPC Electric Tariff, as the same may be amended from time to time, are incorporated by reference into this contract. d V. Miscellaneous. This contract shall be. binding upon, the Company only when accepted by its duly authorized agent and shall not be modified by any promise, agreement or repre-sentation of any agent or employee of the Company unless in-corporated in writing .in this contract before such acceptance. l l IN-WITNESS WHEREOF, the parties hereunto have ca'used l this. contract to be executed by their duly authorized officers. l -ATTEST GEORGIA POWER COMPANY BY: Title Date Customer l-ATTEST BY: Title Date l . '. l 1' Issued by Harold C. McKenzie, . Jr.
-Executive Vice President Issued on June 30,-1975 Effective July 1, 1975 Le . _ . _ _ _ _ _ _ _ _ _ _________.-___n _ _ _ _ . __. _ _
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- FPCrElsetric Teriff- '
fTOriginal Volum3.No.. Originhl Sheet No. 24 V d' GEORGIA POWER COMPANY Wholesale Partial Requirements Electric Service Contract ) For. Year Beginning.on'or after June 1.-1985
' THIS AGREEMENT, by and between. GEORGIA POWER COMPANY f, L(the. Company) and
,(the Customer)', an entity organized'and existing under the L' ' lawsLofithe State of Georgia.
II WI'THESSETH l P That in consi'deration of the mutual covenants and agree-ments hereinafter contained, the parties hereto for themselves, _ .
'their sucessors and assigns, have mutually agreed with each R
L other- as follows:
- 1. Service. In the year June 1., 19__ through May 31, f 19__, the Company will supply to the Customer, the Customer will take or pay'for, and the Company shall be relieved from any obligation to supply'more than, the following quantities of= partial requirements. electric service.:
, Unreserved base capacity kw Unreserved intermediate capacity kw Unreserved peaking capacity kw Reserve capacity per Terms and Conditions
- and Wholesale Service Rate for Partial Require-ments Service Excess reactive capacity per Terms and Conditions and Wholesale Service Rate for Partial Require-ments Service Issued by Harold C. McKenzie, Jr.
' Executive Vice President Issued on June 30, 1975 Effective July 1, 1975
+ _. ._. . __- - _ . _________ __ _-_-
lFPU r.icetric Tariff
- Original Volums No.- Original Sheet No. 25 1'
' less such quantities as may.be specified in notices given pursuant to and in conformity with Paragraph 6(b) of the
?' Terms and Conditions. II. Payment.. The Customer shall purchase and pay the-Company for such service for each month in accordance with Y I' the Wholesale Service Rate for Partial Requirements Service in the Company's FPC Electric Tariff, as the same may be amended from time to time or superseded. The term " month" as used in this section designates the period of approximately
~
one month between successive regular meter readings.
.It is recognized that the said Wholesale Service Rate and other Tariff Provisions are subject to change pursuant to provisions of the Federal Power Act.
III. Delivery. Service hereunder shall be delivered by l-the Company to the Customer at the bus bars of the Company's step-up substations at its several generating plants. IV. Electric Tariff. The Terms and Conditions and the Wholesale Service Rate for Partial Requirements Service set forth in the Company's FPC Electric Tariff, as the same may
.be amended from time to time, are incorporated by reference into this contract.
V. Miscellaneous. This contract shall be binding upon the Company only when accepted by its duly authorized agent and shall not be modified by any promise, agreement or repre-sentation of any agent or employee of the Company unless in-corporated in writing in this contract before such acceptance. Issued by Harold C. McKenzie, Jr.
. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 n___ ' - 8'
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. Georgia Power Comp ^ny-1
- FPC Elcctric Tcrif JOriginal Volume No.
Original Sheet No. 26 9' IN WITNESS WHEREOF, the parties hereunto have caused ? this contract to be executed by their duly authorized officers. ?- ATTEST GEORGIA POWER COMPANY BY:
- , Title Date
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Customer . ATTEST BY: Title Date l 1ssued by Harold C. McKenzie, Jr. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975
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- l ATLATf7A -
; June 30, 1975 Yi ,;
- Federal. Power! Commission, j
- 825 North Capital Street,.N.E.
. Washington, D. C. 20426 ss -
Attention: : Honorable Kenneth F. Plumb, Secretary Gentlemeni Enclosed. herewith for filing with the Commission g
- Jareisix-copiesHof Original' Sheets No. 1 through No'.20, ;!
icomprising Georgia'PowerLCompany's FPC Electric Tariff,; j
' Original Volume No.. ,ean_ initial tariff to provide trans- o
- mission service-to Customers within the State of Georgia -!
(other than Chatham, Effingham,;Fannin, Towns and Union uCounties).-
.The following:information with respect ~to the enclosed initial' tariff.is submitted in compliance with Section 35.12 of the Commission's Regulations under the
! Federal Power'Act. ,
o . Pursuant.to its FPC Electric. Tariff, Original Volume _No.,1, the Company presently provides full require-ments wholesale ~for resale service to 50. municipalities and _Oglethorpe Electric Membership Cor? oration ("0EMC") , an association of 39' electric membership cooperatives, in the
~ State of Georgia. OEMC.has recently acquired an undivided i 301 ownershipfi nterest in the Company's nuclear Plant Hatch Unit No. 1, and OEMC will begin receiving and retaining a portion of that unit's output on July 1, 1975.
t ,Accordingly,'the Company has designed and is filing today an initial . partial requirements tariff, containing a ~ x' ' Rate Schedule "PR-1," under which OE'4C will take service.
'"PR-1" is a bus bar rate with a Customer being responsible-
~for transmitting power from the step-up substations at the J { Company's generating plants to the Customer's delivery point.
To, facilitate such transmission and to integrate their trans-1 mission syctems, the Company and OEMC have executed an l l I J 4 i ']
. Fiv.mitv A 3Nnwwetfetams Arty Integrated Transmission System Agreement in the form con-l tained in this tariff. A co closed: herewith. Initially,py OEMC of saidwill Agreement be the onlyiscustomer en-taking service under 'TS-1", but the service shall be avail-able to any customer meeting the requirements set forth in the tariff. "TS-1" represents the result of considerable i negotiation between the Company and OEMC, and the executed contract reflects agreement on all issues.
As explained above, the transmission service provided under this tariff must be available to OEMC July 1, 1975: therefore, the Company and OEMC are requesting, pursuant to Section 35.11 of the Commission's Regulations, that the Commission waive the 30-day notice requirement of Section 35.3, so that the tariff and the contract may be-come effective July 1, 1975. Pursuant to the tariff, the Company will transmit a Customer's bulk power resources within that portion of the State of Georgba described above pursuant to entry by the Company and the Customer into arrangements for the ownership and use of an integrated transmission system, which arrange-ments provide'for parity of investment in said system among Custcmers and the Company and for payments by one party to the other in the event of disparity of investments. Because of the nature of the arrangement, as de-seribed above, the Com accuracy the revenues,pany cannot estimate with relativeif any, which may be produ 1 The Integrated Transmission System Agreement the tariff. between the Company and OEMC is the result of arms-length negotiation. Any additional arrangements-entered into by the Company and another Customer under "TS-1" will similarly reflect such arms-length negotiation. As stated above, OEMC is the only customer who will initially be able to utilize transmission service under "TS-1." In addition to the OEMC personnel, counsel and consultants shown on the attached Address List, the Company has also provided copies of this entire filing to counsel and/or con-sultants for all of its other wholesale customers who may, at some later date, be able to receive service under this tariff. The names and addresses of such individuals are also shown on the Address List. The Company's check in the amount of $100.00 is enclosed herewith in payment of the filing fee required under Section 36.2 of the Commission's Regulations. 9
Wc:;f ' U 4l:pf 3 Ly , y' ihomu A Powwn (hnmswery -
.h The following.is.a: complete list'of.the documents',
} six' copies of which are submitted with this filing letter:
'(1) . Tariff sheets (detailed'.above)';-
4; (2)' ' Integrated . Transmission System Agreement : ' - between the Company and OEMC; (3).. Form of Notice for FederalLRegister;
-(4) Address . List;-
l(5) . Check for filing' fee. b V ry truly.yours, N
,' LC.h,kl(.dC
'f Ha old'C. McKenzie,'Jr.
Executive Vice President HCMJr/sd.
;EnclosuresL(as described-above) e 4
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' GEORGIA POWER COMPANY FPC-Electric Tariff.
Original Volume No. . TRANSMISSION. SERVICE
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h Q . .. Georgia Power Company; g FPC Electric Tariff Original Volume No. ? TRANSMISSION SERVICE TARIFF. Transmission service to Customers within-the State;of Georgia pursuant' - to'.an integrated transmission system > . agreement which will result in parity of investment in said system among
, . Customers and;the Company.
1 Filed With The' s . Federal Power Commission ?. Communications concerning this 9- Tariff should be addressed to: Mr. Harold C. McKenzie, Jr. Executive Vice President
. ' Georgia Power Company P. O. Box 4545 Atlanta, Georgia 30302 and Messrs. Troutman, Sanders, Lockerman.& Ashmore 1400 candler Building Atlanta, Georgia'30303 i
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Ge:rgiol Power-Compiny, FPC:Elodtric Tdriff 10riginaliValume No.- ' Original Sheet No. 1 - a ? ,
- TABLE OF-CONTENTS:
s Sheet No.
'l ' Tabic of Contents
.' 2 ' - Preliminary Statement a
3 Index of Purchasers 4 - Transmission Service Tariff "TS-1" 6- Form of Integrated Transmission 4 System Agreement 1 Ih 4 Issued by Harold C. McKenzie, Jr. Executive Vice President Issueden1 June 30,ig75 Effective July 1, 1975
1 lGeorgiolPowir' Comp:ny FPC ElCctric Tariff Original Volume No. - Original Sheet No. 2 -
\
PRELIMINARY STATEMENT T Georgia Power Company is an electric utility operating within the State of Georgia. In addition to serving more than 1,000,000 customers at retail, on the date of issue of this tariff, the Company provided full requirements wholesale for resale service to 50 municipalities and
- Oglethorpe Electric Membership Corporation,.the bulk power supplier for 39 electric membership cooperatives.
Georgia Power Company's common stock is wholly-owned by The Southern Company. The Company's electric operations are coordinated witn those of the other operating subsid-iaries of The Southern Company. Simultaneously with the issuance of this tariff, the Company ~is issuing a wholesale for resale partial require-ments: tariff, pursuant to which a Customer . receiving par-tial requirements service will be responsible for trans-mitting power from the step-up substation at the Company's generating plants to the Customer's delivery point. The Integrated Transmission System Agreement; provided. for in . this transmission service tariff will facilitate the trans-mission'of a Customer's partia1' requirements purchases and will. integrate _the transmission system of the Customer and the Company. Both . tariffs contemplate significant joint planning between the Company and any Customer to maximize the economy and reliability of electric service on their com-bined systems.
' Issued by Harold C. McKenzie, Jr.
Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 __.._____--x_---____.._ - - - _ - - -~
g o .__ _ _ _ _ p4 _ L i' ? ) Georgia 1. Power Cgmpany iFPCiElectric Tariff-1 Original: Volume No'. Original Sheet No,-3 {! . ? ,y INDEX OF PURCHASERS' UNDER THIS TARIFF - k.: Date of Purc Mc.er Service Contract. Effective Date
.Ogl'ethorpe - Electric Membership Corporation 1/6/75 7/1/75-148- Cain Street.
Atlanta, Georgia 30303 l l i i 1 l 1 Issued by Harold. C. ' McKenzie, Jr. Executive:Vice President IssuedJon.;une 30, 1975 Effective July 1, 1975 l l =_m-_ _. _ _ __ - _ - . _ _ _ _ _ _ _ _ _ __ _ _ _ . . . - _u
Grcrgli Pow;r Compnny FPC Electric Tariff Original Volume No. _ Original Sheet No. 4 s GEORGIA POWER COMPANY Transmission Service Tariff TS-1" AVAILABILITY Transmission service available to Customers in accor-dance with the provisions of the attached contract. The Customer shall be required to accomodate its system to the characteristics of the Company's system. APPLICABILITY Transmission service for requirements of Customers to transmit bulk power within the State of Georgia (other than r Chatham, Effingham, Fannin, Towns and Union Counties). As used herein, " Customer" means any financially responsible person, private or public corporation, municipality, county, cooperative, association, joint stock association or business trust, owning, operating or proposing to own or operate equip-ment or facilities within the State of Georgia (~ther o than Chatham, Effingham, Fannin, Towns and Union Counties) for the generation, transmission or distribution of electricity, pro-vided that, except for municipalities, counties, or rural electric cooperatives, " Customer" is restricted to those which are or will be public utilities under the laws of the State of Georgia or under the laws of the United States, and are or will be providing retail electric service under a contract or rate schedule. on file with and subject to the regulation of the Public Service Commission of the State of Georgia or any regulatory agency of the United States, and, provided further, that as to municipalities, counties or rural elec-tric cooperatives, " Customer" is restricted to those which provide electricity to the public at retail within the State of Georgia (other than Chatham, Effingham, Fannin, Towns and Union Counties) or to responsible and legally qualified organizations of such municipalities, counties and/or coop-eratives in the State of Georgia (other than Chatham, Effing-ham, Fannin, Towns and Union Counties) to the extent they may L~ , bind their members. Whenever the words " Customer",
" Customers" or similar words appear herein or in any related tariff documents, they shall refer to an individual Customer, an organization of Customers , or both, as the context reason-ably requires. This schedule does not apply to any Customer Issued by Harold C. :1cKenzie , Jr.
Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 L_______________ - - - - - ~ ~ - ^
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I [GbirgidLPower' Company. ' LFPC Elcetric.Teriff l Original Volume.No..,_. . Original Sheet No. 5 ' l
..w ho purchasesLits full requirements, other than SEPA, from:thel Company' pursuant:to Georgia' Power Company's ,i Full; Requirements Wholesale Service Schedule, contained' in its FPC Electric Tariff, Original Volume No. 1, as _
the'same may be-amended pursuant to the' Federal Power
'Act. 1 DESCRIPTION OF SERVICE Service under this tariff shall consist of the'trans-mission of. Customer's bulk power resources, as defined, within1 the- State of Georgia- (other than Chatham, Effing L, ham,.Fannin,' Towns and Union. Counties) pursuant.to entr .
by the Company;and the Customer into arrangements for t e ) ownership and'use of an integrated transmission system, which arrangements provide for parity of investment in said system among Customers And the Company and for payments by one party to the other-in the event of disparity of in-
. vestment.
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i i I f' l l . 1 o l i -
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Issued tor Harold C. :IcKenzie, Jr. .)
' Executive Vice President '
l LIssued on. June 30. 1975 Effective July 1, 1975 i R l a L_=:_ __ __________________. __ _ __ 2________ _ _ _ _ _ - i
3.
- i. Georgia: Power;Ccmpany FPC Electric' Tariff (Original'VolumeLNo. . Original Sheet No. - 6
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1 l4 INTEGRATED. TRANSMISSION SYSTEM AGREEMENT y
.between and b ..
l GEORGIA POWER COMPANY 4
- Dated as of , 19_
1 Issued by Harold C. McKenzie, Jr. Executive Vice~ President
- Issued on June'30, 1975 .
Effective July 1, 1975 1 _. c_ _ _ _ _ _ . _ _ _ _ _ . _ _ _ _ _ . _ _ _ _ _ _ . _ _ . _ _ _ _ . . _ _ . _ _ _ . _ _ _ _ . _ . . ._ m -. _ . _ e
[} r
. G:crgid Pow;r Comp ny .'LFPC E1Cetric Tariff Original Volume No. _ Original Sheet No. 7 I
THIS AGREEMENT, dated as of , _ , 19__ is.between i and GEORGIA POWER COMPANY, a corporation organized and j 3 existing under the laws of the State of Georgia ("GPC"). I WITNESSETH: A. GPC is engaged in the business of generating, transmitting and distributing electric power and energy in the. State of Georgia and is (description). i B. .(Other appropriate recitations, if any.)
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C. It is tne parties' general desire that the i Integrared Transmission System 'of GPC and will be used to provide the trans-mission requirements of GPC and . D. GPC and desire to develop and utilize such Integrated Transmission System to' supply electric power and energy to each other within the State of Georgia. E. ' Additions to the Integrated Transmission System as required will be made separately by GPC and with the intent that each party will ultimately own separate facilities proportionate in the aggregate to its use of such system. NOW, THEREFORE, in consideration of the premises and the mutual agreements herein set forth, GPC and hereby agree as follows: i Issued by Harold C. McKenzier,
- Jr.
- Executive Vice .? resident Issued on June 30, 1975 .
Effective July 1, 1975
Georgio Power Comp ny FPC'Elcetria Tcriff Original Volume No. _ Original Sheet No. 8 ARTICLE I DEFINITIONS 1.01 Transmission Facilities. Transmission Facilities ~ shall be all facilities (including land) owned by a party, in existence on the Effective Date (as hereinafter defined), or hereafter coming to be so owned pursuant to Section 2.03 (ii) of this Agreement, within the State of Georgia other than in Chatham, Effingham, Fannin, Towns and Union Counties,
, used or useable to transmit power the operating voltage of which is 40kV or more and to transform power the high-voltage side of which is 40kV or more and the capacity of which is ,
500kVA or more, excluding step-up substations at generating plants. 1.02- Contract Year. The Contract Year shall begin on January 1 of each year, and end on December 31 of each year; provided, however, that the first Contract Year shall begin on the Effective Date and end on the following December 31. 1.03 Transmission Carrying Charges. For the purpose of this Agreement, the Transmission Carrying Charge for GPC shall mean the aggregate of the annual dollar costs incurred by GPC with respect to its ownership, operation and mainten-ance of its Transmission Facilities divided by GPC's aggre-gate undepreciated dollar investment in such facilities dur-ing the Contract Year (including pro rata credit for facili-ties becoming used or useable, or retired, during the Con-tract year). Such annual dollar costs shall be the aggregate of depreciation, ad valorem taxes, insurance, operation and maintenance expenses including administrative and general expenses properly allocated thereto, all as properly record-able in accordance with the Federal Power Commission's Uni-form System of Accounts, and the cost of funds, including income taxes.' The cost of funds, including income taxes, shall be calculated as follows: - The capital structure of GPC as shown on GPC's most recent 10-Q Report shall be calculated and broken down into three decimal components the sum of which totals one (1.00): (1) Long-Term I l Issued by Harold C. McKenzie, Jr. I
)
Executive Vice President i Issued on June 30, 1975 Effective July 1, 1975 l _ - - .- -]
GIrgio Power C:mp'ny FPC Elcatric Tcriff Original Volume Na. _ Original Sheet No. 9 Debt and Interim Indebtedness, (2) Preferred ) Stock and (3) Common Equity. The cost of the Long-Term Debt and Interim Indebtedness, respect- _
'~'
ively, shall be the then current weighted average percent cost of all First Mortgage Bonds and Interim Indebtedness, respectively, times the 3 Long-Term Debt and Interim Indebtedness ' component of the capital structure determined above. The cost of Preferred Stock shall be the then current weighted average percent dividend rate of such stock times the Preferred Stock component of the capital structure determined above divided by the then current Tax Factor. The cost of Common Equity shall be the most recent percent return allowed on equity by the Federal Power Commission for sales to GPC's wholesale customers or such percent return submitted in a rate settlement with its wholesale customers (whichever is most > recent) times the Common Equity component of the' .. capital. structure determined above divided by the then current Tax Factor. The Tax Factor shall be (1 - S) (1 - F) where S = the then current effec-tive Georgia corporate income tax rate including any surcharges applicable thereto and F - the - _ effective federal corporate income tax rate including any surcharges applicable.thereto. The cost of funds applicable to GPC's invest-ment in Transmission Facilities shall be the sum of the above determined percentage rates for (1) Long-Term Debt and Interim Indebted-ness, (2) Preferred Stock and (3) Common Equity divided by 100 and multiplied by GPC's net depreciated average annual investment in Transmission Facilities. I For the purpose of this Agreement, the Transmission Carry-ing Charge for shall mean the aggregate of the annual dollar costs incurred by with respect to its owner- ! ship, operation and maintenance of its Transmission Facili-l ties for the Contract Year divided by l 's aggregate undepreciated investment in j j Issued by Harold C. McKenzie, Jr. Executive Vice President ! l Issued on June 30, 1975 Effective July 1, 1975 I I l o . . _
'Georgio Pow r Comp ny FPC Elcctric Tcriff-Original Volume No. _, Original Sheet No. 10 Transmission Facilities during the Contract Year (including pro rata credits for facilities constructed ob retired. dur-ing the Contract Year). Such annual dollar costs shall be the aggregate of depreciation, ad valorem taxes, insurance and operation and maintenance expenses including adminis-trative and general expenses properly allocated thereto all as properly recordable in accordance with the Rural Electrification Administration's Uniform System of Accounts if the contracting party is subject thereto or, if not, the Federal Power Commission's Uniform System of Accounts, the cost of funds, and income taxes, if any.
; The cost of funds shall be the product of the ratio of
's cost of debt for the Contract Year divided by
's average outstanding debt during the Contract -
Year multiplied by 's net depreciated average annual investment in Transmission Facilities. 1.04 Integrated Transmission System. The Integrated Transmission System shall be the aggregate Transmission Facilities of GPC, and all other parties who have executed an " Integrated Transmission Sys-tem Agreement" with GPC, (" participants"), subject to the provisions of Section 5.09 hereof. Transmission Facili-ties of the parties in existence on the Effective Date hereof or hereafter coming into existence pursuant to 3 this Agreement shall be included in the Integrated Trans-mission System. 1.05 Joint Committee. The Joint Committee shall mean the committee established pursuant to the Joint Committee Agreement between the parties dated as of , 19__, Which agreement shall have been executed by the part-ies hereto in partial implementation of Paragraph 2 of the Proposed License Conditions attached to the settlement Agreement between the parties relating to Atomic Energy
, Cpmmission Docket Nos. 50-366A, 50-424A, 50-425A, 50-426A and 50-427A.
1.06 Effective Date. Effective Date shall mean
, 19__.
nsued by Harold C. McKenzie, Jr. _xecutive Vice President Issued on June 30, 1975 Effective July 1, 1975
' ~
;fFPC((ElGstriciTariff <
' Original Volume No.._ Originsi Shect No.11
- 1.07 -Peak Load ~. The Peak Load of,any party;sh'all mean J '
- the maximum one-hour integrated coincident / system. demand;of ki ,
(such party delivered from the_ Integrated Transmission System during~s' Contract-Year (including-for either party sales and 0 net interchange-out to any third party located inside or.out-
' side of ethe area described in Section 1.01 hereof; but-excluding for ,.
%- purchases from GPC,and third parties, which purchases are
- delivered by the: supplying party at delivery points for a-charge, which;such deliveries shall be included in'the sup-plying party's; load; and excluding:for either party,:all deliveries of capacity and' energy to the other which are not arrangements: based upon deliveries at delivery points)..
. ARTICLE II INTEGRATED TRANSMISSION SYSTEM 2.01. Purpose. 'The Integrated Transmission System shall provide the transmission service needs of GPC,-
and.other participants, within-the State of-Georgia other.than in Chatham, Effingham, Fannin', R Towns'and Union Counties. The Integrated Transmission'Sys-tem is established in order to obtain the benefits- of >a~ co- , Lordinated development of such Integrated Transmission Sys- ! tem and.to make-it. unnecessary for any participant'to con- ,
.struct duplicating" facilities. For such purposes each. party 3: shall coordinate _its planning for construction of additional
. Transmission Facilities.with other participants and'shall
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utilize.the Integrated. Transmission System so far as is prac-ticable to deliver in accordance with the provisions of this Agreement its power and energy requirements. 2.02 Transmission Facilities and Investments'. 'The Transmission Facilities and associated undepreciated dollar investment of'GPC and as of. the Effective Date shall be designated by written agree-ment by GPC and and shall be revised annually to represent the Transmission Facilities and associated undepreciated investment of each party as,of the beginning of each Contract Year.
. Issued by Harold C. McKenzie, Jr.
. Executive Vice President
. Issued on June 30, 1975 Effective July 1, 1975
U::rgAa;Fow;r Camp:ny FPC Elcctric Tcriff Original Valume N:s. _ Original Sh tt No.12 2.03 (i) Transmission Investment Responsibility. On and after the Effective Date the investment responsibility of each of the parties in Transmission Facilities shall be the ratio, rounded off to the nearest hundredth of a per-cent, of the projected Peak Load estimate of such party for the next succeeding Contract Year divided by the aggre-5 gate of such estimated Peak Loads of the participants mul-tiplied by'the estimated aggregate undepreciated dollar investment of the participants in Transmission Facilities, during the applicable Contract Year (including pro rata credit for facilities becoming used or useable or retired during~the Contract Year). J (ii) Prior to the beginning of each Contract Year, the Joint Committee shall determine a four-year plan.of additions in Transmission Facilities. Such plan shall re-sult from studies of the Integrated Transmission System e considering requirements for adequately supplying the total present and anticipated future transmission requirements to serve the loads of the participants and to maintain the integrity of the Integrated Transmission System. Respons-ibility for construction of the specific facilities in the four-year plan shall be assigned to a participant together ! with an in-service date for such facility. In assigning responsibility for construction of specific Transmission Facilities the Joint Committee will consider each partici-pant's responsibility for ownership of Transmission Facil-ities.so as to achieve or maintain an appropriate Trans-i mission Facilities investment ratio as contemplated in clause (i) of this Section 2.03. Each party shall con-struct the facilities so determined to be constructed by such party in order to meet the in-service date for the facility. Upon completion of the facility it shall be-come a part of the Integrated Transmission System. In the event either party builds transmission facil-ities which are (1) proposed by such party as Transmission Facilities hereunder, (2) appropriate to the purpose of adequately supplying the present and anticipated future loads of one of the parties and (3) conform with good engi-neering practices, then such transmission facilities shall be Transmission Facilities of such party. Neither party shall be assigned responsibility for the construction of Issued by Harold C. McKenzie, Jr. Executive Vice President Issued on June 30, 1975 Effective July 1, 1975
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(GMrghPowerCompcny-TFPC E1:ctric Tariff.
' Original Volume No. _ Original Sheet ' No. ; 13 L
p" Transmission Facilities- which cannot in anyL way be used to
. supply _or make more r'eliable' service to such party.. -
(iii);JAs soonias possible after the termination 'of each Contract Year, the' Joint-Committee shall review ths total bg undepreciated dollar investment in Transmission Facilities
'L ,' ' of each party during the previous Contract Year (including-pro rata: credit for facilities.becoming-used'or useable, or retired, during.the-Contract Year) and the actual; Peak Load of each participant during such Contract Year. In the
^ event that, based upon such review, a party had a-greater undepreciated dollar investment in Transmission Facilities u than was required pursu'nt a to the ratio provided for in clause
~(i);offthis Section 2.03 (after substituting the actual Peak Loads and-investments of the participants for the
. estimated Peak Loads and investments of the participants),
h the other; party shall forthwith pay to such party an~ amount of Leash equal to such party's excess undepreciated dollar investment in Transmission Facilities multiplied by the 7" higher of.GPC's'or 's Transmission Carrying Charge for.the Contract Year but will y receive no interest'in such other party's investment. _2.04L Operation and Maintenance. GPC and' shall each be exclusively re-sponsible'for the operation and maintenance of.its. respective ( . Transmission Facilities. Unless occasioned by the negligent act of the'other' party, the cost of maintenance, including.
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the. replacement of equipment and facilities, shall be borne by the party providing such equipment and facilities.
'2.05 Construction of Transmission Facilities. The
. Transmission Facilities hereafter. constructed by GPC and which are to become a part of the Integrated Transmission System shall be designed and constructed in accordance with good engineering practices.
2.06 Initial Payment. GPC has developed an extensive
= transmission system and; has established expertise and exper-
.ience in the design, construction, operation and maintenance {
of^a transmission system, which expertise and experience was { used in the construction of such system and which is and will j
'be available to and inures to the benefit of a under the terms and conditions Issued by Harold C. McKenzie, Jr.
Executive Vice President
. Issued on. June.30, 1975 Effective July 1, 1975
p n ' H G;;rgio Power Company b : FPC Elbatric Tariff
- Original-VolumeNo. _ Original' Sheet No. 14 q
of this Agreement., In recognition of the foregoing, will pay $ L to.GPC upon the execution of this Agreement. { l l ARTICLE III q OPERATION 3.01 Use. The. parties shall utilize so far as proctic-able the Integrated Transmission System to transmit capacity S and energy supplied from their generating plants and to transmit capacity and energy purchased from other electric suppliers under contract therefor, for the separate distribu- J tion and sale of such capacity and energy by the parties, respectively, each for its own account. After the Effective Date, each. party shall have the right so to use the Integrated Transmission System without charge, provided, however, that the parties' use of such: system shall not be in violation of the provisions 1of Paragraph 5 of-the Proposed License l Conditions attached to the Settlement Agreement between the parties . relating to Atomic Energy Commission Docket Nos. 50-366A, 50-424A, 50-425A, 50-426A and 50-427A.. ARTICLE IV r. FETERING 4.01 Metering. The transfer of capacity and energy into and out of the Integrated Transmission System shall be determined by. meter registrations or other methods as the Joint Committee shall deem to be necessary. The Joint Com-mittee shall determine which party shall furnish metering equipment and the types of metering equipment to be employed. 4.02 Meter Readings. The parties shall cause meters to be read monthly at times agreed upon. Metering records shall be available at all times to authorized agents and employees of the parties for the purposes of this Agreement. 4.03 Meter Tests. Each meter used hereunder shall, by comparison with accurate standards, be tested and calibrated 4 Issued by Harold C. McKenzie, Jr. - Executive Vice President ' Issued on June 30, 1975 Effective July 1, 1975
- FPC Elcetric Tariff '
Original Volume No. _ Originn1 Sheat No. 15 by the party owning the meter at approximate intervaln of 12 months. If a meter shall be found not registering with-D in.1% accuracy, it shall be restored to an accurate condi-tion or an accurate meter shall be substituted. 4.04 Meter Accuracy. The parties shall have the right to request that a special test of metering equipment > be made at any time. If any test, made at a party's re-quest, discloses that the metering equipment tested is registering within 1% accuracy, the party requesting the test shall bear the expense thereof. The expense of all other such tests shall ine borne by the party owning the meter. 4.05 Meter Adjustments. The results of all tests and calibrations shall be open to examination by the part-ies and a report of every test shall be furnished immediately to the other party. Any meter tested and found to be within 1% accuracy shall be considered to be accurate. If, as a ; result of any test, any meter is found to register not with- ' in 1% accuracy, the readings of such meter previously taken shall be corrected according to the percentage of inaccuracy so found, but no such correction shall extend beyond 60 days previous to the day on which inaccuracy was discovered by
. such test. If any metering equipment fails to register or if the meter registration is erratic, the capacity and energy delivered shall be determined by the. parties. ;
D ARTICLE V ) GENERAL 1 5.01 continuity of Service. The delivery of electric energy hereunder shall be continuous, except for the follow-ing: ) (1) Interruptions or reductions due to uncontrol-lable forces which, by exercise of due diligence and fore- i sight, could not reasonably have been avoided. The term '
" uncontrollable forces" shall be deemed to mean any cause beyond the control of the party affected, inclurling, but not limited to, failure of facilities, flood, earthquake, storm, Issued by Harold C. McKenzie, Jr.
Executive Vice President Issued on June 30, 1975 Effective July 1, 1975 n___.___s___w_. .--.-- ._ - --
Georgin Pow;r Comp:ny l FPC Elcctric Tcriff Original Volume No. _ Original Sheet No. 16 b fire, lightning, epidemic, war, riot, civil disturbance, labor disturbance, sabotage, and restraint by court or p _ _ _ _ __ .public authority. The party rendered unable to fulfill any obligation by reason of uncontrollable forces shall exercise due diligence to remove such inability with all reasonable dispatch. (ii) Interruptions or reductions due to operation of devices installed for power system protection. (iii) Temporary interruptions or reductions which are necessary or desirable for the purposes of maintenance, F repairs, replacements, installation of equipment, or invest-igation and inspection. Each party will give the other party reasonable advance notice of such interruptions or reductions, except in case of emergency as determined by the party creating the interruption or reduction, and will remove the cause thereof with all reasonable dispatch. 5.02 Power and Energy Losses. KW losses on the Inte-grated Transmission System shall be shared by the parties in proportion to their respective Peak Loads. KWH losses on the Integrated Transmission System shall be shared by the parties in proportion to their respective energy re-quirements associated with such Peak Loads. 5.03 Power Factor. Each party will ma'intain its power factor at not less than 0.93. 5.04 Liability. Each party is responsible for its own facilities and personnel used in the performance of this Agreement and neither party shall be responsible to the other for damage to or loss of property, wherever located, unless such damage or loss is occasioned by its own negligence or by the negligence of its employees or agents. 5.05 Waivers. A waiver by either party of the other party's defaults shall not be deemed a waiver of any other or subsequent defaults. 5.06 Richt of Access. Each of the parties will give authorized agents and employees of the other party the right to enter upon its Transmission Facilities at all reasonable Issued by Harold C. McKenzie, Jr. Executive VIce President Issued on June 30, 1975 Effective July 1, 1975
t~ v=usq3m ruw=u. t.,ompany FPC ElCctric Tcriff
! Original V31ume N3. ,,,, , Original Sheet No.17 Ltimes for'the' purpose of reading or checking meters, for , constructing, testing, repairing, renewing, exchanging or removing;any or all of -its equipment which may be located on the property of the other party.or performing any work incident to rendering service under this Agreement; pro-vided, however, that each party shall have the right to designate certain parts of its premises where entry of employees or agents of the other party is prohibited unless such employees or agents are accompanied by an authorized employee or agent of the party owning such premises.
5.07 Notices. Any notices, demands, or requests a required or authorized by this Agreement to be delivered by one party to the.other shall be deemed properly delivered if delivered to the party to receive such notice, demand or request through the Joint Committee; provided, however, that in the event the Joint Committee has ceased to function for any . reason, delivery shall be made upon the chief execu-tive officers of the respective parties. 5.08 Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties, their successors and assigns. 5.09 Interpretation. This Agreement shall not be int 6rpreted to limit the right of either party hereafter to design, construct, acquire, or own any facilities it deems desirable. 5.10 Limitations. This Agreement is not intended to and shall not create rights of any character. whatsoever in
-favor of any person, corporation, association, or entity other than the parties to this Agreement, and the obligations herein assumed are solely for the use and benefit of the par-ties. to this Agreement.
5.11 Te'm r of Agreement. This Agreement shall remain in effect througn Decemoer 31, 2012 and if not then termin-ated by five (5) years prior wricten notice given by either 1 party to the other, shall continue in full force and effect l
.until so terminated. In the event of the dissolution, '
liquidation or bankruptcy of either party, this Agreement Issued by Harold C. McKenzie, Jr. Executive Vice President l Issued on June 30, 1975 Effective Date July 1, 1975 . 1 (
v6 As tua t : v u Aume av . _ Original Sh30t No.1B 4 i shall terminate unless the other party eleers to continue the Agreement with the successor in. interest thereof. 5.12 Joint Committee. This Agreement, and the rights and obligations of the parties hereunder, shall be admin-istered and implemented through the Joint Committee. Any determination provided in this Agreement to be made by the ! parties, or any agreement to be reached by the parties, i ~ shall be made or reached through the Joint Committee. The actions and authority of the Joint Committee shall be sub-ject to f the rights and obligations of the parties to this Agreement.. Notwithstanding the foregoing provisions of this section 5.12, it is the clear, controlling and over- I riding intent of this Agreement and of the parties entering into this Agreement that this-Agreement shall survive any functional demise or failure to function of and by the Joint Committee and,.in such event, the responsibilities, duties and obligations designated to be performed by the Joint Committee pursuant to this Agreement shall be per-formed by GPC and - in accordance with good engineering practices. 5.13 No Delay. No disagreement or dispute of any kind between GPC and i* concerning any matter, including without limitation,.the arount ot any payment due trom either party to .the other or the correctness of any charge or credit made to GPC or
, shall permit GPC or to delay or withhold any payment or the performance of any other obligation pursuant to this b Agreement.
5.14 No Partnership. Notwithstanding any provision of L this Agreement GPC and do not intend to create hercey any joint venture, partnership, association taxable as a corporation, or other entity for the i conduct of any busivass for profit, and contemplate seeking a ruling of the Internal Revenue Service that this Agreement has no such effect. GPC and agree to timely take all voluntary action as may be necessary ". to be excluded from treatment as a partnership under the Internal Revenue Code of 1954, as amended, and, if it should appear that one or more changes to this Agreement would be Issued by Harold C. McKenzie, Jr. Executive Vice President } Issued on June 30, 1975 Effective July 1, 1975 I J I- ! l I 1
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V . .. . I. Original Volume NO. _ . Original Shest No. 19 required-in order to obtain.the ruling referred to above, GPC and ' agree to negotiate promptly in good faith with respect to such a changes. E 5.15 Time of Essence. Time is of the essence of this Agreement. N 5.16 Further Documents. From time to time hereafter [ the parties will execute such documents, upon request by the other, as may be necessary or appropriate to carry out
- the intent of this Agreement.
3 5.17 G_overning Law. The validity, interpretation, and performance of this Agreement and each of its provisions shall be governed by the laws ot the State of Georgia. 5.18 Amendments. This Agreement may be amended by and only by a written instrument duly executed by the parties J hereto. 5.19 Counterparts. This Agreement may be executed simultaneously in two or more counterparts, each of which shall be deemed an original out all of which together shall constitute one and the same instrunent. 5.20 Settlement Agreement. The parties have entered into a Settlement Agreement, including Proposed License Conditions, relating to Atomic Energy Commission Docket Nos. 50-366A, 50-424A, 50-425A, 50-426A and 50-427A. This Agreement is entered into by the parties in partial imple-mentation of and is to be construed within the boundaries of said Settlement Agreement, including proposed License Conditions,'and nothing contained herein shall be in viola-tion of said Settlement Agreement, including Proposed License Conditions. 5.21 Section- Headings Not to Affect Meanin_g. The descriptive headings of the various Sections of this Agree-ment'have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms and provisions thereof.
- Issued by Harold C. McKenzie, Jr. .
Executive Vice President
- Issued on June 30, 1975 Effective July 1, 1975
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Fl 'FPC flectric Tcriff '
- 0riginalivslume.Na. ,,, Original Shnet No. 20 5.22~ Regulatory Approval. This Agreement and the
. rights ;and . obligations of. the~ parties hereunder are subject 0 to;the prior: receipt by the parties of all requisite govern-
,. Emental andLregulatory, approvals.
'5.23'. Good Engineering Practices.- ThefJoint Committee, and .th'e parties, J shall be- required to plan jointly the Integrated Transmission System, as. outlined in Section 2.03
.(11), in.accordance with good engineering. practices..
'IN WITNESS WHEREOF, the _ parties have caused this -
L Agreement to be duly- executed and attested by their duly authorized otficers.as of.the day'and year first above Lwritten. l 1. I In the prbsence:of: f BY: ATTEST:- (CORPORATE SEAL) In the presence of: GEORGIA POWER COMPANY B.Y: ATTEST: (CORPORATE SEAL)
; Issued by Harold C. McKenzie, Jr.
Executive'Vice President
. Issued on June 30, 1975 Effective July 1,'1975
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r ., __ . _ _ _- ._ .... _ -- --- . . - _ - _.. - _ - _ - . _ _ - . _ _ - - - - __- -.. _ 3:!;. ; d h' I ...E
. 1; JINTEGRATED TRANSMISSION' SYSTEM AGREEMENT s.
between-l6 .' ll l OGLETHORPE. ELECTRIC MEMBERSHIP CORPORATION and GEORGIA POWER COMPANY l 1
- Dated as of January 6, 1975
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o THIS AGREEMENT, dated as of January 6, 1975, is h between OGLETHORPE ELECTRIC MEMBERSHIP CORPORATION, an electric membership corporation organized and operating underTitle34BoftheGeorgiaCodeAnnotated("0EMC")Yand GEORGIA POWER COMPANY, a corporation organized and existing under the laws of the State of Georgia ("GPC").
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WITNESSETH: A. GPC is engaged in the business of generating, transmitting and distributing electric power and energy in the State of Georgia and OEMC is a corporate cooperative of electric membership corporations and is empowered to engage-in the business of generating, transmitting and distributing electric power and energy to its thirty-nine member electric membership corporations in the State of Georgia, such member electric membership corporations being listed on Exhibit A attached hereto and made a part hereof. OEMC is the sole and exclusive power supplier for each such member electric membership corporation's Georgia operations.
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B. GPC and OEMC have entered into an Agreement ' providing for the co-ownership of the Edwin I. Hatch Nuclear Generating Plant and plan to enter into such agreements for certain other electric generating units. ! l 1 l j l l l l
r C. It is the parties' general' desire that the IntegratedLTransmission System of GPC and OEMC will be used to' provide the transmission requirements of GPC and OEMC, D. GPC.and OEMC desire to develop and utilize such Integrated Transmission System to supply electric. power I
'and energy to each other within the State.of Georgia.
E. Additions to the Integrated Transmission System as required will be made separately by GPC and OEMC with the intent that each party will ultimately own separate
' facilities proportionate in the aggregate to its use of such' ,
system. NOW, THEREFORE, in consideration of the premises and the mutual agreements herein set forth, GPC and OEMC' hereby agree as follows: ARTICLE I DEFINITIONS
. 1.01 Transmission Facilities. Transmission Facilities shall be all facilities (including land)' owned by a party, in existence on the Effective Date (as hereinafter defined),'or hereafter coming to be so owned pursu' ant to Section 2.03(11) of this Agreement, within the State of Georgia, other than in Chatham, Effingham, Fannin, Towns and Union Counties, used or useable to transmit power the operat-ing voltage of which is 40kV or more and to transform power 4
f
L the high-voltage side of which is 40kV or more and the capacity of which is 500kVA or more, excluding step-up p substations at generating plants. 1.02 Contract Year. The Contract Year shall begin on January 1 of each year, and end on December 31 of i each year; provided, however, that the first Contract Year shall begin on the Effective Date and end on the following December 31. 1.03 Transmission Carrying Charges. For the purpose of this Agreement, the Transmission Carrying Charge for GPC shall mean the aggregate of the annual dollar costs incurred-by GPC with respect to its ownership, operation and maintenance of its Transmission Facilities divided by GPC's aggregate undepreciated dollar inve~stment in such facilities during the Contract Year (including pro rata credit for facilities becoming used or useable, or retired, during the Contract Year). Such annual dollar costs shall be the
- aggregate of depreciation, ad valorem taxes, insurance, operation and maintenance expenses including administrative and general expenses properly allocated thereto, all as properly recordable in accordance with the Federal Power Commission's Uniform System of Accounts, and the cost of funds, including income taxes. The cost of funds, including s income taxes, shall be calculated as follows:
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= -
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'The capital structure of GPC as shown on GPC's most recent 10-Q Report shall.be calculated and broken down e '-
6 inte three decimal components the sum of which totals , one (1.00):- (1) Long Term Debt and InterimLIndebted-ness, (2) Preferred Stock and (3) Common Equity. The y ~ cost.of the Long Term Debt and Interim Indebtedness,
-respectively, shall be.the then current weighted ~ average percent cost of all First Mortgage Bonds and Interim
- v. Indebtedness, respectively,. times the Long. Term Debt and Interim Indebtedness component of the capital structure determined above. The cost of Preferred 2 Stock shall befthe then' current weighted average per-cent dividend rate of such stock times the' Preferred
' Stock component of the' capital structure: detennined above divided by the then current Tax Factor. The cost of Common. Equity shall be the most recent percent return allowed on equity by the Federal Power Commission
' t. : for sales to GPC's wholesale customers or such percent return submitted in.a rate settlement with its whole-sale customers (whichever is most recent) times the Common Equity component of the capital structure deter-mined above divided by the then current Tax Factor. The Tax Factor shall be (1 - S) (1 - F.) where S = the then current' effective Georgia corporate income tax 4 4 __-..l_.-..... - . _ . - _
. . ~ . . ~ - - . , - . . - _ . . . . . _ - , -----o ..r.-
$ .oc , m ' k , rateTincluding any. surcharges applicable thereto and. n'~ lF:- the effective.federalLeorporate: income. tax rate-
, incibdinganysurchargesapplicablethereto. Initially j - the Tax Factor = _ (le- .06) (1 - i48) which equates _to.
p 0.4888.. The. cost of funds applicable.to.GPC's' invest-ment in Transmission Facilities shall be ~ the sum of the'
.above determined percentages rates for (1) Long Term g fDebt and Interim Indebtedness,-(2) Preferred Stock and (3)L Common Equity : divided by 100. and multiplied by GPC's net-depreciated average annual. investment.in Transmission Facilities.
For the purposes ofithis Agreement, the1 Transmission Carrying-Charge-for 0EMC shall mean the aggregate of the annual j dollar:' costs. incurred by OEMC with respect to its-ownership,. operation.and maintenance of its Transmission Facilities'for the Contract Year divided by-0EMC's aggregate undepreciated g investment in Transmission Facilities during the Contract-Year (including profrata credits for facilities constructed orLretired.during the Contract Year). Such annual dollar
' costs shall be the aggregate of depreciation, ad valorem taxes, insurance and operation and mainten. ace expenses including administrative and general expenses properly
' allocated thereto all as properly recordable in accordance~ ,
with' the Rural 'Elc.:trification Administration's Uniform a 7 e f ,..l A ~ :. ~ - -....J.. 2.n. ,n, ;_ . .__ a .ma e , ,
- n. .
's
- -System 'of Accounts, . the cost of funds, and income taxes, lLE any.
The cost of funds shall be the product of'the ratio of OEMC'a. cost of debt for the Contract' Year divided by.0EMC's (average outstanding debt during the Contract Year multiplied by OEMC's net depreciated average annual investmentiin - h Transmission Facilities. 1.04
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Integrated Transm'ission System. The Integrated. Transmission System'shall be the aggregate y Transmission Facilities of GPC and CEMC, subject to che
. provisions of Section 5.09 hereof.
Transmission Facilities of the parties in existence on the Effective Date hereof or hereafter. coming into existence pursuant to this Agreement , shall be. included in the Integrated Transmission System. 1.05 Joint Committee. The Joint Committee shall
. mean the cannittee established pursuant to the Joint Com-mittee Agreement between the parties dated as of August 1, 1974.
1.06- Effective Date. Effective Date shall mean L the date of the Closing of the purchase by OEMC of a 307. un-divided interest in the Edwin I. Hatch Nuclear Plant pursuant to the Purchase and Ownership Participation Agreement between the parties dated as of January 6,1975. 1.07 Peak Load. The Peak Load of any party shall- [ mean the maximum one hour integrated coincident system [ __1 -_ ' - - ~
m - ,- - - _ n- , 6 m
' demand of[cuchL party dalivarod from the Integrated T;ans- -
- mission; System during a Contract Year (in l d c u ing.for either:
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y . party' sales and netLinterchange-out. to any thir 11ocated inside or outside of
._ a.'1'01 hereof; but excluding for OEMCthe-area des
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e p . third parties, which purchas's e are delive, purchases fr red by CPC at delivery points for:a charge, which such deli veries shall'be-included in GPC's-load',and ; excludingsfor p either party,'all deliveries .of capacity and energy: to th'e . other which are not arrangements. based upon deliveries atpoints). delivery ARTICI.E II p , INTEGRATED TRANSMISSION. SYSTEM-2.01^ Purpose... The' Integrated Transmission System shall provide the transmission service needs 'L of GPC and OEMC,zwithin the State of Georgia other th - an in Chatham, Effingham,- Fannin, Towns and Union s. Countie . The Integrated-Transmission System is established in orde r!to'obtain the benefits of a coordinated development of such I ntegrated Transmission System and to make it unnecess ary for either' party to' construct duplicating facilities For such pur-poses each party,shall coordinate its planning or con-f struction of additional Transmissions with Facilitie the other party and shall utilize the Integrated Tran smission System so far as is practicable -to deliver i
*. n accordance t
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.~ vith the ' provisions of this Agreement its powernergy and. e requirements. v ,. 2.02 Transmission Facilities and Investments . The Transmission Facilities and associated undepreci ated dollar-investment of GPC and OEMC eas Date of the E shall be designated by written agreement by GPC and and O shall be revised annually to represent-the Transmission Facilities and associated undepreciated investment of each party as of the beginning of each Contract Year. 2.03 (i)
. Transmission Investment Responsibility.
On and after the Effective Date the investment onsi- resp bili,ty~of each of the parties in Transmission Faciliti es shall be the' ratio, rounded off to the nearest hundredth of a percent, of the projected Peak Load estimate of such party for the next succeeding Contract Year divided by the aggregate of such estimated Peak Loads of the parties multiplied the estimated aggregate undepreciated dollar invest ment of g the parties in Transmission Facilities , during the applicable Contract Year (including pro rata credit for facilities becoming used or useable or retired during the Contract Year). (ii) Year, Prior to the beginning of each Contract the Joint Committee shall determine a four year plan of additions in Transmission Facilities.Such plan shall i-9
- . . - . . __ - .n _. --___.- _ - - . . . - - _ . . - n n_.- -- c-,-- -_2_u-_x_.-.a.-.:_.m
s
, , q result"from studies' of L the Integrated Transmission n System y
p
- considering requirements ' for. adequately ' supplying -
otal: the p ' present ' and' anticipated future transmission requireme q
)
> serve,the 1 loads of: the parties- and to maintain' the w
of the Integrated Transmission System. ' Responsibili qb . j construction of ~ the specific . facilities in the' four year plan shall be assigned to a party together with an in- ! y service date for such< facility. In assigning responsibili . ty
?for-construction of specific Transmission Facilitie 1
s:the-cJoint Conunittee will consider each party's responsibility y for. ownership of Transmission ~ Facilities so as ~ to
' achieve or maintain an: appropriate Transmission Facilitiesent- investm ratio as' contemplatediin clause (i) of this Section 2 03 . .
y Each party shall construct the facilities so determi ned to be constructed by such party in order to meet the in
'date for the facility. -service Upon completion of the-facility it shall become ai part of the. Integrated Transmission System.
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In the event either party. builds transmission '
' facilities which are (1)' proposed by such party .
Facilities hereunder, as Transmission (2) appropriate to the purpose of adequatel; supplying the present.and anticipated future loads of one .of the parties and (3) confonn with good - engineering practices, then such transmis'sion facilities
- shall be Transmission Facilities of such party. .Neither
-9_
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4. ur U o.& W pdrtychallbs'no$ignad~responsibilityforth - e construction-of1 Transmission Facilities which cannot'in any
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1 to: supply or. make more reliable' servi ce;to such party.: (iii)- 1,a10w _:m ,:;- of each Contact . Year, the Joint CAs on - soo total undepreciated dollar investment iommittee:shall ties:of each party during the previous Cn Transmission F . pro rata credit fc>r facilities becoming us'edontract ' Yea or useable,.or; rctired,'during-the Contract. Year) and the of'each-party during.such Contract Year actual Peak Load ~ / based upon such review, a party had a greatIn the even . er undepreciated dollar investment in Transmission es than Faciliti was required pursuantito the ratio provided :for clause (1) .
'2.03'(after substituting the actual Peak .of L this Section ments1 oads and' invest-of the parties for-the estimated Peak' Loads and invest-
-ments-of the parties), the other party shallw forth th pay 1 i
to_such party an amount of cash equal-to such party' s excess undepreciated' dollar investment in Transmissi on Facilities multiplied by the higher of GPC's or OEMC's Tra nsmission Carrying.. Charge for the Contract Year but will receive no interest in such other party's investme n. t 2.04 Operation and Maintenance. GPC and OEMC shall each be exclusively responsible for the o peration and 1 maintenance of its respective Transmission c ties. Fa ili l( i 4 F
. - - - . - - - ~ - - - - _ _ - _ . . _ _ . . . _ - - . _ _ . _ . -_-_1.-.AA- .A r A\._------m___--___a-_--_. - - - _ . _ .
t Unless' occasioned by the negligent act of the other party, p the cost _of maintenance, including the replacement of. equipment and. facilities, shall be borne by the party L providing such equipment and facilities. N 2.05 Construction of Transmission Facilities. The Transmission Facilities hereafter constructed 57 GPC and OEMC which are to become a part of the Incegrated Trans-h mission System shall be designed and constructed in ac-cordance with good engineering practices. 2.06 Initial Payment. GPC has developed an extensive. transmission system which presently serves OEMC's members at more than 400 delivery points throughout its service territory and has established expertise and ex-perience in the design, construction, operation and main-
. tenance of a transmission system, which expertise and j experience was used in the construction of such system and which is and will be available to and inures to the benefit i of OEMC under the terms and conditions of this Agreement.
In recognition of the foregoing, OEMC will pay $1,000,000.00
' to GPC at the Closing of OEMC's purchase of a 30% ownership >
interest in the Edwin I. Hatch Nuclear Generating Plant 1 contemplated in Section 5.26 hereof. I 1 4
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4
' ARTICLE III n
OPERATION p 3.01 'Use. The parties shall utilize so'.far.as p practicable the. Integrated Transmission System'to transmit-capacity-and.energyLsupplied from their generating plants 7 and to transmit capacity andl energy purchased from other electric suppliers under contract therefor, for the-separate distribution and sala of such capacity and energy by the
. parties, respectively, each for its own account. After the F
2 Effective Date, each party shall have the right so to.use the Integrated Transmission System without charge, provided,
'however, that.the parties'"use of such system shall not be in violation of the provisions of Paragraph'5 of'the Proposed License Conditions attached to the Settlement Agreement between;the parties relating to Atomic Energy Commission' .
Docket Nos. 50-366A, 50-424A, 50-425A, 50-426A and 50-427A. ARTICLE IV METERING 4.01 Metering. The transfer of capacity and
- energy into and out of the Integrated Transmission System shall be determined by meter registrations or other methods as the Joint Committee shall deem-to be necessary. The Joint Committee shall d te ermine which party shall furnish n_ dL s -t - ' , , _ _ _ .
p mstering Jequipm:nt cnd th3 typos of matering employed. u pment eq to,be i 4.02 Meter Readings. y .The parties shall"cause meters to be read monthly at times agreed upon
. Metering records shall be available at all times r zedto autho i agents h and employees of the parties for the purposes of thi s Agreement.-
4.03 . Meter Tests. Each meter used hereunder shall, by comparison with accurate standards
, be tested and calibrated by the party owning.the meter atmate approxi k
intervals of 12 months. If a meter shall be found not registering within 1% accuracy, it shall be resto red to an accurate condition or an cecurate meter ( . 0.4 shall be substituted. Meter Accuracy. The parties shall have the right to request that a special test of metering equipment be made at any time. If any test, made at a party's re-quest, discloses that the metering equipment tested s i registering within 1% accuracy, the party requesting e th } test shall bear the expense thereof . The expense of all other such. tests shall be borne by the party wningo the meter. 4.05 Meter Adj us tments. The results o.f all tests and calibrations shall be open to examination by the parties and a. report of every test shall be furnished aimmedi t c;.< the other party. ely to-
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Any meter tested and found to be within 1% { 4 {
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. i
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, - - - - - = = "
~
accuracy shall be considered.to be accurate. If, as a result of any-test,.any meterois found to register not j i
-within 1% accuracy, the readings ofisuch meter previously.
taken shal1~be corrected according to the percentage of inaccuracy so found, but no such correction shall extend
.beyond 60 days previous to the day on which inaccuracy was discovered int such test.. If any metering equipment fails to register or.if the deter registration is erratic, the capa-
); city and energy delivered shall be determined by the parties. ARTICLE V GENERAL
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- 5.01' continuity of Service. The delivery of l
electric energy hereunder shall be continuous, except for the following:
- - (i) Interruptions or reductions due to uncon-trollable forces which, by exercise of due diligence and -
foresight, could not reasonably have been avoided. The term
" uncontrollable forces" shall be deemed-to mean any cause beyond the control of the party affected, including, but not limited to, failure of facilities, flood, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance, labor disturbance, sabotage, and restraint by court or
- public authority. The party rendered unable to fulfill any 1
_____,___x, - - - - - 1w- - - - - ^ ~
l i obligation by reason of uncontrollable forces shall exerciae j due diligence to remove such inability with all reasonable f; , dispatch. i
-(ii)
Interruptions or reductions due to operation i of devices installed for power system protection. L - (iii) Temporary interruptions or reductions which are necessary or desirable for the purposes oc maintenance, S repairs, replacements, insta11acion of equipment, or investi-gation and inspection. Each party will give the other party reasonable advance notice of such interruptions or reductions, except in case of emergency as determined by the party creating the interruption or reduction, and will remove the cause thereof with all reasenable dispatch. 5.02 Power and Energy Losses. KW losses on the Integrated Transmission System shall be shared by the parties in proportion to their respective Peak Loads. KWH losses on the Integrated Transmission System shall be shared by the parties in proportion to their respective energy require-ments associated with such Peak Loads. 5.03 Power Factor. Each party will maintain its power factor at not less than 0.93. 5.04 Liability. Each party is responsible for - its own facilities and personnel used in the performance of this Agreement and neither party shall be responsible to the
.. - - . , _ - _ . ~ . . - , .
h f iD.; 6 d C, i y
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+
; 3 other for damage to or loss of property, wherever located; unless such damage'.or loss is occasioned by its own neglige g
or by the negligence of its employees or agents. 5.05 Waivers. A waiver by, either party of the p other: party's -default's shall not be- deemed a waiver of any other or subsequent defaults. 5.06 Righc of Access. Each of ne parties will give authorized agents and employees of'the other party the y right to enter upon its Transmission Facilities at all a reasonable' times for the purpose of reading or. checking ' meters, for-constructing, testing, repairing, renewing, exchanging'or removing any or all of its equipment which may be located on.the property of the other party or per-forming any work incident to' rendering service'under this Agreement; provided, however., that each party shall have the right.to designate certain parts of its. premises where entry ' of employees or agents of the other party is-prohibited unless such employees or agents are acco:apanied by an authorized employee or agent of the party owning such premises.. 5.07 Notices. Any notices, demands, or requests required or authorized by this Agreement to be delivered by cne party to the other shall be deemed properly delivered if-y
. delivered to the party to receive such notice, demand;or 16-i
___ _m._--- - ^ " - - - ~ - ' - _ _ _ _ - - - - -
p request.through the Joint Committee:
'in the event the Joint Committee has' ceased?provid y any reason, delivery shall.be mada upon the to function'for.
officers of the respective . parties, chief executive-5.08~ Successors and Assigns. This Agreement A shall be binding upon ard inure to the benefi t of the parties, their successors and assigns. 5.09 InteroretatioJt . This Agreement shall not o' e ) '
. interpreted to limit the right of either party h
. design, construct, ereafter to desirable. acquire, or own any facilities it deems
- 5.10 Limitations.
This Agreement.is not intended to and shall not create rights of any character in-favor of any person, corporation whatsoever k other than the parties to this Agreementassociation, or entit , herein assumed are solely for the use and band the obliga prarties to this Agreement. enefit of the 3 5.11 Term of Agreement. This Agreement shall remain in effect through December 31
, 2012'and if not then terminated by five years prior writte n notice given by 1 either party-to the other, shall continueu in f ll force and effect until so terminated.
In the event of the dissolution liquidation or bankruptcy of either party , this Agreement shall-terminate unless the other party elects t o continue the Agreement with the successor in int erest thereof. k 1 l _ aMa"---
- pg m.d4-- _ . - . .
_ _ _ _ . . - _ _ _ , _ _ ~ - - - - - - - - - - - ' - - - - -
t g 5.12 ; Joint Committee. This: Agreement, and'the rights-and obligations of the parties her~under,'shall e be k; D
' administered and implemented through'the~ Joint Committee..
Any~ determination providad in this. Agreement toLbe made by w the parties, or any agreement to-be reached by the parties, L shall be made or reached through the' Joint Committee. The 1ctions.and'auchority of the Joint Commiccea ahall be subj ect - to the rights and obligations of the parties. co this Agreement. Notwithstanding the foregoing. provisions of this
-SectionL5.12,-it is the clear, controlling and overriding
- intent of this Agreement and of the parties entering'intu this: Agreement that this Agreement shall survive any func-tional demise or failure to function of and by the Joint' Committee and, in such event, the responsibilities, duties and obligations designated to be performed by the Joint 7
Committee. pursuant to this Agreement shall be performed by
- p. GPC and OEMC in accordance'with good engineering practices.
5.13 No Delay. No disagreement _or dispute of' any kind between GPC and OEMC concerning any matter, including without limitation, the amount of any payment due from either party to the other or the correctness of any charge or credit made to GPC or OEMC, shall permit GPC or OEMC to delay or-withhold any payment or the performance of any othero$ligationpursuanttothisAgreement. 18- ' - S t w__-m._ m.L_a.....z-2-mm__.,_-a m .__^..m...._...-m.ma *m a . . . . ..ai .m a
b 5.14 No Partnership. Notwithstanding any pro-vision of this Agreement GPC and OEMC do not intend to I cre.a.te' hereby any- joint venture, partnership, assoc'iation taxable as a corporation, or other entity for the conduct of any business for profit, and contemplate seeking a ruling of the Internal Revenue Service that this Agreement has no such effect. GPC and OEMC agree to timely take all. voluntary action as may be necessary. to be excluded from treatment as "g-a partnership under the Internal Revenue Code of.1954, as amended, and,lLf it should appear that one or more changes to this Agreement would be required in order to obtain the ruling referred to above, GPC and OEMC agree to negotiate promptly in good faith with respect to such changes. 5.15 Time of Essence. Time is of the' essence of
- /
this Agreement.
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5.16 Further Documents. From time to time here-
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after the parties will execute such documents, upon request c by the other, as may be necessary or appropriate to carry out the intent of this Agreement. 5.17 Governing Law. The validity, interpre-tation, and performance of this Agreement and each of its provisions shall be governed by the laws of the State of Georgia. i w
9 5.18 Amendments. This Agreement may be amended by and only by a written instrument duly executed by the parties hereto. 5.19 Counterparts. This Agreement may be ex- < ecuted simultaneously in two or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument. 5.20 Settlement Agreement. The parties have entered into a Settlement Agreement, including Proposed License Conditions, relating to Atomic Energy Commission Docket,Nos. 50-366A, 50-424A, 50-425A, 50-426A and 50-427A. This Agreement is entered into by the parties in partial implementation of and is to be construed within the boun-daries of said Settlement Agreement, including proposed License Conditions, and nothing contained herein shall be in violation of said Settlement Agreement, including Proposed . License Conditions.
. 5 ~. 21 Section Headings Not to Affect Meaning. The descriptive headings of the various Sections of this Agree-ment have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms and provisions thereof.
5.22 Regulatory Approval. This Agreement and the rights and obligations of the parties hereunder are subject
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l . 1 ' L_ ._. . _ - - _ _
r m to .the prior receipt by the parties of all requisite govern-mental and regulatory approvals. t. 5.23' R.E.A. Approval. This Agreement shall.be of no force and effect until approved in writing by the Adminis-trator of.the Rural Electrification Administration. 5.24 Good Engineering Practices. The Joint Commictee, and the parties, shall be required to plan jointly the Integrated Transmission System, as outlined ih k~ Section 2.03(11), in accordance with good engineering practices. . 5.25 Othe.e Entities. Upon the written notice L from GPC to-0EMC,-this Agreement shall be amended so as to include as parties hereto other " entities" (as defined-in the Proposed License Conditions referred to in Section 5.20. hereof) with the same general rights, obligations and respon-sibilities as those of OEMC and GPC hereunder. , 5.26 Effectiveness of the Agreement. Neither party shall have rights and obligations under terms of this Agreement unless and until OEMC~ purchases a 30% ownership interest'in the Edwin I. Hatch Nuclear-Generating Plant pursuant to the Purchase and Ownership Participation Agree-ment dated as of January 6,.1975, between GPC and OEMC. J .. s 1
, . , . .,1- ,s_a. - r -2 s ~ -- ----c-=------- -- L *-:
- i. .
p.. IN WITNESS WHEREOF, the parties have caused this~ Agreement. to: be . duly executed and attested by their duly I; authorized officers as of the day and year first above I written. - OGLETHORPE ELECTRIC* MEMBERSHIP In the presence of: CORPORATION
.S/ 0. Franklin Rogers BY: S/ I.F. Murph, Pres .
t S/ James C. Brim, Jr. ATTEST: S/ Preston L. Johnson, Sec. (CORPORATE SEAL) l GEORGIA POWER COMPANY In the presence of: S/ Milton'A. Carlton,Jray: S/ Edwin I. Hatch, Pres. S/ H. G. Baker, Jr. ATTEST: S / I.S. Mitchell, III, Secy. (CORPORATE SEAL) I
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p a. E e n - w.. '4 EXHIBIT A . Altamaha Electric Membership' Corporation hc Amicalola Electric. Membership Corporation Canocchec Electric Membership. Corporation Carroll Electric Membership Corporation Central Georgia Electric Membership Corporation-
. Coastal Electric Membership' Corporation s
Cobb County Rural Electric Membership Corporation Colquitt. County Rural Electric Company
.Coweta-Fayette Electric Membership Corporation Douglas County Electric Membership Corporation Excelsior Electric Membership Corporation Flint Electric Membership Corporation
. e', e Grady County Electric Membership Corporation Habersham' Electric Membership Corporation llart County Electric Membership' Corporation Irwin County Electric Membership Corporation
" Jackson Electric Membership Corporation Jefferson County. Electric Membership Corporation Lamar Electric Membership Corporation
' .Little Ocmulgee Electric Membership Corporation
-Middle Georgia Electric Membership Corporation
-Mitchell Electric Membership Corporation Ocmulgee Electric Membership Corporation
,0conce Electric Membership Corporation Okefenoke Rural. Electric Membership Corporati'on-
'Pataula Electric. Membership Corporation Planters Electric Membership Corporation Rayle Electric Membership Corporation Satilla Rural Electric Membership Corporation Sawnce Electric Membership Corporation Fsh Pine Electric Membership Corporation 1.*.,p,inr, Shoals. Electric Membership Corporation Sumt.cr Electric Membership Corporation ThrcenNotch. Electric Membership Corporation ,
Tri-County Electric Membership Corporation Troup County Ele _ctric Membership Corporation Upson County Electric Membership Corporation Walton Electric Membership Corporation Washington County Electric Membership Corporation i l 1 y J t
+,, . . _ _ . . . _ b
UNITED STATES OR AMERICA L BEFORE THE FEDERAL POWER COMMISSION In the Matter of :
- : DOCKET NO.
GEORGIA POWER COMPANY : _ NOTICE OF FILING OF INITIAL TARIFF Take notice that Georgia Power Company, on June 30, 1975, tendered for filing an initial transmission service tariff, Georgia Power Company's FPC Electric Tariff, Original Volume No. _. dnder the tariff, for which the company requested a July 1, 1975 effective date, the customer s bulk power resources, as defined, may be transmitted within the State of Georgia (other than Chatham, Effingham, Fannin, Towns and Union Counties) pursuant to entry by the Company and the customer into arrangements for the ownership and use of an integrated transmission system, which arrangements provide _for parity of investment in said system among cugtomers and the Company and for payments by one party to the other in the event of disparity of investment. The Company states that only one customer, Oglathorpe Electric Membership Corporation, will initially take service under the new tariff. The Company and this customer have entered into an agreement pursuant.to the new tariff. Copies of the filing were served upon the Company's jurisdictional customers. Any person desiring to be heard or to protest said application should file a Petition to Intervene or Protest with the Federal Power Commission, 825 North Capitol Street, N. E., Washington, D. C. 20426, in accordance with Sections 1.8 and 1.10 of the Commission's Rules of Practice and Procedure (18 CFR 1.8, 1.10). All such petitions 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 Petition to Intervene. Copies of this application are on file with the Commission and are available for public inspection. ___-__,m _ .- .- ,. _
c., . 1
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GEORGIA POWER COMPANY ] Transmission Service Tariff
. ..e Address List (7/1/75)-
I'..F.-Murph, II A. J. Rowe, Jr. . President Van Scoyoc & Wiskup, Inc. Oglethorpe Electric Membership 1015 18th Street, N. W. Corporation Washington, D. C. 20036 Reynolds, Georgia o - F. F. " Bud" Stacy- Karl B.. Porter- ^ Oglethorpe Electric Membership R. W.' Beck & Associates 1510 East Colonial Drive
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Corporation 148 Cain Street, N.E. P. O. Box 6817 Atlanta, Georgia 30303 .Orlando, Florida 32803 g O. Franklin Rogers' John T. Miller, Jr., Esq.
; Southern Engineering Co. of Ga. 1001 Connecticut Avenue, N. W.-
11000 Crescent Avenue, N.E. Washington, D. C. 20036' Atlanta,. Georgia 30309 James C. Brim, Jr., Esq. V. D. Parrott, Jr. P. O. Box 304~ Secretary and General 'lanager
- Camilla, Georgia 31730 The Water, Light 6 Sinking Fund Commission William T. Crisp, Esq. P. O. Box.80-Thomas J. Bolch, Esq. Dalton, Georgia 30720 Crisp, Bolch, Smith & Clifton P. O.-Box 751 Raleigh, North Carolina 27602
.l L. Clifford Adams, Jr.
Heard, Leverett and Adams .) P. O. Box ~896 Elberton, Georgia 30635 j C. Emerson Duncan, II,.Esq. Donald R. Allen, Esq. 'l Duncan', Allen & Mitchell { 17 75 K" Street
' Washington, D. C. 20006
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-ATLANTA
- December 2, 1976
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- Mr. F. F. Stacy . .
- Oglethorpe Electric Membership Corporation 4
Mr. Karl B. Porter. R.,W. Beck'and' Associates:
~ Mr. V. D.-Parrott Water, I.ight and Sinking Fund Commission-p Dalton Utilities
. Gentlemen:
In.accordance with our recent conversations,-we will meet-on December!21 and 22,.1976 - in Room 1950,.270- Peachtree Street, at
~ 9 :00 - a.m. .. to' begin f ormulation of the . " Georgia Pool Interconnection Agreement". ,
/
k H..G. Baker, Jr. HGBJr/Imr- *
- Copies' to: -
Mr. H...C.'McKenzie, Jr. Mr. A. W.' Dahlberg, III Mr. E.'G. E111ngeon . Mr. R. A. Newton Mr. M. A. Carlton, Jr. Mr. J. E. Joiner t S
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[;[T." DEC 6'0~5
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. December 2, 1976 l
MR. H. C. McKENZIE , JR. i i NR. A. W. DAHLBERG, III MR. E. G. ELLINGSON. ' MR. R. A. NEWTON I have talked with Sud Stacy and Karl Porter regarding the decisions reached in our recent meeting to pursue the " Georgia Pool" contract negotiations rather than negotiate toward a PR-2 settlement. Both parties indicated that they agree enthusiastically with this approach and are willing to proceed expeditiously. Conversations concerning their calendars indicate December 21 and December.22, 1976 are available for negotiations to start. Accord-ingly, unless otherwise advised, I will make the necessary arrangements for a meeting with all parties on these dates. H. G. BhKER, JR. > HGBJr:Imr cc: Mr. M. A. Carlton, Jr. Mr. J. E. Joiner e e II RECEIVEC n; p .
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December 31, 1980
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Mr.'F.,F. Stacy: Oglethorpe-Power' Corporation
'2888 Woodcock Boulevard
- Atlanta, Georgia - 30341 e
Mr..D. .L. Stokley.
, Municipal Electric' Authority.of Georgia 800' South Tower -'Peachtree Center 225 Peachtree Street, N. E.
; Atlanta', Georgia: 30303 Mr. V. D.' Parrott
-Dalton' Utilities -
'P.;O. Box 869
- Dalton, Georgia' 30720
. ' Gentlemen:
l. You have'previously received copies of the PR-5' Settlement Agreement as filed. . Enclosed is a copy T the Settlement Agreement showing actual signatures for your files. g.
'Yours truly, A. W. Dahlberg AWD:vn Enclosure-e ;
l 1 l ___ _ _ _ _ _ _ _ _ . _ _ _ ____.n_______ _. , , mm m- - - - -
f: SETTLEMENT AGREEMENT-k THIS AGREDfENT is made and entered into by and among i - Georgia Power Company ("GPC"); Oglethorpe Power Corporation (An Electric Membership Generation & Transmission Corporation) [ ("0PC"); the' Municipal Electric Authority of Georgia ("MEAG") ;. and the City of Dalton, Georgia, acting by.and through its Board.of Water, Light &~ Sinking Fund Commissioners (" Dalton"). All of the foregoing except GPC are sometimes collectively-I referred to herein as " Interveners" or " Customers." This Settlement Agreement relates to those matters which are pend-ing before the Federal Energy Regulatory Commission ("FERC") in Docket No. ER80-328 ("PR-5"). Subject to agreement by all parties hereto to the pro-L. . visions set forth in this Settlement Agreement and with the agreement that each provision of the Settlement Agreement is in consideration and support of every other provision, the parties hereby agree as follows:
- 1. DISPOSITION OF PENDING RATE PROCEEDINGS 1.1 The, parties will advise the FERC forthwith
& that the parties-have settled the issuer with respect to FERC Docket No. ER80-328. The Interveners will file such pleadings and make such representations to the FERC and the FERC Staff as are request d by GPC to the end that FERC approval, accord- , , ,, , - ~ . . - , -- ... n . . , ,. -
7. f-
\
l,n -ing to,the' terms hereof, may be obtained as soon as possible. s
'Nothing contained herein shall be construed to prohibit any f party.from filing.any pleading in furtherance of its interests
'under this Settlement Agreement; and nothing' contained herein
~shall be construed to require'any party to take any-action not in its best interests in effectuating this Settlement p' Agreement.
1.2 GPC shallLfile with the FERC a revised tariff sheet revising the " Schedule of Monthly . Charges for Capacity" delivered pursuant.to Rate Schedule PR-5 to read ~as follows:
" SCHEDULE OF MONTHLY CHARGES FOR CAPACITY
" Type of Service Monthly Charge
" Unreserved base capacity $5.74 per KW
" Unreserved intermediate capacity $3.66 per KW
" Unreserved peaking capacity $3.87 per KW
" Reserve capacity $3.65 per KW"
- It is understood and acknowledged by the parties that GPC has utilized a 15.25% return on equity for the purpose of l developing'the settlement rates, and the parties agree, there-fore, that such rate of return shall be used in calculating all " buy-back" and " transmission parity" payments by one party
~
s to another under the several contracts between the parties which' , L.. refer to GPC's partial requirements return on equity., l.3 GPC shall file with the FERC revised PR-5 tariff sheet Nos. ll-A and 20 in the form attached hereto as exhibits . L 1 w - , _. . . ,_ , ~ . . . . _ _ - _.- ns_. - e .. .
