ML18107A360

Non-proprietary Tech Specs Pages Re Transfer of PSEG Ownership Interests & Licensed Operating Authorities to New, Affiliated Nuclear Generating Company,Pseg Nuclear LLC

ML18107A360
Person / Time
Site:	Salem, Hope Creek
Issue date:	06/04/1999
From:	Public Service Enterprise Group
To:
Shared Package
ML18107A359	List: ML18107A357 ML18107A360
References
NUDOCS 9906090124
Download: ML18107A360 (133)

Text

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 APPENDIX2 Technical Specification Changes Salem Unit 1 Changes References to Public Service Electric and Gas Company or PSE&G are being replaced with PSEG Nuclear LLC in the following Sections:

Technical Specification section, page Action Description number Definition 1.16, page 1-4 Change PSE&G to PSEG Nuclear LLC Appendix B cover sheet Change Public Service Electric and Gas Company to PSEG Nuclear LLC Appendix B, section 4.2.1, page 4-1 Change PSE&G to PSEG Nuclear LLC Appendix C, heading, page 1 Change Public Service Electric and Gas Company to PSEG Nuclear LLC

• (

I 9906090124 990604 PDR ADOCK 05000272 P PDR

\

OEFINITIONS

b. Leak191 fnto th1 cont11n1119nt atmosph1r1 from sourc1s that are botn spec1f1ca11y loc1tld ind known t1th1r nae to 1nt1rf1!"9 with tn1 op1rat1on of l11k1g1 dltect1on systens or not to bl PRESSURE aOUNCARY LEAKAGE* or **

c. R~tctor coolant syst* l11kag1 through 1 st** g1n1r1tor to tht secondary syst81.

MEMBER(S) OF ,THE PUBLIC 1.15 MEMBER(S) OF THE BLIC .shall be 111 those persons who ar1 not occup1t1on1lly ass 1tld wfth the pl1nt. Th1s category does not include employees of , ts contractors, or vendors. Also excluded frem this category 1r1 persons who 1nt1r the site to s1rv1c1 equipment or to 1111k1 d1lfv1r11s. This category does include persons who use portions of the site for r1cr11t1on1l, occup1tion11. or other purposes not assccf1ted with th1 plant.

OFFSITE COSE CALCULATION MAHUAL (OOCM) l.17 The OFFSITE DOSE~CALCULATION MANUAL shall be that manual which contains th* current methodology 1nd par11111t1rs used fn the ca1culat1on of offs1te doses du1 to radfoacthe gaseous and liquid 1ff1u1nts, fn the c1lcuht1on of gas~iJus and liquid effluent man1tor1ng 1l1r.1/trfp setpo1nts, 1nd 1n the conduct of tne 1nvf ronmental r1dfologfc1l monftorfng progr111.

OPERABLE

• OPERABILITY l.lS A systc=, subsystem, tr;1n, c~oncnt or dev1aa shall be OPE~ASLE or nave OPERABILITY when it ts cap1bl1 of perfot'llfng its spte1f11d funct1on(s), and when al 1 necesury *ttendlnt 1nstrutn1ntat1on, contr:ols, 1 nort111l and an emergency 11ectr1c1l pow*r source, cooling or s11l w1t1r, lubric1t1on or other aux~11ary equipment th1t 1.-. requ1rld for the syst .. , subsyst.. , tr11n, ca11Qon1nt or dev1c1 to p1rfors its funct1on(s) 1r1 1lso capable of perfor111ng :heir relate~

support funct1on(s).

CPE~ATtONAL MODE

• MOOE l.l9 ~n OP!RATIONAL ~E (t1., MODE) shall correspond to 1ny one fnc~us1ve comb1~1t1on of cart re1ct1vfty c~nd1t1on, power l1v11 and aver191 reactor coolant ttmperature speci-fftd 1"' Table l.l .

• Sl.LS::1 - :JNIT l l-4 Amendment No. 59

'10 FACILITY O~ LIC!Hm ?<<). OPR-70 SAUM ~ STATiaf UNIT 1

~ 00. 50-272 AND FACILITY O~. LICUSE .?<<>. OPR-75 ff:J E& N Vl 1-EA(L \... \_ (_

FUBtafC Sll(Y'fa: EEBelmC >>I) GM ED1PN1Y o Amendment No. 100

4.0 Bnvironmental Conditions 4.1 O'nu*ual or :Important Bnvironmental Bvents Any occurrence of an unu*ual or important event that indicate* or could result in significant environmental impact cau*ally related *to plant operation shall be recorded and reported to the NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> followed by a written report per Subsection 5.4.2. The following are examples: excessive bird impaction event*; onsit* plant or animal disease outbreak*; mortality or unusual occurrence of any species protected by the Bndangered Specie* Act of 1973; fish kill* or impingement event* on the intake screena; increase in nuisance organisms or conditions; unanticipated or emergency diacharg* of waste water or chemical substanc***

No routine monitoring programs are required to implement thi*

condition.

4.2 Bnvironmental Monitoring 4.2.l Aquatic Monitoring The certification* and permit* required under th* Clean Water Act provide mechanisma for protecting water quality and, indirectly, aquatic biota. The Nuclear Regulatory Commission (NRC) will rely on the decision* made by the State of New Jer**Y under th* authority of the Clean Water Act and, in the case of sea turtles and shortnose sturgeon, decisions made by the National Marine Pisheri** Service (NMJ'S) under the authority of the Endangered Specles Act, for any requirements pertaining to aquatic monitoring.

In accordance with Section 7(a) of the Endangered Species Act, on May 14, 1993, the National Marine Pisheries Service issued a Section 7 Consultation Biological Opinion related to the operation of Salem Unit l and 2 Generating Station*. Th* Section 7 Consultation entitled, "Reinitiation of a con*ultation in accordance with Section 7(a) of the Endangered Specie* Act regarding continued operation of the Salem and Hope Creek Nuclear Generating Station* on the eastern shore of the Delaware River in New Jer*ey,* concluded that * *** continued operation not likely to jeopardize the continued existence of listed species.*

Nu tL AfZ... L-\-

-P8Krnit"'sha a ere to the *p*cific requirement* within the Incidental Take Statement, to the Biological Opinion. Chang** to the incidental take statement mu*t be proceeded by consultation between the NRC, a*

the authorizing agency, and NMJ.l'S.

The Conservation Recommendation*, to the Biological Opinion *ugg**t*

conservation recommendation* for implementation by Salem Generating Station. The Station shall implement th*** recommendation* to the satisfaction of the NRC and National Marine Fiaheri** Service.

SALBM UNIT 1 4-1 Amendment No. 216

APPENDIX C ADDITIONAL CONDITIONS OPERATING LICENSE NO. DPR-70 Public. SeL 11+/-C!! !:lectrlc '"13:lld Sa~ CompanC°Philadelphia Electric Company, Delmarva Power and Light Company, and Atlantic City Electric Company shall comply with the following conditions on the schedules noted below:

Additional Condition ImpleJMtntation Date 192 The licensee is authorized to :e:ocate ce::ain Technical -7~e a~enament 3~3 __ =~

Specification :equir~ments to :icer.see-controlled documents. i~piemen:ed ~~:~:~ 6:

mplemer.tation o: this amendment shal: include the :eiocation days ~:cm ~a:=~ ~:,

of tnese technical specif~ca:ion requi:emer.cs to tne appropriate documents, as jescribed in the ~icer.see's application dated .January 1:, :996, as s~pp:emented by

etters dated February 26, ~ay 22, :une 27, Ju:y :2, December 23, 1996, and Maren 17, :997, and evalt;ated in the staff's safety evalt;ation attached to this amendment.

194 The ~icensee is authorized to upgrade the initiation circuitry for the power operated relief valves, as described implemented prior co in the ~icensee's application dated January 31, 1997, as er.cry into Mode 3 from supplemented by letters dated ~arch 14, April 8, and April :he current outage Ecr 28, :997, and evaluated in the staff's safety evaluation Salem Unit :.

attached to this amendment .

• 196 The licensee shall complete all modifications associated with the amendment request concerning Containment Fan Cooler Units (CFCU) response time dated October 25, 1996, as described in the letters supplementing the amendment request dated December 11, 1996, January 28, March 27, April 24, June 3, The amendment s~a:~ ~e implemen~ed prior co entry into Mode J ::om the current outage for Salem Unit 1.

and June 12, 1997, prior to entry into Mode 3 following refueling outage 12. All modifications made in support of this amendment request and described in the referenced submittals shall be in conformance with the existing design basis for Salem Unit 1, and* programmatic controls.for tank monitoring instrumentation shall be as described in the letter dated April 24, 1997. Post modification testing and confirmatory analyses shall be as described in the letter dated March 27, 1997. Future changes to the design described in these submittals may be made in accordance with the provisions of 10 CFR 50.59. Further, the administrative controls associated with CFCU operability and containment integrity described in the letters dated March 27, and April 24, 1997 shall not be relaxed or changed witho4t prior staff review until such time as the license has been amended to include the administrative controls as technical specification requirements.

198 The licensee shall perform an evaluation of the containment The amendment shall be liner anchorage by November 30, 1997, for the loading induced implemented within 30 on the contianment liner during a Main Steam Line Break event days from July 17, to confirm the assumptions provided in the Preliminary Safety 1997.

Analysis Report and Updated. Final Safety Analyhs Report.

1 Amendment No. 198

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 Salem Unit 2 Changes References to Public Service Electric and Gas Company or PSE&G are being replaced with PSEG Nuclear LLC in the following Sections:

Technical Specification section, page Action Description number Definition 1.16, page 1-4 Change PSE&G to PSEG Nuclear LLC Appendix B cover sheet Change Public Service Electric and Gas Company to PSEG Nuclear LLC Appendix B, section 4.2.1, page 4-1 Change PSE&G to PSEG Nuclear LLC Appendix C, heading, page 1 Change Public ~ervice Electric and Gas Company to PSEG Nuclear LLC

OEPINIT!OMS

11. Lffkat* tnta t!t* =nutrmnt 1tmasph*,.. fl'"Clm 1ourc:11 tJtat 1,.. batn sp.:1t1ca1 ly 1ocitld .1na knawi et~.,. not ta 1nterltt'9 w1 t!I t~*

a,erat1Gll of ltlklfe atta1on 11n- Of" nat ta be PRESSURE ICUftOAAY LIAXAG. or

c. *ucur caolant 11~* ltlkage tllroutft 1 st** su*ratar ta tne MCanU1'7 Qtt**

MWD(Sl GI' TMI PUILIC f ________

St.(,

...........'---' ~~---..-)

1.11 ....D(S) "' IC 111111 M 111 ttln* .-sons ....... nd OCQP1t1on11l1 u atea wf"9 tJle plant. 1'1lf1 cat1to'7 claes noc tnchad*

• l01ees of , ts canvac:tars, or 'MMars. Also acluciecl fram t!lf s cauta'7 1" !Mrtaftl ,... lfttll9 U. s1tll to sema -.u1s-nt or to lllk1 alh*r111. 1'1lf1 cat1te1'7 .._ tnch1da 119rsa111

• 111* partfolls of t!I* s1te tor 1"1Cr91t1w1, oce11111t1onal, r oCJlw purposa nae 11soc1lttd wft!I U. plant *

• • aP11stn oon CALcuuna11 MllM. caaon 1.11 nte tJte owsm DOSI CALCUUTtOll MMUAL sun cu'°""' ..UOUlotr to N41oecth* taHOUI m llM&

IM tnat *nual .tttdl conutns par-t*rs aed tn tM c:alcallt1* of offt1t* dasts 11.,1a 1f'1uent1, tn tne ca1aa11t1a11 of gueaus lllfi *11qa1d etf'lu..c -ttor1nt 11&1'W/"'1p setpa1nts, lftCi 111 the canGc:C of tJte M~l"OI urtal rH1alot'fca1 -1tor1nt prov-.

OPOA!U * °'DAltLm 1.11 A 11n*. 1utat1ft*, trtf11, c=im11onent or cl**fca 11t1n ~* OPilUl&.I @F haY*.

• Ol'llAltLm .-.. " ts ~1* of perlOtWtnt tts sa-=tt1tc1 tunctton(s), 111a *h*

111 llKllM"' ICUllC&llll 1~t10ft 1 cmtroll, I rt0,_1 1114

• wrtMC1 tlectr'fcal ~ smara, caolf111 or SM1 *UP, luartcatt* or OC!ler 111a11t117 equtpmne tJ'ld IN ,.....-tr9' for u. 11n*, 1uta11tt*, tratn, *c=im111onenc o,.

da'lica ta perf'Ot'll tu fltancl1a11(1) ' " also capail* of 119rlorwf nt tttet,. 1"'11 atld 11q1..,-C twlelf *(I)*

Ol'llATtO!UL. MGDI

• 9 l.11 All Ol'IUTIOIUI. a l (t*** MDDI) stta11 calftllGIMI to* lllJ one 1nclushe c-1nat1* of ca" rHct1"CJ cancttt1*, PollW 1...1 IH ,.,.,.,,. N1ctar cao: ..ii'C c-.ratu,.. sp.c1'1td tn Tlil* 1.1*

• SALIM

• UNIT Z *'-ldlut Na. 21

APmmDC ..B FACIL!'1Y OPERATIN:; Lic:mm 00. DPR-70 SAUM ~ S'IM'ICN UNIT 1 IXX!l<E'I' 00. 50-272 FACIL!'1Y OPERATIN:; LICENSE .00. mR-75 SAUM ~ STATICN UNl'l' 2 LXX1<El' 00. S0-311 f? e(,- N \Jc.. LE-~ \.-\.....(_

_t;t.lBT TC SERVlC% F"FX'TPIC -UJD ca.9 o::MP>>I¥ Amendment No. 77

4.0 Bnvironm*ntal Condition*

4.1 tJnu*ual or Important Bnvironm*ntal Bv*nt*

Any occurr.nc* of an unu*ual or important *v*nt that indicat** or could re*ult in *ignificant *nviromll9ntal impact cau*ally r*lat*d to plant op*ration *hall b* r*cord*d and r*port*d to th* NRC within 24 houra follow*d by a writt*n r*port p*r Sub**ction 5.4.2. The following ar*

examples: exc*s*ive bird impaction *vent*1 on*it* plant or animal dis**** outbr*ak*1 :mortality or unu*ual.occurr.nc* of any *p*ci**

prot*ct*d by th* Bndang*~~d Sp*ci** Act of 19731 fiah kill* or imping9111*nt *v*nta on th* intak* acr**n*1 incr*a** in nuiaanc*

organisma or condition*; unanticipat*d or em.rg*ncy diacharg* of wast*

wat*r or ch911lical subatanc***

No routin* :monitoring programa ar* r*quir*d to implmnent thi*

condition.

4.2 Bnviromll9ntal Monitoring 4.2.1 Aquatic Monitoring Th* certification* and p*rmit* r*quir*d und*r th* Cl*an Wat*r Act provid* m.chaniama for protecting water quality and, indir*ctly, aquatic biota. Th* Nuclear R*gulatory Commi**ion (NRC) will r*ly on th* decision* mad* by th* Stat* of N*w J*r**Y und*r th* authority of th* Clean Wat*r Act and, in th* ca** of s*a turtl** and ahortno**

sturg*on, d*ci*ion* mad* by th* National Marin* Pi*h*ri** S*rvic*

(NMPS) und*r th* authority of th* Bndanger*d Sp*ci** Act, for any requirements p*rtaining to aquatic monitoring.

In accordance with S*ction 7(a) of th* Bndang*r*d Sp*ci** Act, on May 14, 1993, th* National Marin* Pi*h*ri** S*rvice i**u*d a Section 7 Consultation Biological Opinion r*lat*d to th* op*ration of Salmn Unit l and 2 G*n*rating Station*. ~h* S*ction 7 Con*ultation *ntitl*d, "R*initiation of a conaultation in accordanc* with Section 7(a) of th*

Bndangered Sp*ci** Act r*garding continued op*ration of th* Sal9111 and Hop* Cr**k Nucl*ar Gen*rating Station* on th* *a*t*rn ahore of th*

D*lawar* Riv*r in N*w J*r**y,* conclud*d that * *** continu*d op*ration is not lik*lY to j*opardiz* th* continued *xiat.nc* of li*ted sp*ci****

f\,f.c..~

~'I:::::

~\);\. ;,4,l'Z. \.\.. s

-PS!latr=*hall adh*r* to th* *p*cific r*quir...nt* within th* Incid*ntal Tak* Statement, to th* Biological Opinion. Chang** to the incid*ntal take atatmll9Dt llD18t b* proc**d*d by con*ultation b*tween the NRC, a*

th* authorising ag.ncy, and NJIJ'S.

Th* Con**rvation R*commendation*, to th* Biological Opinion *ugg**t*

cona*rvation-r*commendation* for impl . . .ntation by Sal. . Gen*rating Station. Th* Station *hall implmnent th*** r*ccmmendation* to th*

satiafaction of the NRC and National Marine Pi*h*ri** S*rvice

• SALDI OHl:'l' 2 4-1 Amendment Ho. 196

APPENDIX C ADDITIONAL CONDITIONS

..L~ OPERATING LICENSE NO. DPR-75 i?ublic Ser vice Electtic and c;as Comparrt,"-Philadelphia Electric Company, Delmarva Power and Light Company, and Atlantic City Electric Company shall comply with the following conditions on the schedules noted below:

Am9nctm.nt Additional Condition Implam.ntation Number Dat*

175 7he ::=ensee .:.s a~:~cr~zed __ :e:=:a:e =e:ta~n ~ech~:ca:

Specifica:ior. :equ!remer.ts :o ::cer.see-ccr.trol!ed documer.ts. implemented ~i:r.ir. 50

mp!ementat!cr. of :his amendmer.: sh3:l !nc!ude the relocation days ~=~rn ~a==~ 2:,

of :hese technical specifica:ior. requirements :o the appropriate docu~en:s, as described ir. the !icensee's 3pplicatior. da:ed :ar.1..;ary ::, :396, as S'..lpplemented by

et:e:s dated :"ec:*..:ary 26, ~ay 22, ::..:ne 27, July 12, i:lece:nber 23, :396 and :v!a::c:-. ~7, 1997, ar.d eva!uated in :he staff's safety eva::..:atior. a:tached :o :r.is 3mer.dmer.t.

177 T~e  ::cer.s~e ~s a~:~or:zed :o ~pq~ade the init:at:on ~he ame;.dmenc shal: oe oi:c*..:i::y :or :!'.e power :::pe:a:ec re:ief *1alves, as descr!bed  :.~p:ernented p:ior :o in :r.e ~ioensee's app:ica:ion ~a:ed :ar.1..;ary 3:, :,~7, as en::y in:o :-!cde 3 ::::cm supplemented by cet:ers datea March :4, April 8, and April the cu::::enc o~:age :o:

23, :337, a~d eva::.la:ed .:.:1 :~.e .s':a::'.s .5a:e:y eva:1_;at:::ln sa:em, *_*r.:.: 2.

a::ached :o :his amendment.

17 9 A:l modifications made in suppor: cf :he amer.dment reques:

concerning Containment Fan Cooler units (CFCU) response t!me implemented prior :o dated October 25, 1996, as described in the le~t 0 :s entry into Mode 3 ::om supplementing :he amendment :eques: dated December ll, 1936, t~e =urrent ou:aqe =~=

January 28, March 27, April 24, June 3, and June 12, 1997, Saiem, :..;nit 2.

shall be in conformance with_che existing design basis for Salem Uni: 2, and programmatic controls for tank mor.itoring instrumentation shall be as described in the letter dated April 24, 1997. ?ost modifica:ior. :es::ng and confirmatory analyses shall be as described in t~e :et:er dated ~arch 27, 1997. Fut~re changes :o :he design jesc:ibed in :hese submitta!s ~ay be ~ade ~~ a===:ja~=~ w~:~ :~e p:ovisi~~s ~!

10 ::FR 50.59. F~r:her, :r.a admir.:.s::a::.ve con::::o:s ass~ciated with :r:~ cpe:3oi:i:y an= :on:3inmen: :.n:egr!:y described :.n t~e ~a::e:s ::::a:e*:: :-!a:::-. 0 - a:-.d .:\pr:.: 24, :3r, 181 7he :ice~see sha::* pe:~o=~ an a'la:~a:i=~ ~! ~~a =oncainmen=

liner ar.c!":orage by ~cvembe: 30, :937, :or :he :cad:.ng ir.di.;ced ~~p:e~e~~ed ~~:~:~ __

on the containment :iner du::::ng a Main Stea~ L:ne 3reak event days !:-om ...:\.:~"/

o confirm the assumptions p:ovided :n the ?relimir.ary Safety j_ 397.

Analysis Report and Updated Fina: Safety Analysis Report.

Amendment No. :a:

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 Hope Creek Changes References to Public Service Electric and Gas Company or PSE&G are being replaced with PSEG Nuclear LLC in ~e following Sections:

Technical Specification section, page Action Description number Bases 3/4.8, page B 3/4 8-2 Change PSE&G to PSEG Nuclear LLC 6.9.1.9, page 6-20 Change PSE&G to PSEG Nuclear LLC Appendix B cover sheet Change Public Service Electric and Gas Company to PSEG Nuclear LLC Appendix B, section 4.2.2, page 4-2 Change PSE&G to PSEG Nuclear LLC (in two places)

Appendix C, heading, page 1 Change Public Service Electric ~d Gas Company to PSEG Nuclear LLC

7~* ~~~!mum ~olca9e and fr*quency 1caced ~n ch* Surve1l:anc* Requ 1remer.:s SR1l are :~ose ~*c***ary co enaure the ECO can &ccepc Oe119ft 8**11 Accljer.c

~oad1ng wh1l* !'!\&1nca1n1n9 *ccepc&i)le volca9e and frequency level*. SC*~l*

operac1on ac Ch* nom1nal voltage and frequeiicy valu** 11 alio ****ncl&l :o e1c&i)l1*h1n9 IOG OPl:IAaILITY. buc a time conacra1nc ia noc 1mpcaed. !h!* ~ 5 becau** a cyp1cal IJ:)Q will experience a period of voltage and frequency 01c1llac1ona prior co reach1n9 1ceady 1cace operac1on 1t Ch*** oac1ll&C!ons

• r* nae d&mpened ouc by load applicac1on. Th1a period may excend bayond :~e lO 1econd *ccepcance cr1cer1a and could be a caua* for fail1n9 che SR (for example 1t a 11gn1ficanc n~a~1ve crend developal . In lieu of

• c1me conacra1nc 1n ch* sa. ~ill mcn1cor and crend the accu.l c1me co reach eady 1cace operac1on aa a mean* at enaurin9 Chere 1a no voltage r99Ulacor or d~rad&c1on which could cauae an ECO co beccme inoperatlle.

Th* 1urveillance requireinenca tor detaanacraci119 che OPIJlAIItITY of che un1c bacceri** are in accord&a.c* wich Ch* recoamendaciana of Reg\lla~ory au1d*

1.12' *Maincan&nce T**ti119 &Del Replacetnenc of t.&1'9* Lead scora9e l&cceri** for Nuclear Pow.r Plant**, P~ru.ary 1t71 &Ad IISS Std 450*1910, *tlSS Recoamended Praccic* for Maincenance, Te*ciDlj, and Replacemenc of t.Al'9* Lead Storage aaccerie* for a.n.eratift9 Stationa and Su>>atationa.*

Verifying average eleccrol~e cemperature ~ve che nlinilllWll tor which :~e baccery waa aized, cocal battery terminal voltage on float cha1"9e, connecc!on reaiacance value* and che performance of baccery **rvice and diach.al'9* ce1c1 enaur** tho eftecciv*~*~~ of the ch.a1'9ift9 ayac... the atlilicy co handle h1gh di1ch.ar9* race* and compare* th* battery capac1cy at ch.ac c1me with ch* raced capac:i.cy.

Tattle 4.1.2.1*1 apecifi** the normal limit* tor each de*ignated pilot cell and each connec:ced call fo~ *l*ctrol~* level, float voltage and 1pecif1c gravity. Th* limit* for Clle da*ign&ced pilot call* float voltage and 1pec1f:i.c gravicy, 9reacer chaa 2.1J volt* and .015 below the 111Ul\lfacturer*1 full charge 1pecific gravity or a battery cha1"9er current chat had ac&bilized ac a low value, ia c!lara~ari*Cie of a chagyed cell with adaqu&t* capacity. Th* nc~l limit* tor ..ca CCllllMICCad call for flcac voltage and 1pecific gravity, greacer ch&n 2.1J vole. usd aoc more thaa .020 belcw ch* manufaccurer*1 full charge 1pec1f1c graTity wicla ua average apecif ic gravity of all cha connected eell*

noc mer* thaa ;010-below che mu1ufaccurer*1 full chazv* 1pecif1c gravity, en1ur** the OPSIA8%Lrrt usd capability of Che battery .

• HOPI C:UU B 3/4 l*Z J1Mndlwac Ne. 92

ADMIRISTRATIVB CONTROLS

-~-**------***-----*************---------**--------***--------------------****-

• BADIQACTIYI lllLQINT RILIASI MPQRT (Continued)

Th* radioactive effluent relea*e *report *hall al*o include an ******ment ot radiation do*** to the likely mo*t expo*ed MBHBIR or TBS PtJBLIC from reactor rel***** and other nearby uranium fuel cycle *ourc** (includinq do*** from primary effluent pathway* and direct radiation) for the previou* 12 con*ecutive month* to *how conformance with 40 CPR 190, Snvironmental Radiation Protection Standard* tor Nuclear Power Operation. Acceptable method*

for calculating the do** contribution f~Clll liquid and 9a*eou* *f fluent* are given in Regulatory Gui~* 1.109, Bev. 1.

Th* radioactive effluent rel**** report *hall include the followinq infoz:mation for each cl*** of molid wa*t* (a* defined by 10 CPR 61) *hipped off*it* durinq the report periods

a. container volume,

b. Total curie quantity (*pecify whether detemined by mea*urement or

• • timat*),

c. Principal ~adionuclid* (*pecify whether deteaained by mea*urmnent or e*timat*),

d. Type of wa*t* (e.9., *pent r**in, compact dry wa*te, evaporator bottcm*),

• • Type of container (e.q., LSA, Type A, Typl 1, Larqe Quantity), and

f. Solidification agent (e.g., cement, urea formaldehyde).

Th* radioactive *ff luent rel**** report *hall include unplanned relea*** from the *it* to the UllRSSTRICTBD ARSA of radioactive material* in 9a*eou* and liquid effluent* on a quarterly ba*i**

Th* radioactive *ff luent rel**.. report *hall include any cbanq** to the PROCBSI COR'?ROL PROGRAll (PCP), OffSITS DOS* CALCULA'l'IOK KAllUAL (ODCK) or radioactive wa*t* *Y*tem9 made during th* reporting period.

MONDLJ OPQMIMG RIPOl1'1 6.9.1.8 Routine report* of operating *tati*tic* and *hutdown experience *hall be *ubaitted on a monthly ba*i* to the u.s. llual*ar Regulatory Commi**ion,:.e Document control De*k, Wa*hington, o.c. 20555, with a copy to the USllRC Admini*trator, R8gion 1, no later than the.15th of eacb month following th*

calendar month covered by th* report.

cop QPIMTil9 LIMITS BIPOB'l' 6.9.1.9 core operating limit* *hall be emt&bli*hed and ~nted in th*

~generated COD OPmtATillG LillITI UPOM before each reload cycle or any r ...ininq part of a reload cycle for the following Tec:bniaal Specification*:

3/4.2.1 AvmtAO* Pt.MAil LIDAR DAT GDDATIOll MD 3/4.2.3 KIKIJmll CRITICAL POWSll RATIO 3/4.2.4 LilmAR DA: GDDATIOll RATS BOPB CRSD 6-20 bliadllent No. 6 7 I-

ADPENOIX B TO FACILJTY OPE~ATING LICENSE NO. NPF-57 HOPE CREEK GENEOATING STATION fSf&- r-Jv(L-E:A-<L \.....L-L__

0 PURLIC SER'/IGE ELECTRIC AN9 SAS C~PANr>-<---

DOCKET NO. 50-354 ENVIRONMENTAL PROTECTION PLAN (NONRADIOLOr,ICAL\

Terrestrial Ecology Monitoring completed the implementation of the Salt Drift Monitoring Program to assess the impacts of cooling tower salt drift on the environment in the HCGS vicinity. This study was completed by the submission of two reports: ftPre-operational Summary Report for Hope Creek Generating Station Salt Drift Monitoring Program, August 1~84-December 1986# and ftOperational Summary Report for Hope Creek Generating Station Salt Drift Monitoring Program, January 1987-March 1989w. The pre-operational report was submitted to the NRC on April 30, 1987 (NLR-E87144) as an Appendix to the 1986 Annual Environmental Operating Report. The operational report was submitted to the NRC on October 10, 1989 (NLR-N89201) .

The "Operational Summary Report* contained information that fulfilled the requirements of a final report, and therefore will be considered the *Final Report". This report discusses salt deposition data, native vegetation studies, comparison of estimated salt drift and deposition with actual data, environmental effects of salt drift and pre- and post-operational data comparison.