. . a =_
l.4 It is understood, acknowledged and agreed by the parties that the revised tariff sheets' described in Sec-tions 1.2 and 1.3 of this Settlement Agreement shall be
-effective from November 1*, 1980, until changed pursuant to the Federal Power Act.
1.5 It is understood, acknowledged and agreed that all provisions of the PR-5 tariff except those de-I# scribed in Sections 1.2 and 1.3 of' this Settlement Agreement shall be effective as filed from November 1, 1980, until changed pursuant to the Federal Power Act. 1.6 Hothing. contained in this Settlement Agree-ment shall be deemed to preclude GPC from filing with the FERC a notice of an increase in rates pursuant to Section 205 of the Federal Power Act, however, no such increase shall be effective for service rendered prior to January 1, p1 1982. i V l l 1.7 In-further explanation of th+. rate increase moratorium referred to in Section 1.6 of this Settlement Agreement, it is understood, acknowledged and agreed that f if GPC files increased partial requirements rates on June 1, j 1981, the parties intend for those rates to become effective l d t l on January 1,-1982. The parties specifically agree as fol-(7 $, e lows: (a) GPC may tender for filing increased partial ! requirements rates pursuant to Section 205 of the Federal l 1
)
f ! l- . .- m - __ _m . - . ..
t 7 f Power Act on or after June 1, 1981; t L (b) As required by Section 35.3 of the-Commis-i sion's regulations, the revised tariff sheets contained in V any such filing vill state an effective date earlier than 1. January 1, l'/82 ; (c) If GPC files increased partia1' requirements 4 rates on June 1, 1981, the parties agree to file such plead-ings as are necessary to obtain a January 1, 1982 actual effective date, subject to refund, for such increased rates.
- Such pleadings may include requests for waiver of the notice period provided for in'the Federal Power Act and the Commis-sion's Regulations, requests'for specific suspension periods other than one day or five months and other similar plead-ings or representations as may be required to obtain a January 1,1982 effective date (subject to refund) for-increased rates filed on June 1,1981.
1.8 The parties agree that the Joint Committee-for Planning and Operations, created by agreement among the parties dated as of August 27, 1976, shall develop criteria for rating Customer-owned reserve capacity, such ratings to be utilized in calculating partial requirements billings.
- 2. REFUND OBLIGATIONS 2.1 GPC 'shall refund to OPC, MEAG and Dalton a portion of the revenues collected under PR-5 for the neriod November 1, 1980, through the date of refund as follows:
- __ a . . . _
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[, 1 I . h1 t , h Da l-GPC will. refund to each Customer the difference between the C , , payments actually received from such Customer and the payments L swhich would have been received if the revised. monthly charges described in Sections 1.2 and 1.3 of this Settlement Agree-
- s. -
p ment had-been in effect. 2.2 All refunds shall be paid prior to 10 a.m. L. on a business. day in immediately available funds and shall-a be computed for each billing period or portion thereof. Interest with' respect to such refunds'shall be calculated y pursuant to FERC Order No. 47, as amended (Order Nos. 47-A and 47-B, issued; November 8' , 1979 and December 26, 1979, respectively)..
- 3. COMPROMISE AND SETTLEMENT 3.1 .The parties hereby agree that execution of this Settlement Agreement is solely for purposes of . compro-
' mise and settlement and in-no way constitutes any admissions, nor does it represent a retreat.from the. original positions-taken by any party with regard to the subject matters hereof or acceptance of any principle of rate design or ratemaking, cost allocation, or inclusion or exclusion of items in cost of service.
3.2 .The execution of this Settlement Agreement _ establishes no principles and shall not be deemed to fore- ! close any party from-making any contention in any other pro-u ceeding. In any future proceeding or proceedings relating 4 m_ ! ^f. li z 'i.._* C A?
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p y to rates, charges, terms and conditions of' service and any P matter other.than a proceeding involving the honoring or enforcement of this Settlement Agreement, the parties shall p: not be bound or prejudiced by this Settlement Agreement, except to the extent expressly provided herein. 3.3 The approval of this Settlement Agreement by the FERC shall not in any respect constitute'a determi-nation by the FERC as to the merits of any allegation or contention of GPC, the Interveners or the Staff in this " proceeding. 3.4 The discussions between GPC, the Interveners and the Staff which have resulted in this Settlement Agree-ment have been conducted on the explicit understanding, pursuant to Section 1.18(e) of the FERC's Rules of Practice and Procedure, that all offers of settlement and discussions relating thereto, are and shall be privileged, and shall be without prejudice to the position of the parties, and. are l not to be used in any manner in connection with this proceed-ing or otherwise. This Settlement Agreement is executed on the same explicit understanding and on the further condition that in the event the FERC does not by order accept this Settlement Agreement in its entirety, any party having a direct interest in such failure of approval may, at its option, ) I cancel the Settlement Agreement in its entirety and withdraw or cause to be withdrawn all pleadings and other filings i I c-- , _ _ - - _ - ~ . - . _ - .a . - -_
L:.
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L made with the FERC in connection therewith. ., u IN WITNESS WHEREOF, the parties have caused this Settlement Agreement to be executed, effective December.21, I h 1980, by their duly authorized officers in multiple counter-l parts, each of which shall together constitute and are the same instrument. GEORGIA POWER COMPANY By: s 7M __v i Attest: . h AM.1___I/ , Witness:
- LL m o~ r
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n (CORPORATE SEAL) OGLETHORPE POWER CORPORATION (An Electric Membership Generetion & Transmission Corporation)
/s 3 By: ,. Vi " N w a w
(SIGNATURES CONTINUED ON PAGE 8) 8 7 n.. = . . - - . -m- ._x xn. - . - -. . _ . - - - . _. _ _ - . _ - _ .
! a !c. V' (SIGNATURES CONTINUED) Attest:[..' 4( b W , [\ Witness: - r (CORPORATE SEAL) y MUNICIPAL ELEC~RIC AUTHORITY OF GEORGIA y .-
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Q"'- - i Attest: - m. , mA , Witness: %ed / ,ID. , (CORPORATE SEAL) CITY OF DALTON, acting by and through its BOARD OF WATER, LIGHT AND SINKING FUND COMMISSIONERS
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y Fourth Revised Shect No,-11-A; [ Gacrgia' Pow 2r: Com,pcny-(Superseding-Third Revised ([ LFERC: Electric 1 Tariff- Shaat No. 11-A)' D' 10riginc11Voluma No. 2: DETERMINATION OF-MONTHLY ENERGY CHARGES- . Monthly energy chargesJshall be the sum of (a) the
!I
- Unit. Energy Charges by category, as determined above, multi-plied by-the Customer's energy requirements-by category; and (b).a Variable Operation and Maintenance Surcharge of
.$0.00204 per;kWh multiplied by the Customer's total energy Q requirements..
t
-CUSTOMER SURPLUS CAPACITY AND ENERGY Customer capacity resources excess to requirements in
~
y a category will be defined as Surplus Capacity. . The-Surplus
- Capacity will be deemed to be in the particular Customer resource' highest in such category of the Resource!Classifi-cation List.- Surplus Capacity will-be reclassified-to the next higher category'and will be treated as capacity in the new category with- regard to back-up energy and reserve require-ments for that capacity.
Energy associated with Surplus Capacity will be reclassified and credited to'the Customer's Energy Requirements. in the'next higher catego y. Surplus; energy in a category-will exist'if the energy rom the Customer s resources in that category (including any reclassified resources):and back-up energy exceeds the Customer's requirements'in that category. JWty such surplus energy will be' credited prorata to the L
- Customer's back-up energy requirements in lower categories.
In;the event a Customer gives notice to the Company (at er least:';wo months prior to the filing of ~ a change in partial requirements rates) of that Customer's intention of selling off-rystem a specified quantityL(in kW)xof Surplus Capacity and associated energy, the' Company's. charges contained in.such filing will reflect such anticipated sale. . Thereafter, during the' period such charges are in effect, the Customer will receive no capacity credit for'the amount of capacity contained in such notice or for any additional Surplus capacity which is sold off-system. TERMS-AND CONDITIONS Service su ll' be subject to the " Terms and Conditions," pplied hereunder shaand said Terms and Conditions are inc herein by reference 4 Issued by Harold C. McKend'ie, Jr. Effective November 1, 1980 Executive Vice President Issued on
/
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Fourth navised Sheet No. 2q L G;orgia Powar Compcny FLRC Elactric Tariff (Suosrseding Third Revised Original Voluma No. 2 Shoot No. 20) If the Company is unable to meter or does not have ade-quate metering for Customer-owned resources, the Customer will certify to the Company in writing within five (5) days of the end of each month the kW and kWh delivered to the Customer from each such resource during said month. A Customer shall receive billing credit for customer-owned reserve resources in an amount equal to the rated capacity of the resource times the unit charge for reserve capacity contained in the effective
- partial requirements tariff. Energy generated by such Customer-owned resource shall be credited prorata to the Customer's back-up energy purchases. Any excess energy will be purchased by the Company at the actual average cost of the Company's reser.
generation.
- 10. Determination of Capacity Requirements (a) The Com of each of the 10% pany shall date the 44 hours on each sideand 80 torial Load Duration Curve. The Customer s load coincident j with the maximum one-hour integrated territorial system peak demand shall be the Customer's total unreserved capacity require-ments. The load level represented by the Customer's average load during the 44 hours on either side of the 80% of total time point in the Territorial Load Duration Curve, multiplied by the ratio of the territorial load at such 80% point to the average of the territorial load within such 88-hour band, shall be deemed the Customer's Base Load Level, and shall repre-sent the Customer's base load requirements. The load level represented by the Customer's averagc load during the 44 hours on either side of the 10% of total time point on the. Territorial Load Duration Curve, multiplied by the ratio of the territorial load at such 10% point to the average of the territorial load within such 88-hour band, shall be deemed the Customer's Inter-mediate Load Level and the Customer's intermediate load require-ments shall be the difference between the Customer's Intermediate Load Level and Base Load Level. The Customer's peaking load requirements shall be the difference between the Customer's total unreserved capacity requirements (determined as described above) and the Customer's Intermediate Load Level. Reserve j l
requirements shall be calculated as set forth in the Rate Sched-ule. All capacity requirements determinations shall be reduced j by the Customer's SEPA capacity allocation, if any. The Custo-mer's Capacity Requirements as adjusted for SEPA capacity shall be further adjusted for average transmission systen demand losses by dividing the Customer's Capacity Requirements Sy a factor of
.947.
(b) At the start of a contract year the capacity require- ! ments determination shall be based on the Territorial Load Dura-tion Curve and the Customer's hourly load data for the most recent contract year available. The operation described in Section l 10(a) r.bove will be applied to this data, and the ratios of base, intermediate and peaking requirements to total capacity require-ments will be determined. Issued by Harold C. McKenzie, Jr. Effective November 1, 1957 Executive Vice Presiden.t l Issued on l l r , .> :. .
3 A. RESOLUTION OF THE BOARD OF WATER, LIGHT AND SINKING' FUND COMMISSIONERS OF THE CITY OF DALTON WHEREAS, for a considerable period of time this Board, on behalf of The City of Dalton, has been negotiating, through counsel, with numerous parties concerning claims relating to matters pending before the United States Federal Energy Regula-tory Commission in Docket No. ER80-328 ("PR-5"); WHEREAS, the parties have reached an agreement as to the above said matters; and s WHEREAS, the Mayor and Council of The City of Dalton, has adopted'a resolution authorizing and empowering the Chairman and the. Secretary of this Board to enter into, execute and deliver a certain Settlement Agreement concerning these matters, and it is desirable for this Board to adopt a similar resolu-tion; NOW THEREFORE, BE IT RESOLVED by the Board, and it is hereby resolved by the authority of same: That the Chairman and the Secretary of this Board be, and they are hereby authorized and empowered, in the name of the City and on behalf of the City and this Board, to enter into, execute and deliver a certain Settlement Agreement among parties concerning claims relating to matters pending before the United States Federal Energy Regulatory Commission in Docket No. ER80-328, and to take such steps as may be neces-sary to carry out the terms thereof. l CERTIFICATE I, V. D. Parrott, Jr., the undersigned, do hereby certify that I am the Secretary of the Board of Water, Light and Sinking Fund Commissioners, that at a proper y held and constituted T meeting of the Board, held on the / day of " N*. /9'fo at l which a cuorum was at all times present and voting , the fore-l going resolution was duly adopted, and'that the Chairmajg and Secretary executed said Settlement Agreement on the <b5 - day of 8o./WC e .
.?.
_ _ _ _ _ . A _ _.m._A._._.1_ _ .A ,_ _ ..M a .A_ m 2 2 'a _2__ _ a _. m2 4 2 m a,_ S-#-
s... . y , e AND, I do further~ certify that'the foregoing resolu-tion has'not been in any way. modified, amended.. rescinded or p: revoked,Jand' remains on the.date hereof in full-. force and 1
-effect.- -
.J IN-WITNESS WHEREOF,.'I have hereunto set my hand and affixed.the Seal of the City', this 2 2#day of A2 rte /9/0 - .-
v bD ' YLA Secre k
< . . (CITY SEAL)
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i.' i l' ~ RESOLUTION 0F THE GOVERNING AUTHORITY OF-
- - 'THE CITY OF DALTON _ _.,_,_._ _ _.._,_
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. WHEREAS,xforLa: considerable period of time that City, L, ; : acting-by and;through its. Board of. Water, Light;and Sinking Fund Commissioners, has been negotiating,- through counsel,-
.with~ numerous. parties concerning~ claims relating to matters
.pending before:the United States: Federal' Energy Regulatory Commission'in Docket No'. ER80-328 ("PR-5");
@ WHEREAS,.the parties have reached an agreement as to E .the above.said matters;- , NOW THEREFORE, be it resolved by the Mayor and Council, and it is hereby. resolved by the authority of'same: y That the' Board of Water, Light and Sinking-Fund Com-missioners, by and through'its Chairman and-Secretary,fbe and'they' are hereby authorized and empowered, in the name: and'on behalf of'this; City, to enter into, execute and-
~ deliver a'certain: Settlement Agreement ~among parties' concern-ing claims. relating to matters pending^before_the United States-Federal Energy Regulatory Commission in Docket No.
'ER80-328,-and to take such steps as may be.necessary.to carry.
out the terms thereof. b CERTIFICATE I, h u/ Whd , . the undersigned, do hereby-certify that/I am tKe Clerk of The City 'of: Dalton, State of Georgia, that at. a properly held and constituted meeting of thegoverning aythority of said City, held 'on. the /S" day of E4cenA"4r_ /7/8 , at which a quorum was at al H imes present and voting, the foregoing resolution was duly adopted, and that the Board of Water, Light and Sinking Fund Commis- ,.y sioners, by and through its Chairman and Secregary, exgcuted said Settlement Agreement on the ffy day of 4% Q 84 AND, I do further certify that the foregoing resolution
.has not been in any way modified, amended., rescinded or revoked, and remains on the date hereof in full force and
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<IN WITNESS. WHEREOF, I.have' hereunto see my-h 6- '
w - affixed: the ' Seal- of the City, . this & day of. Je,and M 'and tG-
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,[ ' Clerk
-(CITY SEAL) a u
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e OPC POSITION STATEMENT REGARDING GA-FLA.500 kV TIE LINES ! 1 OPC recognizes the ~need for off-system ties to supplement generation reserve cargins'and reduce.LOLP for Georgia and Florida. We also recognize the wisdom ef establishing these ties before reserve margins in GA shrink to the point that tha ties are absolutely necessary to maintain a desired LOLP criteria. It appears to OPC without benefit of.a detailed study report that only two 500 kV lines would b3 nseessary to proXide sufficient transfer capability between Georgia and Florida I to mtintain a justifiable LOLP. From our understanding of the proposed 500 kV systcm in Florida we see a stong need for a 500 kV tie between Tifton and Fort Whito (FLA) as well as Tha11 man and Duval (FLA). It is obvious that in the five years after these lines are built Florida will receive-u th2 benefits of increased transfer capability in effective . .nination of system s;paration and increased capability for economy sales which will benefit the Florida c:mpanies.which are heavily dependent on oil fired generating units. OPC is interested in determining what benefits these lines will provide to the Georgia ITS. GPC maintains that Georgia will benefit from South Georgia transmission system supp;rt created by power flow from Florida to Georgia on existing tie lines at 230 kV cr balow. GPC has stated that this effect along with the system flexibility gained ifrom 500 kV lines in South Georgia will eliminate or at least delay numerous planned improvements to the South Georgia transmission system. To date OPC has not received any documentation of studies which support these contentions. If such studies . htva been or will be performed, they will provide a basis for judging the effective-n2ss of the = 500 kV lines on a cost / benefit ratio basis. In summary, OPC, recognizes a need for only two 500 kV tie lines with Florida to incraase reliability to the Georgia area. OPC has not been given the opportunity to raview studies which may have been performed to determine the measure of increased ralisbility.that will be provided by the proposed 5,00 kV tie lines. OPC has not barn a party to and has not reviewed studies that evaluate the effect these 500'kV lines have on the ITS in the South Georgia area and show what economic benefit they provide. Until such studies are available and the economic benefits are found to bn favorable, OPC cannot support the construction of these lines or their inclusion in the ITS. 1/29/81 h
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. . . _ . . . . -. - 9. a _
7 , li- . interoffice Ccmmunicati:n aeorgiapowerh i f f. . February 20, 1981 b. MEMO TO: B. L. HOLTON
.S'UBJECT: Hourly Energy Billing To PR Customers During the PRS settlement negotiations I told OPC'and MEAG that Georgia di would develop " Hourly Energy Billing" to the PR customers. Hourly billing is needed to.more accurately identify the cost of energy transactions with the PR customers, especially as they becomt more self sufficient. .As you know the Southern Company pool billing impacts the PR billing and it too is calcula-ted hourly. Therefore, please proceed with the development of " Hourly Energy Billing" with a target date of 1/1/83 for implementation.
A. W. DAHLBERG AWD/nmj 4 1 La 7000:s
- Geov;; a Sa*e* d ,~ caS 7, 333 8'es-em A.eawe At:an's Geo ge 3030] e
' Teiephone 44 526 53?F.
. Ma ung Ac:ress -'
Post O*t ce Ben 4545 At;anta Georgia 30302 -
. GeorgiaPower 3
tne southe-n e+ctrc wr" A.W.DeNberg
- .Vice Pres > cent Oce avces 7:anvg an: Cant <01 October 26, 1981' Mr. Paul R. Heim Municipal Electric Authority of Georgia 1470 Riveredge Parkway AtlanP.a, Georgia- 30328 Mr. G. Stanley Hill' Oglethorpe Power Corporation
- 2888 Woodcock Boulevard Atlanta, Georgia 30341 IGentlemen:
Attached is a fully. executed copy of the agreement reached on October 22 - 1981. Yours truly, , .- A. W. Dahlberg AWD:vn Atta chment ec: (W/ Attachment) Mr. V. D.' Parrott, Jr. Mr. L. C. Adams, Jr. Mr. T. J. Bolch Mr. R. H. Forry Mr. G.'W. Et/ards,-Jr. Mr. R. E. Scott Mr. B. L. Holton, Jr. l a . . . _
24
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. >~y t n 5.ca Est par a Gecrg.a 30302 Georgia Power-g rne smewn e A. W. Dahlberg
. e D'escent a ms n'amng an.: cent c' October 22, 1981 g
Mr.. Paul R. Heim. Mr. G. Stanley Hill-Municipal Electric. Authority Gglethorpe Power Corporation of Georgia 2888 Woodcock Boulevard 1470 Riveredge Parkway Atlanta, Georgia. 30341 Atlanta, Georgia 30328 D Gentlemen: Georgia Power agrees that the normal and intended operation of the Scherer units shall be to operate the units on economic dispatch including off-system sales.- Any retained energy resulting to co-owners from such economic
- dispatch in excess of that which results from a simulated economic dispatch
- which does not include off-system sales, will be purchased by Georgia at the co-owners' production cost. In the event the unit operates outside of economic dispatch, Georgia's owned and purchased entitlement to Scherer generation will be sold off the. system rather than retention of this energy -
in the system while selling lower cost alternate energy. ). Georgia shall not be obligated to purchase and resell other owners' share of Sclerer i generation to the exclusion of Georgia's other market opportunities, except as agreed to above. It is further recognized that Georgia agrees to pursue the Plant Scherer coal supply options listed on Attachment 1. In response to this agreement MEAG and OPC agree to withdraw their interven-tion to the Unit Power Sale contracts. ' It is understood that MEAG and OPC have other. objections which may be pursued in settlement of PR-6 and admini-stration of the ownership and operating agreements. Yours truly, A. W. Dahlberg v cc:- Mr. V. D. Parrott, Jr. Acknowledged and agreed: MUNICIPAL ELECTRIC AUTHORITY OGLETHORPE POWER CORPORATION
+ OF GEORGIA By: By:
G. Stanley Hill aul R. Heim. Director [ Engineering & Operations Division Manage m.__m___.____ ___..________A_._ _ _ . _ _ _ _ _ _ _ _ ._ _ ____.._.-.m _mm. - . .s . .._ .:__= ._ a v . a
4 ATTACHMENT.-1 l ' - ), . - t A 'L : PLANT-SCHERER COAL SUPPLY OPTIONS. l L w
'l. Negotiate tonnage reduction with contract suppliers.
- 2. : Sell additional Plant Scherer energy ~off system.
; 3. - Sell excess' coal to. third parties.
.'4. Stock excess coal at coal mines.
S'. ; . Divert coal to other Southern System plants.
,6. Divert coal to'other territorial generating plants.
.. 7. ~ Operate . Plant Scherer of f economic dispatch (force : burn) .
~ The above options willjall be evaluated in. 'an effort to produce o the best: economic' choice. The System's recent experience at Plant Daniel and Plant Miller indicates, however, that force-burn will.in all probability be required in some amount ~for-some period of: time. .It'is our belief that: procedures should be; developed which make" the ' assumption that this will occur.
The Company,will, in addition to the above-items, arrange a meeting between the co-owners and'the Georgia and-Southern-f System-Fuel Services personnel to review the Scherer. fuel ! supply contracts. L l: l y 1 4 5 10/22/81 u= & e_ = :__: 1. . m .._ . m: = ~ = x __- c :::_=: : _ _ -
August 8, 1989 Supplemental Response of Georgia Power Company volume II
- 12. The April 8, 1982 PR-6 settlement and side agreements reflect further treatment of off-system sales and economic credit for customer-owned resources.
- 13. The PR-7 settlement shows further evolution of the PR tariff.
- 14. Oglethorpe's October 1983 Regulatory Guide 9.3 submission shows how Oglethorpe is not self-sufficient.
- 15. The February 1984 Project Plant to Levelop a Georgia Territorial Power Supply Agreement included the October 12, 1983 letter from A. W. Dahlberg to G.
~ Stanley Hill which initiated this project. As the October 1983 letter stated, new agreements and renegotiation of existing agreements would be necessary to facilitate the desired sales by - Oglethorpe. The jointly sponsored report identified revision of the PR rate as the critical step, at j pages 1-2. Oglethorpe uses Mr. Dahlberg's letter out of context. It did not say that Oglethorpe could export power at will. Oglethorpe also ignores the result of the study process: that revision of the PR rate was necessary.
- 16. Oglethorpe's members have received the benefits of the January 23, 1985 contract with SEPA for four years. Oglethorpe cannot complain about performance of this contract. Moreover, none of.the SEPA power qualifies as capacity Oglethorpe is able to export or resell under the license conditions.
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1 ma i t e. UNITED. STATES!0F: AMERICA
' FEDERAL ENERGY . REGULATORY: COMMISSION e
B e. Georgia Power Compan'y ) Docket No. ER81-730-000-
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$Y EXPLANATORY STATEMENT w
& On1 September 1,1981, Georgia Power . Company (" Georgia; k
Power" 'or the "CompR r") filed increased rates for partial requirements. service 1/ and full requirements service 2/'.
- LBy order' issued NovemEer 20, 1981, : Georgia Power's . fi1Ing was. accepted, the effectiveness'of the PR-6 and FR-4' rates-was suspended until February 1, 1982,.and April 1, 1982,.
respectively, hearingszwere ordered and all of the Company's-l
'partialirequirements 3/ and-full requirements 4/-customers were granted leave to intervene. -The Consumers'. Utility
'$ Counsel of Georgia also: intervened.
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Th'e matter proceeded toward trial until, ' relying on counsel'airepresentations that they had reached an. agree.- Ement in principle,-Honorable Brenda P. Murray,: Presiding. Administrative Law Judge, suspended the. procedural schedule
-iniDocket No. - ER81-730-000 on-January 25, 1982..
_ The. parties have successfully~ resolved all issues.in-
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' Docket.No.'ER81-730-000. Accordingly, there are filed' herewith pursuant Lto' Section 1.18 of the Commi~ssion's RulesVof Practice:and Procedure, six copies of the follow'- -
ing:
~(I) . Explanatory Statement; 1/ Partial' requirements service is rendered pursuant to Georg"ia Power's FERC Electric Tariff, Original Volume No.
2 ("PR-6 ).. PR-6 was designated Docket No. ER81-730-000. 2_/ Full requirements service is rendered purs'uant to "y t, - Georgia. Power's FERC Electric: Tariff, Original Volume No. 1 FR-4 was designated' Docket No. ER81-731-000. ("FR-4") . 3_f City of-Dalcon, Georgia, Municipal Electric
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' Authority 'of GeorF ia and Oglethorpe Power Corporation (An Electric Membership Generation & Transmission Corporation).
$ City of Acworth, Georgia and City of Hampton, m Georgia'.. .
9 we . . . - - - -
r (2) Unanimous Settlement Agreement among Georgia Power and-all partial requirement.s customers; (3) Schedule comparing partial requirements revenues under the partial requirements rates now in effect and the settlement rates for Period II (December 1, 1981 through November 30, 1982); (4) Proposed letter order accepting the settlement; (5) Revised tariff sheets to Georgia Power's FERC Electric Tariff, Original Volume No. 2 (PR-6) -- a Sheet Nos. 6, 7, ll-A, 20, 20-A, 20-D and 20-E (attached to Settlement Agreement) . D The partial requirements settlement rates reflect a reduction in the proposed rate increase from $25,331,000 to $14,326,000 based on Period II. As noted on revised tariff sheet nos. 20 and 20-D, two tariff changes (con-tained in Sections 10 and 12 of the " Terms and Conditions") are not to take effect until June 1, 1982. Changes to these two sections were contdned in the Company's ori-ginal filing in this Docket, but the parties have agreed to delay their effectiveness until the start of the next A chan partial requirements contract year. determinants, resulting fective from datethis delayed e$ce is reflected in the two sets of rates set forth on sheet no. 6. The settlement rate design, detailed in the enclosed reyenue comparison, spreads the settlement reyenues over these two sets of billing determinants to produce the agreed upon revenues. That is, test period revenues are not affected by the delayed effective date so long as rates and billing determinant provisions are applied consistently during the appropriate periods. In addition to the tariff changes described above,. the Settlement Agreement also contains a rate increase moratorium, providing that no change in rates will be effective for service rendered prior to February 1,1983. . C Finally, the following representation concerning tax normalization is being included at Staff's request. Georgia Power Company follows deferred income tax accounting for all significant income tax timing dif-ferences on its books of account end in ratemaking proceedings in accordance with the ax normalization ( ,> requirements of the Internal Revenue Code (including appropriate sections of the Economic Recovery Tax Act of 1981), generally accepted accounting principles and the requirements established by this Commission and applicable state law. s No testimony or exhibits have been received into evidence in this proceeding. The testimony and exhibits constituting Georgia Power a case in chief support the unanimous Settlement Agreement. L h >* L- - - . - __- - - - . _-. -. .. _ . -
i Georgia Power and its full requirements customers have recently. reached an agreement in Docket No. ER81-731-000, t - and a settlement filing-will be forthcoming in that Docket. M : That Docket is not affected by this filing. A copy of the-complete settlement filing is being served upon all parties and the Presiding Administrative Law Judge in Docket No. ER81-730-000'and upon the Georgia Public Service Commission. By copy of this filing, h- ' Georgia Power hereby gives notice that' comments on the-proposed settlements may be-filed with the Commission on or aefore twenty days from this date, and'any reply com-ments mustfbe filed on or before thirty days from this date. I Respectfully submitted, , Rdbert H. Forry ounsel for GEORGIA POWER ANY April 8, 1982 TROUTMAN, SANDERS, LOCKERMAN
& ASHMORE 1400= Candler Building Atlanta, Georgia 30043 i (404) 658-8000 w
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r o t SETTLEMENT AGREEMENT ! THIS AGREEMENT is made and entered into by and among Georgia
- Power Company ("GPC"); Oglethorpe Power Corporation (an Electric l Membership Generation & Transmission Corporation) ("0PC"); the Municipal Electric Authority of Georgia ("MEAG"); and the City of Dalton, Georgia, acting by and through its Board of Water, Light
& Sinking Fund Commissioners (" Dalton"). All of the foregoing N. 1 except GPC are sometimes collectively referred to herein as r
" Interveners" or " Customers." This Settlement Agreement relates to those matters relative to the Company's partial requirements tariff ("PR-6 tariff") which are pending before the Federal Energy Regulatory Commission ("FERC") in Docket No. ER81-730-000
("PR-6"). Subject to agreement by all parties hereto to the provisions set f' orth in this Settlement Agreement and with the agreement that each provision of the Settlement Agreement is in considera-tion and support of every other provision, the parties hereby agree as follows:
- 1. DISPOSITION OF PENDING RATE PROCEEDINGS 1.1 The parties will advise the FERC forthwith that the parties have settled the issues with respect to FERC Docket No. ER81-730-000. The Interveners will file such pleadings and make such representations to the FERC and the FERC Staff as are requested by GPC to the end that FERC approval, according to the terms hereof, may be obtained as soon as possible. Nothing contained herein shall be construed to prohibit any party from
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filing any pleading'in' furtherance of-its. interests under:this Settlement Agreement; and nothing. contained herein shall be 1 construed to require any party to take any. action not in its best interests in effectuating this Settlement Agreement. ; 1.2 GPC shall file with the FERC revised PR-6 tariff sheet do. 6 revising the " Schedule of Monthly Charges for Capacity" delivered pursuant to Rate Schedule PR-6, to be y effective February 1, 1982 to May 31, 1982 and June 1, 1982, to read as follows: February 1, 1982 to May 31, 1982
" SCHEDULE OF MONTHLY CHAEGES FOR CAPACITY
" Type of Service Monthly Charge
" Unreserved base capacity $6.75 per KW .
" Unreserved intermediate capacity $5.27 per KW. I
" Unreserved peaking capacity $4.30 per KW
~" Reserve capacity $3.84 per KW"
- June 1, 1982
" SCHEDULE OF MONTHLY CHARGES FOR CAPACITY'
" Type of Service Monthly Charge
" Unreserved base capacity $6.69 per KW
" Unreserved intermediate capacity $4.12 per KW
" Unreserved peaking capacity $4.51 per KW
" Reserve capacity $4.25 per KW" It is understood and acknowledged by the parties that GPC has utilized a 17% return on equity for the purpose of developing the settlement rates, and the parties agree, therefore, that such rate of return shall be used in calculating all " buy-back" t
and " transmission parity" payments by one party to another under the several contracts between the parties which refer to GPC's partial requirements return on equity. U.- ww 2 su x i~ x va .. - 1 - .t .
e . 4 r E ?:
'l.3 GPC shallLfile with the FERC revised PR-6 tariff sheet Nos. 7, ll-A, 20, 20-A, 20-D and 20-E in the form attached hereto as exhibits.
l.4 It is understood, acknowledged and agreed by the parties that the revised. tariff sheets described in Sections 1.2 and 1.3 of this Settlement Agreement shall be effective from-the dates stated thereon until changed pursuant to the Federal Power y Act. 1.5 It is understood, acknowledged and agreed that all provisions of the PR-6 tariff except those described in Sections 1.2 and 1.3 of this Settlement Agreement shall be effective as 1 filed from February 1, 1982, until changed pursuant to the
' Federal Power Act.
, 1.6 Nothing contained in this Settlement Agreement shall be deemed to preclude GPC from filing with the FERC a
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notice of an increase in rates or other change in the PR-6 tariff pursuant to- Section 205 of the' Federal Power Act, however, no such change shall be effective for service rendered prior to February 1, 1983. l.7 In further explanation of the rate change mora-( torium referred to in Section 1.6 of this Settlement Agreement, it is understood, acknowledged and agreed that if GPC files revised partial requirements rates on July 1, 1982, the parties intend for those rates to become effective on February 1, 1983. The parties specifically agree as follows: (a) GPC may tender for filing revised partial require-ments rates pursuant to Section 205 of the Federal Power Act b
a on or after July 1, 1982; (b) As required by Section 35.3 of the Commission's Regulations, the revised tariff sheets contained in any such filing will state an effective date earlier than February 1, i 1983; (c) If GPC files revised partial requirements rates on July 1, 1982, the parties agree to file 9uch pleadings as are necessary to obtain a February 1, 1983 actual effective date, subject to refund, for such revised rates. Such plead-ings may include requests for waiver of the notice period provided for in the Federal Power Act and the Commission's Regulations, requests for specific suspension periods other than one day or five months and other similar pleadings or representations as may be required to obtain a February 1, 1983 effective date (subject to refund) for revised rates filed on July 1, 1982.
- 2. REFUND OBLIGATIOt4S 2.1 GPC shall refund to OPC, MEAG and Dalton a portion of the revenues collected under PR-6 for the period February 1, 1982, through the date of refund as follows: GPC will refund to each Customer the difference between the pay-ments actually received from such Customer, if any, and the payments which would have been received if the revised monthly charges described in Section 1.2 and 1.3 of this Settlement Agreement had been in effect.
2.2 All refunds shall be paid. prior to 10 a.m. on a business day in immediately available funds and shall be ~.m--, --.--- --.s_- - - - 1.- -..1. -. n - -
computed for each billing period or portion thereof. Interest with respect to such refunds shall be calculated pursuant to FERC Order No. 47, as amended (Order Nos. 47-A and 47-B, issued November 8, 1979 and December 26, 1979, respectively).
- 3. COMPRCMISE AND SETTLDfENT ~
1 3.1 The parties hereby agree that execution of this Settlement Agreement is solely for purposes of compromise and g settlement and in no way constitutes any admissions, nor does it represent a retreat from the original positions taken by any party with regard to the subject matters hereof or accep-tance of any principle of rate design or ratemaking, cost allocation, or inclusion or exclusion of items in cost of service. 3.2 The execution of this Settlement Agreement esta-blishes no principles and shall not be deemed to foreclose any party from making any contention in any other proceeding. In any future proceeding or proceedings relating to rates, charges, terms and conditions of service and any matter other than a proceeding involving the honoring or enforcement of this Settle-ment Agreement, the parties shall not be bound or prejudiced by this Settlement Agreement, except to the extent expressly provided herein. 3.3 The approval of this Settlement Agreement by the FERC shall not in any respect constitute a determination by j the FERC as to the merits of any allegation or contention of
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GPC, the Interveners or the Staff in this proceeding. i I I e
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'3.4 The. discuss' ions between GPC, the Interveners:and the Staff which have resulted in this. Settlement Agreement have f
been conducted on the explicit. understanding, pursuant to Sec - tion l'.18(e) of the FERC's Rules of Practice and Procedure, that; all offers of settlement and discussions-relating thereto, are and shall be privileged, and shall be without prejudice' to the position of the parties, and are not to.be used in any manner in connection with this proceeding or otherwise. This Settlement-
* . Agreement is' executedon the-same explicit understanding and on-the further condition that in'the event the'FERC does not by.
order accept this Settlement Agreement in its entirety, any.
. party having a direct' interest in such. failure of. approval may, at its option, cancel this Settlement-Agreement in its entirety and withdraw or caus'e to be withdrawn all pleadings and other filings made.with the FERC in' connection therewith.
- IN WITNESS WHEREOF, the parties have caused this Settlement Agreement to be executed, effective-April .8 , 1982, by their duly authorized officers in multiple counterparts, each of which shall together constitute and are the same. instrument.
GEORGIA POWER COMPANY By: /s/ A. W. Dahlberg, III vice President, operations. Planning and Control Attest: /s/ Guerry P. Strickland ass:La tan t decretary Witness: /s/ Vicki S. Norman (CORPORATE SEAL) (Signatures Continued on Page 7)
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m.m_m __m, _m______ . - _1_1___ _ _. __m u - _u _m
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'c OGLETHORPE -POWER . CORPORATION (An Electric Membership Generation &
Transmission Corporation)
*- By: '/s/~Fi F. Stacy General Manager ~w Attest: /s/ Charles T. Autry 4' '
Corporate Attorney 1 Witness: /s/ Ali Bufkin 3: (CORPORATE SEAL)- MUNICIPAL ELECTRIC AUTHORITY OF-GEORGIA b By: /s/ Donald L. Stokley General Manager
'Attes t : - '/s/ C. E. Newcomer, Jr.
L As sis tant : Secretary-Treasurer. EI > Witness: /s/- L. Clifford.' Adams,'Jr. (CORPORATE SEAL) 7- CITY.0F DALTON, Acting by and' I through'its. Board of Water, Light and Sinking Fund Commissioners \,. 1 'l By: /s/ James E. Brown V l' Attest: /s/ DeForrest Parrott Witness: /s/ Linda Carlisle 1 l (CITY SEAL) [ 1
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_ _ . _ _ _ .__:_,___ .._.....:_._. . _ .. . _ s. _
w RESOLUTION:OF'THE GOVERNING AUTHORITY OF-THE CITY OF DALTON e P
> t v WHLREAS, for. a considerable period of time the City of Dalton, acting by and through its Mayor and Council has been negotiating,
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through counsel, with numerous parties concerning claims relating to. matters pending before: the United States' Federal Energy Regula-6 tory Commission in -Docket' No.1ER81-730-000 ("PR-6"); e WHEREAS, the parties have reached an agreement as_to the.above Esaid matters; HOW, THEREFORE, be it resolved by the) Mayor and Council, and "' it is hereby' resolved by the authority of same:
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That 'the appropriate' City officials be and they ; are hereby authorized and ' empowered, in the name and on behalf of this Cir*, tcr enter. into, execute and deliver .certain settlement agreemenu between the City, Georgia Power Company, .0glethorpe Power Corpora-tion,- and the Municipal' Electric Authority of Ge~orgia concerning-claims relating; to matters pending _ before the United L States Federal Energy Regulatory Commission in Docket No. ER81-730-000, and to Ltake such steps as may.be necessary to carry out the terms thereof. CERTIFICATE I,. Faye L. Martin , the undersigned, do hereby fcertify that: 1. am- the Clerk of-The City of Dalton, State of Georgia, that at a properly' held and constituted meeting of April,-1982 the governing authority of said City, held on the 5th day of at which a quorum was at all times present and. voting, Mayor. the fore-going resolution was duly adopted, and that the of-said City ~ executed said Settlement-Agreement and an Agreement dealing with accounting fcnr Unit-Power Sales and the tax liability Sch-associated with the sale of a portion of Plant Vogtle on the dayfof April , , AND, I do further certify that the foregoing resolution has ; not been in any way modified, amended, rescinded or ' revoked, and remains on.the date hereof in full force and effect. IA WITNESS WHEREOF, I have hereunto set my hand and affixed
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the Seal of the City, this 5th day of April ._.
/s/ Faye L. Martin k Clerk j
(CITY SEAL) i
G;c;rgic'Powar C mprny Raviccd Shrat N3. 6 FERC Elcatric Tcriff (Superseding. R;viscd Original.V;1ume NJ. 2 Shost N3. 6) Intermediate Load shall be the intermediate portion of a load duration curve which lies between the peaking load level and the base load level. l 'MONTHLYBIb 5 --The monthly bill shall consist of charges for contract capacity by category, reserve capacity by category, energy by category, and their back-up energy as used for reserving Customer-owned generating g resources which result from joint planning with the Company. SCHEDULE OF MONTHLY CHARGES FOR CAPACITY Type of Service Monthly Charge Unreserved base capacity $ 6.75 per kW Unreserved intermediate capacity $ 5.27 per kW Unreserved peaking capacity $ 4.30 per kW Reserve Capacity $ 3.84 per kW DETERitINATION OF RESOURCE CLASSIFICATIONS Prior to the beginning of the contract year, the Company shall prepare a Resource Classification List comprised of all i territorial capacity resources listed in order of ascending variable incremental energy costs (as determined for the purposes of the Southern system power pool) such that the capacity resources with the lowest variable incremental energy cost is at the bottom of the list and the capacity resource with the highest variable incremental energy cost is at the top of the list, except that those capacity resources, includ-ing hydroelectric resources, whose operating characteristics require that they be operated as base, intermediate, peaking or reserve capacity resources shall be assigned to those respective categories without regard to variable incremental energy costs. Starting at the bottom of the Resource Classi- 3 fication List, the territorial capacity resources whose aggregate sum of System Peak-Hour Capabilities (as determined for the purposes of the Southern system power pool) equals the
]
I 1 Issued by George U. Edwards, Jr. Effective February 1, 1982 l Executive Vice President to May 31, 1982 i Issued on April 8, 1982 l i mm_m m _ _ m - = - . I
i Gn:rgio PowarJCrmp:ny R3visCd Shast No. 6 FERC Elcetric Tcriff . (Suparsading R; vised
. Original Volume No. 2 Shact No. 6) -
f Intermediate Load shall be the intermediate
?ortion of a loa 3 duration curve which lies between the peaking load level and the base load level.
MONTHLY BILL The monthly bill shall consist of charges for contract capacity by category, reserve capacity by category, energy by category, and their back-up energy as used for ; reserving Customer-owned generating ; 3 resources which result from joint planning with the Company. SCHEDULE OF MONTHLY CHARGES FOR CAPACITY Type of Service Monthly Charge Unreserved base capacity $ 6.69 per kW Unreserved intermediate 2 capacity $ 4.12 per kW Unreserved peaking cepacity $ 4.51 per kW Reserve Capacity $ 4.25 per kW _ DETERMINATION OF RESOURCE CLASSIFICATIONS Prior to the beginning of the contract year, the Company shall prepare a Resource Classification List comprised of all territorial capacity resources listed in order of ascending variable incremental energy costs (as determined for the Oteposes of the Southern system power pool) such that the ccpacity resources with the lowest variable incremental energy cost is at the bottom of the list and the capacity resource with the highest variable incremental energy cost is at the top of the list, except that those capacity resources, includ-ing hydroelectric resources, whose operating characteristics require that they be operated as base, intermediate, peaking or reserve capacity resoerces shall be assigned to those respective categories vite.out regard to variable incremental energy costs. Starting at the bottom of the Resource Classi-fication List, the territorial capacity resources whose aggregate sum of System Peak-Hour Capabilities (as determined for the purposes of the Southern system power pool) equals the Issued by George W. Edwards, Jr. Effective June 1, 1.982 Executive Vice President Issued on April 8,1982 l
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M Ceorgia-Power Company Revised Sheet No. 7 FERC Electric Tariff- (Superseding Revised Original Volume No. 2 Sheet No. 7) territorial base load-capacity requirements as hereinbefore defined shall be designated base resources of the owner. Those territorial capacity resources next higher on the Resource Classification List whose aggregate sum of System Peak-Hour Capabilities equals the territorial intermediate load capacity requirements as hereinbefore i defined shall be designated intermediate resources of the owner. Those territorial resources next higher on the Resource Classifica-tion List whose aggregate sum of System Peak-Hour Capabilities equals the territorial peaking load requirements as hereinbefore defined - shall be designated as peaking resources of the owner. All other-5 territorial resources shall be designated as reserve resources of the owner. In order to match resources with territorial. require-monts, a resource may be categorized as being in more than one category. All owners of any such resource shall share proportion-ately in the resulting categorization. The initial Resource Classification List shall reflect the System Peak-Hour Capability ratings for generating units as set forth in the Southern Company System Intercompany Interchange Contract ("IIC") most recently filed with the Federal Energy Regu-latory Commission ("FERC"). If a new IIC is filed with FERC after the start of a contract year, the Resource Classification List shall be amended to reflect the System Peak-Hour Capability ratings contained in such new IIC as though they had applied at the time of the coincident one-hour integrated territorial system peak demand, and such amended Resource Classification List shall be used for all billings in the Contract Year subsequent to the requested effective date of such new IIC. If a ne,w generating resource is placed in commercial operation or an existing generating resource is retired after the start of a contract year, the Resource Classification List shall be amended to include or exclude the resource as appropriate as though the amended Resource Classification List were in effect at the time of the coincident one hour integrated territorial system peak demand, and such amended Resource Classification List shall be used for all billings in the contract year subsequent to the date of change of the resource. Capacity unavailable for partial requirements service by virtue of being sold off-system, and which cannot be recalled, will be excluded from the Resource Classification List in the same manner. Such capacity will continue to be excluded from the Resource Classification List as long as all cost responsi-bility and revenues associated therewith continue to be allocated to a class of service other than partial requirements service. Issued by George W. Edwards, Jr. Effective February 1, 1982 Executive Vice President Issued on April 8, 1982
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FERC"Elcctric Tcrlff' (Suparchding~ R5vic3d' Original Valume No. 2s Shaat No. ll-A) DETERMINATION OF MONTHLY ENERGY CHARGES Monthly energy charges shall be the sum of (a) the Unit Energy Char mer'ges by category, s energy as determined requirements above, by category; and multiplied (b) a Variable by the Custo-Operation and Maintenance Surcharge of $0.00192 per kWh multiplied by the Customer's total energy requirements. j CUSTOMER SURPLUS CAPACITY AND ENERGY Customer capacity resources excess to requirements in a cate-gory will be defined as Surplus Capacity. The Surplus Caaacity will be deemed to be in the particular Customer resource highest in such category of the Resource Classification List. Surplus Capacity will be reclassified to the next higher category and will be treated as capacity in the new category with regard.to back-up energy and reserve requirements for that capacity. l Energy associated with Surplus capacity will be reclassified and credited to the Customer's Energy Requirement in the next higher category. Prior to February 1, 1983, surplus energy in a category will exist if the energy from the Customer's resources in that category (including any reclassified resources) and back-up - energy exceeds the Customer's requirements in that category. Any such surplus energy will be credited pro rata to the Customer's back-up energy requirements in lower categories. Effective February 1, 1983, surplus energy associated with a Customer-owned resource will exist if the energy generated by such Customer-owned resource exceeds the ten-hour continuous rated capability of the resource, as determined by the Company, times the number of hours in the-billing period, times the load factor of the base, inter-mediate or peaking portion of the Customer's load duration curve, as appropriate. Any such surplus energy will be purchased by the Company at the owner's actual fuel cost plus actual unit variable operation and maintenance cost. In the event a Customer gives a notice to the Company (at least two months prior to the filing of a change in partial requirements rates) of that Customer's intention of selling off-system a specified quantity (in kW) of Surplus Capacity and associated energy, the Company's charges contained in such filing will reflect such anticipated sale. Thereafter, during the period such charges are in effect, the Customer will receive no capacity credit for the amount of capacity contained in such notice or for any additional Surplus Capacity which is sold off-system. TERMS AND CONDITIONS
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Service su and Conditions,gplied hereunder and said shallConditions Terms and be subject toincorporated are the " Terms herein by reference. Issued by George W. Edwards, Jr. Effective February 1, 1982 Executive Vice President Issued on April 8, 1982
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G:orgio Powar Comprny R; vised Sh;ot Na 20 FERC Electric Tcriff , (Sup3rcading R visad Original Volume No. 2 Shaat Na. 20) If the Company is unable to meter or does not have adequate metering for Customer-owned resources, the Customer will certify to the Company in writing within five (5) days of the end of each month the kW and kWh delivered to the Customer from each such resource during said month. A Customer shall receive billing credit for jointly planned Customer-owned reserve resources in an amount equal to the rated capacity of the resource times the unit charge for , reserve capacity contained in the effective partial requirements tariff. Energy generated by such jointly planned Customer-owned resource shall be purchased by the Company at the owner's actual fuel cost plus actual unit variable operation and maintenance cost.
- 10. Determination of Capacity Requirements (a) The Company shall date the 44 hours on each side of each of the 10% and 80% of total times points on the Territorial Load Duration Curve. The Customer's load coincident with the maximum one-hour integrated territorial system peak demand shall be the Customer's total unreserved capacity requirements. The load level represented by the Customer's average load during the 44 hours on either side of the 80% of total time point in the Territorial Load Duration Curve, multiplied by the ratio of the territorial load at such 80% point to the average of the territorial load within such 88-hour band, shall be deemed the Customer's Base Load Level, and shall represent the Customer's base load requirements. The load level represented by the Customer's average load during the 44 hours on either side of the 10% of total time point on the Territorial Load Duratiod Curve, multiplied by the ratio of the territorial load at such 10% point to the average of the territorial load within such SS-hour band, shall be deemed the Customer's Inter-mediate Load Level and the' Customer's intermediate load requirements shall be the difference between the Customer's Intermediate Load Level and Base Load Level. The Customer's peaking load requirements shall be the difference between the Customer's total unreserved capacity requirements.(determined as described abcve) and the Customer's' Intermediate Load Level. Reserve requirements shall be calculated as set forth in the Rate Schedule. All capacity requirements determinations shall be reduced by the Customer's SEPA capacity' allocation, if any. The Custcmer's Capacity Require-ments as adjusted for SEPA capacity shall be further adjusted for average transmission system demand losses by dividing the Customer's Capacity Requirements by a factor of .947.
(b) At the start of a contract year the capacity requirements determination shall be based on the Territorial Load Duration Curve and the Customer's hourly load data for the most recent con-tract year available. The operation described in Section 10(a) above will be applied to this data, and the ratios of base, inter-mediate and peaking requirements to total capacity requirements will be determined. Issued by George W. Edwards, Jr. Effective February 1,1982 Executive Vice President through May 31, 1982 Issued on April 8,1982 I
~ ~ ~
w ut %toon u9B E D Ets. N Sh3ct N3. IU) If tha Compcny is unsble to motor or doss not hava ed:qu:ta metering for Customer-owned resources, the Customer will certify to the Company in writing within five (5) days of the end of each month the kWsaid during and month. kWh delivered to the Customer from each such resource A Customer shall receive billing credit for jointly planned Customer-owned reserve resources in an amount equal to the rated capacity of the resource times the unit charge for reserve capacity contained in the effective partial requirements ~ tariff. Energy generated by such jointly planned Customer-owned resource shall be purchased by the Company at the owner's actual fuel cost plus actual unit variable operation and maintenance cost. I
- 10. Determination of Capacity Requirements
, (a) The Company shall date the 44 highest hours and the 44 hours on each side of each of the 10% and 80% of total time points on the Territorial Load Duration Curve. The load level represented i by the Customer's average load during the 44 highest load Sours in ' the Territorial Load Duration Curve, multiplied by the ratio of the , territorial peak hour load to the average of the territorial loads during the highest 44 hours shall be deemed to be the Customer's Total Unreserved Capacity Requirements. The load level represented by the Customer's average load during the 44 hours on either side of the 80% of total time point in the Territorial Load Duration Curve, multiplied by the ratio of the territorial load at such 80% point to-the average of the territorial load within such 88-hour band, shall be deemed the Customer's Base Load Level, and shall represent the Customer's base load requirements. The load level represented-by the Customer's average load during the 44 hours on either side of the 10% of total time point on the Territorial Load Duration Curve, multiplied by the ratio of the territorial load at such 10% point to the average of the territorial load within such 88-hour band, shall be deemed the Customer's Intermediate Load Level and the Customer's intermediate load requirements shall be the difference between the Customer's Intermec.iate Load Level and Base Load Level. The Customer's peaking load requirements shall be the difference between the Customer's Total Unreserved' Capacity Requirements (determined as described above) and the Customer's Intermediate Load Level. Reserve requirements shall be calculated as set forth in the Rate Schedule All capacity requirements determinations shall be reduced 7 the Customer's SEPA capacity allocation, if any. The Customer's Capacity Requirements as adjusted for SEPA capacity shall be further adjusted for average transmission system demand losses by dividing the Customer's . Capacity Requirements by a factor of .947. (b) At the start of a contract year the capacity requirements l determination shall be based on the Territorial Load Duration Curve i and the Customer's hourly load data for the most recent i I; Issued by George W. Edwards, Jr. Effective June 1, 1982 Executive Vice President Issued on April 8, 1982 f
.a .
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m--- - q Ge:rgin Pow:r Company. R viscd Shrce No. 20-A L FERC Elcctric Tcriff (Sup3rsading R2vissd' Original Volume N3. 2 ' Sh nt No. 20-A) contract year available. The operation described in Section 10(a) above will-be applied to this data, and the ratios of base, inter-L mediate and peaking requirements to total capacity requirements will be determined. These ratios will be applied to a forecast of the Customer's Total Unreserved Capacity Requirements. When actual data become available for the contract year immediately preceding the current contract year.and when actual maximum one-hour inte- ,,, grated territorial peak demand data for the current contract year become available,the capacity requirements determination shall be recalculated based upon such actual data, and all prior and subse-quent billings during the current contract. year shall be adjusted and rebilled an necessary to reflect such revised capacity. require-ments. As soon as actual data become available for the entire 4' current contract year, the capacity requirements determinations
.shall be recalculated again based upon such actual data and each-bill rendered during the contract year shall be recalculated to reflect such revised capacity requirements. A special bill shall be rendered to each Customer as soon as practicable reflecting the aggregate difference between the bills rendered to each Customer-
, and bills based upon the actual contract year data. As between the Company and each Customer, whichever party owes the other as a result of such recalculation shall make payment (s) to the other as follows: the paying party may elect to spread the. total amount owed in equal installments over a number of months (not to exceed 12 nor to extend beyond the period the respective Customer takes service hereunder); provided, the amount of each such installment i except the last shall not be less than One Million Dollars 1 ($1,000,000). If the paying party elects to pay in installments, the unpaid obligation shall bear simple interest equal to the-interest borne by current 30-day U. S.. Treasury Bills on the first business day of each month that payment is deferred.
- 11. Categorization of Hydro Capacity and Energy
~
Hydroelectric capacity and energy will be categorized as set - forth in this section. (a) Pumped storage hydro capacity will be categorized as 40% Peaking and 60% Intermediate. J (b) Energy used in pumping and costs attributed to it by the Southern Pool are identified. For partial requirements bill- ' ing purposes this energy is deemed to have been generated by Company coal-fired units, the respective amounts being calculated
'in the following manner:
4 The Company coal resources with their corresponding net energy generation anounts and associated fuel dollars after subtracting sales off-system are arranged in order of increasing fuel cost. The total pumping energy a:Iount Issued by George W. Edwards , Jr. Effective June 1, 1982 Execut've Vice President Issued on April 8, 1982
Czargin Powdr Compnny Rsvicod Shoot No. 20-D i FERC Elcctric Tcriff (Supars ding - R: vised Original Volume No. 2 Shoot No. 20-D) capacity will in no way affect the " DETERMINATION OF CAPACITY RESERVES" as set forth in the Partial Requirements tariff. ! 12. Categorization of Customer's SEPA Capacity and Energy On the Customer's contract year load duration curve, the Base and Base plus Intermediate kW levels will be identified. Peaking, y for the ourposes of this SEPA categorization, will be the maximum demand shown on this curve less the Base plus Intermediate amount. ! The Customer's contract year load duration curve will then be adjusted by subtracting capacity from the Base category and accom-panying energy at base category load factor in an amount necessary to make the load factor of the remaining curve equal to the capacity factor of the SEPA resource. This capacity amount will be identified by the formula A" E - SCH H (B-S) where X = the capacity in kW to be subtracted from Base. E = the total metered energy under the customer's annual load duration curve. Total Annual Enargy Allocation S = SEPA capacity factor Cap. Allocation x Hours in Year B = Annual load factor of Base category of customer's loaC duration curve. H = Number of hours in tae contract year. C = Maximum kW level indicated on the Customer's annual load duration curve. This adjd8ted curve will contain Peaking and Intermediate energy and capacity equal to the original curve and base capacity and energy remaining after subtraction of the calculated values. The amounts of capacity and energy by category from this adjusted curve will then be expressed as percentages of the total adjusted curve, and the Customer's SEPA resource will be categorized by multiplying the annual SEPA capacity allocated by the capacity percentages, and the annual SEPA Energy Allocation by the energy percentages. On a monthly basis, the Customer's SEPA energy allocations in Peaking and Base will be categorized by multiplying the total annual SEFA energy for each of those categories by the ratio of the Customer's monthly metered energy in the respective category to the Customer's total annual energy in that category. Inter-mediate SEPA energy will be the difference between the SEPA energy allocation for that month and the sum of that categorized as Base and Peaking. Issued by George W. Edwards, Jr. Effektive June 1, 1982 Executive Vice President Issued on April 8,1982 '
.: .x. -
- 1. - As
s' , (Georgin Powar Company Rsvised Shnet No. 20-E FERC Eloctric Tcriff (Superseding -
' Original Volume No. 2 .
r For monthly billing of a vear in progress, annual energy in a category of the Customer's metered load will be estimated. .After the.end of the contract year, the estimates will be replaced with actual data and the allocations recalculated.
- 13. Amendments
& Nothing contained herein shall be construed as affecting in any,way.the right of the party furnishing service under this rate i.- schedule to unilaterally make application to the Federal Energy
' Regulatory Commission for a change in rates under Section 205 of the Federal Power Act.and pursuant.to the Commission's Rules and Regulations promulgated thereunder.
s l J Issued by George W. Edwards, Jr. Effective June 1,1982 Executive Vice President ] 1 0, Issued on April 8. 1982 a.mmra_aum. _.. a ___ x._. m_.._ _ s , _ . _ _ _ . ___,__m_ _ ,_
n 0584 9515 5152 425 3 e 7200 3521 528 135 0 v 663 337 109 1 - o 1 1 - 2 . N . r e b 4396 3711 4183 11 8 0 o 2384 0315 3352 605 2 t 5703 3823 326 895 3
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- s m 1786 7568 7209 5448 te Vv e 9673 8515 2529 0719 0921
[s n 5 2,2 1 3475 224 R81 u - 326 1888 J 551
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5 $ - $ 3 $ NI 1 ADD Pt u y 2563 5804 5577 6478 4622 2025 1652 4308 e s 4870 2373 224 7478 M RDtse t M, 350 225 685 C1 5t $ $ $ $$ 1 uMa~ Rgfm) $ 1 [rf s r a e PL a Mnt '0 e0 1 1 4363 2306 8277 6377 5936 2924 7456 1603 Ats0 r 5375 2272 124 8772 A! yv( p A 450 225 '6861 I iLe GnEP 1 $ $ $' $
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T 225 1887 S a 561 1 I 8 M 5 1 S0 YF L AS NE y 7861 5678 6422 8851 AT A r a 8808 9572 3778 4577 4623 326
- 6200 4577 M u 1181 I r 754 326 5 1 2 T b 1 $ - $ $
S e $ $ E F y 1843 7726 2282 0741 r 81 44 7244 3734 9123 a 8021 3150 225 2407, u 326 1089 n 753 1 1 a 1 $ 5 $ $ J $ $ $ $ r 0381 2147 e 8547 4329 b 3240 4701 4331 2383 m 8526 3767
- 326 2609 e 225 1988 c 652 $ 1 e 1 $ $ $
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y e o y R y Og y o 0g R i 0g 0g G t t C r A r i r p .re yP eeyE eeym eeyR i i ntO l nt I l ntD Rl ntP r bEi bEi b[i Pb[i c a cl a cl na cl l la l e cl a s il aa il aa ol l ea e r ept 6rept t r ept ar eot ua o t e ec D Ca uao PvFCT C Aa uao EvFCT M lWFCT e
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x .g w - 'Y NOTE TO REVENUE COMPARISON The foregoing revenue comparison indicates that the settlement v tariff will increase Georgia Power Company's partial require-
-ments revenues by $17,693,000 a's follows:
Variable. 0 & M (non-fuel)- $ (609,000) Fue1 1,920,-000-Capacity 16,382,000 Total $17,693,000 From the' customers' standpoint, however, this comparison does-not reflect the effect of recategorizing Plant Scherer from. an Intermediate to a Reserve resource, an- *2 Company's agreement to buy a customer's Scherer c. ,., at his actual fuel and 0 &.M-cost. - Recognizing. the effeet .of this change.. on variable 0 & M and fuel produces the following net increase: Variable 0 & 11 (non-fuel) $ (872,000)
. Fuel (1,184,000)
Capacity- 16,382,000 Total $14,326,000 h
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- ~ ~ .- - - - . . . . - . _ . - - _ - _ _ _ -. c_ _a
R E y" , i-N y Docket No. ER81-730-000 p
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. Georgia Power Company C
333 Piedmont Avenue P. 0; Box 4545 Atlanta, Georgia 30302 4- Attention:- George W. Edwards, Jr. o
~ Gentlemen:
On April. , 1982,-your Company submitted a unanimous proposed settlement agreement regarding settlement of the
. issues rained in the Partial Requirements (PR-6) wholesale rate' increase in this. Docket; Staff fileo comments in support _of this settlement agreement.. Based'on Staff's analyses, the. earned rate of return under the. proposed settlement agreement will not exceed Staff's-recommended settlement % rate of return, with. %'on common equity and a common equity ratiofof The proposed settlement agreement appears to be just uand reasonable and is in the public interest. Accordingly, the' settlement tariff sheets,. copies of which are attached to this order,'are approved. In accordance with the terms of the agreement, within 30 days.after Commission acceptance i of the revised settlement rate schedules, all amounts col-lected in excess of the settlement rates must be refunded !
with interest as provided in Section 35.19a of. the Commission's Regulations.- Within 15 days after refunds have been made, l please file with t,his Commission a compliance report showing , monthly billing determinants and revenues under prior,- i present.and settlement rates; the monthly revenue refunds; and the monthly interest computation toge.ther with a summary of'such information for the total refund period. A copy of such report shall also be furnished to the Georgia Public ' Service Commission. ; 1 The Commission's approval of this settlement shall not constitute ap7roval of or precedent regarding any principle , or issue.in'this proceeding. Upon satisfactory completion of'these requirements, Docket No. ER81-730-000 is terminated. 1 4 ! xmm= - 1
m 9: Georgia Power Company-Attention: ~ George W. Edwards,'Jr. Docket No. ER81-730-000 Page Two By direction of the Commission. b. r Secretary-cc: Mr.. Robert H. Forry Troutman, Sanders, Lockerman
& Ashmore 1400 Candler Building Atlanta, Georgia 30043 W
l l 4 4 f L. ._,c._ m-_._ m ._ .. _..o. _ .m_ _. __. ._ _m 1_ : ._iz_ m
a b y. VERIFICATION Robert H. Forry, first being duly sworn, deposes and says: that he is an attorney for Georgia Power Company; that he has read _the foregoing document and is familiar with the contents thereof; that as such attorney he is authorized to file such F document on' behalf of Georgia Power Company; and that the_ state-ments of' fact. contained therein are true and correct to the best of his knowledge, information and belief. ROBERT H. FORR Sworn to and subs before-me this @Lgribed ' day of /1,A l , 1982. . fJL arn<L 4 Notary Public. Notary Pettic Cecch. '"'t r:" My Ccmmm.on Op.ta ~.. . , .M CERTIFICATE OF SERVICE I hereby certify that I have this day served the foregoing document upon each person designated on the official service list compiled by the Secretary in this proceeding in accordance with the requirements of Section 1.17 of the Rules of-Practice i and Procedure. q DatedinAtlanta,Georgiathish ay of w b , 1982.
~v s
ROBERT H. FORRY W ' I l m_m _. s m_ mz _ _ _ _ . - - _ __ 1
c. AGREEMENT THIS AGREEMENT is made and entered into by and among Georgia Power Company ("GPC"); Oglethorpe Power Corporation (an Electric 3 Membarship Generation and Transmission Corporation) ("0PC"); the Municipal Electric Authority of Georgia ("MEAG"); and the City of Dalton, Georgia, acting by and through its Board of Water, Light ,, and Sinking Fund Commissioners (" Dalton") . All of the foregoing r except GPC are sometimes collectively referred to herein as
" Customers." . E1IEESSEIg:
WHEREAS, the parties hereto have executed as of this date a Settlement Agreement disposing of the issues with respect to Federal Energy Regulatory Commission ("FERC") Docket No. ER81-730-000 ("PR-6"); W1EREAS, the parties desire to memorialize their agreement as to the interpretation of certain provisions of that Settlement Agreement and the revised PR-6 tariff sheets filed pursuant thereto; and WHEREAS, the parties desire to provide for the future accounting treatment of certain transactions involving or affecting them. NOW, TREREFORE, in consideration of the mutual promises contained herein and with the agreement that each provision of this Agreement is in consideration and support of every other provision, the parties hereby agree as follows: w m__._ _.m._m___ _ . _ _ _ _ _ _m _ _ . _ _ . .__ _ -- _m . h._
L R .
- 1. OFF-SYSTEM TRANSACTIONS
- 1.1' The parties agree that for purposes o'f calculating the cost of partial requirements service in future partial require- !
ments' rates, certain unit power sales and similar transactions ..; should be treated as a separate class of. service distinct from- ! i partial requirements and retail service. That is, the capacity, investment, expenses and revenues associated with such transactions , 7., shall be allocated to such other class of service and will not be , included in partial requirements rate determinations. The parties agree that the general principles set forth above and the specific l examples which follow apply to the unit power sale agreements between the affiliates of The Southern Company system (including GPC) and Florida Power & Light Company ("FP&L") (dated February
.19, 1981) and Jacksonville Electric Authority ("JEA") (dated February 27, 1981), which contracts are the subject of FERC -
Docket No. ER81-678-000 ("UPS Contracts") . (a) The amount of Plant Scherer capacity set forth or calculated in the UPS Contracts as being sold Enr GPC to FP&L and JEA shall be excluded from the Resource Classification List i utilized in the partial requirements tariff. Such capacity sales will be treated in the same manner and as of the same date as capacity additions and retirements are treated on Revised Sheet No. 7 of the partial requirements tar 1ff, a copy of which is
. attached to the PR-6 Settlement Agreement. l (b) All costs (whether investment- or expense-related) associated with the unit power sales as identi#ied in the Unit Power Sale Periodic Rate Computation Procedure Manual of Scuthern 4 ? -
l Em _.'MlMO km....E 3 . NC - mi._..m_ _ .L - _ s_..m - nE _ m- .A 5 i A ., ..m9 s l
V t Companies (" Manual"), copies of which are attached to each 'UPS Contract, shall be allocated to unit power sales service, and no responsibility therefor shall be' assigned to partial requirements customers or otherwise included in partial requirements rates in y, future partial requirements rate determinations. (c) All revenues (whether production- or energy-related) received by GPC from FP&L and JEA under any provision ( of the UPS Contracts or Manuals shall be allocated to unit power sales service, and no credit therefor shall be assigned > to partial requirements customers or otherwise reflected in partial requirements rates in future partial requirements rate determinations. 1.2 The parties acknowledge that they have been unable to agree on a method for treating the capacity, invest-ment, expenses and revenues of certain reca11able bff-system sales, commonly referred to by the parties as " Schedule 'E' Sales," in which GPC participates pursuant to Service Schedule "E" of the interchange contracts between affiliates of The Southern Company system '(including GPC) and certain other parties, which service schedules were the subjects of FERC Docket Hos. ER80-160, ER80-243, ER80-262, ER80-343 and ER80-415. The parties expressly acknowledge that they have not agreed upon the use of either the accounting treatment set forth in Section 1.1 above, or any other particular treatment, in accoanting for Schedule "E" sales in future partial require-ments rate determinations. 3- i 1 l 1 h,_ _,m, _mm __m__ J _ A N' -- D'- -- I dEd 1 - " ^- -- --- '-- " ' - - - - - " -
L. 9 - 1.3' The parties' acknowledge that GPC is presently
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' negotiating additional unit power sales agreements and may engage in unit; power sales or similar transactions in the future. The parties agree that any future transactions which are substantially similar to those pursuant to the UPS Contracts shall be accounted for in partial requirements rate determinations in substantially.
the same manner as provided in Section 1.1, above. 1.4 In the event GPC engages in any other off-system ' transaction which rendere capacity unavailable for partial
~
requirements service by virtue of being non-recallable, the (. parties igree thatithe capacity, investment, expenses and reve-nues associated with such transactions will be allocated to'such other class of service and will not be included in partial requirements rate determinations. Such allocations shall be made,on a basis which is just and reasonable and not unduly
~
discriminatory to partial requirements customers. 1.5 'In developing cost of service studies for future partial requirements rate determinations, GPC shall utilize the most current reasonable' estimates of future offisystem transac-tions then available to it, such as letters of intent or contracts with prospective purchasers. 1.6 Sections .l.1 through 1.5 of this Agreement shall terminate and become null and void with respect to any unit power sale or similar transaction, as defined above, for which GPC voluntarily provides a revenue credit in a retail rate filing.
- 2. TAX ON SALE OF PROPERTY 2.1 The parties acknowledge that GPC is presently
. __ - : =-_ .. :. - x , - +
~
negotiating the sale of a portion of its undivided interest in i Plant Vogtle (up to 16.5% of the plant) to one or more entities in " { Florida and that such a sale or sales, if any, may or may not occur ' during:the PR-6 test period. The parties agree that GPC may incur ) J federal and state income tax expense as a result of any such sales. ! l 2.2 The Customers agree to make a one-time cash payment to GPC in respect of GPC's tax expense, if any, associated with any such asset sales. At the time GPC makes refunds pursuant to the PR-6 Settlement Agreement, or upon demand if no such refunds are required to be made, the Customers agree to make one-time cash payments to GPC in the following amounts: Dalton $ 8,500 MEAG $ 105,500 OPC $ 204,000 2.3 GPC agrees that the payments described in Section 2.2, above, shall be in lieu of any other obligation the Customers may have in respect of any GPC income tax liability resulting from the asset sales identified in Section 2.1, above. GPC further agrees that it shall not include any such income tax expense (associated with the sale of up to 16.5% of Plant Vogtle) as a cost of service in any future partial requirements rate.
- 3. MISCELLANEOUS 3.1 The parties agree to engage in good faith negotia-tions in an effort to place a new power supply relationship into effect by February 1, 1984.
3.2 This Agreement shall be binding according to its terms upon all parties, their agents, successors and assigns. 1 l V - . .x .x. - .. . _ . - ... .- .__- : _. _.-_ -_a
3.3 The parties agree to file such pleadings and make such representations as may be reasonably requested to the end that the agreements contained herein be given effect by any court, agency or other authority having jurisdiction over any relationship among or between the parties. IN WITNESS WHEREOF, the parties have caused this Agreement to be executed, effective April 8, 1982, by their duly autho- ' rized officers in multiple counterparts, each of which shall together constitute and are the same instrument. GEORG1A POWER COMPANY By: /s/ A. W. Dahlberg, III Vice President, Operations Planning and Control i Attest: /s/ Guerry P. Strickland Assistant Secretary Witness: /s/ Vicki S. Norman (CORPORATE SEAL) OGLETHORPE POWER CORPORATION (An Electric Membership Generation & Transmission Corporation) By: /s/ F. F. Stacy General Manager Attest: /s/ Charles T. Autry Corporate Attorney Witness: /s/ Ali Bufkin (CORPORATE SEAL) l (Signatures Continued on Page 7) , 1
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F* MUNICIPAL ELECTRIC l AUTHORITY OF-GEORGIA By: /s/ Donald L. Stokley General. Manager Attest:" /s/ C. E. Newcomer, Jr. L _ Assistant Secretary-Treasurer. h.t c Witness: /s/ L. Clifford Adams, Jr. 'T
;s
'(CORPORATE SEAL).
y CITY OF " DALTON', Acting by and... 7 through its Board of Water, Light: and' Sinking Fund Commissioners Byl: /s/ James E. Brown Attest: /s/'DeForrest'Parrott~ Witness: /s/ Linda Carlisle 6 (CITY SEAL) O d q q 1 i l ' LSEN Ll s e .' wAa - - a a L. . ..a. '. - , ,- .,.a- -
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AP 30 se > #e ue O *N aC 1 AAT One ATTORNcYS AT. L AW CANDLER SutL0tNG. SUITC esOO (27 PLACHTREE STRCCT, N.E. i werfge's DistCT DEAL RUtf4CR
-DCERT H. VoRRY ese-eose
* * * * * * *l
- November 10, 1982 Honorable Kenneth F. Plumb Secretary Federal Energy Regulatory Commission Room 9310 825 North Capitol Street, N.E.
Washington, D. C. 20426 y' Re: ' Georgia Power Company ("PR-7") FERC Docket No. ER83-1-000
Dear Secretary Plumb:
Enclosed for. filing on behalf of Georgia Power Company in the captioned proceeding are fifteen conformed copies of a Settlement Agreement, the original of which was executed in multiple counterparts. Ill provisions.of the executed agreement filed herewith are identical to the unexecuted draft agreement which accom-panied the Company's Motion for Approval of Settlement Rates in Lieu of Tendered Rates and Request for Conditional Stay of Action on Tendered Rates, filed on October 22, 1982. Please note that revised tariff sheets required by the Settlement Agreement are also enclosed. You will recall that each of the Company's partial requirements customers has previously indicated its support of the settlement in separate. pleadings. If the Commission rec uires any addi-tional information, please contact the undersigned at the address or telephone number shown above. Yours very truly, b ~ - Robert H. For RHF/dwm cc: All Parties Robert L. Woods, Esquire
-m - m _._Lhnkt___L__-.__
' SETTLEMENT AGREEMENT i
1
.i THIS AGREEMENT is made and entered into by and among Georgia !
Power Company ("GPC"); Oglethorpe Power Corporation (An Electric ! Membership Generation & Transmission Corporation) ("0PC"); the. Municipal Electric Authority of Georgia ("MEAG"); and the City of Dalton, Georgia, acting by and through its Board of Water, Light
& Sinking Fund Commissioners (" Dalton") . All of the foregoing i except GPC are sometimes collectively referred to.herein as
" Interveners" or " Customers. " This Settlement Agreement relates to those matters relative to the. Company's partial requirements tariff ("PR-7 tariff") which are pending before the Federal Energy Regulatory Commission ("FERC") in Docket No. ER83-1-000
("PR-7"). Subject to agreement by all parties hereto to the provisions set forth in this Settlement Agreement and with the agreement that each provision of the Settlement Agreement is in considera-tion and support of every other provision, the parties hereby agree as follows:
- 1. DISPOSITION OF PENDING RATE PROCEEDINGS 1.1 The parties will advise the FERC forthwith that the parties have settled the issues with respect to FERC Docket
' No. ER83-1-000. The Interveners will file such pleadings and make such representations to the FERC and the FERC Staff as are requested by GPC to the end that FERC approval, according to the terms hereof, may be obtained as soon as possible. Nothing Md.u_L_ L_m_,. . ,. _ . , ,
contain d heroin'chall b3. construed to prohibit any party from' - filing;any' pleading'in furtherance of its interests under this ': Settlement Agreement; and nothing. contained herein shall be construed t'o require any party to - take any action not in its-Ebest intereses- in effectuating this Settlement Agreement.- t 1.2 :GPC shall file with the FERC-revised PR-7 tariff s sheet No. 6 revising the " Schedule of Monthly-Charges for i
- Capacity" delivered' pursuant to Rate Schedule PR-7, to be 0 effective February 1, 1983, to read as follows:
'" SCHEDULE OF~ MONTHLY CHARGES FOR CAPACITY
" Type of Service Monthly Charge b " Unreserved base capacity $8.30 per KW
" Unreserved intermediate capacity 5.32 per KW
" Unreserved peaking capacity 4.70 per KW
" Reserve capacity 4.76 per KW" It is - understood and acknowledged by the parties that GPC has utilized a 167. return on equity for the purpose of developing
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the settlement rates, and ;the parties agree, therefore, that l such rate of return shall be used in calculating all " buy-back" and " transmission parity" payments by one party to another 1 under the several contracts between the parties which refer l I to GPC's partial requirements return on equity. 1.3 GPC shall file with the FERC revised PR-7 tariff sheet Nos. 11 and 20 setting forth new loss factors of .9499 H and .'9604, respectively. 'l 1.4 It is understood, acknowledged and agree,d by the parties that the revised tariff sheets described in Sections 1.2 and 1.3 of this Settlement Agreement shall be effective 1 I 1 lw _ .-- . s .
l' from February 1, 1983 until changed pursuant to the Federal Power Act. E .
.l. 5 It 'is understood, acknowledged 'and agreed that all other provisions of the PR-7 tariff shall be effective as filed from February 1,1983, until changed pursuant to the Federal 1 Power c
Act. 1.6 Nothing contained in this Settlement Agreement shall be deemed to preclude GPC from filing.with the FERC a notice of Lan increase in rates or other change in the PR-7 tariff pursuant to Section 205 of the Federal Power Act, however, no such change shall be effective.for service rendered prior.to February 1, 1984. 1.7 In further explanation of the rate change moratorium referred.co in Section 1.6 of this Settlement Agreement, it is-understood, acknowledged and agreed that if GPC files revised partial requirements rates on July 1, 1983, the parties intend for those rates to become effective on. February 1, 1984. The i parties specifically agree as follows: 1 (a) GPC may tender for filing revised partial require- 1 ments rates pursuant to Section 205 of the Fe/nial Power Act on - or after July 1, 1983; (b) As required by Section 35.3 of the Commission's y l i Regulations, the revised tariff sheets contained'in any such filing will state an effective date earlier than February 1, 1984; (c) If GPC files revised partial requirements rates on July 1, 1983, the parties agree to file such pleadings as are j m .: .-
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necessary to obtain a February 1, 1984 actual effective date, subject to refund, for such revised rates. Such pleadings may ^ include requests for waiver of the notice period provided for in the Federal Power Act and the Commission's Regulations, t requests for specific suspension periods other than one day or five months and other similar pleadings or representations as may be required to obtain a February 1,1984 effective date (subject to refund) for revised rates filed on July 1,1983.
- 2. REFUND OBLIGATIONS 2.1 GPC shall refund to OPC, MEAG and Dalton a portion of the revenues collected under PR-7 for the period February 1, 1983, through the date of refund as follows: GPC will refund to each Customer the difference between the payments actually received from such Customer, if any, and the payments which would have been received if the revised monthly charges described in Sections 1.2 and 1.3 of this Settlement Agreement had been La effect.
2.2 All refunds shall be paid prior to 10 a.m. on a business day in immediately available funds and shall be computed for each billing period or portion thereof. Interest with respect to such refunds shall be calculated pursuant to FERC Order No. 47, as amended (Order Nos. 47-A and 47-3, issued November 8,1979 and December 26, 1979, respectively).
- 3. COMPROMISE AND SETTLEMENT 3.1 The parties hereby agree that execution of this Settlement Agreement is solely for purposes of compromise and
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- settlement and:in no way constitutes any admissions, nor does
*1 ici represent- a retreat from theLoriginal positions taken. by any? '
party;with# regard to the . subject matters hereof or acceptance
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of-any principle of rate design or'ratemaking, cost' allocation,- {
- or inc1'usion-or exclusion of' items.in cost of service.
y L 3.2 The execution of this Settlement Agreement esta-4 blishes no principles and shall not be deemed to foreclose any party from making any contention in'any other proceeding. In' any future proceeding or. proceedings relating to rates, charges', terms and conditions of ' service and any matter other than a procaeding involving the honoring or enforcement of this Settle-ment Agreement, the parties shall not be bound or prejudiced
. by this Settlement Agraement, except to the extent expressly provided herein.
3.3 The approval'of'this Settlement Agreement by the FERC:shall-not in any respect constitute a determination by
; the:FERC.as-to the merits of any allegation or contention of GPC, the Interveners or the Staff in this proceeding.
3.4 The discussions between GPC, the Interveners and'the Staff which have resulted in this Settlement Agreement have been conducted on the explicit understanding, pursuant to Rule 602(e) of the FERC's Rules of Practice and Procedure, i
. that all offers of settlement and discussions relating thereto, are and shall be privileged, and shall be without prej udice to
. the. position of the parties, and are not to be used in any manner in connection with this proceeding or otherwise. This
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; Settlement Agreement- is executed on the same explicit understand-Ling and on the further condition that in the event the FERC does not. by. order accept this Settlement Agreement in its entirety, 1 any. party having~a direct. interest in such failure of approval may, at_its option,: cancel _this Settlement Agreement in its-entirety and withdraw or cause to be withdrawn all pleadings and other filings made with the FERC in connection-therewith.
IN WITNESS WHEREOF, the parties have caused this' Settlement Agreement to be executed,. effective as of October 22 , - 1982, by
- their duly authorized officers in multiple counterparts, each of which shall together constitute and are the same instrument.
r GEORGIA POWER COMPANY By: /s/ A. W. Dahlberg, III Attest: /s/ Charles L. Ratterree Witness: /s/ V. S. Norman (CORPORATE SEAL) OGLETHORPE POWER CORPORATION (An Electric Membership Generation & Transmission Corporation) By: /s/ F. F. Stacy Attest: /s/ G. Stanley Hill Witness: /s/ J. Fred Jones (CORPORATE SEAL) (Signatures Continued on Page 7)
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- Ge;rgic' Power Company Rtvissd.Shsat No..6 FIRC Elcctric Teriff- (Superseding Revised Original V0lume N3.-2 Sheat Ns. 6)
Intermediate Load shall.be the intermediate
?ortion of a load duration curve which lies T 3etween the peaking load level and the base load level.
MONTHLY BILL , - The' monthly bill shall consist of charges for contract capacity by category, reserve capacity by category, energy by. category, and their-back-up energy as used for reserv-ing Customer-owned generating resources which result from joint planning with the Company. SCHEDULE OF MONTHLY CHARGES FOR CAPACITY Type of Service Monthly Charge Unreserved base capacity $8.30 per KW
- Unreserved intermediate capacity 5.32 per KW Unreserved peaking capacity 4.70 per KW Reserve capacity 4.76 per KW
. -DETERMINATION OF RESOURCE CLASSIFICATIONS Prior to the beginning of the contract year, the Company shall prepare a Resource Classification List comprised of all territorial capacity resources listed inl order of ascending variable incremental energy costs (e..i determined for the purposes of the Southern system pear: pool) such that the ,
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capacity resource with the lowest variable.increme.ntal energy cost is at the. bottom of the list and the capacity resource with the highest variable incremental energy cost is at the ; top of the list, except that those capacity resources, includ-J ing hydroelectric resources, whose operating characteristics q require. that they be operated as base, intermediate, peaking or reserve capacity resources shall be assigned to those I respective categories without regard to variable incremental energy costs. Starting at the bottom of the Resource Classi-
' fication List, the territorial capacity resources whose aggregate sum of System Peak-Hour Capabilities (as determined for the purposes of the Southern system power pool) equals the 1
- Issued by George W. Edwards, Jr. Effective February 1, 1983 J Executive Vice President Issued on October 22, 1982 i
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Ge:rgia Pcwcr C:mpany Revisad Shoot No. 11 FERC Elcceric Teriff (Suparsading Revisad Original Volume No. 2 Sheet No. 11) Customer-owned generating resource. The back-up energy shall be J deemed to have been supplied by a pro rata share of the surplus energy from each category above the category requiring the back-up energy. The deficit energy in each category not generated by Company s resources in that category shall be deemed to have been supplied by a pro rata share of the surplus energy remaining after provision for back-up energy for Customer-owned resources from each category above the category requiring the deficit energy. The weighted average cost of all energy thus assigned to each category, including back-up energy, shall be the Unit Energy Charge for energy in each category to be billed to the Customer. DETERMINATION OF CUSTOMER ENERGY REQUIREMENTS The Company shall determine the Customer's monthly energy use by eategories from the Customer's monthly load duration curve in the following manner. The base load energy use shall be the kilowatt hours represented by the area of the monthly load duration curva which lies below the Customer's Base Load Level coincident with the integrated territorial base load level. The peaking load energy use shall be the kilowatt hours, if any, represented by the area of the monthly load duration curve which lies above the ! Customer's Intermediate Load Level. The intermediate load energy use shall be the kilowatt hours represented by the area of the monthly-load duration curve which lies between the Customer's Intermediate Load Level and Base Load Level. Customer Energy Requirements as determined herein shall be l reduced by the Customer's SEPA energy allocation, if any, and J shall be further adjusted for Customer-owned resources and l Customer-purchased resou'rces. The Customer's Monthly Energy j Requirements shall be further adjusted to account for average , transmission system energy losses by dividing the Customer's Monthly Energy Requirements by a -factor of . 9499. Initially, the Customer's estimated contract year hourly load data shall be utilized in the energy requirements determina- ! tion set forth above. When actual data is available, the ]' Customer's actual contract year hourly load data shall be utilized in recalculating all energy billings during the Contract Year. 1 I Issued by George W. Edwards, Jr. Executive Vlee President Issued on October 22, 1982 Effective February 1, 1983
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@Biginal Wolume'No. 2
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~Shh5t 5o!~20) l If th2 Company is unable to meter or doos not hava ad:quzte metering for-Customer-owned resources, the Customer will certify to )
'the Company in writing within fivo (5) days of the end of each month 1
' the kW and kWh delivered to the customer from each such resource during said month. A Customer shall receive billing credit for jointly. planned Customer-owned reserve resources in an amount equal to the rated capacity of the resource times the unit charge for l reserve-capacity contained in the effective partial requirements tariff. Energy generated by . such jointly planned Customer-owned resource shall be purchased by the Company at the owner's actual fuel cost plus actual unit variable operation and maintenance cost.
- 10. Determination of Capacity Requirements (a) The Company shall date the 44 highest hours and the 44 hours on each side of each of the 10% and 80% of total time points on the Territorial Load Duration Curve. The load level represented by the Customer's average load during the 44 highest load hours in the Territorial Load Duration Curve, multiplied by the ratio of the territorial peak hour load to the average of the territorial loads during the highest 44 hours shall be deemed to be the Customer's Total-Unreserved Capacity Requirements. The load level represented by the Customer's average load during the 44 hours on either side of the 80% of total time point in the Territorial Load Duration Curve, multiplied by the ratio of the territorial load at such 80%
aoint to the average of the territorial load within such 88-hour sand, shall be deemed the Customer's Base Load Level, and shall represent the Customer's base load requirements. -The load level' represented by the Customer's average load during the 44 hours on either side of the 10% of total time point on the Territorial Load Duration Curve, multiplied by the ratio of the territorial load at such 10% point to the average of the territorial load within such 88-hour band, shall be deemed the Customer's Intermediate Load Level and the Customer's intermediate load requirements shall be the difference between the Customer's Intermec.iate Load Level and Base Load Level. The Customer's peaking load requirements shall be the difference between nhe Customer's Total Unreserved Capacity Requirements (determined as described above) and the Customer's l Intermediate Load Level. Reserve requirements shall be calculated as set forth in the Rate Schedule. All capacity requirements determinations shall be reduced by the Customer's SEPA capacity allocation, if any. The Customer's capacity Requirements as adjusted for SEPA capacity shall be further adjusted for average transmission system demand losses by dividing the Customer's Capacity Requirements by a factor of .9604. (b) At the start of a contract year the capacity requirements determination shall be based on the Territorial Load Duration Curve ' and the Customer's hourly load data for the most recent
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Issued by George W. Edwards, Jr. Effective February 1, 1983 Executive Vice President Issued on October 22, 1982
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-:" NRC Docket Nos. 30-424 and 50-425 I Construction Permit Nos. CPPR-108 and CPPR-109 j Vogtle Electric Generating Plant Units 1 and 2 l 1
Owners: Georgia Power Company, l Oglethorpe Power Corporation (An Electric Membership Generation ] .~
& Transmission Corporation), a Municipal Electric Authority of Georgia, i
, City of Dalton, Georgia {
i Information for Antitrust Review of Operating License Application
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INTRODUCTION - j 1 The following information is submitted pursuant to the requirements set forth in Nuclear Regulatory Commission Guide 9.3. The information has been compiled to assist the , NRC's staff in determining whether an antitrust review is required as part of proceedings for the issuance of an operating license for Units l and 2 of the Vogtle Electric Generating Plant (" Plant Vogtle"). BACKGROUND Oglethorpe Power Corporation ("O51ethcrpe") is an electric generation and transmission cooperative formed under the laws of the State of Georgia in August 1974. The principal purpose of Oglethorpe is to serve as the power supplier for 39 electric membership
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corporations (" members" or 'tilstributbn cooperatives") which distribute electricity in primarily rural ar-s of Georgia. The aren served by these I? distribution cooperatives l covers approximate 4y 71% of the land area of the State. Eadl of these 39 distribution
' cooperatives has entered into a wholesale power contract with Oglethorpe lasting until the year 2022 pursuant to which Oglethorpe serves as the sole power supplier of its cooperative members, except for power received under individual member contracts with the Southeastern Power Administration.
Since 1975 Oglethorpe has acquired from Georgia Power Company an ownership interest 1 in certain- generating facilities located within the State of Georgia. Oglethorpe's i i ownership interest is as follows: 30% of Plant Edwin I. Hatch,30% of Plant Hal Wansley, c 30% of Plant Alvin W. Vogtle and 60% of Plant Robert Scherer, Units 1 and 2. Oglethorpe does not directly operate these facilities, but rather has entered into operating and maintenance agreements (" Operation Agreements") with Georgia Power Company under which Georgia Power Company acts as the agent for Oglethorpe in the operation and maintenance of the facilities. Oglethorpe does not currently own sufficient generating
. facilities to meet the electrical demands of its members and, therefore, continues to be a partial requirements customer of Georgia Power Company.
Oglethorpe is dedicated to achieving generation sufficiency on behalf of its 39 member system electric distribution cooperatives during the 1990s. 2000L ' L c,.
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- Sufficiency, as defined by Oglethorpe, means adequate base and intermediate generation capacity. . Peak load capacity will be evaluated in future studies but is presently planned.
( .to be met through purchased power arrangements due to economic considerations. - hn addition to'the ownership interests and Operation Agreements, Oglethorpe participates with Georgia Power Company, tht City of Dalton and the Municipal Electric Authority of Georgia in an Integrated ' transmission System. Under this arrangement each participant has equal access to a statewide transmission system. Each participant has an investment ' T responsib111ty in : the total territorial system relative ' to its expected use of the e transmission system. Oglethorpe,' Georgia Power Company, the City of Dalton and the Municipal Electric Authority of Georgia have formed a. Joint committee .in. order to f acilitate implementation of the contractual relationships among the various participants in these joint agreements. V., INFORMATION NEEDED BY THE NRC REGULATORY STAFF IN CONNECTION WITH ITS ANTITRUST REVIEW OF OPERATING LICENSE APPLICATIONS FOR NUCLEAR POWER PLANTS. , 1(a) Generating' Capacity Resources. Regulatory Guide 9.3 Describe anticipated excess or shortage in generating capacity resources not expected at the construction permit stage. Give
.. reasons for the excess or shortage along with data on how the excess will be allocated, distributed, or otherwise utilized or how ' the shortage will be obtained.
Oglethorpe's' Response , The Oglethorpe' peak demand projection, coincident with the Georgia territorial peak, is given in Table L The Oglethorpe. Peak Demand is measured at various delivery points and as such does not include transmisalon and transformer losses, in addition, a portion of the load is projected to be served by the Southeastern Power Administration ("SEPA"). The anticipated SEPA allocation is based on a proposed SEPA Marketing Policy.~ Changes to , the Marketing Policy are possible and may result in changes in the allocation of .SEPA resources. Table Illists the existing and projected resources of Oglethorpe. Oglethorpe jointly owns 9 units with Georgia Power Company, the Municipal Electric Authority of Georgia and the City of Dalton. Six of the units are on-line and three are presently under construction. Table II shows CPC retained ownership in generating units including the effect of unit sellback agreements between Oglethorpe and Georgia Power Company. Table III presents a comparison of Oglethorpe's peak demand as projected in April 1976 and in July'1983, Table III also presents projections of generating resources made in each of those two years. The major change between the April 1976 and July 1983 projections is change in projected future load growth, which reflects actual load growth experience. Projected generation resources have also decreased from 1976 projections due to a later irsservice date for Plant Vogtle and changes in Oglethorpe's ownership interest, the
~ in-service date and sellback schedules for Plant Scherer.
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rie l , In' April 1976, Oglethorpe had been in existence less than two years and no pan had been developed. to fully meet Oglethorpe's projected peak demand with owned generating
- + capacity. . Shortages in resources shown in the 1976 #an were expected to be satisfied
,with power purchased from Georgia Power Company. Oglethorpe has responded and pans to respond to this decrease in projected load growth in the future by reducing power >
purchases from Georgia Power Company. ' Reductions of purchased power from Georgia Power Company are still part of Oglethorpe's pans, but at an accelerated rate from 1976.' ' Despte the decrease in projected resources between the 1976 and 1983 plans, - ,' Oglethorpe currently projects that its resources will exceed peak demand in 1990, a date earlier than was projected in 1976.. 4 em e
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p b 1 TABLEI I Oglethorpe Power Corporation Demand Forecast
' ' " ^ July,1983 (MW)
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y s Losd Served Forecast of* - Projected SEPA Oglethorpe Load . by-
. Year . Peak Demand Allocation Not Served by SEPA Losses ** Oglethorpe 1983- 2035 296 1739 77 1816 L
1984 12122 548 1574 69 1643 1985 2195 578 1617 71 1688 1986 2268 578 1690 74 1764 1987 2371 .608 1763 78 1841 1988 2456 638 1818 80- 1898 1989 2527 638 1889 83 1972 1990 2603 638 1965. r,6 2051 1991 2658 638 2020 89 2109 1992 2711 638 2073 11 2164 1993 2756. 638 2118 93 2211
- Load measured at Oglethorpe's metering points.
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** Projected to be 4.4% of Oglethorpe's load not served by SEPA.
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TABLE !! f ~"- Projected Oglethorpe Generating Resources
- July,1983 (MW)
Plant Plant Plant Plant. Year ' Hatch Wansley Scherer Voztie Total p '1983' 379- 486 98 963 j.
'1984 403 521 195 1119 i{
-1985 434 521 293 1248' 1986- 465 521- 390 1376-1987 465 521 487 115 1588 1988 465 521 585 150 1721 1
-1989 465- 521 682 299 1967
-1990 465 521 779 368 2133
-437 1991 465. 521 877 2300 1992 ~ ~ 465 521- 925 518' '2429
'1993- 465 521 974 598 2558
- Resources available at the time of the projected peak load (contained in Table D. '
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TABl.E III Oglethorpe Projections of Peak Demand and Operating Resources Projected Peak Decrea:,e in Projected Generating Decrease in Demand (MW) Projected- Resources (MW) Projected Generating Year April,1976 July,1983* Peak Demand (MW) April,1976 July,1983** Resources (MW) 1976 :1518 191 1977 1699 241 1978 1904 378 1979 2138 335 1980 2407 644 1981 2710 847 1982 3054 1104 1983 3451 1816 1635 1451 963 488 1984 '3902 1643 2259 1842 '1119 723 1985 4429 1688 2741 2288 1248 1040 1986 5026 1764 3262 2443 1376 1067 1987 5705 1841 3864 2512 1588 924 1988 6475 1898 4577 2594 1721 873 1989 7349 1972 5377 . 2686 1967 719 1990 8341 2051 6290 2731 2133 578 1991 2109 2300 1992 2164 2429 1993 2211 2558
*To be served by Oglethorpe (see Table 1).
++From Table II.
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_ - - , _ - _ . _7 1(b). Power Pool or Coordinating Group Membership. Regulatory Guide 9.3 Describe new power- pools or coordinating groups- or changes in structure,
. activities, policies, practices, or membership of power pools or coordinating groups in which the licensee was, is, or will be a participant.
Oglethorpe's Response Oglethorpe is not a member of any power pool, but is a memb'er of the Joint Committee
- described in Georgia Power Company's submittal. Insofar as the information contained therein relates to Oglethorpe, Oglethorpe adopts the statement by : Georgia Power-
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1 3 ., <Q. , w 1(c) Chames in Transmission.
- Tegu atory Guide 9.3
< (2) Inter- connections, or (3) connections to wholesale customers.
4 Oglethorpe's Response N Insofar as thejnfor_mation contained therein relates to Oglethorpe, Oglethorpe adopts the statements by Georgia Power Company contained in its submittal pursuant to Regulatory-Guide 9.3. g tisk 9
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h. 1(d)' Changes in Ownership of Plant Hatch. l . Regu.atory Guide 92 h .-
-- Describe changes in the ownership or contractual allocation of the
- output of the nuclear facility. Reasons and basis for suchchanges should be included.
1 Oglethorpe'3s,Respon,se, .1 . i V Insofar as the information contained therein relates to Oglethorpe, Oglethorpe adopts the statements by Georgia Power Company contained in its submittal pursuant to Regulatory l- Guide 9.3. L . l ll
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e i 1 l l, 1(c) Rate Changes. i ! Regulatory Guide 9.3 J k Describe changes in design, provisions, or conditions of rate schedules I and reasons for such changes. Rate increases or decreases are not necessary. Oglethorpe's Response 5 Oglethorpe sells power under one wholesale rate schedule which is only applicable to its 39 distribution cooperatives. The initial Oglethorpe wholesale rates to its members were identical in structure to the full requirements rate structure under which Oglethorpe purchased power from Georgia Power Company. For these rates, demand billing was based upon noncoincident peak at each point of delivery. Oglethorpe's wholesale rate was subsequently amended to e billing , demand coincident with the Georgia territorial peak to railect the demand responsibility used when Oglethorpe began purchasing powe: from Georgia Power Company under the Partial Requirements Rate. ew a
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1(f) Customers, Schedule Transfers, Service Area, Acquisitions and Mergers. _ Regulatory Guide 9.3 List of all (1) new wholesale customers, (2). transfers from one rate
. schedule to another, including copies of schedules not previously furnished, (3) changes in licensee's service area, and (4) Ilcensee's acquisitions or mergers.
Oglethorpe's Response 1(fXI) New Wholesale Customers - Oglethorpe has 39 cooperative Member Systems which, from the inception of Oglethorpe, have constituted its wholesale customers. 1(fX2) Transfers From One Rate Schedule to Another - There have been no rate schedule ~.- changes. A copy of oglethorpe's current rate schedule, not previously furnished, is attached hereto. 1(fX3) Changes in Licensee's Service Area - There have been no changes in Oglethorpe's service area since its formation. r, . 1(fX4) Licensee's Acquisitions or Merriers - Oglethorpe has not been involved in any acquisitions or mergers.
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RATE SCHEDULE D D~ TO WHOLESALE POWER CONTRACT
.1 OPC-6 la y.
I J AVAILABILITY: Available to Members of Seller. Billing hereunder shall'.be by' Member with ~
- delivery point.' meter readings totalized by hour, less the allocation of power and.
energy provided by the Southeastern Power Administration,
- SCHEDULE OF CHARGES (MONTHLY):
Demand Charge: 1
$6.68 per kW of Billing Demand. '.
t F Energy Charge: FI.rst 500 hours use of Billing Demand at 27.58 mills per kWh ' Excess- at 22.58 mills per kWh Station Charge: j
- 4 E $1,500 per Point of Delivery l In the event the Point of Delivery is classified by the Seller as a Distribution. O y : Point of Delivery, the Station Charge will be half the above charge.
In the event that two or more parties share a comm~on Point of Delivery, the Station Charge for that Point of Delivery shall be equally divided by the parties. j a w .. l Effective January 26,1932 \ 1 1 i l I i i. mesh.me=m- z m . . - . m 1
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DETERMINATION OF BILLING DEM AND: Page 2 of 3 f 1 The monthly Billing' Demand shall be based on the sixty minute demand- .. "'7 measured coincident .with the Georgia Territorial Monthly Peak Hour Demand and ;
' .with the Highest Georgia Territorial Demands Year-to-Date. 1 Each month a Multi-hour Demand shall be computed by multiplying the average of . the Member's ' demands ' coincident with the highest year-to-date Georgia j Territorial Demands times the ratio of the highest Georgia Territorial Demand since - t June i to the average of the highest year-to-date. Georgia Territorial Demands, such- !
highest year-to-date demands measured in accordance with the following table: 1 Number of Highest Hours Year-To-Date (Since June 1) s June 6' July 31 August 43 September - May 44
. For the Billing. Month of June, the Billing Demand shall be the greater of:
'(1) The Multi-hour Demand applicable to the current month, or (2) 90% of the Multi-hour Demand for the previous contract year.
For the Billing Months of July through September, the Billing Demand shall be the Multi-hour Demand applicable to the current month, s . For the Billing Months of October through May, the Billing Demand shall be the greater of: (1) 75% of demand measured coincident with the Ge.orgia Territorial peak Demand for the current month, or (2) 85% of the Multi-hour Demand applicable to the current month.
' FUEL AD3USTMENT PROVISION:
All bills rendered shall be respectively increased or decreased in an amount per kWn equal to the difference between the estimated current month cost to the Seller of fuel yer kWh of sales and the base period cost of 17.21 mills per kWh of sales. , Estimated energy sales shall be all kWh sold, excluding inter-system sales.
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Estimated fuel costs shall be the cost of: (1) Fossil fuel recorded in Account 301 and nuclear fuel recorded in Account $18 consumed in the Seller's own plants and the Seller's share of fossil and nuclear fuel consumed in jointly owned or leased ' plants; plus Effective January 26, 1932 W 9 L 1 Gw= x_=. ~ ,
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- (2). 'The actual identifiable fossil and nuclear fuel costs associated witn-energy purchased fer reasons other than identified in (3) below; plus.' .
4-" '(3)
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The net energy cost-of. energy ' purchased recorded in Account 555, exclusive . of r capacity or. demand charges (irrespective of the: designation assigned - to such transaction) 'when such energy 'is purchased on an economic dispatch basis.- Included herein may be such costs as the charges for economy. energy purchases and the icharges as a result of scheduled outage, all such kinds of energy - ! being purchased by the Seller to substitute for its own higher cost 1 F energy; and less 7 (4)- The cost of fossil and nuclear fuel recovered through inter-system l L ,
. sales including' the fuel costs related to. economy energy sales and j, other energy sold on an economic dispatch basis.
Determination shall be made for the current month and: shall include an :l adjustment for accuracy of previous month's estimate in order that the accumulated : ! excess fuel costs allocable to Member kWh sales shall equal as nearly as possible to '
' revenues recovered ~ under the terms- of this . fuel adju'stment. The . resulting
- l
- adjustment in the rates, if any, shall be taken to'the nearest'one-thousandth of a !
cent (.001d) per kWh.' -
. PAYMENT:' i q
L:j '
' Member -shall submit,. either by depository transfer check, wire transfer, or:
' ' regular check in funds collected en the date indicated on monthly billing statements,
- which date shall be coincident with Seller's obligations to Georgia Power.. Company
- i. . for payment of Partial Requirements indebtedness. .
L .
, 1 Any payment not received on the date indicated shall be deemed delinquent and ; l ;7 ,
shall bear interest'at the National Rural Utilities Cooperative Finance Corporation.
. (CFC) prime rate as'of the date' when such delinquency first occurs. -
l d d
.1 7 .
j l D I Effective January 26,1982
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m-g - ' Pageiof1- + RATE SCHEDULE D I TO' WHOLESALE POWER CONTRACT STANDBY SERVICE RIDER (OPC-6) ? AVAILABILITY: Available to Members 'of Seller at annually- agreed upon individual points of
,..s delivery where firm backup capacity is required to support Alember consumer owned and operated generation.
SCHEDULE OF CHARCES: Monthly charges for standby service hereunder shall be computed in accordanc<e with the schedule of charges cor.tained in Rate Schedule D (OPC-6), providerd ' however, for Billing Demand purposes, a minimum monthly demano shall be appl.ed equal to thirty percent (30%) of the Contract Standby Capacity. The Contract Standby Capacity is the maximum amount of capacity that Seller is obligated to deliver. I a I i Effective January 26,1932
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, RATE SCHEDULE D~
D<<> JTO WHOLESALE PO'WER CONTRACT
~
i
' QUALIFYING FACILITIES RIDERS (OPC-6)
' INTRODUCTION:
The final rules issued by FERC to implement sections 201 and 210 of the Pubtle-Utility' Regulatory Poilcies Act of 1978 (PURPA) require all electric utilities to interconnect with and to buy and. sell. electric energy 'and capacity. from and to
" qualifying cogeneration facilities" and " qualifying small power procuction facilities" -
f (such qualifying facilities are referred to as "QFs" in these riders). Supplementary, interruptible, back-up, and maintenance power must be sold to QFs at "Just and reasonable" rates,' established in accordance with traditional' ratemaking concepts.
; !. Supplemental and Backuo Service Rider l To meet the 'needs of Member in complying with the requirements of PURPA, Seller offers four categories of. service designed to meet the total electric power needs of QF consumers of Member. These are:-
Supplemental- Firm Service
~
. Suppleme'ntai- Interruptible Service Sackup - Unscheduled Service
, Backup - Scheduled Service'.
All capacity made available by; Member to QF consumers with a.. capacity requirement of 10 kW or. more must be contracted for'and covered under some combination of these services. ' For each .QF selling power to Seller under Rate QF-A, Member must report to Seller the contracted capacity by type of service, and, . i by. month, the average demand coincident with the peak hours determining billing
- demands under OPC-6, and monthly energy requirements. For QFs selling power to P - Seller under Rate QF-B Member must report to Seller the monthly aggregate l
estimated average ~ demands coincident with the peak hours determining billing demands under OPC-6, and aggregate monthly energy requirements.
- l. Supplemental - Firm Service
. . This service applies to all capacity available from Member to QF consumers of
-Member, except for that covered by contracts for Supplemental - !aterruptible Service; Backup - Unscheduled Service; and Backup - Scheduled Service.'
Charges for this service will be the same as those contained in Rate Schedule D v- - (OPC-6). Monthly billing demand for this service will be the greater of:. l; .
' (a) . contracted Supplemental- Firm Capacity; or Ef fective January 26,1982
$* a# ? - Y h i ._0 _ ?.?.5l.L51!L O N .1 $- s _Y.YO '. . YN .h - ad m .YL? x ??_.\t _ .N . - - u es 4. % . - ~ . ~t ..-n k. ? n. . -
Page 2 of 3 (b)
- Monthly Billing Demands of QF consumers of Member, net of any capacity supplied under Supplemental - Interruptible or Backup -
Schecuted service.
- 2. Sucolemental- Interruotible Service
? This service is available only for capacity for which Seller, Member, and the QF consumer have entered into an interruptible service contract providing for up to L50 hours of interruption per year upon notification by Seller. So long as tne consumer complies with the total interruption provisions of the contract, monthly capacity billing to Member will include a discount for capacity beyond that capacity covered under Supplemental - Firm, Backup - Unscheduled, and Backup - Scheduled Services, up to the amount of Contracted Interruptible Capacity. Demand charges to Member for interruptible capacity will be at an 80% discount; all other charges will be the same as those contained in Rate Schedule D (O PC-6).
- 3. Bacuuo - Unscheduled Service This service is available to back up QF consumer owned and operated generation, where the QF consumer has entered into a Backup - Unscheduled Service Contract with Member. Seller must be notified whenever power is received under this service. Member may sell a QF no more than 1,314 hours per year under this service. Charges to Member for backup service will be computed in accordance with Rate Schedule D (OPC-6), provided however, for Billing Demand purposes, a minimum. monthly demand will be applied equal to thirty percent (30%) of the Contract Backup - Unscheduled Capacity. Normal charges for Supplemental -
Firm Service will apply whenever this service is utilized. The Contract Backup - Unscheduled capacity is the maximum amount that Seller is obligated to deliver.
- 4. Backoo - Scheduled Service This service is available to back up QF consumer-owned and operated generation, only when Seller, Member, and the QF consumer have entered into a
' Backup - Scheduled Service Contract. The consumer may receive up to four weeks per year of service under such a contract, subject to scheduling by Seller.
Charges to Member for Backup - Scheculed Service Capacity will be $1 per kW per week; all other charges will be the same as those contained in Rate Schedule D (OPC-6). IL Billing Adjustments to Reflect Power and Energy Received at QF _ Deliverv Points Rider All power and energy purchased by Seller from a QF interconnected with Member distribution system and simultaneously sold by Seller to Member shall, for purposes of computing Member's demand and energy charges, be measured and adjusted in the manner prescribed by contract among Seller, Member and the QF, and Member shall pay for the amounts of energy and cemand so determined at the
. rates prescribed in Rate Schedule D (OPC-6).
Effective January 26,1932 . I wa+- wm nx . x ~~u: : -
7., .y 7 ._ Page 3 of 3 111. Member Partial Requirements Service Rider In the event that Member purchases power from a QF, Seller may reallocate to Member the costs that have not been avoided as a result of Member's purchases from
. . the QF.
l Ef fective January 26,1932 l 4 l kr. __ _ _xwn ~ . . _ A. x- %L 2 '-- -
- o 1(g)- Generating Capacity Additions.
Regulatory Guide 9.3 List those generating capacity additions committed for operation after the nuclear fa'cility, including ownership rights or power output allocations. Oglethorpe's Response s Oglethorpe has at times prepared generation plans which called for the addition of generating units after Plant Vogtle's completion. At the present time, units considered for addition after Plant Vogtle's completion date are in the earliest stages of preliminary planningt no land has been purchased, no construction has taken place, no equipment has been ordered, and no permits or licenses have been applied for. Consequently, Oglethorpe
, does not consider these' units to be " committed for construction and operation."
Although none of the units involved in seilback arrangements between Oglethorpe and-Georgia Power Compary are added after Plant Vogtle, reductions in the seliback capacity amounts do occur after Plant Vogtle begins operation. Since these reductions in se11back capacity amounts are similar to capacity additions, Table I has been prepared to show the proje ted increases in Oglethorpe's resources resulting from changes in the se11back carn:: ty amounts af ter Unit 2 of Plant Vogtle is piaced in-service in September,1988. AddL4:s are due solely to reductions in sellback and no new units are being placed into operation. Additions shown are determined at the time of Oglethorpe's projected peak load. 1 1 t I L. , - . _ . . . _ . . ~ ..
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.. d 6
, TABLE I
/.; Oglethorpe' Power Corporation Committed Generating Capacity Additions Af ter Plant Vogtle Unit 12-~ -- - - - - - '
' Plant Scherer Plant Vortle
- Year Unit i Unit 2 Unit 1 Unit 2 Total 1989 4L90 48.48 34.50 0 -131.88 i.
g L1990 48.90 48.48 34.50 34.50 166.38 e ' 1991- 48.90 48.48 34.50 34.50 166.38 1997 0 48.48 46.00 34.50 128.98 1993 0 48.48- 46.00 34.50 128.98 p-1994' 0 'O O 46.00 46.00 t 1995 0 0 0 46,,00 46.00 L. . - l 4 as 9
' usens Aseess-. .
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g Ausnia. Georgia 303o2 /.\ y> 1a, g % . ,q : . c,. m sener wee preseen .
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a' . tre soume,n enctre sysmen . ~
- October 12, 1983 m , ... .
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Mr. G. Stanley.HillE Oglethorpe Power Corporation 2188 Woodcock Boulevard -/ 4 - Atlanta, Georgia- 30341f p-Dear Stant GPC~ agrees: ('
-1. That .OPC is' not restricted by the PR-7 tariff, or any contractual ~ relationship between the parties,.from
, . making off-system. sales, including Unit Power Sales, i- 'and.that GPC will work with'OPC to resolve'any operating, scheduling or dispatching arrangements required =to facilitate such sales in a timely fashion.
.2.- To. work with OPC to develop by; June 1984 a project plan: .
and conceptual' framework for a. pooling relationship.~; If.a pooling relationship is determined to be feasible, the plan should be extended.to develop a schedule'for-implementation'as'soon as practical.- GPC further agrees that to.the extent.outside. resources are required for
, ,- this-initial. development work,LGPC will share with-OPC -
- costs ~of those-resources which'are mutually' agreeable.
- 3. - OPC'and GFC agree that resolution oflthe ITS contract revisions are an appropriate step in facilitating'both '
- off-system sales and pooling.
Yours truly, M-M-- ,. A. W. Dahlberg. AWD:vn - i
.l '
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lI A PitOJECT PLAN TO DEVELOF A GEtmGIA TERRITORIAL POWER, SUPPLY. AGREEMENT 'w. 9 February 1984
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l-1 I [' TABLE OF CONTENTS , k a i j i Page INTRODUCTION 1 l i:. BACKGROUND' 2 OBJECTIVES OF THE NEW AGREEMENT 3 ADVANTAGES AND DISADVANTAGES OF A'NEW AGREEMENT 4 SCOPE OF THE POOL 5 Relationship of'New Agreement to Southern Pooling
'Agreamsnt 5 Parties.to the New Agreement 5 Treatment of Existing Agreements 5 Legal, Regulatory and Other Constraints 6 Treatment of Off-System Sales 7 POOL' METHODOLOGIES 8
~
- Stratification 8 Capacity Responsibility 8-
* . Capacity Costs 9 Capacity Pricing 9 Capacity True-Up 10 Energy Responsibility 10 Energy Costs 11 Energy Pricing 11 Energy True-Up 12 POOL PLANNING AND OPERATIONS 13 Joint Planning 13
- Operawien 13 Administration 14 km_ s ,1 m . ___.m__ ___m. , _ _ . _ _ _ _ . , - _ . - .
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H
. Page IMPLEMENTATION 15 Overview.of Pool Development Process .15, l .Susanary of' Phase II'. Effort 15
[ * 'Overall Development Sche'dule' 16
* . Project Organization 17 Phase II-A Sununary Project Schedule ' 18
* - Project Management Approach 19 l; ~*
Cost-Responsibility 19 b Modeling Requirements 20
-APPENDIX A Summary.of Pool' Development Costs 22 l APPENDIX B Detailed Work Plan For Phase II. 23 APPENDIX C'. Phase,II-A Cost Analysis 29-f.1 APPENDIX.D Modeling Requirements '30 a
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INTRODUCTION
]
This report documents the results of a planning project to develop a new agreement for the purchase and sale of power between Georgia Power Company and Oglethorpe Power Corporation. The intent of this agreement would be to replace the current 1 Partial Requirements tariff. The purpose of undertaking such a planning project was to establish a broad framework for the new agreement and agree on key objectives prior to committing significant resources to the project. This report constitutes an investigation of issues and concepts that must be addressed prior to the formulation of a Territorial Power Supply Agreement. For discussion purposes, this agreement is often referred to as a "new agreement" or " pooling agreement", and a " Georgia Pool" is sometimes mentioned. Other than for the purpose of establishing a framework for negotiations, this report does not represent a commitment on the part of either party to any particular position on any of the issues and concepts that are raised herein. The project was sponsored by Messrs. A. W. Dahlberg (Georgia Power Company) and G. Stanley Hill (Oglethorpe Power Corporation) and was completed over an eight week period from December, 1983 to February, 1984. It is the intent of both parties to present this Project Plan to other interested parties to determine their interest in this form of agreement. The project team consisting of Georgia Power, Oglethorpe Power and Ar'thur Andersen & Co. personnel performed the detailed work. The major issues addressed by the Project Team are grouped into four main areas: Scope of the new agreement Methodology issues (cost, pricing, etc.) Planning and Operations required for the new agreement
- Implementation Each of these areas is addressed in remaining sections of the L; report.
h Page 1 i
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BACKGitOUND As part of the 1974 Settlement Agreement, a Partial Requirements Tariff was developed to provide a mechanism for the joint-owners of certain generating plants to purchase capacity and
, energy to supplement their ownership. Its stratified structure j i
recognized that these generating units were not of an appropriate mix to meet the overall load needs of these customer-owners. Although the tariff has served well in meeting its stated purpose, it does not appear to be a suitable vehicle to meet each party's long term needs. ' As a PR customer approaches sufficiency in owned generation or generation purchased outside of the PR Tariff, there will be occasions when it will have excess generation as well as deficit. For this reason, an agreement is required which can provide for both buying and selling by each party. The current PR tariff has an interim provision to handle exceas customer ge.neration, but this
- interim provision is not appropriate over the long term because it distorts the original objectives of stratification. ~
There are three broad alternatives which could be followed to remedy this situation: Continue to modify the ,PR Tariff to avoid the need for customer sales This option would continue to distort the original l concept of stratification but would eliminate the I need to provide for firm sales by a customer.
- Eliminate the PR Tariff and establish bilateral buy and sell agreements as necessary This option would require each company to independently plan for the needs of its system and to independently contract for purchases or sales as b required to balance load and generation needs.
Establish a pool to share resource obligations and risks This option would continue the level of integrated l planning and operations presently established. The project team elected to follow the third option because it best maets the objectives of the parties for establishing a long-term agreement. The broad conceptual framework for a Georgia Pool which is described in this report was then developed. 1 w Page 2 L. .- ,
. - - . .1_ _ _ T _ :: __ - =_ _ _ _ -
I OBJECTIVES OF THE NEW AGREEMENT In'or' der to make effective detailed decisions regarding methodology.and administration of a new agreement, an overall framework must first be established. This framework is established . ; through a mutual understanding of the key objectives of the new l agreement. The following were established as these broad objectives j of the new agreements .J
- i Provide for'the purchase and sale of power between l parties 1 L
Provide a means to ensure an equitable sharing of mutual i benefits.and risks Promote continued integrated planning and operation including: Provision for dispatch of all future units applicable to dispatch clarification of each party's responsibilities related to joint planning and operations. l p e ?- . 4 Sge 3 -m__.m.m2_x.__^_m=. .,m.m_m-m.._...mm._.. m. ..m_. ._. ..mn. . s-m. ...,.. ta .
n l
. ADVANTAGES AND DISADVANTAGES OF A NEW AGREEMENT V
Prior to committing significant resources to implement a new agreement, it is important that each company understands the advantages and disadvantages of entering.into the agreement based upon the concepts developed to date. The advantages identified'
- l. include three major areas:-
6 The establishment of long-term r2sponsibilities for each party on an equal barts by: Eliminating uncertainty of long-term relationships Sharing riuks of long-term planning Establishing each party as a purchaser and seller Providing for ' economic stability for GPC through the commitment of former customers to serve own loads. The promotion of integrated planning and operation to achieve lowest cost by: Minimizing the' cost of capacity expansion Providing for the central dispatch of all applicable units, whether or not jointly owned Continuing the current level of coordination among i the entities of the Southern'and Georgia territories. The reduction or elimination of effort associated with e periodic filing, contesting, and settlement of rate cases by the use of formulary pricing. Although the project team felt that the advantages for both l pa'rties are compelling, a new agreement may also produce certain - disadvantages: 7te ability of either party to independently set its own course for meeting its load requirements may become limited By sharing risks, the rewards associated with those risks j would also be shared i I Oglethorpe may become subject to indirect FERC regulation j The development of the complex billing and accounting systems necessary for the administration of a Georgia Pool will impose an additional burden on the participants (primarily Georgia Power) if separate agreements for non-participants are also required. l Page 4
- _ _ _ _ _ _ _ . , _ _ _ . . _ . . _. _ _ _ - _ _ _ . ,_ .- __m __ _ _ . _ _ . __
, . SCOPE OF THE POOL Y . Relationship of New Agreement to Southern Pooling Agreement Two feasible alternative ways in which the Georgia Pool could operate within the Southern Pool were discussed by the Project Team Continue relationship through Georgia Power Company Operate as a member of the Southern Pocl. With the first alternative, the membership and operation of the Southern Pool would be relatively unchanged by this agreement. With the second alternative, the Georgia Pool would designate a representative to the Southern Pool which would act on behalf of I all parties to the Georgia Pool agreement. Unanimous agreement of the members of the Southern Pool would be required in the s-cond alternative. Under either alternative there are several issues that impact , the Southern Pool and must be addressed. These-include: I Application of Southern Pool dispatch procedures to generation operated by non-Southern entities Treatment of each party's capacity and energy in the Southern Pool Off-system sale of each party's capacity and energy. Parties to the New Agreement While this report has been prepared by Georgia Power and Oglethorpe, there are other parties which may wish to participate in a Georgia Pool. The principles established in this report will be used to complete development of a new agreement, and thus this report will provide a basis on which any other party can decide whether to participate in the phases of the project which are to follow (see IMPLEMENTATION Section). Treatment of Existing Agreements The New Agreement will contain the terms and conditions of power supply transactions between the participants. Various existing agreements between the parties could impact this new Agreement and the question therefore arises as to whether those agreements should be incorporated into the new Agreement or
. continue operating independently outside.
Page 5
R e /
.In general, existing agreements, the terms of Which could be incorporated, deal primarily with issues of the PR tariff which the new Agreement.is to replace. Some of'these agreements are:
PR-6 Settlement Agreement, including letter agreements for the economic dispatch of Scherer on a territorial basis Unit Power Sales Settlement Agreement AEC (now NRC) Settlement Agreement, including Hatch licensing conditions. Other agreements, Which deal with matters outside the PR Tariff,-could remain separate. These agreements include:
- Jointly-owned Plant Agreements. (Hatch, Wansley, Wansley !
CT, Scherer, and Vogtle) These agreements provide for the operation, use of capacity and energy, and sharing of costs in the jointly-owned plants. Provisions of these agreements which could' interact with the Georgia Pool agreement are the provisions for economic dispatch and for unit sale of capacity and energy. ITS Agreement This agreement *provides for ownership and operation of the Integrated Transmission System. While the ITS is structured so that it could remain separate from the Georgia Pool Agreement, pool agreements in t general provide for usage of transmission as.well as generation. However, the ITS Agreement is a tariff on file with FERC available to any qualifying entity. If the other ITS parties choose not to participate, there may be a problem with including it in the Georgia Pool. Pride Transloader Agreement Provides for sharing the costs of Wansley's use of the Transloader. Legal, Regulatory and o'ther Constraints In order to implement a new agreement, a review must be conducted of any potential legal, regulatory, or other constraints of either party. A partial list of these constraints include: The impact of existing contracts between the parties, and between Geprgia Power Company and others Page 6 w _ mmmm _, _ __m . .~ _ / . _ .
E i N _1 Issues associated with regulatory bodies: T ?
- FERC
/
Requirements for filing, jurisdiction over GPC, cost-based rates, and service class differentiation are examples of these issues.
. All of Georgia Power Company's filings with FERC must contain consistent treatment of issues.
l
- REA
- i.
Oglethorpe's participation in a new agreement i will be subject to the review and. approval of the REA. In Phase II, a detailed analysis of the RE Act and REA Bulletins will be required to determine the extent of any limitations Oglethorpe may have in its participation in a new agreement. For exarole, any requirement for Oglethorpe to sell power will be subject to the restriction that generating plants built with REA funds must be primarily for the beneficiaries of the RE Act.
- NRC The new agreement must be in. compliance with !
the conditions of the Plant Hatch operating
- license.
.q
- ' Georgia PSC 1 SEC Georgia-Power Company is subject to the Public Utility Holding Act of 1935.
Treatment of Off-System Sales The Agreement will not prohibit, restrict, hinder, or limit a party's ability to participate in'off-system sales. In the event Chat the pool has surplus or deficit generation, the parties should endeavor to reduce the surplus or make up the deficit by engaging in off-system transactions. While the agreement will address the treatment of off-system transactions by the parties, the parties may also want to engage in joint transactions which may be to the mutual benefit of the parties . While~the Agreement may provide for joint transactions, the parties
,. must. determine, in the next phate, whether to make a commitment to l a,ttempt joint transactions before or after proceeding separately.
l Page 7
= _ , . __. -- _
a l l j POOL METHODOLOGIES l This section identifies major areas of the pool methodologies and the various alternatives to be addressed in the design phases. < The project team has identified several items which have been ' agreed upon in Phase I Which will form the basis for future design work. These are described in each of the following sub-sections. Stratification l The concept behind stratification is the recognition of the ! principles used by generation planners, wherein a mix of various s' types of capacity is needed to serve a varying load. The current
)
categories may not be representative of the current generation planning options and should be reviewed in this light. The Southern system recognizes the need to have plants j committed to serving load and raserves available to cover I uncertainties. Other pools (Mid-South) categorize capacity by fuel i requirements. The Georgia Pool could adopt a procedure such as one of these or continue to designate capacity to categories according to the system's load shape. Since the four categories currently defined may not accurately represent our current or planned system, they will be reviewed and replaced if a more appropriate representation can be found and agreed upon. Generation criteria, system operation, etc. should be considered in this analysis. Capacity Responsibility A party's capacity responsibility should recognize that party's load requirements as well as the characteristics of the system and its capacity. These characteristics should include generation mix, both size and type of units, operating characteristics (start up i time, minimum operating capability, etc.) and availability (accounting for maintenance and forced outages). Another responsibility is the sharing of reserves based either upon the quantity available or limited to a specified level. An additional responsibility may be assigned as a contribution to operating ruserves depending upon the mix of the party's capacity. Since capacity planning involves a considerable lead time, long-term or advance commitments may be appropriate to ensure that the owner of a facility built to serve the indicated needs of the pool has a market for capacity which is excess to its requirements. The project team has concluded that:
- Capacity responsibilities should be based on full sharing of reserves Page 3
-. _ _ _ _ . ._ _x _ _ - = _a-w -- _- - - - _ _ _ _
Assignment of operating reserves should be considered to p determine'if such assignment is appropriate. Capacity responsibility will be established and equalized by the stratification categories. Capacity Costs Since capacity pricing will be based on related cost, a method
. of determining that cost must be established.
Capacity costs are generally based upon carrying charges, the ~
. cost of ovning a facility. Carrying costs consists of four major components. the cost of money (dividend and interest expense),
taxes (income, ad valorem, franchise, etc.),-depreciation, and miscellaneous e'xpenses (insurance, fixed operating and maintenance expenses, etc.)., A convenient method of determining capacity cost is to represent each component's contribution to carrying cost as a percent of the undepreciated investmet t in the facility. This produces a . fixed charge rate which when multiplied by the investment yields the carrying cost.
.The investment may'be based upon one of the following:
undepreciated balance of some units (embedded) l
- +
1 1ast or.next unit, perhaps escalated to current date , (incremental) R
- I phe.ntom unit appropriate to desired capacity sale (incremental). I These and other methods of determining capacity cost will be analyzed in the next phase.
i capacity Pricing. Capacity pricing will be based upon a formulary rate. The general form of this rate could be to multiply a fixed charge rate times an investment. Several aspects of this form of formulary rate which will be considered are: determination may be by: I unit plant group of units (load category or type of cap *acity) {
\
company
- l l
Page 9 l l l i La_ 2_ - . s r u :: e v .- >=:.*=m'~"
.. - = A ' '
[. r. F -.
- pool aggreg. ster
*- investment may be based on:
embedded cost incremental cost fixed charge rate may be: embedded (applied to embedded or incremental p investment)
. incremental (applied to embedded or incremental-investment).
Capacity may be sold and purchased at its identified cost, or the purchaser may be required to determine.his avoided capacity cost. In that case the purchase would be based upon split-the-savings with the seller or at the purchaser's full avoided cost with the pool allocating the difference. Capacity True-Up capacity costs may be tiued-up from e,stimated to act'al u by
- adjusting the. investment and/or the fixed charge rate to values determined over a specified period. Specific components of the fixed' charge rate, such as cost of money or fixed O&M, may be identified for true-up while others are unchanged. -The capacity responsibility may be trued-up based upon the' demonstrated capability of - the units, the actual -loads or reserve levels, or the categorization (if used) of the units based upon demonstrated characteristics or actual load phapes. If the system incorporates energy entitlement with capacity purchases, true-ups of the -
capacity responsibilities may require rebilling of the entire year's (or whatever capacity selling period is adopted) energy based upon the new entitlement. In addition, rates to a party's customers which were based upon f projected capacity expenses / revenues are generally not trued-up, i Therefore, a change in capacity payments will become the responsibility of the party's equity holder / owner and may create a l cash flow problem. For these reasons, the most appropriate action may be to bill capacity based upon the most recent historical data available adjusted uniformly by an agreed upon escalation rate or to " roll" the true-ups into the ne.it billing period where the party l may recover. the cost through its rates. Energy Responsibility A consensus exists that hourly energy accounting should be employed in the Georgia Pool. ] Page 10 h 1$dh .m. _a [.M ...w a b@ ' n , n_ a# .u.* se 1. _ - I .ia - _ _ _ . b. 2_ '('i. i 1. 'E _ _I '_4 .
9 I l I h- Even if categorization is employed to determine capacity responsibilities, categorization is not necessarily required to determine energy responsibilities. For example, if capacity purchases are allocated by unit, energy entitlement may be q appropriate to determine the available generation of the parties. i The available generation would be compared to the party's load each ' hour to determine whether they will buy or sell for the hour. The energy- responsibility of a party may be determined from meter point data plus losses or, for GPC, be based upon the territorial input less the other party's responsibilities. Since some hours' load data will be unavailable due to meter malfunctions, fabricated data will be required. A standard procedure should be developed to allow this process to proceed with a minimum of effort. Depending upon the distribution of capacity owned and purchased by an entity, an additional charge for operating or spinning reserves may be appropriate and will be analyzed in the next phase. Energy Costs Energy costs are generally grouped into two categories, fuel and variable operating and maintenance expense (VO&M). The dollars expensed for fuel and VO&M are converted to a dollar per unit of . energy rate. One method is to account for the dollars expensed ove,r a period of time, then divide by the energy produced over the same period. This calculation yields what is commonly referred to as an average energy rate. An incremental energy rate may use a similar fuel and VO&M accounting methodology or a projected replacement fuel cost with projected VO&M expenses. The fuel expenses are converted to an energy rate by using the unit's incremental heat rate over a specified range of operation. VO&M expenses (if expressed in dollars per unit of fuel) may be added to the fuel cost before the conversion or, as in the Southern Pool, converted directly to an energy rate to be added to the fuel rate for a total incremental j energy rate. ; 1 i Energy Pricing Once a methodology to determine the energy costs and responsibility by party has been determined, the rate for sales of surplus or purchases of deficits must be determined. If all energy is to be sold at average cost, the available energy of an party may J be stacked and the surp,lus sold from the top of the stack or the average of a block of units, i.e. by category. If incremental ccsts are used to sell / buy energy above 1 Page 11 a ~ n ax x. . - . . = =~ *- ~=
i f entitlement, two methods may be employed. Energy could be sold A based upon a stack of the units' running rates (the incremental cost rates at the units ' current output level) . This is the method employed . for sales within the. Southern Pool. Alternately, a
- redispatch methodology could be employed to determine the avoided cost of the buyer and the replacement cost of the seller for the energy transacted. The two parties may pay / receive their A-identified costs with the difference being allocated through the pool on some criteria, or the transaction may be priced at a value
.between the two costs (split-the-savings ) . . A 50-50 split of the savings is used for incrementally priced sales external to the Southern system. This split need not be 50-50, however.
If a party's capacity responsibility recognizes a contribution to operating reserves, the energy cost of spinning reserves could be also al3ncated across the pool. Charges for spinning reserves could be determined by calculating the additional (incremental) costs incurred by a party to serve load with higher cost energy while maintaining reserves on a particular unit.
- Energy True-Up i
Energy costs determined from average expenses over a period may be trued-up if desired. The true-up may consist of adjustments to the~ accounting cost of the fuel and the amount of fuel " consumed" (stockpile adjustments). Energy costs based upon replacement fuel cost (incremental) should not be trued-up, however. If energy entitlement based upon capacity purchases are used and the capacity purchases are altered (trued-up) after the fact, major revisions may.be required for all energy bills rendered under the previous entitlement. True-ups, if required', may be handled by rebilling the affected period or by rolling the adjustments into the next period. E
.4 Page 12 I nw . .x .. : ._ . ~ , . = _ x: .a~.-. x= .u - - _ _ - _A
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v.. POOL PLANNING'AND OPERATIONS
- Joint Planning It is to the. mutual benefit of the parties involved in an integrated system to participate in joint planning activities.:
E-Such activities ensure the most economic andieffective generation-mix for the-integrated system.- The Joint. Planning activities of the parties will take place within the context of the L new agreement - and therefore.should embody the ideas.and responsibilities included. in the agreement. > The Joint Committee Agreement' between' the parties provides ' for the: preparation'of.a joint generation plan..Since no new generation construction has been required since the Agreement's inception other than that then planned, joint planning is still < evolving to the commitment stage. At present, there are disagreements' between Georgia Power and 4 Oglethorpe regarding future generation additions. Such disagreements emphasize the need for joint' planning between the parties to a pooling agreement. By independently pursuing the same. goal in generation planning, neither party has available data and considerations of the other party. ' Joint Planning should not replace the independent planning-activities of the parties,-but should. provide t2us vehicle for the exchange of data toward the ultimate goal of'a mutual territorial plan. Given that the parties may still not be able to; agree to a mutual plan after the joint planning activities,- the new agreement 1 sh6uld provide for the protection of pool members from the
. independent ' actions. of one member which may be detrimental to the other members.
Operation Dispatch of all generating units approved for inclusion in dhe p pool will be performed by the Southern Pool. This. dispatch will be subject to any limitations and constraints imposed on any unit
- dispatched by the Southern Pool such as area protection, energy limitations, and non-dispatchability. This dispatch will include daily-and weekly unit commitment and coordination of maintenance schedules. Procedures will be required to recognize the participation of non-Southern Company entities in this daily operation process including:
Operating limits Coordination of maintenance Operation other than-economic dispatch: Performance tests Page 13 Wm _ , -ww.wa,w m w,, h e u =- o , A- - -
. Partial outage or reduced output f-'
.,, - Load cut.
Generation to off-system loads - m Communication responsibilities Data transmission responsibilities operation during system emergencies. s Administration The bulk of the pool's efforts appears to- be in bookkeeping and billing. This' work could also be done either by Georgia Power Company or by a Pool Authority which, in turn, could be jointly staffed. Consideration should be given to best utilization of q" ' resources, keeping in mind Georgia Power Company's present involvement in and existing mechanisms for coordinating with the Southern Pool. b l 1:
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e IMPLEMENTATION Overview of Pool Development Process The Georgia Pool Development Plan calls for an orderly development of the major aspects of the Georgia Pool. This development will cover primarily a four year period, with certain items delayed until required. The estimated total cost of design and implementation for each party is expected to range from
$'800,000 to $ 1,500,000. APPENDIX A contains a' summary of the Pool development costs by Phase. These cost estimates are order of magnitude representations only since the pool methodology and
, administration issues are yet to be resolved.
.The Conceptual Design (Phase II-A) will be preceded by a letter of intent to develop the Georgia Pool within the framework desired in this Project Plan. This Conceptual Design will include resolution of<the major issues and methodologies and will require seven months to complete. Following Conceptual Design, approximately nine months will be required to complete a Detailed Design and Transition Plan (Phase II-B).
Implementation (Phase III) will be completed in three major steps --- hourly energy accounting, formulary rate, and pool organization and procedures. This phase will require about two years to complete.
- Development of hourly energy accounting will include resolution of the detailed billing methodologies (building on the 1982 work if appropriate) and design, installation and testing of the billing ,
and reporting system. In parallel with this development, a similar effort will be required for installing a formulary rate except that the cost accounting systems development will require more effort. While hourly energy accounting could probably be implemented within the PR tariff, the formulary rate application envisions firm purchases and sales by all parties and thus will require the
. execution of a multi-lateral pool agreement.
Dispatch procedures for new non-Southern Company operated generating units can be developed following these phases as ! required. A schedule of this overall development plan *is shown on the following page. Summary of Phase II Effort The objectives of Phase II of the Georgia Pool Development are to: Present the Phase I concepts to other parties (e.g., MEAG and Dalton) to determine level of interest Page 15
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Finalize the scope, methodology concepts, and planning and operations issues
- Obtain the commitment of each party for implementation of the Georgia Pool and develop an implementation plan.
Phase II has been further divided into two segments, A and B. Phase II-A would include the resolution of the basic pool methodology issues and would require the development of the Planning Model to finalize decisions related to costing and pricing methodology and the long-term pool structure. At the completion of Phase II-A, each party would reconfirm its continued participation to proceed to Phase II-B. In Phase II-B the detail design of the pool would be finalized and pool organization and administration issues would be settled. In addition, the specific transition approach from the PR agreement to the pool would be established. A detailed billing model would also be developed to test detail economic transactions, and a conceptual design of the pool billing system would be established in order to confirm the system design and installation estimates. A detailed work plan for Phase II-A supporting the manpower estimatec for that phase has been prepared and is included as Appendix B of this report. A summary project schedule showing the major project segments, estimated work-days and elapsed time is shown on the following page. It has been estimated that a total of 1290 work-days of effort over 7 elapsed months will be required to complete Phase II-A. An analysis of the cost required to complete Phase II-A is shown in APPENDIX C. Project _ Organization The project will be organized with three levels of authority: J Steering Committee The Steering Committee will consist of one executive from each party. This committee will be responsible for overall direction of the project and will be the final authority for decision making. Project Management Team The Project Management Team reports to the Steering Committee. This team will be responsible for the management of the project and will attempt to resolve disagreements in principle that arise in the working groups. This team will consist of one member from each party plus one designated alternate. Page 17 mm_ _ _.
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[ l l l Working Groups Y Working Groups will be established by the Project Management Team. The groups will con?,ist of whatever membership each company desires and their make-up will vary depending on the requirements of the task. The groups will be responsible for developing the i details of all concepts and will report to the l Project Management Team. Project Manacement Approach F. The successful completion of each project phase will require l significant resources and a commitment to meet established time schedules. To ensure that each phase meets the budget and schedule objectives, several project management techniques will be employed: Detailed work programs will be used to define the tasks to be accomplished, estimated manpower, individual assignment responsibilities and starting and completion dates Project budgets, including time and dollars, will be established as the basis for reporting actual tinie and expenses. Estimates of remaining effort will be periodically reviewed to ensure the project is on schedule Periodically, project status will be reported to the
- Steering Committee. Status reports will address accomplishments as well as problem areas or key decisions to be made.
Cost Responsibility i The development and implementation of a pooling agreement will require significant personnel resources of varying skills *nd background. Each pool participant will assign direct project team participants as well as draw upon other internal resources of each participant as needed. Other costs that may be incurred in the pool development include external costs such as: Legal fees I Consultir.g fees Travel expenses Computer software and hardware. The costs incurred by each pool participant can be categorized 1 as follows: , { l
- Costs which are rel'ated to the joint development Of the pool (pool development costs) )
Page 19
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- Costs incurreG by a pool participant solely for the benefit of the participant (individual participant ' costs ) .
While- individual participant costs will be borne by those B participants incurring the costs, the pool development costs vill .. be. shared among'the pool participants. Ideally, these costs should l 13 assigned to each participant based on the benclits to be p achieved. Practically, however, identification and agreement of l: each participant's benefits would be a difficult and subjective exercise until an agreement on detailed issues has.been reached.
~
l . I L Accordingly, each pool participant will equally share the pool [ . development costs ' incurred. To control these costs, a project budget will be established for each phase based on written work plans and agreed staffing assignments and external costs (consultants, computer charges, etc.) prior to initiating each
- phase of work. Periodic status reporting will highlight budget L variances and. Executive Steering Committee approval will be required for budget adjustments.
As a first step in the next phase, the participants will establish the mechanism for cost accumulation and billing. In addition, financial executives within each company will establish appropriate accounting treatment for pool development and individual participant costs. Modeling Requirements The need for a computer model will likely evolve through three phases in the project: *
- Basic conceptual models - computional aids such as electronic worksheet analysis to evaluate concepts Planning model - simulation of pool billings to verify effects and economic viability Billing model - simulation of hourly accounting to facilitate final development of pool concepts.
Three models are currently available which might be useful in the Georgia Pool Project in the planning model phase OPC's Financial Mode] EMA's PR Energy Model XSIM Modeling language interfaced with PTI's interactive ] production costing (IPC) at OPC. These models and modeling requirements are described in more detail in APPENDIX D. O , 7 1
- 1 Page 20 .
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. The'OPC model is-the only comprehensive capacity and energy model currently ava-lable. However, the model may be infeasible-for GPC due to its ootal' cost,. relative inflexibility, and the.need to acquire SIMPLAN language skills. GPC's alternative is the development of an internal model - possibly using EMA's PR energy model as a base. In either case, the relative accuracy of period energy.. accounting versus hourly accounting.will need to be reviewed.
If GPC and OPC. elect,.for the reasons mentioned above, to,use separate internal models for the project, joint analysis can still-be- accomplished through' the sharing of production and accounting data and assumptions and the comparison of results. Due to the bs inherent' lead' time in model development, howevsr, the project tant l force should resolve these modeling issues as soon as possible. l W' 9 I Page 21 c m our:1 w: m a ma:A n +r." .xa___ .iz ., _ _ _ , . .,.a_. - - - ._ ..__.N_ 16 11 ,. m a -_.1-
e l-g- APPENDIX A-s' ., l SUl#4ARY OF POOL DEVELOPMENT COSTS GPC OPC
, Phase II-A Conceptual Design S '136,000 $ 151,000.
1 Phase.II-B' Detail Design / $ 175,000 . $ 175,000-Transistion Planning $ 250,000 $ 250,000 Phase III Implementation S 500,000- $ -500,000-
$ 1,000,000 $ l~,000,000
) $. 811,000- $ 826,000-1,386,000 1,401,000 r j:.9a . Page 22
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_ g l DETAILED WORK PLAN Estimated 1 Man-days ?; 160 'I . Project Organization'and Administration
.A. Finalize' Phase II'workplan'-
- 1. . Detailed Work steps
, 2. Estimate man-days and target dates.for each step 3 .1 Manpower assignments' B.' Provide supervision for work performed I
.C. ' Review progress,: prepare' written progress' reports,.and. conduct periodic progress
. review meetings
.r 15: II, Present' Phase I Results A.. GPC management
.-- B. OPC management C.- MEAG D. Dalton E. Others-130 III. Determine Scope of-Pool.
A. Relationship of'new agreement to Southern
~
H Pool
- 1. GPC as pool agent decision
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- 2. Involvement of.SCSI cr other S'uthern o
. Operating companies in determining of g dispatch of non-GPC owned units and L non-GPC sale / purchase.
l
- 3. Commitment'of non-GPC retained capacity and energy to Southern
., Company dispatch including off-system sales - before/after retention? (Unit commitment and maintenance schedule coordination.)
. Page 23 N:r mxh=& tr:2 &r~ n11.r& u:r .c . a:n - - "c
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E . F , Yl l p. B. Treatment of exinting agreements H"
- 1. Finalize agreements to be operated-- - - - - -
outside the pool and determine modifications that may be necessary to these agreements: b
- a. . Hatch Operating Agreement
- b. Wansley Operating Agreement
- c. Wansley CT Operating Agreement
- d. Vogtle Opeating Agreement
- e. Scherer Operating Agreement
- f. Integrated Transmission System Agreement
+
- g. Pride Transloader Agreement
- 2. Finalize agreements to be incorporated into the pool
- a. PR-6 settlement agreement and associated letter agreements for
- economic dispatch of Scherer
- b. Unit Power Sale Settlement Agreement
- c. NRC Settlement Agreement, including Hatch licensing conditions C. Legal, regulatory, and other constraints
- 1. FERC i
- 2. NRC .i
- 3. Review RE Act/REA bulletins for OPC restrictions
- 4. Southern Company restrictions
- 5. Georgia PSC j
- 6. .SEC l
D. Treatment of off-system sales
- 1. Inclusion / exclusion of curoent ]
. off-system sales !
Page 24 l 1 wn.- . x: s . . u a. : . x:_.- . w.ve ax . w e ?n.<s - , um : - : 1 :. u.c . :. a . :. . . ::a . _u : 2~ - ~:Muas W_* 3
w ?: 2. Determine policy for the sale of pool surplus or acquisition of pool' deficit 460 IV. Design Pool Methodology A. Capacity
- 1. Stratification
- a. Analyze alternatives
< (1) Load-(2) Capacity type (3) Operations
- b. Establish ' method for assigning
- f. capacity to categories (1)- Nuclear' (2) Fossil (coal / oil) u.
., (3) Combustion Turbines (4) Conventional hydro (5) Pumped, storage hydro G
(6) SEPA (II-B) * (7) Other (QF's, etc., II-B) ! 2. Responsibility w.-
- a. Requirements by category. -
(1) Loads (2) Losses (II-B)
- b. Treatment of capacity p
(1) Rating methodology (2) Timing of additions (II-B) (3) Retir.ements
- c. Analyze feasibility of energy entitlement
- d. Reserve sharing methodology Page 25 LLun -- . - ~ ~ . ~ . u=e- ~ =u =- -- --- # " - "= - ^ A
- e. Acceptance criteria for approved resource (II-B)
- f. Treatment-.of off-system sales / purchases
- g. Determinationof long/short parties.by ca'tegory
- h. Determine appropriate treatment of operating reserves 1 3. ' Costs
- a. Embedded versus. incremental
- b. Cost of-service - allocation of investment consistent with y ,
stratification
- c. Components of cost (1) General definition y,
- .~ (2) specific accounting treatment (II-B)
- 4. Pricing
~
- a. At cost, avoided cost,* or split based on cost
- b. Determination of bilateral exchange
- 5. True-up
; a. Analyze different degrees.of true-up as to cost versus benefit (1) Stratification - assignment
., of units to category.
c (2)~ Responsibilities * , (3) Costs
- b. Analyze true-up payment alternatives (1) One payment transaction
', (2) Spread over next billing period Page 26
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- 1. Stratification
- a. Analyze whether energy needs to s '
be stratified (if entitlement are used).-
- b. Consistent with capacity, if used-
- 2. Responsibility - hourly
- a. Requirements (1) Loads.
(2) Losses (II-B)
- b. Entitlement . (including off system sales / purchases)
- c. Outage energy (forced / maintenance)~
- d. Determine appropriate treatment for spinning reserves (II-B)
- e. Determination of long/short parties
; f. Treafment of non-conventional sources (II-B)
- g. Pumping energy
- 3. Costs - average, incremental, 9: -
redispatch/ incremental heat rate rate
- a. Conventional generation
- b. Hydro and pumped storage hydro
- c. non-conventional sources '(11-B)
- d. Off-system transactions
- 4. Pricing
- a. At cost, avoided cost, or split E
- b. Determined by stacking or redispatch?
- 5. O True-up (II-B)
~Page 27 U !l.i:D EZ Y:!AX' .WL - Wi^- a f -a 2~ 1'o L *.m!. ~ ? ?.* ..L? ~ T
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- a. Degree'of true-up consistent with
' capacity true-up
- b. Methodology for load. data fabrication i 475. -V. Model Alternatives
'A. Base line planning / specifications ~
B.. Base line planning / development. fl. ' C. Data exchange / benchmark cases "; ., D. Production mode (interactive methodology. development) 50 VI. Interim Report A. Summary of Phase II-A work. B. . Detailed' work plan for Phase II-B d'. VII. Develop Implementation Plan-A. Develop' timetable for implementation B .* Develop schedule for Steering Committee meetings and-working group meetings C. Develop presentation of pool agreement structure and submitJ to. management for approval
. VIII.. ' Prepare final report A., . Detail of work performed B. Outline of remaining work i
G.l C. Preparation of skeleton pool agreement 1 i l-e., 5 '.