The study indicated that only'minor, localized effects of cooling tower drift deposition are occurring. Higher deposition rates potentially attributable to the cooling tower were me~~ured at only one location, which is on station property at a distance of 0.4 km southeast of the cooling tower. The salt deposition rate at this site is 113 mg/m2/month, which is well below the deposition levels that have been reported to cause vegetative damage of 10,000 mg/m2/year. Hope Creek Generating Station is surrounded by extensive areas of tidal salt mar*h and the nearest uplands are located approximately three miles to the ea*t, therefore no aignificant adverse impacts will occur as a result of cooling tower operation.

~s satisfied the commitments under this requirement. No further monitoring is required .

• HOPE CREEK 4-2 Amendment No. 111

APPENQIX C

. --*------------- ADDITIONAL CONDITIQNS OPEBATING LICENSE NO. DPR-57

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Ptlblie Se~ice ElectEie aaa Gas Compaai2and Atlantic City Electric Company shall comply with the following conditions on the schedules noted below:

Additional Condition Implmuntation nate 97 The Licensee is* authorized to relocate certain The amendment Technical Specification requirements to shall be licensee-controlled documents. Implementation implemented of this amendment shall include the relocation within 60 days of these technical specification requirements from March 21, to the appropriate documents, as described in 1997.

the licensee's application dated January 11, 1996, as supplemented by letters dated February 26, May 22, June 27, July 12, December 23, 1996, and March 17, 1997, and evaluated in the staff's safety evaluation attached to this amendment.

103 The licensee shall relocate the list of "Motor The amendment Operated Valves - Thermal Overload Protection shall be (BYPASSED)" from the Technical Specifications implemented (Table 3.8.4.2-1) to the Updated Final Safety within 60 days Analysis Report, as described in the from September licensee's application dated July 7, 1997, and 16, 1997.

evaluated in the staff's safety evaluation attached to this amendment.

105 The licensee shall use the Banked Pattern The amendment Withdrawal System or an improved version such shall be as the Reduced Notch Worth Procedure as implemented described in the licensee's application dated within 60 days June 19, 1997, and evaluated in the staff's from September safety evaluation attached to this amendment. 30, 1997.

110 The licensee shall relocate the suppression The amendment chamber water volume, as contained in shall be Technical Specifications 3.5.3.a, 3.5.3.b, implemented 3.6.2.1.a.1 and 5.2.1 to the Updated Final within 60 days Safety Analysis Report, as described in the from November 6, licensee's application dated August 20, 1997, 1997.

and evaluated in the staff's safety evaluation attached to this amendment.

114 The licensee is authorized to perform single The amendment cell charging of connected cells in OPERABLE shall be class lE batteries as described in the implemented licensee's application dated September 8, within 60 days 1998, as supplemented by letter dated December from February 9, 8, 1998, and evaluated in the staff's safety 1999.

evaluation attached to this amendment.

1 Amendment No. 97, ?0J, l0 ll0, 114

APPENDIX3 Basis for Operating License and Technical Specificatio:µ Changes and No Significant Hazards Consideration Determination

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 Appendix 3 License Change Request (LCR) H99-06 and 899-14 The changes proposed by LCR H99-06, for the Hope Creek Generating Station, and LCR S99-l 4, for the Salem Generating Station, are described and shown in Appendix 1 and Appendix 2 of this Attachment. Appendix 1 contains the changes associated with the Operating License for each of the three units, while Appendix 2 contains the Technical Specification changes for each unit. The purpose of these changes is to revise or replace references to Public Service Electric and Gas Company, or PSE&G, with the new name PSEG Nuclear LLC. The reason and justification for these changes, as well as additional background information, is contained in the cover letter of this transmittal (LR-N99257).

The following section provides the 10 C.F.R. § 50.92 No Significant Hazards Consideration determination for these changes. The proposed amendment changes related to the transfer of the nuclear plants were reviewed by the Salem and Hope Creek Station Operations Review Committee.

No Significant Hazards Consideration Determination Although not required by the ruJe governing license transfer, which became effective December 3, 1998, this No Significant Hazards Consideration evaluation is included to facilitate NRC Staff review of the application and the conforming license amendments.

Description of the Change The transfer in ownership interests and operational responsibility for Salem, Units 1 and 2, and Hope Creek, involves making a number of administrative changes to the operating licenses and plant Technical Specifications to reflect a new nuclear generating affiliate, referred to as PSEG Nuclear LLC, as the owner and operator.

Basis for Proposed No Significant Hazards Consideration Determination

1. The conforming amendments do not involve a significant mcrease m the probability or consequences of an accident previously evaluated.

The proposed amendments do not involve a significant increase in the probability or consequences of an accident previously evaluated because of the following:

The change does not involve any change in the design, configuration, or operation of the nuclear plants. All Limiting Conditions for. Operation, Limiting Safety System Settings and Safety Limits specified in the Technical Specifications remain unchanged. Also, the Physical Security Plans and related plans, the Operator Training and Requalification 1 of3

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 Programs, the Quality Assurance Programs, and the Emergency Plans are not being changed by the proposed amendment.

The technical qualifications of PSEG Nuclear LLC to carry out its responsibilities under the operating licenses, as amended, will be equivalent to the present technical qualifications of PSE&G. Upon the effective date of the transfer of the licenses, PSEG Nuclear LLC will operate, manage, and maintain the nuclear plants in accordance with the conditions and requirements established by the NRC as defined in* the operating licenses. PSE&G Nuclear Business Unit management, personnel, and organizations presently operating the units will continue to operate the units on behalf of PSEG Nuclear LLC. The qualifications of the personnel engaged in the operations, maintenance, engineering, assessment, training, and other related services are either unchanged or not changed significantly by the transfer. A Chief Nuclear Officer at the site will continue to be the officer at the site responsible for the overall safe operation and maintenance of the nuclear plants.

Therefore, the transfer does not involve an increase in the probability or consequences of an accident previously analyzed.

2. The conforming amendments do not create the possibility of a new or different kind of accident from any accident previously evaluated.

• The proposed amendments do not create the possibility of a new or different kind of accident from any accident previously evaluated because of the following:

The change does not involve any change in the design, configuration, or operation of the nuclear plants. The current plant design and design bases will remain the same. The current plant safety analyses, therefore, remain complete and accurate in addressing the design basis events and in analyzing plant response and consequences.

The Limiting Conditions for Operations, Limiting Safety System Settings and Safety Limits specified in the Technical Specifications are not affected by the change. As such, the plant conditions for which the design basis accident analyses were performed remain valid.

The change does not introduce a new mode of plant operation or new accident precursors, does not involve any physical alterations to plant configurations, or make changes to system set points that could initiate a new or different kind of accident.

Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

• 2 of3

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354

3. The proposed amendments do not involve a significant reduction in a margin of safety.

The proposed amendments do not involve a significant reduction in a margin of safety because of the following:

.The change does not involve a change in the design, configuration, or operation of the nuclear plants. The change does not affect either the way in which the plant structures, systems, and components perform their safety function or their design and licensing bases.

Plant safety margins are established through Limiting Conditions for Operation, Limiting Safety System Settings and Safety Limits specified in the Technical Specifications.

Because there is no change to the physical design of the plant, there is no change to any of these margins.

Therefore, the proposed amendments do not involve a significant reduction in a margin of safety .

3 of3

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NP.F-57 50-354 APPENDIX4 Stipulation

• Francis E. Delany, Jr.

Vice Pres1aent ar.o Coroorate Rate Counse1 Public Service Electric and Gas Company 80 Park Plaza. Newark. NJ 07102 I 973-430-6155 Fax No. 973-648-0838 fde1any@pseg.com Mailing Address: P.O. Box 570. Newark. NJ 07101

• March 17, 1999 In the Matters of Public Service Electric and Gas Company Restructuring, Stranded Costs, and Unbundling BPU Docket Nos.

E097070463, E097070462, E097070461 Mark Musser, Secretary Board of Public Utilities Two Gateway Center Newark, New Jersey 07102

Dear Secretary Musser:

On behalf of the undersigned parties, enclosed is a Stipulation encompassing a resolution of the issues in the stranded cost and rjlte unbundling proceedings and all of the non-generic restructuring proceeding issues included by the Board in the settlement process.

The undersigned parties, after extensive litigation and prolonged negotiations, have arrived at this Stipulation of the proceedings in a manner that resolves the following:

• Rate Reductions - PSE&G customers will receive four rate reductions over a three-year time period beginning with a 5% rate reduction on August 1, 1999 rising to 13.9 percent on August 1, 2002.

• Shopping Credits - One of the largest across-the-board restructuring rate reductions in the country is matched with the largest consumer shopping credit of any restructuring proceeding in the Country averaging in excess of five cents.

Mark Musser, Secretary 03117199

• Transition Period - Achieves full competition in only four years with Basic Generation Service supplied on the basis of a competitive bid in year four.

• PSE&G will transfer- its Generation Assets and Liabilities to an unregulated company - This transfer, coupled with a Code of Conduct for Generation, is intended to establish a level competitive playing field for generation.

• Assurance of Capacity Availability within PJM - The transferred generating capacity will be maintained as a capacity resource within the PJM system for the four year transition period.

The undersigned parties have arrived at this Stipulation after having considered the positions of all of the parties as they were reflected on the record at the Office of Administrative Law and at the Board of Public Utilities in the above-referenced proceedings .

The parties, after considering the positions in the record and the directive for rate reductions in the New Jersey Electric Discount and Energy Competition Act, propose through this Stipulation that the rates for all customers be reduced by 5% on August 1, 1999. This rate reduction for customers will *be approximately $200 million annually or

$800 million over the transition period.

The parties have further agreed upon an additional estimated 2% rate reduction for all the Company's customers. This estimated 2% rate reduction is related to the cost savings resulting from the securitization process and is projected to become effective on or about January 1, 2000. The reduction will result in an additional reduction in customers' rates of $85 million annually or approximately $300 million during the transition period.

The undersigned parties have agreed that on August 1, 2001 rates will again be reduced for all customers so that the aggregate reductions will be 8'/.i%. At this point, annual discounts will total almost $350 million annually.

The final rate reduction, which will take place on August 1, 2002 pursuant to this Stipulation, will average 13.9%. This will result in a reduction of revenues of almost

$600 million on an annual basis. The cumulative revenue savings to customers over the

• transition period will total approximately $1.5 billion.

• Mark Musser, Secretary 03/17/99 The parties to the Stipulation, giving consideration to the positions regarding shopping

• credits in the record, have agreed to a level of shopping credits for the four-year transition period which is higher than that provided by any utility or required by any state in the Country. The shopping credit levels agreed to in the Stipulation, will provide all classes of customers, residential, commercial and industrial, as well as marketers, with an opportunity to develop and engage in a competitive retail electric marketplace.

Furthermore, the parties have agreed that the recovery of eligible stranded costs are $3 .3 billion, which is approximately $600 million less than the Company's original request for recovery of $3 .9 billion. The parties have further agreed that the Company can only recover $3.075 billion of stranded costs, which results in the Company's foregoing the recovery of an additional $225 million of eligible stranded costs. Therefore, through this Stipulation, the parties have agreed that, based upon the record evidence, the Company will have the opportunity to recover a level of stranded costs that is substantially less than its original request in the proceeding.

The parties have also agreed that pursuant to the Act, the Company should be authorized to securitize approximately $2.475 billion of its stranded costs agreed to in the Stipulation.

The undersigned parties, in order to promote the development of a competitive generation marketplace, have proposed that the Company will transfer all of its generating assets and liabilities out of the utility and into an unregulated company. This company will pay the utility full market value based upon the stranded asset values agreed to in the Stipulation.

Additionally, this separatfon of generati~n from the utility will establish a framework for ensuring a level playing field for all other generators who will be offering generation services in New Jersey or within PJM. The Company has agreed that the unregulated generation company will, during the *transition period, offer any excess capacity, after it has first provided reliable capacity services to the utility and its customers to other potential suppliers within the PJM region. By this feature of the Stipulation, reliable service will be assured to those customers who stay with the utility and capacity will be first provided to potential purchasers within PJM. This agreement will assure a reliable supply of economic capacity for potential purchases within PJM and should assist in the development of a competitive marketplace to the benefit of New Jersey's citizens.

In addition to Public Service Electric and Gas, the undersigned parties that have executed the Stipulation represent a wide range of diverse interests, all of who have been actively

• involved in these proceedings, as follows:

Natural Resource Defense Council (NRDC)

Mark Musser, Secretary 03/17/99 A national environmental organization that was active in the proceeding representing positions and interests concerned with assuring a clean environment.

New Jersey Commercial Users (NJCU)

A diverse group comprised of the New Jersey Foo4 Council (NJFC) and the New Jersey Retail Merchants Association (NJRMA). The NJFC is the business trade association for the food distribution industry in New Jersey whose retail members represent over 1,500 New Jersey supermarkets and conv~nience stores along with their suppliers, many of which have locations in the service territory of PSE&G. The NJRMA represents over 1,400 companies conducting retail business in over 2,000 locations in New Jersey and within the service territory of PSE&G.

International BrotherJiood of Electrical Workers 94 (IBEW94)

This party is the collective bargaining representative of approximately 4,000 employees of Public Service Electric and Gas Company (PSE&G), many of which are electric customers of the Company. These men and women operate the nuclear and fossil generation stations, construct and maintain both the high voltage transmission and area distribution electric lines and transformers read and service all aspects of metering staff the research laboratory.

New Jersey Transit Corporation This party represents the largest single mass transit customer in the State of New Jersey.

Enron Capital and Trade Resources A large wholesale and retail marketer of natural gas and electric power actively involved in all aspects of these proceedings.

Tosco A customer which is one of New Jersey's largest companies engaged in the refining of petroleum products, who has been actively involved in these proceedings.

Independent Energy Producers of New Jersey (IEPNJ)

This party represents the interests of New Jersey's non-utility generators. They have been actively involved in these proceedings.

• Mark Musser, Secretary 03/17/99 The undersigned parties request that the Board approve this Stipulation at its earliest opportunity. The Board's approval of this Stipulation will insure rate reductions for all customers, full retail access to competition as of August 1, 1999, unprecedented shopping credit levels and assured reliability for electric customers.

Steven Montovano for Enron Capital Francis E. Delany, Jr. for And Trade Resources Public Service Electric and Gas Company Ashok Gupta for Charles D. Wolfe, President for Natural Resource Defense Council International Brotherhood of Electrical Workers, Local 94

• William Harla, Esq. for Independent Energy Producers of NJ Michael J. Mehr, Esq. for Ransome E. Owen for New Jersey Transit Corporation James E. McGuire, Esq. for Tosco/Bayway New Jersey Commercial Users C Herbert H. Tate, President Carmen J. Armenti, Commissioner Service List

• STATE OF NEW JERSEY BOARD OF PUBLIC UTILITIES In the Matter of the Unbundling BPU Docket No. E097070461 Energy Master Plan Phase II Propeeding OAL Docket No. . PUC-7348-97N to Investigate the Future of Stranded Costs BPU Docket No. E097070462 the Electric Power Industry OAL Docket No. PUC-734 7-97N Restructuring BPU Docket No. E097070463 Public Service Electric and Gas Company STIPULATION On January 16, 1997, the Board of Public Utilities (Board) issued an Order releasing "Restructuring tbe Electric Power Industry in New Jersey: Phase II Proceeding Proposed Findings and Recommendations Report" (Draft Report)

The Board held public meetings to receive comments on the recommendations contained in the Draft Report at the Board's Newark offices, at

.Camden County College in Blackwood, New Jersey, and at the Board's Trenton, New Jersey Hearing Room on February 4, 1997, February 5, 1997 and February 11, 1997, respectively.

On April 30, 1997, the Board released the Final Report entitled, Restructuring the Electric Power Industry in New Jersey: Findings and Recommendations (Green Book).

On February 9, 1999, the New Jersey Electric Discount and Energy

• . Competition Act, Chapter 23 of the Laws of 1999 (Act), was enacted. It provides inter

alia that all New Jersey retail electric customers are entitled to reduced electric rates and shall have the opportunity to exercise choice as to their electric supplier commencing August 1, 1999.

The undersigned parties rely upon the procedural history provided by ALJ Louis G. McAfoos in his Initial Decision of August 14, 1998 and on the procedural history provided by the parties in their briefs in the above-referenced proceedings.

On February 11, 1999 the.Board, at an Open Public Meeting established a target date of March 3, 1999 for receipt of any stipulations between the parties in the proceedings and indicated it was targeting a decision in the proceeding for March 31, 1999. Subsequently, the parties convened on numerous occasions in an effort to resolve issues in these proceedings.

During the course of these conferences, the undersigned parties have collaboratively resolved the following issues in the above-referenced proceedings. As a result, it is hereby agreed among the undersigned that the following encompasses a resolution of all the issues in the above-referenced stranded cost and rate unbundling proceeding and all of the non-generic issues in the restructuring proceeding which the Board included in the settlement process:

RATE REDUCTIONS. TRANSITION PERIOD AND UNBUNDLED RA TES

1) The parties agree that electric rate reductions shall be implemented as follows to comply with the provisions of Section 4(d) of the Act:

a) A 5% rate reduction from rates in effect as of the date of this Stipulation (hereinafter "current rates") for service rendered on and after August 1, 1999. This reduction includes a 1% reduction relating to the savings from securitization.

b) An estimated additional rate reduction of 2% of current rates targeted for

• service rendered on or after January 1, 2000 subject to the receipt prior to such date of a Bendable Transition Cost Rate Order establishing a securitization bond charge and providing for the securitization of $2.475 billion of generation-rela_ted stranded costs and the recovery of related taxes, costs of issuance, and transaction costs including costs of refinancing or retirement of debt or equity as provided in paragraph 11 (together "Bendable Stranded Costs") and the sale of the securitization bonds. The date of the reduction will be the same date as the securitization transition charge is established. The rate reduction provided to customers will reflect the actual savings from the issuance of the securitized bonds as computed under the methodology set out in Attaclnnent l, less the 1% savings

• included within the initial 5% rate reduction set forth in paragraph l(a).

This rate reduction and all subsequent rate reductions are contingent upon the implementation of the securitization transition charge.

c) A further rate reduction for service rendered on or after August 1, 200 I to bring the total rate reduction to 8.25% from current rates.

d) A final rate reduction for service rendered on and after August 1, 2002, in an amount that, when considered with the above reductions, will result in a rate reduction by* customer class of 10% relative to rates in effect as of April 30, 1997.

e) All rate reductions will be applied to each customer's bill to reflect the above agreed upon reductions, as set forth on Attachment2, page 2of19.

f) The rate reduction described in paragraph l(d) shall be sustained until July 31, 2003.

2) The parties agree that there shall be a four-year transition period commencing on August 1, 1999 and terminating on July 31, 2003 (Transition Period).

3) The unbundled rates to be effective for each rate class in Public Service's Tariff for Electric Service have been developed using the Company's 1995 Cost of Service Study will be using the parameters defined in Attachment 2, including the unbundled rates and rate components. Each customer's bill shall indicate the

• dollar amount of the difference between what the customer's total charges would have been without the reduction and the total charges in that bill pursuant to Section 4(b) of the Act.

DEPRECIATION

4) The parties agree that an excess electric distribution reserve in the amount of

$568. 7 million is to be amortized over three years and seven months beginning on January 1, 2000 and ending July 31, 2003. Amortization amounts will be $125 million in the year 2000, $125 million in the year 2001, $135 million in the year 2002, and $183.7 million in the year 2003.

• SOCIETAL BENEFITS CHARGE CLAUSE (SBC)

5) The parties agree that consistent with Section 12 of the Act, Public Service will establish a Societal Benefits Charge Clause (SBC). The SBC will include costs related to: 1) Social Programs (including the Universal Service Fund); 2) Nuclear Plant Decommissioning costs; 3) Demand Side Management Program costs; 4)

Manufactured Gas Plant Remediation costs; and 5) Consumer Education Costs.

6) The SBC will be set at the level of costs for the above items included in rates as of February 9, 1999, the effective date of the Act, and as more explicitly defined in Attachment 2. This SBC level will remain constant through the Transition Period.

Actual costs incurred by. the Company for each of the cost components enumerated in paragraph S will be subject to deferred accounting. Interest at a seven-year single A debt rate (lnter~st Rate) will be accrued on any under- or over-recovered balances. At the completion of the Transition Period, the SBC will be reset and then reset annually upon Board approval to amortize any over- or under-collected balances.

7) The parties agree that the DSM generation-related lost revenue created subsequent to August I, 1999 will no longer be reflected in the calculation of costs eligible for Demand Side Management Program cost recovery and deferral as described in Attachment 2.

NON-UTILITY GENERATION MARKET TRANSITION CHARGE (NTC)

8) Consistent with Section 13 of the Act, the parties agree that the Company's unbundled electric tariffs and distribution *service rates will include a NTC to recover the above-market stranded costs of Public Service's existing non-utility generation contracts. These contracts will continue to remain the obligation of Public Service Electric and Gas Company during the life of the contracts .. The Company will sell the energy and capacity from these contracts at the PJM Interchange Hourly Locational Marginal price and at wholesale within the PJM region, respectively.

• 9)

The parties agree that the initial level of the NTC will be set based on the above-market non-utility generation (NUG) costs for 1999 of $183 million (Exhibit PS-20, Schedule CJL-F3) and as more explicitly defined in Attachment 2 .. This NTC level will remain constant for a period of four years from August 1, 1999. Actual annual payments made by the Company for NUG costs will be reduced by the value received from the sale of the energy and capacity associated with those contracts as described in paragraph 8. For the purpose of <:=alculating the amount of stranded cost which Public Service is entitled to recover during the Transition

• Period, any increase or decrease in the above-market costs will be subject to deferred accounting and interest at the seven-year single A debt rate will be calculated on any under- or over-recovered balances. After the Transition Period, the NTC will be reset and then reset annually upon Board approval to amortize any

. over- _or under-collected balances. Board approved buy-outs and buy-downs of NUG contracts will be reflected in this clause in a manner consistent with Section 13(1)(3) of the Act.

STRANDED COST QUANTIFICATION (GENERATION ASSETS)

10) The Company maintains that it has established, through its testimony and exhibits, a conservative valuation of the fair market value of its generation assets. This

• valuation, when compared with the net investment in its generation assets, results

• in stranded costs of $3.873 billion (Exhibit PS-22, p.45). However, for purposes of this Stipulation, the Company and the signatories to this Stipulation agree that the Company is entitled ~o recover $3.30 billion of its generation-related stranded costs resulting from a market valuation of $0.046 billion and $1. 722 billion for nuclear and fossil generating assets, respectively. The increase in the value of fossil generating assets represents a compr~mise between the positions of the Company and other parties. The -Company and the signatories to this Stipulation agree to a total reduction of $225 million in the unsecuritized generation-related stranded costs including (1) to reflect the Company's estimated overrecovery in its Levelized Energy Adjustment Clause (LEAC) as of )uly 31, 1999 ($60 million after-tax) and (2) a reduction of $90 million of Salem stranded costs. As set forth in paragraphs 11 and 13, the Company will be provided with an opportunity to recover up to $3.075 billion-* of generation related stranded costs through securitization of $2.475 billion and an opportunity to recover up to $600 million of its unsecuritized generation related stranded costs on a present value basis.

SECURITIZATION

11) The parties agree that (i) Public Service, in order to comply with the requirements of Section 14 of the Act, will utilize the net proceeds of securitization, after

• payment of all related fees and expenses of issuance and sale, to refinance or retire

• its debt and/or equity; (ii) that such refinancing and/or retir~ent of such debt niay occur as a result of, among other things, mandatory and/or optional redemption, repurchase and/or tender by or on behalf of Public Service, which optional redemption, repurchase or tender may be at a premium; and (iii) that the Board should authorize Public Service to employ such methods as are reasonable and necessary to achieve the overall intent and purposes of the Act.

a) The parties agree that the Board issue a financing order to authorize Public Service to issue up to $2.6 billion of transition bonds representing $2.475 billion of generation-related stranded costs and an estimated $125 million of transaction costs including related fees and expenses of issuance, sale and to refinance or refund its debt and equity subject to approval of the Board.

The parties other than the New Jersey Commercial Users also agree that all taxes related to securitization will be separately stated on the tariff and will be recovered through the Board-established transition bond charges. The New Jersey Commercial Users reserve the right to comment on this tax issue. The signatories to this Stipulation also agree not to oppose the issuance of such a financing order or the sale of such transition bonds in any judicial or regulatory forum .

• 12)

The Company requests and the other parties do not object that the Board in connection with its review of Public Service's stranded cost filing and the record in the stranded cost proceeding should find pursuant to Section 14 of the Act that:

a) Public Service has taken reasonable measures to date on Mitigation of stranded costs (Exhibit PS-14) and the terms of this Stipulation including rate reductions, rate freezes, and other mitigation measures will create appropriate incentives in place to mitigate the total amount of its stranded costs;

• b) Public Service will not be able to achieve the level of rate reduction deemed by the Board to be necessary and appropriate pursuant to the provisions of Sections 4 and 13 of the Act absent the issuance of transition bonds providing for the recovery of its Bondable Stranded Costs as set forth in paragraph l(b); and c) The issuance of such bonds will provide tangible and quantifiable benefits to ratepayers, including greater rate reductions than would have been achieved absent the issuance of such bonds and net present value savings over the term of the bonds (see Attachment 1).

• . UNSECURJTIZED GENERATION STRANDED COST RECOVERY

13) Pursuant to paragraph 10, the parties agree that PSE&G should be provided with the opportunity to recover up to $600 million of its unsecuritized generation stranded costs on a net present value (8.42% discount rate) net oftax: basis over the Transition Period. This recovery is to be accomplished via a 2 mill per kWh retail adder, an expiicit Market Transition Charge (MTC), exclusive of the NTC, as discussed in Attachment 2, and the amount funded by the excess distribution depreciation reserve amortization. The parties further recognize that as Basic Generation Service (BGS) customers leave PSE&G for third-party suppliers, full recovery of these costs is not assured and represents a risk of undercollection .to Public Service.

14) At the end of the Transition *P~riod, the recovery of the $600 million will be reconciled to actual collections based on actual sales, the net present value (NPV) of recovery from both the MTC, exclusive of the NTC, and collections from a 2.0 mill per kWh retail adder for all customers retained on the BGS, and the depreciation amortization, and any payments to PSE&G resulting from BGS bidding in year four of the transition period pursuant to paragraph 17. In the event the Company fails to collect $600 million, it will be at risk for any such shortfall.

In the event the Company collects over $600 million, it shall use any such

• overrecovery to reduce the Company's SBC at the end of the Transition Period when the SBC is reset. The parties agree that the discount rate used in these present value calculation~ will be based on the same cost of capital/discount rate used to calculate securitization savings on Attachment 1.

BASIC GENERATION SERVICE/SHOPPING CREDIT

15) The parties agree that the Company's shopping credit shall equal its BGS rate, which shall be inclusive of an allowance for the cost of energy, capacity, transmission, ancillary services, losses, taxes and retail adder. The parties agree that the Company's BOS/shopping credit levels should be established and fi.xed for the duration of the transition period without adjustment or true up of any kind.

Accordingly, the parties agree to the following:

~ IQQQ 2illU. 2.002 2illll RS 5.71 - 5.86 5.86 5.86 5.86 GLP 5.30 5.35 5.39 5.44 5.44 LPL-S 4.84 4.88 4.93 4.97 4.97 LPL-P 4.54 4.58 4.62 4.66 4.66 HTS-SubT 4.30 4.35 4.40 4.44 4.44 HTS-HV 4.12 4.16 4.21 4.25 4.25 Overall 4.95 5.03 5.06 5.10 5.10 The above rates are rate schedule averages, which will differ by blocks and time periods of each rate schedule as defined in Attachment 2. Other minor rate schedules (RHS, RLM, WH, WHS, HS, BPL and PSAL) will be calculated

• consistent with the above as presented in Attachment 2. Additional shopping-related savings, resulting from customers receiving electric generation service from a supplier at a price less than the above shopping credits, are above and beyond the rate reductions set forth in paragraph 1.

16) The parties agree that the above-referenced pre-established BGS rates meet the shopping credit definition in the Act and resolve the issue of BGS pricing and the shopping credit in a manner that accommodates the partie~' concel_lls and satisfies the requirements of Sections 9(a) and 9(d) of the Act.

17) Basic Generation Service Obligation - Pursuant to Sections 9(a) and 9(b)(3) of the Act, the undersigned parties agree that the Company has a three-year obligation to provide BGS to _those retail customers who choose to remain with the utility during the three-year period ending July 31, 2002. The parties agree that they support the

. biddiQg out of the BGS to be provided after July 31, 2002. The first year bid will be a pre-payment method based upon pre-established shopping credit for year 4. If the bid for generation results in a payment to PSE&G, it shall be considered as a part of the MTC. If the bid for generation requires a payment by PSE&G, such payment shall be subject to deferral and subsequent recovery at the Interest Rate.

The undersigned parties agree that Public Service Enterprise Group Incorporated's (PSEG) non-regulated affiliate, pursuant to this Stipulation, will be ~uthorized to

bid for such BGS to be provided after July 31, 2002 pursuant to terms that apply to other suppliers of electricity, subject to procedures to be determined by the Board.

18) The Company agrees that it will not promote its BGS as a competitive alternative.

GENERATION-RELATED ASSET TRANSFER FROM PSE&G TO AN AFFILIATED ENTITY

19) Pursuant to the provision of Section 7( d) of the Act, the parties will not object to the Board approving the transfer of the Company's electric generation-related assets and their operation, and all associated rights and liabilities into a separate

• corporate entity or entities (Genco) to be owned by Public Service Enterprise Group Incorporated and not by Public Service Electric and Gas Company. The specific generation facilities and assets which shall be transferred are identified on Attachment 3 (the "Generation Facilities"). Public Service represents that these facilities and assets constitute all of its specific assets related to electric generation.

20) The parties agree that the final and fixed transfer value pursuant to Sections 7(d) and 13(e) of the Act, for the Generation Facilities is $2.368 billion (Attachment 4),

which is the fair market .value of the assets transferred considering all revenues derived from the BGS contract described in paragraph 21 hereof. In addition, Public Service will transfer at book value at the time of transfer other generating-related assets including materials, supplies, and fuel. Such transfer prices will and

• are intended to ensure ~at Public Service receives full and faii recompense for the Generation Facilities and related assets and that Public Service will not retain any liabilities associated with* the transferred Generation Facilities and assures that*

customers' responsibility for stranded costs is established at the lowest reasonable level. No land held for future use (Account 105) will be transferred to Genco. All generation-related expenses will be borne by Genco. The Company shall have auditable accounting protocols in place no later than the effective date of the transfer to assure that_ all expenses and capital expenditures related to generation

• will be borne by Genco.

21) The BGS contract between Public Service and Genco will contain the following prov1s1ons:

a) To ensure the reliability of service to BGS and to remove the risk of price volatility to the regulated Company during the transition to a competitive market and to further ensure that Public Service can meet its contractual obligations to provide power under certain Off-Tariff Rate Agreements (listed in Attachment 5), the transfer to the Genco shall be accompanied by the Genco and Public Service's entering into a BGS contract whereby the Genco would provide full requirements service for energy, capacity, losses and ancillary services needed by the Company for BGS and for Off-Tariff

. Rate Agreements for the period that the Company will be providing BGS under this Stipulation; b) In exchange for ensuring the reliability of supply for Public Service's BGS, for removing the risk of price volatility from the regulated Company in providing such service and to further ensure that Public Service can meet its contractual obligations in its Off-Tariff Rate Agreements, the BGS contract shall provide that the consideration paid by Public Service for such full requirements service shall be (i) an amount computed on a monthly basis equal to the full amount charged for BGS to Public Service's retail electric customers as set forth in paragraph 15 (less any sales and use tax and transmission); (ii) an amount computed on a monthly basis equal to Public Service's retail delivery to Off-Tariff Rate Agreement customers, multiplied by the comparable BGS rate for such customers (less sales and use tax and transmission); and (iii) an additional charge for price stability services provided by the combustion turbine assets of Genco, payable based on the installed capacity of those assets. The additional charge, set forth in (iii) above, will be an amount computed on a monthly basis equal to the full actual amount collected pursuant to paragraph 13 excluding the 2 mill per kWh retail adder. Pursuant to Section 9(b)(3) of the Act, no net revenue

• from ~s contract may be used as a reduction of the MTC or distribution rates.

c) To further ensure the reliability of supply for Public Service's BGS and to remove the risk of price volatility from Public Service, the BGS contract shall also provide that Public Service shall transfer to the Genco the authority to act as its agent for the purpose of scheduling, electing and/or using all rights, including Fixed Transmission Rights, associated with transmission delivery of full requirements service for Public Service's BGS

• and Off-Tariff Rate Agreement customers. Genco will be responsible for costs related to BGS scheduling activities to the same degree it would be responsible for those costs for other load serving entities.

d) The BGS contract shall be filed with the Board. The parties reserve the right to comment to the Board on terms and conditions which are reflected in the BGS contract but which are not set forth herein.

22) To further ensure the reliability of the BGS after transfer of the Generation Facilities, Public Service shall continue to supply, on an as needed basis, dedicated intrastate natural gas transportation services for the Genco's own gas supplies from Public Service's city gate to the transferred generating facilities in accordance with the Stipulation approved in Docket No. ER94070293, OAL Docket No. PUC

• 7328-94 on May 5, 1995. Such dedicated intrastate natural gas transportation services shall continue to be supplied by Public Service to the Genco for the term of the BGS contract.

23) To ensure that the goals of reliable service and sustained rate reductions are

• achieved, the parties agree that the transferred Generation Facilities may only be sold or otherwise transferred by the Genco to any other party during the Transition Period if the other party agrees to take the Generation Facilities subject to entering into a comparable BGS* contract with the same consideration including the right to recover the MTC allocated to such Generation Facilities. If a sale of some or any of the transferred Generating Facilities by Genco occurs within the Transition Period, any net after tax gains from such sale will be shared equally between shareholders and customers in a manner to be determined by the Board.

24) The Company requests, and the undersigned parties do not object that the Board find that qualifying the Generation Facilities being transferred, either separately or jointly, in accordance with Section 32(c) of the Public Utility Holding Company Act of 1935 as Exempt Wholesale Generators (EWG) will benefit consumers, is in the public interest, will not provide any unfair competitive advantage by virtue of the Genco's affiliation or association with the Company, and does not violate State law. As an EWG the Genco will not offer retail electric service.

25) The Company requests and the undersigned parties do not object to the Board finding that in accordance with Section 32(k) of the Public Utility Holding Company Act of 1935, the Board has sufficient regulatory authority, resources and access to books and records of Public Service Electric and Gas Company and any relevant associate, affiliate or subsidiary company, to ensure that the BGS contract will (a) benefit consumers; (b) not violate any State Law; (c) not provide the Genco any unfair competitive advantage by virtue of its a.ffiliation or association with the Company; and ( d) is in the public interest.

26) Public Service shall submit, within 60 days of the date of issuance of the Board's written Order approving this Stipulation, a tentative schedule for the receipt of authorization for the transfer from other agencies for the Generation Facilities described in Attachment 3. Within 60 days following approval, Public Service

.shall a,lso file with the Board copies of any documents evidencing such transfer and assumption of liabilities in connection therewith. Upon the receipt of approval from other agencies, Public Service will provide a filing, which reflects the terms and the approvals received and accounting implemented.

27) The parties agree that in order to ensure that Public Service does not retain any risks or liabilities associated with the electric generating business after the

• Generating Facilities have been transferred, the Board should order that all

contracts (except for the NUG contracts) associated with the electric generating business, including, but not limited to, wholesale electric purchase and sales agreements, fuel contracts, real and personal property interests, and other-_

contractual rights and liabilities, be transferred from Public Service to Genco simultaneous with the transfer of all generating assets, and to substitute the Genco for Public Service as the party(s) to any such_ contracts.

28) The parties recognize that various federal and state regulatory approvals, as well as third-party consents, will be necessary to complete the transfer of assets, rig~ts and obligations contemplated by this Stipulation. The parties anticipate that such approvals and consents will result in a delay between the date that the Board issues an Order approying this Stipulation and the date that the Generation Facilities are actually transferred. To ensure that the intent of the parties is kept intact during this period of transfer and that Public Service is not unduly penalized while diligently complying with this Stipulation and supplying BGS at rates approved by the Board, the parties agree that in order to effectuate the purposes of this Act under Section 9(b)(3), a~y requirement under Section 7 of the Act which would require the payment of any percentage of net revenues for the sharing of common assets and personnel is inapplicable.

• 29)

Generating capacity transferred to Genco will be maintained as a capacity resource within the PJM system for the Transition Period. During that period, Genco will be permitted to sell said. capacity outside of the PJM system for periods of les~

than one year after it makes good faith efforts to sell the transferred capacity into the PJM system at market rates.

30) The parties other than. Enron agree that in addition to any other Affiliate Standard of Conduct that might apply to Public Service, the following shall apply until the expiration of the MTC as provided herein or until appropriate and applicable safeguards or Code of Conduct are adopted by the FERC, whichever occurs first, to transactions by Public Service in its role as supplier of BGS or by any related business segment of Public Service or related business segment of Public Service's holding company selling electric power at retail in New Jersey (PSEG Supplier),

with PSEG's Genco.

"Neither Public Service nor PSEG Supplier shall receive from Genco an unreasonable preference over a non-affiliated retail electric supplier (RES) that is not comparable to that afforded a non-affiliated RES in the purchase, sale, use or conveyance of goods and services. This provision shall not apply to the BGS Wholesale Supply Agreement entered into between Genco and Public Service and approved by the Board."

Relative to other electric power generators, Genco will receive no unreasonable benefit or unreasonable preference from its relationship with PSE&G.

30A) .Enron contends that the Affiliate Standard of Conduct that should apply is as follows:

"GENCo shall not offer power or other services to any of ~ts affiliates which* are not made generally available to non-affiliated companies, nor shall it offer such power or other services to affiliates at prices more favorable than those generally available in the competitive marketplace and/or to those offered to non-affiliated companies. This provision shall not apply to the BGS Wholesale Supply Agreement entered into between Genco and Public Service and approved by the Board."

Relative to other electric power generators, Genco will receive no unreasonable benefit or unreasonable preference from its relationship with PSE&G.

31) The Company requests and the other parties do not object that the Board should further find that the transfer of Generation Facilities and related rights and liabilities contemplated by this _Stipulation is in the public interest and will not jeopardize the reliability of the electric power system. The parties also agree that such transfer will not adversely impact the ability of Public Service to meet its obligations to its employees with respect to pension benefits, as contemplated pursuant to N.J.S.A. 48:3-7.

32) The Company requests and the other parties do not object that the Board further should find that the requirements under N.J.A.C. 14:1-5.6 or any other Board Order or regulation in conjunction with Public Service's compliance with this

Stipulation are waived because of the extensive nature of the record regarding valuation of the assets being transferred and that no further authorizations by the Board are required to effe~tuate this Stipulation.

NUCLEAR DECOMMISSIONING TRUST FUNDS

33) Upon the transfer of the nuclear generation assets, neither Public Service Electric and Gas Company nor its retail customers shall be responsible to decommission its previously owned nuclear units, subject to the Nuclear Regulatory Commission (NRC) approval. That responsibility will pass to the Genco with the transfer of the nuclear generation and associated assets described in Attachment 3 and the Nuclear Decommissioning Trust Funds.

OTHER TARIFF CHANGES

34) On February 1, 1999, the Company filed its proposed Third-Party Supplier Master Service Agreement. At that time, the Company also filed associated electric tariff modifications annexed hereto as Attachment 6, which also reflected the recognition of a capacity market for generation. This Attachment was developed prior to the enactment of the Act and reflects a net back approach for capacity and energy. The parties agree that the proposed tariff modifications be approved subject to: (I) conformance with the balance of this Stipulation; (2) conformance

with the Act; (3) changes resulting from the resolution of restructuring issues; and, (4) changes as a result of the Third-Party Supplier Master Service Agreement resolution. These changes will be included in a completely new tariff which will be filed with the Board after approval of this Stipulation and resolution of other restructuring issues.

MARKET POWER/MONITORING

35) The parties agree with Staffs recommendation that the Board work cooperatively with the PJM-ISO to monitor actual market behavior in connection with the PJM-ISO's FERC ordered market monitoring plan (Exhibit S-8, Audit of PSE&G Restructuring Filing, p. 7)

BILLING AND METERING PROCEEDING

36) The parties agree to work cooperatively to conclude the billing and. metering proceeding in an* expedited fashion, which proceeding the parties request that the Board conclude by May 1, 2000.

Mar-15-99 12:59pm From-NRDC NEW YORK OFFICE 2122436043 T-Zl3 P.02/0Z ~-ZIE CONCLUSION

37) The undersigned agree that this Stipulation contains mutually balancing and inteniepc:Ddcnt provisions and is intended to be accepted and approved in its entirety and the parties agree to be boum:l by its tcllllS. In the event any particular aspect of this Stipulation is not accepted and approved by the Board, this Stipulation shall be null and void and the parties shall be placed in the same --*

position that they were in immediately prior to the execution of this Stipulation.

The parties agree that nothing in this agreement shall prevent the parties from

• arguing a different policy or position before the Board in any other proceeding including issues related to competitive and Code of Con.duct matters.

Public Service Electric and Gas Company International Brotherhood of Electrial Worken Local 94 By_~O-WcfA-Charles D. Wolfe. President Enron Natural Resource Defense Council TCTl=!L.. P.01

New Jersey Transit Corporation New Jersey Commercial Users es E. McGuire, Esq.

d, Smith, Shaw & McClay, LLP Independent Energy Producers of NJ Tosco/Bayway By /.)d!L 3 Ii(, /95 William Harla, Esq.

By '1,iuJ.. sU / t, {'1 /A-Michael J. Mehr:Esq.

/fo /4.v I fff DeCotiis, Fitzpatrick & Gluck Waters, McPherson, McNeill

ATIACHMENT 1 SCHDULE OF ESTIMATED SECURITIZATION PAYMENTS 15 Years 6.5% Interest (thousand of $)

Investment Recovery 2.475,000 Issuance cost 25,000 Use of funds cost 100,000 Total Principal 2.600,000 Pa~ment Interest State tax Fed tax Year including SUT PrinciQal 6.50% 9% 35% SUT 2000 408,429 131,352 169,000 18,718 66.241 23.119 2001 408,429 136,402 160.462 19,486 68,960 23, 119 2002 408.429 141,646 151,596 20,284 71,784 23,119 2003 408.429 147,092 142,389 21, 113 74,716 - 23,119 2004 408,429 152,748 132,828 21,973 77,762 23, 119 2005 408.°429 158.620 122.899 22,867 80,924 23, 119 2006 408,429 164,719 112,589 23,795 84,208 23.119 2007 408.429. 171.052 101,882 24,759 87,618 23.119 2008 408,429 177,629 90,764 25,759 91, 159 23, 119 2009 408.429 184,458 79.218 26,798 94,836 23, 119 2010 408,429 191,550 67,228 27,877 98,655 23, 119 2011 408,429 198,914 54,778 28,998 102,621 23, 119 2012 408.429 206.562 41.848 30,162 106,739 23, 119 2013 408,429 214.504 28,422 31,370 111,015 23,119 2014 408,429 222.751 14,479 32.625 115.456 23.119 2.600~000 1,470,382 376,585 1,332,692 346,780 SECURITIZA TION SAVINGS Revenue Reguirement PV Of Rate Year incl'g SUT Pa~ment Savings Savings 2000 546,161 408.429 137,732 127,036 2001 535,373 408.429 126,944 107,992 2002 524,694 408.429 116,264 91,226 2003 517.230 408.429 108,801 78,740 404,994 123.421 3.0%

Level'd Amt- Rev base 4 yrs. $4.082

~

ATTACHMENT 2 PAGE I OF40 PUBLIC SERVICE ELECTRIC AND GAS COMPANY RATE DESIGN/RATE REDUCTION SPECIFICS Unbundled rates will be developed for each rate schedule showing the following components:

Service Charge:* No change from service charges, including sales tax, m effect on January 1, 1999.

Distribution Charge: Based on the unbundling analysis provided in Exhibit PS-55 of the rate unbundling proceeding. The 1995 cost of service study was rerun to remove those components of the proposed Societal Benefits Charge, including gross receipts and franchise tax, from the Distribution Delivery component. Unbundled cost components of Distribution Access, Distribution Delivery and Customer Services are then summed by rate schedule. To this subtotal, $80.46 million related to OPEB was added and $20 million related to a stipulated reduction in the distribution cost of capital to 9 .5% was subtracted. The net of these two changes was allocated to the rate schedules based on the sum of Distribution Delivery and Distribution Access. Revenue requirements recovered

• through the Customer Service Charges were then removed from the balance of the distribution unbundled costs: This balance was then increased for the effects of the Corporate Business Tax related to distribution through application of the PSE&G "A" factor from the Energy Tax Reform proceedings. TEFA taxes in effect for 1999 were then added to the distribution unbundled rates. The rate de~ign provided in subsequent pages will be modified in each year to reflect the year's TEFA tax rates for subsequent years when determined by the Board. Final rates include the appropriate sales tax.

Transmission Charge: The PJM OATi PSE&G rate for network integration transmission service charge (including Schedule l charges) was used as the basis for the retail Transmission Charge.

For rate schedules GLP, LPL, and HTS the monthly transmission charge is equal to the transmission rate divided by twelve times the customer's individual transmission obligation (in kilowatts), adjusted for losses and NJ Sales and UseTax.

For residential rates and the balance of the rate schedules, the monthly transmission charge was converted to a per kWh charge. This is equal to the transmission rate, times the rate class's 1999 unrestricted coincident peak divided by 1999 kWh sales, adjusted for losses and for NJ Sales and Use Tax.

Capacity Charge: For rate schedules GLP, LPL and HTS, this charge is the annual generation capacity values from the stranded cost proceeding, divided by twelve, times

AITACHMENT 2 PAGE20F40 the customer's PJM capacity obligation adjusted for voltage level losses and sales tax.

For the balance of the rate schedules, the capacity charge will be included in the kWh charge for Basic Generation Service. It will be determined by utilizing the identical generation capacity value used above times the rate class's 1999 unrestricted coincident peak divided by 1999 kWh sales adjusted for losses and for NJ Sales and Use Tax.

Basic Generation Sezyice (BGS) Charge: For rate schedules GLP, LPL and HTS. this charge, combined with the unbundled capacity charge and the transmission charge described above, comprise what is referred to as the "shopping credit" in the Act and in the body of the Stipulation. For the balance of the rate schedules, this BGS charge will include the capacity charge described above.

Securitization Transition (SIC) Charge: An equal per kWh charge for all kWh, adjusted at least annually, including all applicable State and Federal taxes.

Societal Benefits Charge (SBC): A kWh charge as described in the body of the Stipulation. Details of the charge are set forth in pages 8 to 9 of this attachment.

DSM lost revenues are presently calculated as specified in the Company's DSM Resource Plans. This starts with total revenues by rate schedule, by time period, exclusive of sales tax. From this amount, TEFA taxes and variable production expenses are subtracted. The remainder is divided by that month's sales, by rate schedule time period, to derive that month's fixed costs. This fixed cost per kWh is then multiplied times the lost kWb by rate schedule time period for that month.

Effective August 1, 1999 lost revenues will be calculated by rate schedule time period to include only revenues from Distribution Charges and Transmission Charges, exclusive of Sales and.TEFA taxes. -

Non-Utility Generation Transition Charge CNTC): A kWh charge as described in the body of the Stipulation. Details of the charge are set forth in page I 0 of this attachment.

Market Transition (MTC)Cbarge: These kW and kWh charges will be developed for each rate schedule for each year as the residual in the kW and kWh charges, starting with the rates in effect in each year without the rate reductions described below, less all of the charges described above. A net MIC will appear on the customer's bills as the sum of the unbundled MTC charges, the NTC charge, less the Restructuring Reduction.

Restructuring Reduction: This will appear on a customer's bill as a line item to meet the legislative requirement to show the effects of the legislation on a customer's bill. It will be calculated as a fixed percentage of the subtotal of the above charges, varying by rate class by year. For those customers who are purchasing their energy supply from a third

ATTACHMENT2 PAGE3 OF40 party supplier, a subtotal will be calculated assuming the customer is taking basic

.generation service for the purpose of calculating the discount.

Other Rate Scbedule Cban.ies: Rate Schedule EHEP will be modified, similar to the changes proposed in the unbundling proceeding, to allow the existing customer contract to appropriately reference the restructured HTS tariff. Rate Schedule SL will be split into Rate Schedules BPL and PSAL as proposed by the Company in its July 1997 filing and which was unopposed by any party.

Tariff Format: Pages 4 of 40 and 5 of 40 show sample Commercial and Industrial and Residential unbundled tariff formats.

Bill Fonnat: Page 6 of 40 shows a sample bill format for a Commercial and Industrial rate schedule. Residential rate schedule bills will be*developed in a similar format. Page 7 of 40 shows the formulas used in the development of unbundled components after discount in the sample bill format.

Detailed Rate Design Components: Pages 11-15 of 40 show the 1999 Unbundled Rates Detail, including the rates which will appear on the rate schedule tariff sheets for August I, 1999. These rates include the TEFA tax rates for 1999. Also shown are the shopping credit by block and time period and the overall average shopping credit by rate schedule.

Pages 16-40 of 40 provide the 2000-2003 Unbundled Rates Detail. The years 2000, 2001, and 2002a include 1999 rates and 1999 TEFA tax rates. The years 2002b and 2003

( 10 percent rate reduction period) reflect 1998 rates and 1998 TEFA rates. All these years will be modified to reflect the TEFA tax rates for subsequent years when determined by the Board.

ATTACHMENT 2 PAGE4 OF40 SAMPLE TARIFF FORMAT Rate Schedule Comm. &Ind.

Service Charge : $SCI In each month Capacity Obligation:

Basic Generation Service - Generation $A per KW of capacity Capacity obligation per month Transmission Capacity $B per KW of trans. capacity obligation per month Qo-f~ak Intermediate Q((-P~ak Kilowatt Charge-Summer:

Per kilowatt of monthly maximum demand Market Transition Charge $C $D SE Distribution Charge SF SG SH*

Total $1 $] SK Kilowatt Charge-Winter:

Per kilowatt of monthly maximum demand Market Transition Charge $L $M $N Distribution Charge $0 SP $Q Total $R $S $T Kilowatthour Charge:

Per kilowanhour Basic Generation Service SU $V $W Market Transition Charge sx SY SZ Securitization Transition Charge SAA $AB SAC Distribution Charge SAD SAE $AF Adjusnnent Charges:

Societal Benefits Charge $SBC $SBC $SBC Non-Utility Generation Transition $NTC $NTC $NTC Charge Total SAG $AH $AI Actual Tariff sheets will show rates both with and without Sales and Use Tax.

AITACHMENT 2 PAGE50F40 SAMrLEIAR.IFFFORM.AT Rate Schedule Residential Service Charge: $SC2 In each Month Fjrst 600 In excess of 600 In excess of 600

• kilowatthoun kilowatthours used kilowatthours used in used in each in each of the

• each of the months of m.an.th months of Jun.- Oct.-May.

~

Kilowatthour Charges:

per kilowatthour Basic Generation Service $BA SBB $BC Market Transition Charge $BD SBE $BF Securitization Transition Charge $BG $BH $BI Transmission Charge $BJ SBK $BL Distribution Charge $BM $BN $BO Adjustment Charges:

Societal Benefits Charge $SBC $SBC $SBC Non-Utility Generation Transition $NTC $NTC $NTC Charge Total $BP SBQ SBR Actual Tariff sheets will show aJl rates both with and without Sales and Use Tax.

ATTACHMENT2

• SAMPLE BILL FORMAT Rate Schedule Comm. & Ind.

PAGE60F40 Bate CQ!JlgQnent ~ ~ .s  !.!abunc!lec! CQ!JlgQnent~ s After Discount Service Charge xxxx $SC1 xxxx Customer xx xx Capacity Obligation-Generation xxxx *$A xxxx Basic Generation Service

• (BGS)

• xx xx*

Transmission xxxx $B xxxx Market Transition Charge (MTC) xxxx Securitization Transition Charge (STC) xxxx KW On-Peak xxxx $1 xxxx KW Inter xxxx $J xxxx KW Off-Peak xxxx. $K xxxx Transmission

• xx xx Distribution xxxx KWhr On-Peak xxxx $AG xxxx KWhr Inter xxxx $AH xxxx KWhr Off-Peak xxxx $Al xxxx SBC xxxx Other charges (e.g. Area Devel. Svc.) xxxx $XXX xxxx Restructuring Rate Reduction ~ (x.x~)

Subtotal

$ yy.yy Total of Charges= $yy.yy If you are supplied by a Third Party Supplier, you do not have to pay the items asterisked (*)

above right (x.xx)

TPS Billing

~

Pay this amount $zz.zz

• '"*This area varies depending on billing options and customer choice: customer stays with PSE&G, PSE&G bills for TPS. TPS bill separately.

ATTACHMENT 2 PAGE 7 OF40 SAMfLE BILL FORMAT Rate Schedule Comm. & Ind.

Expanded Right Side

.Unbundled Components .i After Discount Customer Revenue resulting from $SC1 Basic Generation Service Revenue resulting from $A+$U+$V+$W (BGS)

• Market Transition Charge Revenue resulting from (MTC) $C+$0+$E+$X+$Y+$Z+$NTCless Restructuring Rate Discount Securitization Transition Revenue resulting from $AA+$AB+$AC Charge (STC)

Transmission

• Revenue resulting from SB Distribution Revenue resulting from

$F+$G+$H+$AD+$AE+$AF SBC Revenue resulting from $SBC Total_ of Charges =

$yy.yy

ATTACHMENT 2 PUBLIC SERVICE ELECTRIC AND GAS COMPANY PAGE 8 OF40 B.P.U.N.J.No.13 ELECTRIC Original Sheet No.

SOCIETAL BENEFITS CHAR<a.E Cost of Recovery Average Cost oer kilowattbour tor: (cents)

SJ2Cial Programs ....................................................................................................... 0.05432 Nuclear Decommjssjoning Funding Reguirements ......................................................... . 0.07739 O.emand Side Management Programs ........................................................................... .. 0.43402 M.anu~d Gas Plant Remediation ............................................................................ .. 0.00508 Consumer Education ..................................... :....... .......................................................... 0.00000 Universal Service Fund ............................................................................. 0.00000 Sub-total Cost per kilowatthour. .. 0.57081 Amount per kilowatthour of cost recovery after ap~tion of losses*

Se_c.QQ.da.ry_S..ervice..__ _ ___,1.,.Los..s Factor = 9~%) .......................... ;...... . 0.6298 LPL Primary Closs Factor = 4...SSS..O o/o) **..****............*...........*. 0.6006 l::!IS....s.ub.transmission Closs Fader= 3~.fil  %) ................................. . 0.5919 HTS High Voltage (Loss Factor= ~ 0/0) ................................. . 0.5778 Charges including New Jersey Sales and Use Tax (SUT)

Seco.odar:y...SJ:!rvice~***** .. ****************** .............................................................................. 0.6676 LPL_~1LmaJY~-~ ...................................................................... ,......... '. ..................... . 0.6366 HTS ~Sub.tl"Snsr:ms.si.on.. ....................................................................................................... 0.6274 HTS_!:i.igb_~oJ.tage.~ ....................................................................................................... 0.6125 Date of Issue: Effective:

Issued bY---,,-------------.,,,.~----

80 Park Plaza. Newark. New Jersey 07101 Filed pursuant to Order of Board of Public Utilities, dated in Docket No.

ATTACHMENT 2 PAGE90F40 PUBLIC SERVICE ELECTRIC AND GAS COMPANY B.P.U.N.J.No.13 ELECTRIC Original Sheet No.

SOCIETAL BENEFITS CHAB._G__E (Continued)

S~tal Benefits Charge This mechanism js designed to insure recovery of costs associated with adiwleutta.t are.re~uii:.ed to be ac:compljshed to achjeve specific public policy determinations mandated by..,.G9yemrne.IJL...hctual costs incurred b_y~ Company for each of tbese cost components will be subject to deferred_a_~_u_a.ti.119...Jo~ei:est at the se.Y.e.n-year debt rate for a single A rated utility will be accrued on any under- or over-rec~e_r:_e~..,.balances S~atemgram&

T.his factor shall recover costs associated with exis~al programs This includes but js not limited to u_ru::ol!ectible customers accounts.

N_u~lear Decommissioning Funding Requirem~

This factor shall recover costs associated with nuclear decommissioning funding reguiremeQtU1ecessary to_meet F.filtm~te. reguirements to decommission the nuclear units O.em.and..Sld.e_llll.an.agement Program&

T..bts....fam>L.J.s_a recovery mechanjsm which will operate in accordance*with tbe O_mnao_d_S.!d.e...M.anageme_l'.1.t(DSM) conservation incentive regulations The factor shall recover Core and Performance PrQg1:;:1111_c_o_s.ts and

~e.!forrn.an.ce Pro9ram Payme..ntLoo..a..c.urrent basis and shall also recov~_ay_menttlo.LLa.rg~Scale Conservation Investments.

Cor_e..il.mtE..~r:fQrrnance Program C.Q..s.ts of BPU-approved DSM orograms consist of but a~Ui!!lited to~re.bates.

grants*.Jli!Y.ments to third parties for program imp!e_mentation -direct marketing costs DSM ha.rd..vtare, admimsm1tion measurement and e.Yaluation of DSM programs customer commu!!icatiQn and_e_d_ucation, market

- researcil....Co.sts_as_~aJed with de.v.e!Qp.iD9~1mmeme~.mt..ta_iniog..reguJatQ!:Y-filW!:IDl.aL@_sts. of _research and. oev.elcmrnent.a.ctivitin.a.s.~ciate~twit!l...D-5M...c;ippJJ~-b.l§lJ..QS1.Re.v_e11ue.S-M.d_QS_M.Jldyer:ti_s!D9 costs.

PerfolJ'T'!aoce_P.rogra~~Jl(e_ba~.e.d..upon _a_stand.ard.PIJC.e..Q.ffer for_gen.e.raJ>>plicati.oos_or for particular DSM measures~wru.m..es.tab!istl.es a_per.JJ..ailprrce.tor_eriergy_and_caRacrty_sa_y!ngs_whi,eh_e,ub~~-Service wilLpay to th1rd_par_tres .foLD_SM.pIQJeJ;ts._wh1ch_rn_e_et_v1abil1ty. teclJr.iologicaUneasure.!!leDtandJler:ificatio!J criteria.