- 4
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Li APPENDIX D MODELING REQUIREMENTS The need for a computer model will likely evolve through three phases in the projects (1) basic conceptual models, (2) planning
~
model, and (3) billing model. Basic Conceptual Model. In the early conceptual design phase of the project, the use of computational aids to evaluate concepts will-likely be quite limited. Existing computer 6 P resources could be used to present ideas and project the general impact. In fact, the extansive use of comprehensive models would present the obvious disadvantages of diverting attention from general concepts and placing.an analytical burden on the team. Simple electronic worksheet analysis accompanied by minor user-developed computer software should be sufficient for this phase. Planning Model. Comparison of various alternative concepts will be required prior to finalizing a pool agreement. This planning model would serve two functions: (1) test concepts to determine whether they produce the _ intended effect, and (2) compare to the current agreements to determine economic viability. As a minimum, the models used would need to perf'rm o pro-forma pool billing of capacity and energy. Since it is generally agreed that some form of capacity stratification is required, individual unit capacity rates must be developed for each owner. This requires a representation (or approximation) of
)
each participant's corporate finance and unit ' accounting. Energy accounting can also-be (
#computationally intensive, particularly if simulation of the dispatch is being performed with ,
existing dispatching models. Extension of the simulation beyond the pool per se to include a comprehensive busbar analysis for each participant would be even more useful -- perhaps
. essential -- since the total impact of an
, , alternative can be analyzed. Such an extension is straightforward once the pool is modeled, and the extension results in a rather small computational burden.
l
< Billing Model.
1 The final modeling phase will be the development of l an hourly energy billing model for implementation of Page 30 , j N b *M2M5.'
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the pooling agreement. Historical and projected
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data would be utilized for development and , validation. The billing model should be developed prior to finalizing the pooling concepts so that alternative scenarios can be tested using detailed billing logic. 9 ^ Resources. Four models are currently available which might be useful in the Georgia Pool project in the Planning Model phase s OPC's Financial Model. h OPC's model was developed several years ago. It simulates the Georgia Pool concept developed in the 1977 negotiations. GPC and OPC are modeled explicitly and all energy costs are included. However, MEAG's sell-backs to GPC e" are not included in GPC's capacity sale rates. The model accepts input of an expansion plan, annual production dispatch and data, and various load, investment, and financial requirements and resources for GPC and OPC, projects and energy category costs (rates, including and sales computesand capacity purchases) for OPC. GPC's busbar costs are generally available, but not. currently
- tabulated. As a seldom-used option, a simplistic internal algorithm can be used to produce or modify the dispatch.
1 The OPC model is the most comprehensive model j available and the only comprehensive capacity j model for our purposes. However, the annual dispatch requirement poses a potential problem ] j in. energy accounting. It is likely that a less than annual pro-forma energy billing period will be needed, e.g., bi-weekly, monthly, or day type. Furthermore, modification of the { 1 model to simulate various pooling concepts is ! expected to be difficult due to the model ) structure. j t , The OPC model will be expensive for G?C to obtain. In addition to any purchase or lease charges by CPC, it will require acquisition of 1 the SIMPLAN modeling language at an estimated ; cost of $60,000 plus annual maintenance. 1 Energy Management Associates' PR Energy Model. This model was developed for use by MEAG with EMA's PROMOD program. GPC has had preliminary I discussions with EMA concerning use of the Page 31 a
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.q, L model. The-model uses a PROMOD dispatch p(;i "
interface file to produce monthly PR; energy billing. (A monthly representation may or.may: not be adequate for-pool hourly accounting;)- Several minor program modifications have been identified as needed if the model isLused for territorial analysis. Also, logic changes % would be required to convert to Pool from PR representation. H EMA has ' tentatively offered . the .model to' GPC L for $40,000. The cost to OPC would:likelyLbe' K- an: additional $40,000.; TheEmodel uses U MORTRAN/ FORTRAN, requiring no' incremental' language cost. GPC estimates that internal development of an interface to its detailed production cost program and the' addition of 3.;~
. capacity and_ report modules can be' completed by May 1; 1984 at an additional estimated cost of
$25,000 ($65,000 Ltotal).
PTI's Interactive Production Costing ModA1 (IPC) Oglethorpe currently leases .the IPC Model f rom PTI.' This is a production
- costing model which utilizes an hourly' redispatch methodology. The minimum' reporting period -in this. model is one week; however, hourly data can be obtained
, although not in a structured report format.
Oglethorpe currently has the technology to interface IPC with its other analytical models, specifica11y' its' Financiali Model and Partial-Requirement Model. The cost for GPC to obtain this model is undetermined. However, Oglethorpe believes its ' lease agreement with PTI will permit it to share the results of this model with GPC. Further, specific cases could be run.for Georgia Power and Georgia Power' personnel could use the model provided such use is supervised' by Oglethorpe, performed at Oglethorpe's premises and utilized Oglethorpe facilities. The only restriction to.the use of the IPC Model-is that it not leave the computer. While. it appears -IPC may be used in this study, Oglethorpe's present computer facilities may 4 not beable to handle the increased usage at
; this time.
XSIM Modeling Language of Interactive Data Corporation. Page 32 - _ _ _ . _ . ~ . - _ - _ , - _ - . ~ . . _ . - - , .- - . _ . ,
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( , I Oglethorpe currently has in-house the.XSIM
... modeling language developed by Interactive Data
- Corporation. This is a powerful time-oriented modeling language which may be useful in the modeling of pooling concepts . developed by the working conunittee. This language may. prove extremely useful in that'models developed in p- this language could be- interfaced with the IPC .
Model. (l ' '1 i: Page 33 c_ _wc_ z u.c_: - :. v - _. :: _. -. m _ - _ _ _ , _- _ _ , _ _ x__ , .-
. ~
Contract No.
, 89-00-1501-640 -
. 1/23/85 CONTRACT -
executed by s THE UNITED STATES OF AMERICA y DEPARTMENT OF ENERGY. acting by and through the SOUTHEASTERN POWER ADMINISTRATION s and GEORGIA POWER COMPANY O.1 THIS CONTRACT, executed. as of January 29, 1985, by and between the UNITED STATES OF AMERICA (hereinafter called the Government), Departme nt of ' Energy , acting by and through the Southeastern Power Administrator (hereinafter called the Administrator), and GEORGIA POWER L COMPAN_Y (hereinaf ter called Georgia Power), a corporation organized and existing under the laws of the State of Georgia; WITNESSETH: That, 0.2 WHEREAS Section 5 of. the Flood Control Act of 1944, as amended, (l'6 U.S.C. 825s) provides as follows: Electric power end energy generated at reservoir projects under the control of the Department of the Army and in the opinion of the Secretary of the Army not, required in the operation of such projects shall be delivered to the Secretary of Energy, who shall transmit ' l and dispose of such power and energy in such manner as to encourage the most widespread use thereof at the l lowest possible rates to consumers consistent with sound business principles, the rate schedules to become effective upon confirmation and approval by the Secretary of Energy. Rate schedules shall be drawn having regard to the recovery (upon the basis of the E application of such rate schedules to the capacity of the electric facilities of the projects) of the cost of , producing and transmitting such electric energy, ; i 9 l _, . _ _ _ , . _= - . , . _ >1 > .~_t z __--A~.x __ - t- :~ > -L' :--- _ 21 r
- :=- - - - - --
y- 3(r ~ E[ o including the amortization of the capital. investment i allocated to power over a- reasonable' period of years.. - l ' Preference in the . sale. of such power and energy shall be . W4 ^ given to public bodies and' cooperatives. The Secretary - of Energy is authorized, from funds.to be. appropriated by the Congress, to construct or acquire, by purchase or
'o th e r ' a g reeme n t', only .such transmission lines and related facilities as _may be'necessary in order to make p the: power : and ; energy generated 'at . said- proj ects
~ available in wholesale quantities for sale on fair and. reasonable terms and conditions to facilities owned by the Federal Government, public bodies, cooperatives, and'.
. privately : owned companies. All moneys received from such sales'shall be deposited in the.. Treasury of _the p United States as miscellaneous receipts.
and' O.3 - WHEREAS the Secretary of Energy by Interim Management J Directive No. 0204, dated October 3,:1977, as extended, delegated to the-Administrator = his. authority under Section 5 with respect to projects then or thereaf ter constructed in the States of West Virginia, Virginia, North , Carolina,. South Carolina, Georgia, F1'orida, Alabama, Mississippi, Tennessee, and Kentucky; and -- 0.4 'WHEREAS the Department of the Army has constructed reservoir projects: on the Etowah, Savannah, Alabama, Coosawattee and Chattahoochee Rivers known. respectively. as Allatoona, Buford, Carters, Clatts Hill, . Hartwell West Point, Millers Ferry, Robert F. Henry and Walter F. George and is constructing a reservoir project on the Savannah River known as'the Richard B. Russell Project (the ten Projects hereinafter sometimes
- collectively called the Projects) together with generating facilities whose output not-. required in the operation of the Projects shall be disposed of by the Administrator; and ,
0.5. WHEREAS the Government, acting through the Administrator, in accordance with Section 5 of the Flood Control Act of 1944, has decided to market electric capacity and energy to preference customers which are electrically connected to Georgia Power and to which the Government has no
~
2 desu zo =n u.m ._x wo =:mr,m m a,.. . . .E .u -
. . . ore
L . . transmission lines and, in furtherance thereof, proposes to utilize the transmission facilities of Georgia Power or others to deliver such capacity and energy to those preNrence customers designated by the Government under the terms of this agreement; and 3 0.6 WHEREAS Georgia Power is a public utility company engaged in the business of selling electric capacity and energy to the general public, and owns and operates generating plants and transmission and distribution
, systems which are electrically connected to the electrical systems 'of certain preference customers which the Government has designated; and 0.7 WHEREAS Georgia Power's generating and transraission system is interconnected with the Projects except Millers Ferry and Robert F. Henry and together with generating and transmission systems owned respectively by Alabama Power Company (hereinafter called Alabama Power), Mississippi Power Company (hereinaf ter called Mississippi Power), and Gulf Power Company (hereinaf ter called Gulf Power) form an interconnected system permitting the transfer of power between systems; and 0.8 WHEREAS the parties hereto have agreed and the Government has agreed with Alabama Power, Mississippi Power and Gulf Power (which together with Georgia Power are sometimes collectively referred 'to as "the C omp a ni e s " ) i n contracts executed simultaneously herewith, that the Projects enumerated in subsection 0.4 hereof will be operated to meet the respective and combined commitments of Government contracts with all such Companies; and 0.9 WHEREAS pursuant to the terms of the above-quoted statute, it is the intention and purpose of the Government to provide for the sale of, and it is the desire of the preference customers (as designated pursuant to Section 4) to purchase capacity and energy from the Projects in the maximum amounts consistent with the securing of a dependable arrangement for the 3
a,- ~ = _~ . s -x.- ~~+ . = = . ~- . - - -,
n 7-a transmission and_ delivery of such capacity and energy to such preference l customers' electric systems; and l-I' O.10 WHEREAS to secure and to maintain just such a dependable I arrangement, there will be made available to Georgia Power, Alabama Power, 4 Mississippi Power and Gulf Power, l l (1) for scheduling the use thereof in the Companies' systems, up to the total ~ amount of capacity made available and allocated by the Government to the Western portion of its Georgia-Alabama System (which for the purposes of this contract i s rated at 1,685,000 kilowatts af ter the Richard B. Russell Project is declared available for commercial operation); together with the total energy at Allatoona Project (hereinafter sometimes called Allatoona), the total energy at Buford Project (hereinafter sometimes called Buford), the total energy at Millers Ferry Project (hereinafter sometimes called Millers Ferry), the total energy at Rcbert F. Henry Project (hereinafter sometimes called Henry), the total energy at West Point Project ( he rei na f ter i sometimes called West Point), the total energy .at
-i Carters Project (hereinafter sometimes called Carters), J the total energy at Walter F. George 1.ock and Dam (hereinaf ter sometimes called George), approximately one-hal f (1/2 ) of the total energy at Clarks Hill Project (hereinaf ter sometimes called Clarks Hill),
approxia.4tely one-half (1/2) of the total energy at Hartwell Project (hereinaf ter sometimes called Hartwell) and the total energy of the first two conventional units
~
4
- 2 *-
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.A., A__4_m- T* ? 12. E k l._
- a- * ..i' _l e_. 2 _a. m%~ 2-.__ _ A_ .- __ m m a..m m. u_ T _ _ _ . A44___._
7
.j of the Richard 8. Russell Project (hereinafter sometimes '
called Russell) until such time as the third and fourth conventional ~ units are declared available for commercial operation, at which time approximately one-half (1/2) of x the total energy at Russell', specifically including the use of the capacity and accompanying energy being sold ! to the preference customers, and b (2) for outright purchase thereof by the Companies, up to. the following kilowatts of cepacity during the periods specified: s.; Period Capacity (kw) February 1985 thru May 1985 655,719 June 1985 thru May 1986 588,454 June 1986 thru May 1987 519,541 June 1987 thru May 1988 450,473 June 1988 thru May 1991 276,000 June 1991 thru May 1994 ' as such scheduling and purchase are ' defined and conditioned, and with respect to both of which the preference customers, in separate contracts l between them and the Government, have foregone and waived the exercise of ) any rights in connection with such power as they, under the law, may have; and 0.11 WHEREAS the parties have intentionally not described or characterized the capacity being made available under this contract as
')
" dependable," or.by any other descriptive adjective or connotation, it is the position of the Administrator that the capacity to be made available
.for purposes of this contract is dependable; and considering the time period selected and the use to be made of the capacity, Georgia Power may i
or may not agree with a description of a portion of the capacity as being q dependable; however, in any event, such descriptions and characterizations ! I i l , s ! l
. t .N A o
- 1.,7w i._ Om *.m _.E 4 l * '.5 '
- -- 1 * - * " ' ' - - - - - - - " - - - - - - - - - - - - - - - - "
l'
& l are not necessary to the performance of the obligations undertaken by j either party to this contract; and '
O.12. WHEREAS the parties hereto recognize that the Government, in a separate contract with South Mississippi Electric Power Association w- ' (hereinaf ter called SMEPA), a generation and transmission cooperative, has sold during the ters of this contract up to 61,000 kilowatts of capacity . and weekly amounts of energy before losses, exclusive of any pumped energy,
~
during the respective months as follows: Month Energy Month Energy mwh nwn January - 1587 July 2011 February 2116 August 2011 March 2116 September 1905 April 2011 October 1286 May 1587 November 1286 June 1693 December 1481 li 0.13 WEREAS the parties hereto recognize that the Government, in a sept. rate contract with Alabama Electric Cooperative, Inc. (hereinaf ter called AEC), a generation and transmission cooperative, has sold up to 91,000 kilowatts of capacity and a pro rata portion of the declared energy, exclusive of the energy allocated to SMEPA, during the term of this
. contract; and 0.14 'WHEREAS the parties recognize th'dt the Government has l
entered into contracts with other preference customers located within the States of Georgia, Alabama, Florida and Mississippi for the sale of up to - I the following kilowatts of capacity during the periods specified: ' Period . Capacity (kw) L February 1985 thru May 1985 770,281 June 1985 thru May 1986 944,546 June 1986 thru May 1987 - 1,013,459 June 1987 thru May 1988 1,072,527 June 1988 thru May 1991 1,107,000 June 1991 thru May 1994 1,296,000 ' 6 w_ _ _ _ - , _ _ _ _ _ =_ . - - - - = s_ = _ -
=- .a =0
0.15 WHEREAS the parties hereto have agreed that the Government will hold in reserve and not make available for sale or use to any party
-(other than the scheduling rights granted to the Companies) the following kilowatts of capacity. during the periods specified:
4 Period Capacity (kw) June 1987 thru May 1988 - 10,000 June 1988 thru May 1991 150,000 June 1991 thru May 1994 237,000 0.16- WHERE AS the parties hereto have agreed that the transmission lines of Georgia Power will be utilized on the terms and conditions and during the time f rames hereinaf ter set forth for transmitting and disposing of capacity and energy from the Projects; and 0.17 WHEREAS the parties hereto have agreed to purchase, sell and exchange power on the teries and conditions hereinafter set forth: WOW, THEREFORE, in consideration of the premises and of other condiff ons hereinafter set forth, the parties hereto mutually covenant and agree as follows: Section 1. Capacity To Be Made Available. j i 1.1 Georgia Power, together with the other Companies, shall have the right to schedule the use of all of the capacity made available and allocated by the Government to the Western portion of its Georgia-Alabama System (from the Projects identified in Section 0.10(1) hereof). { I 1.2 Of the amount of capacity being purchased by the Companies { l as identified in Section 0.10(2) hereof, Georgia Power agrees to purchase d for its own use the following kilowatts of capacity each month (except as modified by the provisions of subsectic 11.6) during the periods specified: i. l 7 i l
)
4
p . Period Capacity (kw) Jan, thru Apr. June thru Aug. May & Sept. Oct thru Dec. February 1985 thru May 1985 410,746 379,309 June 1985 thru May 1986 383,602 360,398 328,960 h' June 1986 thru May 1987 332,021 308,817 277,380 June 1987 thru May 1988 280,323 257,120 225,683 June 1988 thru May 1991 149,730 149,730 149,730 June 1991 thru May 1994 0 0 0 1.3 Of the amounts of capacity (identified in Section 0.14
~
hereof) being allocated to preference ' customers by the Government, the parties agree that the following amounts of capacity will be made available
.each month to preference customers located within the State of Georgia O during the periods specified:
Period Capacity (kw) February 1985 thru May 1985 575,573 June 1985 thru May 1986 707,623 June 1986 thru May 1987 759,069 June 1987 thru May 1988 803,166 June 1988 thru May 1991 831,094 June 1991 thru May 1994 970,000 l 1.4 The Government agrees to hold in reserve and will not make available for sale or use to any party (other than the scheduling rights e granted to Georgia Power together with the other Companies) the following kilowatts of capacity during the periods specified: Period Capacity (kw) June 1987 thru May 1988 10,000 June 1988 thru May 1991 150,000 June 1991 thru May 1994 237,000 i 1.5 The commitment to make capacity available under subsections 1.1 through 1.4 and energy available under subsection 2.1 is an overall commitment to be met from all the Projects; provided, however, that such capacity and energy shall be divided among the respective Projects in amounts acceptable to the Companies. 8 L.~ ._- . _: . . - _ . . :~=.. ... i . -_-____;_ ~___n_.
O 1.6. Prior. to the commercial availability of the first two conventional units at Russell, (a) The capacity in kilowatts to be purchased by Georgia Power for its own use pursuant to subsection 1.2 shall be reduced to the amounts shown in the following table:
--- If Zero Units Available ---
Jan. thru Apr. June thru Aug. May & Sept. Oct. thru Dec. February 1985 thru May 1985 357,603 326,166 June 1985 thru May 1986 254,860 231,656 200,220
--- If One Unit Available ---
3" Jan, thru Apr. June thru Aug. May & Sept. Oct. thru Dec. February 1985 thru May 1985 410,746 379,309 June 1985 thru May 1986 310,997 287,794 256,357 Payments f or such capacity shall be prorated by the number of days remainj ng in the month when the unitis) become commercially available. (b) In the event the commercial availability of either of the first two units at Russell is delayed beyond May 1986, the amount of capacity to be purchased by Georgia Power pursuant to subsection 1.2 and the amount of capacity to be allocated to preference customers pursuant to subsection 1.3 shall be equitably adjusted by negotiations between the parties to reflect the unavailability of such units. 1.7 The Government's commitment to make capacity available shall be subject at particular times to restrictions on generation at Allatoona or at Buford by the Corps of Engineers for flood. control purposes; provided, however, that capacity not delivered from Allatoona or Buford during such perioos of restricted generation shall, with accompanying i mi nimum ene rgy , be delivered to Georgia Power, if or to the extent available, at other projects listed in subsection 0.4. 9 L . L_- , nm - -= =. = - -- - - - - - - - - -- . =-
i 1.8 .ne Integration Agreement between the Government and Georgia Power dated June 28, 1957, as amended, which provides for the integration
,of the Projects listed in subsection 0.4 (except Millers Ferry, Henry, and Carters) with the Jim Woodruff Project (hereinafter called Jim Woodruff) anticipates that up to a total of 22,222 kilowatts of support capacity
. required by Jim Woodruf f' may. be supplied from the seven projects. The Government may make available from the seven projects for delivery to Jim Woodruff (and will account for such as having been taken by Georgia Power) up to 22,222 kilowatts.
1.9 For purposes of determining monthly capacity to be made available and for purposes of scheduling capacity at the Projects, a week shall be deemed to commence at the beginning of Saturday and extend to the end of the next Friday. Any week which falls within two months shall be considered to be completely within the month in which Wednesday of such week falls. 1.10 During the tem of this contract, the parties agree that the total capacity of the Carters Project is 575,000 kilowatts of which, for the period February 1,1985 through May 31, 1991, only 276,000 kilowatts shall be deemed to be capacity supported by pumped energy and for the period June 1,1991 through May 31,1994, only 388,000 kilowatts shall be l' deemed to be capacity supported by pumped energy; however, all energy, both 7 natural flow and pumped, shall be available to support the total 575,000 s kilowatts of generating capacity at the Carters Project. Section 2. Energy To Be Made Available. 2.1 (a) There shall b'e made available to Georgia Power from the Projects each week and Georgia Power will accept mi nimum weekly declarations of energy during the respective months for the period February 1985 through May 1991, as follows: 10 __1 . _ _ _ _ .___ _ _ _
I l Minimum Weekly Minimum Weekly l Declaration Declaration
~
Month avh/ week Montt mwh/ week January 17,636 July 22,019 Februa ry 15,025 August 25,866 March 13,685 September 21,536 g April 13,913 October 18,396 May 16,161 November 17,637 June 19,450 December 17,790 (b) There shall be made available to Georgia Power from the h Pro.iects each week and Georgia Power will accept minimum weekly declarations of energy, including Carters pumped energy, during the 1 respective months for the period June 1991 through May 1994, as follows: L., Minimum Weekly Minimum Weekly Declaration Declaration Month mwh/ week Month mwh/ week January 19,400 July 22,019 February 19,400 August 25,366 March 19,400 September 21,536 April 19,400 October 19,400 l May 19,400 November 19,400 J.pne 19,450 December 19,400 (c) In the event the first two units at Russell are unavailable, i these. weekly quantities for the period February 1985 through May 1991 will be reduced in accordance with the tat .e set forth in Appendix A hereto. Any week which f alls withi n two r.onths shall, for the purpose of determining the minimum energy to be made available, be considered to be completely within the month in which Wednesday of such week falls. If releases to meet streamflow requirements are necessary in addition to power releases scheduled, the Goverranent may make available to Georgia Power and ! Georgia Power shall take energy equivalent to 69.935 percent of the energy at Allatoona, Buford, Millers Ferry, Henry, West Point, Carters and George, respectively, and 34.9675 percent of the energy at Clarks Hill, Russell (af ter the four conventional units are declared available for commercial operation) and Hartwell, respectively. L 11 -
. . .. : _ =_ _.: - __ _ _ _ _ _ _
1 b - 2.2 The Government shall determine when energy in excess of minimum is available for declaration and shall make available to Georgia l Power and Georgia Power sna11 accept declarations of such energy so that at each project total declarations (including minimus) will not exceed the k total quantity of energy that can be generated during the 168 hours of a 1 week: (or during'any portion thereof remaining at the time a revised declaration becomes effective) with 69.935 percent of the machine capability available by days at Allatoona, Buford, Millers Ferry, Henry, 1 West Point, Carters, and George, respectively; 34.9675 percent of the machine capability available. by days at Clarks Hill and Hartwell, p respectively, and 69.935 percent of the machine capability available by
^
days of the first two conventional units at Russell until such time as the third and fourth conventional units are declared available for commercial-operation at which time 34.9675 percent of the machine capability available by days at Russell; provided, however, that 69.935 percent of the capacity utilized to make transfers to Jim Woodruff or to perwit the Government to furnish standby capacity to South Carolina Public Service Authority, shall I for the days actually so utilized, be subtracted from the total capability available for the purpose of determining maximum declarations of energy which the Government shall make available to Georgia Power and which Georgia Power shall accept under this subsection 2.2; provided further, that Georgia Power will not be required to accept with the capability hereinbefore made available at the Clarks Hill, Russell (after the four conventional units are declared available for commercial operation) and Hartwell Projects, more than 34.9675 percent of the excess energy available in any week t any of the aforesaid projects. Declarations of excess energy shall be made for periods not shorter than the remainder of the week in which they become effective $ut such declarations may be increased with 12 i w - . .- ._ c : .- . .- - ; .? :_ s --___a_ ^ _-__ - - : ._ __ i
respect to ~ quantities at any time and may be decreased as provided herein for transfers to Jim lioodruff or to permit standby operations to South Carolina Public Service Authority or upon mutual consent of the parties. Subject to the provisions of subsection 2.5, declarations and revisions [ shall become ef f ective as agreed between the operating representatives of. the Government and Georgia Power. 2.3 Energy declarations made in accordance with subsections 2.1 3 and 2.2 shall be scheduled for the respective Projects by Georgia Power during the period for which they are made; provided, that the Government may require, solely for the purpose of meeting streamflow requirements, up y to fif teen percent (155) of the total minimum energy made available under subsection 2.1 to be scheruled from the Projects designated by the Government during any of tt.e five days, Monday through Friday, inclusive. Schedules for the respective Projects showing hourly quantities of declared and storage energy (pursuant to Section 15) shall be furnished by Georgia Power to the Government's duignated operating representative for each declaration period. Subject to the provisions of subsection 1.5 energy o shall be taken by Georgia Power in accordance with such hourly schedules or stored in'accordance with the provisions of Section 15. Schedules may be revised by Georgia Power at any time and schedules or revisions thereof shall become effective upon reasonable notice. During the ters of this contract 1.6790721649 percent of the energy made available by the Government to the Company in any week shall be scheduled by the Crisp County Power Commission against the Company's system during the period for which the declaration is made. Schedules showing hourly quantities of ) I declared energy to be Jelivered shali be furnished by Crisp County for each , declaration period to both Georgia Power's designated operating 4 representative and the Government's designated operating representative. 13 b _m._ _.__E_l. 'Zi' ' ~ ~ I_m_. _m . [ ' ___. _ _.o_1_ E Y. _ i _ ' .I d. . "_hh ,__._M __. J _ __ _1 M '$ _ _ m._mm_. ._ m._ __.a m. ' _ _ _ ___. . _ _ ._ _2 . _...___._ _'.___ iu._ _ au _ _ . .-u
4 I Hourly schedules shall not exceed the capacity allocated to Crisp County. Schedules may be revised by. Crisp Co,unty at any time and schedules or revisions thereof shall become effective upon reasonable advance notice. It is understood that the Government will require Crisp County to schedule its pro rata share of all energy declarations for the purpose of meeting streamflow or must run requirements. It is also understood that Crisp County's right to schedule will not influence their energy credit for billing purposes as set forth in subsections 5.3 and 5.4. 2.4 Energy will be furnished by Georgia Power to supply the equivalent of 74.85 percent of any excess of Project use over Project w generation at each of the Projects listed in subsection 0.4. Project use energy at Allatoona shall include that ergy delivered by Georgia Power, plus losses, to the City of Cartersville for the account of Thompson, Weinman and Company under existing arrangements. Energy so supplied by Georgia Power will be deducted from the actual deliveries to Georgia Power to determine the net energy deliverief for energy accounting and billing purposes. 2.5 The Administrator shall endeavo- to limit weekly declaration changes to a minimum per project, unless otherwise mutually agreed, or during flood concitions. Section 3. Points of Delivery to Georgia Power. Capacity and energy delivered to Georgia Power hereunder will be , delivered to it at mutually agreeable points in the vicinity of the Projects' power stations or at points of interconnection between Georgia euwer and Alabama Power. The delivery voltage at the Hartwell, Russell and Carters Projects, respectively, will be approximately 230,000 volts; at the other Projects, approximately l'.5,000 volts. 14 L- ua= - __ _ = _ - . - = . - _ ._ . _ - . ' .. _:. __ _ _a -
A 'p- . .
'( j
. Section 4. Designation of Preference Customers.
The customers in Georgia to whom the. Government has allocated l capacity _ and energy are any of the following whose requirements or a
, portion thereof the Government shall have contractee to supply by delivery ,
.from the. Georgia Integrated Transmission System pursuant to this contract:
a municipality, county or other public body detemined by the Government to' be a preference entity owning its own transmission or distribution system, and desiring to purchase capacity and energy from the Government for resale to the public in its territory or an electric cooperative operating unoer the Georgia Electric Membership Corporation Act of July 1,1981, as amended, interconnected with the Georgia Integrated Transmission System
- desiring to purchase capacity and energy from the Government for resale under the provisions of said Act. It is expressly recognized that the Government was solely responsible f or this determination of the-qualifications for designation as a preference customer and the selection of such customers including the amount of capacity and energy to be allocated to such customers.
Section 5. Determination of Capacity and Energy To Be Made Available to Preference Customers. 5.1' The capacity made available by the Government to preference customers in the State of Georgia (as provided for in subsection 1.3) shall be allocated to preference customers and the delivery points of the [espective preference customers by the Government. Allocation of capacity -i to 'each delivery point of each pref erence customer shall be approximately l pro rata based on the maximum load at each delivery point of such customer l and shall be reallocated whenever a new point is added or an existing point 1 is discontinued as agreed to by the Government and the preference custome rs. However, nothing in this contract shall be construed to require f n. 15
. _2.A .m aA m m_ah___[_h-_. .m__m_. _a u. _m A.a__A_' _._m_ am.-__ a_ ____ . _ _ . m..___m__ _m___w_.2__n_. __ m.h__
_' O '
~ .. Georgia Power to relocate any existing delivery points or establish additional delivery points for the Government's preference customers, but the relocation of existing points or the establishment of additional points shall be a matter solely between Georgia Power and the preference customers. The initial allocations of capacity by the Government to each preference customer are set forth in Appendix B to this contract. Changes in these initial allocations may be made by the Government upon prior % written notice by the Administrator to Georgia Power. 5.2 Georgia Power will provide an appropriate capacity credit to the preference customers .to whom a capacity allocation has been made by the Government as set forth in subsection 5.1. This credit will be provided in accordance with the provisions of the then current and effective tariffs or rate schedules of Georgia Power as filed with the Federal Er.ergy Regulatory Commi s si o n. As of the date of the execution of this contract, existing tariffs and rate schedules will provide capacity credits equal to the amounts set forth 'n subsection 1.3 and will not require preference customers to furnish or purchase reserves in respect to such capacity. It is understood by the parties that such tariffs or rate schedules including the provisions related to this capacity credit are subject to adjustment pursuant to subsection 5.5 hereof; however, for the term of this contract, such tariffs or rates will provide capacity credits equal to the amounts l i set forth in subsection 1.3 and will not require preference customers to furnish or purchase reserves in respect to such capacity.
]
5.3 The amount of energy that shall be available under the terns i of this contract to accompany the capacity allocations of the Government's { preference customers af ter adjustment for the energy allocation to SMEPA, - pursuant to Section 0.12, shall be 94.5 percent (reflecting 5.5 percent l losses) of the sum of the following: (1) approximately 69.935 percent of 4 16 L 2_.. _.-_2 ._:__m_...A _O _ . , _ . _mi_.A* _' u u.A _? k
._4 .h. _l._ _-. ..
the declared energy at Allatoona, Buford, Millers Ferry, Henry, West Point and George, (2) approximately 69.935 percent of the declared energy resulting from natural flows at Carters (excluding pumped energy until June 1991 which is addressed in subsection 6.3), (3) approximately 34.9675 percent of the deci. red energy at Clarks Hill and Hartwell, and (4) approximately 69.935 percent of the declared energy of the first two conventional units at Russell until such time as the third and fourth w conventional units are declared available for commercial operation at which time approximately 34.9675 percent of the declared energy at Russel); and adjusted for the following: (1) any transfers to Jim Woodruff as provided D for in subsection 2.2, (2) any energy associated with standby capacity f urnished by the Goverreent to South Carolina Public Service Authority as provided for in subsection 2.2, (3) project use ano any energy supplied by Georgia Power for project use pursuant to subsection 2.4, (4) streamflow generation pursuant to provisions of subsection 2.1, and (5) other energy transactions mutually agreed to by the parties. The initial capacity and energy allocations (expressed as percentages) by the Government to each preference customer are set forth in Appendix B to this contract. Changes in these initial allocations may be made by the Government upon prior written notice by the Administrator to Georgia Power. 5.4 Georgia Power will provide an appropriate energy credit to the preference ' customers to whom an energy allocation has been made by the Government as set forth in subsection 5.3. Such credit will not be altered l by storage transactions under Section 15. The credit will be provided in accordance with the provisions of the then current and effective tariffs or rate schedules of Georgia Power as filed with the Federal Energy Regulatory C ommi s si on. It is ur.derstood by the parties that such tariffs or rate schedules including the provisions related to this energy credit are 17 L_ x = _ a_ _ _w - un _m . w_ - _ a _.- -_l . _-- _ - _
v
! subject to adjustment pursuant to subsection 5.5 hereof. The amount of energy to be credited in a billing period (1'.e., the period of time between .
- meter readings of a delivery point of a preference customer) under such tariffs or rate schedules shall be determined in accordance with the P ' calculation specified in subsection 5.3. Since the actw1 data for the energy calculation provided for in subsection 5.3 may not be available by the preference- customer billing date, estimated data may be utilized to 5' detemine' the amount of energy to be credited during the billing period and an appropriate adjustment will be made after actual data becomes available.
5.5 Notwithstanding anytning herein to the contrary, Georgia p Power shall have the right to make unilateral application to the Federal Energy Regulatory Commission, or its successor in function, for a change or substitution in whole or in part in any of its tariffs, contracts or rate schedules and the terms and conditions of service contained therein, including such tariff s, contracts or rate schedules with preference castomers or other power supply entities. This subsection shall. not be construed to waive, limit, or otherwise change the rights of any preference customer under the Federal Power Act -to oppose such changes or substitutions. Section 6. Accounting and Rates. 6.1 (a) Georgia Power will pay the Government for monthly capacity made available to it as provided for in subsection 1.2 at the rate of $1.41 per kilowatt per calendar month. (b) Georgia Power will pay the Government for the use of its Projects including Carters pumping capability the following monthly amounts for the periods specified: W 18 u ~_ .:. -= u~_.n x. . - -. - . -
(. Period - Monthly Charge February 1985 thru May 1985 581,875.00 June 1985 thru May 1986 - 80,412.00 June 1986 thru May 1987 78,500.00 , June 1987 thru May 1988 75,912.00 June 1988 thru May 1991 67,812.00 > 6.2 As between the Government and Georgia Power, energy made available under this contract shall be accounted for on a calendar month basis.- To determine the total energy made available to Georgia Power in C any month, in accordance with subsections 2.1 and 2.2, the energy made-available for any week which f alls within two months shall be divided between the months on the basis of the schedules furnished by Georgia Power p under the provisions of subsection 2.3 showing daily quantities of energy. 6.3 For the period beginning February 1,1985, and ending May 31, 1991, the Ccapanies will furnish all of the pumping energy required at Carters and tha Companies will in turn be entitled to receive for their own use all energy generated from pumped water. Southern Company Services, Inc., acting as agent for the Companies, will, with concurrence of the Government, determine the amount and frequency of pumping at Carters. A conversion f actor of 70 percent shall .be applied to the net quantity of-pumping energy furnished by the Companies to determine the net quantity of energy that can be subsequently generated f rom pumped water. The conversion factor may be chan9ed by the Government with the concurrence of the Companies as experience warrants. The Companies will be allowed to examine all test and other data involved in determination of the conversion factor. Subsequent to May 31, 1991, the preference customers served hereunder will assume responsibility for the supply of pumping energy and will receive the energy resulting therefrom. 6.4 The rates and charges for the sale of capacity under this contract shall be subject to interim approval by the Deputy Secretary of g 19 ihe i mi_m _1_m ' E _.z_2 ___<m _ 2 m __ _ _ _ . . _ . .m _s I
p - the Department of Energy and to final confirmation and approval by the Federal Energy Regulatory Commission. 6.5 The rates and charges for the sale of capacity under this contract shall be subject to adjustment on October 1,1985, and on ?- October 1,1990; provided that any adjusted rates or charges shall not become effective unless and until confirmed and approved on 2n interim basis by the Deputy Secretary of the Department of Energy and shall be subject to final confirmation and approval by the Federal Energy Regulatory Commission; provided further, that the Administrator may extend any rate adjustment date by up to one year if written notice is given to Georgia ? Power sixty-(60) days in advance of such dates. In no event will the rate or charge for capacity purchased by Georgia Power from the Government be higher than the rate or charge established by the Government for capacity sold to preference customers after such preference customer rate or charge has been reduced to exclude that portion of the preference customer rate or charge which is attributable (1) to transmission charges paid by the Government to the Companies or to any other entities performing transmission services for the Government, (2) to other charges paid by the Government for services provided by Georgia Power under this contract or similar contracts with the other Companies, and (3) to other costs or 1 charges experienced by the Government which are not directly related and directly allocable to the capacity being sold to Georgia Power. Further, for the rate period beginning with the rate adjustment date October 1,
'1985, or such extended rate adjustment date pursuant to this subsection, the capacity rate per subsection 6.1(a) will not be increased by a percentage which is greater than the percentage increase in the generation costs (total costs allocated to power generation including all fixed and variable costs but excluding all costs properly allocated to transmission !
20 i LA:xw Ra.. _c - . L . .. - . <
- ,n . .n.. .. n
and delivery service) filed by the Administrator with the Federal Energy Regulatory Commission for the rate period beginning with the rat'e ' adjustment dated October 1,1984, (FERC Docket No. EF84-3011) and the generation costs to be filed by the Administrator in support of the rates-for the rate period beginning with rate adjustment dated October 1,1985, or such extended date pursuant to this subsection. Nothing herein shall be construed to waive, limit or otherwise restrict the right of Georgia Power to oppose any proposed change in the Government's rates and charges for capacity and energy. 6.6 The Government shall notify Georgia Power in writing at least three months prior to the effective date thereof of any proposed adjustment in rates and charges including the amount of such proposed adjustment and the reasons therefor and also shall notify Georgia Power promptly in writing of any adjustment in rates and charges when confirmed and approved by the Federal Energy Regulatory Commission. Notwithstanding anything herein to the contrary, if such adjusted rates and charges, as of the rate adjustment date of October 1,1985, or the extended rate adjustment date pursuant to subsection 6.5, exceed 51.70 per kilowatt per month, Georgia Power, at its sole option,-may cancel this contract in its entirety, upon p giving the Admir.!strator written notice of cancellation within sixty (60) days af ter rece jt of notice from the Government advising of such adjusted rates and charges, such cancellation to become effective at a' time l specified by Georgia Power not less than four (4) months from the date of l l receipt of the notice of proposed adjustment given by the Administrator, l l l and the Administrator at his sole option may cancel this contract in its entirety upon receiving notice of cancellation f rom Alabama Power, Mississippi Power or Gulf Power, such cancellation to become effective at the time shecified by Alabama Power, Mississippi Power or Gulf Power. 21 Mm fm.. iw& a -m_... L* . ~ . _ x .%. * - nu e 2,
v . I Section 7. Transmission Services To Be Provided the Government.
. 7.1 (a) During the period February 1,1985, through May 31, 1989, Georgia Power shall deliver to all of the Government's preference g customers in Georgia the capacity allocated in subsection 1.3 in the amounts and at the delivery points as established pursuant to subsection 5.1. Georgia Power shall deliver to all of the Government's preference customers in Georgia the energy declared pursuant to subsections 2.1 and 2.2 in the amounts ~ and at the delivery points as established pursuant to subsection 5.3. It is recognized that the Administrator and Georgia Power may enter into alternative transmission arrangements to that stated in this subsection 7.1(a) for delivery of some or all of the capacity allocated in subsection 1.3.
(b) Effective June 1,1989, and continuing for the remaining ters of this contract Georgia. Power will continue to deliver capacity and energy as provided for in subsection 7.1(a)- to all preference customers in Georgia other than those preference customers who are participants of the Municipal Electric Authority of Georgia. or members of Oglethorpe Power Corporation or a participant in the Georgia Integrated Transmission System. 7.2. It is recog11 zed that a portion of the capacity of the Projects located in and adjacent to the State of Georgia exceeds the capacity allocated by the Government to preference customers located within the State of Georgia. During the tem of this contrt:t, Georgia Power will deliver capacity and energy to its interconnections with Alabama Power and Gulf Power for f urther delivery to preference customers of the Government located outside the State of Georgia. It is recognized that the l alternative transmission arrangements referred to in subsection 7.1(a) may 22 --m u_ ____ _ _ . _ _ a _ __ _ m = _ 1_ _ m i_ _ _ _ . - .
t . o also include an alternative transrdssion arrangement with respect to the capaci6 referred to in this subsection 7.2. 7.3 Delivery for the account of the Government to all preference customers being served by Georgia Power pursuant to this contract shall commence upon the effective date hereof, a request for such delivery having been previously made by the Government. In making the request for service under this Section 7, the Government shall certify in writing to Georgia Power that such delivery will be for the purpose of serving the preference g customers under this contract and shall furnish to Georgia Power one copy of each of the contracts which have been executed between the Government ~ and each of the preference customers for such electric service. 7.4 Georgia Power will discontinue delivery of electric capacity and energy for the account cf the Government to any preference customer of 4 the Government under the terms of this Section 7 upon receipt of a written reques$ to do so from the Administrator delivered to Georgia Power not less than fif teen (15) days prior to the, effective date thereof and upon certification by the Administrator that notice has been given to the preference customer. The Government shall also-furnish Georgia Power with copies of any notice of termination of any contract with a preference customer given by either party to such contract, but Georgia Power shall have no obligation to discontinue deliveries unless expressly directed to do so by the Government. Section 8. Charge for Transmission Service Furnisned by Georgia Power to Government. 8.1 The Government will pay the Companies for the use of their f acilities in delivering capacity and energy for the account of the Government (pursuant to Section 7 herein and Section 7 of the other 23 = - __ x _ a _ - _ - _
._x,_-+ a .i, ~. . _ _ .. ._-
L < j p y Government-Company contracts) the following amounts during the periods b specified: Period Monthly Charge l February 1,1985 to May 31,1985 $ 625,000.00 b June 1, 1985 to'May 31, 1986 875,000.00 [ June 1,1986 to May 31,1987 1,166,666.67 June 1,1987 to May 31,1988 1,416,666.67 June 1, 1988 to May 31, 1989 1,775,000.00 Georgf a Power will notify the Administrator of the portion of the above n monthly payment to be paid to Georgia Power at least 30 days in advance of the due date- of the payment. It is expressly recognized that the above monthly payments are not adequate to fully compensate the Companies for the H cost of providing such service and that the Companies have agreed to such payments as a portion of a total package of benefits to be derived over.the term of this contract. l 8.2 Effective June 1,1989, the Government will begin paying Georgia Power monthly for the use of its facilities in delivering capacity and energy for the account of the Government (pursuant to subsections 7.1(b) and 7.2) an amount det. wined in accordance with the cost of service formula attached to this contract as Appendix C and entitled Transmission Service Allocation Methodology and Periodic Rate Computation Procedure Manual ("the Manual") which is incorporated herein by reference. Section 9. Metering and Records. 9.1 The electric capacity and energy delivered to the Government's preference customers will be measured at the now existing points of delivery or at such points as may subsequently be established as provided i n subsection 5.1. Electric capacity and energy delivered to Georgia Power by the Gove'enment will be measured by meters installed at the Projects. When measurement is made at any location other tnan a point 'of 24
^ ' ._ - . _ - _ - - - - _ - . - - - -- L- mi-
a (2)' An interruption or reduction of capacity made available to l
. Georgia Power as provided for in subsection.1.2 with a corresponding reduction in capacity payments by Georgia Power which shall be computed on a daily basis for each day of the billing period in accordance with the 1.
'~ following formula: Number of kilowatts unavailable x Monthly Demand Charge for at least 12' hours in any Number of days E calendar day in billing month (3) An interruption or reduction of capacity made available' to preference customers as provided for in subsection 1.3 with a corresponding reduction in the capacity credit afforded preference customers under k subsection 5.2 during the preference customer billing period when such interruption or reduction occurs. l (b) Duri ng the period June 1991 through May 1994, any interruption' or reduction in capaeMy made available, which exceeds the amount of unsold capacity set forth in subsection 1.4 and which has not been arranged for or agreed to in advance by the parties, will not be i deemed to be an interruption or reduction of the capacity made available to the preference customer under subsection 1.3 for the instant calendar month in which such interruption or reduction occurs plus an additional thirty (30) day period. If the period of such interruption or reduction in capacity exceeds the aforesaid instant calendar month plus an additional thirty (30) day period, the Administrator for the next' subsequent sixty , I (60) day period following the end of the aforesaid additional thirty (30)- day period, will reduce the amount of capacity to be made available to preference customers of the Government to the actual amount of capacity available, with a corresponding reduction in the capacity credit to be afforded by Georgia Power pursuant to subsection 5.2 hereof. If the period of such interruption or reduction ,in capacity exceeds the aforesaid instant 29 w _ -_-- - -- -
- _- ._ -- - =- = - - at - m=~ ~ s 1
e .* . 4 calendar month plus an additional thirty (30) day period as well as the ? next subsequent' sixty (60) day period, the Administrator will reduce the
-amount of capacity made available to the preference customers to the actual
' amount of capacity available, less fourteen percent (145) reserves, with a k
corresponding . reduction in the capacity credit to be afforded by Georgia Power pursuant to subsection 5.2 hereof. 12.3 In the event the Government is unable to deliver or elects not to deliver from the Projects any portion of the minimum weekly energy specified in subsection 2.1 (without regard to whether such inability or election is caused by an uncontrollable force set forth in Section 16) the Government shall 'obtain replacement energy from other sources to meet such weekly minimum energy obligation, If the Government requests Georgia Power to replace all or part of the minimum weekly energy not delivered by the z Government, Georgia Power agrees to sell. to the Government and make available to preference customers for. its account replacement energy up to 1 the quantity of minimum energy not delivered by the Government, less five {! and one-half percent (5-1/2%) losses, if available on Georgia Power's . System or if it can be acquired by Georgia Power from other sources; provi ded, however, that the Government shall pay Georgia Power an amount > equivalent to the cos t, plus fifteen percent (15%) of such energy, including losses, from the least expensive alternative source (after provision of Southern System load requirements, off-system sales and any
, other sales of opportunity) then deemed available by Georgia Power for that purpose.
l
'. 2 . 4 In the event Georgia Power is unable to receive capacity and energy at the Clarts Hill, Russell, Hartwejl, George and Henry Projects due 4 to equipment f ailure or other uncontrollable causes on the Companies' systems, the Government will endeavor to deliver to other agencies with l
30 2= = a ~ . x -
= - ==: w- == - -.-- =E - - *
whom Georgia Power has appropriate interconnection agreements at available interconnections for delivery to Georgia Power that portion of Georgia i' Power's declarations that can' be transferred without adversely affecting the interconnected system or the system of the transferring party. That , i portion of the declaration not delivered to Georgia Power during the period of interruption will be stored by the Government as space is available, and such Stored energy shall be delivered to Georgia Power at such time as Georgia Power's facilities are restored and capable of taking i delivery. In the event other customers of the Government being served from l Clarks Hill, Russell, Hartwell or George are unable to receive capacity and energy into their systems through their connections to the Government Projects, Georgia Power will endeavor to accept that portion of such customers' declarations that can be transferred to such customers without adversely affecting the interconnected system or the transferring party and provided that Georgia Power has an appropriate interconnection agreement with such customers. . 12.5 In the event of interruptions or emergencies in its own transmission or generating facilities, Georgia Power will endeavor to maintain the same continuity of service to preference customers of the Government served pursuant to this contract as it endeavors to maintain for Georgia Power's customers not receiving Projects' power. Section 13. Scheduled Maints.w .. The parties hereto shall so f ar as practicable coordinate their scheduled outages of f acilities for maintenance to the end that the highest degree of continuity and reliability of deliveries pursuant to this agreement will be mai ntai ned. The parties through their operating representatives may agree to a reasonable variation in the quantities of capacity delivered to Georgia Power pursuant to subsection 1.1 when such 31
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variation will facilitate scheduled maintenance on the parties' respective
; systems; provided, that payment for capacity as specified in subsection -
6.1(a) shal.1 not be changed by any such agreements. Section 14. Power Factor, Voltage Control' ; and System Reliability. 14.1 Georgia Power shall . take capacity and energy from the Government at such power factor as will best serve Georgia Power's System from time to time; provided, that Georgia Power shall not impose a power
.f actor of less than .85 lagging on the Government's facilities which requires operation contrary to good operating practice or results in overload or impairment of such facilities or unreasonably interferes with the delivery of capacity and energy by the Government to Georgia Power and to its other customers.
14.2 The Government will endeavor to control the voltage of its generation and the ratio of its transformers at the Projects .so that-capacify and energy will be delivered by the Government to Georgia Power at the nominal voltage with such changes above or below nominal voltage as ay from time to time or at any time be requested by Georgia Power; provided
-- that such changes are within the limits of good operating practice, do not
- jeopardize the Government's facilities nor unreasonably interfere with the delivery of capacity and energy to the Government's other customers.
14.3 The Government shall, upon request, cause the available generating units at Allatoona, Buford, Clarks Hill, George, Hartwell, Russell, West Point and Carters to be operated as condensers or for l spinning reserve if such operation does not unreasonably interfere with the delivery of capacity and energy by the Government to any of its customers, is not contrary to good operating practice, is not detrimental to such l' generating f acilities in excess of ordinary wear and tear, and does not 32 { . x . _ x= - -
~_~ .-'
- - c _ _. - _ = - : =AL
9 overload. such-generating facilities. Such operations, subject to the preceding limitations, shall be in accordance with procedures and schedules developed and agreed upon from time to time by the operating representatives of the parties hereto. All energy required in such operations requested by Georgia Power shall be furnished by_ Georgia Power. Section 15. Energy Storage. 15.1 The Government will permit: Georgia Power to utilize, as herein provided, unused storage in the Projects' reservoirs. For this purpose, a storage account shall be maintained and the operating representatives of the Government shall keep the official record of such account. (a) Upon request, the Government will store declared energy for Georgia Power in any unused storage capacity available for such purpose in the reservoirs and will deliver energy which Georgia Power has in storage as scheduled by Georgia Power in accordance with the provisions of subsection 2.3. The Government will also deliver to Georgia Power from storage, upon request, energy which Georgia Power does not have in storage up to a debit balance of 7,485,000 kilowatt-hours or such larger quantity of kilowatt-hours as mutually agreed to by the parties from time to time. ' Such energy will be returned to the Projects as expeditiously as conditions on Georgia Power's System will permit. Additionally, if such deliveries at any time result in a reduction in the Projects' capacity, the Government's
- i. Obligation to make capacity available under this contract shall be reduced during such times in the same amount except that payment by Georgia Power to the Government for capacity shall not be reduced.
(b) When delivery of declared energy is postponed by agreement between the operating representatives of the parties affected, the number of kilowatt-hours so postponed shall be credited to Georgia Power's storage 33 L~. -i : . . - . _ _. .- , . _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _
p. 1 account. When delivery of energy to Georgia Power is made in advance of L declarations, the number of kilowatt-hours so delivered shall be charged against Georgia Power's storage account. Inadvertent deviations in delivery of declared energy shall be charged against or credited to Georgia Power's s torage account. When the above transactions result in a negative balance in Georgia Power's storage account, such energy shall be returned by Georgia Power in subsequent scheduling of energy declarations as expeditiously as possible until the storage debt is returned to zero. The exact amount of charge or credit for each day for each reservoir shall be agreed upon between the operating representatives of the parties affected. (c) It is recognized that changes in generation from predicted daily quantities at Georgia Power's and Alabama Power's upstream Projects could alter estimated quantities of available energy at George, Millers Ferry and Henry Projects, and it is the intent of the parties hereto and Alabama, Gulf and Mississippi Power Companies to make full use of the provisions of this Section 15 to minimize changes in the declaration due to the changes-in the availability of declared energy at these projects. Unless otherwise agreed by the operating representatives, such changes in generation at the Millers Ferry and Henry Projects which result in debits or credits to tne storage account shall be adjusted in subsequent declarations for these two projects. i 15.2 In the event it becomes necessary for the Government to spill water from a reservoir over the spillway or through the sluice gates as a means of keeping such reservoir under proper control, the kilowatt-hours which could have been produced f rom such water at the time of the spill, as reasonably determi ned by the Government, shall be deducted ) proportionately from any credits then existing in storage accounts of Georgia Power and other customers for whom the Government maintains a 34 1
. _ _ _ . _ I
to - 4 storage account.- -The necessity for spilling water shall be determined by. A the Government. , 15.3 Any kilowatt-hour debit or credit to Georgia Power in' the storage account shall be repaid or withdrawn prior to termination of this contract. 15.4 Deliveries of electric capacity and energy to Georgia Power or reduction in deliveries for the purpose of storing energy under the U terms of this Section 15 shall in no way interfere with the operation of the reservoirs for purposes other than electric energy production, as determined solely by the Government. C Section 16. Uncontrollable Forces Except for remedies and events provided for in Section 12 of this contract, either party prevented in whole or in part from fulfilling any y obligations hereunder by reason of uncontrollable forces, including but not limited to f ailure of f acilities, flood, earthquake, storm, lightning,
' fire, epidemic, war, riot, civil disturbance, labor disturbance, materials or equipment shortages, or restraint by court or public authority, but excluding drought, shall be relieved of its duty to perform to the extent made necessary by that uncontrollable force, which by exercise of reasonable diligence and foresight could not have been avoided. Either party rendered unable to fulfill any obligation by reason of an uncontrollable force shell remove such inability with all reasonable dispatch.
Section 17. Provisions Relative to Empl oyment. During the performance of this contract, Georgia Power agrees as follows: (a) Georgia Power will not discriminate against any employee or applicant for employment because of race, color, religion, sex or national 35 , w- :w _- 21: x :=. = . :=. . - - -. - -- - -: -=-7
E 3- } 1 o ri gi n. Georgia Power will take affirmative action to ensure thst-5 applicants are employed, and that employees are treated during employment, without regard to their race, color, religion, sex or national origin. Such action shall include, but not be limited to the following: empl oyme nt, upgrading, demotion, or transfer; recruitment or recruitment advertising; layof f or termination; rates of pay or other forms of-compensation; and selection for training, including apprenticeship. E Georgia Power agrees to post in conspicuous places, available to employees and applirants for employment, notices to be provided by the contracting officer setting forth the provisions of this nondiscrimination clause. 5 (b) Georgia Power will, in all solicitations or advertisements for employees placed by or on behalf of Georgia Power, state that all qualified applicants will receive consideration for employment without
, regard to race, color, religion, sex, or national origin.
(c) Georgia Power will send to each labor union or representative of workers with which they have a collective bargaining agreement or other contract or understanding, a notice, to be provided by- the agency contracting officer, advising the labor union or workers' representative of Georgia Power's commitments under Section 202 of Executive Order No.11246 of September -24,1965, and shall post copies of the notice in conspicuous places available to employees and applicants for employment. (d) Georgia Power will comply with all provisions of Executive Order No.11246 of September 24, 1965, and of the' rules, regulations, and relevant orders of the Secretary of Labor. (e) Georgia Power will furnish all i nformation and reports required by Executive Order No.11246 of September 24, 1965, and by the rules, regulations, and orders of the Secretary of Labor, or pursuant thereto, and will pemit accessgto his books, records, and accounts by the 36 4 ,. . _ _ .A__ ____.i __ . __m_l.__.x__z . ua
l contracting agency and'the Secretary of Labor for' purposes of investigation to ascertain compliance with such rules, regulations, and orders.
' (f) . . In_ the event of Georgia Power's noncompliance..with the
, nondiscr.imination-Clauses of this contract or with any such rules, t . regulations,- or orders,'this contract may be cancelled terminated or
- suspended in whole or in part and the Compary may be declared ineligible for further Government contracts in accordance with procedures authorized A .in Executive Order No. '11246 of September 24, 1965, and such other sanctions may be imposed and remedies invoked as provided in Executive' Order No.~ 11246 of September 24, 1965, or by rule, regulation, or order of
- h. the Secretary of Labor, or as otherwise provided by law.
' (g) Georgia Power will include the provisions of paragraphs (a)
- through (g) in every subcontract or purchase order unless excepted by .
rules, regulations, or orders of the Secretary of Labor. issued pursuant to Section 204 of Executive Order No.11246 of September 24, 1965, so that such provisions will be binding upon each subcontractor or vendor. Georgia Power will take such action with respect to any subcontract or purchase order as the contracting agency may' direct as a means of enforcing such provisions including sanctions for noncompliance; provided, however, that in' the event Georgia Power becomes involved in, or is threatened with, litigation with a subcontractor or vendor as a result of such direction by the contracting agency, Georgia Power may request the United States to g enter into such litigation to protect the interests of the United States. Section 18. Notice s. , l Except as otherwise specified herein, any notice, demand, request, or approval required or authorized by this contract shall be deemed . properly given on behalf of Georgia Power, if mailed, postage prepaid, to the Administrator at the address shown on the signature page hereof, and on 37 L_*'.h l ' u_I _ _, .l _e_ _ _ ...m. _ ._h S' Y .
"' ' 'I b - _. . A b.__ ._ml._.m_m __.__a___ -
_mh __ _mL _ _ . _ _ _
, l behalf of the Government, if mailed, postage prepaid, to the Vice
? President-Bulk Power Markets.of Georgip Power at the address shown on the signature page hereof. The designation of the person to represent either party for such purposes or the address of such person may be changed at any I time by similar notice. Section 19. Officials Not To Benefit. No Member of or Delegate to Congress or Resident Commissioner k 'shall be admitted to any share or part of tnis contract or to any benefit l- that may arise therefrom, but this restriction shall not be construed to extend to this contract if made with a corporation or company for its L general benefit. l Section 20. Waivers. Any waiver at any time by either party hereto of its right with respect to a def ault or any other matter arising in connection with this contract shall not be deemed to be a waiver with respect to any subsequent def ault or matter. Section 21. Transfer of Interest in Contract. l No voluntary transfer of this contract or of the rights of Georgia l Power hereunder shall be made without the written approval of the Secretary
, of Energy; provided, that any successor to or assignee of the rights of Georgia Power, whether by voluntary transfer, judicial sale, foreclosure !
sale, or otherwise, shall be subject to all the provisions and conditions of this contract to the same extent as though such successor or assignee ! l- were the original contractor hereunder, and provided further, that the execution of a mortgage or trust deed, or judicial or foreclosure sale made thereunder, shall not be deemed voluntary transfers within the meaning of l thi s section. 1 I 38 L< m u. n - -
li L . Section 22. Approval of Contract. Certain provisions of this contract are subject to approval by the Federal Energy Regulatory Commission. If the Federal Energy Regulatory i l Commission, or any other Governmental agency or court having jurisdiction to do so, modifies this contract in any manner, this contract may immediately . be cancelled .by either party. If this contract is so I' cancelled, the parties will undertake to renegotiate this contract in order g to achieve such modifications as are necessary to restore the overall l L benefits to each party to the levels provided for in this contract as originally executed. Provided, however, that nothing in this section shall %: require either party to agree to terms different from those in this contract. Section 23. Effective Date and Term of, Contract. Subject to the approval by the Federal Energy Regulatory l Commission of the initial filing of this contract, the effective date of this contract shall be February 1,1985, and the contract shall terminate ! a t mi dni gh t, May 31, 1994. If the Federal Energy Regulatory Commission or any court shall disapprove this contract or approve it subject to modification upon the initial filing thereof, the parties shall y retroactively adjust their performance under this contract to conform with the provisions of the contract between the Government and Georgia Power dated June 19, 1970, as amended, (designated as Contract No. 89-00-1501-378) but shall have no further obligation to continue to perform under this contract unless and until a mutually satisf actory agreement is reached pursuant to Section 22'. Section 24. Precedential Nature of Contract Provisions. By executing this contract, the parties hereto shall not be deemed to have agreed on any method of capacity rating, energy rating ratemaking 39
, .- . == ..: . e n . . . :. . . . = _ = . . x a_~ __ = _W=
) 1 1 principle or method of allocation for the purposes of future contractual [ negotiations af ter the expiration of this contract or with respect to future regulatory or court proceedings regarding future contractual relations between them, nor shall any of the parties be prejudiced with N respect to any position that any of them may desire to take in any such future contract negotiations or proceedings involving such futere ! contractual relationships. S
. Section 25. Termination of Existing Contract.
Subject to the provisions of Section 23 hereof, the existing contract between the Government and Georgia Power dated June 19, 1970, as O amended, (designated as Contract No. 89-00-1501-378) will terminate upon the effective date of this contract; provided that all liabilities accrued as of the date of termination shall be preserved. Credits anc debits in the storage account existing as of the date of termination of the existing contrtet shall be preserved and carried forward under this contrc:t. Energy contained in the energy account under the existing contract shall be distributed to the preference customers in accordance with the preference customer allocations under the existing contract on an equal daily basis, unless otherwise agreed, during the period from the effective date of this contract through May 31, 1985. Section 26. Operating Committee. 26.1 The Admi nistrator and Georgia Power shall each appoint one r,perat 'ng representative to act for them in matters pertaining to detailed operatiny arrangements for delivery of capacity and energy hereunder, and the. Administrator and Georgia Power may each appoint an alternate to act for it in the absence of its operating representative. The two operating representatives, or their alternates, so appointed shall comprise and be referred to as the Government-Georgia Power Company Operating Committee. 40
=~v- . ::. -
*- a- = _-_ i_ _ _ . _ _ _ . _____a
F o e V _.,_ . m It' is understood that Georgia Power may appoint a representative of 'its agent, Southern Company Services, Inc. , to act as its operating representative ~ on the Operating Committee. Evidence of the appointments shall be given' by written notice to each of the parties, and such ) appointments may be changed at any time by similar notice. 26.2 The Government-Georgia Power Company Operating Committee, in addition to any matters specifically referred to elsewhere in this v contract, shall be ' responsible for the following: (a) Communications with respect to energy declarations and scheduling under subsections 3 2.2 and 2.3. (b). Establishment of arrangements for metering, tel emeteri ng~, telecommuni cati ons , data acquisition, etc., associated with the delivery and receipt of power and energy hereunder. (c) Establishment of control and operating procedures to the extent not provided for by this contract. (d) Establishment of methods and procedures for accounting and billing hereunder to the extent not provided by this contract. _ (e) Inf o rmation exchange as to daily water releases, daily reservoir elevations, I rainfall, load patterns, and other operating conditions pertinent to this contract. 41 m e 1 ,. . a rrma - e: asz -
, -AL<xmM- J
[. ,' .. . ,. V . i l IN WITNESS WHEREOF, the parties hereto have caused this contract b' to be executed the day and year first above written. UNITED STATES OF AMERICA' Department of Energy
, * /
L - . l gy ./; l ,
~~~
Administrator ~
- a Southeastern P~ower Administration Elberton, Georgia 30635 GEORGIA POWER COMPANY <
By p Vice President--Bulk Power Martets Georgia Power Company Post Office Box 4545 , Atlanta, Georgia 30302 (5EAL) ATTEST:
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, Secretary gg o.
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l s O F 42 ; 3 %:- m;; . :.2 L: L .. %: ~ ^ 's a:; '~", ~
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APPENDIX A REDUCTIONS TO WEEKLY MINIMUN DECLARATIONS COMMERCIAL AVAILABILITY OF RICHARO B. RUSSELL UNITS i b- REDUCTIONS IN MEGAWATT-HOLFRS ( NO UNIT 5 AVAILABLE AT RUSTETL Month Total' Ga. Pwr. Ala. Pwr. Miss. Pwr. Gulf Pwr. AEC Month p Jan. 3,400 2,376 627 152 20 225 Jan. Feb. 3,000 2,100 554 134 17 195 Feb. Mar. 2,300 1,609 425 103 13 150 Mar. Apr. 2,300 1,609 425 103 13 150 Apr. May 2,500 1,748 461 112 14 165 May June 3,500 2,448 646 156 20 230 June s ' July 5,000 3,495 923 223 29 330 July Aug, 5,500 3,847 1,015 246 32 360 Aug. Sep. 5,000- 3,495 923 223 29 330 Sep. Oct. 4,000 2,799 739 179 23 260 Oct. Nov. 3,500 2,448 646 156 20 230 Nov. Oec. 3,700 2,586 683 165 21 245 Dec. RE00CTIONS IN MEGAWATT HOURS ONE UNIT AVAILABLE AT RUSSELL Month Total Ga. Pwr. Ala. Pwr. Miss. Pwr. Gulf Pwr. AEC Month Jan. 0 0 0 0 0 0 Jan. Feb. 0 0 0 0 0 0 Feb. Mar. 0 0 0 0 0 "O Mar. Apr. 0 0 0 0 0 0 Apr. May 0 0 0 0 0 0 May June 0 0 0 0 0 0 June July 500 348 92 22 3 35 July Aug. 1,000 700 184 45 6 - 65 Aug. Sep. 500 352 93 22 3 30 Sep. Oct. 0 0 0 0 0 0 Oct. - Nov. 0 0 0 0 0 0 Nov. Oec. 0 0 0 0 0 0 Dec. i i 6 1
.i._ j. lx > r .k .n. . 'A ' ~. * ,e
7:
- v. ,1 I APPENDIX 8 i
PAGE 1 0F 7 l r ~ J
- . GEORGIA AREA CAPACITY AND ENERGY ALLOCATIONS
+
\
EXISTING FEB 85 JUNE 8S JUNE 86 JUNE 87 JUNE 88 JUNE 91 ENERGY J CAPACITY T0 TO . TO- TO TO TO 8ASED ON
. ALLDC JUNE 85 JUNE 86 JUNE 87 JUNE 88 JUNE 91 JUNE 94 1994 KW ALLOC
'PUBLIC 800!ES' KW KW~ KW KW: KW KW- KW %
ACWORTH 1185. 1249. 1498. 1611. 1708. 1769. 2075. 0.2139175258- > c: ADELL 3684. 3839. 4508. . 4860. 5162. 5353. 6304 0.6498969072 30727. 32584 39480. 42417. 44935. 46530. 54460. 5.6144329897 l{ ALBANY-
! BARNESVILLE 1347. .1423. 1712. 1841. 1951, 2021. 2369. 0.2442268041 " BLAKELY: 2837. 2973. 3528. 3799. 4031. 4178. 4910. 0.5061855670 BRINSON 78. 83. 102. 109. 115. . 119. 139. 0.0143298969 BUFORD 1220. 1283. 1533. 1650. 1750. 1813, 2128.. 0.2193814433 4 CAIRO 3106. 3312. . 4051. 4348. 4603. 4764. 5566. 0.5738144330 CALHOUN. 3639. 3938. 4938. 5286. 5584. 5773. 6712. 0.6919587629
, CAMILLA . 3239. 3376. 3966. 4276. 4541. 4709. 5545. 0.5716494845 CARTERSVILLE 8826.. 9304 11156. 12000. 12723. 13181. 15459. 1.5937113402 COLLEGE PARK 7576. 8131. 19058. 10782. 11403. 11796. 13751. 1.4176288660'
- COMMERCf. 2420. 2508. 2916. 3147. 3345. 3471. 4096. 0.4222680412 4706. 5002. 6084. 6534. 6920. 7164. 8379. 0.8638144330 p^:COVINGTON-0 ALTON 22373. 23899. 29325. 31463. 33296. 34457. 40231. 4.1475257732-l00ERUN 326. 343. 409. 440, 467. 484. 568. _0.0585567010.
DOUGLAS . 5284. 5555. 6628. .7133. 7566. 7840. 9204. 0.9488659794 EAST FOINT '17517. 18369.. 21821. 23495. 24930. 25839. 30360s 3.1298969072 ELBERTON 6210. 6438. 7491. 8085. 8594. 8916. 10519. 1.0844329897 ELLAVILLE' 472. 501. 608. 653. 692. 716. 838. 0.0863917526 FAIRDURN 869. 935. 1162. 1245. 1316. 1361. 1585. 0.1634020619 FITZiERALD 4982. 5258. 6319. 6795. 7203. 7462. 8748. 0.9018556701 FOREYTH - 1922.- 2023.' 2420. 2604. 2761. 2861. 3357. 0.3460824742' FORT VALLEY 4818. 5088. 6121. 6581. 6976. 7226. 8469. 0.8730927835 GRATTVILLE -255. 264 307. 331. 352. 365. 431. 0.0444329897 GRIFFIN 9297. 9816. 11802. 12691. 13453. 13935. 16334. 1.6839175258 1HAPPTON 401. 427. 522. 560. 593. 614. 717. 0.0739175258
.HOGANSVILLE 809. 846. 999. 1076. 1142. 1184. 1393. 0.1436082474 EJA KSON 1054. 1114. 1343. 1444 1530. iB85. 1857. 0.1914432990 LAFAYETTE 3428. 3604. 4301. 4629. 4910. 5088. 5973. 0.6157731059
'LAGRANGE 8509. 9067. 11078. 11891. 12588. 13030. 15226. 1.5696907216 LhWRENCEVILLE 2228. 2429. 3084. 3297. 3480. 3596. 4171. 0.4300000000 KANSFIELD . 211. 217. 249. 269. 286. 297. 351. 0.0261855670 MARIETTA 18028. 19375. 24018. 25741. 27218, 28154. 32807. 3.3821649485 MONROE.. 3795. 3974. 4709. 5072. 5383. 5580. 6559. 0.6761855670 MOWTICELLO 990. 10?8. 1200. 1295. 1376. 1427. 1683. 0.1735051546-MOULTRIE 7990. 8414. 10071. 10835. 11490. 11905. 13967. 1.4398969072
,NEWNAN 3544. 3737. 4483. 4822. 5112, 5296. 6211 0.6403092784
!.NORCROS$ E?8. 895. 1120. 1199. 1267. 1310. 1524 0.1571134021 PALMETTO 471. 498. 600. 645. 684. 708. 830. 0.0855670103. JC*JITMAN 2393. 2484 2897. 3126, 3322. 3446. 4064 0.4189690722
'SANDERSVILLE 2653, 2769. 3262. 3516. 3733. 3871. 4556. 0.4696907216 SYLVANIA 2643. 2838. 3513. 3766. 3983. 4120, 4802. 0.4950515464 SYLVESTER 1963. 2093. 25E9. 2747, 2908. 3010. 3517. 0.3625773196 1THOMASTON 3779. 4043. 49# 4 5335. 5645. 58/1. 6816. 0.7026804124 THOMASVILLE 12805. 13527. 16281. 17505. 18554 1921.1 ?2524 2.3220618557
. WASHINGTON 2637, 2770. 3300. 3552. 3768. 3905. 4586. 0.4727835052 WEST POINT 2581. 2663. 3070. 3317. 3528. 3662. 4328. 0.4461855670 WHIGHAM 145. 159. 204 218. 230. 238. 275. 0.0283505155 i
-CRISP COUNTY 9304. 9805. 11752. 12C41. 13403. 13886. 16287 1.6790721649 j 1
TOTAL'PUBLIC BODIES 242104. 256270. 309532. 332674. 352510. 365075. 427561. wwx w .- r e _- 1 e ~=x , . 2 :_ - .xza s-l
P g.Q 7 _ 3 APPENDIX 8
~
.PAGE~2 0F 2 GEORGIA AREA CAPACITY AND ENERGY ALLOCATIONS-( . EXISTING FE8l85 JUNE 85 JUNE 86 JUNE 87 JUNE 88 JUNE 91 % ENERGY
, TO -
CAPACITY .TO TO TO TO TO .' BASED ON *' w _ . ALLOC ' JUNE 85 JUNE 86 JUNE.87. JUNE 88 JUNE 91 JUNE 94 1994 KW ALLOC COOPERATIVES' 'KW' KW KW -KW' KW KW KW . C b'ALTAMAHA EMC' L5268. 5674.- 7060. 7564. 7996. 8269. . 9629.. 0.9926804124 $ AMICALOLA EMC- 5690. 6073. 7440. 7984.. '8450. 8745. 10214 1.0529896907c H CAN00CHEE EMC -4426. 4800.. 6040. 6463. L6826.' 7056. 8198. 0.8451546392~
. CARROLL EMCL . =8336.. 8926. 10996. 11793. 12476. 12909. .15060. 1.5525773196 CENTRAL GA EMC- 6264. '6808. 8598. .9197.. 9710. 10035. 11652. 1.2012371134 COASTAL.EMCJ '
1430. 1572. 2022. ~2159. 2276. 2350. 2719.s 0.2803092784-
,:C088 EMC 17347. 19255, 25143..~26801. 28222. 29122. 33599.- 3.4638144330' N COLOUITT EMC 19162. 20389. 24850. 26681. 28251. 29245.. 34191. 3.5248453608-i COWETA-FAYETTE EMC 6036. 6644. -8564. 9141. 9636.. -9949. 11507. 11.1862886598 DOUGLAS EMC . 14442. 15816. 20221. 21601. 22784. 23533. 27260. L2.8103092784
'"EXCELSIORLEMC- 4323. 4643. 5750.. 6163. 6517. 6741. :7857. 0.8100000000 DFLINT.EMC 27709.; 29518.-- 36050. 38698. 40969. 42407. 49558. 5.1090721649' 3GRADY.EMC 5206. 5540. 6753. 7251. 7678. 7948. 9292.- 0.9579381443 pHA8ERSHAMEMC- 5038. 5374.. :6578. 7060. 7473. 7734. 9034. 0.9313402062' ^ HART EMC~. 9502. 10038. 12083. 12991. 13770. 14263. 16715. '1.723L958763' ' : IRWIN: EMC ' 4 188. 4430.' 5346. 5746. 6089. 6306. 7387. - 0.7615463918
' JACKSON EMC -23033. -'24897. 31163c 33364. 35251.. 36446.~ 42391. 4.3702061856?
l JEFFERSON EMC i6493. 7112.. 9095. 9716. 10248. 10585. T12261. :l'.2640206186: LAMAR EMC- 3231. 3501. 440G. 4709. 4974 5142. 5976. 0.6160824742 e LITTLE OCMULGEE EMC 3998.. -4209.- 5035. 5417. 5745.- 5952. .6984. '0.7200000000 KiMIDDLEiGA EMC 3015. 3205. 3901. 4189. . '4436.- 4592. 5370. 0.5536082474-MITCHELL EMC 8973. 9554. 11657. 12515. 13250. 13716. 16032. l'.6527835052
- 0CMULGEE EMC -- 4143. l4388. 5306. .5702.; 6041. 6256. 7325. 0.7551546392 '
OCONEE EMC- 3860.- 4156. 5168. 5537. 5853. 6053. 7049. 0.7267010309 H OKEFENOKE EMC 4654. 4979. 6126. 6571. 6952. 7194. 8395. ~0.8654639175-L.PATULA EMC 1609. 1715. 2097.- 2251. 2383. 2466. 2881. 'O.2970103093 PLANTERS EMC 5115. 5444. 6637. 7126. 7545. 7810.- 9130. 'O.9412371134-
,RAYLE EMC 5195. 5516. 6699. 7196. 7522. 7892. 9233. 0.9518556701 .SATILLA EMC' 15145. 16117.- 19649, 21097. 223384 23124 27033. :2.7869072165' i SAWNEE EMC . 9244. .9991. 12502. 13386. 14143. 14623. 17009.- '1.7535051546 -SLASH PINE EMC 2385. 2539. 3096. 3324 3519. 3643. 4259. 'O.4390721649' .SNAPP3NG SH0ALS EMC' 8995. 9933. 12867. 13727. l'464. 14931. 17253. 1.7786597938-F SUMTER EMC- 5465. 5899. 7365. 7887. 8335. -8619. 10029, 1.0339175258 bTHREE NOTCH:EMC. 5984 6402. 7875. 8447. 8937. 9248.. 10792. 1.1125773196 LTRI-COUNTY EMC 2915, 3201. 4110. 4389. 4628. 4779. 5531. 0.5702061856~
TROUP:EMC. 5537. 6056. 7728. 8257. 8711. 8998. 10427, 1.0749484536 UPSON EMC- 2249. 2406. , 2959. 3174. 3358. 3475. 4055. .0.4180412371 WALTON EMC 13513. 15113. 19962. 21254. 22361. 23062. 26550, 2.7371134021 QWASAINGTON: EMC 6928.. 7470. 9200. 9867. 10439. 10801. 12602. 1.2991752574 TOTAL' COOPS -296096. 319303. 398091. 426395. 450656. 466019. 542439.
.TOTALLPREF. CUST. 538200. 575573. 707623. 759069. 803166. 831094. 970000. 100.0000000000 l
1 kmw::ne=ur_a a = t x :2
- L: m :1er: m - m x:~
~? ~ ma:u . . 1
APPENDIX C TRANSMISSION SERVICE ALLOCATION METHODOLOGY AND SERIODIC RATE COMPUTATION PROCEDURE MANUAL (" MANUAL")
-B Section 0.0 De'scription and Purpose of This Manual: This Manual contains a formulary description of the methodology and procedure used to calculate the
- charg(s for transmission service provided pursuant to subsection 8.2 of the Contract. The Manual is divided into eight (8) basic articles as follows:
Article I- - Definition of Contract Year ? Article II - Service Levels, Load Flows, and Associated Losses Article III - Derivation of Capacity Charge for Transmission Service at Level B-2 Article IV - Derivatio.n of Capacity Charge for Transmission Service at Level C
' Article V - Derivation of Capacity Charge for Transmission Service at Level D Article VI - Derivation of Capacity Charge for Transmission Service at Level E Article VII
- Derivation of Capacity Charge for Transmission Service at Level F Article VIII - Determination of Transmission Service Requirements and Charges j
w_w.-__ . _ x- _x __ _ 2 __ . _- : : w: -_x : a : L u x ,. . ~u -
M-2. Section 0.1 Rate Computation Procedure: _ The Government and the Companies recognize that the cost of providing the transmission services contemplated by subsection 8.2 of the Contract will change during the term of such Contract. Thus, in . order. for the~ Companies to be compensated fairly and adequately, it will be necessary to revise or update, on a periodic basis, the cost, expense, investment, and load figures utilized in the derivation of the transmission charges provided for in the Contract. In order to facilitate revisions or n. updates of the transmission charges under the Contract, the Companies and the Government have adopted this Manual to be utilized in the periodic calculation of charges provided for in the Contract. The Manual shall serve as a fomulary D rate allowing periodic revisions of the charges to reflect changes in costs of providing the transmission services contemplated by the Contract. The cnarges and the amount of capacity to be transmi+ted by each of the Companies 4:alculated in accordance with the Manual will be shown on the Informational Schedule described in Section 0.2 herein. L Section 0.2 Informational Schedule: An Infomation Schedule showing the charges for the transmission services contemplated by the Contract during the portion of the initial calendar year in which the transmission charges become 0 effective pursuant to Subsection 8.2 (June 1,1989) shall be submitted by the Companies to the Government on or before April 1,1989. The Informational Schedule will be revised for each calendar year during the continuation of the Contract. Revisions of charges contained in toe Informational Schedule shall follow the methodology and procedure set forth in the Manual. A revised Informational Schedule shall be submitted by the Companies to ;he Government on or before November 1 of each year for application on January 1 of the following year. This time period will allow the Government and the Companies to verify G n - ,=_ w w _w = _ - 2: = _ =.- * . .
P., 1 , (, .h . M-3. l that the' charges contained in the revised Informational Schedule have been f computed in accordance with the methodology and procedure set forth in the 7 - Manual. In the event the Government objects to the resulting charges produced l by such revision, the Government shall have the right, within 60 days from the
~
receipt of such revised charges, to initiate proceedings through appropriate regulatory filings with the FERC to challenge the appropriateness of the inputs
. to the formulary rates (but not the components of the fomulary rate) utilized to derive the charges under such formulary rate. Any charges, calculated pursuant to this Manual which are challenged by the Government because of disagreements with the inputs to the formulary rate, shall become effective on D the proposed effective date subject to refund in the event the FERC determines such inputs to be unreasonable- or unjustified. To the extent the Federal Energy Regulatory Comission (FERC) cetemines, such charges to be unreasonable or unjustified because of changes in the inputs to the formulary rate, refunds will be made with interest determined in accordance with the regulations of the FERC.
l Since the charges contained in the revised Informational Schedule will be computed in accordance with the fomulary rate method and procedures described in the Manual, it is the intent of the Companies and the Government that such revisions will not be changes in rates which would require a filing and suspension under the Federal Power Act and the applicable Rules and Regulations of the FERC. A revised Informational Schedule will be filed with the FERC, or
- itr successor in interest, for informational purposes to show the application of i the fomulary rate method and procedere and the resulting charges provided for
(-
- l. in tnis Marual.
Section 0.3 Unilateral Revision of the flanual: In addition to the right to change the charges as described above, the Companies shall have the right to 1
,1 M _ _ f_ c e-m"L . : __Z 1 ._
_ M_ m _ _ _ _ __m_ _m__ ..m._ ___.____ _ _ _ m_ _d
- r. ..
M-4. I 1 unilaterally make application to the FERC to amend the formulary transmission l rate established in this Manual, including the right to make changes in provision for percentage return on equity capital, changes in provisions establishing losses, cost components included in the formulae for transmission l rates, and any other provisions of the formulary rate contained in the Manual. In accordance with applicable provisions of the Federal Power Act, the Government shall have the right to make a complaint to the FERC to amend the h formulary transmission rate established by this Manual including the right to make complaint regarding these provisions for percentage return on equity capital, losses, cost components included in the fomulae, and any other provisions of the formulary rate except the methodology and procedure for dete"ining the movement of capacity fror the Projects through the systems of the Companies to the preference customers as set forth in Section 8.4 of this Manual. The filing party shall give the other party written notice and full explanation 1 of each such change or revision as far in advance as reasonably possible, but at least sixty (60) days in advance, of the date the filing party seeks to have its 4 proposal (s) made effective by the FERC. Government and the Companies shall, within the time allowed by the notification, seek to settle any objections to the filing party's proposal (s). If Government and the Companies reach a complete settlement in advance of the date the filing party seeks to have its proposal (s) made effective by the FERC, the other party agrees to support actively before the FERC the proposal (s) (as mo'dified by the party's settlement) becoming effective without any suspension. If a complete settlement is not reached by the parties, the other party shall be free to raise any objections it ' may have to the filing party's proposal (s) before the FERC in a filing which .
. I
_ : 1.- - _ . - _- ' ~ - .~ . ,
[ , M-5. complies with applicable FERC rules,' regulations, and notices. The Companies i and the Government agree that, in any such filing of objections pertaining to changes in the rate formulae, the Government shall have the right to seek up to the maximum period of suspension afforded by the Federal Power Act, as amended. and regulations issued thereunder.
- l. Section 0.4 Uniform System of Accounts: The Accounts set forth in the Manual 5:
are currently prescribed in the FERC's " Uniform System of Accounts Prescribed for Public Utilities-and Licensees (Class A and Class B)" in effect as of the date of this Agreement. If these Accounts are amended, then the Manual shall be b i' construed to reflect the amended- Accounts prescribed by the FERC or its successor agency. 1 e l l 1 xxx=nw: .- -
M-6. . ! ARTICLE I Y' DEFINITION OF CONTRACT YEAR
'This article of the Manual establishes the definition of Contract Year as k utilized throughout the Manual.
1. Section 1.0 ' Contract Year: For purposes of determining charges for transmission service or allocation of transmission charges under the Contract, the Contract Year shall be determined to be the_ calendar-year. The Companies
- will revise-the charges provided for in the Contract on a yearly basis and will 3 submit such charges to'the Government. The ContractL Year. will be divided into
~
' tw'o distinct. periods, January through May, and June through December. This division.of the Contract Year into two periods is necessary in order to l-recognize that the Comptnies consider an operating year to be June 1 through May-31 of the following year.
F-t v i
- t. I a. KIN [ ' -' _ A . . _ - m. [ _ .'a . a.
M P .
, n.
M-7. - e ARTICLE 11 I' SERVICE LEVELS, LOAD FLOWS, AND ASSOCIATED LOSSES y- This article of the Manual establishes the definition of service levels and the determination of the capacity loss percentages on each Company's system for each of.the service levels. Section 2.0 The service levels for each Company's system are defined as follows: SERVICE LEVEL DEFINITION B-2 . . . . . . . All transmission lines with a voltage of 115 KV and above. Also included are all transformation, metering, and switching sub-stations rated 115 KV and above, excluding generator step-up substations. C . .... All substations having a transmission voltage of 115 KV and above on the high side and a sub-transmission voltage of 39 KV through-69 KV inclusive on the low side. D . . . ... All sub-transmission lines, metering, and switching substations of voltages 39 KV through 69 KY inclusive. E . .... All substations having a transmission or sub-transmission voltage on the high side and a primary distribution voltage of less than 39 KV on the low side. F . .... All primary distribution lines, metering, and switching " substations. Also included are substations having primary distribution voltages on both the high side and the low side of the transformation. Section 2.1 Computations of capacity losses on each Company's system at service levels C, D,_ E, and F, shown on the Informational Schedule, are expressed as a percentage of territorial sales. Losses at level B-2 are as shown in Section
'3.2.19. These percentages will be revised in subsequent calendar years to reflect the most recent loss data.
Y 1 ? - 2 f ..f.. *-N. _ - 7 % f_ "_.i . 4 ._2 m A. I*-'"m __b .m___ _ _ _ _ _.m_.i...a---__..__mLl.a. _._.m;
M-8. . F Section 2.2~ Service Levels Load Flows and Associated Losses: The following load flow diagram shows the service levelt and the formula components of demand and sales as discussed in Articles III through VII of the manual.
~ SERVICE I LEVEL DESCRIPTION- DIAGRAM Territorial Input
- l....D B-2 Highside at B-2 Y
. Losses at B-2 l Losses l 0
Lowside at B-2 ......D B Sales at B-2 ..... 5 8-2 V p 4 Forward to C i.... DST " Fomard to E DB SB-2.-DST i.' C Highside at C V Losses at C. l Losses _l Lowside at C. - o .Z. DC Sales at C o....S C V & Forward to D o
....DCD Forward to E -
o
- D Highside at D y ....Dc -Sc -DCD Losses at D l Losses l l
Lowside at D o....DD l Sales at D o....S D l - l Fomard from B-2, C, D . V V V h 1 l" E Highside at E V I Losses at E ILossesl l Lowside at E o....D E Sales at E "....S E l F Highside at F V l Losses at F . lLossesI h Lowside at F A....DF Sales at F o
....SF V
9 p u-+ w . =- -- -- -
._ x -
l.. N t; i- . M-9. L. ARTICLE III ?' DERIVATION OF CAPACITY CHARGE FOR p-- - TRAERI5510N SERVICE AT LEVEL B-2 b Section 3.1 Level B-2 Capacity Charge: Level B-2 facilities are defined as all transmission lines with a voltage of 115 KV and above, including all transformation, metering, and switching substations rated 115 KV and above. The computation of the capacity charge for service from level B-2 facilities is based on the investment, expenses, and load related to facilities rated 115 KV 1- and above: -This capacity charge excludes the investment and expenses associated with the generator step-up substations. The computation of the capacity charge for service from Level B-2 facilities for each period of the Contract Year is
, described in the following sections. The charge for each period of the Contract Year will be shown on the Informational Schedule and will be revised in accordance with this Manual in subsequent calendar years.
Section 3.2 Derivation of Monthly Level B-2 Capacity Charges: The derivation of the monthly Level B-2 capacity charge of each of the Companies is based on g each company's respective investments, expenses, and load related to transmission lines and associated substation facilities rated 115 KV and above excluding generator step-up substations during the Contract Year and the cost of capital and incremental income taxes in each period of the Contract Year. This derivation excludes the investment, expenses, and associated load in , transmission owned by Oglethorpe P6wer Corporation (OPC), Municipal Electric Authority of Georgia (MEAG), and the City of Dalton (Dalton) if applicable. The
. _ - - - . e s-- -x- - -- -- ----._ - - - - - - - . .s. J --. . - - - ---J----- - .----e - A- - - - -- ---- --E
t M-10.- 1 investment and expense associated with " Southern Electric Generating Company" g (SEGCO) transmission line facilities are assigned to Georgia Power. The derivation of. the monthly Level B-2 capacity charge of each of the Companies for each period of the Contract Year is expressed in the following fonnulae: ' R y
= I B-2 x (CM g + IT )/100%
7 + E. B-2 x 100' D x 12 100 - %L R 2p
- I B-2 x (CM2 + IT 2)/100t + EB-2 x 100 D x 12 100 - C Where: R 3
= Monthly Level B-2 capacity charge for January through -
p B-2 May ($/KW-month). R = Monthly Level B-2 capacity charge for June through 2 B-2 December ($/KW-month). L CMy- = The weighted average cost of capital (%) associated with the January through May period of' the' Contract Year. CM 2
= The weighted average cost of capital (%) associated with 'the June through December' period of the. Contract Year.
IT = The income tax requirement associated with the preferred stock 1 and cocinon equity weighted cost of capital (%) associated with the January through May period of the Contract Year. IT = The incame tax requirement associated with the preferred stock; 2 and conynon equity weighted cost of capital. (%) associated with S the June through December period of the Contract Year. I B-2 = The 12-month average investment (5) in transmission lines and j associated substation facilities (excludir,g generator step-up substations) rated 115 KV and above (Level B-2). i l l lio . _ ,;_- -_n _
,,m o - ,-: _ _ _ _ _: _ : -
. - _____; __d
x; . yy.c .. .
; ' Mill.
i E B-2
= The 12-month annual' expenses ($) for transmission lines and e
associated substation facilities (excluding generator step-up
-substations) rated 115 KV and above-(Level.B-2).
D =- The 5-day average estimated load at the generator (KW). y L = Average transmission loss percentage of the Companies as. determined in Section 3.2.19 of' this Article. l. y
'The source of the load, investment, and expense data incorporated in the above formulae 1for each of the Companies (including FERC Account ch.nbers and descrip-tion of allocation procedure and calculation of the cost of capital)-is as set i
forth-in the following sections. The generation owned and' retained by OPC, MEAG, and Dalton and th'etr partial requirements load at the generator bus are excluded for the Georgia- Power load calculation. Also the investment and expenses associated with OPC, MEAG, and
. Dalton ownership'in transmission facilities are excluded. .For Mississippi L
Power, the generation of the Standard Oil Station is ' excluded. Section 3.2.1 Five-Day Average Load is the estimated annual peak one-hour net H territorial load (KW) at the generator adjusted;to a 5-day average load based on the preceding' year's actual loads. Each Company's one-hour peak net' territorial load (KW) is the sum of the following: (1) generation (+).(2) associated 6, companies' pool receipts (+), (3) associated companies pool deliveries (-) .(4) l E , non-associated companies receipts (+), (5) non-associated companies deliveries-(-).'and (6) any known loads associated with the transmission services that'are 1' l l mAmm_ :_ou - m,m u 3. , -- n -
, _- _ . ._=_u
'6 M-12.
lL responsible for revenues which were not credited to operating expenses (+)-and p I is the value "D" in the formulae in Section 3.2. Section 3.2.2 Gross Investment for i.svel B-2 is the summation of FERC Accounts 350. 354, 355, 356, 357, 358, and 359 associated with 115 KV and higher voltqge
' lines plus Accounts 350, 352, and 353 associated with transformation, metering,
~
and switching between-115 KV and the. higher voltages. (Generator step-up D~' substations are excluded.) Section 3.2.3 Accumulated Depreciation is that depreciation associated with the Lgross investment defined above and is allocated to Account based on investment. and depreciation rates:by Account. The allocation to level.is based on gross investment. Section 3.2.4 Net Investment is the difference between Section 3.2.2.(Gross i Investment) and Section 3.2.3 (Accumulated Depreciation). Section 3.2.5 General Plant-(Net) includes the investment in Accounts 389' through 399 excluding amounts directly assigned to production. The allocation ) a of net. general plant to function (excluding the direct assignments) is done on the basis of salaries and wages as developed in Section 3.2.18. l ic-After net general. plant has been allocated to function, it is allocated to Level B-2 based on the ratio of the total net investment in the 115 KV and above facilities (Section 3.2.4) to the total net plant investment. 'i
~
,.~..L..... -
- _-a . . . -- -.--._ -- - - _ _ _ _- .___.:.____2__.xK
m. l :. .. : q.. M-13.. Section 3.2.6: Working' Capital is-the summation of cash working capital, prepay-
.ments. and material and supplies. Cash working capital is one-eighth of the
' allocated operation and maintenance expense plus one-eighth of the allocated administrative and general expense associated with the facilities considered F..
'herein, adjusted for working capital deposits as appropriate. . Prepayments are
. allocated on the basis of operation and maintenance expenses associated with the facilities considered herein. Materials and supplies are allocated on the. basis I of gross investment less land.
Section 3.2.7 Accumulated Deferred Income Tax is the net total of FERC Accounts. 190, 281, 282, and 283 which have been analyzed and allocated by each of the Companies in'accordance with'each Account's runctional use. The. portion related to general plant is allocated to function in accordance with the' general plant-allocations as described in Section 3.2.5. The allocation to Level B-2 is on the basis,of net investment less land. Section 3.2.8 Total Net Investment represents the direct and allocated investments that are associated with Level B-2 and is the sumation of. Sections - 3.2.41(Net Investment) through 3.2.7 (Accumulated Deferred Income Tax) and is the value "I B-2 in the formulae in Section 3.2. 1 Section 3.2.9 Operation and Maintenance Expenses, FERC Accounts 560 through L573, are allocated in relation to the net transmission plant associated with the facilities considered herein unless more detailed assignments can be made from each Company's existing recor'ds. I 1 1 1
^- ^ .n _ _~ . .~_ - .- : . a
- x 1 2 .. . .
~
y m ,.._ N' g ,. . r
..q<
M-14.. l
'Section 3.2.10 Administrative and General Expenses, FERC Accounts 920 through .
- 932, excluding 924,:are allocated to function based on salaries and wages and to
- Level B-2 on'the basis of net investment. ' Account 924'is directly assigned to function by each of the Companies and allocated withi". function based on net iinvestment.
.)
'Section 3.2.11- Depreciation Expense is net of Amortuation of Investment Tax I
Credit (AITC). .The depreciation expense is taken directly from the records of each of the Companies. The depreciation expense associated.with Level B-2-is idetemined on the basis of the gross investment in 115 KY and above' facilities ;
- , q
'and the associated depreciation rates. The depreciation expense associated with i
)
general plant is' allocated to function in accordance with the general plant ' allocations as described in Section 3.2.5. The general plant depreciation
' expense allocated to function is further allocated to Level B-2 on the basis-of 2 depreciation expense related to the 115 KV and above facilities and the total transmission plant.
Section 3.2.12 Real and Personal Property Taxes are assigned directly to function. These taxes are allocated to the 115 KV and above facilities (Level B-2) based on the ratio of the net investment in the 115 KV and above facilities to the. net transmission plant. The real and personal property taxes associated with general plant are allocated to function on the basis of salaries and wages b and within function to the facilities rated 115 KV and above (Level B-2) on the basis'of net investment. , 1 0 Lu-'* _dm _ _ _.md ___ _ 2 .,_ll S L1_..l' ' '
- J_ m "? f ' ) 1 ? A_ .R , .__._? . Ik 1 2.%._. + ***'.8-
...,.y w -;
f 9., d . r . M-15.. l
'Section 3.2.13 Payroll Taxes are developed for function by applying the f
. expected payroll tax rates to the salaries and wages developed'in Section 3.2.18.. The transmission plant payroll taxes plus the allocated A&G are y allocated to the 115 KY and above facilities (Level B-2) based on the ratio,of the net investment in the 115 KV and above facilities to the total net
-transmission investment. '
b Section 3.2.14 Credits '(or Debits) to Operating Expenses: The revenues clas- J
.sified as 'Other Operating Revenue' or ' Purchased Power' in each Company's budget will be credited to the operating expenses if the transmission facilities considered herein were responsible for such revenues (e.g., such revenues associated with long tem capacity, short term capacity, and Unit Power Sales).
-If the revenues for transmission service are not credited, the estimated demands ^
associ6ted-with the revenues will be added to the demand of each of the affected
' Companies'for the transmission rate calculation. Because certain companies have operating agreements with other p,arties with respect to the transmission facilities considered herein, there may be revenues or expenses associated with the facilities rated 115 KY and above (Level B-2) that will be credited or debited to the operating expenses for the affected companies.
+ . 4 4 ? ? ^l_'lY. ?. [.. .s.~-l-a A .-l- ??' $ $
- .+.A # '?*~-
- A ' - - - - - -
^
l ;;;. - l M-16. , j
' Section 3.2215c Additional Income Taxes and Income Tax Efiect of 5% Basis y
Reduction. Additional income taxes- (IT$ ) are due to the treatment of Allowance
, for Funds Used During Construction (AFUDC) and Amortization of Investment Tax
!. Credits (AITC).' Additional income taxes and the income tax'effect of 5% basis-O reduction (IT b) are computed in the following manner. ITj= IT n.or.ITg and IT T b = p x BD* 9 ' Where: *[AFUDCequity + ANDCdebt -AITC) ITn" - ITg =
.AITC]
h x [AFUDCequity Where:
.T. = F+5-2FS (federal income taxes deductible 1 - F5 for state income tax purposes).
or T = F +~S - FS (federal income taxes not deductible L - for state income tax purposes) ITp = Additional-income taxes due to the treatment of Allowance for Funds Used During Construction (AFUDC) and Amortization of Investment Tax Credits (AITC). The subscription "i" denotes whether the company uses a " gross of tax" (ITg) method or a
" net of-tax" (IT )nmethod for-accounting for AFUDC.
*This is applicable only to companies which elect the 10% Investment Tax Credit. .
4 ' A lbl.
. >Y V .n. n _"Yl M' '"
-c . . . . -
l L .L ?I.' ? '- ' $ . . >
, . s. . :
l ; u , M-17.- 1 , i
- ITn-=- Inc me tax effect of equity AFUDC, debt AFUDC, and AITC for.
p" ... each of:the companies using'the " net of tax" method.
, ITg=. Income tax effect of equity AFUDC and AITC for each of the L companies using:the " gross of tax" method.
ITb= ' Income tax effeet of.5% basis reduction. AFUDC equity
= . Depreciation expense of the AFUDC equity component-u associated with the facilities considered herein.
E [' - AFUDC debt
= Depreciation expense'of the AFUDC debt component associated with the facilities' considered herein.
AITC = Amortization of investment tax credit associated with~the
. facilities considered herein.
BD' = The amortization of the permanent difference between book basis-and tax basis arising from the 5% basis reduction for purposes as specified by TEFRA.
.T = Combined state and federal income tax rate.
F .= Federal income tax rate. l .S = State income' tax rate.
- Section 3.2.16_ ' Total Expenses represent the direct and allocated fixed expenses associated with the facilities considered herein and are the summation of Section 3.2.9 (Operation and Maintenance Expenses) through Section 3.2.15 (Additional Income Taxes and Income Tax Effect of 5% Basis Reduction) and is the
. value "EB-2 in the formulae in Section 3.2.
*d #% e *-a ' Y. # ( '**f,'Y.
1 # . **
- M-18.
go. , Section 3.2.17 The Cost'of Capital and Associated Income Taxes are computed in U l- the following manner and are the values "CM g
". "CM ", "IT ", and "IT " in the-2 3 2 formulae in Sections 3.2,.4.2, 5.2, 6.2, and 7.2:
CM1,2 - [(DR x 1) +'(PR x p) + (ER x c)] IT 1,2
=- h x [(PR x p).'+ (ER x c)]
Where: DR + PR + ER = 1.0 [ and T = F + S - 2 FS- (federal income taxes deductible-1 - F5 for state income tax purposes) or
~T- = F + S - FS (federal income taxes not deductible
) for state income tax purposes) CM 1,2
= Weighted' average cost of capital for the January-May and June-December periods of the Contract Year, respectively -
(%). IT 1,2 = Inc me tax requirement associated with preferred stock and connon equity weighted cost of capital for the January-May and June-December periods of the Contract Year, respectively (%). DR = Ratio of debt capital (target ratio; includes- first mortgage bonds, pollution control obligations, and capitalized leases). PR = Ratio 'of preferred stock (target ratio). ER = Ratio of common equity (target ratio). i = Embedded cost of debt capital (%). l E'mbedded cost of preferred stock (%). p = c = 16.0%, return on common equity. T = Combined state and federal income tax rate. 1 F = Federal income tax rate. S = State income tax rate, r+_:_ u::_. ->c v :_ - t ~ - -
~ . ~- v- ,
4 N-19. Section 3.2.18 Salaries and Wages are budgeted by each of the Companies for V each functional group for the Contract Year. The budgeted salaries and wages account for. changes in wage rates and number of employees. The salaries and wages associated with the administrative classification are allocated to the functional groups based upon the ratio of the functional group's salaries and wages to the total salaries and wages less the ) administrative classification's salaries and wages.
- The transmission plant salaries and wages which includes the allocated A&G are allocated to the 115'KV'and above facilities (Level B-2) based on the ratio of
.the net' investment in the 115 KV and above facilities to the total net
- transmission investment.
Section 1,2.19 Average Transmission Loss Percentage: For purposes of determin-ing charges under the Service Schedule of the Contract, the average transmission loss percentage for each of the Companies shall be three percent (3%) and is the value "L" in the formulae in Section 3.2. a e 9 i l w :.,.s -.a. : , ., .rs .
~~ '
.- v .
.--L.. _~L'-
. T L :- . ---- .-:-------t. -
f ;,; . . . M-20. ARTICLE IV DERIVATION OF CAPACITY CHARGE FOR TRAN5 MISSION SERVICE AT , LEVEL C f Section 4.1 Level C Capacity Charge: Level C facilities are defined as all
. substations that transform voltage from a transmission voltage (i.e.,115 KV and above) to a sub-transmission voltage (i.e., voltages 39 KV through 69 KY inclusive). The computation of the capacity charge for service from the Level C facilities is based on the investment, expenses, and load related to substations at Level'C, and facilities' rated 115 KI and above (Level B-2). This capacity charge excludes'the investment and expenses associated with the genera-tor step-up substations. The computation of the capacity charge for service from Level C facilities for each period of the Contract Year is described in the following sections. The charge for each period of the Contract Year will be shown on-the Informational Schedule and will be revised in accordance with this
. Manual in subsequent. calendar years.
Section 4.2 Derivation of Monthly Level C Capacity Charges: The derivation of the monthly Level C capacity charge of each of the Companies is based on each
- Company's respective investments, expenses, and load related to facilities at
- Level B-2 and C during the' Contract Year and the cost of. capital and incremental income taxes in each period of the Contract Year. The derivation of the monthly Y Level C capacity charge for each period of the Contract Year is expressed in the following formulae:
h
+
- m. -_ -- . c , y. r..
l .. M-21. R = 3 I'C x (CM 3 + IT 3)/100% + E'c D C
- 1A R
2 I C x (CM2 .+ IT p,)/100% + E'C C 3 D C x 12 I' C . ' IB-2x-[1.0-SB-2 /DB-2][D ST/ (DB 38-2))*IC
=
18-2 * (UST /DB-2) + IL E'C
= E B-2 x[1.0-S B-2 /DB-2][D ST/ (DB-2 ~ IB-2)] + EC
= E B-2 x (DST
/DB-2) + EC Where: R 3
= Monthly Level C capacity charge for January through May ($/KW-month).
R 2
= Monthly Level C capacity charge for June through C
December ($/KW-month). CM 1
= The weighted average cost of capital (%) associated with the'.
January through May' period of the Contract Year. CM 2
= The weighted average cost of capital (%) associated with the June through December period of the Contract Year.
l IT 3
= The income tax requirement associated with the preferred stock i
and.comon equity weighted cost of capital (%) associated with the January through May period of the Contract Year. ] IT 2
= The income tax requirement associated with the preferred stock-l' and comon equity weighted cost of capital (%) associated with I the June through December pericd of the Contract Year. j
)
IB-2 = The 12-month average investment ($) in transmission lines and associated substation facilities (excluding generator step-up substations) rated 115 KV apd above (Level B-2). 9 M a. ._A n. : .2- w - = r :. - _=__:=_. -- - 3_ _ _ a ._ . . _ _= w:b
4 9 9 .. M-22.
. -1 IC = The 12-month average. investment ($) in substations having a transmission high-side voltage (i.e.,115 KV and above) and a sub-transmission low-side voltage (i.'e., 39 KV through.69 KY, inclusive).
y I'C
= The 12-month average investment ($) at Level C plus an allocated portion of the 12-month average investment ($) at level B-2 that' is used to serve load at Level C.
The' 12-month annual expenses ($) for transmission _ lines and EB-2 = associated substation facilities (excluding generator step-up substations) rated 115 KY and above (Level B-2). Si E = - The 12-month annual expenses ($) for substations having a C transmission high-side voltage (i.e.,115 KV and above) and a - sub-transmission low-side voltage (i.e., 39 KV through 69 KY, inclusive). E'C
= The 12-month annual expentes ($) at Level C plus an allocated portion of the 12-month attnual expenses ($1 at Level B-2 that is used to serve load at Level C.
D C
= The 5-day average estimated load at the generator (KW) adjusted for losses through the substations having a transmission voltage
@ on the high-side (i.e.,115 KV and above) and a sub-transmission I voltage on the low side (i.e., 39 KV through 69 KV, inclusive). The 5-day average estimated load at the generator (KW) adjusted DB-2 = _ U for losses through the transmission. lines and associated - substation facilities rated 115 KV and above (Level B-2). 1 i 4 m w ' .', ,n
- 4-e- u ._y e+ , +v. ms ,
.= .e~, _em,-
pg , n. y ... ~ ' v
- j. . M-23.
7 s D =- The 5-day average estimated load (KW) at Level B-2 that flows-( ST , into the~ substations having a transmission voltage on the high' side and a sub-transmission' voltage on the low side'(Level C). SB2= The. 5-day average estimated sales (KW) made to custow rs-1 served from transmission lines and associated substation e facilities rated 115 KV and above (Level B-2). The source of the load, investment, and expense data incorporated in the above fonnulae for each of the Companies (including FERC Account numbers and description of allocation ' procedure .and calculation of the cost of capital) is as-set forth.in the following sections. _Section 4.2.1- Five-Day Average Load is computed based on the estimated annual peak one-hour. net territorial load (KW) at the generator for each of the
. Companies. The estbated peak one-hour load is then adjusted to an estimated 5-day average load based on the preceding year's actual loads (Section 3.2.1).
i: The estimated 5-day average load at the generator is then adjusted to the estimated 5-day average load at Level C. Section 4.2.2 Five-day Average Sales are the estimated ~ peak one-hour sales (KW) adjusted to a five-day average based on the preceding year's actual sales. Section'4.2.3 Gross Investment for Level B-2 is the summation of FERC Accounts 350; 354, 355, 356, 357, 358, and 359 associated with 115 KV and higher voltage lines plus Accounts 350, 352, and 353 associated with transformation and switching between 115 KV and higher voltages. (Generator step-up substations ) i M ; i j M &L k _i ax = ~~< = mz m m x:.m c2 xuw := _ _. c -s " ~ - -~
- l. M-24.
L- are excluded.) Gross investment for Level C is the sumation of FERC Accounts ) l 350, 352, 353, 360, 361, and 362 associated with transforming between ' transmission and sub-transmission voltages. Section 4.2.4 Accumulated Depreciation is that depreciation associated with the gross investment defined above and is allocated to Account based on investment and depreciation rates by Account. The allocation to level is based on gross n investment. Section 4.2.5 Net Investment is the difference between Section 4.2.3 (Gross Investment) and Su tion 4.2.4 (Accumulated Depreciation). Section 4.2.6 General Plant (Net) includes the investment in Accaunts 389 through 399 excluding amounts directly assigned to production. The allocation of net general plant to function (excluding the direct assignments) is done on the basis of salaries and wages as developed in Section 4.2.19. After net general plant has been allocated to function, it is allocated to level of service based on the ratio of the total net investment in the respective facilities to the total net investment considered herein. ) l Section 4.2.7 Working Capital is the summation of cash working capital, prepay-ments, and materials and supplies. Cash working capital is one-eighth of the allocated operation and maintenance expense plus one-eighth of the allocated 3 administrative and general expense associated with the facilities considered i
, herein, adjusted for working capital deposits as appropriate. Prepayments are )
4 ==::=w=werw=:L :ww::~ - ~ m - -
'- * ~ ' '
M-25. allocated on the basis of operation and maintenance expenses associated with the P
' facilities considered herein. Materials and supplies are allocated on the basis of gross investment less land.
Section 4.2.8 Accumulated Deferred Income Tax is the net total of FERC Accounts 190, 281. 282, and 283 which have been analyzed and allocated by each of the Companies in accordance with each Account's functional use. The portion related to general plant is 'llocated to function in accordance with the general. plant assignments as described in Section 4.2.6. The allocation to level of service is on the basis of net investment less land. y Section 4.2.9 Total Net Investment represents the direct and allocated investments that are associated with Levels B-2 and C and is the summatior, of Section 4.2.5 (Net Investment) through Section 4.2.8 ( Accumulated Deferree'. Inccine Tax). These'are shown as the values "IB-2 " 8"d IC , respectively, in the formulae in Section 4.2. L t Section 4.2.10 Operation and Maintenance Expenses, FERC Accounts 560 through 573 plus Accounts 580, 582, 588, 589, 590, 591, 592, and 598, are allocated in relation to the net investment associated with the facilities at Levels B-2 and C considered herein unless more detailed assignments can be made from each Company's existing records. . Section 4.2.11 Administrative and General Expenses, FERC Accounts 920 through 932, excluding 924, are allocated to function based on salaries and wages. The administrative and general expenses allocated to function are then allocated to
$ -- - - - - - - .. A .$- a_-
- g. * ,
M-26. each level of service on the basis of net investment. Account 924 is directly assigned to function by each of the Companies and allocated within function based on net investment. g e Section 4.2.12 Depreciation Expense is.nct of Amortization of Investment Tax Credit (AITC). The depreciation expense is taken directly from the records of each of the Companies. The depreciation expense associated with each level of service is determined on the basis of the gross investment in the' respective facilities and the nssociated depreciation rates. The depreciation expense associated with general plant is allocated in accordance with the general plant
. allocations as described in Section 4.2.6. The general plant depreciation expense allocated to function is further Allocated to each level of service on the basis of depreciation expense related to the respective facilities and the total plant investment considered herein.
Section 4.2.13 Real and P,ersonal Prpertdaxes, are assigned directly to function. These taxes are allocated to each level of service based on the ratio of the net investment in the respective facilities to the total net investment considered herein. The real and personal reoperty taxes associated with general plant are allocated to function on the basis of salaries and wages, and within function to each level of service on the basis of net investment. P Section 4.2.14 Payroll Taxes are provided from each Company's records. The l payroll taxes associated with the administrative and general functions are allocated to function based on salaries and wages. The payroll taxes plus tne allocated A&G are further allocated to each level of service based on the ratio er _ - -=c_~ ,
- :,_- . -_.x= __: x_2 _a_ xx _ ~ . - n
ht . M-27. 7 of the net investment in the respective facilities to the total net investment considered herein. Section 4.2.15 Revenue Credits are assigned if the facilities for transmission service ware responsible for such revenues; however, if transmission service revenues are not credited, the estimated demands associated with the revenues 3 will be added to the demand of each of the Companies. Section 4.2.16 Additional Income Taxes and Income Tax Effect of 5% Basis
- , Reduction. Additional income taxes (IT4) are due to the treatment of Allowance for Funds Used During Construction (AFUDC) and Amortization of Investment. Tax .
Credits (AITC). Additional income taxes and the income tax effect of 5% basis reduction (IT ) are computed as described in Section 3.2.15. b Section i.2.17 Total Expenses represent the direct and allocated fixed expenses associated with the facilities considered herein and are the summation of-Section 4.2.10 (Operation and Maintenance Expenses) through Section 4.2.16 (Additional Income Taxes and Income Tax Effect of 5% Basis Reduction) and are the values "E B-2 " and "EC " in the formulae in Section 4.2. Section 4.2.18, The C3 t of Capital and Associated Income Taxes are computed as described in Section 3.2.17. 2 Section 4.2.19 Salaries and Waoes are budgeted by each of the companies for each functional group for the Contract Year. The buogeted salaries and wages account for changes in wage rates and number of employees. i i ~ = _
- . . - =i
+ r . =v
.,; -n .
2 M-28.
. The. salaries and wages associated with the administrative classification a e 4- allocated to the functional groups based upon the ratio of tha functional' group's salaries and' wages to the total salaries and wages'less the
-administrative classification's salaries and wages, s.
The salaries and wages which include the allocated A&G a'e allocated to each
. ;]; level of service based on the ratio of the net investment in the _ respective p- " facilities to the total net investment considered herein.
- s 1 ,
W 9 r l 9 l . w
+
h:2'.91_C..'YUI t/' ' ' * * ': X7.. '
- _ 4 4 - L. ? 1 ^4 e .***T** ' " **
- t
$1,(. e M-29.
ARTICLE V DERIVATION OF' CAPACITY CHARGE FOR TRAN5 MISSION SERVICE AT g LEVEL D s Section'5.1 Level D Capacity Charge: Level D facilities are defined as all
, lines with voltages 39 KV through'69 KV inclusive. This also includes all metering.and/or switching stations at voltages. of 39 KV through 69. KV, inclusive. The' computation of the capacity charge for service from Level D
- facilities.is based on the investment, expenses, and load related to facilities at-Level D, substation facilities with a transmission high-side voltage and.a sub-transmission low-side voltage (Level C), and facilities rated 115 KV and above (Level B-2). This capacity charge excludes the investment and expenses associated with the generator step-up substations. The computation of
..the capacity charge for service from Level D facilities.for each period of the Contract Jear is described in the following sections. The charge for each period of' the Contract' Year will be shown ca the Informational Schedule and will
~
be revised in accordance with this Manual. in, subsequent calendar years. Section 5.2 Derivation of Monthly Level D Capacity Charge: The derivation of the monthly Level D capacity charge of each of the Compcnies is based on each Company's respective investments, expenses, and load related to facilities at
. Levels B-2, C, and D during the Contract Year and the cost of capital and l incremental income taxes in each period of the Contract Year. The derivation of the monthly Level D capacity charge for each period of the Contract Year is
. expressed in the following formulae:
5 dsw1..l urw2 2 29 :: ': 1 2 l ' - -- L_- 1 .- "kD . lls ' T-- -- L J *' -- * - ' " ' 'h- ' '
- ? *
-- L 1
. i H , ,
i M-30. l
.. 1
=
s Ry D I'D x (CM g + IT 1)/100% + E'D DD
- 1A R
- I D x (CH 2 + IT 2)/100% + E'D 2
D DD x.12 x I'D I'C x[1.0-S/D)[D C C CDdD C ~ 3C )) + ID -l
)
=-
I'C x (DCD/DC ) + I D C C CD/ (DC - 3C)] + ED B = E'D E'C x[1.0-S/D)[D
=
E'C x (DCD /DC) + ED Where: R y = Monthly Level D capacity charge for January through l p D < May.($/KW-month). R 2
= Monthly Level D' ca acity charge for June through !
D December ($/KW-montn). 1 CM = The weighted average cost of capital-(%) associated with the 1 January through May period of the Contract Year, j CM = The' weighted average cost of capital (%) associated with the 2 June through December period of the Contract Year. IT 3 = The income tax requirement associated with the preferred stock and common equity weighted cost of capital (%) associated with the January through May period of the Contract Year. IT = The. income tax requirement associated with the preferred stock j 2 and comon equity weighted cost of capital (%) associated with 5 the June through December period.of the Contract Year. 4 ID = The 12-month average investment ($) in sub-transmission lines and substation facilities (Level D). i W mm -- ?:n - ._ 1 _= : n >. ~
- .L- _, x _:- _ m. 2 - _ .:_-.- - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ .
y , . . - ., M-31. . I'C. = The 12-month average investment ($) at Level C plus'an allocated-portion of the12-month average investment ($) at Level B-2 that - - -- is used to serve load at Level C. .(Refer to Article IV) I'D
= The 12-month average investment ($) at Level D plus an allocated portion of the 12-month average investment ($)~ at Level B-2 and Level C that is used to serve load at Level D.
E D
= The.12-month annual expenses ($) for sub-transmission'11nes and n
substation. facilities (Level D). E'C = The 12-month annual expenses ($) at Level C plus an allocated portion of the expenses ($) at Level B-2 that is used to serve 6 load at Level C. (Refer to Article IV) E'D
= The 12-month annual expenses 3) at Level D plus an allocated portion of the expenses ($) at Level B-2 and Level C that is u' sed to serve load at Level D.
Og = The 5-day average estimated lead at the generator (KW) adjusted for losses through the transmission substations having a transmission voltage on the high side (i.e.,115 KV and above) and a sub-transmission voltage on the low side (i.e., 39 KV through 69 KV, inclusive). D CD
= The 5-day average estimated load (KW) thet flows into Level D.
D D
= The 5-day average estimated load at the generator (KW) adjusted for losses through the sub-transmission facilities (Level D).
R S C
= The5-dayaverageestimaiedsales(KW)madetocustomersserved from substations having a transmission voltage on the high side and a sub-transmission voltage on the low side (Level C).
l/ t e 4_wx _ - L.- _ ,x -c- r e- ~ :m:> - n.a v *
=" - *'
M-32. ( The source of the load, investment, and expense data incorporated in the above
' formulae (including FERC Account numbers and description of allocation procedure and calculation of the cost of capital) is as set forth in the following sections.
Section 5.2.1 Five-Day Average Load is computed based on the estimated peak one-hour net territorial load (KW) at the generator. The estimated peak one-hour load is then adjusted to an estimated 5-day average load based on the preceding year's actual loads. The estimated 5-day average load at the generator is then adjusted to the estimated 5-day average load at Level D. 9 Section 5.2.2 Five-Day Average Sales are the estimated < inual peak one-hour sales (KW) adjusted to a five-day average based on the pravious year's actual sales. Section 5.2.3 Gross Investment for Level B-2 'is the summation of FERC Accounts 350, 354, 355, 356, 357, 358, and 359 associated with 115 KV and higher voltage lines plus Accounts 350, 352, and 353 associated with transformation, metering, and switching between 115 KV and higher voltages. (Generatorstep-up substations are excluded.) Gross investment for Level C is the summation of FERC Accounts 350, 352, 353, 360, 361, and 362 associated with transforming between transmission and sub-transmission voltages. The gross investment for Level D is the summation of FERC Accounts 350, 354, 355, 356, 357, 358, and 359 associated with sub-transmission lines plus Accounts 350, 352, 353, 360, 361, and 362 associated with sub-transmission metering and switching substations, arn: u: _= a' m' ~ - - -
~. .
~
v
M ::wy
,. ;M-33.-
. l 1
j y Section 5.2.4 Accumulated Depreciation 1s that depreciation associated with'the ai W. 'i h- : gross' investment d6 fined above and is allocated to' Account based on-investmeht' l L andl depreciation rates by Account. The allocation to level is based on gross b y _ investments a
-{
Section' 5.2.5 ' Net Investment is the difference between Section 5.2.3 (Gross. 1 Investment) and Section 5.2.4 (Acc.umulated Depreciation).. W E g . 9 Section 5.2.6 General Plant' (Net)-includes the investment in Accounts 389 through 399 excluding amounts directly assigned to prodt'etion. The allocation y . of net general' plant to function (excluding the diree' assignments) is done on the basis.of salaries and wages-as developed in Section 5.2.19. After net. general plant has been allocated to function it is allocated to' level of servict based on the ratio of the net investment in the respective. facilities-1 g , )to the. total. net. investment considered herein. ] 3 :q 1 q Section 5.2.7 Working Capital is the summation of cash working capital, prepay- ! ments, and materials and. supplies. Cash working capital is one-eighth of the o iallocated operation ar3d maintenance expense plus one-eighth of the allocated administrative and general expense associated with the facilities considered herein, adjusted for working capital deposits as appropriate. Prepayments are ( et I ~- - '. allocated on the basis of operation and maintenance expenses associated with the { facilities considered herein. Materials and supplies are allocated en the basis f i of_ gross investment less land. 1 s ! 1 i l i 1 &mn ~ ~ -+ - - - = = , n =. ,.~ x __ ~A
Q.+- , M-34. Section 5.2.8 Accumulated Deferred Income Tax is the net total of FERC Accounts 190, 281, 282, and 283 which have been analyzed and allocated-by each of the
. Companies'in accordance with each Account's functional use. The portion related to general: plant is allocated to function in accordance with the general plant assignments as' described in Section 5.2.6. The allocation to each level of service is on the basis of net investment-less land.
Section 5.2.9 - Total Net Investment represents the direct and allocated investments that are associated with Levels B-2, C, and D and is the summation of Section 5.2.5 (Net Investment) through Section 5.2.8 (Accumulated Deferred I IncomeTax). .These are shown as the values "I B-2" ' "I " and "I ", respectively, C D in the formulae in'Section-5.2. Section 5.2.10 Operation and Maintenance Expenses, FERC Accounts 560 through 573_plus_ Accounts 580, 582, 588, 589, 590, 591, 592, and 598, are allocated in
. relation to the net plant associated with the facilities at Levels B-2, C,. and 0
- considered herein unless more detailed assignments can.be made from each Company's existing records.
'Section 5.2.11 Administrative and General Expenses, FERC Accounts 920 through 932, excluding 924, are allocated to function based on salaries and wages. The 1
administrative and general expenses' allocated to function are then allocated to
- s. each level of service on the basis of net investment. Account 924 is directly assigned to function by each of the Companies and allocated within function based on net investment.
%=_ :_=_wn_ _- nn .s_e m _w- _ -m m _: . _-
1,.
'M-35.
~
; Section 5.2.12 Depreciation Expense is net of Amortization of Investment Tax Credit (AITC). The depreciation expense is' taken directly from the records of each of the Companies. The depreciation expense associated with each level of service is determined on the basis of the gross investment in the respective Y facilities and the' associated depreciation rates. The depreciation expense associated with general plant is allocated in accordance with the general plant l
l allocations as described in Section 5.2.6. The general plant depreciation 0 expense allocated to function is further allocated to each level of service on the basis of depreciation expense related to the respective facilities and the total plant investment considered herein. O Section 5.2.13 Real and Personal Property Taxes are assigned directly to function. These taxes are allocated to each level of service based on the ratio
- - of the net investment in the respective facilities to the total net' investment considered herein. The real and personal property taxes associated with general plant are alloc ted to function on the basis of salaries and wages and within function to each level of service on the basis of net investment.
Section 5.2.14 Payroll Taxes are provided from each Company's records. The. I payroll taxes associated with the administrative and general functions are allocated to function based on salaries and wages. The payroll taxes plus the allocated A&G are further allocated to each level of service based on the ratio of the net investment in the respective facilities to the total net plant investment considered herein. 6 m..m .s e 6
- 2 PA, v' La.* * * * '- - - - 1
~
_- ~ . - . '
( . M-36. Sectio'n 5.2.15 Revenue Credits are assigned if the facilities for transmission
- service were responsible for such revenues; however, if transmission service revenues are not credited, the estimated demands associated with the revenues will be added to the demand of each of the Companies.
Section 5.2.16 Additional Income Taxes and Income Tax Effect of 5% Basis Reduction. Additional income taxes (IT$) are due to the treatment of Allowance 2
- for Funds Used During Construction (AFUDC) and Amortization of Investment Tax Credits (AITC). Additional income taxes and the income tax effect of 5% basis reduction (IT ) are computed as described in Section 3.2.15.
b ) Section 5.2.17 Total Expenses represent the direct and allocated fixed expenses associated with the facilities considered herein and are the summation of Section 5.2.10 (Operation and Maintenance Expenses) through Section 5.2.16 (Additional Income Taxes and Income Tax Effect of 5% Basis Reduction) and are the values "EB .2 , "E ", and "E " in the formulae in Section 5.2. C D Section 5.2.18 The Cost of Capital and Associated Income Taxes are computed as described in Section 3.2.17. Section 5.2.19 Salaries and Waces are budgeted by each of the Companies for each functional group for the Contract Year. The budgeted salaries and wages
- account for changes in wage rates and number of employees.
The salaries and wages associated with the administrative classification are allocated to the functional groups based upon the ratio of the functional i ec ma -- t
- = x -- _v = . .
. y, v ..
M-37. l',.. t . . L . group' s sal ar ies 'and wages to the total!. salaries and: wages-less'the v' administrative classification's . salaries 'and wages.. The~ salaries and wages which include the allocated A&G are allocated.to each
' level of. service based on the ratio of the net investment in the. respective facilities to the total net investment considered herein.
4 t f me s,
* .1 a
l 1 . il
.q J
i s 1 1
)
i. 1 Mm._L ua __ #m,_._ .,.,.m4a,..._.r t r1 s .. o..,, , ,_3,m._.y. , , 3 , ..y,_ p
p,:.. M-38. p ARTICLE VI R f. DERIVATION OF CAPACITY CHARGE FOR TRAN5 MISSION SERVICE AT LEVEL E O Section 6.1 Level E Capacity Charge: Level E' facilities are defined as all substations' that transfonn voltage from a transmission voltage (i.e.,115 KV and f above) or a sub-transmission voltage (i.e., voltages from 39 KV to 69 KY, inclusive) to a distribution-voltage (i.e., voltages below 39 KV. through 12 KV).
.The computation of the capacity charge for service from Level E facilities is
. based on the investment, expenses, and load related to substations with
. transmission or sub-transmission high-side voltage and distribution low-side voltage (Level E), sub-transmission facilities (Level D), transmission substations with transmission high-side voltage and a sub-transmission' low-side voltage (Level C), and transmission facilities rated 115 KV and above (Level B-2). This capacity charge excludes the insestment and expenses. associated with the generator step-up substations. The. computation of the capacity charge for service from Level E facilities for each period of the Contract Year is
. described in the following sections. The charge for each period of the Contract Year will be shown on the Informational Schedule and will be revised in q accordance with this Manual in ~ subsequent calendar years.
I Section 6.2 - Derivation of Monthly Level E Capacity Charge: The derivation of j i the monthly Level E capacity charge of each of the Companies is based on each Company's respective investments, expenses, and load related to facilities at L - Levels B-2, C D, and E during the Contract Year and the cost of capital and a ; L& _ . -m _ - . , - -- .
, +
f b '-
- M-39..
incremental income taxes in each period of the Contract Year
. The derivation 'of '
' the monthly; Level _ EL capacity charge for each period of the Contract Year is
- expressed in the following formulae:
Ry =-
. ,; - I'E x (CMy '.+ IT3 )/100( + E'E D x 12 E
,>i R
- 2 E
I'E x (CM2 + IT 2)/100% & E'E / l D x 12 E I'E -IB '2 x (1.0 - SB-2 /DB-2)[1.0 - (D ST/ (DB-2 ~ IB-2))) > + I'C x[1.0-S/D][1.0-(D CC CD/ (DC-3))3 C
+ I'g.x (1.0 - 5g/03 ) + Ig
=
IB-2*EIUB-2 ~ SB DST)/UB-2 3 . i
+ I'C x[(DC~bC-DCD)/D3 C
' +I D.x (1.0 - SD/DD) + IE E'E = E B-2 x (1.0 - S B-2 /DB-2)[1.0-(DST/ (DB-2'- 3B-2))3
?
~ + E'c x[1.0-S/D][1.0-(D CC CD/ (DC'3))3 C
. +E D x (1.0 - S D/DD) + E E
= E B-2 x [(DB-2 ~ 3B DST)/DB-23
' +E C x [(DC~$C-DCD)/D3 C
+E D
x (1.0 - SD/DD) + E E Where: R y = Monthly Level E capacity charge for January through ,
- E .
May (5/KW-month). R 2 Monthly Level E capacity charge for June through E December . ($/KW-month) . l 4 f g sur
. M.M.?.T.'.N . l a. L. . .'*a'
.% ., 1
* * * * * * **%* _fr="'_j.%
***'VW
. *'. * ~ '
N -'*%- Y 't'"#*
, y, . + *
- M-40.;
The weighted average. cost of capital (%) associated with the
, CM = -
1 3 ,
~ January through May period of .the Contract Year.
The weighted average cost of capital (%) associated with the
~
CM = 2-June through December period of the Contract Year. ITy .= The inco.x tax requirement associated with the preferred st'ock-and common equity weighted cost'of capital '(%) associated with the January through May _ period of the Contract Year.
- a. .
i IT 2
= The _ income tax requirement. associated with the preferred stock' and. common equity weighted cost of capital (%) associated with the June through December period of the Contract Year .
k' IB-2 = - The 12-month userage investment ($) in transmission lines and-associated substation facilities (excluding. generator step-up s'ubstations)- rated 115 KV and above (Level B-2). IE = The 12-month average investment .($) in substations' having a - distribution low-side voltage (Level E). I'D
= The.12-month average investment ($) at Level D plus'an allocated
- portion of the 12-month. average investment (5) at Level _ B-2 and
.. .. Level C that is used to serve load at Level D. (Refer to
- Article V)
I'E
= The 12-month average investment ($) at Level E plus an allocated portion of.the 12-month average investment ($) at Levels B-2, C, and D that is used to serve load at Level E. l Q E B-2 = The 12-month annual expenses ($) for transmission lines.and associated substation facilities (excluding generator step-up .
substations) rated 115 KV and above (Level B-2). e U , I I l {ta'*
- e iJ._eqW."r* '9r *
*4 .,_
- 8 ' . - t 3
4* % - ce* - *% ~
"""'?<
m_ * **T # y
- q _"_ft " .
't f s T #, '* r e te,'_
M-41.--
.E . = sThe 12-month annual expenses ($) for substations having a n E
~ ~. .
distribution loiw-side vol'tage (Level: E). .
= The 12-month annual 'expensesJ($)- at Level D plus. an allocated ElD
,' portion of the expenses ($) at Level B-2 and Level C that is
' used to serve load- at Level D. (Refer to Article V)'
E'E .=- The 12-month annual' expenses ($)'at Level E plus an allocated portion of' the expenses ($) at Levels B-2, C, and D that is. used to Lserve' load at Level E. The 5-day average estimated load at the generator (KW) adjusted DB-2 = for losses through the transmission lines and associated e substation facilities rated 115 KV and above (Level B-2). D = The 5-day average estimated load at the ' generator-(KW) adjusted C for losses through substations having a transmission voltage on the high side (i.e.,'115 KV and above) and a sub-transmission voltage on the low side (i.e., 39 KV through' 69 KV, inclusive).- (Level C). LDCD = .The'5-day average estimated load (KW) that flows into Level D.
'D = The 5-day average estimated' load at the generator. (KW): adjusted D
for losses through the sub-transmission facilities (Level D). D E
.= The 5-day; average estimated load at the generator (KW) adjusted )
for losses through the substations having a distribution voltage on the low' side (Level E). .- i ~ D ST
= The 5-day average estimated load at the generator (KW) that i flows into the substations having transmission voltage on the ;
high side and a sub-transmission voltage on the low side (Level C). i I I &_mk1 mah_m - *,n +:: _n~_r+-_.% ~ & Az~~:mc~~~-? mee L'_ > n ~L __ r-N
. _ _ _ = - --- _
r O . , M-42. j f SB-2 = The 5-day average estimated sales (KW) made to customers served.
. from transmission lines and associated substation. facilities 4
rated 115 KV and above (Level B-2). ,;. S. D
= The 5-day average estimated sales (KW) made to custome.rs served .
from Level D facilities. g The source of the load, investment, and expense data incorporated in the above V , fomulae for each of the companies (including FERC Account numbers and description of allo $ation procedure and calculation of the cost of capital) is as set forth in the following: sections'. Section 5.2.1 Five-Day Average Load is computed based on the estimated peak one-hour net territorial load (KW) at the generator. The estimated peak one-hour load is then adjusted to an estimated 5-day average load based on the preceding year's actual loads.' The estimated 5-day average load at the generator is then adjusted to the estimated 5-day average load at Level E. i r Section 6.2.2 Five-Day Average Sales are the estimated annual peak one-hour sales (KW) adjusted to a five-day average based on the previous year's actual sales.
-Section 6.2.3 Gross Investment for Level B-2 is the summation of FERC Accounts 350, 354, 355, 356, 357, 35B, and 359 associated with 115 KV and higher voltage lines' plus Accounts 350, 352, and 353 associated with transformation, metering,
'and switching between 115 KV and higher voltages. (Generator step-up I
; j l
substations are exc1'uded.) Gross investment for Level C is the summation of q l l &n y u_ c12 . < - 1_x em :- e.~mrgo m ~~;~~ s. m. , .- 1 s - . . - .
O .
.4'.
e . . c M-43. FERC Accounts 350, 352, 353, 360, 361, and 362 associated with transforming between transmission and sub-transmission voltages. The gross investment for Level D is the summation'of FERC Accounts 350, 354, 355, 356, 357, 358,-and 359 associated with sub-transmission lines plus Accounts 350, 352, 353, 360, 361, and 352 associated with sub-transmission metering and switching substations. The gross investment for Level E is the summation of FERC Accounts 350, 352, 353, 360, 361, and 362 associated with transformation from transmission or sub-transmission to distribution. Section 6.2.4 Accumulated Depreciation is that depreciation associated with the gross investment defined above and is allocated to Account based on investment and depreciation rates by Account. The allocation to level is based on gross investment. Section 6.2.5 Net Investment is the difference between Section 6.2.3 (Gross Investment).and Section 6.2.4 (Accumulated Depreciation). Section 6.2.6 General Plant (Net) includes the investment in Accounts 389 through 399 excluding amounts directly assigned to production. The allocation of net' general plant to function (excluding the direct assignments) is done on the basis of salaries and wages as developed in Section 6.2.19. s After net general plant has been allocated to function, it is allocated to level of service based on the ratio of.the net investment in the respective facilities to the total net investment considered herein. .
?
1 . l R L + - . . . . . = . -_ . . ,, - 1
.. .i M-44.
Section 6.2.7 Working Capital is the summation of. cash working capital', prepay- >:r
'ments, and materials and supplies. Cash working capital is one-eighth of the allocated operation and maintenance expense plus one-eighth of the allocated
. administrative and general. expense l associated with the facilities considered y
herein, adjusted for working capital deposits as appropriate. Prepayments are allocated t,n the basis of operation and mainteriance expenses associated with the facilities considered herein. Materials and supplies are allocated on the basis of gross investment'less land. . Section 6.2.8 Accumulated Deferred Income Tax is the net total of FERC Accounts 190, 281, 282, and.283 which have been analyzed and allocated by each of the'
, Companies in accordance with each Account's functional use. The portion related to general plant is allocated 'to function in accordance with the general plant assignments as described in Section 6.2.6. The allocation to each level of.
service is on the basis of net investment less land. Section 6.2.9 ' Total Net Investment represents the direct and allocated investments that are associated with Levels B-2, C, D, and E and is the summation of Section 6.2.5 (Net Investment) through Section 6.2.8 (Accumulated Deferred Income Tax). These are shown as the values "I B-2 ' "I "' "I ", and C D "I E", respectively, in the formulae in Section 6.2. 4 Section 6.2.10 Operation and Maintenance Expenses, FERC Accounts 560 through 573 plus Accounts 580, 582, 588, 589, 590, 591, 592,-and 598, are allocated in relation to the net plant associated with the facilities at Levels B-2, C, D, and E considered herein unless more detailed assignments can be made from each Company's existing records. MO 1_ _ __i_. -_[.# i '
-. b [ 1. ! d - ' l .N [-- U " '
- f 4 h
i il { .I n , - e'
, M-45; a .
Section 6.2.11 . Administrative and General Expenses, FERC Accounts 920 through I E 932 excluding l924, are allocated to. function based on salaries and. wages. ' The g . administrative and.. general expenses. allocated to function are then allocated to' p
-: each level of service on:the basis 'of net investment. Account 924. is directly assigned to functionLby each of the Companies and allocated within function.
based on net investment. Y
-Section 6.2.12. Depreciation Expense is net of Amortization of Investment-Tax Credit (AITC). The depreciation expense is taken directly from the records of each of the Companies. The depreciation expense associated with each. level of 1
service is.. determined on the basis of the gross investment in the. respective facilities and the associated depreciation rates.' The depreciation expense associated with. general' plant is allocated to function in accordance with the general plant allocations _ as described in Section 6.2.6. The general plant ~
. depreciat4on expense allocated to function is further allocated to each level of
-service on the basis of depreciation expense related to the respective i facilities and'the total investment considered herein.
Section 6.2.13. Real and Personal Property Taxes are assigned directly to
- function. These taxes are allocated to each level of service based on the. ratio of the net investment in the respective facilities to the net investment considered herein. The real and personal property taxes associated with general b plant are allocated to' function on the basis of salaries and wages and within function to each level of service on the basis of net investment.
f a Y t la' a_2t_.1_ t. _ _ _ _ _ _ . . ~ .. _m 1 t_ r i
- _a iA._h.*1 1 i ? ' i ?*MW *"*
-- - - '?.L.-' 4 1 "' *
- - -I'- * '
- m. , ,
p ,:. M-46. Section 6.2.14 ' Payroll Taxes are provided from each Company's records. The payroll ' taxes associated with the administrative and general functions are
- allocated to function based on salaries and wages.- The payroll' taxes plus the allocated A&G are further allocated to each level of . service based on the ratio
. of;the net investment in the respective facilities to the total net investment considered herein.
Section 6.2.15' Revenue Credits are assigned if the facilities for transmission service were responsible for such revenues; however, if service revenues are not 7 credited.'the estimated demands associated with the revenues will be added to
' the demand of each of the Companies.
' Section 6.2.16 ' Additional Income Taxes and Income Tax Effect of 5% Basis Reduction. Additional income taxes (IT4) are due to the treatment of Allowance
- for Funds Used During Construction (AFUDC) and Amortization of Investment Tax Credits.(AITC). Additional income taxes and the income. tax effect of 5% basis reduction (IT b) are computed as described in Section 3.2.15.
Section 6.2.17 Total Expenses represent the direct and allocated fixed expenses associated with the facilities considered herein and are the summation of Section 6.2.10 (Operation and Maintenance Expenses) through Section 6.2.16 (Additional Income Taxes and Income Tax Effect of 5% Basis Reduction) and are
- the values "E B-? ", "E ", "E ", and "E " in the formulae in Section 6.2.
C D E i Section 6.2.18 The Cost of Capital and Associated Income Taxes are computed as described in Section 3.2.17. 1 4 8 M wr. ' u* 2 a_. A # 'arn . L *+a * ,, e n = Me t =t y==* , .W ' Y** . L & t+ t _.. *
- t 8-* * * -u--
7 mw: , L '[ M-47. a. h Section 6.2.19' Salaries and Wages are~ budgeted by each of.the Companies for each functional group for the Contract Year. The budgeted salaries and wages account for changes in wage rates and cumber of employees. b The salaries and wages associated with the administrative classification are-allocated to the functional-groups based upon the ratio of the functional y . group's salaries and wages to the total salaries and wages less the administrative classification's salaries and wages. The salaries and wages which includes the allocated A&G are allocated to each 4 leve'l of service based on the ratio of the net investment in.the respective facilities to the total' net investment considered herein. 6 9 i
)
__ --____:_=_= b
p: '. M-48. ARTICLE VII DERIVATION OF CAPACITY CHARGE FOR TRAN5 MISSION SERVICE AT LEVEL F Section 7.1 Level F Capacity Charge: Level F facilities are defined as facilities at voltages below 39 KV. The computation of the capacity charge for ? service from Level F facilities is based on the investment, expenses, and load related to primary distribution facilities (Level F), substations with transmission or sub-transmission high-side. voltage and a. distribution low-side 0- voltage (Level E), sub-transmission facilities (Level D), substations with transmission high-side _ voltage and a sub-transmission low-side voltage (Level C), and transmission facilities rated 115 KV and above (Level B-2). This capacity charge excludes the investment and expenses associated with the , generator step-up substations. The computation of the capacity charge for service from Level F facilities for each period of the Contract Year is 1- described in the.following sections. The charge for each period of the Contract Year will be shown on the Informational Schedule and will be revised in accordance with this Manual in subsequent calendar years. Section 7.2 Derivation of Monthly Level F Capacity Charoe: The derivation of the monthly Level F capacity charge of each of the Companies is based on each Company's respective investments, expenses, and load related to facilities at-Levels B-2, C, D, E, and F during the Contract Year and the cost of capital and incremental income taxes in each period of the Contract Year. The derivation of the monthly Level F capacity charge for each period of the Contract Year is expressed in the following formulae: 4 W 4
*v* *,* , p V .* 4 ***st'*'"g"' "*'""r * +- "'1 ' ~*'p7'***'
] t' t' $e,* l'", W 'h * "
y ,.
. . s . -n l' M-49.
k< .
- p. R. =
I'p x (CM y + IT g)/100% + E'p 3 . h Dp x 12
- I'F x (CM2 .+ IT g)/100% + E'y R "
2 @, .F Dp x .12 l'p. = .I'E x (1.0 - SEIOE )
- IF I E' p . = E'E x (1.0 - SE/DE) + E p Where: R 3
= ' Monthly Level F capacity charge for January through F
M May ($/KW-month).
- R 2
Monthly Level F capacity charge for' June through F December ($/KW-month). - CMy . = The~ weighted average cost. of capital (%) associated with the January through May period of the Contract Year.
. CM 2
. =- The weighted average cost of capital (%) associated 'with the June' through December period of the Contract Year.
IT y = The income tax requirement associated with the preferred stock and common equity weighted cost of capital (%) as:;ociated with the January through May period of the Contract Year. . IT = The income tax requirement associated with the preferred stock 2 and common equity weighted cost of capital (%) associated with the June through December period of the Contract Year. Ip The 12-month average investment ($) in Level F facilities.
=
As n . .x. .u.- ~s, , s. n- ,,.
; w 4
M-50. 1' - 9 y 31'E
= -
The 12-month average: investment ($) at Level E plus an allocated 3.
~
- g. por' tion of the 12-month average investment ($) at Levels B-2, C. .
q and.D.that is used to serve load at Level E. (Refer to Article ! g VI) i
'I I'p = - The 12-month average investment-($) at Level F plus an allocated portion of the 12-month average investment ($) at Levels B-2, C, j
.: D, and E that is used to serve load at. Level F. ji l
Ep = The '12-month annual expenses ($) for Leve1 ~ F facilities .
.]
1 E'E
= The 12-month annual expenses ($) at Level E plus an allocated 1 portion of the expenses ($) at Levels B-2, C, and D that is used to serve load at Level E. (Refer to Article VI) .
E'y:=' The 12-month annual expenses ($) at Level F plus an allocated portion of 'the expenses ($) at Levels' B-2, C, D, and E. that 'is a,ed to serve load at Level F. Dg
= The 5-day average estimated load at the generator (KW) .
adjusted for losses through substations having a distribution .; i voltage on the low side (Level E). Op =-
,The 5-day average estimated load at the generator (KW) adjusted for losses through the primary distribution facilities j (Level F). q S = The 5-day average estimated sales (KW) made to customers E
' served from substations with a distribution low-side voltage (Level E).
g . , , ,,o
- m. r- ,-.I ,_.e g .u f ., -+ g , ,# g e, p ,,. 7 ,9e gg g.
e ( ; M-51.
. 1 I
The source of the . load,- investment, and expense data ' incorporated in the above' l
. formulae for each of the companies (including FERC Account numbers and -]
description of allocation procedure and cal.culation of tha cost of. capital)-is y as set forth in the following sections. Section 7.2.1 Five-Day Average Load is computed based on the estimated peak ! y one-hour net territorial load (KW) at the generator. The estimated peak one-hour load is then adjusted to an estimated 5-day average load based on the preceding year's actual loads. The estimated 5-day average load at the l , generator is then adjusted to the estimated 5-day average load at Level F. I Section 7.2.2 Five-Day Average Sales are the estimated annual peak one-hour sales (KW) adjusted to a five-day average based on the preceding year's actual sales. Section 7.2.3 Gross Investmen't for Level B-2 is the summation of FERC Accounts 350, 354, 355, 356, 357, 358, and 359 associated with 115 KV and higher voltage lines plus-Accounts 350, 352, and 353 associated with transformation, metering, and switching between 115 KV and higher voltages. (Generator step-up substations ar'e excluded.) Gross investment for Level C is the summation of FERC Accounts 350, 352, 353, 360, 361, and 362 associated with transforming between transmission and sub-transmission voltages. The gross investment for Level D is the summation of FERC Accounts 350, 354, 355, 356, 357, 358, and 359 associated with sub-transmission 1.ines plus Accounts 350, 352, 353, 360, 361, and 362 associated with sub-transmission metering and switching substations. [.
~,,m v.c - x , .- r.: - x : - --, -
n -~.- ~ . ,
l s y, . . M-52. 7 The. gross-investment for Level E is the summation of FERC Accounts 350, 352, 353, 360, 361,:and 362 associated with transformation from transmission or sub-transmission to distribution. . The gross investment for Level F is the summation of FERC Ac^ counts 360, 364, 36E, 366, and 367 associated with
. distribution lines plus Accounts 350, 352, 353, 360, 361,-and 362 associated with metering and switching substation facilities.
~
Section 7.2.4 Accumulated Depreciation is that depreciation associated with the gross investment defined above and'is allocated to Account based on investment and' depreciation rates by Account. The allocation to level is based on gross ll : investment. l Section 7.2.5 Net Investment is the difference between Section 7.2.3-(Gross l:, Investment) and Section 7.2.4.(Accumulated Depreciation). i. Section 7.2.6 General Plant (Net) includes the investment in Accounts 389 through 399 excluding amounts directly assigned to production. The allocation of net general plant to function (excluding the direct assignments) is done on the basis of salaries and wages as developed in Section 7.2.19. N i After net general plant has been allocated to function, it is allocated to level of service based on the ratio of the net investment in the respective facilities to the total net investment considered herein. l Section 7.2.7 Workino Capital is the summation of cash working capital, prepay-fU 'ments, and materials and supplies. Cash working capital is one-eighth of the allocated operation and maintenance expense plus one-eighth of the allocated (
,, , +. 2 . u .s ei, ::&- a tr a ~
e _l
.]. C, .; ,
, M-53.
1; administrative and general expense associated with the facilities considered herein,' adjusted for working capital deposits as appropriate. prepayments are allocated on the basis of operation and maintenance expenses associated with.the h - facilities considered herein. Materials and supplies are allocated on the basis l', of gross investment less land. ( Section 7.2.8 Accumulated Deferred Income Tax is the net total of FERC Accounts 1190, 281, 282, and 283 which have been analyzed and allocated by each of the Companies in accordance with each Account's functional use. The portion related to general plant is allocated to function in accordance with the general plant assignments as described in Section 7.2.6. The allocation to level of service is on the basis of net investment less land. Section 7.2.9- Total Net Investment represents the direct and allocated investments that are associated with the facilities at Level B-2, C, D, E, and F and is. the sunnation of Section 7.2.5 (Net Investment)~ through Section 7.2.8 q
- (Accumulated Deferred Income Tax). These are shown as the values "I B-2" ' "I C '. i "I "' "I ", and "Ip ",respectively, in the formulae in Section 7.2.
D E Section 7.2.10 Ooeration and Maintenance Exoenses, FERC Accounts 560 through
.]
573 plus Accounts 580, 582, 583, 584, 588, 589, 590, 591, 592, 593, 594, and 598 I are allocated in relation to the net investment associated with the facilities at Levels B-2, C,' D, E, and F considered herein unless more detailed assignments can be made from each Company's existing records. l i l a i i __m_ . _ _ - - - . - - - -
L 2 M-54.. Section 7.2.11- Administrative and General Expenses FERC Accounts 920 through - 932, excluding 924', are allocated to function based on salaries and wages. The administrative and general expenses allocated to function are then allocated to levels of service on the basis of net investment. Account 924 is directly 1 assigned'to function by each of the Companies and allocated within function. based on net investment. 4
'Section 7.2.12 Depreciation Expense is net of Amortization of Investment Tax Credit (AITC). The depreciation expense is taken directly from the records of-each of the Companies. The depreciation expense associated with each level of
?' service is detennined on the basis of the gross investment in the respective facilities and the associated depreciation rates. The depreciation expense associated with general plant is allocated to function in accordance with the general plant allocations as described in Section 7.2.6. The general plant depreciation expense allocated to function is further allocated to each level of service on the basis of depreciation expense related to the respective facilities and the total investment considered herein. Section 7.2.13 Real and Personal Property Taxes are assigned.directly to function. These taxes are allocated to each level of service based on the ratio of the net investment in the respective facilities to the net investment , considered herein. The real and personal property taxes associated with general y plant are allocated to function on the basis of sclaries and wages and within
. function to each level of service on the basis of net investment.