Lar9e-Scale _ConseIY.a.tioDJn.vestrnents..are_oay_rnents for_measured_and_vei:i.fied_e11ergy_savio9s .trom contracts executed Jll response_to_E.S.E&G's RequestfotP.roposals underJhe_Stipul_ation of_Settlem.e.l'.lt.i.IJ_[)_ocket No.

8010~6878 .dated _J_uly 1 1988.

Manufactured_ GasJ~.lant.Remediation This factQLsball_ [eco~.Qsts..as_socr_ate.d .wi1h _add resslflg a(l_d _resolving. claims by_and..oLreguir.ements of gove_rnrner:itaL entrti.es_amtprrvate part1es_related to act1vtt1es necessar:y_tQ.perfo1:rn il]Y~stigaticms__and the remed1at1on of env1ronmeDJa.Lrued1a.

Consumer Education This factor shall recover_restructunng costs such as educating residential .. small business .. and special needs consumers about the 1mph.cat1ons for consumers of the restructuring of trre_etectnc power jndustries. The consumer education. program _slJalUnclude. but need not be lrm1ted to. the dissemination. of informatiorJJO enable consumei:s to make informed chorces_among electricity services and suppliers. and the communication.Jo.consumers of consumer protectio1LJ)r.ovis1oris .

Universal Service_Fund This factor shall recover costs assoc1ated _w1th new or expanded_socia!_programs.

Date of Issue: Effective:

Issued by~~~~~~~~~~~~~~~~~~

80 Park Plaza. Newark. New Jersey 07101 Filed pursuant to Order of Board of Public Utilities. dated in Docket No.

ATTACHMENT 2 PUBLIC SERVICE ELECTRIC AND GAS COMPANY PAGE 10 OF 40 B.P.U.N.J.No.13 ELECTRIC Original Sheet No.

NON-lJTIUTY GENERATION TRANSmON CHARGE Cost of Re_covery (cents)

T.._o""'ta....._IC""""'os...,t..,.o..,e....r ....

ki...lowattb......,

o...

ur.....,..,..._....._,............................................................................. 0.43540 Amount per kilowatthour of cost recovery after ai:!,.Dlication of losses*

S.econdary Service (Loss Factor= ~Oht) ..........................*....... 0.4804 LPL Primary (Loss Factor = 4..9590 O/o) .*.**.**.*..*..**. ***...*.-*. **** .. 0.4581 HTS Subtransmjssjon CLpss Factor = ~o/o) ................................. . 0.4515 HTS High Voltage <Loss Eactpr = ~%) ................................. . 0.4407 Charges including New Jersey Sales and Use Tax (SUT)

Secondary Service ....................................................................................................... 0.5092 LPL Primary ....................................................................................................... 0.4856 HTS Subtransmission ....................................................................................................... 0.4786 HTS High Voltage ....................................................................................................... 0.4671 No11.:.Utility_Gem~_ration Tra.ns.Hion.Cruu:ge Th1.s_rri_1:~cbanrSl!l...!S_d~_S!Q!Je..dJQJQ.sure recove.ry_ot_costs..as.s.0~1ate.d. with activities that are reguired to .b.e acc.QmpJ1.sned.to..Pcl:l!.e~.cific.pu~~etermma_trt1.ns...mandate~GJM!lDI!lfU'l.L.Act.U;i.U:os.ts.i11gJ.rre_d byJIJ.e~Qrnp_any_fo.r each of tt1ese...cofilQ!!!po11ents..wi!Ltle_JiUb.JeCUQ..ctef.erre..d_a_ccounting. 1ruerest at the seveo.:Ye.i!Ldeb.Uate tor a smgl.e_A rated.J.ttijrty_wlll be_acc1JJed...Q..fl..a~.e~~c~b.alaoc~.

This factoLS.t"!allre_coJ.'.er_ab~_market.costs associated w1th_non.:regulate.d..,ge11er:.ati_o_n..co.it!L..whi~ are related .10_ e.l.C!Str.ngj as_o.i.J.U!)'.....LJ 997). long-term contractual. poweLmJICb;is.e.J1.rraagei:rumts...appr:.o.ved_t>_y_the Board and/or_estabhstled.Jm.a.eueQu1reme1Jts of the Public Util1~.egula_tor¥.f_p!Lcies..Acto.LI.m.

Date of Issue: Effective:

Issued by _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __

80 Park Plaza. Newark, New Jersey 07101 Filed pursuant to .Order of Board of Public Utilities. dated rn Docket No.

1999 Unbundled Rates Detall blll del. Subtolal 1999 Prellmn. Shopping ShpCr MTC Adj Rate SBCINTC

• 111 Trans Dist BGS STc Subtot11I MTC Cr.edit Revenue ObllgAdj, MlC 121 (31 141 151 161 171 (&=sum 3-7)

RS (9"'2*81 (10"4+6) (11*1"10) (12) (13)

Service Charge 20,231 858 2 41 0 00 0 00 2 41 0.00 0.00 2 41 0.00 0.00 Energy Charges 0 0-600 7,966.126 11 6394 I 1768 0 6679 3 2744 4 9927 0 0000 10 1118 1.5276 5 6606 Over600 Sum 1,446,728 13 1022 I 1768 0 6679 450,931 36795 5 8875 0 0000 11.4117 16905 6.5554 Over 600Win 1,134,116 11 0607 1.1768 06679 94,839 31008 4 3484 DODOO 9.2939 1.7668 Totals 10,546,970 5.0163 58,891 5.71 602,661 RHS Service Charge *202 344 2 41 0.00 0 00 2 41 0.00 0.00 2.41 0.00 0.00 Energy Charges 0 0-600 120.617 11 6394 1.1768 0 3460 4 0895 3 9530 00000 95653 2 0741 4.2990 Over600 Sum 18,656 13 1022 1 1768 0 3460 5, 185 4 6089 5 1495 00000 11 2812 18210 Over 600 Win 115,381 8 0174 I 1768 54955 1,025 0 3460 2 8285 3 5482 00000 7 8995 0.1179 Common 0 13 1022 I 1768 38942 4,493 0 3460 4 6089 5.1495 00000 11 2812 1.8210 Totals 254,654 54955 0 4.20 10,703 RLM Service Charge 59 630 12 l2 0 00 0 00 12 12 000 0 00 12 12 0 00 0 00 Service Charge over 20,000 121 066 6 79 0 00 0 00 6 79 0 0 00 000 6.79 000 0.00 Service Charge Sp. Prv. fll 0

• Energy Charges Summer On 61.543 17 6369 1 1768 0 5547 3 7675 7 4115 0 0000 12 9105 4.7264 lnler 11.539 16 1126 I 1768 7 9662 4.903 0 5547 3 2418 6 3404 00000 11 3137 4 7989 OH 55.132 6 3140 1 1766 0 5547 6.8951 796 I 2092 3 7262 0 0000 6 6669 (0 3529)

Winier On 81,842 12 0486 I 1768 0 5547 4 2809 2,360 2 6110 4 7211 0 0000 9 0636 2 9850 lnler 16,740 12 2680 I 1768 5 2758 4,318 0 5547 2 4708 4 3946 00000 8 5969 3 6711 OH 87.422 6 3140 I 1768 0 5547 4 9493 829 Totals 1 2092 3 4069 00000 6 3476 (0.0338) 39618 314,218 3,463 5.30 16,669 WH Energy Ch1rge 11,362 10 1713 1.1768 0.0000 5.2921 2 4607 0.0000 8.9296 1.2417 Totals 11,362 24607 280 2.46 280 WHS Service Charge 1 270 2.82 0.00 000 2.82

• 0.00 0.00 2.82 Energy Charge 243 5.4289 0.00 0.00 0000 1.1768 0.0000 1.5340 2.4631 0.0000 5.1739 Totals 243 02550 24631 5 985 2.46 . 5.985

~>

>~

C1 ~

tt1 >

(")

o~

l'rj

=

tt1 STC, preliminary values, adjusted at least annually. ~2 o~

N

blll del. Subtotal 1999 Unbundled Dela II Ral~

Prelhnn. Shopping ShpCr MTC AdJ 1999 Rate SBC/NTC Trans Dist BGS src Subtol;1I r.uc credit Reve1111e ObllgAdJ. r.tlC 111 121 Ill 141 151 161 111 111::1um l*7) 19*2-8) 110*4+6) (tt"t"tO) 1121 *1u1 GLP Service Charge 2,B25 642 4 04 0 00 0 00 4 04 0 00 000 4 04 0 0 0 Service Charge- Night Use I 356 367 OB 0 00 0 00 367 OB 0 00 0 00 367 06 0 0 0 Capacity Obllgallon 25.42B 0 0000 0 0000 0 0000 0 0000 2 9150 0 0000 2 9150 12 9150) 2 9150 74,123

. Tr1nt1mlsslon Obllgallon 21.40B 0 0000 0 0000 1 5961 0 0000 0 0000 0 0000 1 5961 11.59611 I 5961 34,169 Dem1nd Ch1rges 0 0000 0 0000 0 0000 0 0000 00000 00000 00000 0 0000 DODOO 0 Summer 0.1 707 4 BB66 0 0000 0 0000 3 0170 0 0000 0 0000 3 0170 I 8696 00000 0 1.9315 100819) over I 10.737 9 5930 0 0000 0 0000 5 915B 00000 00000 5 9158 3.8772 00000 0 3 7946 10. 1174)

Winter 0-1 1.419 4 BB66 DODOO 0 ODDO 3 0170 00000 00000 3 0170 1 8896 0.0000 0 19315 10.08191 over 1 18.956 8 4568 0 ODDO DODOO 5 2059 D DODD 0.0000 5.2059 3 2529 0.0000 0 3.3468 ID.0939)

Energv Charge1 All Use*x nighl use 8,0DB.OB5 8 2050 I 176B 0 0000 0 3583 3 9525 00000 5 4876 2 7174 3 9525 316,520 2.7174 NighlUse 60,685 7 0751 I 1768 DODOO 0 3583 3 9525 00000 5.4876 1.5875 3.9525 2,399 1.5875 Total1 B.068.770 5.30 427,211 MonlhlV Minimum, MD Speclal Annu1I Minimum Speclal Provisions Standby 2 000 3 B600 0 0000 0 1BOD 2 8900 0 7800 D 0000 3 8500 0 0100 0.9600 2 Area Dev Svc Cr Yrs I *5 357 (2 85001 0 0000 0 0000 (2 85001 00000 0 ODDO 12 85001 00000 0 0000 0 Area Dev Svc Cr Yrs 6&7 Curt Elec Svc Cr Curt Elec Svc Peak Cr Police/Fire-Each Police/Fire-Minimum HS Energv Ch1rge1 Summer 4,684 14 2258 I 1768 0 3788 5 7003 5 3637 00000 12 6196 16062 5 7425 269 Winier 25.648 10 9897 I 1768 0.3788 4.3648 3.8348 00000 9.7552 1 2345 4.2136 1,081 Tot1l1 30,332 4.45 1,350

• • 1999 Unbundled De tall Rat~

blll de!. Sublotal Prellmn. Shopping ShpCr MTC AdJ 1999 Rale SBC/NTC Trans Dist BGS STC Sublotril MTC Credit Reveo11e ObllgAdJ. 1\UC 111 121 131 141 151 161 111 18asum l-71 19=2*111 (10a4+81 (11a1"101 1121 1131 LPL-Secondary Service Charge 77 386 368 64 0 00 0 00 368 64 0 00 0.00 368 64 0 0 0 Capacity Obllgallon 26.556 0 0000 0 0000 0 0000 00000 2 9150 00000 2 9150 (2 9150) 2 9150 77,411 Transmission Obllgallon 22,344 00000 0 0000 I 5961 0 0000 0 0000 0 0000 1 5961 11 5981) 1.5961 35.663 Demand Charges 0 0000 0 0000 0 0000 0 0000 0 0000 00000 0 0000 0.0000 00000 0 Summer On 6.609 6 7556 0 0000 0 0000 4 1045 00000 0 0000 4 1045 4 6511 00000 0 4 2732 03779 Inter 6.312 1 1660 0 0000 00000 0 5336 0 DODD 0 0000 0 5336 06324 00000 0 0 5663 0.0641 Off 8,035 I 1660 0 0000 0 0000 0 5336 0 0000 ODDOD 0 5336 D6324 00000 0 0.5683 *. 00641 Winier On 14.650 7 6108 0 0000 00000 3 5710 0 0000 00000 3 5710 4 0398 OOODO 0 3 7134 0.3284 Inter 11.036 1 1660 0 0000 OOODO 0 5338 00000 00000 0 5338 08324 00000 0 0 5683 0.0841 Off 13.122 1 1660 00000 0 OOOD 0 5336 OOODO 0 DODO 0.5336 06324 0.0000 0 0.5683 0.0841 Energy Charges On 5.315.404 8 2888 1 1768 00000 0 2777 4 6541 00000 6 1088 2 1602 4 8541 247,364 2.1802 lnler 710 757 7 2606 I 1768 0 0000 0 2777 4 0490 0 0000 5 5035 I 7571 4 0490 28,779 I 7571 Off 4.127 510 5 6292 1 1768 0 0000 0 2777 2 4703 0 0000 3 9248 1.7044 2.4703 101.962 1.7044 Totals 10. 153 671 4.114 491,199 Speclal Annual Minimum LPL-Primary Service Charge I I 193 368 64 0 00 000 368 64 0 00 000 368 64 0 0 0 0 000 9 4800 0 0000

• a0000 9 4800 0 0000 00000 9 4800 00000 00000 0 Capacity Obllgallon 9 960 0 0000 0 0000 0 0000 0 0000 2 9150 00000 29150 (2 9150) 2.9150 29,033 Tran1ml111lon Obllgallon 8 400 0 0000 0 0000 I 5961 0 0000 00000 0 0000 1 5961 (1 5961) 1 5981 13,407 Demand Charges 0 0000 00000 0 0000 0 0000 00000 00000 00000 00000 00000 0 Summer On 3 117 8 5648 00000 0 0000 3 1337 0 0000 0 DODD 3 1337 54311 00000 0 4 31199 1.0412 lnler 2 286 1 0494 0 0000 0 0000 0 3761 00000 00000 0 3761 0 6733 0 0000 0 0 5400 0.1333 Off 2.91D I D494 0 0000 D DODO 0 3761 0 0000 00000 0 3781 08733 00000 0 05400 01333 Winier On 5.495 7 4306 0 0000 0 0000 2 7264 0 OODD 00000 2 7284 4 7042 00000 0 3 8104 0.8938 Inter 4.206 I 0494 0 0000 0 0000 0 3761 00000 0 0000 0 3761 06733 0.0000 0 0 5400 0 1333 Off 5.077 I 0494 0 0000 00000 0 3781 0.0000 0.0000 0 3781 0.6733 0.0000 0 0.5400 01333 Energy Charg111 On 2,049,715 7 5452 1 1222 0 0000 0 2661 4 4299 0 0000 5 8182 I 7270 4.4299 90.800 I 7270 Inter 286.960 6 5689 I 1222 00000 0 2681 3 6594 00000 5 2477 13212 3 8594 11,075 I 3212 Off 1.762.754 5 6096 I 1222 00000 0 2861 2 3650 0.0000 3 7533 18563 2.3850 41.889 18583 Total* 4.099.429 4.54 186,004 Speclal Annual Minimum Special Provl1lon11-LPL Slandby-Sec. 29 3 6600 0 0000 0 1800 2 8300 0 8500 00000 3.8800 (0 0000) I 0300 JD Slandby* Prl. 38 2.7300 0 DODO 0 1800 16900 0.870D 0.0000 2.7400 (0.0100) 1.050D 40 70 ,,, >

Area Dev. Svc Cr Yrs 1*5-Sec. 1.158 12 85001 0 0000 00000 (2 85001 00000 00000 (2 85001 0 0000 0 0000 o* >~

Area Dev Svc Cr Yrs 1-5-Pri 300 0 0000 0 0000 00000 0 0000 00000 00000 0 0000 00000 0 0000 0 C') ~

Curt Elec Svc. Cr Curt Elec Svc Peak Cr M>

- (j

!N::Z::

IES Cr 2 Hr. Nlc.-Sec 36 13 29001 00000 0 0000 00000 13 2900) 0 0000 (3 2900) 00000 13 2900) (I 181 IES Cr. 30 Min Nlc.*Sec. 99 (4 53001 0 0000 0 0000 0 0000 (4 5300) 00000 (4 5300) 0 0000 (4 5300) (4481 o~

IES Cr 2 Hr. Nlc.-Prl.

IES Cr. 30Min Nlc.-Pri 0

75 (3 2900)

(4 5300) 00000 00000 00000 0 0000 00000 0 0000 (3

(4 2900) 53001 00000 00000 13 (4

29001 5300) 0 0000 00000 13 2900)

(4 5300) 0 (340)

"TJ M IES Chg 2 Hr. Nie. (906) ~~

IES Chg 30 Min Nie ~

t-.1

• • blll del.

1999 Subtotal Rale SBC/NTC 1999 Unbundled Raio Trans Oelall Olsl BGS STC Sublol11I Prellmn.

MTc Shopping Credit ShpCr MTC Revenue ObllgMJ.

'Adj 1vn:c (11 121 Ill (4) (51 (61 171 (8=eum 3-71 (9*2-11) (10"4+6) 111-1*101 1121 113)

HTS-Subtrans Service Charge 2 180 2.026 07 0 00 0 00 2.026 07 0 00 0 00 2.026.07 0 0 0 C1paclly Obligation 8,004 0 0000 0 0000 00000 0 0000 2 9150 0 0000 2 9150 12 91501 2 9150 23.332 Tran1ml1t1lon Obligation 8.734 0 0000 0 0000 1 5961 0 0000 00000 0 0000 1 5961 (1 5961) 1 5981 10,748 Oem1nd Ch1rges 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 00000 00000 0 Summer On 2.820 10 4834 0 0000 0 0000 1 3031 0 0000 00000 1 3031 9 1803 0 0000 0 4 3823 4 7980 lnler 0 0000 0 0000 00000 0 0000 0 0000 0 0000* 0 0000 00000 00000 0 00000 00000 Oft D DODD 0 0000 0 0000 00000 00000 00000 00000 D DODD 00000 D ODDDD DODOO Winier On 5.429 9 5718 D 0000 D 0000 1 1858 D 0000 DODOO 11858 8 3860 0.0000 D 4 0010 43850 lnler D DODO D 0000 00000 00000 DODOO 0 ODDO 00000 0 0000 00000 0 DODOO 0.0000 Oft 0 0000 0 0000 0 0000 0 0000 00000 00000 D.0000 0.0000 0.0000 0 0.0000 0.0000 Energy Ch1rges On 1.583.322 6 8074 1 1060 0 0000 0 1940 4 3049 00000 5 6049 1 2025 4 3049 68,160 1.2025 lnler 282.658 5 8365 1 1060 0 0000 0 1940 3 7459 00000 5 0459 0 7906 3 7459 10,588 0 7908 Oft 1 615.873 5 0616 1 1060 0 0000 0 1940 2 2779 0 0000 3 5779 I 4837 2 2779 36,808 1.4837 Tolal11 3.481 .853 4.30 149,838 Special Annual Minimum HTS-High Voll*ge Service Charge 0 168 I 823 47 0 00 0 00 1.82347 000 000 1,823 47 0 0 0 C1paclly Obll91tlon 696 0 0000 0 0000 0 0000 0 0000 2 9150 00000 2 9150 (2 91501 2 9150 2,029 Tran1ml11lon Obligation 586 0 0000 0 0000 1 5961 00000 00000 00000 I 5961 (1 59611 1 5961 935 D11m1nd Ch1rg11 0 0000 00000 0 0000 0 0000 0 0000 00000 00000 00000 00000 0 Summer On 324 9 4351 0 0000 0 0000 1 1726 0 0000 00000 1 1728 e.2623 00000 0 3 3337 4.9288 lnler 0 0000 0 0000 0 0000 00000 00000 00000 00000 00000 00000 0 0 0000 00000 011 0 0000 00000 0 0000 0 0000 DODOO 00000 00000 00000 DODOO 0 00000 00000 Winier On 619 8 6146 0 DODD D 0000 I 0686 00000 00000 1.0666 7.5460 00000 0 3 0437 4 5023 lnler 0 0000 *O 0000 0 0000 00000 00000 00000 00000 0.0000 00000 0 *D ODDO DODOO Oft D ODDO 0 0000 0 0000 0 0000 0 0000 0.0000 D.0000 D.DDDD O.DDOD D D DODD D.DDDO Energy Charges On 192.419 6 0555 1 0798 0 ODDO 0 1940 4 2069 00000 5 4805 0.5750 4 2069 8,095 0 5750 lnler 26.167 5 1816 I 0796 00000 0 1940 3 6615 0 DODD 4 9351 0 2465 3 6615 958 0 2465 011 159.868 4 4842 1 0796 00000 D 1940 2 2291 DODOO 3 5027 0 9815 2.2291 3,584 09815 Tol1l11 378,454 4.12 15,581 Specl1I Annual Minimum Specl1I Provl11lon11-HTS Standby- Sublrans 410 1 3900 0 0000 0 1700 0 3200 0 9000 0 0000 1 3900 0 0000 1 0700 439 Standby- High Vollage 208 1 2500 0 0000 0.1500 0 2900 08200 00000 1.2600 IDDIDD) 0.9700 202 841 Area Dev. Svc Cr Yrs 1-5-Sub 70 (1 90b01 D ODDO 00000 11 90001 0 DODO 0 0000 119000) 00000 00000 0 ~>

Area Dev. Svc Cr Yrs 1-5-HV 49 00000 D 0000 00000 00000 00000 DODOO 0 0000 DODOO 00000 0 >::1 Curt Curt Elec Svc Cr Elec. Svc. Peak Cr ~>

~ Ci IES Cr 2 Hr. Nie -Sub 312 319 (3 2900) 14 5300) 0 0000 DODOO 00000 0 0000 0 0000 DODOO (3

(4 2900) 5300) 00000 D 0000 (3 2900)

(4 5300) 0 0000 0 0000 (3 2900) (1.026) ol:o.:J:

IES Cr 30 Min Nlc.-Sub (4 5300) (1,445)

IES Cr 2 Hr. Nie. -HV D (3 2900) 0 DODO 00000 00000 (3 2900) 00006 13 2900) 00000 (3 2900) 0 o~

IES Cr. 30 Min Nie -HV 779 (4 5300) 00000 0 0000 00000 (4 5300) 00000 (4 5300) D 0000 (4 5300) (3.529) ""1 tr1 IES Chg. 2 Hr Nie. (6.000) .i:..

0 z IES Chg 30 Min Nie. ~

t"

• • blll det.

1999 Subtotal Rate SBC/NTC 1999 Unbundled Rate.

Tra111s Detail Dist BGS Prellmn. Shopping ShpCr MTC Adj STC Subtotal MTG 111 m Ill 141 151 l&J 17) fll=sum 3-71 f9=2-ll)

!:redlt Revenue ObllgAdJ.

ft0 ..4*61 1tt 11 t*to) llH.C BPL 1121 (tJJ 306.693 17 3316 1 1768 0 0000 10 7704 2 8324 0 0000 14 7796 2 5520 306,693 2 8324 8.687 2.113 8,687 PSAL 147.752 21 8335 1 1768 0 0000 13 3919 2 8324 00000 17.4011 4 4324 2.8324 147.752 4,185 2.113 4.Ul5

bill del. Subtotal 2000 Unbundled Rat.

Dela II Prellmn. s*hopplng ShpCr MTC Adj 2000 Rate SBC/NTC Trans Dlsl BGS STC Sublolal MTc Credit Reven11e ObllgAdJ. r.nc (11 121 Ill (41 (51 (61 (71 ll"SUm l-7 (9=2-111 (10=4+&1 111=1*101 (121 (131 RS Service Charge 20,447 304 2 41 0 00 0 00 2 41 0 00 0 00 2 41 000 0 00 0 Energy Charges

. 0*600 8.157,618 11 6394 I 1768 0 6624 3 2744 5 1438 1 0315 11 2889 0 3505 5 8062 473,648 Over 600 Sum 1.481.505 13 1022 1 1768 0 6624 3 6795 6 0451 1 0315 12 5953 0 5069 8 7075 99.372 Over600Win 1.161.377 11 0607 1 1768 0 6624 3 1008 4 4949 I 0315 10 4664 0.5943 5 1573 59.898 Totals 10.800,500 5.116 632,916 RHS Service Charge 118 282 2 41 0 00 0 00 2 41 0 00 000 2 41 000 0 00 0 Energy Charges 0*600 73.336 j 1 6394 1 1768 0 3340 4 0895 4 0734 I 0315 10 7052 0 9342 4 4074 3.232 Over 600 Sum 11.343 13 1022 I 1768 0 3340 4 6089 5 2783 I 0315 124295 0.6727 5 6123 637 Over 600 Win 70.153 8 0174 1 1768 0 3340 2 8285 3 6658 t 03t5 9 0364 (I 0190) 3 9996 2.806 Common 0 n 10n 1 1768 0 3340 4 6089 5 2783 1 0315 12 4295 0 6727 5 6123 0 Totals 154 832 4.31 6.875 RLM Service Charge 59 281 12 12 0 00 0 00 12 12 0 00 0 00 12 12 0 00 0 00 0 Service Charge over 20,000 120 359 6 79 0 00 0 00 6 79 0 00 0 00 6 79 0 00 0 00 0 Service Charge Sp. Prv. (ii Energy Charges summer On 60 478 17 6 )69 I 1768, 0 5520 J 7675 7 5734 1 0315 14 1012 3 5357 8 1254 4.914 lnler 11 340 16 1126 1 1768 0 5520 32416 6 4945 1 0315 12 4968 3 6160 7 0485 799 Off 54 178 6 3140 1 1768 0 5520 I 2092 3 8617 t 0315 7 8312 (1 51721 4 4137 2,391 Winier On 80 426 12 0486 1 1768 0 5520 2 6110 4 8636 I 0315 10 2349 1 8137 5 4156 4,358 lnler 16451 12 2680 I 1768 0 5520 2 4708 4 5348 1 0315 . 9 7859 2 5021 5 0888 837 Off 85.909 6 3140 1 1768 0 5520 1 2092 3 5401 1 0315 7.5096 (1 19561 4 0921 3,515 Totals 308.782 5.44 18,812 WH Energy Charge 9.890 10 1713 I 1768 0 0000 5 2921 2 5725 1.0315 10.0729 0.0984 2.5725 254 Totals 9.890 2.57 254 WHS "

Service Charge I 165 2 82 0.00 0 00 2.62 000 0.00 2 82 0 00 0.00 0 000 Energy Charge 218 5 4289 1 1768 0 0000 1 5340

• 2 5749 1 0315 6 3172 (0.8883) 2 5749 5613 Tolal1 218 2.117 5 813 STC, preliminary values, adjusted at least annually.

. 2000 Unbundled Rate.