E 1 i i l- w U_=_e au_ - ,_w.are _c_m:- =- = __ x- ~ r. -
< 13. - __-- -- _r
__z w ~ k . g - M-55. 4
- Section' 7.2.14 i Payroll' Taxes are provided from each Company's' records. The
{
; payroll taxes associated with the-administrative and general functions are allocated to function based on -salaries and wages. The payroll taxes plus the
-7 ' allocated A&G are further allocated to each level of service based on the~ ratio u
, of the net investment in the respective facilities to' the total net investment considered herein.
I b Section 7.2.15 Revenue Credits are assigned if the facilities for transmission service were responsible.for such revenues; however, if service revenues are not credited,,the estimated demands associated with the revenues will be added to the demand of each of the Companies. Section 7.2.16 Additional Income Taxes and Income Tax'Effect of'5% Basis Reduction.. Additional income taxes (ITg )'are due to the treatment of Allowance for Funds Used During Construction (AFUDC) and Amortization of Investment Tax
, Credits (AITC). Additional income taxes'and the income tax effect of 5% basis
- reduction (ITb);ars computed as described in Section 3.2.15.
Section 7.2.17 Total Expenses represent the direct and allocated fixed expenses associated with the facilities considered herein and are the summation of
= Section. 7.2.10 (Operation and Maintenance Expenses) through Section 7.2.16
. (Additional Income Taxes and Income Tax Effect of 5% Basis Reduction) and are the values "E B-2 " , "EC ", "E D", "E ", and "E " pin the formulae in Section 7.2.
E Section 7.2.18 -The Cost of Capital and Associated Income Taxes are computed as
~
described in Section 3.2.17. _1_. . _ . __.__[
#_. m___a__ .__ u 5._ _ _ . _ _ _ . - .d.' u_...bb __' f 5. ^ # I . ..
!,+
. M-56.
b i Se'ction 7.2.19 Salaries and Wages are budgeted by each of the Companies for , each functional group for the Contract Year. The budgeted salaries and wages account'for changes in wage rates and number of employees.
.The salaries and wages' associated.with the administrative classification are allocated to the. functional. groups based upon the ratio of the functional group's salaries and wages to the total salaries and wages less the administrative classification's salaries and wages.
The salaries and wages which . includes the allocated A&G are allocated to each ' level of service based on the ratio of the net investment in the respective facilities to the total net investment considered herein. i O f e ~ ~ .. _._. ,, , ,_ ,. ,, -. ,. _
v v c. M-57.
~
ARTICLE VIII DETERMINATION OF TRANSMISSION SERVICE REQUIREMENTS AND CHARGES This article of the Manual establishes the methodology for determination of the compensation due from the Government to each of the Companies for use of their facilities in delivering capacity and energy for the account of the Government to preference customers within their respective states and to adjacent states or adjacent Companies. Section 8.1 Specification of Goternment Generatine Capability by States ~. and Allocations by Customers: It is recognized that the capacity allocations made by the Government will not coincide with the generating capabilities of the Projects'in each geographical location. The generating capabilities of the Projects'1ocated in the States of Alabama and Georgia, and the allocations from the Projects shall be deemed, for the purpose of this Manual, to be as follows: TOTAL GENERATING CAPABILITIES February 1985 February 1985 June 1985(a) Through Through Through Territory - May 1985 May 1985 May 1994 (With zero (Witn One (Witn Two Russell Units) Russell Unit) Russell Units) Alabama (KW) George 150,000 150,000 150,000 Henry 78,000 78,000 78,000 Millers Ferry 78,000 78,000: 78,000 Total 306,000 306,000 306.000 Georgia (KW) Hartwell 214,000 220,000 220,000 Clarks Hill 159,000 - 159,000 159.000 l Buford 100,000 100,000 100,000 l-West Point 78,000 78,000 78,000 ' Carters 575,000 575,000 - 575,000
- h. Allatoona 75,000 75,000 75,000 Russell (Conv.) 0 65,000 172,000 Total 1,201,000 1,272,000 1,379,000 TOTAL 1,507,000 1,578,000 1,685,000
.. .. .. . .. . ,, -n . ~.
- ~
N+7.e w - M-58. s - Generating Capability Allocations t Feb.-1985 Through-May 1985 1985/86 1986/87 (KW) (KW) (KW) Pref.LCust. . 770,281 944,546 1,013,459 SouthernCompanies.(a)' 655,719 588,454 519.541 A. E..C. 91.000 91,000 -91,000
'SMEPA 61,000 .61,000 61,000
' Held in Reserve 0 0' 0
; . Total 1,578,000 1,685,000 1,685,000 1987/88 1988/91 1991/94 (KW) (KW) (KW)
Pref. Cust. -1,072,527 1,107,000 1.296,000 B: Southern Companies (a) 450,473 276,000 0 A. E. C. - -91,000 91,000 91,000 SMEPA- 61,000 61,000 61,000 Held in Reserve :10,000 150,000 237.000 Total 1,685,000 1,685,000' 1,585,000 (a) A delay in one or more of the first two conventional units at Russell' past .May,1985, will necessitate an adjustment to these. figures which will be made in accordance with Section 1.6 of the Contract. le Section 8.2 Determination of Total Transmission Service Charge for Each of the Companies: The transmission service charges for each of the Companies is derived .from the following fomulae: Alabama EA.G,F,M = CTRB + (C BB N + C RCC+CRDD+ EE+CN) N FF i Georgia Gulf-Mississippi i The total transmission service charge for each of the Companies shall be set d 3 forth on the Informational Schedule applicable to the contract year.- ) (NOTE: The terms C and R, and the subscripts B, C, D, E, and F are different for each of the Companies and produce different results in the fomulae. ) 1 !~ &__ __a_ _ _r
~
- - ._ -~ ~ = m~ --
r _ -
~
~
-- "i-
l ('y H-59.- Where: w_ _ a._. EA .Eg ,Ep,Eg= Monthly total transmission service charges ----- - --- --- --- of Alabama, Georgia, Gulf, and Mississippi, respectively ($) 1
- - C = Capacity delivered to adjacent companies or States T
on bulk transmission facilities (KW) g (Determined in.accordance with Section 8.4 hereof.) C B,C,0,E.F
= Capacity allocations delivered to preference.
customers in accordance with the Contract at service levels B-2, C D.' E, and F as such service levels are defined in Article II of the Manual (KW) R = M nthly rate (as determined in accordance with Articles-B.C.D.E.F III through VII herein for delivering capacity allocations to preference customers at service levels B-2, C, D, E, and F as such service levels are defined in Article II of the Manual ($/KW-MO.) Section 8.3 Effective June 1,1989, and continuing for the tenn of the contract, the Government will pay to each of the Companies for the use of their transmission facilities the monthly expenses determined in Section 8.2. I
._ *_ _____m_ _ _ _ _ _ _ _ _ __ _ . _ _ _ _ _ _ _ . _ _ _m_ - _-
O l .. . M-60.
- Section 8.4 Determination of Tran'smission Service Requirements For Deliveryg Capacity to Adjacent Companies or States
- The capacity allocated to Alabamt Electric. Cooperative, Inc., is deemed to be delivered from the George and Henry y projects located within the State of Alabama. The pumped storage capacity of Carters (276,000 KW) located within the State of Georgia is retained by the Companies through May 31, 1991. Except for such allocations to AEC and the g
Companies, all other alloc?ations are deemed to be supplied on a pro rata basis from the remaining generating capabilities of all Projects in the Government's Georgia-Alabaina System, and delivery is deemed to be in accordance with the following descriptions and tabular notations: The c: 7acity remaining in the Government's Georgia projects, after excluding the Cart 5 pumped storage capacity, the pro rata share of other capacity retained by the - ..panies or held in reserve by SEPA, and the allocation of capacity to
- preference customers within the State of Georgia, will be delivered to Gulf Power (providing the total preference customer requirements of Gulf Power) and to Alebama, Power. The capacity remaining in the Gcvernment's Alabama projects, after excluding the pro rata share of other capacity retained by the Companies or held',in reserve by the Government, and the Government's AEC allocation, is 1 delivered to preference customers by Alabama Power. The capacity remaining in i the Sovernment's Alabama projects provides a portion of the preference customers' requirements delivered by Alabama Power, and the remaining requirements are provided from part of the capacity delivered to Alabama Power {
from Georgia Power. The remaining capacity delivered from Georgia Power is in 1 turn delivered to Mississippi Power to provide the capacity allocated to i preference customers within Mississippi Power, and to deliver the capacity allocated to SMEPA. These movements of capacity are shown in the following table: i l
~
p ,z. I' M-61. Feb. 1985 JuneL1985 June 1986 Through Through Through Location May 1985 May 1986 May 1987 sKW) J, KW ) (KW)
- Georgia
- 1. Generating Capabilities 1,272,000 1,379,000 1,379,000 S 2. Less Pumped Storage (276,000) (276,000) (276,000)
- 3. Net -996,000 1,103,000 1,103,000
- 4. Retained by Southern Companies (290,476) (244,597) (190,650)
- 5. Net Capabilities 705,524 858,403 912,350
'6. Preference Customers 575,573 707.623 759,069
- 7. Delivered'to Gulf 4,628 5,838 6,246
- 8. Delivered to Alabama 125,323 144,942 147,035 Alabama g 9. Generating Capabilities 306,000 306,000 306.000
- 10. . Retained by Southern C'mpanies (89,243) (67,857) (52,891)
- 11. AEC Allocati.;n (91,000) (91,000) (91,000)
. 12. Net Capabilities 125,757 147,143 162.109
- 13. Preference Customers 154,008 185,106 199,011
- 14. Deficiency ia Alabama (28,251) (37,963) (36,902)
- 15. - Received fror Georgia 125,323 144,942 147,035
- 16. Deficiency in Alabama (28,251) (37,963) (36,902) 17.. Delivered to Mississippi 97,072 106,979 110,133 Gulf
- 18. Received from Georgia 4,628 5,838 6.246 -
- 19. Preference Customers 4,628 5,838 6.246 Mississippi
- 20. Received from Alabama 97,072 106,979 110,133
- 21. Preference Customers 36,072 45,979 49,133
- 22. Delivered to SMEPA 61,000 61,000 61,000 i The values shown on Lines 7, 8, 17, and 22 in the above Table represents the capacity delivered to adjacent companies or States (the tenn CT in Section 8 2 .
hereof). s 6
..h.,'
y .. M-62. n June 1987 June'1988 June 1991
.- Through .Through . Through Location May 1988 May 1991 May 1994 (KW) (KW) ,
,KW) .
Georgia
- 1. Generating Capabilities 1,379,000 1,379,000 1,379,000 h 2. Less Pumped Storage (276,000) (276,000) 0
- 3. Net 1,103,000 '1,103,000 1,379,000
- 4. -Retained.by Southern Companies (136.582) 0 0
- 5. . Held by SEPA (7,828) (117,424) (193,960)
W
- 6. . Net Capabilities 958,590 985,576 1,185,040
- 7. Preference Customers 803,166 831,094 970,000
- 8. Delivered to Gulf 6,595 6,816 8,000
- 9. Delivered to Alabama 148,829 147,666 207,040' p - Alabams' i 10. Generating Capabilities 306,000 306,000 306.000 11.. Retained.by.
Southern Companies (37,891)' O O
- 12. Held by SEPA (.2,172) (32,576) (43,040)
~
- 13. AEC Allocation (b) f91,000) f91,000) (91,000)=
- 14. . Net Capabilities h74,937 h82,424 171,950 L 15. Preference Customers 210,929 215,541 256,000 L 16. Deficiency in Alabama (35,992) (33,117) (84,040) 1
- 17. Received from Georgia 148,828 147,666 207,040
- 18. Deficiency in Alabama (35,992) (33,117) (84,040)
- 19. . Delivered to Mississippi (b) 112,837 114,549
'123,000 Gulf
. 20. Received from Georgia 6,595 6,816 8,000
- 21. . Preference Customers 'Gi9T 6,816 TOTI6 Mississippi
- 22. Received from Alabama 112,837 114,549 123,000
- 23. Preference Customers 51,837 53,549 62,000
- 24. Delivered to SMEPA (b) 61,000 61,000 61,000 (b) If the Government. arranges for the capacity allocated to SMEPA to be
~ delivered through AEC after May 31, 1989, the above descriptions of transmission deliveries and use will be revised appropriately to reflect such arrangement.
? The values shown on Lines 8, 9,19, and 24 in the above Table represents the capacity delivered to adjacent companies or States (the term C7 in Section B.2 hereof).
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'. August 8,1989: Supplemented Response of Georgia Power Company Volume III
- 17 . - The August 30, 1985 request' to facilitate a delivery.
to Seminole required a. complex operation of a jointly-owned plant out'of: economic; dispatch. 'As shown by . the original. request . and contract with F - Seminole, no winter .of 1986 deliveries. were contemplated at the. time.
- 18. . The November 26, 1985 internal mesorandum shows that substantial. negotiations were ongoing =and that' Oglethorpe= understood Georgia Power's position L concerning the license conditions and the Integrated -
Transmission, system lat that time.
- 19. The December 2,1985, internal memorandum shows how Georgia Power facilitated the : leverage lease refinancing ~of' Plant Scherer by making an offer to negotiate transmission that is not required by the
.-license ' conditions . At this time Georgia Power also made' Oglethorpe aware again of' Georgia ?ower's position on off-system transactions.
'20. On December 18, 1985, Georgia Power made Oglethorpe aware of ' the existing Georgia / Florida interface priorities.. ' Oglethorpe has never sought relief ' from '
these pursuant to the Federal Power Act and ~ has. never indicated how they could be improper under any legal or utility operating standard.
- 21. ~ At page 13 of Oglethorpe's May 20, 1985 submission Lin support of Georgia Power's contract with SEPA, Oglethorpe (and- its fellow committee members)-
informed the FERC that "the contracts, entered into after lengthy negotiations,. represent a satisfactory compromise of competing interests."
- 22. Oglethorpe's October 2,1985 Statement of Objectives shows that it recognizes that its off-system transection desires are part of the context of negotiating a broad new Georgia Territorial Power Supply Agreement..
- 23. The December 13, 1985 draft of the Georgia Power Supply Agreement Scope Working Group Review of Issues shows that Oglethorpe's representatives (including the chairman of the committee) agreed that a-commitment from the PR customers as to load and capacity responsibilities was critical to progress on the other issues, including off-system sales.
e
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- 24. The final January 31, 1985 Georgia Power Supply -
[: Study Scope Working- Group Review of Issues, k recognizes, at page one, the critical need for a coannitment from Oglethorpe with regard to load and capacity responsibilities.
- 25. The March 31,. 1986 transmittal- of the AEC e Interconnection Agreement by'Oglethorpe shows that
"~ Oglethorpe affirmatively was not seekina to activate the interconnection, but was intending to " help provide some structure and guidance for the development and implementation of ... " what Oglethorpe calls "the Generic Scheduling Service Agreement."
- 26. Mr. Taylor's August 4, 1966 letter to Mr. Smith shows that multiple layers of agreement were needed, including the establishment of "the contractual and procedural mechanisms to enable Oglethorpe to transact a full rance of off-system sales and purchases, including transmission service."
(emphasis added). Oglethorpe did not suggest that this effort should precede the critical issue of it making. a commitment as to its power supply responsibilities. Oglethorpe alm recognizes that new contracts would be needed,- contrary to the positions it has taken later. Also, and incidentally, this is the first reference by _ Oglethorpe to it brokering transmission capability, which is not provided for by the license conditions or any existing agreement or tariff.
- 27. The March 21, 1986 Florida Power Corporation letter to Seminole indicates that Oglethorpe in fact suffered no delay.in implementing this arrangement due to Georgia Power.
- 28. The April 3.0, 1986, Scheduling Services Agreement to facilitate the sale from Plant Scherer shows Georgia Power's cooperation in backing up the sale and also that Oglethorpe was aware of the limitations on its rights under existing agreements. j
- 29. The October 10, 1986, four party Memorandum of Understanding enabled Oglethorpe to-make its desired sale to Seminole. Georgia Power helped Oglethorpe overcome co-owner objections to this transaction.
- 30. The October 15, 1986 letter to Mr. Taylor shows Georgia Power's responsiveness to Oglethorpe's inquiries concerning its sale to Seminole.
hamlAA _ _ _ _ m__ _. .:...m__._ _ _ _ . _ _ _ _ _ _ _.A. _.w. .
y l
- 30. . In November of 1986, Georgia Power contunicated to Oglethorpe.its-interpretation of the role of self-
- c. sufficiency and transmission of power off-system as e', .its reason-for refusing.to sign-an agreaw nt with Oglethorpe , to terminate . Oglethorpe's intervention in the Schedule EP proceeding at ? FERC. Also, Oglethorpe. was specifically informed that ~ Georgia Power did not' agree with the final paragraph of 'its 7 - " offer."
- 31. . The July,9~, 1987[ letter-'to W. .J. Smith shows.how
. Oglethorpe has evaded FERC = jurisdiction over ' the issues raised by its." generic
- scheduling agreement
' demands. Oglethorpe recognizes .on the hat ' page - , that these issues aro' appropriately :within the-jurisdiction.of FERC.
- 32. Mr. Smith's' letter.of-January 13, 1987 refutes the allegations of delay made by Oglethorpe.
m . 33. Mr. David Springs. of Southern Engineering,. which is
- Oglethorpe's engineering firm and has no affiliation with. Georgia Powar or' The Southern Company, conducted an assessment of the Georgia Power Supply Methodology and reported in December of 1987.- This report rebuts Oglethorpe's assertions of bad faith tactics. It also shows in Exhibit A that Oglethorpe .
recognizedLthe need to commit to nelf-sufficiency. g .. 1
" + M m_u.om_:.1_.M___a__ 1 _w.'A A . ..u_.._4
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w a. c Oglethorpe Power Corporation . .o
~ =
1J j 2!00 East Exch.ne i"2 PD tu :. heker. Georma .k ee k _ Nov ;,, .... ( August 20, 1985 ly y
- y j Mr. Fred D. Williams j Bulk Power Markets j Georgia Power Company
~
Post Office Box 4545 Atlanta, Georgia 30302 k
Dear Fred:
j
Subject:
Arrangements for Transaction with Seminole Electric Cooperative In accordance with our discussion, please make the necessary arrangements-for Oglethorpe to deliver up to 200 MW to Seminole Electric Cooperative, such transaction having the following terms: ,
- 1. Delivery will be made to Florida Power Corporation.
- 2. Capacity will be specifically reserved on a daily basis i with reservation made by 3:00 p.m. of the day preceding.
- 3. At the time of reservation an hourly schedule will be specified subject to modification during the day as required.
- 4. Delivery should be made from the lowest cost Oglethorpe units available fo'r additional dispatch at the time of delivery.
- 5. The Florida utilities will determine which transactions l should be scheduled during hours when the approved transfer J capability is less than the total desired transfer.
Schedules for this transaction may be arranged to fill f the valleys around the limits. - 6. If GPC prefers to schedule the energy from a non-Oglethorpe plant that has a lower incremental cost then we will be happy to consider arrangements to accommodate that.
- 7. It is presently anticipated that this specific transaction will be utilized from now through the end of September.
my 3.,
. .cc -l - -
.s - .
J-I AUG2' 3 9-An Electric Membership Cooperative www ; i i -m=_ . . _ _ _ _ __ _ _ _ _ _ _ _ . - - _. m_ m___ _ _ __ _ _ _ _]
4 F Mr. Fred D. Williams Page' 2 August 20, 1985
- 8. It is anticipated that the Seminole oporators will' deal with Florida Power' Corporation who will deal with the.
g Southern Company for actual. scheduling purposes. Seminole will deal.directly with Oglethorpe concerning most cost information.
- 9. Records'of the transactions should be maintained by GPC (or its agent) and provided to Oglethorpe at the end of each month.
Due to tho'short-term nature.of.this' transaction and our need to ! implement it as soon as possible, certain procedures may be established that Oglethorpe may wish to modify for future transactions. Thank you for giving your prompt attention to this project as time it of the essence in initiating this transaction. If you have any questions,concerning the details of this particular transaction, e please contact George Taylor-or. John Johnson. Sincerely yours, G. Stanley Hill Division Manager
~
Engineering sjw xc: George Taylor John Johnson e
+
4 N-- --A-_.-_ _ _ . _ _ _._ . _ _ _ _ _ _ _ . , _ _ _ _ _ _ _ _ _
A
+ .
A REEMINT TO RO C E ENEDGY . TO 5EMih0.E ELECTRIC C00FERATIVE. INC._ OGLETHOGE P0btER CORDOPT ION Bs day cf
~
(AGREEMENT) .is, r.ade and entered into this _ This ' Agreement
) and November,1985, by' and - between Seminole Electric Ceeperative Oglethorpe Power Corporation (OPC), collectively "the parties assured economy ener;Lv.
ARTICLE I TERM OF AGREEMENT _ ~ 5ection 1.1 This. AGREEMENT shall become effectNe at 12:01 A.M 31, 1985. _ , 1985, shall continue in effect through Oc: ember
* ==
ARTICLE IIs.,. - SCHEDULED EMERBY__ Section 2.I_ Beginning with the date of this AGREEMENT and each during its term, SECf or its agent shall notify OPC orfits hourly agent by te no later than 9:00 A.M. C.P.T. (Central Prevailing Time) of, the st. cunt o energy (Scheduled Energy) SECI anticipates needing. pursuant to OFC or its agent will confim by
' the following calendar day (Scheduling Day).
F.M. C.?.T. the schedule of Energy to be deli-telepnene. by r.o later than Such Scheduled Energy may be modifie: vered for the following Scheduling Day. ;
,a. ,
- by mutual essentpfgbe:PEtief.AMhair .- ager.jsy,.
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. ^^ _ _ - - * - - . - _ , _ _ _ _ _ _
g .( i .,' ART *CLE III ENERGY CHREES S Section 3.1 SECI shali pay OPC en Energy Charge for each Wh of Schaculed
. Energy. This charge will be detemined by the parties as the average of OPC's incremental cost and SECI's decremental cost during the transaction period. OPC c
shall be solely responsibl e for detemining its in:renental cost and SECI shall
'be solely respcnsibie for determining its de:remental c:st. , It is the intent of the' parties'tht;t the transaction price so detemined and ' agreed to will represent an equal sharing of the savings and will be of mutual benefit.
n ARTICLE IV UNANTICIPATED OCCURRENCES Se: tion 4.T In the event. that OPC' experiences an. unanticipated oc:urrence, including but not limited to, the less of a generating unit, cancellation of a purchase, or outage of a transmission facility that would result'in the cost of providing the Scheduied Energy to be greater than that projected, then OPC or its
' agent. shall.irrnediately provide an estimate of the' ccsts to centinue to. provide Scheduled Energy to SECI.
J Section 4.2 In the event tna GPC anticipa:es a ceak cesand that w:uid in:rease its costs under its Integrated Transmission System Igreement, OPC shall ime-
}
'N' diately 'prdvide an estimate of the costs to ,co,nti6ue to
.- provide Scheduled Energy SECI ennavcid, su:h_ additienal- costs by i;:rnediately cancelling the to' SECI.
energy s:hedule pursuant to Section 4.2.
~
)
Se:tien 4.3 In :ne even: tha- 0:~ experier.:es an unanti:irated c curren:e as j des:ribed in Ee::i:r 1.1 er 4.2, SECI er CPC has ce,. rich: t: :ar.:ei Scheduied !
. Energy at' any time during the una ,:i:ipated c::grreri:e :y r. -i*ying the c ner party cr its agent.
m_ amu ._. . _ _ _m. .____.m.. . . _ . , __. __ . _ _ _ _ _ _ _ . _ - - _ . _ '_.____m. __ ___ _ _ _ _ _ . _ -__________.m____._ _______.___.m. __mmm____m_U
4 ART!;LE V p BILLING AND PAYMENT k Section 6.1_ OPC shall submit to SECI, as promptly as practicable after the first
- of each month, a billing statement and bill for the energy delivered to SECI
-under. the terms of this AGREEMENT for the preceding' calendar month. All bills shall be due and payab~a within fifteen (15) days .from the date -of mailing (as
' determined by the postmark), or date received if bill is hand delivered. Date of
. payment shall be date of postmark of payment.
- n s
Section 5.2 In case any portion of any bill is in bonafide dispute, the undis-puted' amount shall be payable when due. Uper, determination, of. the correct
/
amount, the remainder, if any,- shall be:ome due and payable.in accordance with 1
~J 15:ction 5.1.
i ARTICLE VI
- 3 GENERAL OPERATING PROVISIONS I
.Se:tien 6.1 For':ne term f this AGREEMENT, the parties agree to Operate their respective systems using corrnon standards.fer goe:i utility pra:: ice.
Se::icn 6.2 Ary no ite, cemand, bill or racues. required er cu:horized by this
' AGREEMENT shall be deemed properly given if mailed p; stage pr paid, to DGLETHORFE d
Tucker, Georgia,- --
... POWER. CORf RATID,,
N 2100 East Exchange Place, P.O. . - Box -W - . 300E5-1349, in thege cf 0FC; and to SEMINOLE ELECTRIC C00 NATIVE, INC., P.O. Box 272000, Tar:a, FL 235E5 2000, in the case cf SECI cr to .15 c:her person as 4
)
nay be designated by Op; by EECI. The designati:n of the person ;o be noti- ! find or tne ediress cf su:... :ersen may be changed by 0?O or 5: Ci at any time, or
-fre time to time by simil!.s notice.
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- 33. : .,g y .-: . .
I, ... . . .. 3 . ,:. .,.. ,....;- (- IN i'ITNESS WHEREDF,. the parties nye chused this' 4ree:nent to be executed by - their duly authorized officers, and copies deMyered- to each party,' as of the 1- date and year.first above stated. SEMINOLE ECTRIC COOPERATIVE, INC. r .' ATTEST:
-By:
M# 5r:retary
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By: , , vice Presioent a Genere4 Manager i no lQaf. s ( . r ATTEST: OGLETHORPE POWER CORPORATION
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'![M 5enerrJ ManagerW
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c g ' Novenber 26,'1985 y li? Frems :' W. J. Smith To: .E F.' D. Willians. fRe: ~ Draft Agreement with OPC (Seninole)- During the past several weeks, discussions,: negotiations 0 t. .
.and' drafts.of a Scheduling Services Agreement (SSA) and a .
4 Memorandtsa 'of Understanding (10). have passed between Georgia
< . Power and Oglethorpe Powere addressing the.OPC-GPC relationship; in'OPC's proposed transaction;with seminole. 'At this point,'the
, < ? latest drafts,' dated Novenber 7,1985, and _ November 6,1985, ,
;re4 ctively, are' approaching mutually agreed upon final verbage.-.
- w. '
However,Las the two. parties approach finalLagreement regarding , these doctanents, a few points of disagreement' exist. 'In-Laddition,.OPC may wish'to add same new language to clarify fperceived. issues.L The following sunnarizes the existing situation. LIn the.SSA, Article II - Scheduling, Paragraph 2.1 (a), addresses Unit Energy,; limiting the amount of' energy available for scheduling tol230 Miel per' hour.L This: limitation represents-E 'the sum of the: truncated values of OPC's retained capacity categorized as' reserve (Scherer i - 132.655 MW and Scherer,2 - 98.676 MW). ' OPC wants to stan these retained capacity values and
-then truncate. 'Since OPC has been Jranted'the right to schedule 7
energy equivalent.to the reserve tetention in each unit,Eand e since.these schedules are' established in terms of whole MWs, they. 1 may schedule 132 MW plus 98 MW for a total of 230 MW. Although 3f .we have given OPC tho'right to schedule the equivalent of two-1
- units of capacity, fran a single unit, even if .the second_ unit is not operational,.this added right does not have the associated privilege of scheduling more than 230 MW. Our position parallels -
the situation of both units operating and the maximum capacity available for OPC's scheduling is 132 MW plus 98 MW or 230 MW. Although this-1 MW is trivial and will probably not be a factor in this application, precedence for future agreements may be set. :j w 3
- iC ,
h ( h ..
F. D. Williams Draft Agreement with OPC/ Seminole November 26, 1985 % Page 2 . In the SSA,' Article V - Administration, Paragraph 5.5 and MU, Paragraph 7, the existing language addresses " deliveries of energy to FPC...as though made by OPC on the ITS...". This language is a recognition that the OPC energy is economically S dispatched frun the system, not specially dispatched frm Scherer. Accounting-wise, the energy is treated as though it were dispatched from Scherer. OPC wishes to strike the language "as though". OPC has suggested additional changes that do not appear to
- be controversial; however, they have not been reviewed by counsel. They also want to add language in several locations to clarify their positions. However, we have not as yet seen these prrt - d new passages. In the SSA, OPC wishes to add audit priviledge language to Paragraph 4.5 - Billing and Payment. They have also suggested a similar addition to Paragraph 4.6 - Initial Costs. This latter change could probably be avoided by negotiating an implementation fee, and thus avoiding further discussion and auditing of programming, legal and labor fees.
As indicated in Paragraph 2.lC - Unit Energy - GPC plans 7 to schedule all of the desimd energy or none. In other words,
- y mnditions do not oermit scheduling of the total desired MW level . than no delivertes will be scheduled. UN nas not asn-d "to a "no partials" arrangement.
In the MU, Paragraph 7 states that, "The Parties acknowledge GPC's contention that the ITS Agreement does not authorize OPC to make such deliveries." OPC has indicated new language may be offered for this clause to soften the context. OPC has requested examples of UPS Base Energy Rate calculations (see MU, Paragraph 2.B) and a numeric justification of the scheduling limit set at 350 MW net output for each Scherer Unit (see SSA, Paragraph 2.lC). Both itms will be prepared. One final point, OPC has indicated a three month extension may be requested for termination of the contract. However, up to this point, there has been no official request of this nature. t. RTS/JG xc: R. H. Forry I. B. Ballard F. T. Paradise x- -_ - _ - - - _ - _ - . _ . _ _ _ - - _ - _ _ _ _
y { L
.Moeting with oglethorpe Power Corporation 12/02/85 l
Attendees: Georgia Power Canpany Mr. H. G. Baker, Jr. Mr. W. Y.'Jobe Mri W. L'. Westbrook 6> Mr. F. D. Williams U, - Oglethorpe Power Corp. Mr. Eugen Heckl Mr. Tom Smith
- 1. At any time OPC defaults under the lease agreement on Unit 2 at Scherer, GPC, has the right to step . in OPC's . place h;., with all rights and options OPC has. . (Applies to fixed price leases OPC may exercise after. first term of 27 1/2
, years.)
- 2. Assuning GPC does not excercise any of its rights and the lessors take possession, GPC agrees to discuss transmission access to lessors.
- 3. GPC agrees to continue pricing of buy-backs as if OPC had been the owner (split cost).
r. 4.s GPC accepts number of operators (equity owners) up to d eight.
- 5. Confidentiality of blue prints and Operating manuals - GPC does not consider this a problem after lessor possession date (27 1/2 years).
- 6. Extension of operating agreement - GPC does not consider this a problem, just a matter of price for doing it (operating charges)..
h. I4 e h 9
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vL - 333 e<cemor: Acase . 4 Mar.ta Geor;a 30308 " ?. l - f' Te.conone 404125-6326 . '
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- g. r* scurve" ew. c svsre +
sunk Powe, merk.ung , December 18, 198E Mr. G. Stan Hill
, Oglethorpe Power Corporation L 2100 E. Excht t Place P. O. Box 134' 30085-1349 Tucker, Geor.
Dear Stan:
v As you requested, copy of the agreement specifying remedial. operating procadures for the Southern / Florida interface is attached. It is our intention to view the proposed transactions between Oglethorpe Power and Seminole
'Ilectric in same perspective as assured economy transactions.
Should you have any questions or require additional information, please advise. sincerely, , r, - p 4
~ William J.ismith WJS/aa Attachment
/ '
cc: r. D. Williams / G. B. Taylor 9
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March 5,1985 a
- f. ; /
. Florida Power Corporation - J. H. Blanchard -
Jacksonville Electric Authority - R. A. Basford
.. City of Tallahassee - P. N. Koikos Re: Operating Procedures for Southem/ Florida Import Attached is a copy of this agreement with all of the necessary signatures affixed.
Sincerely,-
~
W. E. Coe Director- Power Supply WEC: pas Attachment cc: J. E. Scalf R. R Taylor , ~ 9 l W b e m m__m___-__m.-____1m_ _ _ _ _ ___________.____m____ma. _ __ _ _ _._ _ _^m_ ..A ____...e, - QA.m .-h9 - f m.
y o p . OPERATDiG PROCEDURES FOR SOUTHERN / FLORIDA IMPORT
- k I. Whers a Etuatiorr occury ore either the Florida Systent or the Southerrt
' Systent which results in a reduction of the State import Limit to e level below the cumulative import schedules, the scheduled amounts of Southern's Discretionary Energy shall be reduced first4 " hourly economy'*
transactions shall be reducednext, irr the order of those blocks providing the least savings being reduced first,. to be fonowed by reductions irt.
" assured economy" irr the same manner, until the import level is reducet to the 1985 contracted capacity of 2900 MW. !
l I' 0 Wherr a situatiorr occurr. ort the Southerrr Eystent whictr requirer a reductiert ofimports below the 2900 megawattlevelandthe.importreductions. identified irt. Paragraph 1 above have been made, the Southerrr Coordinator will reduce the schedule of imports, orr a prt* rate basis of the Schedule !
"E" contracted capacity, until an acceptable limit ir met or the reductiore
. equals the sum of the Schedule"E" contracted capacities.
1985 Schedule"E'" 4 UtDity Allocation % Contracted Capacity l
. FPL. 34
- 300MM
.JEA 34% - 300K W -
l FPC'- 21 % . 200 MW - TAL 9% 75MW '
- -" 100 % &75MW '
.r: ..
. If further reductions are required, the schedule of imports will be revised so that the remaining availableimports are allocated on a pro-rate basis-of UPS contracted capacity. )
1985 UPS . Utilitu ,, Allocatiou % Contracted Capacitw EPL 85 % 1722M W JEh 15% 303MW 100 % 2025MW N
;, lh the event that one utility's sch dele prior to such reduction is less than its allocated share, the unused capacity will be applied toward the import reduction until the ut'Uty schedulingless than its allocated share increases its schecule.
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- 7. Where imports are required to be reduced below the 2906 megawatt level, as a result of outage of facilities identified to a Florida 6 system party of this agreement and the import reductions identified in Paragraptr 1 above have beerr made,. that party (s) identified as the cause of the f . reduction wiE be responsible for additional required import reductions ugita ltacontracted capacity. If one or more utilities schedule (s) prior to sucte reductioer is less thart its allocated share,. the unused capacity wiC .le applied toward the import reductiorr until the utility scheduling l
1ess thart its allocated share increases its schedule. If further reductions are required the schedule of imports will be revised so that the remaining available imports are allocated. to the other parties ort a pro-rate basis of their 1995, corrtracted capacities. The following examples illustrate this procedure if an import limit reductions is required as e result of the outageof theidentifiable facilitiest. A). Outareof Suwannee-Pine Grove 23s Kv line- Floride Power Corpora.- trorr will take the impore recuctiorr up. to, 200. MW,. or the amount ofitsschedule prior to this reductiorr,. whicheverisless. If further reductions are required;. the schedule of imports wi1L be revised se that the remaining available imports are allocated orr - the followingpercentages. - 1985 Contractedt Ut!!!tw ADocation % Canecity . PPL 75 % 2022MW JEA 22 % 603MW TAL 3% 75ME
~ .r 100 % . . . 2700MW
'~
B) Outaneof Bookine-E h8ahridae232 EVline-Tallahassee willtake tneimport recuctiorr up to 75 MW, or the amount of its schedule prior to this reductiorr,. whichever isless. If furtherreductions are required the scheduleofimports wi1Lbe further revised so thac the remaining available imports are allocated. crr the following percentages. 1985 Contracted .
~~.' ~
UtDitw _ Alloestfore Canecitw
- . PPL 72 % 2022' MW JEA 01 % 603 MW
. FPC 7?' 200 MW IM% 2825 MW
, 9 4
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i ( , l C) W==e of either Duval-Hatetr 50. KV Une- FPL and JEA will share !- equauy any import capacity aoove the surn of:. N EPCs schedule,up to 200 MW. l - TAL's schedule,up to,75 KW. The first 208 MW of FPL's schedule. o>or any coro mioewe svu o-.r-e.i ett see avu.e l' transmission une mternal to EPL's system wruen unpacts the State Import Limit - EFL wilt take any required import reductiorn
~ to theimport umit. 1
- 4. If the outage of other facilitiesor a combination of facilities of the Southerre .
Systant and/or Florida Systent results irr the reductiorr of the State Import H Limit andthe situatiore causing; the reductiore cannot be identified witty
= specific utility, and. the import reductions: Identified irr Paragraptr I have beerr made, further reduction will. be allocated; orr a pec> rate basis ,
of total 1985 contracteccapacities. TotallSSEContractedt UtDitw ADoestions% ,,, c-dtv E+ UPS + TotaI
~
FPL 70 % 303 + 1722 = 2022 JEA 21 % 300.- 303 = 602 FPC'- 7% 200;+ 0 = 200s ' l* TAL. :. 2* . ' 75 + 0 =~ 75
~
,~
100 % 875'* 2025 = 290s Wherr at determinatiorr can be,made of the situation causing the reductierr,.
~
the provisions of Paragraph 2 or Paragraph I will apply, as applicable. L Wherr Florida utiHties are required te reduce import schedules due t& a reductiorr of the;*tateImport Limit for any reasorr, each Florida utiHty shall have the optiorr of Identifying the specific type (r) of service te-be reduced subject to the UPS' Minimum Scheduung Requirements which may be applicable irt the care of FPL and JEA , N O e P 4 e e & - Km _-- u. wa,- ---,---m---._----__a.--__.a.-_-, _..--^n,- -- u - f -.-a.
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- 6. The above procedures shall remain in'efrect until circumstances require
' i; a modificatforr. N -
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Florica Power e Lignt Company Date L' ( Florica PowErrorporatiort k $ f5
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................ May 20, 1985
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_BY HAND Hon. Kenneth F.' Plumb. Secretary-Federal. Energy Regulatory Commission D Room 3110 825 North; Capitol Street, N.E. Washington, D.C. 20426 Re: Georgia Power Company j Docket No.~ER85-393-000 Dear Mr Plumb Enclosed for filing in'the above-captioned docket are-an' original and 14 copies of the Answer of Southeastern Power
. Resources Committee to motions of Electricities for Leave to Intervene Out of Time and Conditional Motion for Leave to Inter-vene Out of Time.
If you have any questions concerning this filing, please call the undersigned at (202) 457-9424. Sincerely,
- l. A brwtu N. Beth Emery for pat lL, HASTINGS, JANOTS & WALKER Enclosures cc Service List,
t r : ,: UNITED' STATES OF- AMERICA Before the 7
. FEDERAL ENERGY REGULATORY COMMISSION
- GEORGIA POWER COMPANY
\ Docket Nos. ER85-393-000
'ER85-339-000 t ' MISSISSIPPI POWER COMPANY ER85-312-000 Ei ' ALABAMA POWER COMPANY ER85-327-000 GULF POWER COMPANY' )
(Unconsolidated) ANSWER OF THE SOUTHEASTERN POWER k ' RESOURCES COMMITTEE IN - OPPOSITION TO MOTIONS OF ELECTRICITIES FOR LEAVE TO IKTERVENE OUT OF TIME AND CONDITIONAL MOTION FOR LEAVE TO INTERVENE OUT OF TIME sv Pursuant to Rule 213 of the Commission's Rules of Practice and Procedure d/ r The Southeastern Power Resources Committee (the " Committee"), on behalf of five of its generation and -transmission cooperative members, hereby answers the motions of Electricities of North Carolina, Inc.) virginia. Municipal Electric Authority No. 1; and the Cities of Bennettsville and Camden,-South Carolina for leave to (hereinaf ter collectively "Electricities") intervene out of time in and to hold in abeyance the proceedings set forth in the above-captioned dockets. Pursuant to Rules 212 and 214 of the Commission's Rules,.2/ the Committee hereby moves for leave to intervene out of ; time in the a*sove-captioned dockets, such request to be 1/
~~
(Hereinafter the " Commission's Rules"), 18 C.F.R.
$ 385.213 (1984).
j!/ 18 C.F.R. SS 385.212, 385.214. j 1 _ 3 1 _ 1._ _. _ _ _ _
, _ _ _ _ _ _ _ . _ . . _ _ _ _ _ _ . _ . ._______.___________________._____J
c J
=!
i 1 a ~ condi_tioned,upon the grant of intervenor status to any other 1 party so requesting out'of time.3/ In support of these i 3 motions,..the Committee respectfully states the following: y A \. I. Service of Pleadings The Committee is an unincorporated association with' ^ its current headquarters at 2100 E. Exchange Place, P.O. Box 1349, Tucker, Georgia. Six of its members are rural elec-who tric generation and transmission cooperatives ("G&Ts") 1 are either direct customers of the Southeastern Power Admin-istration ("SEPA"), ' a federal power marketing authority within the Department of Energy (" DOE"), Or unoi:e rural
~
electric distribution cooperative member / owners are customers of SEPA..$/ J 3/ By motion filed May 13,-1985 (to which answers may be Tiled up through May 28, 1985), the City of Greenwood, Mississipi has a.lso asked to intervene in the above-captioned dockets. The Committee also understands that other parties may move for leave to intervene out of time in conjunction with filing' answers to Electricities' motions.
~
4/ ' The six G&T members of the Committee are North Carolina
~~
Electric Membership Corporation ("NCEMC"), Raleigh, o North Carolina; Old Dominion Electric C,ooperative ("Old Dominion"), Richmond, Virginia; Central Electric Power Cooperative,'Inc. (" Central"), Columbia, South Carolina; Oglethorpe Power Corporation ("Oglethorpe") , Tucker, Georgia; Alabama Electric Cooperative, Inc. (" AEC " ) , Andalusia, Alabama; and South Mississippi Electric Power For l' Association' ("SMEPA"), Hattiesburg, the Mississippi. Committee is acting on purposes of this proceedings, g" behalf of NCEMC, Old Dominion, Oglethorpe, SMEPA and AEC. Centralhaschosennottopartfcipate. _j_
Communications and correspondence concerning these-L motions should be addressed to: F. F. Stacy Chairman. Southeastern Power Resources Committee c/o Oglethorpe Power' Corporation P.O. Box 1349 Tucker, Georgia 30085-1349 with a copy to: ii. Beth Emery, Esq. Paul, Hastings, Janofsky & Walker Twelfth. Floor 1050 Connecticut Avenue, N.W. s Washington, D.C. 20036 II. Opposition to Electricities' Motions to Intervene on May 3, 1985, Electricities filed four virtually identical pleadings seeking to intervene out of time in each of the above-captioned dockets. Electricities should be denied intervention in each of the dockets because (1) they
- do not have an interest which may be directly affected by the outcome of the proceeding; (2) they have failed to {
demonstrate good cause for failing to file their motions within the time prescribed; and (3) their intervention will disrupt the proceedings, prejudice the other parties and 1 place unreasonable burdens on the parties. l l l _ _ . - . . _n..-. h _-
r -
.A. Electricities Will Not be L Directly Affected-by.the _ . .
Outcome of the Four Proceedings Because Electricities are not' entitled to partici-f pate pursuant.to law or Coreission rule, they must demon-strate that they have an interest which may be "directly affected by the. outcome of the proceeding' or that their
'iintervention is.otherwise "in the public interest. 5/
Electricities have failed to demonstrate how approval of the transmission arrangements at issue in the four dockets may directly affect them. These dockets involve jurisdictional wheeling services necessary to implement SEPA's marketing plan for the western division of its Georgia-Alabama system of s, projects. This plan was adopted by SEPA in 1980 and is The attached to each of Electricities motions as Exhibit A. plan establishes two marketing areas, with the Savannah River as the dividing line, and allocates power to each area. The plan does not allow allocations of power to be shifted from the eastern area to the western area, or vice l Versa. ElectriCities' complaint is that the SEPA alloca-tions upon which the instant transmission services are based are illegal. Even if this were true, Electricities, by kg 5/ Commission Rule 214 (b) (2), 18 C.F.R. S 385.214 (b) (2) .
~~
l matterElectricities of law. is not entitled to interventionIn fact, as aNor has I ) participation.would serve the public interest.Electricities does not is in the public interest. 4 b __ . - -
y their own admission, do not lie within the western marketing area and thus, would not be entitled to the SEPA allocations they seek to challenge. Merely being interested in receiving additional allocations of SEPA power provides no direct interest since in any event the SEPA power at issue in the four dockets
- - would not be available to Electricities. Nor should the mere contemplation of a lawsuit challenging the legality of the actions of a sister federal agency be sufficient to give
- n. a novant a direct interest.
Electricities will not be directly affectad by these proceedings. A motion to intervene should be denied when the movant's interests are too remote or speculative or where, as here, the movant's concern is that another proceeding might be affected by Commission action in the case in which intervention is sought 6/ w B. Electricities Have Failed to Demonstrate Good Cause for Failing to File Timely Motions to Intervene Motions to intervene in the above-captioned dockets ER85-393-000, ERB 5-339-000, ER85-312-000, and ER85-327-000 were due April 17, March 27, March 14, and March 21, 1985, l respectively. Notice of the rate change filings and the time limits for interventions were published in the Federal l [ Inc., 21 FERC 1 61,285 6/ Kansas-Nebraska Natural Gas Co.,
-~
at pp. 61,781-82 (1982). e _=_ _.- ~ _ _ _ - . ._- .:
T
-- Register on April 12,2/' March 20,.8,/ March 5,M and March 12, .. -.
1985,3.0,/ respectively. The Commission's Rules make explicit the require-ment that-a motion to intervene which is filed out of time must demonstrate good cause why the time limitation should be waived. E Electricities' only excuse for their late filings are that the Federal Register notices did not adequately e notify them that the contract terms involved sales or allo-cation of SEPA capacity to certain jurisdictional companies.J2,/ The'only issue within this Commission's jurisdic-tion -- consideration of the justness and reasonableness of f the' jurisdictional wheeling services -- was explicitly I discussed in each of the notices. Electricities' desire to l 1 l I l 2/ 50 Fed. Reg. 14416. B/ 50 Fed. Reg. 11238. 9/ 50 Fed. Reg. 8779. 10/ 50 Fed. Reg. 9882. 11/ Rule 214 (b) (3) , 18 C.F.R. S 385. 214 (b) (3) ; Rule !
' 214 (d) (1) (i) , 18 C.F.R. S 385. 214 (d) (1) (i) . l l
12/ Given Electricities' active involvement in challenging
~
l
~~~
various aspects of SEPA's marketing policies, it indeed l strains credulity to believe that had Electricities' counsel read the Federal Register notices they would have been unaware of the potential effects of these contracts which they now so fervently protest. . 6-
p. l. p use'the Commission proceedings to challenge SEPA's alloca-i tion decisions, and their assertion.that the notice failed L to explicitly notify them of SEPA's marketing decision, is L no justification for their untimely motion to intervene in l these dockets. C. Electricities' Intervention Will
' Disrupt the, Proceedings, Prejudice Other Parties, and Place Unreasonable Burdens on the Parties to the Contracts and The Beneficiaries of the Contracts The Commission's jurisdiction in these four dockets, pursuant to Section 205 of the Federal Power Act,12/ is'over the terms and conditions whereby the jurisdictional companiesid/ intend to provide wheeling se'rvices to SEPA. Electricities' concern with these contracts, on the other hand, is based on their assertion that the allocation of power from SEPA to the Operating Companies is a violation of the Flood Control Act of 1944.3.5/
Electricities' desire to litigate before FERC matters which "should properly be brought in district court" J3/ 16 U.S.C. S 8258 (1983). i 14/ Georgia Power Company (" Georgia Power") , Alabama Power (" Gulf") , Company (" Alabama Power") , Gulf Power Company and Mississippi Power Company (" Mis s i s s ippi") , (hereinafter collectively the " Operating Companies") all of which are (" Southern"). j operating subsidiaries of The Southern Company f 15/ 16 U.S.C. S 825s (1983).
)
(Electricities Motions at p. 19) is sure to' disrupt the orderly review and approval of these contracts. Electricities' principal objective appears to be to obtain a stay of the Commission' proceedings pending the potential review of the contracts by a federal district court. Granting such a stay will disrupt the timely review of the instant proceeding. Such a stay would also' disrupt 1 FERC decision-making processes in general by leading parties to believe that they can block FERC approval of rates under the Federal Power Act by merely announcing their considera-tion of a lawsuit to challenge non-jurisdictional elements of a transaction. Permitting Electricities to intervene in these dockets will prejudice and place an unreasonable burden on th'e parties to the four contracts and the beneficiaries of those contracts, including the Committee, by unnecessarily proliferating costly and time consuming litigation over matters already before other forums. Electricities unsuccessfully challenged SEPA's 1980 l marketing plan in federal district court 5./ and is presently appealing this decision in the United States Court of Appeals.12/ In the court challenge, Electricities raised Southeastern Power 16/ Administration,
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Electricities of No. North Carolina v. 62-888-Civ. 5, slip. op.-(E.D.N.C. Oct. 15, 1984). v.' Southeastern Power 17/ 7~" Electricities of Administration, North flo. Carolina 84-2271 (4th C[r.). !
)
)
__ ]
f "fr.cdamental policy' issues challenging SEPA's plan. Electri-Cities soight to raise the same policy issues before SEPA in the public information and commentL forum on SEPA's proposed
+ rate adjustment for the Georgia-Alabama system of projects held May 16.18/ In attempting to interv'ene in the above-captioned dockets, Electricities is raising issues identical
?.n to those already raised and lost in the district court proceeding. Electricities should not be permitted to relitigate the same issues again in the instant proceedings. III. Opposition to Electricities' Motion for a Stay The Committee opposes Electricities' motion to stay l for the same reasons stated above -- the motion is merely an nttempt to challenge SEPA's 1980 marketing' plan in another improper _ forum. The issues properly-before this' Commission are the justness and reasonableness of the terms and condi-tions of the jurisdictional wheeling service. Whether the capacity allocations to the Operating Companies violate the Flood Control Act of 1944 is irrelevant to the instant pro-ceedings. Whether the preference entities in other SEPA marketing areas should have been offered allocations given to the Operating Companies is irrelevant. Whether SEPA has complied with the Administrative Procedure Act is irrelevant. 18/ See Notice of Proposed Rate Adjustment, 50 Fed. Reg.
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13870 (Apr. 8, 1985). A L -
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Electricities is attempting to bootstrap'such inquiries into ' review under Section 205 of the Federal Power Act on the basis that a contract which "contains provisions k that violate federal laws, as well as agency regulations i
. cannot be round just and reascnable." (ElectriCities' Motions at pp. 16-17.)
The Commission's regulatory obligations would be a' overwhelming indeed if it were required to consider the legality of every act underlying contracts for jurisdic-tional services. Should Electricities challenge the contracts in court.19/ and should the-contracts be ruled invalid, new contracts :would be negotiated and the Operating Companies would then have to file such new or modified agreements with the Commission for approval. The Commission should, in the . meantime, decline Electricities' request that it second - guess the administrative determinations of a sister agency within DOE. IV. Conditional Motion for Leave ' to Intervene Out of Time The Committee's members are cooperative preference entities located in the states of Virginia, North Carolina, The South Carolina, Georgia, Alabama, and Mississippi. lo/ Which action Electricities by their own admission are f
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currently only considering. 3
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I Committee's membership consists of both rural electric ! J. cooperative generation and transmission systems and many of the one hundred and twenty-five distribution electric f i cooperatives in those states. The Committee's primary i purpose is to support and promote the development of federal hydroelectric power generating f acilities in the SEPA marketing area and to protect the right of its membership 4
- with regard to power allocation. The Committee has participated in numerous policy making proceedings, and its membership have intervened in two preference power lawsuits challenging existing SEPA allocations.3S/
Oglethorpe has long-term power contracts with thirty-nine electric cooperatives headquartered in. Georgia, under which it is required to sell, and the Georgia electric co5peratives are required to buy, all of their requirements for electric power and energy except for the power and energy sold by SEPA. In addition, Oglethorpe acts, and has 20/ Electricities of North Administration, Carolina v. (E.D. No. 82-888-CIV-5 Southeastern Power17, N.C. December l 1982) (order granting intervention) . Greenwood Utilities I Comm'n v. Andrus, No. 77-0689 (D.C. July 26, 1977) (order ) j granting intervention). By way of clarification, the motion 1 to intervene was presented to Judge Gesell in the United States District Court for the District of Columbia because I the case was originally flied in that Court and the case was 1 then pending there. ' Subsequently, Defendants sought and obtained an order _ transferring the case to the United States District Court for the Middle District of Georgia (where SEPA is located). Greenwood Utilities Comm'n v. Edwards, et al., No. 77-179-MAC (M.D. Ga. October 21, 1983) (final order); Greenwood Utilities Comm'n v. Edwards, et al. (M.D. i Ga. 1983) appeal docketed, No. 84-8069 (llth Cir. Jan. 20, 1984). 5 I I J
for many years acted, as the bargaining agents of the i A Georgia elDetric cooperatives in their purchase of power and energy from SEPA.
.AEC has long term' power contracts with Alabama and s
Florida distribution cooperatives under which it is required to sell, and the cooperatives are required to buy, all of their requirements for electric power and energy except for
" In addition to being a
' power and energy sold by'SEPA.
direct customer of SEPA, AEC acts, and for many years has acted, as the bargaining agent of its members in their purchase of power' and energy from SEPA. SMEPA has long term power contracts with Mississippi distribution cooperatives under which it is
. required to sell, and the cooperatives are required to buy, all of their. requirements for electric power and energy except for power and energy sold by SEPA. In addition to being a direct customer of SEPA, SMEPA acts, and has for many years acted, as the bargaining agent of the Mississippi cooperatives in their purchase of power and energy from SEPA.
Old Dominion has long term power contracts with Virginia cooperatives under which it is required to sell, l and.the cooperatives are required to buy, all of their requirements for electric power and energy, except for power and energy sold by SEPA. All of the Virginia cooperatives are preference customers within the meaning of Section 5 of w
b p the Flood. Control Act of 1944, and all of them except Old Dominion actually-pdrchase power and energy directly from SEPA out of the SEPA Kerr-Philpott projects. NCEMC has long term power contracts with othe b. l i North Carolina cooperatives under which it is require. ,o sell, and the cooperatives are required to buy, all of their 7,- requirements for electric power and energy except for power and energy either sold by SEPA, or purchased under contracts pre-existing the NCEMC contract. NCEMC acts, and has for many years acted, as the bargaining agent of the North Carolina cooperatives in their purchase of power and energy from SEPA. All of the North Carolina cooperatives are preference customers-within the meaning of Section 5 of the Flood Control Act of 1944 and a substantial number purchase power and energy directly from SEPA out of the Kerr-Philpott systems.21/ The Committee chose not to intervene in the four dockets initially because the contracts, entered into after lengthy negotiations, represent a satisfactory compromise of competing interests. Although neither the Committee nor its members are parties to the contracts, pursuant to SEPA's marketing policy, preference customers were kept currently 21/ A sixth G&T member of the Committee, Central, chose not to participate in these proceedings.
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e y
- _ advised.of.the negotiations and allowed to consult with and.
offer advice to SEPA.22/ - Electricities has now requested to litigate before FERC questions relating to these contracts which are prop-erly' brought only in other forums. The Committee respect-fully requests that the Commission grant the Committee's motion to intervene- if - the Commission grants Electriccities' g.- or.any party's. late motion to intervene.
. The Committee's intervention was not timely (11ed because it did notLanticipate that Electricities would seek review of SEPA's power marketing policy in the instant dockets. Because the members of the Committee have! vital economie interests involved in any challenge of the instant contracts, which interest cannot be adequately represented' by any other party, late intervention is appropriateLin this instance.2}/
)
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22/ Since the formulation of SEPA's marketing' plan, the l
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Committee and its membership have participated in the negotiation of the four contracts'at issue in the instant i i l dockets as well as the preference power purchase contracts between SEPA and the Committee's members. 23/ See Southern Natural Gas Co., et al., 25 FERC 1 61,167 (Nov. 4,1983) ~ (Late intervention granted to two peti-tioners who stated that they filed late because they did not ! anticipate the entrance of another opposing intervenor to the proceedings. Although the Commission had previously 1 held that such. lack of foresight was not by itself a ) l sufficient reason to allow late intervention, the parties (a i g recipient of the subject off-system gas, and a. customer of the recipient) have vital economic interests that could not be adequately represented by any other parties) . 14 - ! 1
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In particular, three of the members of the-Com-f mittee (Oglethorpe, LAEC, and SMEPA) will either purchase directly, or are responsible for the power supply planning of their members who will purchase directly, the SEPA power being wheeled under the contracts in question. As existing customers in the western marketing area I p of the Georgia-Alabama system of projects, these three members of the Committee (or their distribution members), have been determined to be the proper. recipients of SEPA
- power in accordance with the purposes of the Flood Control Act of 1944.
If the Commission rejects the contracts, or
-approves them subject to modification, by each contract's terms, the parties must retroactively adjust their per-formance to conform with the provisions of' previous contracts between SEPA and each of.the Operating Companies until new contracts can be negotiated. Such action would result in considerable harm, administrative expense, and disruption. In particular, under the previous contracts, the western marketing area preference customers were entitled to significantly less power than allocated under current arrangements.
The preference customers, by taking power in the early years, have invested in SEPA's projects during their less cost-advantageous periods. They have relied to their detriment on continuing allocations from the SEPA projects 15 - _ _ _ _ _ _ _ _ _ _ =-- __ _ _ _ _ _ _ _ . - _ _ _
p and have foregone opportunit..es to build other generation p and transmission f acilities or make. other arrangements to-lower their power costs. They have structured ongoing and x long-term power. programs in reliance on the delivery of the SEPA power in accordance with the 1980 marketing plan. 1 1 The Committee's other two members represented here, l1 Old Dominion and NCEMC and their distribution cooperative member s) are cooperative preference customers similarly L, situated to the North Carolina and Virginia cities within a Electricities. Because this motion is conditioned upon the grant of intervenor status to Electricities or other late inter-venors, no. additional disruption to the proceedings or
- prejudice to or additional burdens upon the existing parties will result from a grant of the motion.
WHEREFORE, the Committee hereby requests that If, however, Electri-Electriccities' motions be denied. . Cities' motions to. intervene out of time are granted, the Committee respectfully requests that its motion to intervene be granted. Respectfully submitted, May.20, 1985 2I ) /L/ N. Beth Emery, Esq. PAUL, HASTINGS, JANOFSKY & WALKER Twelfth Floor 1050 Connecticut Avenue, N.W. Washington, D.C. 20036 (202) 457-9424 SPECIAL COUNSEL TO THE SOUTHEASTERN POWER RESOURCES COMMITTEE 1' CERTIFICATE OF SERVICE I hereby certify that I have this day served the foregoing Answer of 'the Southeastern Power Resources Committee in Opposition to Motions of Electricities for Leave to Intervene Out of Time'and Conditional Motion for Leave to. Intervene Out of Time upon each person designated on the official service list compiled by the Secretary in each'of these four proceedings in accordance with the requirements of Rule 2010 of the Commission's Rules of Practice and Procedure. Dated this 20th day of May, 1985.
< ./ ..
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N. Beth Emery j PAUL, HASTINGS, JANOFSKY & WALKER Twelfth Floor' < 1050 Connecticut Avenue, N.W. Washington, D.C. 20036 (202) 457-9424 i
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OGLETHORPE POWER CORPORATION OBJECTIVES OF NEW GEORGIA TERRITORIAL POWER SUPPLY AGREEMENT- [ l (PRESENTED TO STRATIFICATION WORKING GROUP 10/2/85) l
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k Oglethorpe agrees with the thres broad objectives as listed on page _3 of the Phase I report: " 1.) Provide for the purchase and sale of power between the parties;
- 5. 2.) Provide a means_to insure an equitable sharing of_ mutual benefits ' and risks;
[ ' 1 3.) Promote continued integrated planning and operations including:
- Provision for dispatch of all future units applicable to.
dispatch; "*
- Clarification of each party's responsibility related to
' joint planning and operations At the request of the Stratification Working Group, Oglethorpe is preuenting the items it is specifically seeking in.the new agreement.
The items listed fall under the three broad objectives stated above. r Specifically, Oglethorpe desires in the new agreement the following:
'
- The provision for each party to simultaneously sell its surplus capacity and energy in a territorial category to the parties that .
are' deficit in the category and purchase capacity and energy in territorial category in which it is deficit; g 2
- A territorial capacity and energy stratification methodology -
' - similar to, if not identical to, the current territorial strat-ification methodology, unless it can be shown that an alternative
- would have substantial advantages; 3
- A methodology to determine mach party's responsibility to the territory that accurately tracks the territorial stratification; d
- Formulary capacity pricing; 6
- The right to continue purchasing embedded cost capacity until the Georgia Territorial Power Supply Agreement is fully functional; 6
- Hourly energy accounting for energy purchases and sales;
~/* An agreement that vill allow it to meet the requirements of its Member Systems in the long term in the most economical manner; 8 * ' An agreement that will not force nor require it to enter into individually uneconomical commitments;
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- An; agreement that will'.not.' require it to' carry more than-its! share ofsthe territorial l responsibility to serve native -j l'oad and:that will provide for full sharing of reserves that 8 . -- iresult'fromjoint. planning;.
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- An agreement that will . end the ." Company-Customer" relationship .
- and'will promote. equality among the parties -
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- An agreement.that'will embody Georgia Power's responsibilities.
and obligations under the several: agreements now existing-among
.the parties; ffk' The opportunity to participate in off-system transactions on ai ~
' territorial basis as well as:on an individual basis;-
v 13
- To have-its future resources, including PSH and SEPA dispatched *
'on a' territorial basis.by Southern Company Services
/A*Anagreementthatpromotes,andequitablyallocatestheresults
.: of,' joint generation and transmission planning on'a territorial basist;and-
'If
- Ailong-term contractual arrangemer.t with the other parties.to eliminate or-reduce uncertainty in planning for long-term resources.
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' Oglethorpe also submits its subjective criteria for. stratification' to accomplish the objectives as follows:
L 1.) Identifies load served by' unit; F-
'2.) Premotes long-term planning; 3.),Provides effective price signals; h; 4.) Discourages sub-optimal territorial operations; r-5.) Encourages effective allocation of resources; 6.) Provide a' favorable benefit / cost for implementation and administration; ^
7.) Equitable treatment of like resources; 8.) Stratification performed on territorial basis and equitably
- allocated to: individual parties; 3.' . 9.) Logical design that is readily traceable, justifiable and
'explanable to regulatory agencies; 10.) Mutually agreeable to the parties W
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h & GEL 3GIA PCHE; SUPPLY AGREEMENT SCOT.. F..t't'NG GROUP Re i;. ;. Issues W .- J 13, 1985 mw- A_ a. m. u
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Scope Working Group Oglethorpe - John Johnson - Chairman Reb Carlton Ed Tatum
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MEAG - Bill Scott John Hewitt GPC Fred Paradise O e
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" TABLE OF CONTENTS Pace I.
SUMMARY
AND RECOMMENDATIONS-g 1 A. ' Relationship'.to Soutnern Pool . . . ._. . . . . . . . - BJ 1mpact on Unit Dispatch ...............1 Impact on Off-System Transactions . . . . . . . . . . . 2-
'C.
4 II. -STATEMEltT OF ASSIGNMENT- , i 1 i 3: A. Project flanagement Team's Original Charge. . . . . . . e/ _
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Recommendation: for Study inPthe ProjectNPlan . . .- .4 B.
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C. Working Grottp Interpretation . . . . . . . . . .4 y ) / III. - RELATIONSHIPTOSOUTHERNdPOOL(fIssuey-u
.A. Introduction .
h h.u. .l:.[ 3 . . . . . . . . . 5
.5 E. Evaluation . . . . . . . .
. . . . . . . .7
. C. Recommendati: . . .
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IV. IMPACT ON UNIT DISPATCH 8 A. Intro _cuct1on . . . . . . . . . . . . . . . . . . . . . 8 B. Evaluation . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . 11 C. Recommendations s.
V. IMPACT ON OFF-SYSTEM TRANSACTIONS 13 A. Introduction . . . . . . . . . . . . . . . . . . . . 14 B. Evaluation . . . . . . . . . . . . . . . . . . . . . C. Recommendations ..................19 4 9 0353W k A- - - __ __...m._
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SUMMARY
AND RECOMMENDATIONS 4 h e e o 0353W _.m , _ .__m_ _ _ _ m m_m__ .A_ - _.._a__ _ ._ _ __ ._ ______m.. _uteAm
8 _' l 2 I.
SUMMARY
AND RECOMMENDATIONS . The Scope Working Group, consisting of representatives of.the Municipal Electric Authority of Georgia,. Georgia Power Company and Oglethorpe Power Corporation has completed its investigation of the following areas:
- 1. Feasible Alternatives in which the Georgia Power Supply (GAPS)
Agreement could operate within the Southern Pool
- 2. The method by which future generating units could be treated in GAPS.
- 3. The method by which off-system transactions could be treated in GAPS.
This document is the result of one working group's review of 'three spe:ific -issues relating to the Scope of a Georgia Power Supply The Agreement to succeed the current Partial Requirements Tariff. three issues should - be considered as separate and independent and do not encompass all' of the concerns of the parties involved. This document must not be interpreted c:. a final statement of conclusions or policy but simply as a guide for further analysis. A critical area not
,/ h m &>
addressed by this documen^ i s g. I' some form of commitments g by the E current customers, with regarr' te load and capacity responsibilities which are necessary beforr suci. :.n .piement can be consumated. l I i l'xamination cf tne! 'r a1- '* the 'llowing recommendations *
?. Relationship Tc ::ut'e L I
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? The L Working ' Group examined alternative relationships ~ between GAPS and the Southern Pool and recommends that only the following be included in further analysis.
- 1. GPC represents. the territorial load and capacity, but only 'it:
S-own cost within the Southern Pool;
- 2. GPC represents tne territorial load, capacity ard -cost, includin; the cost of the other GAPS members; and
- 3. GPC represents only its own load, _ capacity and cost, excluding
, . c '-
0 the capacity and cost of the other GAPS members. . . p e' ~
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f 4 This should not be construed to mean that Georgia Power anticipates Furthermore,L a changing its relationship with the Southern Pool.
- decision to change its relationship with the Southern Pool is the sole prerogative of Georgia Power. . It should also not be construea to mean that Georgia Power's right to determine its relationship Pool relieves i t of the responsibility of with the Southern i
providing full _ access to the benefits of interconnected bulk power supply operation's to the non-Southern entities in Georgia. f i
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A standard setl of criteria was used to evaluate each. alternative. In summary, all three pr:sent workable solutions to the relationship i The -Working Group-~ recommends between GAPS and .the Southern Pool. p- that all . further analysis performed. in Phase II-A be structured so I as' to quantify the differences within GAPS between the three al t'ernatives. . B, Impact on Unit Disoatch I I, Gecrgia Power. Company (GPC) through Southern Company. Services (SCS) will be responsible for the dispat'ch of the system as a whole f j
- regardless of the dispatch method selected by- a GAPS member for its l future unit. :i i
I The' Working Group examined the following methods for dispatch of a. future unit: i l
- 1. Unit is submitted to SCS dispat:h: ;
l j
- 2. Unit is dispatched independently but .its output schedule is
~ ' coordinated with SCS through GPC; and y- ,
- 3. Unit is dispatched independently and its output schedule is not coordinated with SCS. -
\
The Working Grcu; : n: luce- nat ; preferential accounting treatments within GAPS should te afforced to cer,trally dispat hed units over dis;a;: red units. However, an independentl y independently
.' ' ,/ -
a .. . coordinated with- SCS4 L'f uW kI !., . dispatched unit Lwhose -schecule.:is and-
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contrbutes to system. requi, dents may be' afforded treatmert simila. .
- 4." . Eto aLeentrally dispatched unit.
1< ' h: , C. Impret on Off-System Transactions t R for Tne 'following alternatives participation in- 'off-syste-
- transactions should be . included in further ' analyst s , ' erformed p . in r Phase II-A.
di n. 7
- l. _Off-system: transactions entered .into by. the Southern System; only' GPC resources ~ contribute; and N
4 :
- 12. Off-system transactions entered into jointly or individually by.:
members of GAPS in which: O
- a. on,1y individual member's resources contribute; and-I
;l
.b. all Georgia. Territorial resources contribute. ]
Accounting treatments should be structured such that no individual's
>- transactions- adversely affect the system as a whole. GPC througn SCS will be responsible for scheduling - l transactions and 'for .
determining what, .if any, costs should b'e . charged to the a 1 participants . in. a' transaction. . GPC would - use its best efforts in _
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2 6 3 4- ' ., p 4 , 0 coordina'tilng all transactions with SCS and in ensuring that ' the .
; operating and accounting practices employed . by SCS, including fees ,
charged 'for implementing a transaction, are non-discrfm,hnatory. _ 1 Participation in Georgia: Territorial transactions' by a GAPS member mayJ be inadvertent (by releasing its . units for dispatch including of ."-sys tem transactions) or contractual. The parties agree to e
' investigate sharing revenues above cost for their units released to o serve off-system sales. The role of GPC as agent will be recognized in these discussions.
Acceptable options for the determination of responsibilities and allocation of benefits are: _1.. load,or generati ng capacity ratios; e'd
- 2. contribution to a sale or displacement by a purchase.
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?.\ M o M-4 II. STATEMENT OF ASSIGNMENT hi WP 4 4 e 0253W I { 1 A i i, f m - --- _ N'-- -- -- _ ____ ._ _ _ . _ _
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]Y LII. STATEMENT OF ASSIGNMENT The Scope ' Working Group relied on' two, sources to formulate its charge:
v ~ the. Project Management Team and the Project Plan. The following: are excerpts from Project Management . Team memoranda anc h the Project Plan, developed on la theoretical . basis, and do not represent conclusions of the working group- . (The name Southern Pool
. Relationship Working- Group in these. memoranda refers to the Scope Working. Group.)
A. Project Management Team's Original Charge By memo dated April 12, 1985, the Project Management Team d, iverec the following charge: s - 'l I The Southern Pool Relationship Working Group will _ investigate feasible alternatives in whict. the " Georgia Pool" .could- operate a within the Southern Pool. As e. minimum, the group will address the following alternatives: ] a (1) All parties are me. ers of the Southern Pool. (2) Georgia Pool oporr.n a: subordinate of the Southern Pool. { l 1 I (3) Georgia Pooi : r' an: dontly of the Southern Pool. , I i (4) Other alterr. . r " ,ed by Working Grouc. L_ o _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ,__ _ _ _ _ _ _ _ _ _
,r m , . N-- y 7,- Ea:h alternative should be: evaluated with regards'to:.
' ' (1) Feasibility. ,
; . (2). Degree of adherence to Southern methodology. ,.
6: (a) Recognition.of capacity. k (b)' Rating of capacity. (c)~ Treatment of existing contracts (E. etc.). p (3) Determination of responsibilities, i , (4) Allocation of benefits.
~
(5) Other criteria-as determined by Working Group.
- The . Chairman of the Working Group will provide the Project-Management Team' with written status reports following each of :the Working Group's meetings. The final written report will be delivered to the Project Managtment Team no later than May 17, 1985. The report will be reviewed at a Project Management Team Y^ meeting on'May 23r.1985.
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r 13 L v DuringL the May 30. 1985' meeting of th'e Project Management Team it . was' decided that the Scope Working Group .should add the. following t0 l ' its ch'arge: { L-
- 1. Investigate means of communication with _ Southern dispatch office of a non-Southern member who might desire Southern dispatch c' its . wholly owned unit. How would benefits flow to the owner if benefits occurred'under the Southern Company System IIC?
. '2. -How would off-system sales or ' purchase L of non-Southern - ownea
- units be handled:under the various options. studied?
B. Recommendations for Study in the Project Plan
~ -
TWo' . feasible ' alternative ways in which the Georgia Pool coulc operate within the Southern Pool were discussed by the Project Team:
- Continue relationship through Georgia Power Company.
- Operate as.a member of the Southern Pool, o With the first alternative, the membership and operation of the
, Southern Pool would be relatively unchanged by this agreement. With the Georgia Pool would designate a the- second alternative, l representative to the Southern Pool which would act on behalf of all parties to the Georgia Pool agreement. Ur.animous agreement of the members of the Southern Pool would ce required in the secenc alternative. f 4
[imilm ____ __ ___m.1, _ _.m...__ _.___.___._._.fmm._ .A__ _..A,_ . . . . _o m..A.n. _a &
p , i (, - JF Under ~elther alternative o there are> several . issues that impact the
-Southern Pool and must: be' addressed. Theselinclude:
p.: .F .. .
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- Application of; Southern Pool- dispatch procedures to generation operated by. non-Southern entities.
- Treatment of each party's capacity and energy in the' Southern. Pool.
, ~
- Off-system sale of each party's capacity and energy, e -C. Workino Group' Interpretation 4
Team's' c'riginal . charge l' n Evaluating the ~ Project Management
. conjunction with-the alternatives set forth in the Project Plan, the .
-. Scope Working Group developed - the following interpretation of .its chargey P '
The. Scope Working Group will:
- 1. Investigate feasible -alternatives in which GAPS could operate
- within the Southern Pool.
e 5
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- 2. Inves,tigate ways by which future generating units could be treated in GAPS.
s
- 3. Investigate ways by which off-system transactions could be treated i- GAPS.
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I III. RELATIONSHIP TO SOUTHERN POOL t (5 i l ( 1 r I-e a l l' p 0353W s M i [' -J- : - ' z___&_'_ _ _______.:_-_____
v.. .y l y< s b IIIi RELATIONSHIP TO SOUTHERN POOL h k A.' Introduction l The .. Scope Working Group will investigate, feasible alternatives in-W. . 0 which the Georgia Power Supply (GAPS) Agreement could. operate within'- the Southern Pool.. The . original question put : forth in : Phase I .of
' this project was whether' GPC or another .' entity should represent
' .: - members of . GAPS in :its relationship - with the. Southern . Pool.
Discussions.. In the working : group have' eliminated all ' alternatives except' those in which GPC is the representative. The alternatives / put forth by the working group are variations of this GPC
. :t representation theme.
jp/pp./.f O I; This.'should not be construed to mean that Georgia Power anticipates, Furthermore,s a changing its relationship with the Southern Pool. , decision to change its relationship with the Southern Pool is the It should also not be construed sole prerogative' of Georgia Power.
. to mean that Georgia Power's right to determine its relationship with the Southern Pool relieves it of the responsibility of u.
providing full access to % ' ~ fits of interconnected bulk power supply operations te the no v +rn entities in Georgia. Th '.iree alternatives art t : J ww:
- i. GPC represt
~ tad and capacity, but only its own cost, wit'. .
- (Current Representation);
....:i
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'l6 o.
E represents. . the ' territorial load, capacity, and cost,
- 2. GPC including the cost. of. the other GAPS members (Territorial
" Representation); and 3.1GPC represents only its own load, capacity, and cost, excludin;
-the capacity and' load of the other . GAPS members (GPC Onl, Representation).
S.-Evaluation
- 1. Feasibility 1 .
It appears that c all. three alternatives are feast'ble at Lthis time reflect'ing ' GPC's ' virtually unchanged relationship within the Southern' Pool. Territorial or GPC Only Representation may l _ require modification to the Southern Company System 11C and tnus approval' by FERC and the Southern Company operating companies. h, " With regard to GPC Only Representation, this group recommenos that "GPC Only" load, ' capacity and cost be more explicitly defined in a later phase'of the project. i
- i L
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- i f
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- 2. Degree of adherence to Southern's methodology With regard to the recognition of capacity and energy, rating of K
. capacity, and treatment. of existing contracts, Current Representation or Territorial Representation - would typically- be in agreement with the Southern Pool -methodology. GPC Only E Representation, however, could represent significant divergente -
from'the existing methodology. Under' this alternative the other members of GAPS would no longer be represented in the Southern Pool and ' would , no longer ' be . constrained by the Southern. Pool's methodology. .Any significant' deviation, however, may be
- challenged by interveners and may result in mandated compliance of the IIC or GAPS to the other's methodology as well as placing
_ an Additional administrative burden on GPC. M 3. Determ'ination of responsibilities
~
Responsibilities and corresponding costs associated with capacity and energy excnanges must be tailored to the specific appropriate that some level of alternative. It may be responsibility be assigned to all parties regardless of whether s
- their capacity and load are " represented" in the' Southern Pool The responsibilities associated with operating and dispatching the system should be addressed in a later phase of the project.
These responsibilities should include operating reserves 'and deviations from cc uputer dispatch to preserve the integrity. of the system.
- c. m,_a.m___ m.-_____.______ _.m_____._m _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
ll, , .' . go
- t- The. part*es . agree that the allocation of benefits associated with capacity and. energy. exchanges. should follow- the
. determination of responsibilities. The parties recognize that-there are intangible- benefits which will flow to all the parties L -
'due to interconnected operation, regardless of the contract structure. .
1- 5. Southern Company Services (SCS) 'or other operating ' company; h r.. involvement For Current Representation, since the relationship is virtually
-unchanged, there may be no .need for the involvement of SCS or 1
the other operating companies in the' development of GAPS. Since the present .IIC methodology will be. changed under the 'other g
- . al ternatives , some involvement by SCS or. the other operating
- - - companies may be needed. SCS may be involved in analyzing any proposed agreement with regard to the impact on the 'other operating companies and may act as their agent in proceedings before FERC. For all alternatives, SCS will be responsible for ;
j the operation of the system, administration of the' IIC and ' the' preparation ' of budgets. If Territorial or GPC On2g L l- Representation is chosen, there may be additional involvement by ( - 3 D 1 ? u l' _a_ m - ____.-_m _ _ - _ . - - - __ 1
4ll 7 a
. SCS ionce the agreement is implemented. This involvement. may consisti of auditing the territorial cost for-the other operating.
companies or ' auditing the' methodologies used to . determine the separation of load and capacity within the. Georgia Territory.
- 6. Impact on accounting systems 1
Accounting- systems will be impacted whenever- the 'curren: representation is changed .by either adding the co-owner's cos:. or removing some amount of capacity and load from GPC's responsibility within the Southern System. These changes will not ~ necessarily be limited to direct charges, but may involve procedures for charging the. co-owners for' benefits derived from common dispatch and joint planning. For Current or Territorial Representation, the accounting system developed for GAPS will probably be driven by the accounting system cf the Southern System. .The GAPS's accounting system L
-must clearly' recognize the flow of costs and benefits from the Southern Pool. It would not be unreasonable to expect the' I GAPS's accounting system to mirror the accounting system of the g .
? - Southern Pool, for GPC Only Representation, the flow of costs and benefit- within the Southern Pool is clearly a GPC responsibility. The GAPS's accounting system must clearly recognize the Southern Pool transactions by GPC and be able to remove, with; ac erse et Tects, those transactions which are not serving G: rgir Ter-itorial load. In this regard, it may be .
\
l-necessary fo. the other GAPS members to receive Southern Poo L L l --
; [L- '
.transac81on information- to ensure? tha? the flod of dollars 1
. between . - GPC and : the other Southern Pool members . is properly.
recorded. [ l '
- 7. Contractual' arrangement
- p. direct' contract 0&l 5 None of' .the . alternatives require a arrangement L between the Southern Pool and- G' APS. .HoWever, the other GAPS _ members may ; require a ' contractual arrangement 'with r,
GPC which clearly outlines . the flow of costs and benefits from the Southern Pool. 4 C. Recommendations All three alternatives present -workable solutions to' the relationship between GAPS and. the Southern Pool. The Working Group
-recomme,nds that all further analysis performed in Phase II-A be.
structured so as to quantify the differences within GAPS between the- . b three alternatives. Areas which should be specifically addressed in this analysis include: o s W O
r- - r 1
$ in I- ;
(l'. : Determination of cost for non-Southern entities . to.' be used
.the Southern Company System IIC if Territorial Representation is selected; .
n 5
- 2. Determination : of GPC "Only" . load and capacity if GPC Only
-E . Representation is selected; h
- 3. Responsibilities . associated with Loperating and dispatching the' j.;
system; Accounting 'and allocation of the flow of dollars between GAPS 4. and the Southern Pool. 1 Y. k 4 h ' m i 4 4' 6 1
-d
. _ - - - . _ - _ _ - _ _ _ _ _ - _ _ . _ _ = _ - - _ _ _ _ _ _ _ _ - - _ _ -
4 Y r i2-IV. IMPACT Old UNIT DISPATCH 9
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-! IV. IMPACT ON UNIT DISPATCH-IJ .i L . 'A.~ Introduction The Scope Working. Group will. investigate ways by.' which o future 6 ' generating units could be treated in the GAPS Agreement.
H
- i.
Three alternatives with regard to the. dispatch of a future unit.will r-. . be examined: L
- 1. Unit is submitted .to SCS dispatch (coordinated .for maintenance, H etc.).
l l
- 12. Unit ' is dispatched independently but its output schedule is-h' . coordinated with SCS through.GPC.
E
- 3. Unit is dispatched independently and .its output schedule 1.s not coordinated with SCS.
It is obvious that a. GPC ownef generating unit would be submitted to SCS dispatch; therefore, the discussion of otner forms of dispatch h refers to non-GPC owned units. 4 Jv
.fS ' A major area which this working grc"? does not address, but should s ., v . .
be addressed in a fu:urc thass is the approval of a future
., ?
generating unit as a G'P rc ce (i.e.. the joint planning
- h. -
- of Southern have the sole
#- process).., The . operating .?ii..:.
b_-1E -_ _ . . _ _ _ ___ _ ._ _ _ _ _ _ _ _ _ _ _ _ _ _
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~
' authority So' determine if ~ a i future' generating unit qualifies / as. a-
'~
t
. Southern. Poo11 resource. It is assumed L for the' pt+ poses- of this s
workingi group', ithat a future generating unit .in question, has gone $ .through the joint planning- process and has been . accepted.as a GAPS' -i resource and a Southern Pool resource. This -discussion' excludes - small' power producers , and facilities tha:
-are primar11y dispatched for other than electrical production (1.e..
cogeneration). 1
- 8. Evaluation e -
l '. Southern Company Services (SCS) involvement SCS will be' responsible for the dispatch of the system. To-accomplish this task, 'they shall require' telemetry.of the unit's output at the high side bus or from the low side with a mutually agreed upon adjustment to the high side. m If the unit is submitted to SCS dispatch. it will be dispatched the..same as any other Southern System unit.- SCS would need to put
-a. control signal .into the unit and would need appropriate incremental . cott and opert. ting data to economically dispatch the uni t.. This would increast the effort required to maintain SCS's -
1 .
' data base. If 'the omer si . cts not to load or cut the unit.~when dictated by SCS's dis "c5 program, appropriate accounting penalities ithir GA; sho;' L imposed (i.e., frozen units).
h l l
11 The schedule, for an independently dispatched unit whose output is to be coordinated with SCS, will' have to be coordinated through This would increase the information flow to the SCS GPC. dispatchers and the number of separate schedules entered into the central dispatch computer. The, owner will provide SCS with an anticipated schedule of the unit's output for a period consistent Y SCS may _ propose a with SCS's unit commitment program (7 days). modified schedule, if they desire, and the parties will alternately propose schedules until a mutually acceptable schedule is derived. Schedules may.be reviewed daily with additional runs of the dispatch
-program.
l' l ' A unit which is dispatched independently and treated by SCS as an
- uncontr. piled tie flow, requires no direct involvement by SCS in dispatch. However, SCS must know the input to the iystem from that unit to properly determine the loads of its operating companies and the Georgia: Territory.
l
- 2. Simplicity {
l ( i Simplicity deteriorates as one goes from centralized - dispatch 'to + . independent dispatch. From a dispatching perspective, having all J l units dispatched by SCS would require the least modifications in J normal operating procedures. Scheduled independent dispatch will f
)
require 'the most coordination between SCS and the owner, but should j be relatively easy to implement within the current dispatch logic. Non-scheduled independent dispatch may adversely affect SCS's l j ability to regulate the control area, although, from the owner's O_m______._____ ._m._m,_, _y_ _ _ _
f .
' ~ =
perspec%ive e it: may require the least expense and involvement 'cith SCS.
-3. Administration
- a. Accounting requirements 4
The;= GAPS's accounting requirements will be driven by the- ) allocation of benefits and responsibilities. A . unit's t . . r :. ' . accounting. requirements should vary - little between. the- .{ y alternatives. l
- b. Operating data requirements a
SCS dispatch- requires the greatest amount of operating data. For example, heat rate equations, high/ low limits, response-
. rates, replacement fuel costs, variable O&M rates, and fuel ;
)
handling rates are required for computer dispatch. All ] 1
^
alternatives may require telemetry of the unit's output and l
- approved adjustments to determine the unit's net input to the l transmission system. The owner of' the generating unit may ll desire the above operating data as - well as data about its own l load and the Southern System's . costs in order to more l r effectively dispatch 1ts unit. The availability of this ' data j, .
1 l h will be dependent on the form of the GAPS Agreement developed. i l l l L ' 1 L=_ _m _ _. _ _ _ . j
21 h
- 4. Acceptability ,
- a. Regulatory Regulatory acceptance will be most favorable .toward the alternative which produces - the least cost system. Although it would appear that the least cost system would be produced by central dispatch, regulatory agencies view participation in centralized -dispatch as a voluntary decision. All of the alternatives should be' acceptable to regulatory authorities given'an appropriate allocation of benefits and responsibilities.
- b. GAPS members The GAPS accounting procedures need to be sufficiently flexible
- to allow an entity to independently dispatch a unit for reasons of non-conforming fuel . supply, take-or-pay fuel contracts or to fulfill a unit specific off-system transaction' while protecting the cost stru'cture of the other members.
i The acceptability of each GAPS member will depend on its opinion' of each alternative to produce the least cost and maximum benefit (i .e. , back-up energy for an independently dispatched unit). .The knowledge needed to form this opinion will not be i l available until specific accounting treatments for eacn -l alternative are known.
- 5. Determination of responsibility u -- ._u__._ _ ,_ ._ , .
a; . -~ [ ly
= Units.- submitted to SCS dispatch should be ' treated the same! within The owner will be . responsible' for -
~
E theLrules developed for. GAPS. y O providing, the data' necessary :to dispatch its unit and for performing appropriate heat rate and response rate tests to assure:the validity e of its dispatch' data.- The owner'.s . unit will be- expected-'to h contribute to the system's. dispatch- requirements including unit l E - commitment ~, regulation, operating reserves,- maintenance- scheduling, . etc. The owner willL also be expected to contribute to the costs vn F : associated with dispatching the system. - A unit whose Loutput schedule is coordinated with SCS may, under the 7.;
,- following condition, be treated the same as a SCS. dispatched unit within LGAPS. It' is expected that the ~ unit will be made available:
and dispatched above its intended schedule. When. the 'sys'.em requires e " it to avoid.more expensive types of fuel or off system purchases and. during.: emergency . conditions. However, it is recognized that situations exist beyond the control of the owner which may prohibit , Its unit from responding to system requirements (i.e., environmental 1. limitations, fuel limitation's, transmission limitations or a unit eltetrical). The Working Group whose primary outpu't is not recommends that under such conditions the owner should not be penalized. Since the unit is scheduled and is not available to contribute to system regulation, etc , the owner may be expected to L M contribute monetarily to the cost associated with scheduling the 4 e _11. &= . := :-.: - - :- - .
. .- -.c. . . ~ - - . _
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.1
.l b unit and , regulating'the system. It may be appropriate that all or a portion of the energy generated by a scheduled unit be retained by the owner and be unavailable for sale within GAPS.
h. 1 . An~ independently dispatched, r.on-scheduled unit contributes-virtually nothing to the system's ir.tegrity and may hinder tne coordinator's -ability to regulate the system. Rather than .a capacity credit, the unit may be assigned a load responsibility.
.The cost of replacing the unit's output during an outage or deration
- An should not be . priced the same as load ' served within GAPS.
approved ur.i t should be given preferential treatment over an
. unapproved unit. The owner will be expected to contribute monetarily to the regulation of the system.
- 6. Allocation of benefits 3
The flow of benefits should be to the entity who assumes the risks and the costs of the unit and should not be affected by the method of dispatch except to protect the other members. Benefits are: best allocated by the determination of capacity credits. The benefits associated with regulation, etc., flow to all parties in an
- interconnected system regardless of the alternative.
C. Recommendations . Assuming the Southern System will remain one control area including the Georgia Territory regardless of the dispat:h method sel'ected by a GAPS member for its future unit, the Working Group recommends the c_ - -- . .. . _- _- - _ _ - _ _ _ _ _ - _ _ - _- . --. -
4
")k follosing:
- 1. A procedure for approval of a future unit as a GAPS resource needs to be d,eveloped. - An approved unit should receive preferential treatment within GAPS for reserve capacity and backup energy over a non-approved unit;.
V
- 2. Since centrally dispatched units contribute the most to the system, they should be afforded preferential treatment in the GAPS accounting methodol691 es;
- 3. The GAPS accounting system should recognize that an independently dispatched unit. contributes less to the system as a whole. If an
' independently dispatched unit's schedule is coordinated with SCS, and it is made available to the system under certain specified conditions, it may be afforded accounting treatment within GAPS
- similar.:to a centrally dispatched unit;
- 4. The owner of an independently dispatched unit should be expected to 8
contribute monetarily to the ' cost of regulating the system;
- 5. It may be appropriate that all or a portion of the energy generated by an independently dispa'tched unit be retained by the owner and be unavailable for sale within GAPS *.
f
. I t._
__ =__ N_ _- ______- ____-_ - i . _ . - . .
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n4 V. IMPACT ON OFF-SYSTEM TRANSACTIONS l>. O 4 L 4 24 0353W O W 9 h___...._m.__ ._ m ..< > . .
,a 4
b; A ,
' V. IMPACT ON OFF-5YSTEM TRANSACTIONS A. Introduction-The Scope Working Group will investigate ways by which off-syste-c Transactions could be treated in the GAPS Agreement.
For off-system transactions entered into by: 1..The Southern System; only GPC resources contribute.
- 2. GAPS members,.either individually or jointly.
- a. Only individual 1 member's resources contribute.
3
- b. All Georgia Territorial. resources.contribu.te.
- 1) Inadverte'nt contribution.
- 2) Contractual contribution.
f'.'
'W1th a pool form of agreement or. other arrangement involving central economic dispatch, interchange among members is' typically automatic anc ~
settlement is typically accomplished after-the-fact. Off-system transactions, on the other hand, are typically arranged and pricec I before-the-fact and some effort is usually required to implement them, None of' the a' alternatives can be eliminated from the study as the future L= - .w_: _ _ - _ _ __ __
p. g l' , * ; agreement cannot be' allow 2d to restrict any member from entering. Into l L an - off-system : transaction. For some alternatives and some types of transactions, it may be difficult to structure a GAPS Agreement which N allows comglete -individual member flexibility , in making off-system L transactions while not interfering with .the efficiency of automatic interchange among members. No unilateral action taken by an individual
; member to the agreement must be allowed to be a detriment to the system. For this reason.- each treat:nent must provide for 1) the determination of all appropriate identifiable costs associated with the transactions . and 2) the allocation of those costs to the member (s) accepting. responsibility for the sale. The' members to the agreement should recognize the costs associated with an off-system transaction involve more than just fuel and variable OGM.
Off-system . transactions are typically easiest to complete between " electric systems that are directly interconnected and have their own control areas. A more difficult transaction to complete is one with a control area that is more than one system away. Perhaps the most E difficult transaction to arrange and complete is where both systems are in separate control areas and one or both are embedded and do not have real-time information and control capability.. This typically involves scheduling through an agent who may be in competition with the embedded 1C.
.2 - :. ___;_ __ _ _ . _ _ _ _ _ _ . - - _ _ _ . + - __o. _
o 3
' h-M.
r
. system.. The discussion' of ' the alternatives for the following -:
s' , transactions is: based ~ on the assumption that real-time coordination-would-be ma'intained by SCS. v For all alternatives of this Charge the Working Group must consider: s 1. Non-firm transactions - Purchases to off-set more expensive generation. The purchaser. is responsible for reserves. These transactions come from a mixture of system units and are reca11able prior.to native load being shed. 2.; Firm' transactions - Capacity needed to meet load or off-set' more
. expensive- generation. The seller is responsible for reserves.
Service.:is not interruptable except unde'r limited conditions (i.e., similar to native loads). Firm transactions do not come from w. specific units.
- 3. Unit-specific . transaction - A contractual right, without ownership, to a portion of the output of a particular generating unit. It is non-firm. The-sale should not increase the cost of serving the native load and the unit sold' must be excess to the native load l
A requirements. -
]
1 i 1
- 4. Wheeling' - The transfer of power and energy from a non-GAPS member !
I I to another non-GAPS member. The Wot'Aing Group will address the use of . capacity and energy to facilitate wheeling transactions. (The ITS group will address the use of the transmission system for wheeling.) w n L:-_ _. _. _ ._ .-i. .n _. ...n - - -- _s.... ..
p ___ .._
; "hl
- 5. Treat' ment cf inadvertent exchange -
The difference betreen the l-1 schedule on a tie-line and the actual flows across the tie-line.
~
' The Working Group recognizes that inadvertent exchanges exist but recommends that' a uniform' treatment of. Inadvertent. flows not be-i dictated by the GAPS Agreement. Inadvertent- flows should be ,
[ addressed by the parties to the transaction and SCS on an individual l transaction basis, if possible.
- 6. Reserve transactions - Capacity purchased to improve the system's
{ reliability but.not needed to meet the system's anticipated load.
- , - B. Evaluation
- 1. Southern Company. Services (SCS) involvement The involvement' of SCS will be coordinated through GPC. SCS will be responsible for scheduling the transactions and determining what, if
,, any, costs should be charged the participants in a transaction. GPC would use its best efforts in coordinating all transactions with SCS and in ensuring that = the operating and accounting practices employed by SCS including fees charged for implementing a transaction, are non-discriminator g l l j 4 L
= _=_ - _ _ - _ . -__:_-_:____ -
h
+
[v 3,
. .Non-firm transactions- are typically. predicated on- knowing the-real-time generation, load = and . marginal cost at the time of L
interchange.. SCS would be involved in non-firm transactions as scheduler and accountant. Firm transactions tend to.'be individually initiated and are y typically treated as load modifications. A firm transaction ' would be scheduled ' by SCS and Georgia's lo.id would be modified hourly by the firm transaction before re-dispatch. The seller, however, must make suitable arrangements with the. purchaser to ensure the firmness of the transaction. , True' wheeling is a. transmission service which would normally be negotiated and contracted with an individual GAPS member. SCS would
~
only need to be involved in scheduling and loss accounting. 7 For embedded systems, inadvertent energy accounting tends to be contract specific and' should be addressed by the parties to . the transaction. The treatment should be based on accepted utility interconnected operating practice. The capacity side of the reserve transaction would normally be a arranged by an individual entity for a specific reliability purpose. In' a mutual obligation' reserve sharing arrangement a reserve transaction should be predicated on system reliability requirements and not those of an individual entity. The energy scheduling and accounting would be similar to a non-firm transaction.
- 2. Simplicity i
~w_.________________________._ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .m_
g _
- o. .
f L. , Simo11 city is greatly dependent upon the type and size of s transaction. Currently, schedules are committed on an -hourly basis... The minimum time and MW increment available to be scheduled must be7 addressed on an : individual transaction basis by the parties to the ' transaction. The- seller, however, must make suitab'e p arrangements with the purchaser to ensure the firmness of ar . transaction over the established time increment. Since non-firm transactions are based on ' central' economic dispatch. the energy associated with non-firm sales can routinely be traced to individual units. The accounting within GAPS should address not
- only' the costs associated with this energy but also the revenues associated with these sales.
Assuming Territorial resources are contributing to a GAPS member's transaction, the following methods of distributing revenue are possible:
- 1. Revenues are distributed based on load or generating capacity ratios-and energy is' purchased at cost from the other members.
2.-Revenues are distributed based on the energy contributed to.-the transaction. D
.~x-n I,-----. - _ - - - . - - - - _ . - - _n x Du f a n. __.n.-_ - L -' W.&-
y n F . Existing ownership agreements coverir.g central economic dispatch obligations of. co-owned units may complicate the use of co-owned anits ' -in making off-systen: unit specific sales. Provisions for scheduling portions of: co-owned. units while economically dispatching the remainder f would- facilitata their use in unit specific sales. Arrangements to complete the transactions when the specified unit is unavailable should be treated depending on'the terms of the transaction. Within the established time increment, a wheeling. transaction should be
- treated as a simultaneous firm buy / sell transaction by GAPS.
When reserves are shared in a centrally dispatched operating
). arrangemen',- individual off-system reserve transactions, without specific guidelines based on system reliability requirements, can adversely impact the reliability and/or costs of the other members.
- 3. Logistics of. implementation.
- a. Accounting requirements.
The accounting requirements between the off-system party and the
- Territory should be easily implemented. ' However, an agreement to.
facilitate the transaction must be implemented between the GAPS member (s) and GPC. This agreement should address situations when a transaction is scheduled and carried out, but the' GAPS member is unable to meet its commitment.
- b. Operating data requirements ;
. _ = _ - - _ _ _ _ _ - _ - _ - _ - _ _ _ . - -__.___: - .-
_ . ._ x_ -
y. _y ), Operating. data requirements may. be. as simpleLas MW telemetry of any. delivery / receipt points (including generation buses). involved with
~
j the transaction. . However . if the brice of the transaction ' varies-
~
with system ' or . unttL dispatch, all of the -appropriate. dispatch parameters must be available.
- 4. Acceptability
- a. Regulatory Within GAPS, regulatory acceptance will pivot on sound' engineering and economic- practice. Regulatory review will involve the terms executed with the off-system. party and . the treatment afforded the ransaction within GAPS. , M g y g k' & & Crp yys',2 liZe , c N e b
..t e m hmwN.g+W,
eJC t v m
- m b.' GAPS members /
- Acceptability by GAPS members will depend on the equitable treatment each member receives. .
c.-Third party Acceptance by a third party will be based on economics and his n perception of the capability of the GAPS member (s) to follow through with the transaction. E i S. Determination of responsibilities o
. The scheduling of t transactions. will be the responsibility of. SCS and 'be It is the GAPS members'~ responsibility to.
~
coordinated through . GPC. arrange with. GPC for the dispatch and. scheduling 'of independent
~
transactions they wish to execute. Side-.. agreements will be rt;quirec between GPC t..o the affected GAPS members. These side agreements will vary depending upon the type of transaction and must recognize that transactions are scheduled for a minimum time and MW increment. Therefore, a member must make arrangements. to support the . transaction. over: the minimum time increment.
~
' Alternately, if a m' ember's units are released for use in a GAPS member's. off-system transaction, that member accepts responsibilities determined by one of the following methods:
a i
- 1. Re'sponsibility is based on load or generating capacity ratios. '
- 2. Responsibility is based on contribution to a sale or displacement by a purchase. ,
.]
f The premise behind' off-system sales within the GAPS Agreement should be p that nothing sold off-system should cause a detriment to the territory as a whole. If all parties agree that the transaction is in the best
]
. interest of the system, then all parties should share the risks of that transaction. If a party desires to proceed with a transaction 'without the concurrence of thhother parties, then that party should incur all the risks associated with that transaction (i.e., off-system sales
( .. b-. =- - . _ = _ _ _. -_______-__________________Y
m m
- : should not be replaced by purchases under the GAPS Agreement).
J ..
- 6. Allocation o'f benefits s.-
~
Each treatment for - an off-system transaction should recognize the degree to which responsibilities are shared and allocate benefits V accordingly. The benefits associated with off-system transactions are essentially + capacity or energy related. Capacity related benefits promote a more economical use of system resources through either selling surplus capacity to realize an additional return on the system's investment or 3 through .purchases to avoid additional investments. Energy related benefits are structured - to relieve the system of some burden (i .e., controlled burn energy), share the savings associated with avoiding the use of high cost energy, or improve the operating characteristics of
. the system (i.e., valley load problems and thermal cycling).
Some of these benefits are difficult to quantify. monetarily and .will flow to
;. all parties in the interconnected system.. Other benefits have a direct monetary value assigned. Two options to allocate the energy related benefits should be analyzed:
4 1 i l
y p [
- 1. Distribute ' benefits based on an appropriate allocator such as loa.1 or generating capacity ratios.
- 2. Distribute benefits based upon contribution to a sale e displacement by a purchase.
i ) .. Capacity credits for purchases and capacity responsibilities for sale; j should be linked with the disposition of capacity revenues and will be
- dependent upon the type of transaction. It may be appropriate to trea:
a firm capacity ; transaction as a modification to load, categorized j similar to QF's for capacity equalization purposes. A unit specific ;
- or reserve transaction, on the other hand, may be more appropriately i
. handled as a modification to the member's resources. A' non-firm l transaction may require no adjustment with regard to capacity. The
- side agreement required by GPC to facilitate, or firni any transaction ;
y should be treated outside the normal GAPS accounting arrangements, i C. Recommendations All of the alternatives for participation in off-system transactions should be included in further analysis performed in Phase II-A. The - GAPS Agreement should be structured such that no individual's transactions adversely affect the system as a whole. The involvement of SCS will be coordinated through GPC. SCS will be responsible for 4 scheduling transactions and for determining what, if any, costs should be charged to the participants in a transaction. GPC would use its best efforts in coordinating all transactions with SCS and in ensuring that the operating and accounting practices employed by SCS, including
- _ = _ _ _
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. fees L charged fer implementing I transaction, are non-discr m natory.
- An ' individual member's: participation ~ in a GAPS member's transaction-could be; inadvertent' .'(by releasing' its units for dispatch, including O 'off-system transactions) . or. contractual . All transactions' should be considered firm over some established minimum time increment.
The Working Group recommends the following:
- 1. Side agreements will be required ' between GPC and the GAPS member addressing the . criteria -and cost associated with scheduling the
~ transaction- as well as making arrangements . to- support. the transaction over'a minimum time increment;
- 2. If units are released for participation in a GAPS member's transaction, the options- for the determination of responsibilities and allocation of benefits are:-
- a. load or generating capacity ratios;
'b. contribution to a sale or displacement by a purchase;
- 3. Under mutual reserve sharing arrangements, reserve transactions should be based on system reliability requirements, not those of an individual entity; a
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M 1 4If a member - desires to ' make - a unit specific transactl6n from' a co-owned anit, provisions' may 'be made to allow scheduling' a portion of.the unit while economically dispatching the remainder; y S. It may be appropriate that no capacity. responsibility be assigned to non-firm transactions. , Unit specific or reserve- transactions may be. handled as resource modifications. Firm transactions may be handitd as load modifications. 4
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. GEORGIA' POWER SUPPLY STUDY s
SCOPE WORKING GROUP Review of Issues E January 31, 1986
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?: Lil Scope Working Group Oglethorpe:- John Johnson Chairman Rob Carlton Ed Tatum MEAG - Bill Scott. John Hewitt. GPC - . Fred Paradise 1 L 0353W c.. u - - - - - _ - . ----__ _=_ _
k TABLE OF CONTENTS
.s l- Page P
I. SUNMARY'AND RECOMMENDATIONS A. Relationship to Southern Pool ............1 y B. Impact on Unit Dispatch' ...............1 l- C. Impact on Off-System Transactions ..........2 l II. STATEMENT OF ASSIGNMENT A. Project Management Team's original Charge. . . . . . . .'4 l B .~ Recommendations for Study in the Project Plan ....5 C. Working Group Interpretation . . . . . . . . . . . . . 5 g III. RELATIONSHIP TO SOUTHERN POOL p l A. I n t rodu c t i on . . . . . . . . . . . . . . . . . . . . . . 7 l B. Ev a l u a t i on . . . . . . . . . . . . . . . . . . . . . . 7 l C. Recommendations ...................9 IV. IMPACT ON UNIT DISPATCH
~
i A. Introduction . . . . . . . . . . . . . . . . . . . . 10
- 8. Eval uation . . . . . . . . . . . . . . . . . . . . . 10 C. Recommendations ..................13 V. . IMPACT ON OFF-SYSTEM TRANSACTIONS A. Introduction . . . . . . . . ... . . . . 15 .
B. Evaluation . . . . . . . . . . . . . . . . . . . . . 16 1 C. Recommendations ..................20 i 5- J I l 1
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SUMMARY
AND RECOMMENDATIONS en a 0353H
--~_-_- __ - _ _ _
p~ ~ wa . s; - 1 $UpmARY AND REC 0pW!NDATIONS The. Scope Working Group, consisting of. representatives 'of. the.' Municipal x Electrici- Authortty ofl Georgia, Georgia Power Company and .0glethorpet
- f. Power Corporation .has ' completed Its l investigation l of the ~ following l
areas:
- 1. Feasible Alternatives -in which the. Georgia Power Supply Agreement -
could operate within the Southern Pool.
,2. The method by. which future generating units could be treated in the Georgia Power Supply.
l
- 3. The method by which off-system transactions could be treated- in the
. Georgia Power Su? ply.;:
k E" This: document is the result of . one working group's review of ~ three : specific ~. issues relating to the , Scope of a Georgia . Power L Supply Agreement to succeed the current Partial Requirements-Tariff. 'The three issues should be. considered :as separates and independent and do
- not . encompass all lof.' the concerns of the- parties involved. This-document must'not'be interpreted:as a final statement of conclusions or..
c policy but simply as. a guide . for i further analysis. Nothing in= this report. is ;intendedLto change the rights and. obligations granted under
- the settlement agreement and license conditions relating to Plant Hatch and Plant -Vogtle. A critical area not addressed -by. this' document is; some form ofs commitment frem the current customers with regard to load and~ . capacity ' ' responsibilities before such an' agreement- can be consumated.'
Examination of these' areas led to the following recommendations
~A. Relationship To Southern Pool y (The Working Group examined alternative relationships ' between the Georgia' Power Supply and the Southe?n Pool and recommends that~ only '
t,he'following be-included in further analysis.
- 1. GPC represents the territorial load and capacity, but only its-
. own cost;within the Southern Pool;
- 2. GPC represents the territorial load, capacity and cost, including the cost'of the other Georgia Power Supply members; and 3.' GPC represents only its own. load,. capacity and ~ cost, excluding the capacity and cost of the~other Georgia Power Supply members.
This should not be construed to mean t' hat Georgia Power anticipates
- changing its relationship with the Southern- Pool . Furthermore, a decision to change its relationship with the Southern Pool is the sole prerogative of Georgia Power.
. A standard set of criceria was used to evaluate each alternative.
In summary all three present workable solutions to the relationship between Georgia Power Supply and the Southern Pool. The Working 0353W - 1, - m.
a Group recommends _ that all' further analysts performed in Phase II-A z be structured so ,as to' quantify the differences within the- . Georgia Power Supply.between the three alternatives.
- 8. Impact on Unit M spatch-Georgia Power. Company (GPC) through Southern Company Services -(SCS) will be responsible for the dispatch of the system as a whole regardless of the dispatch method selectedL by a Georgia Power Supply g . member for its future unit.
The Working Group examined < the following methods for' dispatch of a future unit:
- 1. Unit is submitted to SCS dispatch; L
- 2. Unit is ' dispat . led independently' but its output schedule is.
coordinated with SCS through GPC; and
- 3. Unit is dispatched independently and ite output schedule is not coordinated.with SCS.
The Working Group concludes that preferential accounting treatments-
-within . the . Georgia' Power Supply should be afforded to centrally dispatched ' units. over = independently dispatched' units. However, an
-independently dispatched unit whose schedule is coordinated with SCS and contributes to system requirements may be afforded treatment similar to a centrally dispatched unit.
C.: Impact on Off-System Transactions The following alternatives for participation in: off-system transactions should be included in'.further analysis performed in Phase II-A.
- 1. Off-system transactions entered into by the Southern System; only
- GPC resources contribute; and 4
- 2. Off-system transactions entered into jointly or individually by- .
members of Georgia Power Supply in which: .j
- a. only individual member's resources contribute; and b.'all Georgia Territorial resources contribute.
,, Accounting treatments should be structured such that no individual's transactions adversely affect the system as a whole. GPC through SCS will be responsible for scheduling transactions and for ; determining ' what, if any, costs should be charged to the l participants in a transaction. GPC would use its best efforts in i coordinating all transactions with SCS and in ensuring that the l operating and accounting practices employed by SCS, including fees charged for implementing a transaction, are non-discriminatory. 1 Participation in Georgia Territorial transactions by a ; Georgia Power Supply member may be inadvertent (by releasing its 0353H ! w_2__mr_ . _ _ _ _ _ _ . _ _ , -
. m a _ n=~
hl :- units - 'for. dispatch ' including off-system' transactions) or. contractual. The parties agree to investigate. sharing revenues above cost for L their uni ts. released to' serve off-system sales. The ci , role of GPC as' agent will b,e recognized in these discussions. P. .
~Acceptible ' options for the determination of responsibilities and-allocation of benefits are:.
- 1. load or generating capacity ratios; and
- 2. contribution to a. sale or displacement by a purchase.
1 . a 0353W -__ - __. _ _ . .__=_____ . - _ . -- - x - .w .
7v'vww----w- )l:: I' II. STATEMENT OF ASSIGNMENT k e
- - -"~ - - L- . . ~ , . _ _ .______ _ _ _ _ _ _ _ _ _ _ _ ]
u II. STATEMENT OF' ASSIGNMENT [ [ The Scope Working Group ' relied on two sources - to formulate its charge. the Project Management Team and the Project Plan, y The following are excerpts from Project Management Team memoranda and the Project Plan, developed on a theoretical basis, and do not represent conclusions of the working group. (The name Southern Pool Relationship Working Group in these memoranda refers to the Scope
. Working Group.)
A. Project Management Team's Orictnal Charge By meno dated April 12, 1985, the Project Management Team delivered the.following charge: The Southern Pool Relationship Working Group will investigate feasible alternatives 'in which the " Georgia Pool" could operate within .the Southern Pool . As a minimum, the group will address the following alternatives:
-(1) All. parties are members of the Southern Pool.
(2) Georgia Pool operates as a subordinate of the Southern Pool. (3)' Georgia Pool operates independently of the Southern Pool. (4) Other alternatives as determined by Working Group. Each alternative should be evaluated with regards to: (1) Feasibility. (2) Degree of adherence to Southern methodology. (a) Recognition of capacity. (b) Rating of capacity. j (c) Treatment of existing contracts (E, etc.). (3) Determination of responsibilities. I (4) Allocation of benefits. l (5) Other criteria as determined by Working Group. i The Chairman of the Working Group will provide the Project Management Team with written status reports following each of the Working Group's meetings. The final written report viii be delivered to the - Project Management Team no later than May 17 1985. - The report will be reviewed at a Project Management Team . meeting on May 23, 1985. j l 0353W i l __.wm_.__im__h-_.A _ _. .. .. .. .s ..u'%.*
~ During the May 30, 1985 meeting of the Project Management Team it was decided that the Scope Working Group should add the following to its charge:
I p
- 1. Investigate .means _of: communication with Southern dispatch office of~ a non-Southern member' who might desire Southern dispatch of its wholly owned. unit. How would benefits flow to the owner if benefits occurred under the' Southern' Company System IIC?
(--
- 2. How would off-system sales or purchase of non-Southern _ owned b units be handled under the various options studied?
- 8. Recommendations for Study in the Project Plan Two feasible alternative ways in which the Georgia Pool could 7 operate within the Southern Pool were discussed by the Project Team:
r
- Continue relationship-through Georgia Power Company.
- Operate as a member of the Southern Pool.
- With the n first alternative, the membership and operation of the r Southern Pool would be relatively unchanged by this agreement. With the second- alternative, the Georgia Pool would designate a representative to the Southern Pool which would act on behalf of all parties to the Georgia Pool agreement. Unanimous agreement. of the j members of the Southern Pool would be required in the second alternative.
Under either alternative there are several issues that impact the Southern Pool and must be addressed. These include:
- Application of Southern Pool dispatch procedures to generation
-operated by non-Southern entities.
- Treatment of each party's capacity and energy in the Southern Pool.
- Off-system sale of each party's capacity and energy.
C. Working Group Interpretation Evaluating the Project Management Team's original charge in conjunction with the alternatives set forth in the Project Plan, the Scope Working Group developed the following interpretation of its charge: The Scope Working Group will:
- 1. Investigate feasible alternatives in which the Georgia Power Supply could operate within the Southern Pool.
0353W xxu . _- - - - i
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- 12. Investigate) ways by .wh1ch . future: generating.' units .could. be
& T treated in the Georgia Power Supply.
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e y, gj J: '.-3 . : Investigate : ways by which_ off-system : transactions could be: 4sg + < treated in the Georgia Power Supply;. I.. e>
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j/ i-III. RELATIONSHIP TO SOUTHERN POOL A a G. b l t I i l h-1 1 l l 4 1
III, . RELATIONSHIP TO SOUTHERN POOL A. Introduction t.
~
The ' Scope' Working Group will- investigate feasible' alternatives in which the Georgia Power Supply Agreement could operate within the Southern Pool'. - The' original question put forth in Phase I of this project was whether GPC or another . entity should represent members y of the. Georgia Power Supply in its relationship with the Southern Pool, Discussions in .the working group have eliminated all alternatives _ except those in which GPC_ is the _ representative. The alternatives put forth by the working group are variations of this GPC representation theme. y This should not be construed to mean that Georgia Power anticipates ' changing its relationship with the Southern Pool. Furthermore, a decision to change its relationship with the Southern Pool is the sole prerogative of Georgia Power. The three alternatives are as follows:
- 1. GPC represents the territorial load and capacity, but only its own cost, within the Southern Pool (Current Representation);-
- 2. GPC represents the territorial load, capacity, and cost, including ' the cost of the other Georgia Power Supply members
- p. (Territorial Representation); and
- 3. GPC represents only its own load, capacity, and cost, excluding
_ the capacity and load of the other Georgia Power Supply members (GPC Only Representation). ,
-B. Evaluation j
- 1. Feasibility It appears that all three alternatives are feasible at this time reflecting GPC's virtually unchanged relationship within the .iI Southern Pool. _ Territorial or GPC Only ' Representation may require modification to the Southern Company System IIC and thus approval by FERC and the Southern Company operating companies. l Hith regard to GPC Only Representation, this group recommends !
that "GPC Only" load, capacity and cost be more explicitly defined in a later phase of the project. ~
- 2. Degree of adb'rence e to Southern's methodology ~l l
With regard to the recognition of capacity and energy, rating of I capacity, and treatment of existing contracts, Current { Representation or Territorial Representation would typically be ' in agreement with the Southern Pool methodology. GPC Only Representation, however, could represent significant divergence from the existing r.;ethodology. Under this alternative the other 0353W l
members of the Georgia Power Supply would no longer be represented in the Southern Pool and would no longer be
- f. constrained by the Southern Pool's methodology. Any significant deviation, however, may be challenged by interveners and may result in mandated compliance of the IIC or the Georgia Power' Supply to the other's methodology - as well as placing an additional administrative burden on GPC.
- 3. Determination of responsibilities E Responsibilities and corresponding costs associated with capacity and energy exchanges must be tailored to the specific alternative. It may be appropriate that some level of responsibility be assigned to all parties regardless of whether their capacity and load are " represented" in the Southern Pool.
The responsibilities associated with operating and dispatching the system should be addressed in a later phase of the project. These responsibilities should include operating reserves and deviations from computer dispatch to preserve the integrity of the system. r
- 4. Allocation of benefits The parties agree that the allocation of benefits associated with capacity and energy exchanges should follow the determination of responsibilities. The parties recognize that there are intangible benefits which will flow to all the parties due to interconnected operation, regardless of the contract L,
structure.
- 5. Southern Company Services (SCS) or other operating company involvement For Current Representation, since the relationship is virtually V unchanged, there may be no need for the involvement of SCS or the other operating companies in the development of the
. Georgia Power Supply. Since the present IIC methodology will be changed under the other alternatives, some involvement by SCS or the other operating companies may be needed. SCS may be involved in analyzing any preposed agreement with regard to the impact on the other operating companies and may act as their agent in proceedings before FERC. For all alternatives. SCS will be responsible for the operation of the system, administration of the IIC and the preparation of budgets. If Territorial or GPC Only Representation is chosen, there may be additional involvement by SCS once the agreement is t implemented. . This involvement may consist of auditing the territorial cost for the other operating companies or auditing the. methodologies used to determine the separation of load and capacity within the Georgia Territory.
- 6. Impact on accounting systems Accounting systems will be impacted whenever the current representation is changed by either adding the co-owner's cost 0353W ,
-_-_..n____x_... . .x.: .n . .
$I or. removing some amount of capacity and load from GPC's responsibility' within the Southern System. These changes = will not necessarily be limited to direct charges, but may involve i procedures for charging the co-owners for benefits derived from k cogmon dispatch and joint planning. For Current or Territorial Representation, the accounting system developed for the Georgia Power Supply will probably be driven by. the accounting system of the Southern System. ( The Georgia Power Supply's accounting system recognize the flow of costs and benefits from the Southern must clearly Pool. It would not be unreasonable to expect the Georgia Power Supply's accounting system to mirror the accounting system of the Southern Pool. For GPC Only Representation, the flow of costs and benefits within the
, Southern Pool is clearly a GPC responsibility. The Georgia Power Supply's accounting system must clearly recognize the Southern Pool transactions by. GPC and be able - to remove, without adverse effects,.those transactions which are not serving Georgia Territorial load. In thi s regard,, it may be necessary for the other Georgia Power Supply members to receive Southern Pool transaction information to ensure that the flow of dollars between GPC and the other Southern Pool members is properly recorded.
- 7. Contractual arrangement None of the alternatives require a direct- contractual arrangement between the Southern Pool and the Georgia Power Supply. However, the other Georgia Power Supply members may
- require a contractual arrangement with GPC which clearly outlines the flow of costs and benefits from the Southern Pool, p C. Recommendations All three alternatives present workable solutions to the relationship between the Georgia Power Supply and the Southern Pool. The Working Group recommends that all further analysis performed in Phase II-A be structured so as to Quantify the differences within the Georgia Pcwer Supply between the three alternatives. Areas which should be specifically addressed in this analysis include:
1 .. Determination of cost for non-Southern entities to be used in the Southern Company System IIC if Territorial Representation is
- selected;
- 2. Determination of GPC "Only" load and capacity if GPC Only Representation is selected;
- 3. Responsibilities associated with operating and dispatching the system;
- 4. Accounting and allocation of the flow of dollars between the Georgia Power Supply and the Southern Pool.
0353W _ _ _
a .. . IV. IMPACT ON UNIT DISPATCH 4 i r 6 K f. {- - _
J' IV. IMPACT ON UNIT DISPATCH A. Introduction a The Scope Working Group will investigate ways by 'which future generating units could be treated in the Georgia Power Supply Agreement. p Three alternatives with regard to the dispatch of a future unit will be examined:
- 1. Unit is submitted to SCS dispatch (coordinated for maintenance, etc.).
l s 2. Unit is dispatched independently but its output schedule is coordinated with SCS through GPC.
- 3. Unit is dispatched independently and its output schedule is not coordinated with SCS.
It is obvious that'a GPC owned generating unit would be submitted to I SCS dispatch; therefore, the discussion of other forms of dispatch j refers to non-GPC owned units. A major area which this working group does not address, but should be. addressed in a future phase, is the approval of a future generating unit as a Georgia Power Supply resource (i.e., the joint , a planning process). The operating companies' of. Southern have the sole authority to determine if a future generating ' uni.t qualifies as
. a Southern Pool resource. It is assumed .for the purposes of this i working. group, that a future' generating unit in question, has gone through the joint planning process and has been accepted as a Georgia Power Supply resource and a Southern Pool resource.
This discussion excludes small power producers and facilities that are primarily dispatched for other than electrical production (i.e., cogeneration). B. Evaluation
- 1. Southern Company Services (SCS) involvement i
SCS will be responsible for the dispatch' of the system. To accomplish this task, they shall require telemetry of the unit's , output at the high side bus or from the low side with a mutually ' agreed upon adjustment to the high side. .. If the unit is submitted to SCS dispatch, it will be dispatched i the same as any other Southern System unit. SCS would need to put 1 a control signal into the unit and would need appropriate j incremental cost and operating data to economically dispatch the l Unit. This would increase the effort required to maintain SCS's l 0353W 1 1
- u. _. - _______-____a
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data base. If the owner elects not to load or cut the Unit when
' dictated -by SCS's- dispatch program, appropriate accounting-penalities within the Georgia Power Supply. should be imposed (i.e.,
y frozen units).
- The sc7:edule, for an independently dispatched' unit whose output is to . be coordinated with SCS, will have to be coordinated 'through GPC. This would ' increase the information flow to the SCS dispatchers and the number of separate schedules entered into the 4 central dispatch computer. The owner will provide SCS with an
' anticipated schedule of the unit's output for ' a period consistent with SCS's uni t commitment program (7 days). SCS may propose a modified schedule, if they desire, and the parties will alternately propose schedules 'until a mutually acceptable schedule is derived. Schedules may be reviewed daily with additional runs of the dispatch program. A unit which is dispatched independently and treated by SCS as an uncontrolled tie flow, requires no. direct involvement by SCS in dispatch. However, SCS must know the input to the system from that unit to properly determine the loads of its operating companies and s the Georgia Territory.
- 2. $1mplicity .
Simplicity deteriorates as one goes from centralized dispatch to independent dispatch. From a dispatching perspective, having all units ' dispatched by SCS would require the least modifications in normal operating procedures. Scheduled independent dispatch will require the most coordination between SCS and the owner, but should 2 be relatively easy to implement within the current dispatch logic. Non-scheduled independent dispatch may adversely affect SCS's ability to regulate the control area, although, from the owner's perspective, it may require the. least expense and involvement with }- SCS.
- 3. Administration
- a. Accounting requirements The Georgia Power Supply's accounting requirements will be driven by the allocation of benefits and responsibilities. A unit's accounting requirements should vary little between the alternatives.
- b. Operating data requirements SCS dispatch requires the greatest amount of operating data.
For. example, heat rate equations, high/ low limits, response rates, replacement fuel costs, variable O&M rates, and fuel handling rates are required for computer dispatch. All alternatives may require telemetry of the anit's output and approved adjustments to determine the unit's net input to the transmission system. The owner of the generating unit may 0353W =- _ _ = - .. -
desire the above operating data as well as data about its own load 'and the Southern System's costs in order to more effectively dispatch its unit. The availability of this data ) will be dependent on the form of the Georgia Power Supply Ag,r,eement developed.
- 4. Acceptability
- a. Regulatory Regulatory acceptance will be most favorable toward the alternative which produces the least cost system. Although it would appear that the least cost system would be produced by central dispatch, regulatory agencies view participation in centralized dispatch as a voluntary decision. All of the
, alternatives should be acceptable to regulatory authorities given an appropriate allocation of benefits and responsibilities.
- b. Georgia Power Supply members The Georgia Power Supply accounting procedures need to be
. sufficiently flexible to allow an entity to independently dispatch -a ' unit for reasons of non-conforming fuel sup-ly, take-or-pay fuel contracts or to fulfill a unit specific off-system transaction while protecting the cost structure of the other members.
" The acceptability of each Georgia Power Supply member will depend on its opinion of each alternative to produce the least cost and maximum benefit (i.e., back-up energy for an .
- independently dispatched unit). The knowledge needed to form this opinion. will not be available until specific accounting treatments for each alternative are known.
- 5. Determination of responsibility Units submitted to SCS dispatch should be treated the same within -
the rules developed for the Georgia Power Supply. The owner will be res6onsible for providing the data necessary to dispatch its unit and for performing appropriate heat rate and response rate tests to assure the validity of its dispatch data. The owner's unit will be expected to contribute to the system's dispatch requirements including unit commitment, regulation, operating reserves, maintenance scheduling, etc. The owner will also be expected to contribute to the costs associated with dispatching the system. A unit whose output schedule is coordinated with SCS may, under the folicwing condition, be treated the same as a SCS dispatched unit within the Georgia Power Supply. It is expected that the unit will be made available ed dispatched above its intended schedu'e when the system requires it to avoid more expensive types of fuel or off system purchases and during emergency conditions. However, it is recognized that situations exist beyond the control of the owner which may prohibit its unit from responding to system requirements 03S3W . . .
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i (i.e., environmental limitations, fuel.. limitations, transmission limitations < or a' unit whose primary output 1s not electrical). The Working Group. recommends that under such conditions the owner should q not;be penalized. Since the unit is scheduled and 1s not available t to contribute to system regulation, etc., the owner may be expected to. contribute monetarily to the cost associated with scheduling the
. unit and regulating the system. It may be appropriate that all or a portion of the energy generated by a scheduled unit be retained by the owner, and be ' unavailable for sale within the Georgia Power g Supply.
An independently . dispatched, non-scheduled unit contributes virtually nothing to the- system's integrity and may hinder the l' coordinator's ability to regulate the system. Rather than a capacity credit, 'the unit may be assigned a - load responsibility.
. The cost of replacing the unit's output during an outage or deration should not be . priced the same as load served within the Georgia Power Supply. An approved unit should be given preferential treatment over an- unapproved unit. The owner will be expected to contribute monetarily to the regulatior' of the system. ,
- 6. Allocation of benefits The flow of benefits should be to the entity who assumes the risks and the- costs of the unit and should not be affected by the method of dispatch except to protect the other members. Benefits.are best allocated by the determination of capacity credits. The benefits associated with regulation, etc., flow to. all parties in an interconnected system regardless of the alternative.
C. Recommendations Assuming the Southern System will remain one control area including the Georgia Territory regardless of the dispatch method selected by
^ a Georgia Power Supply member for its future unit, the Working Group recommends the following:
- 1. A procedure for approval of a future unit as a Georgia Power Supply resource needs to be developed. An approved unit should receive preferential treatment within the Georgia Power Supply for reserve capacity and backup energy over a non-approved unit;
- 2. Since centrally dispatched units contribute the most to the system, they should be afforded preferential treatment in the Georgia Power Supply accounting methodologies;
- 3. The Georgia Power Supply accounting system should recognize that an independently dispatched unit contributes less to the system as a whole. If an independently dispatched unit's schedule is coordinated with SCS, and it is made available to the system under certain specified conditions. It may be afforded accounting treatment within the Georgia Power Supply similar to a centrally dispatched unit;
- 4. The owner of an 1. independently dispatched unit should be expected to contribute monetar'lly to the cost of regulating the system; 0353W t
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,.,/yJ' l' ' - 5. Itn may be. appropriateithat all or a - portion .of tho' energy generated k; % by an^ Independently dispatched. unit:be retained by;the owner and be..- unavailable for sale within the Georgia Power Supply. A' . 6 .m p i-! p. f, t t \ 1 h s 4 P 3 r q.
- 5. ?
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V. IMPACT ON OFF-SYSTEM TRANSACTIONS ?; an. l' t W [. - _ _ _ _ _______ ___ _
V. IMPACT ON~0FF-SYSTEM TRANSACTIONS 3 A. Introduction' The Scope- Working Group will investigate ways by which off-system
. transactions could be treated in the Georgia Power Supply Agreement.
For off-system transactions entered into by: )
- 1. The Southern System; only GPC resources contribute.
- 2. Georgia Power Supply members, either individually or jointly.
- a. Only individual member's resources contribute.
- b. All Georgia Territorial resources contribute.
- 1) Inadvertent contribution.
- 2) Contractual contribution.
With a . pool form of agreement or other arrangement involving central economic dispatch, interchange among members is typically automatic and settlement is typically accomplished after-the-fact. Off-system transactions, on the other hand, are . typically arranged and priced before-the-fact and some effort is usually required to implement them. None of the alternatives can be eliminated from the study as the future agreement cannot be allowed to restrict any member from entering into an off-system transaction. For some alternatives and 'some types of transactions, it may be difficult to structure a Georgia Power Supply Agreement which allows complete individual member flexibility in making off-system transactions while not interfering with the efficiency of 3 automatic interchange among members. No unilateral action taken by an ~ individual member to the agreement must be allowed to be a detriment to the system. For this reason, each treatment must provide for 1) . the determination of all appropriate identifiable costs associated with the transactions and 2) the allocation of those costs to the member (s) accepting responsibility for the sale. The members' to the agreement should recognize the costs associated with an off-system transaction involve more than just fuel and variable O&M. Off-system transactions are typically easiest to complete between electric systems that are directly interconnected and have their own control areas. A more difficult transaction to complete is one with a control area that i s more than one system away. Perhaps the most difficult transaction to arrange and complete is where both systems are in separate control areas and one or both are embedded and do not have real-time Information and control capability. This typically involves scheduling through an agent who may be in competition with the emoedded 0353W .
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y k , system. . ; The . discussion , of the. alternatives for . the L following transactions- is based' on the' assumption ' that real-time coordination would be maintained by SCS. .
b .. .
.For all alternatives of this Charge the Working Group must consider:
- 1. Non-firm . transactions -: Purchases to -off-set more expensive.
generation.- The purchaser is responsible' for. reserves. These
, transactions, come from a mixture- of. system units 'and are recallable
% prior'to native load being shed. Firm ' transactions .- Capacity needed to meet load or toff-set 'more
'2 expensiveL generation.. The ' seller is responsible for reserves.
-Serviceis inot ~ 1nterruptable except under limited conditions (i.e.. .
.similar to native loads). Firm transactions do . note come from p specific unitsk 4
- 3. Unit-specific. transaction 2 A contractual right, 'without> ownership, to a portion of ' the output of. a particular generating. unit. 'It is.
non-firm. . The': sale should ~ not increase: the cost of serving the nativeL load and the unit sold must' be excess to - the native load:
- - requi rements.' '
- 4. Wheeling - The transfer of power ad energy > from a non-Georgia' Power -
Supply member? to: another non-Georgia Power Supply.= member. The
' Working Group, will address the use of : capacity and energy..to
. facilitateewheeling transactions. '(The ITS . group . will address the' use of:the transmission system for_ wheeling.)
5; Treatment of. inadvertent exchange The difference between the..
.. ' schedule on a' tie-line and the actual flows across the tie-line.
The Working ~ Group recognizes that inadvertent exchanges exist but
~
recommends that a uniform treatment of inadvertent flows ' not he , : dictated by"the Georgia Power Supply Agreement. - Inadvertent flows should be addressed by the parties to the transaction and SCS'on an individual' transaction basis, if possible.
- 6. Reserve transactions - Capacity purchased. to improve the system's-
' ~
reliability but not needed to meet the system's anticipated load. B'. Evaluation
- 1. Southern Company Services (SCS) involvement l
, . The involvement of SCS will be coordinated through' GPC. SCS will be , responsible for scheduling the. transactions and determining what, if d any, costs should be charged the. participants in a transaction. GPC '
would use its' best efforts in coordinating all transactions with SCS and in ensuring that the ~ operating and accounting practices employed < by SCS, ' including fees charged for implementing a transaction, are non-discriminatory.
- 0353W- ~_ _ . _- .
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Non-fire - transactions are typically predicated on knowing the: real-time : generation,- load and. marginal . cost at the- time of interchange. SCS would : be involved in non-firm transactions as scheduler and accountant. [ Firm transactions ~ ' tend to- be individually initiated and are-typically treated as Ioad modifications. A firm ' transaction would-be scheduled by SCS and Georgia's load would be. modified- hourly by the firm . transaction before re-dispatch. The seller. however, must s make suitable arrangements with the purchaser to ensure the firmness of the transaction. True wheeling is a transmission service which would normally be negotiated and contracted with an individual Georgia Power Supply member. SCS would only need to be involved in scheduling and loss. accounting. For embedded systems, inadvertent energy accounting tends' to be contract specific and should be addressed by the parties to the transaction. The treatment should be based -on accepted ' utility interconnected operating practice.
"a The capacity. side of the reserve transaction would normally be arranged .by an individual entity for a specific reliability-purpose. In a mutual obligation reserve sharing arrangement' 'a reserve. transaction should be predicated on system reliability requirements and not those of an individual entity. The energy scheduling and accounting would be similar to a non-firm transaction.
- 2. Simplicity-
~
Simplicity is greatly dependent upon the type and size of a transaction. Currently, schedules are committed on an hourly
, basis. The minimum time and MW increment available to be scheduled must be addressed on an individual transaction basis by the parties to the- transaction. The seller, however, must makel suitable
, arrangements with the purchaser to ensure the. firmness of any transaction over the established time increment. i Since non-firm transactions are based on central economic dispatch, the energy associated with non-firm sa~les can routinely be traced to i individual units. The accounting within the Georgia Power Supply should address not only the costs associated with this energy but -)
also the revenues associated with these sales. J l Assuming Territorial resources are contributing to a j Georgia Power Supply member's transaction, the following methods of ' distributing revenue are possible: J
. 1. Revenues are distributed based on load or generating capacity ratios and energy is purchased at cost from the other members.
l
- l. 2. Revenues are distributed based on the e'nergy contributed to the i transaction.
0353W j
..--_.--~_-.bE.N..-....,_.L._. - - - - - _-I.'._.--
- .. A a _ma._. a .,_n. A~ -.
- -Uls ..Da-
. Existing ownership agreements covering central economic dispatch obligations of co-owned units' may' complicate the use of co-owned units in making off-system unit specific sales. Provisions for scheduling portions of co-owned units while economically dispatching the remainder -
K would facilitate their use in unit specific sales. Arrangements to complete lhe transactions when the specified unit is unavailable should be treated depending on the terms of the transaction. Nithin the established . time increment,- a wheeling transaction should be y' . treated as a simultaneous firm buy / sell transaction by the Georgia Power Supply. When reserves are shared in a centrally dispatched operating e arrangement, individual off-system reserve transactions, without specific guidelines based on system reliability requirements, can ., adversely impact the reliability and/or costs of the other members. I
- 3. Logistics of implementation.
- a. Accounting requirements.
The - accounting requirements . between the off-system party. and the Territory should be easily implemented. However, an agreement to facilitate the ' transaction must be implemented between the Georgia Power Supply member (s) and GPC. This agreement should address situations when a transaction is scheduled and carried out, but the Georgia Power Supply member is unable to meet its commitment.
- b. Operating data requirements Operating. data requirements may be as sincie as NW telemetry of any delivery / receipt points (including generation buses) involved with the transaction. However, if the price of the transaction varies with system or unit dispatch, all of the appropriate dispatch
~ parameters must be available.
- 4. Acceptability
- a. Regulatory Within the Georgia Power Supply. regulatory acceptance will pivot on sound engineering and economic practice. Regulatory review will involve the terms executed with the off-system party and the treatment afforded the transaction within the Georgia Power Supply.
The practical ability to complete off-system transactions free from operating complications and discriminatory treatment may also be P issues for regulatory review. 1
- b. Georgia Power Supply members Acceptability by the Georgia Power Supply members will depend on the equitable treatment each member receives.
- c. Third party 0353H :- __ . _ - - _ - _ __ x -
Acceptance by - a - third : party' will be based on economics and his L, perception of the capability of. the Georgia Power Supply member (s) to. follow through with the. transaction. f 5. Determination of responsibilities
~
l
.The scheduling of transactions will be the responsibility'of 'SCS and be coordinatedLthrough GPC. It. is the= Georgia Power Supply members' responsibility to. arrange with GPC for the dispatch and scheduling of e independent transactions they wish to execute. Side agreements will be F required between GPC- and the affected Georgia Power Supply members.
These side agreements will vary depending upon the type of transaction and must recognize that ' transactions are scheduled for .a minimum time
-and MN Increment. Therefore, a member must make arrangements to support the transaction'over the minimum time increment.
' Alternately,. if a member's units are released for_ use in a Georgia Power Supply . member's off-system transaction, that member accepts. responsibilities determined by one of the following methods:
- 1. Responsibility is based on load or generating capacity ratios.
- 2. Responsibility is -based on contribution to a sale or displacement by a purchase.
The premise behind off-system. sales within the Georgia Power Supply Agreement should be that nothing sold off-system should cause a detriment to the territory as a whole. If all partier, agree that the transaction is in the best interest of the system, then all parties - should share ' the risks of that transaction. If a party desires _ to proceed _ with a. transaction without the concurrence of the other parties, then that party should incur all the risks associated with that transaction (i.e., off-system ' sales should not be replaced by purchases under the Georgia Power Supply Agreement). 6.. Allocation of benefits Each treatment for an off-system transaction should recognize the # degree to which responsibilities are shared and allocate benefits accordingly. D The benefits associated with off-system transactions are essentially capacity or energy related. Capacity related benefits promote a more economical use of system resources through either selling surplus capacity to_ realize an additional return on the system's investment or through purchases to avoid additional investments. Energy related benefits are structured to relieve the system of some burden (i .e., ; controlled burn energy), share the savings _ associated with avoiding the j use of high cost energy, or improve the operating characteristics of 1 the system (i.e., valley load problems and thermal cycling). Some of these benefits are difficult to quantify monetarily and will flow to all parties in the interconnected system. Other benefits have a direct ! monetary value assigned. Two options to allocate the energy related ' benefits should be analyzed: l 0353W. '
== . x-
l'. DHtribute benefits based on an appropriate ' allocator such as load or generating capacity ratios, p 2. Distribute benefits ' based upon contribution to a sale or i i l' ,
..displac,ement by a purchase.
Capacity credits for purchases and capacity responsibilities for sales should be linked with the disposition of capacity revenues and will be i dependent upon the type of transaction. It may be appropriate to treat ' L a firm capacity transaction as a modification to load, categorized l similar .to .QF's. for capacity equalization purposes. A unit. specific I or reserve transaction, on the other hand, may. be more appropriately handled as a modification to the member's- resources. A non-firm transaction may require no adjustment with regard to capacity. The side' agreement required by GPC to facilitate or firm any transaction 3: should be treated outside the normal Georgia Power Supply accounting-
- = arrangements.
C. Recommendations All of the alternatives for . participation in off-system transactions should be included in further analysis performed in Phase II-A. The >- Georgia Power Supply ogreement 'should be structured such that no individual's transachoff idversely affect the system as a whole. The involvement of SCS will be coordinated through GPC. SCS will be
. responsible for . scheduling transactions and for determining what, if any, costs should be charged to the participants in a transaction. GPC would use its best efforts in coordinating all transactions with SCS and in ensuring that the operating and accounting practices employed by
. SCS, including fees charged for implementing a transaction, are non-discriminatory. An individual member's participation in a Georgia Power Supply member's transaction could be inadvertent (by releasing its units for dispatch, including off-system transactions) or
, contractual. All transactions should be considered firm over some established minimum time increment.
The Working Group recommends the following:
- 1. Side agreements will be required between GPC and the Georgia Power Supply member addressing the crite_ria and cost associated with scheduling the transaction as well as making arrangements to support the transaction over a minimum time increment;
- 2. -If units are released for participation in a Georgia Power Supply member's transaction, the options for the determination of
( r responsibilities and allocation of benefits are:
- a. load or generating capacity ratios;
- b. contribution to a sale or displacement by a purchase;
- 3. Under mutual reserve sharing "~rangements, reserve transactions should be based on system reliability requirements, not those of an individual entity; 0353W '
m m m_ . - - - _ _ _ - . _ _ __ _ _ _
o., o-
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- 4. If a- member desires to make a unit specific.' transaction from a co-owned unit, provisions may be made to allow scheduling a- portion of the. unit while economically dispatching the remainder;
- 5. It may be appropriate that no capacity responsibility be~ assigned to' non-firm transactions. Unit specific or reserve transactions may be
. handled as resource modifications. Firm transactions may be handled as load modifications.
k F h r . a. I-r 0353W _
c
.,s,., . ,
lc I Interconnection Agreement
- between L
- - - - - - Alchema Electric Cooperative, Inc.
H. N ~
- and Oglethorpe Power Corporation s
- TABLE OF CtNTENTS '
u Page 1.0 Service Obligations . . . . . . . . . . . ._ . . . . . . . . . . . . . , ,1 (. 1.01 Services to be' Rendered .......................I'- 1.02 : Initial Service' Schedules .....................1 1.03 Changes in Service Schedules . . . . . . . . . . . . . . . . . . 1 1 - % 2.0 Service Arrangements: ....................... 1 2.01. Operating. Committee . . . . . . . . . . . . . . . . . . . . . . 2
~2.02 Interconnection Facilities . . . . . . . . . . . . . . . . . . . 2 2.03_ Metering . . . . . . . . . . . . . . . . . . . . . . . . . . ...
2 2.04 Operating Responsibilities . . . . . . . . . . . . . . . . . . . 4 2.05 Wheeling. Responsibilities ......................3 3 2.06 Cperating Standards ....................... 3.0. Scheduling .............................A 4 3.01 Specification ......................... 4 + 3.02 Methodology '. . . . . . . . . . . . . . . . . . . . . . . . . . 4.0 Limits of Liability . . . . . . . . . . . . . . . . . . . . . . . . . A 4 4.01 Force Majeure ......................... 5.0 Billing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 5 5.01 Schedule of Payments . . . . . . . . . . . . . . . . . . . . . . 5 5.02 Maintenance of Records . . . . . . . . . . . . . . . . . . . . . . 6 4 5.03 Billing Meters . . . . . . . . . . . . . . . . . . . . . . . . .
........ 6 5.04- Consolidation ................. 6 F :5.05 Applicability to Schedules . . . . . . . . . . . . . . . . . . .
6.0 Term ...............................6-7 7.0 . Termination . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.0~ Agency .............................. 7 9.0- Indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . s 1 01851. 1
- I m . 1
c. 10.0 Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
~10.01 No Deley_. . ... . . . . . . . . . . . . . . . . . . . . . . . .
8- ' 9 10.02 Further Executions . . . . . . . . . . . . . . . . . . . . . . . 9 10.03 Governing Law . . . . . . ... . . . ... . . . . . . . . . . . . 9
'10.04 Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 10.05 Section Headings.Not to Affect Meaning . . . . . . . . . . . . .
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9
- 10.06 No Partnership.. . . . . . . . . . . . . . . . . . . . . . . . .
. . . . 10 10.07 Amendments . . . . . . . . . . . . . . . . . . . . . . 10 10.08 Counterparts . . . . . . . . . . . ... . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . 11 SIGNATURE PAGE . . . . . . 12 APPROVAL 7 RLRAL ELECTRIFICATICH ADMINISTRATICH . . . . . . . . . . . .
SERVIE SCEDULE "A" . . . . . . . . . . . . . . . . . . . . . . . APPENDIX A SERVIE SCEDLLE "B" . . . . . . . . . . . . . . . . . . . . . . . APPENDIX B SERVIE SCEDULE "C" . . . . . . . . . . . . . . . . . . . . . . . APPENDIX C SERVIE SCED1E'"D" . . . . . . . . . . . . . . . . . . . . . . . APPIDOIX D SERVIm SCEDLLE "E" . . . . . . . . . . . . . . . . . . . . . . . APPENDIX E a V e 4 n . O O s
~
01851 11 L
p~ f . ( . L
' THIS AGREEENT, dated as of the Ap_ day of &febe#" , 198A, between
- s. AUSAMA S.ECTRIC C0(PERATIVE, 12. , en elec;ric cooperative organized and P- texisting under the laws of .the State of Alabama (AEC), and OGLETHORPE POIER CORPORATION, en electric cooperative organized and existing under the laws of-the State of Georgia (OPC).- (AEC and OPC hereinafter collectively called the
" Participants".)
WITtESSETN [ AEC and CPC are generation and transmission i. g eratives engaged in the production and supply of electric power and energy to their respective members located in the States of Alabama and Georgia. The Participants desire by this Agreement to establish a contractual basis for the Intercontaction of their s electric systems -and for the direct and indirect excMnge of electric power and energy. NW, TEREFGtE, in consideration of the premises and the mutual agreements herein set forth, AEC and OPC hereby agree as follows: 1 1.0 Service 211ostions. - 1.01 . Services to be Rendered. A. Each Participant. will provide, on an as available~ basis, electric power and energy requested by the other Participant in accordance 1 with the Service Schedules provided for herein. 1.02 Initial Service Schedules.
~
A. The initial Service Schedules indicated below are attached to this Agreement and incorporated herein by reference: w Service Schedule A - Emergency Energy Service Schedule B - Short Term Power and Energy } Service Schedule C - Economy Ene my Service Schedule 0 - Wheeling (Transmission) Service Service Schedule E - Maintenance Energy 1.03 Chances in Service Schedules. A. The Participants contemplate that the initial Service Schedules provided for above may from time to time be amended, modified,- deleted entirely or that new Service Schedules may be added. Each both such change will be effective only upon agreement' by Participants and, when agreed to, will be fully incorporated into the terms of this Agreement. l
. I 2.0 Service' Arrangements. l 2.01 Operatina Committee. ,
A. Each Participant shall designate a representative and an alternate for an Operating Committee wnich will meet annually and more often if requested by either Participant. 1 _ . _ . J
- y ,
L B. Participants.- on; the ' Operating. Committee will coordinate operation. " under'this. Agreement, . including - the establishment ' of operating and maintenance procedures, pursuant.to the Service Schedules hereunder. Further, this Committee shall ' be the : appropriate form for the ~ discussion of all issues regarding this Agreement. C. The . Operating- Committee shall be responsible for. periodic review- of 3~ current .and: future generation, transmission and interconnection
. plans as they may affect this Agreement.
n l
- 0. This Constittee shall have no power to modify the terms of this Agreement'or..any Service Schedule hereunder.
2.02 Interconnection Facilitias. A. The. initial; point '.of interconnection shall be, at the . Walter F. George ' Substation.1 The Participants understand that- this initial point of interconnection may be changed or that additional points of
-interconnection may be added. Any deletion or addition of any point -
"' ..of. interconnection must be agreed to by both Participants. 2.03 Meterina. A.' Each Participant,: at its cost, shall provide all necessary metering n equipment at each interconnection point. Each Participant, shall be responsible for the operation and maintenance of such equipment. B..The metering! equipment shall be used for billing purposes, and..will measure and record: ) y' (a) "in" and'"outa kilowatt-hours per clock hour, " (b) ain" and "outa kilovar-hours per clock hour, and (c) "in" and "out" total kilowatt-hours at these 1 interconnection facilities. C. Each Participant, upon request, shall provide the interconnection data recorded at its interconnection facility. D. Each Participant will be responsible for supplying such data as may be necessary to their respective control centers. 2.04 Ooerstino Responsibilities. s A. Each Participant shall. be responsible for the operation and maintenance of any facilities and related equipment- under its control which are necessary to the implementation of this Agreement. B. Each Participant agrees to install, or arrange for the installation of, .underfrequency relays on its respective system which will s automatically disconnect a minimum of 40 percent of its system load j in four 10 percent steps as follows: 01851 I l
m
'(s) Disconnect to a m'inimum of 10 percent of system load c'
-- - when system frequency drops _to 59.5 hertz. . . .
.' Tb) Disconnect to a minimum of a second 10 percent of system load when system frequency drops to 59.2 hertz.
(c) Disconnect a ' minimum of a third 10 percent of system load when system frequency drops to S8.8. hertz. y (d) Disconnect a minimum of a fourth 10 percent of system load when system frequency drops to 58.4 hartz.. C. The Participants agree that the steps outlined in subparagraph 8 are consistent with the operating requirements of .the . Southern. Company with which both. of the Participants are interconnected. The e' Participants further agree that to the extent these steps may .be ! modified by Ethe Southern Company in its relationship with the individual Participants,. this Agreement shall be automatically modified _to reflect those changes. D. The l installation of any additional underfrequency relays beyond s those already. installed _ shall be determined and agreed on by ' both ~ Participants. 2.05 Wheelino Responsibilities. A. Each Participant shall arrange for transmission service required, if. any, and pursuant to this Agreement directly to the utility with which it is connected and which is to perform the wheeling service. B The_ finalizing of 'all necessary. uneeling arrangements are a condition precedent-to either Participant's obligations hereunder. y 2.06' Operatina Standards. A. Each Participant. agrees to discharge its obligations 'under this Agreement in accordance with Prudent Utility Practice.- Forat thea' i purpose' of this Agreement, " Prudent' Utility Practice" particular time shall mean any of the practices, methods and acts en0 aged in - or. approved by a significant- portion of the electric utility industry prior to such time, or any of the _ practices, j methods and acts which, in the exercise of reasonable judgement in ;
-light of the facts known at the time the decision was made, could have been expected to accomplish the intent of this Agreement at the ;
lowest reasonable cost ~ consistent with good business- practices, reliability, safety and expedition. At a minimum, ~ each Participant J 3, ' agrees that its conduct and operations relative to this Agreement -j will conform to the - applicable quidelines of the North. American i Electric Reliability Council Operating Manual as the same may, . from time to time, be amended.