Detall bllldel. Suhlolal Prellmn. Shopping ShpCr MTC AdJ 2000 Rate SBC/NTC Trans Dist BGS STC Sublol'I MTC Credit ReYe11ue ObllgAdJ. MlC (11 (21 Ill (41 (51 (61 (71 8=sum 3-7 (9"2-81 (10a4+8J (11a1"10J 1121 (13)

GLP Service Charge 2,844 257 4 04 0 00 0 00 4 04 0 00 0 00 4 04 0 0 0 S1rvlc11 Cherge- Night Use t 224 367 OB 0 00 0 00 367 08 000 0.00 367.06 0 0 0 C1p1clty Obllgallon 25.620 0 0000 0 0000 0 0000 0 0000 3 0033 0 0000 3 0033 (3 0033) 3 0033 76.945 Tren1mlsslon Obllgatlon 21.564 0 0000 00000 1 5961 0 0000 0 0000. 0 0000* 1.5961 . (1 59611 I 596t 34,418 Dem1md Charges 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 00000 00000 00000 0 Summer 0-1 716 4 6666 00000 0 0000 3 0170 0 0000 00000 3 0170 1 6696 DODOO 0 1.9817 (00921) over I 10.869 9 5930 0 0000 0 0000 5 9156 0 ODDO DODOO 5 9156 36772 0.0000 0 3.8541 (0.1769)

Winier O*I 1.437 4 8866 00000 0 0000 3 0170 0 0000 0 0000 3 0170 16698 0 0000 0 I 9617 (0.0921) over I 19.195 8 4566 0 0000 00000 5 2059 0 0000 00000 5.2D59 3.2529 00000 0 3.3993 (0.1464)

Energy Chargea All Use-x nighl use 8, 127.093 6 2050 I 1766 0 DOOO 0 3563 3 9652 I 0315 6.5518 1.6532 3 9652 323.661 16532 Night Use 54,305 7 D751 1 1766 0 DODD 0 3563 3 9652 1 0315 6.5516 0.5233 3 9852 2, 184 0.5233 Tot1h1 8, 181,398 5.35 437,408 Monthly Minimum, MO Specl1I Annual Minimum Specl1I Provisions Slandby 2 OOD 3 8600 0 0000 D 18DO 2 8900 0 78DO 0 OOOD 3.8500 00100 09600 2

,l\rea Dev Svc Cr Yrs 1-5 357 (2 85001 0 0000 " 0 0000 (2 8500) 0 0000 0 0000 (2 8500) 0 0000 00000 0 Area Dev Svc Cr Yrs 6&7 Cur1 Elec Svc Cr Cur1 Elec Svc Peak Cr Police/Fire-Each Police/Fire-Minimum HS Energy Ch1rge1 Summer 4.526 14 2258 1 1768 D 3921 5 7DD3 5 3378 1 0315 13 6385 D 5873 5.7299 259 Winier 24,767 1D 9897 11768 D 3921 4 3648 3 7981 1.0315 10.7633 0.2264 41902 1,039 Tot1l1 29.313 4.43 1,298

• • blll del. Subtolal 2000 U11bundled Rat, Detall

• Prellmn. Shopping Shp Cr MTC AdJ 2000 Rate SBC/NTC Trans Dist BGS src Subtotal MTC Credll ~eve11ue Obllg.AdJ. MlC 111 121 Ill 141 151 161 111 8=11um 3-7 19=2-I) 110=4+61 (11*1"10) (121 *cu1 LPL-Secondary Service Charge 78 203 368 64 0 00 0 00 368 64 0 00 0.00 368 64 Ii 0 0 Capacity Obllgallon 26.760 0 0000 0 0000 0 0000 0 0000 3 0033 0 0000 3 0033 (3 00331 3 0033 80,368 Tran9mlulon Obllgallon n.536 00000 0 0000 1 5961 00000 0 0000 0 0000 1 5961 (I 59811 I 5961 35,970 Dem1nd Ch1rges 0 0000 0 0000 0 ODDO 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 Summer On 8.744 8 7558 0 0000 0 0000 4 1045 00000 0 0000 4 1045 4 8511 0.0000 0 43311 0 3200 lnler 8.411 t 1660 0 0000 00000 0 5336 0 0000 0 0000 0 5336 06324 DODOO 0 05780 00564 OH 8. t61 I t680 0 0000 0 0000 0 5336 00000 00000 0 5336 0 6324 00000 0 0 5760 *. 00564 Winier On 14.866 7 8t08 0 0000 00000 3 5710 0 0000 00000 3 5710 4 0398 0 DODO 0 3 7637 0.2761 lnler t1.199 11860 00000 0 0000 0 5336 0 0000 00000 0 5336 06324 DODOO 0 05760 00564 OH 1J,3t6 t 1660 00000 0 0000 0 5336 00000 0.0000 0.5336 ~.6324 0.0000 0 05760 0.0564 Energr Charges On 5.400.39t 8 2888 I 1768 0 0000 0 2777 4 6919 1 0315 7 1779 I 1109 46919 253,381 1.1109 lnler 722. t21 7 2606 1 1768 00000 0 2777 4 0824 I 0315 6 5664 06922 4.0824 29,460 0.6922 OH 4. t93.507 5 6292 t t766 00000 0 2777 2 4924 I 0315 4 9784 06506 2.4924 104,519 D..6508 Tolals t0.3t6,0t9 4.11 503,716 Specl1I Annual Minimum LPL-Prlm1ry Service Ch11g11 11 277 368 64 0 00 0 00 368 64 0 00 0 00 368.64 0 0 0 0 000 9 4800 0 0000 0 0000 9 4800 0 0000 0 0000 9 4800 00000 0 DODO 0 C1p1clty Obllg1tlon 9.972 0 0000 0 ODDO 0 0000 0 0000 3 0033 0 0000 3. 0033 (3 0033) 3 0033 29,949 Tran*mlHlon Obllg1tlon 8,400 0 0000 00000 1 5961 00000 00000 00000 1.5961 (I 5961) 15961 13,407 Dem1nd Ch1rg11 0 0000 0 0000 00000 0 0000 0 0000 00000 00000 00000 DODOO 0 Summer On 3.146 8 5648 0 0000 0 0000 3 1337 00000 00000 3 1337 5 4311 00000 0 4 4445 0.9866 Inter 2.307 1 0494 0 0000 00000 0 376t DODOO 00000 0.3761 06733 DODOO 0 05467 0.1268 OH 2.936 t 0494 0 0000 00000 0 3761 00000 00000 0 3761 06733 00000 0 0 5467 0 1286 Winier On 5.544 7 4308 0 0000 00000 2 7264 00000 00000 2 7264 4 7042 0 ODDO 0 3 85711 011464 lnler 4,243 t 0494 0 0000 00000 0 3761 00000 00000 0 3761 0 6733 0.0000 0 0 5487 01266 OH 5, 121 t 0494 00000 00000 0 3761 0.0000 00000 0.3761 0.6733 0.0000 0 0 5467 0.1266 Energr Ch1rgH On 2.068,759 7 5452 I 1222 00000 02661 4 4658 1.0315 6 6856 06596 4 4656 92,387 06596 lnler 289.626 6 5889 I 1222 00000 02661 36912 I 03t5 6 3110 0257!1 3.8912 11,270 0 2579 OH 1.779.133 5 6098 11222 00000 0 2661 2.3862 1.0315 4.8060 08036 2.3862 42.454 08036 Tol1I* 4, 137,518 4.51 189,467 Specl1I Annu1I Minimum Sp11cl1I F'rovl1lon1-LPL Slandbr-Sec. 29 3 8600 00000 0 1800 2 8300 0 8500 00000 3 8600 (0 0000) I 0300 30 Slandbr* Pri 38 2 7300 0 0000 0 1800 16900 0.8700 0.0000 2.7400 10.01001 1.0500 40 70 Area Dev. Svc Cr Yrs 1-5-Sec 1, 158 12 8500) 00000 00000 (2 85001 00000 00000 12 8500) 0 0000 0 0000 0 Area Dev. Svc Cr. Yrs 1-5-Pri 300 00000 0 0000 00000 0 0000 00000 00000 00000 00000 00000 0 Curt Elec. Svc Cr Curt Elec. Svc. Peak Cr IES Cr 2 Hr. Nlc.-Sec. 36 13 29001 00000 00000 0 0000 (3 29001 00000 (3 2900) 0 0000 (3 2900) (t t81 IES Cr. 30 Min Nlc.-Sec. 99 (4 5300) 00000 DODOO 0 0000 (4 5300) 0 0000 14 5300) 00000 14 5300) (4481 IES Cr. 2 Hr. Nie -Prl. 0 13 2900) 00000 00000 00000 13 2900) 0.0000 13 2900) 0 0000 (3 2900) 0 IES Cr. 30 Min Nie -Prl. 75 14 53001 0.0000 00000 00000 14 5300) 00000 (4 5300) 00000 14 5300) (340)

IES Chg. 2 Hr. Nie. (9061 IES Chg 30 Min Nie.

2000 Unbundled Rate.

Detall bill del. Subtotal Prellmn. Shopping ShpCr MTC AdJ 2000 Rate SBC/NTC Trans Dist BGS STC Sublol*I MTC credit Reveri11e ObllgAdJ. MT.C 111 (21 Ill 141 151 161 (71 ll*sum 3-7 (9*2*111 110:04+61 111*1*101 1121 (131 HTS-Sublrans Service Charge 2 192 2.026 07 0 00 0 00 2.026 07 0 00 0.00 2,026.07 0 0 0 C1paclly Obllgallon 8.038 00000 0 0000 0 0000 0 0000 3 0033 0 0000 3 0033 (3 0033) 3.0033 24,141 Tr1n1ml11lon Obllgallon 6,768 0 0000 0 0000 1 5961 0 0000 00000 0 0000 1 5961 (1.59611 1.5981 10,802 Dem1nd Ch1rge1 00000 00000 0 0000 0 0000 0 0000 00000 0.0000 00000 0.0000 0 Summer On 2,835 10 4834 0 0000 00000 1 3031 0 0000 00000 13031 9.1803 00000 0 4.4700 4 7103 lnler 00000 00000 00000 0 0000 00000 00000 00000 00000 0.0000 0 0.0000 0.0000 Off 0 0000 0 0000 0 DODO 00000 0 0000 00000 00000 DODOO 00000 0 DODOO 0.0000 Winier On 5,457 9 5718 00000 00000 1 1858 00000 00000 11858 e 3860 0.0000 0 4 0811 0049 lnler 00000 00000 00000 0 0000 00000 DODOO 00000 DODOO 0.0000 0 0 DODO 0.0000 Off 00000 00000 00000 0 0000 00000 0.0000 00000 0.0000 0.0000 0 0.0000 0.0000 Energy Ch.rgH On I 587.774 6 8074 1 1060 0 0000 0 1940 4 3401 1 0315 86716 0.1358 4 3401 88,911 0 1358 lnler 283.453 5 8365 I 1060 0 DODO D 1940 3 7771 I 0315 8 1088 (0 27211 3.7771 10,708 (0.27211 Off 1.620 416 5 0616 I 1060 0 0000. 0 1940 2 2987 I 0315 4.6302 0 4314 2 2987 37.249 0.4314 Tol*l1 3,491.643 4.35 151,809 Specl1I Annu1I Minimum HTS-High Voll*ge Service Charge 0 168 I 823 4 7 0 00 0 00 I 623 47 0 00 0 00 1.823 47 0 0 0 C1p1clly Obllg1Uon 696 0 0000 0 0000 0 0000 0 0000 3 0033 0 0000 3 0033 (3 0033) 3 0033 2,098 Tr1n1ml11lon Obllg1tlon 568 0 0000 0 0000 I 5961 0 0000 0 0000 0 0000 15961 (I 5961) 1.5961 939 D1m1nd Ch11ge1 0 0000 D 0000 0 0000 00000 00000 0 0000 0 ODDO 00000 00000 0 Summer On 326 9 4351 00000 D 0000 1 1728 0 0000 DODOO 1 1728 8 2623 00000 0 3 3918 4 8705 lnler 0 0000 0 0000 00000 0 0000 00000 0 ODDO 00000 DODOO 00000 0 00000 0.0000 Off. 0 0000 00000 O ODDO 00000 0 0000 00000 00000 OPOOO 00000 0 0 0000 00000 Winier On 623 8 6146 DODOO 00000 I 0688 DODOO 00000 I 0886 7.5460 00000 0 30987 4.4493 lnler 00000 0 0000 0 0000 00000 0 0000 00000 00000 00000 00000 0 DODOO DODOO Off DODOO 0 0000 0 ODDO 0 ODDO 00000 0.0000 0.0000 0.0000 0.0000 0 0.0000 0.0000 Energy Ch1rg1111 On 192.959 60555 1 0796 D DODO 0 1940 4 2413 1 0315 6 5484 (D.4909) 4 2413 8, 184 (0 4909) lnler 26,240 5 1816 1 0796 00000 0 1940 36918 1.0315 5.9969 (08153) 3 89111 989 (08153) on 160.317 4.4842 I 0796 00000 0 1940 2 2493 1.0315 4.5544 (0.07021 2.2493 3,608 (0 0702)

Tol1l1 379,516 4.111 15,794 Sp1cl1I Annu11 Minimum 8pecl1I Provisions-HTS Slandby* Sublran1. 410 1 3900 00000 0 1700 0 3200 0 9000 0 DODO 1 3900 00000 1 0700 439 Slandby* High Vollage 208 1.2500 00000 0.1500 D.2900 06200 0.0000 1.2600 (00100) 0.9700 202 641 Area Dev Svc. Cr. Yrs 1*5-Sub 70 (I 90001 00000 00000 11 90001 0 0000 DODOO (190001 00000 0 0000 0 ~>

Area Dev.

Cur1 Elec Svc. Cr Yrs 1-5-HV Svc Cr 49 0 0000 00000 0 0000 0 0000 0 0000 0 0000 0.0000 D 0000 0 0000. D

> "'i C') "'i tTJ >

Cur1 Elec Svc. Peak Cr 312 (3 2900) 0 0000 00000 0 0000 (3 2900) 0 0000 (3 2900) 00000 (3 2900) .-n

"'=

IES Cr 2 Hr. Nlc.-Sub (l.026)

IES Cr 30 Min Nie -Sub 319 14 5300) 00000 0 ODDO 00000 (4 5300) DODOO 14 5300) 00000 (4 5300) (1.4451 IES Cr. 2 Hr. Nlc.-HV 779 0 (3 (4

2900) 5300)

D 0000 00000 00000 DODOO 0 0000 0.0000 (3

(4 2900) 5300) 00000 00000 (3

(4 2900) 53001 00000 00000 (3

(4 29001 5300)

D (3.529) o~

IES Cr. 30 Min Nlc.-HV 'T2 tTJ IES Chg 2 Hr. Nie. (6.000J IES Chg 30 Min Nie. ~ L!

~

N

• blll del. Sublolal 2000 Unbundled Rale Del all

• Prellmn. Shopping ShpCr MTC AdJ 2000 Rate SBC/NTC Trans Dlsl BGS STC Subtotail IYITG CJedll Revenue Obllg.AdJ. FtttC Ill 121 (JI (41 (5) (61 171 ll"SUm 3.7 19*2*111 110:r4+81 111*1*101 1121 1131 BPL 310.201 17 3316 1 1166 0 0000 10 7704 2 6571 1 0315 15 6356 1.4956 2.6571 8,863 310.201 2.118 8,863 PSAL 152.172 21 6335 1 1766 0 0000 13 3919 2 6571 1 0315 18 4573 3.3762 2.8571 4,348 152, 172 2.118 4,348

blll del.

2001 Sublolal Rale SBC/NTC 200 I Unbundled Rall Trans Del all Dlsl BGS src Sublolal Prellmn.

ll'ITG Shopping

~redll ShpCr MTC Rov1111111e ObllgAdJ, Adj PAtC 111 121 Ill 141 151 161 (71 8=1um 3-7 (9=2*81 (10*..4+61 (11a1"101 (121 (131 RS Service Charge 20.664 277 2 4I 0 00 0 00 2 41 0 00 0 00 2 41 0 00 000 0 Energy Charges 0-600 8,346.624 11 6394 1 1768 0 6585 3 2744 5 1461 1 0199 11 2757 0 3637 5 8046 484,488 Over 600 Sum 1.515.830 13 1022 1 1768 0 6585 3 6795 6 0602 I 0199 12 5949 0 5073 6 7187 101,844 Over 600 Win 1.188,286 11 0607 I 1768 0 6585 3 1008 4 4880 I 0199 10 4440 08167 5.1465 61,155 Tolals I 1,050,740 5.116 647,487 RHS Service Ch1rge 34 044 2 41 0 00 0 00 2 41 000 000 2 41 000 0.00 0 Energy Chmrges 0-600 26.137 11 6394 I 1768 0 3124 4 0895 4 0532 1.0199 106518 0 9876 4 3656 1,141 Over600Sum 4.043 13 1022 I 1766 0 3124 4 6089 5.2753 1 0199 12 3933 0 7089 5 5977 226 Over 600 Win 25,003 8 0174 I 1768 0 3124 2 9285 3 6397 1 0199 8.9773 10.95991 3 9521 988 Common. 0 13 1022 I 1768 0 3124 4 6089 5 2753 1 0199 12 3933 0.7089 5.5977 0 Tol1ls 55, 183 4.27 2,355 RLM Service Ch1rge 58 933 12 12 0 00 0 00 12 12 000 000 12 12 0.00 000 0 Service Ch1rge over 20,000 I 19 652 6 79 0 00 0 00 6 79 000 0 00 6.79 000 ODO 0 Service Ch1rge Sp. Prv. (II Energy Ch1rges Summer On 59 453 17 6369 I 1768 '* 0 5490 3 7675 7 6199 I 0199 14 1331 3 5038 8 1689 4,857 lnler 11. 148 16 1126 I 1768 0 5490 3 2418 6 5258 I 0199 12 5133 3.5993 7 0748 789 011 53.260 6 3140 I 1768 0 5490 I 2092 3 8556 I 0199 7.8105 (149651 4 4046 2,346 Winter On 79.063 12 0486 I 1768 0 5490 2 6110 4 8718 I 0199 10 2285 18201 54208 4,286 Inter 18.172 12 2680 I 1768 0 5490 2 4708 4 5383 I 0199 9 7548 2 5132 5 0873 823 011 84.454 8 3140 I 1768 0 5490 I 2092 3 5294 1 0199 7.4843 (1.17031 4.0784 3,444 Tol1l1 303,550 5.45 16,545 WH Energy Ch1rge 8.512 10 1713 I t768 00000 5 2921 2 5681 1.0199 10.0569 0.1144 2.5681 219 Tol1l1 8,512 2.57 219 WHS Service Charge 1 068 2.82 0.00 0 00 2.82 0.00 000 2.82 0.00 0.00 0000 Energy Ch1rge 191 5 4289 I 1768 0 0000 I 5340

• 2 5705 1.0199 6 3012 (0.87231 2.5705 4 910 Tot1l1 191 2.57 4.910 STC, preliminary values, adjusted at least annually.

2001 Unbundled Rate.

De tall blll det. Subtotal 2001 Prellmn. Shopping ShpCr MTC Rate SBC/NTC Trans Dist BGS Adj (fl (21 Ill (41 SJC S11blolal MTG Credit Revenue ObllgAdJ. r.nc (51 (61 171 llmaum J-7 (9"2-111 (10*4+6) (11a1"10)

GLP (12) (13)

Service Charge 2,862 877 4 04 0 00 0 00 4 04 0 00 0 00 4 04 0 Service Charge- Night Use 1 104 367 08 0 00 0 0 0 00 367 08 0 00 0.00 367.08 C1p11clly Obllg11lon 25.884 0 0000 0 0 0 0 0000 0 0000 0 0000 3 0033 0 0000 Tr1n1mlulon Obllg*llon 21.432 3 0033 (3 0033) 3 0033 77,737 0 0000 0 0000 '5961 0 0000 0 0000 0 0000 Demand Charges 1 5981 (I 59611 15961 34,208 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 Summer O*I 0 0000 00000 00000 0 725 4 8866 0 0000 0 0000 3 0170 0 0000 over 1 0 0000 3 0170 1 8696 0 0000 11.007 9 5930 0 0000 0 0000 5 9158 0 1.9468 (0.07721 Winier 0-1 0 0000 00000 5 9158 3 6772 0.0000 1.455 4 8888 0 0000 0 0000 3 0170 0 3.11248 (0.1478) 0 0000 0 0000 3 0170 1 8698 00000 over I 19,446 8 4588 0 0000 0 0000 0 19488 (0.0772) 5 2059 00000 0.0000 5.2059 3.2529 Energy Charges 0.0000 0 3.3735 (0.1208)

All Use.x night use 8.249.900 8 2050 I 1768 0 0000 0 3583 4 0424 I 0199 8 5974 t 6076 N1ghl Use 48.536 7 0751 I 1768 4.0424 333,494 1.8078 0 0000 0 3583 4 0424 1 0199 8 5974 Totals 8.298 436 0 4777 4 0424 1,982 0.4777 6.39 447,401 Monthly Minimum, MD Special Annu1I Minimum Special Provisions Standby 2 000 ) 8600 0 0000 0 1800 2 8900 0 7800 0 0000 3 8500 0 0100 0 9600 2 Area Dev Svc Cr Yrs 1-5 357 12 R500) 0 0000 0 0000 12 8500) 0 0000 0 0000 (2 85001 00000 Area Dev Svc Cr Yrs 6&7 0 0000 0 Curt Elec Svc Cr Curt Elec Svc Peak Cr Police/Fire-Each Police/Fire-Minimum HS Energy Ch1rges Summer 4,366 14 2258 1 1768 0 4063 5 7003 5 4334 1.0199 13 7387 0.4891 Winier 23,917 10 9897 1 1768 0 4083 5.8397 255 Tot111** 4 3648 3 8718 1.0199 10.8396 0. 1501 28,283 4.2781 1,023 4.112 1,278

bill del.

2001 Subtotal Rale SBC/NTC 2001 Unbundled Ral Trans Delall Dist BGS

• STC Subtotal Prellmn.

MTC Shopping Credit ShpCr MTC Revenue ObllgAdJ.

Adj MTC 111 121 (3) 141 (51 161 171 6=sum 3-7 (9=<2-6) (10 .. 4+6) (tl=<l'IOI (12) . '(13)

LPL-Secondary Service Charge 79 006 368 64 0 00 0 00 368 64 0 00 0 00 368 64 0 0 0 Capaclly Obllgallon 27,036 0 0000 0 0000 0 0000 0 0000 J 0033 0 0000 3 0033 (3 0033) 3 0033 8t,197 Transmission Obllgallon 22,740 0 0000 0 0000 1 5961 0 0000 0 0000 0 0000 1 5981 11 5961) 1 596t 38,295 Demand Charges 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 Summer On 8.879 8 7556 0 0000 0 0000 4 1045 0 0000 0 0000 4 1045 4 6511 00000 0 4 3097 0 3414 Inter 8.510 1 1660 0 0000 0 0000 0 5336 0 0000 0 0000 0 5336 0 8324 00000 0 0 5732 00592 Off 8,287 1 1660 0 0000 0 0000 0 5336 0 0000 0 0000 0 5336 0 6324 00000 0 0.5732 00592 Winier On 15.083 7 6108 0 0000 0 0000 3 5710 00000 0 0000 3 5710 4.0398 0 0000 0 3 7451 0 2947 Inter 11,382 1 1660 0 0000 00000 0 5336 0 0000 00000 0 5336 0 8324 00000 0 0 5732 00592 Off 13,510 I 1660 0 0000 0 0000 0 5336 0 0000 0 0000 0.5336 06324 0.0000 0 0.5732 0.0592 Energy Charges On 5,485.658 8 2000 I 1768 0 0000 0 2777 4 7590 1 0199 7 2334 1 0554 4.7590 261.082 10554 Inter 733,523 7 2608 I 1768 0 0000 0 2777 4 1410 1 0199 6 6154 0 8452 4 1410 30,375 06452 Off 4.259.721 5 6292 I 1788 0 0000 0 2777 2 5284 I 0199 5 0028 06264 2 5284 107,703 . 0.6284 Totals I0,478.902 4.93 518,832 Special Annual Minimum LPL-Primary Service Charge 11 374 368 64 0 00 0 00 368 64 0 00 0 00 368 64 0 0 0 0 000 9 4800 0 0000 0 0000 9 4800 0 0000 00000 9 4800 0 0000 00000 0 Capaclly Obllg1tlon 10 008 0 0000 0 0000 0 0000 0 0000 3 0033 0 0000 3 0033 (3 0033) 3 0033 30,057 Tr11nsmlulon Obllgallon 8 424 0 0000 00000 I 5961 0 0000 00000 00000 I 5981 (1 5981) I 5981 13,448 Dem*nd Charges 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 Summer On 3. I 73 8 5648 0 0000 0 0000 3 1337 0 0000 00000 3 1337 5 4311 0 0000 0 4 4227 10084 Inter 2.327 1 0494 0 0000 0 0000 0 3761 00000 0 0000 0 3761 0 6733 0 0000 0 0 5440 0 1293 Off 2.962 I 0494 0 0000 00000 0 3761 0 0000 00000 0 3761 0 6733 0 ODDO 0 0 5440 0.1293 Winter On 5.589 7 4306 0 0000 0 ODDO 2 7264 0 0000 00000 2.7264 4 7042 0.0000 0 3 8389 0 8853 Inter 4,278 1 0494 00000 0 0000 0 3781 0 0000 0 0000 0 3761 06733 00000 0 05440 0.1293 Off 5,164 1 0494 0 0000 0 0000 0 3761 00000 00000 0 3761 0.6733 0.0000 0 0.5440 01293 Energy Charges On 2,086,870 7 5452 1 1222 0 0000 0 2661 4 5297 1 0199 8 9379 06073 4 5297 94,529 06073 Inter 292.162 6 5669 1 1222 0 0000 0 2861 3 9470 I 0199 8 3552 02137 3 9470 11,532 0 2137 Ott 1,794,708 5 6096 I 1222 00000 0 2661 2 4206 1.0199 4.8288 0.7808 2.4206 43,443 0.7808 Totals 4, 173.740 4.112 193,007 Special Annual Minimum Spec:l1I Provl1lon11-LPL Slandby-Sec. 29 3 8600 0 0000 0 1800 2 8300 0.8500 00000 3 8600 (0 0000) I 0300 30 Standby- Prt. 38 2 7300 0 0000 01800 I 6900 0 8700 0.0000 2 7400 (0.0100) I 0500 40 70 'i1 >

> :J Area Dev. Svc Cr Yrs 1-5-Sec. 1,158 (2 8500) 0 0000 00000 12 8500) 0 0000 0 0000 12 8500) 00000 00000 0 Area Dev Svc. Cr Yrs 1-5-Pri 300 0 0000 0 0000 00000 0 0000 0 0000 0 0000 00000 0.0000 00000 0 Curt Curt Elec Svc Elec. Svc Cr Peak Cr ~>(j N

IES Cr 2 Hr. Ntc.-Sec. 36 13 2900) 0 0000 0 0000 0 0000 (3 2900) 0 0000 (3 2900) 00000 (3 2900) 1118) ~=

IES Cr 30 Min Ntc.-Sec IES Cr 2 Hr. Nie -Pri.

99 0

(4 5300)

(3 2900) 0 0000 0 0000 DODOO 0 0000 0 0000 0 0000 14 (3

5300) 2900) 0 DODO 0 0000 (4

(3 5300) 2900)

DODOO 00000 14 (3

5300) 2900) 14481 o~

0 lof1 t'f'.I IES Cr. 30 Min Nlc.-Pri. 75 14 5300) 0 0000 00000 0.0000 14 5300) 00000 14 5300) 0 0000 (4 5300) (340)

IES Chg 2 Hr. Nie. (908)

.ii. 2!

IES Chg 30 Min Nie. o~

N

• blll det.

2001 Subtotal Rate SBC/NTC 2001 U!1bundled Rate.

Trans Detall Dist BGS STC Subtotal Prellmn.

MTC Shopping Credll ShpCr MTC RevenUI! Obllg.AdJ.

Adj MtC (fl 121 (JJ (41 (51 161 171 8=sum l-7 (9"2*11 (10 .. 4+6) (11*t"10J (121 '(131 HTS-Subtrans Service Charge 2 203 2.026 07 0 00 0 00 2,026 07 000 000 2,026 07 0 0 0 C*paclty Obllgallon 7.894 0 0000 0 0000 0 0000 0 0000 3 0033 0 0000 3 0033 (3.00331 30033 23.708 Transmission Obllgallon 6,646 00000 0 0000 t 596t 0 0000 0 0000' 0 0000 I 5961 (I 5961) I 5961 10,608 Dem*nd Chuges 0 0000 00000 0 0000 00000 0 0000 00000 0 0000 0.0000 0.0000 0 Summer On 2,803 10 4834 0 0000 00000 I 3031 0 0000 00000 I 3031 9 1803 00000 0 4 4417 4.7386 lnler 0 0000 0 0000 0 0000 00000 00000 00000 00000 0 0000 00000 0 00000 *.0 0000 OH 0 0000 0 0000 0 0000 0 0000 0 0000 00000 00000 00000 0 0000 0 0.0000 00000 Winier On 5,392 9 5718 00000 0 0000 I 1858 0 0000 00000 1 1858 8.3880 00000 0 4 0553 .. 3307 Inter 00000 0 0000 00000 00000 0 0000 00000 00000 Q0000 00000 0 00000 0.0000 OH 0 0000 0 ODDO 0 0000 00000 00000 00000 00000 0.0000 0.0000 0 0.0000 0.0000 Energy Ch*rges On 1.560.374 6 8074 I I060 00000 0 1940 4 4027 f 0199 6 7228 00848 4 4027 88,899 0.0848 Inter 278.562 5 8365 I I060 00000 0 1940 3 8319 f 0199 6 1518 ID 31531 3 8319 10,874 co 3153)

OH I 592.452 5 0616 I 1060 0 0000 0 1940 2 3324 1 0199 4 6523 0.4093 2 3324 37.142 0.4093 Totals 3.431,388 4.40 150,831 Specl*I Annu*I Minimum HTS*Hlgh Vollage Service Charge 0 169 I 823 47 0 00 0 00 1.823 47 000 000 1.823.47 0 0 0

(

C1paclly Obllg*tlon 686 0 0000 0 0000 0 0000 0 0000 3 0033 00000 3 0033 (3 0033) 3 0033 2.060 Tr*n1ml111lon Obllgatlon 578 0 0000 0 0000 I 5961 00000 0 0000 00000 1 5961 (1 5961) 1 5961 923 D1m1nd Charg111 0 0000 0 0000 0 0000 00000 0 0000 00000 00000 00000 0 0000 0 Summer On 323 9 4351 00000 0 0000 1 1728 0 0000 00000 I 1728 8 2623 0 0000 0 3 3725 4 6898 Inter 0 0000 0 0000 0 0000 0 0000 0 0000 00000 00000 0 0000 00000 0 00000 0 0000 OH 0 0000 0 ODDO 00000 00000 00000 00000 00000 00000 00000 0 00000 00000 Winter On 615 8 6146 0 0000 0 0000 I 0886 00000 00000 1 0666 7.5460 00000 0 30791 4 4669 Inter 0 0000 0 0000 0 0000 00000 0 0000 00000 00000 0 0000 00000 0 00000 00000 OH 0 ODDO 0 0000 DODOO 00000 DODOO 0.0000 0.0000 0.0000 00000 0 00000 0.0000 Energy Charg1111 On 189,629 6 0555 1 0796 00000 0 1940 4 3025 t.0199 6 5960 (0 5405) 4.3025 8,159 (0 5405) lnler 25,787 5 1816 I 0796 00000 0 1940 3 7452 I 0199 6 0387 (0.8571) 3.7452 968 (08571)

Off 157,551 4 4842 I 0796 00000 0 1940 2 2821 1.0199 4.5758 (0.0914) 2 2821 3,595 (0.0914)

Tot1ls 372,967 4.21 15,703 S111ctal Annu1I Minimum Sp11cl1I Provl1lon1-HTS Slandby* Sublrans. 410 I 3900 0 0000 0 1700 0 3200 0 9000 DODOO 13900 DODOO I 0700 439 Standby* High Vollage 208 I 2500 00000 0 1500 02900 0 8200 00000 1.2600 (00100) 0.9700 202 641 ~>

Area Dev Svc Cr Yrs 1*5-Sub 70 (I 90001 0 0000 00000 (I 9000) 0 0000 . 00000 (I 9000) 0 0000 0 0000 0 >~

~>

Area Dev Svc Cr. Yrs 1*5-HV 49 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 00000 0 ODDO 00000 0 Curl Elec Svc Cr Curl Elec Svc Peak Cr N (j IES Cr 2 Hr. Nte.-Sub 312 (3 2900) 00000 00000 0 0000 (3 2900) 00000 (3 2900) 00000 (3 2900) (l,026)

~=

IES Cr. 30 Min Nie -Sub 319 (4 5300) 00000 00000 00000 (4 5300) 00000 (4 5300) 0 0000 (4 5300) (1.445) o~

IES Cr. 2 Hr. Nle.-HV 0 (3 2900) 0 0000 00000 0 0000 (3 2900) 00000 (3 2900) 0 0000 (3 2900) 0 ~M IES Cr. 30 Min Nlc.-HV 779 (4 5300) 00000 00000 DODOO (4 5300) 00000 (4 5300) 0 0000 (4 5300) (3.529) ~ '.2!