. B. The Participants will normally operate their systems in parallel.
Either Participant may interrupt parallel operation where required for. satisfactory operation of its system. 01851 -- _ -- __- _-
..C. Each Participant agrees to use due diligence to protect, operate and maintain. its respective system so as to avoid or minimize the likelihqpd of system disturbances which might impair the reliability of.the other Participant's system.
O. Each Participant shall take such steps as to ensure that its actions do act impose an undue burden on the other Participant's kilovar s- flow. 3.0 Schedul_ing. 3.01 Specification. A. For any week in which the Participants have agreed to a transaction under one of. the applicable Service Schedules, a weekly schedule specifying power and energy deliveries on an hourly basis will be furnished by the buyer to the seller not later than Noon on Thursday of the week preceding the week in which the transaction is to occur. B. A scheduling week shall be defined as Sunday through Saturday. C. Scheduling sha,11 be performed on prevailing Central Time. 3.02 Methodology. A. Schedule change may be made on verbal notice unless otherwise specified in the Service Schedule. Be All schedule changes shall be confirmed in writing within 3 working days following the schedule change. , C. Hourly schedules will be integrated depending on the rate of change of each schedule.
- 0. The ramp rate for schedule changes will be in accordance with standard industry practice applicable at the time of the schedule change.
4.0 Limits of Liability. 4.01 Force Majeure. A. Each Participant shall exercise due diligence to meet scheduled transactions, but neither shall incur any liability to the other for failure to perform a scheduled transaction due to causes beyond its control or any other reasons due to force majeure. Force majeure shall mean any act, delay or failure to act on the part of any state or federal government authority whether legislative, executive, judicial or administrative including delay or failure to act by any government authority in the issuance of any 01851 . ___I_m__m_.~__A__._._ _. _ _ . . . n e.
- _ _
I i n necessary permits or. licenses, and the prohibiting of acts necessary to2 performance hereunder or the permitting of any such acts .only [^ ~ subject to unreasonable conditions, acts. of God, damage,- accidents, oridisruptions including but not limited to fire, flood, explosions, tornado, hurricane, . earthquake, windstorm, or equipment breakdown, failure er delay beyond the Participant's control in securing y . materials, equipment, services or facilities, labor difficulties such as. strike, slowdowns, or ~ shortages, delays in transportation, civil unrest disturbances, demonstrations, or any other cause beyond e l! the' Participant's contro1~. In no event shall lack of funds be considered force majeurs. B. In the event any cause arises which would impair a Participant's system reliability or ability ; to meet its 'own load requirements,
, deliveries and/or receipts of. power and energy may be suspended as necessary.
' 5.0 Billino.
x '5.01 Schedule of Payments. v p A. All transactions. under this Agreement will be billed by calender month; bills will be due and payable within 10 days of receipt, or 20 days after the end of the month in which the bill is received, whichever is later. B. Payments due from a Participant hereunder, not made when due, . shall
. bear interest compounded daily until id, at a rate per annum which
_shall be based upon the higher of (i)pathe CFC line of credit rate on the date the bill was' initially received or o (ii) the CFC line of credit rate on the date the bill became overdue. 5.02 Maintenance of Records.
' A. Each Participant will keep detailed records of all transactions under this Agreement sufficient to determine all capacity and energy.
transactions on an hourly basis including transactions for wheeling and any necessary metering adjustments. Such records shall be available upon request by the other Participant. B. In' any transaction involving wheeling services with a third party, the Participant directly connected to the wheeling utility will pay the charges for'such service, and add such payment as a separate
-item 6 to the monthly bill of the Participant-4~
requesting service.
- C. Each Participant will maintain an " inadvertent energy account" to account for inadvertent transfers of energy resulting from interconnection.- This account will be cleared in accordance with - the guidelines in the North American Reliability Council Operating Manual.
01851 5
m N , 7, . 5.03 81111no Meters.
~
A. Meters fill be maintained within a tolerance of + 15 and tested at
~
least annually. Each Participant shall provide to the other the
- results of such annual testing. ..
i B. Where a meter,is found to be out of tolerance all' billings. related to that . meter will be adjusted retroactively to the last date . on 4 .which.that meter was checked or to a date 60 days preceding the most recent test date, whichever.results in a shorter adjustment period. C. In addition to 'the annual meter. testing provided for in' 5.03 A.
- above, . either ' Participant may request .in writing that - the other ;
perform a : test on the latter's metering equipment. Within_45 days- ]~ after such request,- a test will be performed. on the metering ' equipment specified in.the written request. If the test proves that .j
~
the equipmentiis_ within the + 15 tolerance- provided for above, the' { requesting Participant will pay all reasonable- cost of. performing a this' test. Payment to be made within 10 days of billing.. In the - ] 4 event the metering equipment tested exceeds the tolerance limits, all prior billing related to that metering eemt will be adjusted in- accordance with 5.03 8. and the owner of the. equipment. shall bear all cost associated with testing. 5.04 Consolidation. A. The billing between Participants for all transactions shall be
- consolidated on a monthly basis.
5.05 Applicability to Schedules. A. Billings will. be at the rates provided -in the applicable Service Schedule as amended from time to time. B. In each Service Schedule there are certain services for which .the charge will be agreed on in advance of the transaction. For those. services for which a charge is specifieo, the Participants recognize that the costs of providing those services may change during the. term of this Agreement. These charges will be reviewed annually and adjusted if_necessary by agreement of both Participants. C. Any Participant desiring to purchase electric power and energy under this Agreement shall be ultimately responsible for all wheeling-charges incurred, if any, in accomplishing such sale. 6.0 Term. A. This Agreement shall become effective uDon execution by. both .! Participants and receipt of all required regulatory approval and shall continue in effect until December 31, 1989-unless sooner terminated under Paragraph 7 hereof. l 01851 _
W, '
)
1 { s.
~s.following the initial ters or any extension hereof, this Agreement' H shall be extended for edditional periods of one year unless et least thirty. days prior to the end of the initial period or any extension hereof 'either Participant notifies the other in. writing of its intent not to extend this Agreement.
o 7.0 Termination. A. It is the intent of the Participants- to this Agreement that .within
'90 days of the effective date of this . Agreement, a. test transaction be held. to verify the mutual . benefits contemplated .by the Participants. Within 60 days after the test, either Participant may ,
s" terminate this Agreement . by 30 days written notice to the other i Participant. B. In the event the performance under this Agreement subjects either i Participant hereunder to regulation by the state regulatory body of the other Participant' or to taxation under the law of the ' state of the other Participant, the Participant so affected may terminate p' - -
.this Agreement upon 30 days written notice to the other Participant.
C. In the event continued participation in this Agreement threatens the system reliability or safety of either Participant, that Participant may terminate this Agreement upon 10 days written notice to the - other Participant. K 8.0 Agency. ;
~
A. Each Participant recognizes that in order to fulfill its obligations hereunder, either Participant may appoint one or more agents to act ' , on its behalf. w. B. In the - event either Participant appoints any such agent, it shall i promptly notify the other Participant and outline in detail the role < of such agent. C. Each Participant agrees to coordinate with and work with any agent appointed by the other Participant to the extent necessary to fulfill the intent of this Agreement. D. Notwithstanding. any language herein to the contrary, either Participant may terminate this Agreement in the event any , appointment of an agent by the other Participant- threatens the i system reliability or safety of the Participant receiving notice of such appointment. Such termination shall be accomplished by 10 days written notice. E. Except as may be included in any Schedule to this Agreement, each Participant shall be responsible for any charges incurred by virtue of its use of any agent. 4 01851 . a . e
{. 3 K 9.0 Indemnification. 4 A. Each Participant shall be solely liable' for, and will indemnify the other against, all damages, injuries, claims, losses, expenses, suits and other ' liabilities, including reasonable attorney's - fees, arising from its own ' activities under this Agreement, or from its L operation, ownership, maintenance or use of its facilities used in the performance of this Agreement,'or from the sole negligent acts or omissions of its agents, servants, ' employees, and contractors.- Each Participant will assume responsibility for all loss and expense resulting from. injury or. death of its.' employees'. arising from operations under this Agreement, and will indemnify -the other against all such liability, except where such injury or death is a I' .' caused'by the sole negligence of the other Participant. Both Participants shall equally bear all losses, expenses, and other liabilities to any ' person: caused by the. joint or concurring negligent- acts or- omissions of both Participants; or theirA respective agents, servants, esployees,. and contractors.- Participant entitled to indemnity must promptly' tender defense of a
- i claim to the other, and fully- cooperate with the other in l
investigation and ~ defense of the claim. A Participant providing indemnity to the other shall be subrogated to all of the rights of such other, which will fully cooperate with the indemnifying Participant in obtaining or enforcing any- rights of subrogation. Neither Participant, by providing indemnity to the other,. shall be held to be estopped or to have waived its right to seek indemnity or contribution from any third party who may have caused'or contributed
-to the injury, ' loss or damage. This indemnity agreement is undertaken by both Participants knowingly and voluntarily, and each acknowledge tne - mutual sufficiency of consideration for this agreement.
10.0 Miscellaneous. 10.01 No Dela'y. ! j A. No disagreement or dispute of any kind between or among any of the j Participants concerning any matter, including without limitation, ' the amount of any payment due hereunder or the correctness of any ; charge made hereunder, shall permit any Participant to delay or withhold any payment pursuant to this Agreement. In the event a-portion of a bill or charge hereunder is disputed, the undisputed ? amount will be promptly and timely paid. Where payment of any ] j disputed amount is withheld, the portion of such amount which is ultimately shown or agreed to be correct will bear interest from the original .due date at the rate specified in Section 5.01(B) hereof. Likewise, where any bill or charge is paid under protest or later discovered' to have been over-paid, the amount of any refund ultimately shown or agreed to be due shall bear interest from the date of original payment at the rate specified in Section 5.01(8) hereof. 01851 -8
p-v L 1 y- -10.0 F Further Executions. A. From time- to time after execution hereof, the' Participants will L execute 'such instruarits eM other documents, upon the request of another Participant, as may be necessary or appropriate, to carry out the intent of this Agreement. F (: 10.03 Governina Law. A. The validity, interpretation, and performance of.this Agreement and each of its provisions shall be governed by the: laws of the state in which any Defendant to any suit brought , under this. Agreement is s located. 10.04 Notice. A. Except as' may .be required by subparagraph _ 2.01 hereof, any notice, request, consent . or other communication permitted or required by-r this Agreement 'shall be in writing and .shall be deemed given when - deposited in tho' United States Mail, first class postage prepaid, and if given to AEC shall be addressed to: General Manager Alabama Electric Cooperative ~,. Post Office Box 550 Andalusia, Alabama 36420
-and if given to OPC shall be addressed to:
General Manager e Oglethorpe Power Corporation 2100 East Exchange Place Post Office Sox 1349 Tucker, Georgia 30085-1349 unless a different individual or address shall have been designated. by the respective Participant by notice in writing. J 10.05 Section Headinas Not to Affect Meaning. l l A. The descriptive headings of the various Sections of this Agreement -{ have been inserted for convenience of reference only and shall in no l way modify or restrict any of the terms and provisions thereof. l 10.06 No Partnership. A. Notwithstanding any provision of this Agreement, the Participants do not intend to create hereby any joint venture, partnership, association taxable as a corporation, or other entity for the conduct of any business for profit. The Participants agree timely to take all voluntary action as may be necessary to be excluded from 4 1 l
; 01851- -9 , .--..___.___.._m ._ m ___
P' , , treatment as a partnership under the Internal Revenue Code of 1954, 1 L as amended, and, if it should appear that one or more changes to -i ' this Agreement would be required in order to most the intent of this Paragraph 10.06, the Participants agree .to negotiate promptly in good faith with respect to such changes. ; 1 10.07. Amendnents. O A. This Agreement may be amended by and only by a written instrument duly executed by each of the Participants hereto.- l 10.08 Counterparts. p A..This Agreement may be executed simultaneously in two or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument. 1 i f 1 ; i 1 q l 1 01851 i
i i This Agreement shall' not be effective. until approved b'y the Administrator of I' 4 .
- the Rural Electrification Administratim.
ALASAMA ELECTRIC COOPERATIVE ' BY: t} /& rde/o m w ITS: V tO,,4:QL'+ v
. ATTEST: ..,
3 b !kn,4& (SEAL) OGLETHORPE POWER CORPORATION yY: N A - General Masa # ITS: ATTEST: - ArMa b* (SEAu 9 A I 01851 -11
=_ _ _ _ _ _ _ _ . _ _ _ _ - _ . - _- _ _ .
e-APPROVAL 7 RURAL ELECTRIFICATION ADMINISTRATION ?' The foregoing Interconnection Agreement was submitted by Alabama Electric Cooperative, an IEA Borrower, and by ' Oglethorpe Power Corporation, an REA borrower, pursuant to the terms of their loan contracts with the Rural Electrification Administration, and said Agreement is hereby approved solely for the purpose of such loan contracts. RURAL ELECTRIFICATION ADMINISTRATION BY: .s ITS: e 6 5 4 e 01851 '
APPENDIX A SERVICE SCEDLA.E 'A" EERGENCY ENERGY Under Agreement of Oc}0hrE6,N , between Alabama Electric Cooperative and Oglethorpe Power Corporation. 1 All of the services contemplated by this Schedule are on an "as, if, and when available" basis, in the sole judgement of the Participant requested to provide the service. Neither Participant shall have any liability to the other for any inability to provide a requested service. ' l.01 This Schedule applies when: .. (a) The buyer is suffering a forced outage or other system emergency . which impairs the buyer's ability to meet its system loads; and
-(b) The buyer requests the aid of the seller; and (c) The. seller, in its sole judgement, can provide the requested service without imposing a. hazard or economic burden on seller's operations and
" without impairing soller's own system loads. 2.01_No obligation to furnish emergency power under this Schedule shall be longer than 72 consecutive hours in any one emergency. - 3.01 in the event that the buyer determines that the emergency condition i will continue past 72 consecutive hours then arrangements must be made to supply its needs as per existing Schedules in this or other Agreements. 4.03 Prior to and during the transaction, the seller will furnish estimated incremental energy cost information hourly (ss shown by seller's economic dispatch program) which will be used for billing. O i
l I APPENDlX B } - SERVICE SCHED LE "B" j SHORT TERM POCR AND ENERGY Under Agreement of CPdObs A $23, lib , between Alabama Electric Cooperative and Oglethorpe Power Co$ oration. l i All of the services contemplated by this Schedule are on an "as, if, and ' when available" basis, in the sole judgement of the Participant requested _ to provide the service, NeitMr Participant shall have any liability to the other for any inability to provida & rcq.csted service. 1.01 Either Participant may request a reservation of power and associated energy from the other on a weekly basis. If the seller has power and energy available. then the Participants will agree on the amount of capacity to be
- supplied, the period during which capacity is to be supplied, a schedule of deliveries, and the price of such capacity and estimated energy cost.
1.02 Each transaction will be confirmed in writing prior to commencement , of deliveries, or as soon as possible thereafter. ] I 2.01 During any period for which Short-Term Power and Energy has been scheduled, the seller will deliver such power and energy on buyer's call up to the amount reserved. 2.02 Power reserved under this Schedule is non-firm. The seller shall not be obligated to supply or cause to be supplied, and buyer shall not be obligated to pay for, any capacity reserved but not able to be supplied by , I seller, due to a system emergency or other abnormal load condition on seller's system which could not reasonably have been foreseen. In such event, deliveries scheduled hereunder may be suspended upon request of the seller, : with a pro-meta reduction in demand enarges. 3.01 Buyer will pay for power and energy reserved and/or s@ plied under this Schedule as follows:
- a. D : At the a kilow i Billing demand will be kilowatts reserved for the week.
- b. E a : All ene supplied under this Schedul Will be at the r ]
I i 1
L APPENDIT c h SERVI 2 SC, EDIAE "C" p l ECCNCMY ENERGY b Under Agreement of- M M 3,I9 , between Alabama Electric Cooperative end Oglethorpe Power Corporation. All of the services contemplated by this Schedule are on an "as, if, and f when available" basis, in the sole judgement of the Participant requested to
- provide the service. Neither Participant shall have any liability to. the other for any inability to provide a requested service. ,
1.01 From time.to thne each Participant may have economy energy available and offer such to the other. If the seller's energy is available at an incremental cost. lower than the buyer's, then the Participants will " split the. ,
. savings."
The rate for economy energy will be calculated by the following formula: Rate per kWh = B + (A-8)/2 ? Where A equals the out-of-pocket cost of energy at point of delivery which buyer avoids as a result of the transaction, and B equals the out-of-pocket cost of energy at point of delivery which seller incurs as a result of the transaction. m 1.02 The price of service under this Schedule will be agreed on an hour-by-hour basis during each transaction. 2.01 The buyer will purchase economy energy under this Schedule only when it has alternate dependable capacity available, including adequate reserve. 2.02 Transactions under this Schedule may be discontinued by either Participant at any time. 4 W
APPENDIX D
- ' SERVICE SCEDULE "D"
~
l l
*EELING (TRANSMISSION) SERVICE _ ]
? Under Agreement of O M M ,I , between AlabfJma Electric Cooperative and S ethorpe Power Corporation. All of the services contemplated by this Schedule are on an "as, if, and when available" basis, in the sole judgement of the Participant requested to provide the service. Neither Participant shall have any liability to the other for any inability to provide a requested service. 1.01 This Schedule applies to transmission service at 115 kV or above when one Participant requests transmission service s.nd the other Participant has transmission capacity available as requested. 3 _ 2.01 The Participant requesting wheeling will deliver, or arrange for delivery of, bulk power to the Participant providing wheeling. The Participant providing wheeling will then deliver 975 of the bulk power it received. The Participant requesting wheeling will make all necessary arrangements with other utilities involved, and will pay all wheeling charges of such other utilities. - 3.0L. From time to time and where available, either Participant may provide to the other " firm" transmission service by the week or month in such amounts as the Participants may agree on. Monthly service will be reserved at - least 7 days in advance, and weekly service will be reserved at least 3 days in' advance. Reservations will be confirmed in writing prior to commencement of service or as soon as possible thereafter. 4.01 From time to time and as available, either Participant may provide "non-firm" transmission service to the other upon at least four hours advance notice unless otherwise agreed. Where "non-firm" service is provided more than three days during any week, then the weekly rate for " firm" service shall apply. 5.01 Either " firm a or "non-firm" service may be suspended or terminated ao deemed necessary by the Participant providing it in the event of an emergency condition on the system of the Participant providing the service, or in the event of an emergency on a third party's system which requires the aid of the wheeling Participant, or where transmission service under this Agreement could not be continued without impairing a prior commitment to transmission service by the wheeling Participant. Additionally, no transmission service is required to be provided which would impair the aci)ity of the wheeling Participant co render adequate service to its customers or reduce the reliability of its system. In the event of any such suspension or termination of wheeling service, transmission service charges will be
- -_-_--_______.m__ _ _
prorated. The Participant suspending service shall not be required to deliver power from its _ own or other sources, aM its sole liability shall be the 3 proration of transmission servics charges, and payment of any wheeling charges of third parties resulting from the suspension or termination. 6.01 Neither Participant shall be responsible for the legality of the other's transactions with third parties. 7.01 The monthly rate for " firm" transmission service shall beM per kilowatt times the maxima capacity in kilowatts reserved by the Participant requesting wheeling. 8.01 The weekly rate for " firm" transmission service shall begof the monthly rate per kilowatt, times the maximum capacity in kilowatts reserved by g, - the Participant requesting wheeling. 9.01 The charge for "non-firm" transmission service shall beM for energy scheduled by the Participant requesting the wheeling. 1 M P i e
9 APPENDIX E
~
SERVICE SCED Li "E" MAINTENANCE ENERGY Under Agreement of bbf k3, N f , between Alabama Electric Cooperative and Oglethorpe Power Corporation. All of the services contemplated by this Schedule are on an "as, if, and when available" basis, in the sole judgement of the Participant requested to provide the service. Neither Participant shall have any liability to the other for any inability to provide a requested service. 1.01 This Schedule applies during a planned outage of the buyer's generating or transmission facilities which has been coordinated in advance with the seller, provided that the soller in its sole judgement has power and . energy avaliable. received under his Schedule by 2.01 r will for all ene payment of 2.02 The initial price of During service under this Schedule will be agreed on any transaction, the seller will furnish
- prior to each transaction.
incremental energy cost information hourly as shown by seller's economic dispatch, which will be used for billing. The seller shall 2.03 Power reserved under this Schedule is non-firm. not be obligated to s@ ply, or cause to be supplied, and the buyer shall not
, be obligated to pay for, any capacity reserved but not able to be supplied by l seller or taken by buyer, dua to a system emergency or other abnormal system l
load- condition which could not reasonably have been foreseen by either j Participant. In such event, deliveries scheduled hereunder may be suspended upon request of the affected Participant. I
ya' Oglethorpe Power Corporation 2100 East Exchange Place P.O. Box 1349 Tbcker. Georgia 30%*e1349 f- (404) 4%7eO) August 4, 1986 Mr. Bil_ Smith Georgia Power Company Post Office Box 4545 4 Atlanta, Georgia 30302.
Dear Bill:
As you know, we would like o establish a scheduling-service arrangement and procedures as necessary te enable Oglethorpe to transact off-system sales and purchases (interchange). In order to form a basis for negotiating contractual and. procedural matters we need to have a written agreement for four general issues, j These ares o Oglethorpe, Georgia Power, and Southerr. Company intend to establish the contractual and procedural mechanisms to enable Oglethorpe to transact a full range of off-system salcs and purchases, including transmission service. o All necessary contractual and procedural mechanisms'will be in place by June 1, 1987 to' enable at a minimum, Oglethorpe to buy'and sell multi-hour economy, short-term, and transmission services. o Any scheduling charges by Georgia Power and Southern Company will be' reasonable and represent the actual incremental increase i in work load and changes to software resulting from Oglethorpe transactions. o Oglethorpe, Georgia Power, and Southern Compny management will expeditiously resolve any obstacles, encountered by their staffs, to meeting the June 1, 1987 target date. We believe that agreement on these issues will form an effective framework for negotiating tht. details necessary to implement an interchange operation at Oglethorpe. i We would like to reach an agreement on these issues by September 11, i An Electric Membership Cooperative j i
)
l
- i p.
- 1. oi, ,
^ *" ~
[Mr,.Bi11' Smith i li , 'Pagi Two-
;w . August'4. 1986.
?
)
L
; Bill,'we appreciate your attention to this matter and look forward to t
our' discussions.. Very truly yours, AAA m V Y George.B. Taylor. Jr. Manager, Power Contracts GBTsj sn - p. 2 xci. G. Stanley Hill'
- 'o Fred D.-Williams l~ l.'
5 6 9 m.i i I,' i4 . g i s. s s T i
,-> .c. , - - - , .
y , . .
.t g L' s W
i W .. .: h+~r n e* { . p ,eoneenavion. f James H. Blanchard - vice passioswt systuu opsmations - T March 21,1986 e3 p Mr. Richard Midulla - r Seminole Electric Cooperative, Inc. P. O. Box 272000 ; Tampa, Florida J 33688-2000 1 1
Dear Richard:
i
Reference:
Transmission '. Wheeling . for Back-up - Energy from Oglethorpe ' l
~l Power Corporation (OPC) to Seminole Electric Cooperative,-
. (SEC1)
The purpose of. this letter is to respond to the request made by Seminole j
. Electric Cooperative for the above- referenced service in a letter from Mr. '
- Walbridge to Mr. Scott dated February 21,1986. .
We ? concur that the.-a for Supplemental ' Resale. - Service, Transmisalon/ Distribution ? greement 1 Service,; and ' Load ' Following Service, ' dated !
. October 13,1983 permits SEC1 to request transmission service for a portion of their ; committed capacity from ~ a new source.f We also agree,' as was " . pointed out in Mr. Walbridge's letter, that there are 1;mitations regar. ding -
our. ability, to provide the requested servic,e based on operating procedures - which have been' established governing' Southern / Florida Imports. Florida
~
Power Corporation is willing to provide the requested service in accordarice
. 3' with the above-referenced contract and within the limitations as' outlined '
- f. below.
'On a daily basis, transmission capacity may be available to Florida Power
' Corporation based upon quotes provided by Florida Power Corporation to '
L
' Southern Company Services. The transmission capacity. established by these.
l i quotes for Florida Power Corporat!on can be made available to Seminole. Upon the request of Seminole, Florida Power Corporation wi!! use that
- b. : transmission capacity to transmit power from Oglethorpe to Seminole load
--int the, Florida Power area, provided Seminole reimburses Florida Power
~ Corporation for the savings which are foregone from the quoted transaction C
n . between Southern Company and Florida Power Corporation. ' At times there > 11s additional unused transmission capacity. During those times, and upon the request of Seminole, . Florida Power Corporation f- will: -rep;Q 4-f.* I , !. _, Y.[ij 9 '
) 6
~ 'Y* . ;*, Q b.
3210 Tturty fourth Street South
- P O. Bos 14042
- St. PetersburD. Florica 33733
- fB13) 866 5220 - .
A Phon 0s Progress Company . u-4
jf ' :. U request that, additional transmission' capacity . be made' available for the
.Oglethorpe/ Seminole transfer.o it should be understood that Florida Power p~
Corporation will: schedule . transmission. and : generation : maintenance in i - accordance with its own system needs; and, from time to. time, this may .,
. preclude or reduce the ability of Florida Power Corporation'to transmit Oglethorpe energy to the Seminoleload.
From time to time, it may be necessary to reduce Southern / Florida imports
- v. to protect the security of electrical service within the State of Florida.
F Operating Procedures have~ been estabilshed for this purposes s' copy is-attached. It is our understanding that the SECI back-up power- purchase from OPC.will be handled on + daily basis la the same manner as assured - economy scheduled by Florida Power Corporation. This is addressed in paragraph 1 of the attachment. b In accordance .with Mr. Walbridge's letter, a copy of this response is being forwarded to Southern . Company.'. In addition, copies are' also being forwarded to other. parties routinely transferring ' power across the e Florida / Southern interface. Please provide ~ your estimates of when you would plan to begin such ' ' transactions and the amount you would plan to transfer. We request two weeks notice prior to the first transfer. In the meantime, our operating and rate personnel will need to work out the detalis of this arrangement. Such. i detalis include the time of' day that communications and commitments will' be made and to whom they will be directed. . Plaue feel free to contact me if you have any questions. 9 51ngerely, ~ (d . 3.nW 3HBibf . Attachment , cc: Mr.W.E.Coe Mr. R. A. Basford
- Mr.1 A. Johnson, Jr.
Mr. P. N. Kolkos-Mr. T. W. Raines, Jr. Mr. T. 5. Woodbury. 4 e
- 4 I b
7 . . - ._. - g y.* E.; -
. 2 .,
- OPERATING PROCEDURES FOR SOUT!!ERN/ FLORIDA IMPORT - - -
j y 1.; .
-1
- 1. When~a3tuation occurs on either the Florida System or the Southern l System which results in a reducilon of the State Import Limit to a level below the cumulative import schedules, the scheduled amounts of Southern's Discretionary Energy shall be reduced firstt " hourly economy" transactions shall be reduced next, in the order of those blocks providing _
the least savings being reduced firstt to be followed by reductions in
" assured economy"in the same manner, until the import level is reduced -
l to the 1985 contracted capacity of 2900 MW. 1 T
- 2. When a situation occurs on the Southern System which requires a reduction of imports below the 2900 megawatt level and the import reductions
.; identified in Paragraph 1 above have been made, the Southern Coordinator will reduce the schedule of imports, on a pro-rate basis of the Schedule "E" contracted capacity, until an acceptable limit is met or the reduction equals the sum of the Schedule "E" contracted capacities.
, j 1985 Schedule "E" Utility Allocation % Contracted Capacity j
, FPL 3% 300M W
' JEA . 34 % *
' 300M W FPC 23 % 2t:0M W TAL. 9% 75MW 100 % - 875MW 6 If further reductions are required, the schedule of impo'rts will be revised so that the remaining available imports are allocated on a pro-rate basis of UPS contracted capacity. f 1985 UPS Allocation % Contracted Capacity
- '- Utility FPL 85 % 1722 M W
- JEA 15% 303MW 100 % -
2025MW r in the event that one utility's schedule prior to such reduction is less than its allocated share, the unused capacity will be applied toward
.. the import reduction until the utility scheduling less than its allocated -
share increases its schedule, j a b
"g u
a
-3. : When imports'are required to be reduced below the 2900 megawntt level H
- as a result of outage of facilities identified to a Florida system party ;
of this agreement and the import reductions identified in Paragraph i 1 above have been made, that party (s) identified as the cause of the
,. reduction will be responsible for additional required import reductions
'up to its contracted capacity. If one or more utilities' schedule (s) prior ~
to such reduction is less than its allocated share, the unused cepacity will be applied toward the import reduction until the utility scheduling less than its allocated share increases its schedule. If further reductions % are required, the schedule of imports will be revised so that the remaining available imports are allocated to the other parties on a pro-rata basis of their 1985 contracted capacities. The following examples illustrate this procedure if an import limit reduction is required as a result of the outage of the identifiable facilities: m A) Outare of Suwannee-Pine Grove 230 KV line - Florida Power Corpore-tion will take the import reduction up to 200 MW, or the amount of its schedule prior to this reduction, whichever is less. If further reductions are required, the schedule of imports will be revised so that the remaining available imports are allocated on - the following percentages. 1985 Contracted Utility Allocation % Capecity
~
FPL* 75 % 2022MW' , JEA 22 % 603MW TAL 3% 75MW
, - 100 % ' 2700MW B) Outare of Ilopidns-5. Dalnbridge 230 KV line - Tallahassee will take the import reduction up to 75 MW, or the amount of its schedule
+
prior to this reduction, whichever is less. If further reductions are required, the schedule of imports will be further revised so that the remaining available imports are allocated on the following percentages. L 1985 Contracted Utility Allocation Capacity I $ FPL 72% - 2022 MW
; JEA 23 % 603 MW +
FPC 7% 200 MW s . 100 % 2825 MW L.
9 :. .e p
.s C) Ontare of either Duval-listeh 500 KV Une - FPL and JEA will store , equauy any import espacity above the sum of:-
V FPC's schedule, up to 200 MW. TAL's schedule, up to 75 MW. .
. The first 200 MW of FPL's schedule.
D)' Outare of Duval-Rice 500 KV Une, Duval-Poinsett 500 KY Une, or any transmission line internal to FPL's system which impacts the State import Limit - FPL will take any required import reduction to the import limit. p 4. If the outage of other facilities or a combination of facilities of the Southern System and/or Floricia System results in the reduction of the State import Limit and the sitcation etusing the reduction cannot be identified with a specific utility, and the import reductions identified in Paragraph I have been made, further reduction will be allocated on a pro-rata basis of total 1985 contracted capacities. Total 1985 Contracted Utility Allocation % Capacity E + UPS + Total
~
FPL
- 70% 300 + 1722 = 2022 L. JEA 21 % 300 + 303= 603 FPC 7% 200 + 0= 200 T.AL 2% 75 + 0m 75 m
100 % 875 + 2025=2900 When a determination can be made of the situation causing the reduction, the provisions of Paragraph 2 or Paragraph 3 will apply, as applicable.
- 5. When Florida utilities are required to reduce import schedules due to a reduction of the State Irnport Limit for any reason, each Florlds utility D shall have the option of identifying the specific type (s) of service to be reduced, subject to the UPS Minimum Scheduling Requirements which may be applicable in the case of FPL and JEA. ,
?, 4
__- _ . _ _ _ _ _ _ _ _ _ - _ _ _ _ _ . - _ _
SCHEDULING SERVICES AGREEMENT
~ ' This Agreement is made and entered into as of this bD day of April, 1986,.by and between GEORGIA POWER COMPANY, a corporation organized and existing under the laws of the State of Georgia
("GPC") and OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION), an electric membership corporation organized and existing under the laws of the State of $ Georgia ("OPC")(individually a " Party" or collectively the
" Parties").
#11EES S g i g:
.01 WHEREAS, GPC and OPC together with the Municipal 7 Electric Authority of Georgia ("MEAG") and the City of Dalton, Georgia (" Dalton"). jointly own Plant Robert W. Scherer Units No.
1 and No. 2 (" Plant Scherer") and have previously executed the Plant Robert W. Scherer Operating Agreement dated as of May 15, 1980 (the " Operating Agreement"), pursuant to which GPC was appointed agent for OPC, MEAG, and Dalton for the management, control, operation (including scheduling and dispatching of capacity and energy) and maintenance of Plant Scherer; and
.02 WHEREAS, GPC, OPC, MEAG, and Dalton have entered into a Memorandum of Understanding of even date herewith; and L .03 WHEREAS, OPC desires to sell energy from Plant Scherer to Seminole Electric Cooperative, Inc. (" Seminole") pursuant *to an agreement between OPC and Seminole, dated April , 1986, (the~" Seminole Agreement"), during the period April . 1986 to May 31, 1986; and C .04 WHEREAS, energy provided under this Agreement is deemed to be Non-Firm (as herein defined) and is available subject to the conditions hereof; and
.05 WHEREAS, OPC will require temporary energy during an hour in which the net g e n e r 2 +. i o n from Plant Scherer becomes insufficient to meet the scheduled energy sales to Seminole; and
.06 WHEREAS, GPC, at its option, may supply other energy to OPC for Seminole's account when Plant Scherer is out of service; and C
1 n ..~_ - - . _ _ - _ _ _ . _ . _ - - _ _ _ _ _ . _ _ . _ _ - - - - _ .a.. ..
.07 WHEREAS, in order to implement such 3 ale of energy to Seminois, GPC, in accordance with this Agreement and the Memorandum of Understanding, has agreed to schedule energy from Plant Scherer to be delivered by'OPC to' Florida Power Corporation
("FPC") at the Georgia-Florida state line; and
.08 WHEREAS, the Parties agree that OPC's utilization of energy from Plant Scherer for the purpose of implementing the Seminole Agreement shall neither be nor establish a precedent concerning f u ture sales or purchases of other capacity or energy outside the Georgia territory; and
.09 WHEREAS, OPC and GPC enter into this Agreement for the purpose of providing scheduling, operating, and accounting procedures for the delivery of energy to FPC, providing for
?- Temporary and Optional Energy service from GPC to OPC, and providing for payment from OPC to GPC for all of these services. NOW, THEREFORE, in consideration of the premises and the mutual agreements herein set forth, GPC and CPC hereby agree as follows: ARTICLE _I_-_ DEFINITIONS 1.1 Definitions. For the purposes of this Agreement the following definitions shall apply: (a) The Delivery Point for all energy delivered to FPC-for Seminole's' account pursuant to this Agreement is deemed to be the Georgia-Florida state line, and transactions hereunder are contingent upon the GPC-FPC 230 kV interconnection being in service. 9 (b) Unit Energy is net generation at Plant Scherer, including incremental transmission losses to the Delivery Point, deemed to have been delivered to meet scheduled energy requirements. (c) Temporary Energy is energy supplied by GPC to CPC j for Seminole's account'in any hour in which Unit Energy becomes insufficient to meet scheduled energy requirements, and will not be available for more than one hour beyond the hour in which Plant Scherer becomes inoperative. (d) Optional Energy is energy supplied by GPC to OPC for Seminole's account, at the option of GPC, when Unit Energy is unavailable. 2 Y \ t-( _ ,
en - , j
^
i p (e) Non-Firm shall mean transactions that are not guaranteed and are subject to cancellation by GPC (or its agent) L at any time at its sole option but not without justifiable k p; reason.
~
(f) Unit Power Sales ("UPS") shall mean_ sales by Southern system companies to non-affiliated companies pursuant to contracts similar to the Amended and Restated ' Unit Power Sales Agreement between Florida' Power G Light Company and the Southern system companies, dated February 18, 1982, as amended. (g) Long-Term Non-Firm Sales shall reJer to sales by Southern system companies to non-affiliated companies pursuant to service schedules such as Service Schedule E to Interchange Contracts such as the one dated October 18, 1979 between Florida Power & Light company and the Southern system compani . ARTICLE II - SCHEDULING 2.1 Unit Energy. (a) In order to implement the Seminole Agreement, GPC, subject to the terms and conditions hereof, hereby agrees to schedule Unit Energy to FPC for the account of Seminole, in the quantities and at the times specified herein. The amount of Unit Energy available for scheduling at Plant Scherer in any hour shall be limited to 230 MWH. (b) In order to arrange for the appropriate scheduling j
'and delivery of Unit Energy pursuant to this Agreement, beginning with the date of this Agreement and on each workday thereafter during its term. FPC shall notify GPC (or its agent) no later than 9:00 a.m. prevailing Central Time, of (i) Seminole's request for hourly energy to be delivered at the Delivery Point to FPC )
3 for Seminole's account for the next 24-hour period commencing at i 12:00 midnight prevsiling Central Time, and for additional 24-hour. periods where weekends or holidays are involved; and (ii) I the average transaction' price (in dollars /MWH) for energy delivered from OPC to Seminole pursuant to the Seminole Agreement for each 24-hour period. (c) Following receipt of such request, GPC (or its agent) shall determine during which hours the requested energy is expected to be available for scheduling. Unit Energy shall be deemed unavailable for scheduling from Plant Scherer when (i) the i incremental cost of generation on the Southern system to serve l territorial requirements and off-system UPS, UPS Replacement Energy, Long-Term Hon-Firm Sales, and the sale described herein is projected to reach the level which would load either unit at Plant Scherer to 350 net MW or greater while such unit is in economic dispatch, or (ii) Plant Scherer is anticipated to be off i 3 i I l
-line...or (iii) the GPC-FPC 230 kV interconnection is expectedoto be out of service._!If a limiting 1 condition is expected on the Georgia-Florida-interconnection, the availability.of Unit Energy will be determined'in accordance with Section 3.1(a)-below. GPC
[ -(or-its agent) .shall notify FPC no later than 5:00 p.m. prevailing Central. Time of the-hours that Unit Energy is anticipated to be available at the requested MW 1evels. This establishes the schedule for Unit Energy deliveries. l l' [" 2.2 Temporary Energy. Temporary Energy shall not be l scheduled. 1 2.3 Optional Energy. Optional Energy may be supplied by 3 .GPC to OPC for Seminole's account at the option of GPC, when. Unit Energy is unavailable. In the event Plant Scherer is anticipated ) to be unavailable for Unit Energy deliveries at any. time during l the scheduling period, GPC (or its agent) may, at its option, declare' Optional Energy available,for scheduling. GPC (or its agent) shall notify FPC no later than 5:00 p.m. prevailing Central. Time of the hours that Optional Energy is anticipated to be available at,.the requested MW 1evels. This establishes the schedule for Optional' Energy deliveries. ARTICLE III - DELIVERY OF ENERGY 3.1 ' Unit Energy. (a) GPC (or its agent) shall make a determination 30 minutes prior to the start of each hour in which a schedule for Unit Energy deliveries exists as to the availability of energy to be delivered under the requested schedule. Unit-Energy ~shall be deemed unavailable, for delivery to Seminole under this Agreement, whenever'the conditions ~ set forth in Section 2.1(c) exist. If a limiting condition exists on the Southern system side of the Georgia-Florida interconnection. relative priority of this transaction and other Southern-to-Florida . transactions will be determined as follows: All UPS, UPS Replacement Energy and Long-Term Hon-Firm Sales will have priority over OPC-Seminole transactions. The relative priority of OPC-Seminole-transactions and Southern system Assured
. Economy transactions shall be determined by the difference between the average transaction price and the projected cost of this OPC-Seminole transaction applied to the schedule for Unit Energy deliveries for the current calendar day, compared to the difference between the Southern system's stated cost and transaction price (in dollars) of its then current' Assured
? Economy: transactions, the largest difference having priority.
.The projected cost of this OPC-Seminole transaction will be the
. total of the current month's projected fuel, variable operation and maintenance ("O&M*) expense and in-plant fuel handling expense components of the UPS Base Energy Rate for Plant Scherer 4
c__
increased by-the percent transmission losses associated with this transaction for the appropriate time period. If the limitation is a result of problems on the Florida side of the
- Georgia-Florida interconnection, access to the., interconnection shall be determined by the Flor (da utilities sharing the interconnection according to their standard operating procedures.
If at any time GPC (or its agent) receives conflicting _ instructions from Florida utilities concerning the relative priority 7Cf an OPC-Seminole transaction and other Southern system-Florida transactions, GPC (or its agent) may, at its sole option, interrupt some or all of the OPC-Seminole transaction. (b) GPC will determine the amount of Unit Energy delivered from Plant Scherer based on a projection of incremental losses from Plant Scherer to the Delivery, Point. The projection h of losses will be determined using the existing algorithms of the Southern system for incremental transmission losses. The total incremental losses thus determined for each hour-of the projected period will be converted to average percent incremental losses for a minimum of two time periods a day. These time periods are expected to consist of the hours beginning 7: 00 a.m. and ending 10:00 p.m. prevailing Central Time, designa*ed as the peak period, and the hours beginning 10:00 p.m. a.n d ending 7:00 a.m. prevailing Central Time, designated as the valley period. The percent incremental transmission losses determined as described herein will be applied to the schedule for Unit Energy deliveries to determine the hourly allocation of Unit Energy to Plant Scherer. GPC will be responsible for monitoring the actual incremental losses and making appropriate corrective adjustments in subsequent scheduling periods in order to assure that all of
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the energy delivered as Unit Energy is allocated to Plant Scherer in the appropriate time periods. m 3.2 T e m go ra ry Energy. Temporary Energy shall be supplied by GPC to OPC for Seminole's account in an hour in which the Unit Energy becomes insufficient to meet the requirements for scheduled energy. The delivery of Temporary Energy will be discontinued as soon as practicable.
, 3.3 Optional Energy. For any hour in which a schedule for Unit Energy deliveries extsts and Unit Energy is deemed to be unavailable. GPC may convert the schedule to Optional Energy and continue deliveries until it is determined.that Unit Energy is again available as scheduled. Optional Energy shall be delivered to OPC for Seminole's account at Plant Scherer, and OPC shall be responsible for transmission losses associated with its delivery to FPC as determined in Section 3.1(b). The delivery of Optional Energy may be discontinued at any time at GPC's sole option.
5 l h\ O
O L 1 r h L W ARTICLE _IV -1 BILLING AND' ACCOUNTING-
- 4.1 Unit Energy. (a) Unit, Energy shall be subtracted from j- .
thousetual hourly net generation at' Plant Schere 'and allocated y tol0PC's; account prior :to: the determination =of-any other energy Allocations.(including;GPC, OPC. MEAG and-Dalton retentions). Unit Energy:shallateLallocated-prorata to whichever units have
- net positive' energy production-within an hour.
F (b). In the event that Unit Energy.plus OPC's peaking energy requirementsifrom~ Plant SchererL as determined under GPC's current ' effective Partial: Requirements Tarif f f axceeds OPC's
; retained energyfin.a~ unit.for-the current month'as determined by the Operating Agreement.'OPC1shall purchase the additional energy from.GPC at the current month's fuel,; variable OEM expense,.and k' in-plant fuel: handling. expense components of the UPS' Base Energy Rate for' Plant Scherer as' determined in:the current-month's.UPS-
' billing.
4.2 Temporary Energy. (a) Temporary Energy will have been delivered if'the-not generation at Plant 1Scherer in any hour is less than the.s'chedule for Unit Energy deliveries increased byf the percentage transmission losses associated with this transaction for the appropriate time period.; The amount of Temporary Energy sha11the determined by subtracting the not
. generation.at Plant Scherer from the schedule for Unit Energy deliveries increased by the percentage transmission losses , . associated with'this transaction for'the appropriate time period.
(b)' . Temporary' Energy will be priced by GPC to.0PC'at the fouthern system's incremental cost above all-transactions for
' the f curre'n t hour plus $5.00/MWH,:or the' current month's fuel, .
-variable OEM expense, andLin-plant fuel handling expense components of the UPS Base Energy. Rate for Plant Scherer, whichever~is higher.
4.3- Optional Energy. . Optional Energy, when delivered, will be: priced by GPC to OPC at the current ~ month's fuel, variable o&M expense, and in-plant fuel handling expense components of the UPS Base Energy Rate for" Plant Scherer. .
'4.4 Scheduling'and Coordination Fee. In addition to all other payments required to be made hereunder, OPC shall pay to e 'GPC $0.50/MWH for all ~ energy delivered to the Delivery Point pursuant-to this Agreement during a month to compensate GPC for R- hard-to-identify and hard-to-quantify c o s t's , including costs associated with scheduling, coordination and' accounting. q 4.5 Billing and Payment. By the tenth working day of each month, or as soon thereafter as practicable, GPC'will provide OPC '
i 6 i
^
; 2 _ d
!e with on invaicofoontcining prolicincry occounting of tho onorgy -
. delivered by: transaction and the costs-associated therewith.
J- -This preliminary. accounting and costs will be replaced with
. actual values'for energy-and costs when available, and the f
g s,
' difference applied'as an: adjustment to the next preliminary bill..
-Upon'terminationiof this. Agreement, all' billings will be calculated onsan actual basis as-soon as practicable. All Plant Scherer1 variable OEM costs 'and in-plant fuel handling costs associated. with energy. delivered to Seminole pursuant to this Agreement'will;be replaced with the 1986' average variable OEM S costs and in-plant. fuel handling costs. f or Plant Scherer when-such costs become'avai2eble and an.appropriatesbilling adjustment
'will be issued. OPC will make payment'forf invoices rendered hereunder within fifteen days of receipt.
4.6 Initial costs. OPC will reimburse GPC for all of Southern Company-Services' initial developmental costs, including D appropriate overheads associated with this Agreement, programming' changes to Southern's on-line Power Management System, modification of billing procedures and programs,.and administrative efforts to formulate and implement this Agreement. All such-costs are estimated to be $23,000 which shall be paid , upon the execution'ofEthis Agreement. ARTICLE V - ADMINISTRATION 5.1 Non-Fira Transactions. The transactions provided for in this Agreement.are Non-Firm, and GPC's scheduling and coordinating obligations hereunder may be interupted by GPC whenever (i)Lthe limiting conditions described in Section 2.1(c) exist; or (ii) conflicting instructions.from. Florida utilities
.are received as described in Section 3.1(a); or (iii) the' output of Plant Scherer is necessary to continue. service to the Southern
- territorial system; or (iv) GPC reasonably expects continuation or implementation of a transaction may cause an adverse economic consequence'to GPC under The' Southern Company System Intercompany In t e r cha rsg e contract, dated Octo,ber 28,fl983.
5.2 Florida Interface Rules.- Prior to scheduling any transactions hereunder, OPC shall provide GPC with written instructions approved by each of the Florida utilities affected by transactions over the Southern system-Florida interface, setting forth Florida's characterization of the OPC-Seminole transactions to be implemented hereunder, the priority of such transactions in relation to other Southern system-Florida O transactions, and any other special scheduling instructions or considerations. For purposes of this section Florida utilities j
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shall include, without ~1 imitation, Florida Power & Light Company,
. Jacksonville Electric Authority, Florida Power Corporation and ; - 7 J
I w <
~ -- . ,
o the-City of-Tallahassee, Florida. 5.3 Seminole Capacity Resources. OPC warrants that Seminole L is an electric utility with load. responsibility, resources, and ( reserves such that a purchase of Non-Firm energy is. appropriate and useable on its system. OPC wil1~take all steps necessary, including obtaining an appropriate contractual commitment from Seminole, to assure that Seminole possesses capacity reserves towned or purchased) in sufficient quantities to permit it to O purchase Non-Firm energy during each hour that energy hereunder is made available. 5.4 Regulatory Approvals. The Parties recognize that this contract is required to be _ filed with and approved by certain regulatory agencies including the Federal Energy Regulatory , Commission ("FERC"). To this end GPC agrees to take steps promptly to file this Agreement with FERC and shall seek a waiver of the notice requirements of the Federal Power Att and Section 35.3 of FERC's regulations so as to obtain an effective date contemporaneous with the effective'date of this Agreement. In
'the event this Agreement is changed or modified by any regulatory agency or authority, either Party, if adversely affected, shall have the right to terminate this Agreement immediately.
Furthermore, OPC will take all steps reasonably requested by GPC to obtain FERC acceptance of the termination date of this Agreement specified herein. In any event, OPC agrees that neither it nor Seminole will seek to have any transaction scheduled under this Agreement after May 31, 1986. 5.5 ITS Load Responsibilities. The Parties agree that deliveries of energy to FPC hereunder will be as though made by OPC'on t h .e ITS from Plant Scherer, and if such transaction causes any increase.in OPC's load responsibility under the ITS by , , creating a new annual peak for OPC, this responsibility will be accepted by-OPC i n ti subsequent ITS Settlement. 5.6 Use of OPC Capacity. The Parties agree that the allocation of Unit Energy from Plant Scherer hereunder is a utilization of OPC's reserve capacity in Plant Scherer for this specific transaction only, and this use neither is nor establishes a precedent for the future use of OPC's. capacity. 5.7 Unique Circumstances. The Parties hereto agree that the circumstances leading to this Agreement are unique, and that this Agreement therefore establishes no precedent for any other services and will not be relied upon by either Party for any purpose other than for the services and payment provided for hereunder. 5.8 Indemnification. OPC agrees to indemnify GPC and save 8
GPC harmless from any claim whatsoever brought by Seminole,
~
another Florida utility or any other. party resulting from GPC's performance hereunder; provided, however, nothing contained
, herein shall relieve GPC of the consequence of its negligence or of any breach of this Agreement.
5.9 Operating Committee. GPC and OPC shall each appoint one representative and one alternate to act for it in matters pertaining to the interconnected operation of its system y~ - hereunder and the detailed operating arrangements for delivery of energy hereunder. The two representatives, or their alternates, shall can,;ise the Operating Committee. Evidence of such appointaccts shall be given by written notice to each of.the Parties, and such appointments may be changed at any time by similiar notice. ARTICLE VI - MISCELLANEOUS 6.1 ~ Term. This Agreement shall become effective as of the date first appearing above, and shall terminate at midnight on 7 May 31, 1986. 6.2 Force Majeure. The term " Force Majeure" shall mean acts of God,-the enforcement or adoption of legislation or lawful rules, regulations or orders of any governmental body, acts of public enemy, riots, strikes, or other industrial disturbances, labor or material shortages, fires, explosions, breakdowns of or damage to generating plants, structural-failure of facilities, or other causes of a similar nature which are beyond the reasonable contrV1 of GPC or OPC and wholly or partly prevent GPC or OPC from performing its obligations hereunder. If because of Force Majeure either GPC or OPC is unable to carry out its obligations n under this Agreement, and if such Party promptly gives the other ; Party hereto written notice of such Force Majeure, specifying the i nature, extent, and expected duration of such Force Majeure, the obligations and liabilities of the Party giving such notice and the corresponding obligations and liabilities of the other Party shall be suspended to the extent made necessary by and during the g continuance of such Force Majeure. l 6.3 Notices. Any notices, billing information and invoices l required by this Agreement shall be deemed properly given if L cailed postage paid, to Oglethorpe Power Corporation, 2100 East Exchange Place, P. O. Box 1349, Tucker, Ge7rgia, 30085-1349, j Attention: Department Manager, Power Contracts in the case of OPC, and to Georgia Power Company, 333 Piedmont Avenue, Atlanta, Georgia 30308, Attention: Manager, Bulk Power Marketing 333/20, in the case of GPC. ( , 1 9 w l l
l' ?- i l 6.4 Transfers-'and Assigns. CPC shall not transfer.or' assign l7 its rights._and obligations.under this Agreement without GPC's L' prior written consent. The terms of this Agreement shall be j binding'upon th^e Parties, their successors and assigns. P-
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'IN' WITNESS WHEREOF,'the parties hereto ha ve ' duly e xe cute d '
. this Scheduling: Services Agreement by their duly authorized representatives as of.the date first above written.
5: [ Signatures on next page]- D W Y. l t I a I l 1 10 i 4 I
?
"GPC" GEORGIA OWER COMPANY
?' By: M l Its: VP - Bulk Power Markets 3
~~
- ' Attest:
-By: ,
d' (Title)
"OPC" I OGLETHORPE POWER CORPORATION
-( AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION
'- CORPORATION)
~
Its: Generaf Manade / Attes . [ By: ) / l _ Corporate Counsel' ' (Title). I 1 i
\
l l l 1 11 W e 1 L____---. - ._ _. =
MEMORANDUM OF UNDERSTANDING This Memorandum Of Understanding is entered into this - 10th day of October, 1986, by and between GEORGIA POWER. COMPANY, a corporation organized and existing under the laws of the State of Georgia ("GPC"), OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION), an electric membership corporation organized 1 and existing under the laws of the state of Georgia ("OPC"), { the MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA, a public body ; corporate and politic and an instrumentality of the State of l Georgia ("MEAG"), and the CITY OF DALTON, GEORGIA, an j incorporated municipality in the State of Georgia acting by , and through its Board of Water, Light and Sinking Fund Commissioners (" Dalton") (individually a " Party", or q collectively the " Parties"). J l W I T N E S S E T H: WHEREAS, GPC, OPC, MEAG, and Dalton jointly own Plant Robert W. Scherer Units No. 1 and No. 2 (" Plant Scherer") and i have previously executed the Plant Robert W. Scherer Operating Agreement dated as of May 15, 1980 (the " Operating Agreement"), pursuant to which GPC was appointed agent for OPC, MEAG, and Dalton for the management, control, operation (including scheduling and dispatching of capacity and energy), and maintenance of Plant Scherer; and WHEREAS, OPC desires to sell energy from Plant Scherer to Seminole Electric Cooperative, Inc. (" Seminole") pursuant to an agreement between OPC and Seminole, dated October 9, 1986 ("the Seminole Agreement") during the period October 10, i 1986 to December 31, 1986; and WHEREAS, GPC and OPC have entered into a Scheduling Services Agreement, dated as of even date herewith, in order to provide for additional services related to the Seminole . Agreement; and )i WHEREAS, in order to implement such sale of energy to I i Seminole, GPC, in accordance with this Agreement and the Scheduling Services Agreement, has agreed to schedule energy from Plant Scherer to be delivered by OPC to Florida Power Corporation ("FPC") at the Georgia-Florida state line; and WHEREAS, Section 3(b) of the Operating Agreement provides that any party shall have the right to receive energy from Plant Scherer in excess of its proportionate share thereof provided that all other parties to the Operating Agreement consent to such increased generation and are relieved of any additional costs associated with such generation as so defined in the Operating Agreement; and 1
t ; i i i WHEREAS, the Parties recognize that OPC has the right to f
/ utilize energy from their 253,530 kW of retained capacity in 1 Plant-Scherer-Unit No. 1 and 150,156 kW of retained capacity j in Plant Scherer Unit No. 2 unless such energy is required to serve territorial load. 4 NOW, THEREFORE, in consideration of the premises and the ?
mutual agreements herein set forth, the parties hereto hereby 1 agree as follows:
- 1. By execution of this Memorandum of Understanding, GPC, MEAG, and Dalton each specifically agree and consent to any increased generation at Plant Scherer due to delivery of (
; energy pursuant to the Scheduling Services Agreement and {
hereby further acknowledge that it is intended that such l increased generation will not adversely affect the capability of Plant Scherer Units No. 1 and No. 2. GPC, MEAG, and Dalton further agree, for the purposes of this Memorandum of Understanding, that OPC's retained capacity in Scherer Units No. 1 and No. 2 shall be deemed to exist in any combination of these units. The Parties recognize that the allocation of l Unit Energy to be delivered pursuant to the Scheduling Services Agreement for OPC's account may reduce the quantity of energy retained from Plant Scherer from the amount previously budgeted.
- 2. (a) Unit Energy shall be subtracted from the actual !
hourly net generation at Plant Scherer and allocated to OPC's , account prior to the determination of any other energy 1 allocations (including GPC, OPC, MEAG, and Dalton i retentions). Unit Energy shall be allocated prorata to whichever units have net positive energy production within an hour. 1 (b) In the event that Unit Energy plus OPC's peaking { energy requirements supplied by Plant Scherer as determined i under GPC's current effective Partial Requirements Tariff f exceeds OPC's retained energy in a unit for the current month l as determined by the Operating Agreement, OPC has agreed pursuant to the Scheduling Services Agreement to purchase the additional energy from GPC at the current month's fuel, a variable operation and maintenance ("O&M") expense, and ) in-plant fuel handling expense components of the UPS Base Energy Rate for Plant Scherer as determined in the current month's UPS billing. { a
- 3. Subject to the terms and provisions of this Memorandum of Understanding, OPC shall, in accordance with the provisions of se'etion 3(b) of the Operating Agreement, be responsible, as of the effective date of this Memorandum of 5 Understanding, for any and all additional costs resulting f rom the generation at Plant Scherer for the delivery of Unit Energy, as defined in the Scheduling Servicet Agreement, J 1
2
)
) l
- - _a
-- q v ; y ,
] N: t- w
~~
Lincluding..all prepaymentsiin connection with acquisition of-J ' coal'and.other fuel,"and OPC agrees to' indemnify and~ hold B : GPC,;MEAG,Jand' Dalton harmless from"and against any and all icosts, expenses,' liabilities;and damages of any. kind'
- occasioned in:any way by such operation.of Plant Scherer Units.No. 1 and No.-2.L
- =4 . ByLvirtue of execution of this Memorandum'of-hc Understanding,calliparties.hereby affirmatively waive, for 7 the-purposes.of'this Memorandum 1 of Understanding only, and subject:to the provisions of. Paragraph:4,fany and allz notice requirements thatraay be contained in;the operating Agreement concerning.the scheduling and dispateit by:GPC of'energyLin
' excess-;of OPC's proportionate share'of the energy from Plant pf' Scherer=which could be generated while operating at the maximum practicable capability.at any'given time.
4
-5. LThe: Parties hereto. agree.that the circumstances
' leading,to this Memorandum of Understanding.are unique, and
- that this Memorandum of Understanding therefore establishes no precedent =for.any'other services and will not be relied
.upon by,anyLParty for_any purpose other than for the services
.and: payment provided for hereunder. <
y 6.x The' Parties agree that deliveries-of energy to-FPC hereunder will.be as though made by OPC on the Integrated Transmission; System.("ITS")'from Plant Scherer, and if such b transaction causes any increase in OPC's, load responsibility under the ITS by creating a new annual-peak'for OPC,'this responsibility will be accepted by OPC. 7.- The' Parties agree that.the allocation of Unit Energy-from Plant:Scherer hereunder is'a utilization of OPC's b- retained' capacity in Plant ~Scherer in accordance with Section 3(b) of the Operating Agreement for this-specific transaction only, and'this use neither'is nor establishes'a. precedent for
-the use of-any Party's capacity.
- 8. Except as may be otherwise specified herein, the
, transaction contemplated hereby shall be subject to.and l governed by the applicable terms, covenants and' conditions of t
the. Operating Agreement. .. IN WITNESS WHEREOF, the parties hereto have duly executed this-Memorandum of Understanding by their duly authorized representative as of the date first above written. s, . . 3 i
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l y [ ie "GPC" GEORGIA POWER COMPANY-p By: hQJk , Name:- Fred D.. Williams
Title:
Vice President, f, Bulk Power Markets - "OPC" !' OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION) JA y: . , k Name: F. F. Stacy
Title:
President and Chief Executive Officer "MEAG" MUNICIPAL ELECTRIC AUTHORITY-OF GEORGIA' By: q Name:- Donald L. okley
Title:
President and General Manager-
" Dalton" THE CITY OF DALTON, GEORGIA BOARD OF WATER, LIGHT AND SINKING FUND COMMISSIONERS (3 By */WEP V
Name: James E. Brown
Title:
Chairman
'l
[ b-i y
/ rc's dmcany ~ ,
j3:3 D40~:atAvence ,; ' )M: s h h ', i
' ( &pp ' , ' L, Teieceone Atianta404Georg.a 52M:26 3C308 '
o r L. Ma4mg Acoress.
, - Post Office Bos 4545 - '
M.. < . At:anta. Georgia 30302 o N __ , Geor.c..ia Power-r
- um mr ~ . - - - % s-October 15,=.1986 h, q.
846 g Mr. George Taylor Oglethorpe Power Corporation 2100 E. Exchange. Place
-P.=0.. Box 1349-Tucker,' Georgia 30085-1349 D e a r ' G e o r g e~,,
. Attached-is'a chronologic itemization of events associated with-Oglethorpe's. sale ~.to.-Seminole on October 13, 1986. The projected-system lambda was: estimated to exceed and the transaction was-terminated,.as shown.
As-further transactions are scheduled, I would appreciate your-
' inquiring of us rather than Southern Company. Services to?obtain transactional,statusior information. Either Itby.Ballard, Fred PETadise, or I should be'available to assist you. At'the same.
. time.we'will' request Southern Company Services to keep;'us' informed of.any unanticipated' changes in a transaction's status and relay L, ,
that information'en to you. If thi~s procedure should not satisfy your requirements,. we will take remedial steps. Your understanding and assistance.in~ this matter'are-appreciated.
't' k
Yours truly, i William J. Smith-
' WJS/aa-i Attachment i~
cc: R. W. Dawson ' W. L. Marshall, Jr.
,.. "4 T d-T -
d-. ! F. D. Williams V-I. B. Ballard OCT lti 1968
- r. T. Paradise BUG PVM dMN I I i
i _. _ m __m_ ________.1._._ _Q
l", I DETAILS OP-;GPC-OPC' TRANSACTION FOR SEMINOLE
- OCTOBER 13, 1986
&" CDT . 7:00A Schedule of-50 MW Unit Energy commenced at a' ramp rate of 10 MW/ minute, integrating 48 MWH'for the hour ending 8:00A. 'This schedule continuedLthrough the hour ending 9:00A. 8:30A
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.The 8:30A evaluation projected Scherer 1 to be loaded above 350 MW during the next hour. The schedule was changed to Optional Energy and' D continued at the 50 MW rate for the hours ending
'10:00A, 11:00A and 12:00 Noon.
- 11:30A. The 11:30A evaluation projected system lambda to'be too high to allow the continuation of Optional Energy.
12:00 'The schedule was. cut to 0 at 12:00 Noon, ramping g, down at 10 MW/ minute. 2 MWH was integrated for the hour ending 1:00P. The schedule was to be resumed when conditions q l allowed. However, Scherer 1 generated in excess of . [ 350 MW and system lambda remained too high for the , remainder of the scheduling period. 4 l 1 i 1 E_m__ m . __.___ __..___: _ _.
, 1 K, ,
. Mr. ' Fred D.' Williams -
Page 2:
..q November 11, 1986 s ,
Oglethorpe recognizes that the operation of the current.ITS Agreement does not 1 . address the burden on nor the compensation to any other participants in the y -ITS. as a result of transactions under Service Schedule EP during valley or E ' low-load conditions nor because of power flowing through Georgia by the ITS. Consequently, ~ even :though Oglethorpe's investment in facilities supports the use of GPC's facilities necessary- to affect transactions under Service Schedule' EP, Oglethorpe' recognizes GPC will be the only party compensated 'for use 'of the ITS Dy Florida Power & Light Company during non-peak periods, and p will receive the benefits of negative incremental transmission losses.
..The parties recognize that just as Southern Company Services, Inc. has offereo its interconnection points to Florida Power & Light Company through Service L- Schedule EP thereby enabling Flordia Power & Light Company to increase its off-system market opportunities, Southern Company Services, Inc, likewise should~ offer a comparable. schedule with similar terms and conditions providing the same opportunity for . Oglethorpe to pursue similar off-system opportunities, 'particularly given Oglethorpe's investment in generation, transmission and substation equipment .which has enabled Southern Company Services, Inc. and GPC to facilitate their own off-system transactions. GPC agrees to use its best efforts to negotiate . and implement, through Southern Company Services, Inc.,.such a schedule for Oglethorpe's benefit.
We' appreciate your efforts to take all reasonable: and necessary actions in order .to expedite. the process to include all of GPC's 500. kV lines interconnected with Florida utilities in the ITS in order to account more properly for the allocation of economic burdens and benefits associated with'
- the use.of these particular lines.
Finally, GPC acknowledges and agrees that pursuant .to the ITS Agreement and Tariff, and notwithstanding the generating resources of such party, each party, -including Oglethorpe, has currently, and in the future during the term-of the ITS Agreement, will continue to have equal access to the transmission facilities of each other party, thereby allowing Oglethorpe now and during said term to use the ITS ' for any transaction similar to those contemplated under Service Schedule EP. Sincerely, P . ;A-G. Stanley Hil Senior Vice Pr ident . Planning and S- tem Operations GSH:ljh ,
' Accepted and agreed to:
Georgia Power Company
, By-Fred D. Williams
_=_____-_-__. ____:___.
n w . .. Oglethorpe Power Corporation 2100 East Excharure Pla. .. July-9, 1987 Po Sa l u9 Tucker. Georgia :1000149
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t an.u r . r... . RECBlVED Mr. William J. Smith Manager, Bulk Power Marketing Services Georgia Power Company 3987 333 Piedmont, N.E. - 20th Floor Atlanta, Georgia 30308-BIRA POUR llARKET3 Dear Bills h
Subject:
JGeorgia Power Company Response to FERC Def.iciency Letter on Scheduling Services Agreement We reviewed Georgia Power's March 9,.1987 response to the FERC deficiency letter on the Scheduling Services Agreement and found ; several items with which we take exception to. We did not F transmit these exceptions to the FERC and now'that the FERC-has approved the. agreement we.wish to bring them to your attention.
.We feel that'certain of these items must be properly addressed in the Interchange Scheduling Services Agreement discussions now ongoing between us.
In- the first item, FERC questioned the basis for charging optional' and Temporary. Energy at Plant Scherer's monthly average cost or the Southern System incremental cost plus 5 mills. Your responss to this question stated that this was deemed to be
-acceptable payment in lieu of capacity charges. We disagree with this raference to capacity charges.
s FERC questioned- the proposal of pricing at Scherer's cmsts when the plant was - unavailable. It appears that they disagree with the concept of pricing a transaction out of a plant that is unable to perform the service and that alternative pricing arrangements are more appropriate. The question arises because the FERC- defines the term " unavailable" differently from that contained in the agreement. optional Energy is provided at GPC's discretion when Plant Scherer is unavailable (as defined by the terms of the Agreement)
'and is an opportunity for GPC to receive an economic benefit by
"~ continuing the schedulo. This economic benefit occurs when GPC can . produce the scheduled energy at a cost less than Plant Scho,rer's monthly average cost. It is, in fact, a transaction between GPC and Oglethorpe Power. Capacity charges should not be considered in this transaction since Oglethorpe Power-owned Scherer capacity is available and able to serve the_syhedul..e... . y_ ___ c . , eU, ,. ;7 , I' An Electnc Membership Cooperative m.
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)
l'- Mr. Willic:2 J. Smith Page 2 July 9, 1987 If- the situation existed where the capacity of Scherer was truly L unavailable to serve the transaction by virtue of being on outage or . economically dispatched to its maximum output to serve-territorial load, your references to capacity may be more valid. However, unit availability that .was invoked in the Seminole j transaction was not for these reasons.but due to an accounting treatment within the. Southern Pool. As it has_been explained to
-us, if Oglethorpe. Power undertakes a transaction that would cause the loading of Scherer. (while in economic dispatch) to raise above its minimum operating level, the Southern dispatch system H would respond to this loading with not only Plant Scherer but with other similarly priced units (i.e., Plants Miller and Daniel). A problem exists because there are no accounting.
methodologies in olace to more accurately compensate the owners f of the Miller an. vaniel units for this increased generation nor to . transfer this cost to Oglethorpe Power. Georgia Power's , solution' to this problem is to declare the unit' unavailable in ) j this. situation. We feel that we are being denied access to our L 'Scherer-capacity.due to shortcomings in the Southern dispatch and . accounting systems. This. is not an accusation that Georgia Power did anything in violation of the agreement. Georgia Power acted within their rights as defined in the Scheduling Agreement, but this is an item that must be resolved in the Interchange Scheduling Services Agreement. The disagreement with the capacity reference to Temporary Energy is. a philosophical matter rather than the clear accounting problem with Optional Energy discussed above.
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Under the PR Tariff, we buy capacity and reserves to supplement our owned generation to meet our annual peak responsibility. We buy this capacity and reserves determined on an annual basis. We have no disagreement with this methodology and strongly support its 'use. However, due to the decoupling of capacity and energy in the PR Tariff, we are in the position of under-utilizing the i capacity and reserves we have purchased. In a situation where our owned generation is on line and than the annual peak available and our load demand is less responsibility, the capacity we have purchased from you is not being. utilized on our system, but rather is available to be used by Georgia Power and the other Southern Operating Companies for your. own benefits. As long as the demand we create on Georgia Power's system (Oglethorpe Power's total demand including off-system transactions less owned generation available) is less than the capacity and reserves purchased on an annual basis, we _ . _ _ _ _ _ _ -. _._._.____.._.__.________-_______m______
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s 4 Mr. William'J. Smith Page 3 Julyf 9, 1987
- are. not using any of Georgia Power's capacity that has not I already -been. paid for by Oglethorpe Power. This is not a new concept .that - we are proposing in light of the Seminole transaction._ but is the very concept we have been. advocating for the:IIC methodology from some time.
- We-are not, sat this time,' advocating'that we have a right to sell p PR capacity during:off-peak hours, but it would appear reasonable
[- that Oglethorpe . Power has-the.right to utilize this capacity to support. an economy transaction. Your reference to capacity
' charges therefore suggests the notion of -selling the same capacity twice to Oglethorpe Power.
I A second item to which we take exception to is your. reconciliation of- the 0.5 mill /kWh . adder for the scheduling service fees. FERC has rejected the proposal that unidentifiable and unquantifiable costs exist in this type service. From the
~information supplied to FERC, it reasons that the cost of providing the . service is both identifiable and quantifiable and L therefore should not be on a mill /kWh basis. We discussed this very item during the negotiations for this agreement and at that time' argued, and will continue to argue, that the fee is totally
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inappropriate.- We would arguo that Oglethorpe Power should compensate . Georgia Power if Oglethorpe Power's transaction
. creates an additional. burden on the control center staff,
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however, when- no such burden exists the notion of this fee is inappropriate. This is true especially when Oglethorpe Power is already contributing to the dispatch of the Southern System through ~the PR rates and other contracts. Further, we find the-coordinators cost of $100 per transaction to be rather high and requires further discussion. O Finally, Georgia Power positioned itself in the Agreement not in a "no-lose" situation, but rather in a " win-win-win-win" situation.
.First, Georgia Power wins when we make a Unit Energy sale by supplying the energy at a cheaper cost than Scherer while charging Oglethorpe Power Scherer rates (demonstrated by the fact that Scherer does not move off minimum while in economic dispatch). Second, Georgia Power wins when it supplies Optional Energy by delivering that energy at a minimum of 3 to 5 mills
.below Scherer costs and charging Oglethorpe Power Scherer rates.
3; Third, Georgia ' Power wins if Temporary Enorgy is supplied by
-charging Oglethorpe Power 5 mills over what it costs to produce
- that energy. (while fixed costs have already been paid in PR).
Finally, GPC wins by charging a 0.5 mills /kWh scheduling service fee when this cost is hardly apparent.
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[Mr.2, William?Je' Smith [I. .Page;4 94
- July .9,; .1987 _
i < IS;reiterateL that these.are matters to.be discussedLand resolved ? between Oglethorpe Power; and Georgia Power;in:the Interchange-Scheduling Services: Agreement. . ife should be:able to come-.to a: p timely understanding =of these items without-the<involvemeret'of Ne the 'FERC.- While the discussions ~for'the Interchange' Scheduling c: : Services;. Agreement; 'have" lagged in?recent~ months, I. hope'that'we. Laay expeditiously proceed with these talks.
- ~ Sincerely, f g, g.
. John'A. Johnson Manager, Power Contracts: Department f
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.. .Mr. G.. Stanley Hill Mr. Brent A..Saylor a Mr.' Robert P. Carlton-
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- 333 p.eamont Avenue i '
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'\ Allenta Georgia 30308 . .
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*" ' Attenta.'Georgte 30302 y" :t
- Georgia Power .
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J e e , m.,e r.,. . R> January- 13,'1987 , J h
.Mr.' John-A.. Johnson m ,oglethorpefPower Corporation
- 2100^E. Exchange Place-P. O . .. Bo x : 1349.
K Tucker, Georgia 30085-1349' m , Dear' John
-This'is to:confira our meeting on. January 15, 1988, to ,
< discuss a proposed Interchange scheduling' services Agreement. J' p
,between Oglethorpe. Power, Corporation and Georgia Power Company. .
~" tit is Georgia Power Company's intention to work with Oglethorpe:to - autually develop, procedures to-implementA.no provisions. granted.it.
'in the various Generating Plant Participation-Agreements andithez
- Integrated Transmission system Agreement.-
As'you will recall,.we tereinated discussions during.the, . e summer,and: fall ofl1987 pending resolution'of the Rocky' Mountain negotiations'which included related scheduling and operations
. matters. Now that those discussions:have been successfully ccaylited,_we can;again give our attention to this project.
.With regard to the October. 12, 1983 meno'to Mr. G. Stanley
- Hill,jMr.!Dahlberg correctly stated that the PR tariff.or-any
. other contractual agreement does not restrict oglethorpe from making off:systemisales. For-example, oglethorpe can sign the 7RJ tariff and perform the necessary notice requirements (which-. _
Georgia Power. Company has' stated would' satisfy the AEC settlement conditions), removing.any. restrictions'to.oglethorpe' making off i
' system' sales. .oglethorpe could also. contract with Georgia Power
' Company as they did with the sale of Scherer energy to seminole.
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As-evidenced by the Seminole Agreement, the multi-year involvement
'in.the Georgia Power Supply. Project, and the new ITSA-negotiations,' Georgia Power has demonstrated 'its willingness to work with oglethorpe, and will continue to do so in the future'.
1 I an'look'ing forward to a productive' meeting on January 15. should you.have any questions in the meantime, please advise. Si rely,
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Y \ Willian J L mith WJS/aa h cc: r. D. Williams [ & 3
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