IES Chg 2 Hr. Nie. (6.000) o~

IES Chg 30 Min Nie N

blll del. Sublolal 2001 Unbundled Ralei.

Del all 2001 Rate SBC/NTC Prellmn. Shopping ShpCr MTC Trans Dist BGS STC Adj Subtolal MT<; ~radii Revenui ObllgMJ.

111 (21 Ill 141 (5) 161 171 l=suml-7 C9*2*11 (t0 ..4+8) C1t*t*101 r.trc 1121 C131 BPL 313.710 17 3316 1 1768 0 0000 10 7704 2 8983 1 0199 313.710 15.8654 1.4662 2.8983 9.092 2.9!J 9,092 PSAL 155,961 21 8335 1 1768 0 0000 t3 3919 2 8983 155.981 1 0199 18 4869 J.3468 2 8983 4.520 Z.90 4,520

2002a Unbundled Ral Detail blll del. Subtolal 2002 Rate Prellmn. Shopping ShpCr MTC SBC/NTC Trans Dist BGS STC AdJ It) Subtotal "'TC credit Revenue ObllgAdJ.

RS 121 131 141 (51 161 111 Bcsum 3.7 (9*2*8) 1\U.C (10*4+6) (11*1"10) (12) (131 Service Charge 20.832 180 2 41 0 00 0 00 2 41 000 0 00 Energ~ Charges 2 41 000 0.00 0 0-600 8,488.719 11 6394 I 1768 0 6550 3 2744 5 1540 1 0069 Over600 Sum 1.541.636 11 2671 0 3723 5 8090 493, 110 13 1022 I 1768 06550 3 6795 6 0712 Over 600Win 1 0069 12 5894 0 5128 6.7262 1.208.515 11 0607 1 1768 0 6550 3 1008 103,694 Totals 4 4935 1 0069 10.4330 06277 1 (238.870 5.1485 62.220 5.16 659,024 RHS Service Charge 0 000 Energ~ Chargea 0*600 0 Over600 Sum 0 Over 600 Win 0 Common 0 Totals 0 RLM Service Chuge 58 585 12 12 0 00 000 12 12 000 000 Service Charge over 20,000 118 944 6 79 12 12 0 00 0 00 0 0 00 0 00 6 79 000 000 Service Charge Sp. Prv. (II 6 79 0.00 000 0 Energ~ Charges S!Jmmer On 58 498 17 6369 1 1768 ' 0 5451 3 7675 7 6338 1 0069 lnler 10.968 16 .1126 14 1301 3 5088 8 1769 4,784 I 1768 0 5451 3 2418 on 52.405 6 3140 1 1768 0 5451 1 2092 6 5359 1 0089 12.5085 3.8061 10810 777 Winier On 3 8583 10089 7 7943 11 4803) 77.793 12 0486 1 1768 0 5451 4.4014 2,307 lnler 2 6110 4 8781 10089 10 2159 15.912 12 2680 I 1768 0 5451 1 8327 5 4212 4.217 on 2 4708 4 5415 1 0089 9 7411 2 5269 83.097 6 3140 1 1768 0 5451 5 0866 809 Tol*I* 1 2092 3 5290 1 0069 7 4670 (1.1530) 298.673 4.0741 3,385 11.45 16,279 WH Energ~ Ch*rge 7.194 10 1713 1 1768 0 0000 5 2921 2 5370 1.0069 Total* 7,194 10.0128 *0.1585 2.5370 183 2.14 183 WHS Service Charge 0 960 2 82 0.00 0.00 2 62 0.00 0.00 Energ~ Ch1rge 166 5 4289 1 1768 2.82 0.00 0.00 0000 0 0000 15340

• 2 5394 1.0089 To111l1 166 6.2571 (0 8282) 2.5394 4 215 2.54 4 215

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STC, preliminary values, adjusted at least annually.

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bill del ..

2002 Subtotal Rale SBC/NTC Trans 2002a Unbundled Ra, Dela II Dist BGS

• STC Subtot11I Prellmn.

r.'ITC Shopping Credit ShpCr MTC Adj (IJ 121 (31 (41 151 (61 Reven1111 ObllgMJ. r.trc GLP (7) ll=sum 3-7 (9"2*11) 110 .. 4+6) (11"1"10) (12) (13)

Service Charge 2.661 491 4 04 0 00 0 00 4 04 0 00 0 00 4 04 Service Charge. Night Use 0 964 367 06 0 00 0 0 0 0 00 367 06 0 00 000 367.06 Capacity Obllgallon 26.160 0 0000 0 0000 0 0 0 0 0000 0 0000 3 0917 00000 3 0917 Transmission Obllgallon 22.020 0 0000 0 0000 (3 0917) 3 0917 80.879 I 5961 0 0000 0 0000 0 0000 1 5961 Demand Charges 0 0000 (1 5961) 1 5981 35, 146 0 0000 0 0000 0 0000 0 0000 0 0000 Summer O*I 734 0 0000 00000 0 0000 0 4 6666 0 0000 0 0000 3 0170 0 0000 over I 00000 3 0170 1 8696 00000 11.146 9 5930 0 0000 0 0000 5 9158 0 1 9922 (0 1226)

Winier 0-1 0 0000 0 0000 5 9158 3 8772 00000 1.474 4 8866 0 0000 0 0000 3 0170 0 3 9140 (0 2368) over I 0 0000 0 0000 3 0170 1 8696 19,698 8 4588 0 0000 0 0000 0 0000 0 1 9922 (0 1226) 5 2059 0 0000 00000 52059 3 2529 Energy Charges 0.0000 0 3.4521 (0.1992)

All Use-x night use 8.373.400 8 2050 1 1768 0 0000 0 3583 4 0623 I 0069 6 6043 16007 Night Use 42,782 7 0751 1 1768 0 0000 4 0623 340, 153 16007 0 3563 4 0623 1 0069 66043 0.4708 Tot1ls 8,416, 182 4.0623 1.738 0.4708 5.44 457,916 Monlhly Minimum, MD Speclal Annu1I Minimum Specl1I Provisions Standby 2 000 3 8600 0 0000 0 1800 2 8900 0 7600 0 0000 3 8500 0 0100 0 9600 2 Area Dev Svc Cr Yrs 1-5 357 (2 8500) 0 0000 0 0000 (2 8500) 0 0000 0 0000 (2 8500) 0 0000 Area Dev Svc Cr Yrs 6& 7 0 0000 0 Curt Elec Svc Cr Curt Elec Svc Peak Cr Police/fire-Each Police/fire-Minimum HS Energ~ Ch1rges Summer 4.206 14 2256 1 1766 0 4217 5 7003 5 5159 I 0069 13 6216 Winier 23.047 10 9897 I 1768 0 4042 59376 250 0 4217 4 3648 3 9490 1.0089 10.9192 Tot1l1 27.253 0.0705 4.3707 l,007 4.11 1,257

blll del.

2002 Sublotal Rate SBCINTC 2002a Unbundled Ra Trans Delall Dist BGS

• STC Subtot;1I Prellmn.

IWTG Shopping Credi I ShpCr MTC Revenue ObllgMJ.

Adj M.tC 111 121 Ill (4) (51 (6) (71 B=sum l-7 19*2-8) lt0=4+61 111 .. 1*101 LPL-Secomtary 1121 (131 Service Charge 79 620 368 64 0 00 0 00 366 64 0 00 0 00 366 64 0 0 Capacity Obllgallon 27,324 0 0000 0 0000 0 0000 0 0 0000 3 0917 0 0000 3 0917 (3.09171 3 0917 TransmlHlon Obllgallon 22.992 0 0000 0 0000 64,476 1 5961 0 0000 0 0000 0 0000 I 5961 (I 5981)

Demand Chargu 0 0000 0 0000 1 5961 36,696 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 Summer On 9.014 6 7556 0 0000 0 0 0000 0 0000 4 1045 0 0000 0 0000 4 1045 lnler 4 6511 0 0000 0 4 3609 02702 6.609 I 1660 0 0000 0 0000 0 5336 00000 0 0000 Ott 0 5336 0 6324 0 0000 0 0 5627 6,413 I 1660 0 0000 00000 0 5336 0 0000 00497 Winier 0 0000 0 5336 0 6324 00000 0 On 15.297 7 6106 0 0000 0 0000 0 5627 0 0497 3 5710 0 0000 00000 3 5710 4 0398 00000 lnler 11.523 I 1660 0 0000 0 0000 0 3 6070 0.2328 0 5336 0 0000 00000 0 5338 0 6324 0 0000 Ott 13,702 I 1660 0 0000 00000 0 0 5827 0.0497 0 5336 0 0000 0.0000 0 5336 0 6324 0.0000 Energy Charge.I 0 0 5827 0.0497 On 5.570.349 6 2686 I 1768 0 0000 0 2777 4 7615 I 0069 7 2429 I 0459 4 7615 lnler 744 848 7 2606 I I 768 266,346 10459 0 0000 0 2777 4 1612 I 0069 6 6226 06360 Ott 4 325 488 5 6792 I 1768 4 1612 30,995 0.6380 0 0000 0 2777 2 5431 I 0069 5 0045 0 6247 Totals IO 640 685 2 5431 110.001 !16247 4.97 526,516 Special Annual Minimum LPL-Primary Service Charge 11 459 JC,ff 64 0 00 0 00 JliA 64 0 00 0 00 368 64 0 0 000 9 4600 0 0000 0 0000 0 0 9 4800 0 0000 0 0000 9 4600 0 0000 Capacity Obllgallon 10 044 0 0000 0 0000 0 0 0000 '* 0 0000 0 0000 3 0917 0 0000 3 0917 (3 0917)

Transml1111lon Obllgallon 6 460 0 0000 0 0000 3 0917 31.053 I 5961 0 0000 0 0000 0 0000 1 5961 Demand Charge! 0 0000 II 5961) 1 5961 13,503 0 0000 0 0000 0 0000 0 0000 0 0000 00000 Summer On 3 202 8 5648 00000 0 0000 0 0 0000 0 0000 3 1337 0 0000 0 0000 3 1337 lnler 2 348 I 0494 54311 0 0000 0 4 4904 0 9407 0 0000 0 0000 0 3761 0 0000 00000 Ott 0 3761 0 6733 00000 0 0 5523 2 988 I 0494 0 0000 0 0000 0 3761 0 0000 0 0000 01210 Winier On 0 3761 0 6733 00000 0 0 5523 5 637 7 4306 0 0000 0 0000 2 7264 0 0000 01210 lnler 0 0000 2 7264 4 7042 00000 0 4.314 I 0494 0 0000 0 0000 0 3761 0 0000 3 6977 0 8065 Ott 0 0000 0 3761 0 6733 00000 0 5,208 I 0494 0 0000 00000 0 3761 0 0000 0 5523 0 1210 Energy Charges 0.0000 0.3761 0 6733 0.0000 0 05523 0.1210 On 2.105.732 7 5452 I 1222 0 0000 0 2661 4 5509 1 0069 6 9461 0 5991 .4 5509 lnler 95.630

... Ott 294,802 1.610,929 6 5689 5 6096 1 1222 0 0000 0 2661 3 9662 I 0069 6 3614 02075 3 9662 11,692 05991 02075 I 1222 00000 0 2661 2 4345 1 0069 4 8297 Totals 4.211,463 0 7799 2 4345 44,087 0 7799 4.86 196,165 Sptclat Annual Minimum Speclal f>rovl1lon11-LPL Slandby-Sec. 29 3 6600 0 0000 0 1600 2 6300 0 8500 0 0000 3 6600 (0 0000) I 0300 Slandby- Prl 36 . 2 7300 0.0000 0 1600 30 16900 0 6700 00000 2 7400 (0.0100) I 0500 40 Area Dev Svc Cr Yrs I *5-Sec 1.158 (2 6500) 0 0000 0 0000 (2 6500) 0 0000 00000 (2 8500) 70 ""d>

~~

Area Dev Svc Cr Yrs 1*5-Pri 300 0 0000 00000 0 0000 0 0 0000 0 0000 0 0000 0 0000 00000 0 0000 Curl Elec Svc Cr 0 0000 0 0000 0 Curt Elec Svc Peak Cr M>

IES Cr 2 Hr. Nie -Sec N ("')

36 IES Cr 30 Min Nie -Sec (3 2900) 0 0000 0 0000 0 0000 (3 2900) 0 0000 j3 2900) 0 0000 (3 2900) (118) 00 ::z=

99 (4 5300) 0 0000 0 0000 00000 o~

(4 5300) 0 0000 (4 5300) 0 0000 (4 5300)

IES Cr. 2 Hr. Nie -Pri. 0 (3 2900) 0 0000 0 0000 (446) 0 0000 (3 2900) 0 0000 (3 2900)

IES Cr. 30 Min Nie -Prl 75 (4 5300) 0 0000 0 0000 00000 (4 5300) 0 0000 0 0000 (3 2900) 0 ~M (4 5300) 0 0000 IES Chg 2 Hr Nie. (4 5300) (340) ~ L!

IES Chg 30 Min Nie (906) O....:j N

2002a Unbundled Ral Dela II bill del. Sublolal Prellmn. Shopping ShpCr MTC Adj 2002 Rale SBCINTC Trans Dlsl BGS STC Subtotal MTc Cre111t Revenue Obllg Adj. PllT.C (II (21 (31 (41 (51 (61 111 8=sum 3-7 (9"2*8) (10"4*61 (11=1*101 (121

• 1u1 HTS-Subtrans Service Charge 2 214 2.026 07 0 00 000 2.026 07 0 00 0.00 2,026.07 0 0 0 Capacity Obllgallon 7.915 0 0000 0 0000 0 0000 0 0000 3 0917 00000 3 0917 (3 0917) 3 0917 24.471 Transmlulon Obllgallon 6.668 0 0000 0 0000 *I 5961 0 0000 0 0000 0 0000 I 5961 (1 59611 I 5961 10,643 Demand Charg111 0 0000 0 0000 0 0000 00000 00000 0 0000 0 0000 00000 00000 0 Summer On 2.817 10 4834 0 0000 0 0000 1 3031 0 0000 0 0000 1 3031 91603 0 0000 0 4 5234 4 6569 Inter 0 0000 0 0000 0 0000 0 0000 00000 0 0000 00000 00000 0.0000 0 0.0000 00000 011 0 0000 00000 0 0000 0 0000 0 0000 0 0000 00000 0 0000 0 0000 0 0 0000 00000 Winier On 5.417 9 5718 0 0000 0 0000 I 1858 00000 00000 1 1858 8 3860 00000 0 . 41299 4 2561 lnler 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 00000 00000 00000 0 00000 0.0000 011 0 0000 00000 00000 0 0000 00000 00000 00000 00000 0.0000 0 00000 0.0000 Energy Charges On 1.563.654 6 8074 I 1060 0 0000 0 1940 4 4293 .I 0089 6 7362 0.0712 4 4293 69.259 0.0712 lnler 279.146 5 8365 I 1060 0 0000 0 1940 3 6565 I 0069 8 1634 (0 3269) 3 6565 10,765 (0.3269) 011 1.595 800 5 0616 I 1060 0 0000 0 1940 2 3516 I 0069 4 6567 04029 2 3516 37,530 0.4029 Totals 3.436.600 4.44 152,666 Special Annual Minimum HTS-High Voltage Service Charge 0 170 I 623 47 0 00 0 00 I 823 4 7 0 00 0 00 1,62347 0 0 0 Capacity Obllgallon 689 0 0000 0 0000'. 0 0000 0 0000 3 0917 00000 3 0917 (3 0917) 3 0917 2,130 Transml11lon.Obllgallon 580 0 0000 0 0000 1 5961 0 0000 0.0000 0 0000 I 5961 (15961) 1.5961 926 Demand Charges 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 00000 0.0000 00000 0 Summer On 324 9 4351 0 0000 0 0000 I 1728 00000 0 0000 11726 6 2623 00000 0 3 4372 4 8251 lnler 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 00000 00000 00000 0 00000 00000 011 0 0000 0 0000 0 0000 0 0000 00000 00000 0 0000 00000 00000 Ii 00000 00000 Winier On 619 e 6146 0 0000 0 0000 1 0686 00000 00000 1 0666 7 5460 00000 0 3.1382 4 4078 lnler 00000 00000 0 0000 0 0000 00000 00000 00000 00000 00000 0 00000 00000 011 0 0000 0 0000 0 0000 0 0000 00000 0.0000 0.0000 0.0000 0.0000 0 0.0000 0.0000 Energy Charges On 190.026 6 0555 I 0796 0 0000 0 1940 4 3266 1.0069 66091 (0 5536) 4 3288 8,228 (0 5536) lnler 25,842 5 1816 I 0796 0 0000 0 1940 3 7694 1 0069 60499 (0 6683) 3 7694 974 (0.6663) 011 157,862 4 4842 1 0796 0 0000 0 1940 2 3013 1 0069 4.5618 (0.0976) 2.3013 3,633 (0 09761 Total* 373.752 4.25 15,669 Sp1cl1I Annual Minimum Speclal Provisions-HTS Slandby- Sublrans. 410 1 3900 0 0000 0 1700 0 3200 0 9000 0 0000 I 3900 00000 1 0700 439 ~>

Slandby- High Vollage 206 I 2500 0 0000 0.1500 0 2900 0 6200 00000 1 2600 (0 0100) 0 9700 202

> ::j

~>

641 Area Dev. Svc Cr Yrs 1-5-Sub 70 (1 90001 0 0000 00000 (I 9000) 0 ODDO 0 DODO (19000) DODOO 0 0000 0 49 DODOO 0 0000 0.0000 0 0000 0 0000 00000 00000 n

=

Area Dev. Svc Cr. Yrs 1-5-HV 00000 0 0000 0 Curt Elec Svc Cr tJ Curt Elec Svc. Peak Cr \0 IES Cr 2 Hr. Nlc.-Sub 312 (3 2900) 0 0000 0 0000 0 0000 (3 2900) 0 0000 (3 2900) 00000 (J 2900) (1.0261 0 3:

lof1 P1 IES Cr 30 Min Nie -Sub 319 (4 5300) 00000 00000 0 0000 (4 5300) 00000 (4 53001 0 0000 (4 5300) (1.445) ~~

IES Cr 2 Hr. Nie. -HV 0 (3 2900) 0 0000 0 0000 00000 (3 29001 0 0000 (3 2900) 00000 (3 2900) 0 0 -i IES Cr. 30 Min Nie -HV 779 (4 5300) 00000 0 0000 00000 (4 53001 00000 (4 5300) 00000 (4 53001 (3 5,29)

IES Chg 2 Hr. Nie. (6.000) tJ IES Chg 30 Min Nie

• blll det. Subtotal 2002a Unbundled Rat.

Detall Prellmn.

2002 Rate SBC/NTC Trans Shopping Shp Cr MTC AdJ Dist BGS STC Subtotal MTC ~redll Revenue Obllg Adj. MTC 111 121 Ill 141 151 161 (7) B=1um 3-7 19 .. 2-11) (10*4*61 111-1*101 1121 "1131 BPL 317.218 17 3316 I 1768 0 0000 10 7704 2 9142 I 0069 15 8683 t.4633 2.9142 9.244 317.218 2.91 9,244 PSAL 159.749 21 8335 t t768 0 0000 13 3919 2 9142 t 0069 t 8 4898 3 3437 2.9t42 t59.749 4,655 2.91 4,655

2002b Unbundled Ral Dela II blll del. Sublolal 2002 Prellmn. Shopping ShpCr MTC AdJ Rate SBCINTC Trans Dist BGS STC Subtolill MTC Creitlt ftevonue Obllg Adj. Mt<:

Ill 121 Ill 141 151 161 RS 171 B=sum 3.7 19"2*111 110=4+61 l1t*t*101 1121 CUI Service Charge 20.832 180 2 41 0 00 0 00 2 41 0 00 0 00 2 4,1 000 0 00 Energy Charges 0 0*600 8.488.719 11 6967 I 1768 0 6550 3 3317 5 1540 1 0069 11 3244 0 3723 5 8090 493,ttO Over600 Sum 1.541.636 13 1595 1 1768 0 6550 3 7368 6 0712 ' 1 0069 12 6467 05128 8 7262 103,894 Over 600Win 1.208.515 11 1179 I 1768 0 6550 3 1581 4 4935 I 0069 10 4903 08278 5 1485 Totals 11.238.870 62.220 5.116 859,024 RHS Service Charge 0 000 Energy Ch1rges 0*600 0 Over600 Sum 0 Over 600W1n 0 Common 0 Totals 0 RLM Service Ch1rge 58 585 12 12 0 00 0 00 12 12 000 000 12 12 0 00 0 00 Service Charge over 20,000 118 944 6 79 000 0 00 6 79 0 0 00 0 00 8 79 0 00 0.00 Service Ch1rge Sp. Prv. Ill 0 Energy Charges Summer On 58 498 17 6761 I 1768 ' 0 5451 3 8067 7 6338 1 0069 14 1693 3 5068 8 1789 Inter IO 968 16 1519 I 1768 0 5451 4,784 3 2810 6 5359 1 0069 12 5457 3 6062 Off 52 405 6 3532 I 1768 0 5451 7 0810 777 1 2484 3 8563 I 0069 7 8335 (148031 Winier On 77 793 12 0878 1 1768 0 5451 4 4014 2.307 2 6502 . 4 8761 1 0089 10 2551 t 8327 Inter 15.912 12 3072 I 1768 54212 4,217 0 5451 2 5100 4 5415 1 0069 9 7803 2 5289 011 83.097 6 3532 1 1768 50888 809 0 5451 1 2484 3 5290 1 0089 7 5062 Tolal1 :198.673 11.15301 ... 0741 3,385 5.45 16,279 WH Energy Charge 7, 194 10 2021 1 1768 00000 5 3229 2 5370 t.0069 ID 0436 0.1585 2.5370 Tol1l1 7,194 183 2.54 183 WHS Service Charge 0 960 2 82 000 0.00 2.82

• 0.00 0.00 2.82 0.00 0.00 Energy Ch1rg1 166 5 4596 I 1768 0.0000 0000 Tol1l1 168 1 5648 2 5394 1.0089 62879 co 82831 2.5394 4 215 2.54 4.215

'i:1 >

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bill del.

2002 Sublolal Rale SBC/NTC 2002b Unbundled Rat.

Trans Detall Dist BGS STC Sublol11I Prellmn.

MTC Shopping credit ShpCr MTC Revenue ObllgAdJ.

AdJ (1) 121 Ill (4) 151 M.T.C GLP 161 171 ll=sum l-7 (9=2-lll (10=4+6) 111*1*101 ltZI 1131 Service Ch1rge 2.66t 491 4 04 0 00 0 00 4 04 0 00 000 4 04 0 Service Ch1rge- Night Use 0 964 367 08 0 00 0 00 0 0 367 08 0.00 000 367.08 0 C1p1clly Obligation 26. t60 0 0000 0 0000 0 0000 0 0 00000 3 09t7 00000 3 0917 (3 0917)

Transmission Obllgallon 22,020 00000 0 0000 t 596t 3 0917 60.879 0 0000 0 0000 0 0000 1 5961 (1 59811 Dem1nd Ch1rges 00000 0 0000 0 0000 1.5961 35,148 0 0000 0 0000 00000 00000 0 0000 Summer 0-t 734 4 6666 0 0000 00000 0 0 0000 3 0170 00000 00000 3 0170 over 1 11,148 9 5930 0 0000 1 6698 0.0000 0 1.9922 00000 5 9t56 0 0000 00000 59158 (0.12261 Winier 0*1 1.474 4 8866 00000 36772 00000 0 3 9140 0 0000- 3 0170 00000 00000 (0.2368) over 1 19,898 3 0170 1.8698 00000 0 8 4588 0 0000 00000 5 2059 00000 19922 (0.1228)

Energlf Ch1rge1 00000 5 2059 3.2529 0.0000 0 3.4521 (0.19921 All Use-x nighl use 8.373,400 8 2580 1 1768 00000 0 4113 4 0623 1 0069 6 6573 16007 NighlUse 42.782 7 1281 t t766 0 0000 4 0623 340, 153 1.8007 Totals 04113 4 0623 10089 8 6573 0.4708 8,416, 182 4 0823 1,738 0.4708 S.44 457,9t6 Monthly Minimum, MD Specl1I Annual Minimum Special Provisions Slandby 2 000 3 8600 0 0000 0 1800 2 6900 0 7600 0 0000 3 6500 00100 09600 2 Area Dev Svc Cr Yrs 1*5 357 (2 8500) 0 0000( 0 0000 (2 8500) 00000 00000 12 8500) 0 0000 Area Dev Svc Cr Yrs 6&7 00000 0 Curl Elec Svc Cr Curl. Elec Svc Peak Cr Police/Fire-Each Pollce/Flre*Minimum HS Entrglf Ch1rg11 Summer 4.206 14 2788 11768 0 4217 Winier 5 7533 5 5159 10069 13 6746 04042 23,047 11 0427 1.1768 0.4217 5 8376 250 Totals 4 4178 3 9490 10069 10.9722 0.0705 27,253 4.3707 1,007 4.111 1,257

2002b Unbundled Ra Detail bill dei. Subtotal Prellmn. Shopping ShpCr MTC Adj 2002 Rate SBC/NTC Trans Dist BGS STC Subtotal MTC Credi! Revenue ObllgAdJ. MT.C Ill 121 Ill 141 151 161 f7I 8=1um 3.7 (9=2-8) (10 .. 4*6) 111 ..1*101 (121 (131 LPL-Secondary Service Charge 79 820 368 64 0 00 0 00 J68 64 0 00 0 00 368 64 0 0 0 C11p11clty Dbllgallon 27 324 0 0000 0 0000 0 0000 0 0000 J 0917 0 0000 3 09t7 fJ 0917) 3 0917 84,478 Transmission Obllgallon 22.992 0 0000 0 0000 I 5961 0 0000 0 0000 00000 1 5961 (I 596t) 1 5961 36,698 Demand Charges 0 0000 0 0000 00000 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 0 Summer On 9.014 8 7556 0 0000 0 0000 4 1045 0 0000 00000 4 1045 4 6511 0 0000 0 4 3809 0.2702 Inter 6.609 11660 0 0000 0 0000 0 5336 0 0000 0 0000 0 5336 06324 00000 0 0 5827 00497 OH 8,413 1 1660 0 0000 0 0000 0 5336 0 0000 0 0000 0 5336 06324 00000 0 0 5827 0 0497 Winier On 15.297 7 6108 0 0000 00000 3 5710 00000 0 0000 3 5710 4 0398 0 0000 0 3 8070 02328 Inter 11.523 I 1660 00000 00000 0 5336 0 0000 0 ODDO 0 5336 06324 00000 0 0 5827 0.0497 OH 13.702 1 1660 0 0000 00000 0 5336 00000 0 0000 0.5336 06324 0.0000 0 0.5827 0.0497 Energy Charges On 5.570,349 8 3301 I 1768 00000 0 3191 4 7815 1 0069 7 2843 1 0458 4.7815 266,346 1 0458 Inter 744.848 7 3019 I 1768 0 0000 0 3191 4 1612 1 0069 6 6640 06379 4 1612 30,995 08379 OH 4 325 488 5 6706 I 1768 0 0000 0 3191 2 5431 I 0069 5 0459 0 6247 2 5431 110,001 .0.8247 Totals I0.640.685 4.97 528,518 Special Annual Minimum LPL-Primary Service Ch1rge 11 459 368 64 0 00 0 00 368 64 000 000 368.64 0 0 0 0 ODD 9 4800 D 0000 0 ODDO 9 4800 D ODDO 00000 94600 0 ODDO 0 0000 0 C1paclty Obllgallon 10 044 0 DODO 0 0000, 0 0000 0 0000 3 0917 00000 3 0917 13 0917) 3 0917 31,053 Tran1ml11lon Obllgatlon 8.460 0 0000 0 0000 I 5961 0 0000 0 0000 00000 15981 (15961) 1 5961 13,503 Dem1nd Ch1rges 00000 00000 0 0000 0 0000 00000 00000 00000 0 ODDO 0 ODDO 0 Summer On 3.202 8 5648 0 0000 0 0000 3 1337 DODOO 00000 3 1337 5 4311 00000 D 4 4904 09407 Inter 2 348 I 0494 0 0000 00000 0 3761 DODOO 0 0000 0 3761 D 6733 00000 0 0 5523 0 1210 OH 2.988 I 0494 0 0000 0 0000 0 3761 0 0000 00000 0 3781 0 6733 00000 0 0 5523 0 1210 Winier On 5.637 7 4306 00000 00000 2 7264 0 0000 0 0000 2 7264 4 7042 0.0000 0 3 8977 06065 lnler 4.314 I 0494 00000 00000 0 3761 0 0000 00000 0 3781 06733 00000 0 0 5523 01210 OH 5,208 1 0494 00000 0 ODDO 0 3761 00000 0.0000 0.3761 06733 0.0000 0 0.5523 0 1210 Energ11 Ch1rge11 On 2.105.732 7 5844 I 1222 0 0000 0 3053 4 5509 1 0069 6 9853 0 5991 4 5509 95,830 05991 Inter 294.802 66081 I 1222 0 0000 0 3053 3 9662 1.0069 64006 02075 39662 11,692 02075 OH 1.810.929 5 6488 I 1222 00000 0 3053 2 4345 1.0069 4 8669 0 7799 2.4345 44,087 0.7799 Tol1l1 4.211,463 4.611 196,165 Specl1I Annu1I Minimum Specl1I Provl1lon1-LPL Slandby-Sec. 29 3 8600 0 DODO D 1600 2 6300 08500 00000 3 8600 (0 0000) I 0300 30 Standby* Prl. 38 2 7300 0 ODDO 0 1800 16900 0 8700 00000 2.7400 (0.0100) 1 0500 40 70 "'C1>

Area Dev Svc Cr Yrs 1*5-Sec 1, 158 12 6500) 0 0000 0 0000 (2 8500) 00000 00000 12 8500) 0 ODDO 0 0000 0

>~

~>

Area Dev Svc Cr Yrs 1-5-Prl 300 00000 00000 0 0000 00000 00000 00000 00000 00000 0 0000 0 Curl Elec Svc Cr Curl Elec. Svc Peak Cr IES Cr 2 Hr. Nie -Sec IES Cr 30 Min Nlc.-Sec IES Cr 2 Hr. Nie -Prl.

36 99 0

13 2900)

(4 5300)

(3 2900) 0 0000 00000 0 0000 00000 0 0000 0 DODO 0 0000 0 0000 00000 fl f4 (3

2900) 5300) 2900) 00000 00000 DODOO (3

(4 (3

2900) 5300) 2900) 00000 0 0000 00000 (3

(4 (3

2900) 5300) 2900) 1118) 1448)

D tH tH o~

=

n "Tj tTJ 75 (4 5300) 0 DODO 00000 00000 (4 5300) 0.0000 (4 5300)

~ 2!

IES Cr. 30 Min Nie -Pri DODOO 14 5300) 1340)

IES Chg 2 Hr. Nie. (906)

IES Chg 30 Min Nie 1-i N

blll det. Sublolal 2002b Unbundled Rah:.

Detall Prellmn. Shopping ShpCr MTC

• AdJ 2002 Rate SBC/NTC Trans Dist BGS STC Subtotal MTC Credll Revenue ObllgAdJ. MT.C (ti (21 131 (41 (SJ (61 171 8=aum 3-7 19=2-I) (10=4+6) 111=1*101 (121 (13)

HTS-Sublrans Service Charge 2 214 2.026 07 0 00 0 00 2.026 07 0 00 0 00 2,026'°7 0 0 0 Capacity Obllgallon 7.915 0 0000 0 0000 0 0000 0 0000 3 0917 0 0000 3 0917 (3 0917) 3 0917 24.471 Transmission Obllgallon 6.668 0 0000 0 0000 1 5961 0 0000 0 0000 0 0000 1 5961 (1 59611 1 5981 10,843 Demand Charges 0 0000 0 0000 0 0000 0 0000 0 0000 00000 0 0000 00000 0 0000 0 Summer On 2.817 10 4834 0 0000 0 0000 1 3031 00000 0 0000 I 3031 91803 00000 0 4 5234 4 8569 lnler o onoo 0 0000 0 0000 0 0000 0 0000 00000 00000 00000 00000 0 00000 00000 Off 0 0000 00000 0 0000 0 0000 00000 0 0000 00000 00000 0.0000 0 0 0000 00000 Winier On 5.417 9 5718 00000 0 0000 1 1858 0 0000 00000 t 1858 8 3880 00000 0 4 1299 4.2581 Inter 0 0000 0 0000 0 0000 0 0000 00000 00000 00000 00000 00000 0 00000 00000 OH 00000 0 0000 0 0000 00000 0 0000 00000 0.0000 00000 00000 0 00000 0.0000 Energy Charges On I 563 654 6 8360 I I060 0 0000 0 2226 4 4293 1 0069 6 7648 0 0712 4 4293 69,259 0.0712 lnler 279 146 5 8651 I 1060 0 0000 0 2226 3 8565 I 0069 8 1920 (0 32691 3 8565 10,765 co 3289)

Off I 595 800 5 0902 I I060 00000 0 2226 2 3518 I 0069 4 6873 0 4029 2 3518 37,530 04029 Tolals J.438.600 4.44 152,868 Speclal Annual Minimum HTS-High Voltage Service Charge 0 110 1en47 0 00 0 00 I 82147 0 00 0 00 1,823 47 0 0 0 Capacity Obllgatlon 689 0 0000 0 0000 '* 0 0000 0 0000 3 0917 0 0000 3 091'7 (3 0917) 3 0917 2.130 Transmlsslou Obllgallon 580 0 0000 0 0000 I 5961 0 0000 00000 00000 I 5961 (159611 1 5961 926 Demand Charges 0 0000 0 0000 0 0000 0 0000 00000 0 0000 0 0000 0 0000 0 0000 0 Summer On J24 9 4351 0 0000 0 0000 I 1728 0 0000 00000 I 1728 8 2823 00000 0 3 4372 4 8251 lnler 0 0000 0 0000 0 0000 0 0000 0 0000 0 0000 00000 00000 00000 0 00000 00000 Off 0 0000 0 0000 00000 0 0000 0 0000 00000 0 0000 00000 00000 0 00000 00000 Winier On 619 8 6146 0 0000 0 0000 I 0686 0 0000 00000 1 0688 7 5480 00000 0 3 1382 4 4078 Inter 0 0000 0 0000 0 0000 0 0000 00000 0 0000 0 0000 00000 00000 0 0 0000 00000 Off 0 0000 0 0000 0 0000 0 0000 0 0000 0.0000 00000 0.0000 0.0000 0 00000 00000 Energy Charges On 190.028 6 0612 1 0796 00000 0 2226 4 3286 1 0069 68377 (0 5565) 4.3286 8,226 (0 5565) lnler 25.842 5 2078 1 0796 00000 0 2226 3 7694 1 0069 8 0785 (0 8707) 3 7694 974 (0 8707)

• • Off 157.882 4 5103 I 0798 0 0000 0 2226 2 3013 1 0069 4 8104 (0.1001) 2.3013 3.633 (0 1001)

Totals 373,752 4.25 15,889 Specl1I Annual Minimum Specl11I Provisions-HTS Slandby* Sublrans 410 1 3900. 00000 0 1700 0 3200 0 9000 0 0000 13900 00000 1 0700 439 Slandby* High Voltage 208 12500 00000 0 1500 0 2900 0 8200 00000 12600 1001001 0 9700 202 ~>

841

>::1

~>

Area Dev Svc Cr Yrs 1-5-Sub 70 (1 9000) 00000 0 0000 (1 90001 0 0000 0 0000 (I 90001 00000 0 0000 0 Area Dev Svc Cr Yrs 1-5-HV 49 0 0000 0 0000 00000 0 0000 0 0000 0 0000 0 0000 00000 0 0000 0 Curt Elec Svc Cr ~ (1

~

Curt Elec Svc Peak Cr o~

==

IES Cr 2 Hr. Nie -Sub 312 (3 29001 0 0000 00000 0 0000 (3 2900) 0 0000 (3 2900) 0 0000 (3 2900) ( 1.026)

IES Cr 30 Min Nie -Sub 319 (4 5300) 00000 00000 00000 (4 53001 00000 (4 5300) 0 0000 (4 5300) (1.4451 "1'1M IES Cr. 2 Hr. Nlc.-HV 0 (3 2900) 0 0000 0 0000 0 0000 (3 2900) 00000 (3 2900) 00000 (3 2900) 0 ~~

IES Cr. JO Min Nie -HV 779 (4 5300) 00000 00000 0 0000 (4 5300) 0 0000 (4 5300) 0 0000 (4 5300) (3 529) ~

IES Chg 2 Hr. Nie (6.000) ....,

IES Chg 30 Min Nie

_2002b Unbundled Rah Dela II bill det. Sublolal 2002 Rale SBC/NTC Prellmn. Shopping ShpCr MTC Trans Dist BGS STC Adj Subtotal MTC Credi! Revenue Obllg Adj.

111 121 Ill (41 (51 (6) 171 8a1rnm 3-7 "'lC (9"2-8) (10=4+6) (11=1"10) (12)

BPL (13) 317.218 17 3645 1 1768 0 0000 10 8033 2 9142 1 0069 15 9012 1 4633 317.218 2 9142 9.244 2.91 9,244 PSAL 159,749 21 8663 1 1768 0 0000 13 4248 2 9142 159.749 1 0069 18 5227 3 3436 2 9142 4.655 2.91 4,655

200] Unbundled Rale

• Delail bill del. Sublolal Prellmn. Shopping ShpCr MTC Adj 2003 Rale SBC/NTC Trans Dis I BGS STC Sublolal MTC Crecllt Revenue. ObllgAdJ. '9\tC Ill 121 Ill (4) (5) (61 171 8=11um 3-7 19=2*81 110=4+61 lt1=1*101 c121 (131 RS Service Charge 20.965 2]6 2 41 0 00 0 00 2 41 0 00 0 00 241 0.00 000 0 Energy Charges 0-600 8.605.JJ7 11 6967 1 1768 0 6533 3 3317 5 1524 0 9969 11 3111 0 3856 58057 499.600 Over600 Sum 1.562.815 13 1595 1 1768 .o 6533 3 7368 6 0600 0 9969 12 6238 0 5357 6 7133 104.916 Over600Win 1.225.118 II 1179 1 1768 0 6533 3 1581 4 4989 0 9969 10 4840 06339 5 1522 63, 121 Tol1l1 11.393.270 5.116 667,637 RHS Service Charge 0 000 Energy Ch1rg11 0-600 0 Over600 Sum 0 Over 600Win 0 Common 0 Tol1l1 0 RLM S11rvlc11 Ch1rg11 58 236 12 12 0 00 0 00 12 12 000 000 1212 000 *o oo 0 Service Ch1rge over 20,000 118 236 6 79 0 00 0 00 6 79 0 00 0 00 6 79 000 0.00 0 Service Ch1rge Sp. Prv. (II Energy Ch11rg111 SufTlmer On 57 547 17 6761 1 1768 '* 0 5410 3 8067 7 5954 0 9969 14 1168 3 5593 8 1384 4,682 ln1er 10.790 16 1519 I 1768 0 5410 3 2810 6 5090 0 9989 12 5047 3 6472 7.0500 761 Olf 51.553 6 3532 I 1768 0 5410 1 2484 3 8574 0 9969 7 8205 11 46731 4.3984 2,266 Winier On 76.528 12 0878 1 1768 0 5410 2 6502 4 8665 0 9969 10 2314 1 6564 54075 4, 1311 tnler 15.653 12 3072 I 1768 0 5410 2 5100 4 5354 09989 9 7601 2 5471 50764 795 Olf 81.746 6 3532 I 1768 0 5410 I 2484 3 5335 09969 7.4966 (1.14341 4.0745 3,331 Tol1l1 293,817 5.44 15,975 WH Energy Ch1rg1 5.947 10 2021 I 1768 00000 5 3229 2 5075 0 9969 10.0041 0.1960 2.5075 149 Tol1l1 5,947 2.lt 149 WHS Service Ch1rge 0 851 2 82 0 00 0 00 2.82 0.00 0.00 2.82 0.00 0.00 0000 Energy Ch1rg1 143 5 4596 1 1768 0 0000 1.5646 ~ 5099 0.9969 6.2484 10.7888) 2 5099 3 589 Tol1l1 143 2.51 3.589 STC, preliminary values, adjusted at least annually.

blll det.

2003 Subtotal Rate SBCINTC 2003 Unbundled Rate.

Trans Detail Dist BGS STC Prellmn. Shopping ShpCr MTC Adj .

Subtot;il MTC Credit Revenue ObllgAdJ.

111 (2) 131 (4) (51 (6) (7) B"sum 3-7 (9*2-1) (10,,4+61 (11*1°101 MTC GLP (121 (131 Service Charge 2.900 104 4 04 0 00 000 4 04 000 0 00 4 04 0 *o Service Charge- Night Use 0 864 367 08 0 00 000 0 367 08 0 00 0.00 367 08 0 Capaclly Dbllgallon 26.484 00000 0 0 0 0000 0 0000 00000 3 t800 0 0000 31800 Transmission Obllgatlon 22.296 (318001 3 1800 84.219 0 0000 0 0000 1 5961 0 0000 00000 00000 Demand Charges 1 5961 (1 5981) 1 5981 35,587 0 0000 0 0000 0 0000 00000 00000 00000 Summer 0-1 00000 00000 0 0000 0 744 4 6866 0 0000 0 0000 3 0170 0 0000 00000 3 0170 1 8698 0 0000 0 over I 11.302 9 5930 0 0000 0 0000 5 9158 20288 (0 1590) 0 0000 00000 5 9158 38772 0.0000 Winier 0-1 1,495 4 8866 0 0000 0 0000 0 3 9855 (030831 3 0170 0 0000 00000 30170 18696 00000 over 1 19,976 8 4588 0 0000 00000 0 2 0286 ,(0 1590) 5 2059 00000 0.0000 52059 32529 0.0000 Energv Charges 0 3.5152 (0.2823)

All Use** nighl use 8,496.54 I 8 2580 1 1768 0 0000 0 4113 4 0319 09969 86169 1 6411 4 0319 N1ghl Use 37.060 7 1281 1 1768 00000 342,572 18411 0 4113 4 0319 09969 88169 0 5112 Totals 8 533 601 4 0319 1.494 0.5112 5.44 483,872 Monlhlv Minimum, MD Speclal Annual Minimum Speclal Provisions Slandby 2 000 J 8600 0 0000 0 1800 2 8900 0 7800 0 0000 3 6500 00100 0 9600 2 Area Dev Svc Cr Yrs 1.5 JSI (2 85001 0 0000. 0 0000 (2 8500) 0 0000 0 0000 (2 8500) 00000 Area Dev Svc Cr Yrs 6&7 00000 0 Curt Elec Svc Cr Curt Elec Svc Peak Cr Police/fire-Each Police/Fire.Minimum HS Energv Charges Summer 4.047 14 2788 1 1768 0 3652 5 7533 5 4005 0.9969 13 6927 0 5861 Winier 22.176 11 0427 1 1768 5 7657 233 0.3652 4 4178 3 8499 09969 10.8066 0 2361 Total1 26,223 4 2151 935 4.45 1,188

2003 Unbundled Rat Detail bill del. Sublolal Prellmn. Shopping ShpCr MTC AdJ 2003 Rate SBCINTC Trans Dlsl BGS STC Subtotal l'JITC Credll Revenue ObllgAdJ. MTC 111 (21 Ill (41 (51 (61 171 8=sum 3.7 19=2*111 110=4+61 1tt*1*101 1121 (131 LPL-Secondary Service Charge 80 638 368 64 0 00 0 00 368 64 0 00 0 00 368.64 0 0 0 Capacity Obllgallon 27.660 0 0000 0 0000 0 0000 0 0000 3 1800 0 0000 3 1800 (3 18001 3 1800 87,959 Transmission Obllgatlon 23.280 0 0000 0 0000 I 5961 0 0000 0 0000 00000 1 5961 (1 5961) 1 5961 37,157 Demand Charges 0 0000 0 0000 00000 0 0000 0 0000 0 0000 0 0000 0 0000 00000 0 Summer On 9, 146 8 7556 0 0000 0 0000 4 1045 00000 o oooci 4 1045 4 6511 0 0000 0 4 4603 0 1908 lnler 6.708 1 1660 0 0000 00000 0 5336 0 0000 0 0000 0 5336 0 8324 00000 0 0 5932 00392 011 8.536 1 1660 00000 0 0000 0 5338 00000 00000 0 5338 08324 00000 0 0 5932 00392 Winier On 15.508 1 6108 0 0000 00000 3 5710 00000 0 0000 3 5710 4 0398 00000 0 3 8780 0 1838 lnler 11.682 1 1660 00000 0 0000 0 5336 0 0000 0 0000 0 5338 08324 0.0000 0 0 5932 00392 011 13,891 1 1660 0 0000 00000 0 5338 00000 00000 0 5338 0.8324 0.0000 0 05932 0.0392 Energr ChargH On 5,653,467 8 3301 I 1768 00000 0 3191 4 7546 0 9969 7 2474 1 0827 4 7548 288,800 1.0827 lnler 755.962 1 3019 1 1768 0 0000 0 3191 4 1408 0 9989 88338 06883 4 1408 31.303 06883 011 4.390.031 5 6706 I 1768 00000 0 3191 2 5395 0 9989 5 0323 0.6383 2 5395 111,485 0.8383 Totals 10.799.460 4.97 538,704 Speclal Annual Minimum LPL*Prlmary Service Charge I I 544 368 64 0 00 0 00 368 64 0 00 000 368 64 0 0 0 0 000 9 4800 0 0000 0 0000 9 4800 0 0000 00000 94800 00000 00000 0 Capacll)' Obllgallon 10I16 0 0000 0 0000 ' 00000 0 0000 3 1800 00000 3 1800 (3 1800) 3 1800 32,169 Transml111lon Obllgallon 8.520 0 0000 0 0000 I 5961 0 0000 00000 00000 1 5961 (1 5981) 1 5981 13,599 Demand Ch1rg11 0 0000 00000 0 0000 0 0000 00000 00000 00000 00000 00000 0 Summer On 3 233 8 5648 00000 0 0000 3 1337 0 0000 00000 3 1337 54311 00000 0 4 5701 0.8610 lnler 2.370 I 0494 0 0000 00000 0 3761 00000 00000 0 3761 06733 00000 0 0 5621 0 1112 OH 3 017 I 0494 0 0000 00000 0 3761 0 0000 OOODO 03781 0 6733 DODOO 0 0 5621 0.1112 Winier On 5.688 7 4306 00000 0 0000 2 7264 00000 00000 2 7264 4 7042 0.0000 0 3 9888 0 7374 lnler 4,354 I 0494 00000 0 0000 0 3781 00000 00000 0 3781 08733 00000 0 05821 0 1112 011 5.255 I 0494 0 0000 00000 0 3781 0 0000 0.0000 0.3761 06733 0.0000 0 0.5621 0.1112 Energr Charges On 2.126.097 1 5844 I 1222 0 0000 0 3053 4 5259 09969 6 9503 06341 4 5259 96,225 06341 lnler 297,654 6 6081 1 1222 00000 0 3053 3 9473 0 9969 8 3717 02364 3 9473 11,749 0 2384 011 1,828.443 5 6488 1 1222 00000 0 3053 2.4318 09969 4 6580 0.7928 24316 44,460 0.7928 Totals 4,252, 194 4.1111 196,202 Sp1cl1I Annual Minimum Speclal f1rovl1lon1-LPL Standby-Sec. 29 3 8600 0 0000 *01800 2 8300 0 8500 DODOO 3 8600 (0 0000) 1 0300 30 Standby- Pri. 38 2 730D 00000 0.1800 1.6900 08700 00000 2 7400 (0.0100) 1 0500 40 70 A1ea Dev Svc Cr Yrs 1-5-Sec 1,158 12 85001 0 0000 00000 (2 85001 0 0000 00000 (2 85DOI 0 0000 00000 0 ~>

A1ea Dev. Svc Cr Yrs 1-5-Pri 300 0 0000 00000 OOOOD 00000 00000 0 0000 00000 00000 00000 0 > :I

~>

Curt Elec Svc Cr Curt Elec Svc Peak Cr t,,.t n IES Cr 2 Hr. Ntc.-Sec IES Cr. 30 Min Nlc .. sec IES Cr 2 Hr. Ntc -Pri.

IES Cr 30 Min Nie -Pri 36 99 0

75 (3

(4 (3

(4 29001 53001 2900) 53001 00000 00000 0 0000 00000 00000 00000 00000 00000 0 0000 00000 00000 00000 (3

(4 (3

(4 29001 53001 2900) 5300) 0 ODOD 0 0000 00000 0 0000 (3

(4 (3

(4 290DI 53001 2900) 5300)

DODOO 0 0000 00000 0 0000 (3

(4 (3

(4 2900) 5300) 2900) 5300)

(118)

(448) 0 (340) 00

~~

=

IES Chg 2 Hr. Nie. (906) ~ 'Z IES Chg 30 Min Nie o~

tJ

2003 Unbundled Rah Dela ii bill det.* Subtotal Prellmn. Shopping ShpCr MTC AdJ 2003 Rate SBCINTC _ Trans Dist BGS STC Subtolt1I MTC Credll Revenue Obllg.AdJ. MTC (fl 121 Ill (41 151 161 (7) ll=sum 3-7 (9'"2*81 (10 .. 4+6) (11*1°10) (12) 113)

HTS-Subtrans Service Charge 2 225 2.026 07 0 00 0 00 2.026 07 0 00 ODO 2.026 07 0 0 0 Capacity Obllgatlon 7.762 0 0000 0 0000 0 0000 0 0000 3 1800 00000 3 1800 (3 1800) 31800 24.683 Transmission Obligation 6.535 0 0000 0 0000 1 5961 0 0000 0 0000 0 0000 1 5961 (1 5961) I 5961 10,431 Demand Charges 00000 0 0000 0 0000 0 0000 0 0000 00000 00000 0 0000 00000 0 Summer On 2.784 10 4834 0 0000 0 0000 1 3031 0 0000 0 0000 I 3031 9 1803 00000 0 4 5773 .. 6030 lnler 0 0000 0 0000 0 0000 0 0000 0 0000 00000 0.0000 00000 00000 0 00000 0.0000 Oii 00000 00000 0 0000 0 0000 00000 00000 0 0000 0 0000 0 0000 0 00000 00000 Winier On 5.353 g 5718 0 0000 0 0000 1 1858 0 0000 00000 11858 8 3860 00000 0 4.1791 4 2089 ln1er 00000 0 0000 00000 0 0000 0 0000 00000 00000 00000 00000 0 DODOO 00000 011 0 0000 00000 00000 0 0000 00000 Q.0000 00000 0 0000 0.0000 0 0.0000 0.0000 Energ11 Charges On 1.536.391 6 8360 1 1060. 0 0000 0 2226 4 4012 09969 8 7267 0 1093 4 4012 67,820 0 1093 ln1er 274 279 5 8651 1 1060 0 0000 0 2226 3 8344 0 9969 6 1599 (0 2948) 3 8344 10,517 *10 2948) 011 1.567 977 5 0902 1 1060 0 0000 0 2226 2 3454 09969 4 6709 04193 2 3454 36.775 0.4193 Totals 3,378,64 7 ........ 150,026 Speclal Annual Minimum HTS-High Voltage Service Charge 0 171 1 823 47 0 00 0 00 1_823 47 0 00 0 00 1.823.47 0 0 0 Capacity Obllgatlon 674 0 0000 0 0000 ( 0 0000 0 0000 3 1800 0 0000 3 1800 (3 1800) 3 180D 2.143 Tr1nsmlulon Obllgatlon 569 D ODDD D 0000 1 5961 0 0000 DDOOD D DODO 1 5961 (I 5961) 1 5961 9D8 Demand Ch1rges 0 DDOO 0 0000 0 0000 0 0000 0 0000 DODDD OOODD 0 DOOD D.0000 0 Summer On 321 9 4351 0 0000 0 0000 I 1728 00000 00000 I 1728 8 2623 OOOOD 0 3 4718 4 7905' lnler 0 0000 00000 0 0000 00000 00000 0 0000 DODOO DODOO 0.0000 0 00000 00000 011 0 0000 0 0000 0 0000 00000 OOODD ODOOD 0 0000 0 0000 00000 0 ODDOO 00000 Winier On 611 8 6146 0 0000 00000 1 0686 0 0000 DODOO 1 0686 7 5460 0 DODO D 3 1898 4 3762 Inter OOOOD 0 0000 0 0000 D DOOO D 0000 00000 DODOO DODOO DODOO D OOOOD 00000 011 0 0000 0 0000 0 0000 0 0000 0 OOOD 00000 00000 0.0000 OOOOD 0 0.0000 0.0000 Energ11 Ch1rges On 186.715 6 0812 1 0796 D ODDD 0 2226 4 3013 0 9969 66DD4 (0 5192) 4.3D13 8,031 (0 51921 Inter 25.391 5 2D78 1 D796 0 OOOD 0 2226 3 7480 09989 6 0471 (D 8393) 3 748D 952 (D 8393) 011 155.129 4 5103 1 D796 0 DOOO 0 2226 2 2951 D9969 4 5942 (D D839) 2.2951 3,56D (D 0839)

Tot1l1 367,235 4.25 15,594 Specl1I Annual Minimum Speclal Provl1lon1-HTS S1andblf* Sublrans 410 1 3900 D DDDD D 17DD D 3200 D 9000 00000 13900 0 DODO 1 D700 439 Standb11* High Voltage 208 1 250D DOOOO D.1500 0 2900 0 8200 00000 12600 (00100) 0 9700 202 ~>

841

>~

~>

Area Dev Svc Cr. Yrs 1-5-Sub 70 (I 9000) 0 0000 00000 (1 900D) 0 0000 00000 (1 9000) 0 0000 00000 0 Area Dev. Svc Cr Yrs 1-5-HV 49 OOOOD 0 0000 00000 0 0000 0 0000 00000 0 0000 00000 00000 0

=

Curt Elec Svc Cr wt'")

Curt Elec. Svc Peak Cr IES Cr 2 Hr. Nie -Sub 312 (3 2900) 00000 o oiloo 0 0000 13 2900) 00000 (3 2900) 00000 (3 2900) (1.026) oa;:

'O IES Cr 30 Min Nie -Sub 319 (4 5300) 0 0000 0 0000 0 0000 (4 5300) 00000 (4 5300) 00000 (4 5300) (1.445) "11 ~

IES Cr 2 Hr. Ntc.-HV 0 (3 2900) 0 0000 0 0000 0 0000 (3 2900) 00000 (3 2900) DODOO (3 29001 0 ~ '.-2!

IES Cr 30 Min Nie -HV 779 (4 5300) 0 0000 0 ODDO D ODDO (4 5300) 00000 (4 5300) 00000 (4 5300) (3.5291 o"'-i IES Chg 2 Hr. Nie. (6.000)

N IES Chg 30 Min Nie

t

• • blll det.

2003 111 Subtotal Rate 121 SBC/NTC Ill 2003 Unbundled Rall Trans 141 Dela II Dist BGS STC Subtotal Prellmn.

MTC Shopping credll ShpCr Revenue MTC ObllgAdJ.

AdJ rue 151 161 171 fla11um 3-7 (9*2*111 (10=4+61 (11 .. 1*101 (12) 1131 BPL 320.726 17 3645 1 1768 00000 10 8033 2 8958 0 9969 15 8728 1 4917 320.726 2.8958 9.288 Z.90 9,288 PSAL 163.538 21 8663 1 1768 0 0000 13 4248 2 8958 0 9969 18.4943 3 3720 163.538 2.8958 4.738 2.110 4,738

ATTACHMENT 3 PAGE 1 OF2 Asset Schedule by FERC Account FERC Account Description Steam Production 311 Structures and Improvements Plant 312 Boiler Plant Equipment 313 Engines and Engine-Driven Generators 314 Turt>ogenerator Units 315 Accessory Electric Equipment 316 Miscellaneous Power Plant Equipment Other Production 341 Structures and Improvements Plant 342 Boiler Plant Equipment 343 Engines and Engine-Driven Generators 344 Turt>ogenerator Units 345 Accessory Electric Equipment 346 Miscellaneous Power Plant Equipment Hydro Production 331 Structures and Improvements Plant 332 Boiler Plant Equipment 333 Engines and Engine-Driven Generators 334 Turt>ogenerator Units 335 Accessory Electric Equipment 336 Miscellaneous Power Plant Equipment Nuclear Production 321 Structures and Improvements Plant 322 Boiler Plant Equipment 323 Engines and Engine-Driven Generators 324 Turt>ogenerator Units 325 326

- Accessory Electric Equipment Miscellaneous Power Plant Equipment Step-up Transformers 353 Step-up Transformers Start-up Transformers Start-up Transformers Land 310-340 Land and Land Rights Fuel & Materials 151-156, 163 Materials and Supplies {Fuel Stock and Other Materials) 120.1-.6, 157 Nuclear Fuel Materials Generation-Related FERC# General Equipment Common Plant

ATIACHMENT 3 PAGE20F2 Asset Schedule Unit Unit Fossil ~ Bergen 1 Peaking Bayonne 1 Burlington 7 Bayonne 2 Burlington 10 Bergen 3 Hudson 1 Burlington 8 Hudson 2 Burlington 9 Kearny 7 Burlington 11 Kearny8 Conemaugh A (DG)

Linden 1 Conemaugh B .

(DG)

Linden 2 Conemaugh C (DG)

Mercer 1 Conemaugh D (DG)

Mercer 2 Edison 1 Sewaren 1 Edison 2 Sewaren 2 Edison 3 Sewaren 3 Essex 9 Sewaren 4 Essex 10 Conemaugh 1 Essex 11 Conemaugh 2 Essex 12 Keystone 1 Hudson 3 Keyston~ 2 Kearny 9 Kearny 10 Nuclear Hope Creek Kearny 11 Salem 1 Kearny 12 Salem 2 Keystone 3 (DG)

Peach Bottom 2 Keystone 4 (DG)

Peach Bottom 3 Keystone 5 (DG)

Keystone 6 (DG)

Linden 3 Linden 5 Generation Related Central Maintenance Linden 6 Assets System Maintenance Linden 7 Testing Lab Linden 8 Step-up Transformers Mercer 3 Start-up Transformers National Park 1 Land Salem 3 Fuel & Materials Sewaren 6 General Plant Yards Creek 1 Future Societal Yards Creek 2 Benefits receivable Yards Creek 3 (Account 130) for nuclear decommissioning pursuant to Section 12(a)(2) of the Act

ATTACHMENT 4 GENERATION FIXED TRANSFER VALUE

$5,068 Net After Tax Book Value (3,300) Stranded Cost

$1,768* Transfer Value 600 MTC

$2,368 Amount Paid by Genco to PSE&G

• Plus Generation-Related Assets, including Nuclear Fuel and Materials & Supplies at Book Value.

ATTACHMENT 5 OFF-TARIFF RATE AGREEMENTS APPROVED OR PENDING AS OF MARCH 3, 1999 APPROVED PSE&G OTRA 96-1 Circuit Foil PSE&G OTRA 96-2 Ford PSE&G OTRA 96-3 Merck PSE&G OTRA97-l Ball Plastic PSE&G OTRA 97-2 Aluminum Shapes PSE&G OTRA 97-3 BASF PSE&G OTRA 97-4 Camden Iron PSE&G OTRA 97-5 Amerada Hess PSE&G OTRA 97-6 Passaic Valley Sewerage Commission PSE&G OTRA. 97-7 Johnson & Johnson PSE&G OTRA 97-8 Union Carbide PSE&G OTRA 97-9 Port Authority Transit Corporation PSE&G OTRA 98-1 Nabisco PSE&G OTRA 98-2 Passaic Valley Sewerage Commission One year extension of OTRA 97-6 PENDING PSE&G OTRA 98-3 Marcal PSE&G OTRA 99-1 .Garwood Paper PSE&G OTRA 99-2 Daily News PSE&G OTRA 99-3 Huntsman

ATTACHMENT 6 PAGE l OF 19 NEW AND REVISED SECTIONS OF THE STANDARD TERMS AND CONDITIONS

• AND ASSOCIATED RATE SCHEDULES OFPSE&G'S TARIFF FOR ELECTRIC SERVICE

ATTACHMENT 6 PAGE 2OF19 FEBRUARY l, 1999-CAPACITY & ENERGY (NET BACK)

IS. THIRD PARIY SUPPLIER SERVICE PROVISIONS IS.I. Alternate Electric Supply: Customers served on any of the applicable rate schedules of this Tariff for Electric Service and who desire to purchase their electric supply of capacity, uanmrission, and energy, hereinafter referenced as electric supply, from a third pany supplier must execute an authorization form. Authoriz.ation forms are included inc the enrollment package described in Section 15.1.1. Customers who are not cmolled with a third party supplier will continue to receive their electric supply from Public Service. The customer may act as a third party supplier for his account if they meet all of the requirements of Section 15.1.2.

• IS.I.I. Enrollment: *customers may request an emollment package from Public Service which in addition to providing general information regarding electric supply, describes thi:

process necessary for a eustomer to obtain a third party supplier of electric supply. This enrollment package will be provided to the customer at no charge and may be obtained by calling or writing Public Service or visiting a Customer Service Center. Once the customer has chosen a third pany supplier, the customer must execute the authorization form contained in the enrollment package, noting the name of the third pany supplier.

Upon written request of the customer, Public Service will provide customer usage information to any number of third pany suppliers at a rate ofS2.00 per copy, billable to the customer.

15.I.2. Third P21't}- Supplier: A third pany supplier is a retail energy and capacity provider that has executed a Third Parry Supplier Master Service Agreement with Public Service so as to be eligible to furnish electric supply with delivery to the retail customer by Public Service. This Agreement requires that the third pmy supplier satisfy the creditworthiness standards of Public Service, be licensed by the Board of Public Utilities and any other appropriate New Jersey state agencies, and satisfy any and all other legal requirements necessary for parncipation in the New Jersey retail energy market. By determining a third party supplier credit wonhy. Public Service makes no express or implied warra.nnes or guarantees of any kind with respect to the financial or operational qualifications of such third parry supplier.

15.2. Initiation of Service: In order to be eligible to receive electric supply from a third pany supplier. the customer must contract with a third party supplier to obtain electric supply for delivery to the customer by Public Service. Delivery of electric supply to retail customers will be provided tn accordance with the terms of the Third Party Supplier Master Service Agreement. The customer is required to notify Public Service of its initial choice of third party supplier of electric supply as well as any subsequent changes in third pany supplier, through the use of the authoriz.ation form included in the enrollment package. lninanon of service will become effective on the customer's next scheduled meter reading date that ts at least fifteen (IS) days following the receipt of the authorization form by Public Service. Such selection shall remain in effect for a period of at least twelve (12) months. subject to the conditions as stated within this subsection.

Once Public Service has received the signed authoriz.ation form for the initial, or subsequent., enrollment with a third pany supplier, which process :is as set forth in this subsection and in Secnon 15.l, Public Service will confum the customer's participation with its designated third party supplier as well as send a letter of confirmation to the customer. hi the event of a dispute, assignment ofa customer will not occur unless and until the dispute is resolved. Once assignmet1t bas occuhed. the third pany supplier will

ATTACHMENT 6 PAGE 3OF19

• be required to provide all of the electric supply consumed on the Public Semce customer's account (single point of delivery).

15.2.1. Customer Change of Third Party Supplier: If a customer subsequently elects to c;hange its third party supplier, the customer must sign an authorization form as set fonh iD Section 1.5.1 and Section 15.2. Service from this altemate third party supplier v.ill become effective on the ctistomer's next scheduled meter reading date that is at least fifteen (15) days following the receipt of the authorization fotm by Public Service. upon enrollment 'With a tbitd pany supplier, the customer may not chaJige its third pany supplier for a miniinum period of twelve (12) months.

15.2.2. Customer Return to Public Service Rate Schedule Electric Supply: If the customer subsequently elects to retmn to Public Service as its supplier of electric supply, the customer must sign an authorization fomi as set forth in Section 15.2.1. The return to Public Service will become effective on the customer's next scheduled meter reading date that is at least fifteen (15) days following the receipt of the authorization form by Public Service and shall be for a minimum term of twelve ( 12) months. However, if a customer's third party supplier no longer satisfies the requirements of Section 15 .1.2.

Third Party Supplier, such customer shall immediately return to, and receive electric

.supply from, Public Service under customer's applicable rate schedule until customer selects another third party supplier in accordance 'With Section 15 .2.1. Where the to customer's rerum Public Service, as its supplier of electric supply. is caused by the customer's third party supplier no longer satisfying the requircmems of Section 15 .1.2, Third Party Supplier, the customer can elect an alternate third pany supplier prior to the expiration of the mlll.imum period of twelve (12) months indicated herein.

15.2.3. Third Party Supplier's Termination of Customer's Electric Supply: A third parry supplier will not be permined to physically connect or disconnect energy semce to a customer. A third pany supplier shall send wrinen or electronic notification to Public Service of any conttacrual termination, whether by cancellation or expiration, of a supply agreement between itself and its customer, and shall simultaneously notify the customer of the same. TemriDation of such agreement will become effective on the customer's next scheduled meter reading date that 1s at least fifteen (15) days following the receipt of the tennination notice by Publi~ Service. unless the customer directs PubliC Service in writing to the contrary. Public Service shall provide electric supply service to the customer on the effective date of the termination of the customer supply agreement in accordance with Pubhc Service* s applicable tariff and Board of Public Utilities rules and regulations.

If the customer disputes the termmanon. which occurs by cancellation, by simultaneous wrinen notice to Public Service and to its third party supplier, Public Service will 'not begin supplying electric supply to the customer until the customer.agrees to the termination. Such electnc supply will continue to be supplied by the third pany supplier until such time that the dispute lS resolved or the Board of Public Utilities approves in writing the temunation of the agreement between the customer and the third party supplier. At that time the temunation will become effective on the eustomer's next scheduled meter reading date that is at least fifteen (15) days following the receipt of the termination notice by Public Service. In the case of termination, which occurs by expiration, Public Service will furnish electric supply if the customer has not selected another third pany supplier in accordance with Section 15.2.1.

15..2.4. Administrative Fee: upon selection of a third parry supplier an administrative charge of

$20.00 ($21.20 including New Jersey Sales and Use Tax, SUT) will be applied to the customer* s account on Rate Schedules RS, RHS, and RLM. The administrative charge 2

ATTACHMENT 6 PAGE 4OF19 for Rate Schedules GLP, LPL, HTS, HS, BPL and PSAL is SS0.00 ($53 .00 including SUT). The administrative fee is applicable each time a customer enrolls "With a third party supplier or retmDS to Public Service. Public Service will waive this administrative fee if the customer's retum to Public Service fumished elec:ttic supply is necessitated by the~custamer'~ third pany supplier no longer satisfyjng the requirements of Section 15.1.2, Third Party Supplier.

15.3. Customer Billing Process: Public Service will provide one combineq bill to the third party supplier's mail customer(s) connrmmg both Public Service charges and third party supplier information including their name, telephone number, current electric supply charges, unpaid prior balance elec:ttic supply charges, and the total electtic supply charges. Only Public Service owned, installed, and read meters will be used to determine customer usage for the purpose of calculating Public Service charges.

15.3.1. Payment of Bills: Payment of bills, including third party supplier's charges for electric supply, shall be made to Public Service and shall be in accordance with Section 9, Meter Reading and Billing, of these Standard Terms and Conditions. Where a partial payment is received, in lieu of full payment, it shall be applied in the following order: (i) undisputed Public Service customer charges; (ii) undisputed third party supplier customer charges; (iii) disputed Public Service customer charges; and (iv) disputed third party supplier customer charges. Any customer overpayment will be held in the customer's Public Service account to be applied agajnst fumre customer bills or will be refunded to the customer at the customer's request. In the event that any customer checks are returned unhonored by a bank, such debits will be applied in inverse order to the order set fonh above.

15.3.2. Late Payment Charges: In the case of electric supply furnished by third party supplier, Section 9.12. Late Payment Charge, of these Standard Terms and Conditions is to be applicable only to Public Service customer charges. Customer shut-offs in cases where there is non-payment to Public Service for its customer charges are only performed in accordance with Secnon 12. Discontinuance of Service, of these Standard Terms and Condinons.

15.3.3. Billing Disputes: In the event of a billing dispute between the customer and the third party supplier. Public Service's sole duty is to verify its eustomer charges and billing determinants. Customer connnues to remain responsible for the timely payment of all Public Service charges in accordance with Section 9, Meter Reading and Billing, and Secnon 15.3.l. Payment of Bills. of these Standard Terms and Conditions, regardless of third party supplier billmg dispute(s). All questions regarding third party supplier's charges or other terms of the customer's agreement with a third party supplier are to be resolved between the customer and its third party supplier. Public Service will not be responsible for the enforcement. mtervennon. mediation, or arbitration of agreements entered into between third party supplier customers and third pany suppliers. Billing disputes that may arise regardmg Public Service's charges shall be subject to Section 12, Discontinuance of Service. of these Standard Terms and Conditions.

15.4. Continuity of Service: In addition to the terms specified in Section 12, Discontinuance of Service, and Section 14, Service Limitations, of these Standard Terms and Conditions, Public Service shall have the nght (i) to require a tmrd party supplier's electric supply sources to be disconnected from Public Service's elec:trical system; (ii) to otherwise curtail, interrupt. or reduce a third party supplier's electric supply; or (iii) to disconnect a third pany supplier's customer(s) whenever Public Service detetmines, or whenever Public Service is directed by PIM, that such a disco:miection, curtailment, interruption or 3

ATTACHMENT 6 PAGE 5OF19 reduction is necessary to facilitate construction. installation. maintenance, repair.

replacement or inspection of any of Public Service's or PJM members' facilities: to maintain the safety and reliability of Public Service's electrical system and any genemion facilities attached thereto; or due to Emergencies, :minimum generation ("light load") conditions, forced outages, potential overload of Public Service's or PJM*s transmission and/or distnbution circuits or events of Force Majeure including. but not limited to, those events specified in Section 14.1, Continuity of Service, of these Standard Temis and Conditions.

15.5. Limitations of Liability: In addition to those items enumerated in these Standard Terms and Conditions, Public Service shall not be liable in any way for any failme in whole or in part, temporary or pcnnanent, to deliver electric energy under any rate schedule within this tariff. Further, Public Service shall not be liable, to either third paity supplier customers or to third pany suppliers, in any way for any errors in the calculation of the load profile, demand, and/or electric energy usage, nor will Public Service be responsible for any additional electric supply costs and/or penalties inCUITCd by third party supplier customers or third party suppliers as a result of any such errors. Load profiling is a process that determines customer's hourly energy usage by taking a cUStomer's total monthly billed kWh and dcrivmg hourly usage amounts based upon the hourly usage panems of a relevant sample group.

Public Service shall have no respoDSlbility with respect to such electric energy before:.

third pany supplier delivers or has delivered on its behalf such electric energy to Public Service or after Public Service delivers such electric energy to customer at customer's meter, or on account of anything which may be done, happen or arise with respect to such electric energy before such delivery to Public Service or after such delivery to the customer.

15.6. Metering: In addition to the terms specified in Section 9. Meter Reading and Billing, of these Standard Terms and Condinons. for customers choosing a third party supplier to obtain its electric supply and havmg a peak load of 100 kW or greater for ten (IO) out of the prior twelve ( 12) billing months, Public Service will, in all circumstances install an interval metering device for customer billing purposes, at the customer's expense. which will pcnnit the recording of ~age and demand data in a maximum *of hourly increments, or in increments as specified m the customer's particular rate schedule, whichever.is smaller. The customer will be required to pay Public Service a set-up fee of$XXX.XX and a monthly service fee of SXX.XX for such interval metering devices. This fee is based upon the customer prov1dmg a smgle phase 120 volt electric supply"source, an individual message: business control office line and arrange for data tralismission of metering infonnanon and tc:munanon of data on an RJ45S modular jack. Other options may be available: for an addmonal set-up andior monthly service fee. The charges for the set-up fee and monthly service: fee will be billed upon completion of the instillation of the interval metc:nng device and will be included with the customer's next Public Service bill. If the interval metenng device is not installed prior to customer's initiation of third party supply then customc:r*s usage and demand will be determined by employing load profiling based upon the customer's rate schedule or historical customer usage and demand data, at the discrenon of Public SCTVicc:.

If the customer of a third party supplier is not required to have an interVal metering device as indicated above, hourly usage and demand, where applicable, will be

• determined by cmploymg load profiling based upon the customer's rate schedtile, unless the third party supplied customer chooses to have an interval metering device installed in which case the customer will be billed as indicated above. If a eust0mcr of a third party supplier has an inrcrval metering device and said device is not operational, customer's 4

ATTACHMENT 6 PAGE 6OF19

• hourly usage and demand, where. applicable, will be detmnined by employing load profiling based upon the customer's rate schedule or hlstorica.l customer usage and demand data, at the discretion of Public Service.

If a customer* of a third pany supplier already has an installed interval metering device OD its premises when electric retail choice is implemented, or one is installed subsequent to the initiation of retail choice, which interval metering device was installed solely for the pmpose of panicipating in Interrupable Electric Service (!ES) , the eustomer will be requjred to pay Public Service the aforementioned set-up fee and monthly service fee charged for interval metering devices. The charges for the set-up fee and monthly service fee will be included with the customer's next Public Service bill Those custamers participating in the Cunailable Electric Service (CES) program may continue to participate in that program. If a c::ustomer of a third pany supplier already has an installed interval metering device on its premises when electric retail choice is implemented, or one is installed subsequent to the initiation of reWl choice, which interval metering device was installed solely for the purpose of participating in CES. and the customer chooses to no longer participate, or alternatively is disqualified for this Special Provision because of continual f.ailure to meet agreed upon load reductions, the customer will be required to pay Public Service as indicated above for IES.

If a customer of a third pany supplier already has an installed inrerval metering device oD its premises when electric retail choice is implemented, or one is installed subsequent to the initiation of electric retail choice, for purposes includlng but not limited to conducting load research, Public Service may at its option remove that inrerval metering device. If customer chooses to retain that interval meteriiig device then customer will be required to pay Public Service as indicated above for IES.

16. TERMINATION, CHANGE OR MODIFICATION OF PROVISIONS OF TARIFF Tiris tariff is subject to the la\Vful orders of the Board of Public Utilities of the State of New Jersey.

Public Service may at any time and many manner permitted by law, and the applicable rules and regulanons of the Board of Public Utilities of the State of New Jersey, terminate, or change or modify by revision. amendment. supplement. or otherwise. this Tariff or any part thereof. or any rev1S1on or amendment hereof or supplement hereto.

5

ATIACHMENT 6 PAGE 70F 19 OTHER TARIFF CHANGES Sqndard Imns & Conditions 2.7. Temporary Service: Where service is to be used at an installation for a limited period and such installation is not permanent in natme, the use of service shall be classified as temporary. In such c:ases, the c:ustamer may be requjred to pay to Public Service the cost of insiallation and removal of the facilities required to fumish service and such service bemg .

only available with ele~c supply provided by Public Service. The m'inDnum period of tempOrary service for billing purposes shall be one month.

After two years of service a temporary service installation shall be eligil>le for refunds.

excluding the first two annual service periods, refunds equal to 100/o of the revenue received by Public Service during an annual service period shall be made at the end of such period. In no c:ase shall the total amount refunded be in excess of the installation cost paid by the customer, nor shall refunds be made for more than eight consecutive annual service periods.

Temporary service will be furnished only under Rate Schedules GLP, LPL, and HTS except that it will not be supplied for c:og~eration or standby purposes under any rate schedule at locations where electric: service is regularly supplied from another source, nor will it be supplied under Rate Schedules BPL and PSAL.

3. EXTENSION OF DISTRIBUTION LINES

• 3.2. Individual Residential Customer: Where the cost to Public Service for an extension to serve an individual permanent residential customer does not exceed $0.50 per estimated. ai:mual kilowatthour usage or where the length of an extension is 2500 feet or less, Public Service will make the necessary extension upon receiving from the customer an application for service. Such application shall be made by the owner of the property or by a responsible tenant and shall be an mdefmjte penod; not less, however, than the number of years necessary to produce, at the normal annual distribution charge, the cost of the extension.

3.2.1. \Vb.ere the cost of an extension exceeds the amount which Public Service will install without cost to a customer, in accordance with Section 3.2. the excess cost of the extension shall be deposited and remain with Public Service without interest. As additional customers are supplied from along this extension. an adjustment will be made to the depositor based on the pomt along the extension that such additional customers are connected. In no event shall more than the origmal deposit be returned to the depositor nor shall any pan of the deposit remaining after ten years from the date of the original deposit be returned. Public Service will waive the deposit reqUlJ'ed where the amount is $100.00 or less.

3.2.2. Where the cost of Public Service for an extension to serve an individual perm.anent residential customer exceeds the amount which Public Service will install without cost to the customer, in accordance with Section 3 .2, Public Service and the customer may agree upon a monthly revenue guarantee. in lieu of a deposit pursuant to Section 3.2.1, 1bis monthly revenue guarantee shall be based upon a guaranteed monthly kilowatthour usage billed at customer's applicable rate, net of production and transmission charges. The guaranteed monthly kilowatthour usage shall be determined by dividing one-twelfth of the total cost of the extension by $0.50 per kilowanbour.

3.3. Residential Land Developer: Where applications for extensions into newly developed tracts of land are made by individuals, partnerships, or corporations interested in the development or sale of land, but not as ultimate n:sidents, Public Service may require a deposit from the applicant covering the entire cost of the extension necessary to serve the tract.

6

AITACHMENT 6 PAGE 8OF19 3.3.1. Extension deposits shall not cmy interest and are to be returned as hereinafter provided to the depositor when and as street lights have been installed or new buildlng abutting on such extensions are under constnlction and have been framed and roofed.

3.3.2. The deposit shall be retmned in an amount equal to SO.SO per estimated annual kilowatthour usage from each such completion on said extension. If during a ten-year period from the date of the origlnal deposit, the actual annual kilowatthour usage, during any year of said ten-year period, from premises and street lights abutting upon said extension exceeds the esnmated aDilual k:ilowatthour usage which was the basis for the previous deposit remm, there shall be returned to the depositor an additional amount equal to SO.SO per annual kilowatthour times such excess kilowatthour usage. In no event sball more than the original deposit be returned to the depositor nor shall any part of the deposit mnaining after ten years from the date of the original deposit be retumed.

3.4. Commercial and Industrial: Public Service may require any customer to deposit an amount equal to the entire cost of the new facilities required to supply service, such amount to be subject to refund as follows: At the end of the first service year, an amount without interest equal to $140.00 times the sum of the year's monthly kilowatts billed to and paid by the customer for electric service delivered by Public Service for that year will be refunded, and thereafter refunds similarly dctennined will continue each year until such time as the

i.ccumulated annual refunds are equal to but not in excess of the sum deposited; provided.

however, that any part of the deposit not returned to the .eustomer within ten years after the beginning of the first service year shall remain the property of Public Service. No refund will be made if service is discontinued prior to the expiration of the first service year.

Where it is necessary to provide additional facilities to serve increased reqtrirements of an existing customer, Public Service may require the customer to deposit an amount equal to the cost of such additional facilines. This amount shall be subject to refund as outlined in the preceding paragraph. except that the refunds will be calculated at $140.00 times the sum of the year's monthly kilowatts of the excess over a predetermined base.

4.2. Types of Service: Subject to the restrictions in Section 4.1, the rypes of service available, with their nominal voltages from the specified supply system are:

Suppjy Systfm Type of Service 4.2.1. Secondary Distribution Single-phase, two-wire 120 Service: Single-phase, three-wire 120/240 Single-phase, three-wire 120/208 Three-phase, three-wire 240 Three-phase, four-wire 120/240 Three-phase, four-wire 120/208 Three-phase, four-wire 277/480 4.2.2. Primary Distribution Three-phase, four-wire 2,400/4,160 Service: Three-phase, four-wire 13.200 4.2.3. Subtransmission Service:

Three-phase, three-wire 26,400 Three-phase, three-wire 69,000 High Voltage Service: Three-phase, three-wire 138,000 Three-phase, three-wire 230,000 7

ATIACHMENT 6 PAGE90F19

5. SERVICE CONNECTIONS 5.2. Overhead Service: For overhead service in overhead zones, Public Service will furnish.

install, and maintain the overhead service facilities to the point of connection to the customer's facilitic:S.

Public Service will supply, without cost to the customer, 750 feet of single-phase or 600 feet of three-phase ovemead service connection, as measured from the curb line_ nearest to the customer's facilities to the pole nearest the point of connection. If the length of service connection exceeds the aforementioned, the customer may be required to pay the cost of such excess, such charge belng equal to the amount by which the cost of the service connection exceeds the greater of either $0.25 per annual kilowatthour for Residential Rate Schedules RS, RHS, and Rl.M, hereinafter Residential Rates, or $65.00 limes the sum of the year's monthly kilowatts for Rate Schedules GLP, LPL, HI'S, HS, BPL, and PSAL receiving secondary, primary or subtransmission service, as applicable, hereinafter Commercial and Industrial Rates, as estimated by Public Service, or the cost of the service connection which otherwise would be furnished without charge as provided above. The service drop between the pole nearest to the point of connection and the point of connection shall be installed at the expense of Public Service.

5.3. Underground Service in Underground Zone: For underground service in underground zones, Public Service will fumish, install, and maintain the underground service facilities to the point of connection to customer's facilities.

Public Service will supply, without cost to the customer, up to 100 feet of underground service facilities measured at right angles to the curb nearest the point of service connection to the customer's facilities. If the length of service connection exceeds the aforementioned.

the customer may be required to pay the cost of such excess, such charge being equal to the amount by which the cost of the service connection exceeds the greater of either S0.25 per annual kilowatthour for Residential Rates or $65.00 times the sum of the year's monthly kilowatts for Commercial and Industrial Rates as estimated by Public Service, or the cost of the service connection which would be furnished without charge as provided above.

5.4. Underground Service in Overhead Zone:

5.4.1. Secondary Distribution Service: Where underground service in an overhead zone is to be supplied, and secondary voltage supply from overhead facilities is inadequate for the size of customer's load, the customer shall furnish and install at his expense and in accordance with the specifications of Public Service the pr.mary conduits and any necessary manholes, which will be maintained by Public Service. The customer shall also be required to furnish, install, and maintain all secondary conduits and conductors and provide space on his property for necessary traDSfonnanon.

Where underground service in an overhead zone is to be supplied, and secondary voltage supply from overhead facilines is adequate for the size of customer's load, such service will be supplied under the following condinons:

At Request of Customer: The customer shall furnish and ins1all the service facilities at his own expense in accordance with the specifications of Public Service. Public Service will connect the service conductors and maintain the service facilities without charge to the customer.

8

ATTACHMENT 6 PAGE IO OF 19 Operating Reasons Beyond the Control of Public Service: The customer shall furnish and install at his expense and in accordance with the specifications of Public Service the service conduit which will be maintallied by Public Service. Public Service 'Will furnish, install and mainWn the service conductors to the point of connection to customer's facilities. Where the distance .from the nearest curb line to the point of connection to customer's facilities.

measured at right angles to the curb line is 100 feet or less, the service conductors will be fumished in place without charge. If the length of service conductors exceeds I 00 feet the customer may be required to pay a charge equal to the amount by which. the cost of service conductors exceeds the greater of either $0.25 Per annual kilowatthour for Residential Rates or S65.00 times the sum"ofthe year's monthly kilowatts for Commercial and Industrial Rates as estimated by Public Service, or the cost of the service conductors which otherwise would be furnished without charge as provided herein.

5.4.2. Primary Distribution Service: Where underground service in an overhead zone is to be supplied, and primary volmge supply is required because of the size of the customer's load.

such service will be supplied under the following conditions:

At Request of Customer or for Operating Reasons Beyond the Control of Public Service: The customer shall furnish and install at his expense and in accordance with the specifications of Public Service the service conduit and any necessary manholes which will be maintained by Public Service. Public Service will furnish. install, and mainmin the service conductors to the point of connection to customer's facilities. Public Service will supply, without cost to the customer, 750 feet of single-phase or 600 feet of three-phase conductors measured at right angles from the nearest curb to the point of connection to the customer's

• facilities. If the length*of service conductors exceeds 750 feet of single-phase or 600 feet of three-phase, the customer may be required to pay a charge equal to the amount by which the cost of the primary service conductors exceeds the greater of either $75.00 times the sum of the year's monthly kilowatts as estimated by Public Service or the cost of the service conductors which otherwise would be furnished without charge as provided herein.

5.4.3. Subtransmission Service: Vlhere underground service in an overhead zone is to be supplied, and subtransmiss1on voltage supply is required because of the size of customer's load. such service will be supplied under the following conditions:

At Request of Customer: The customer shal! furnish and install at his expense and in accordance with the specificanons of Public Service. the service conduit and any necessary manholes which will be mamtamed by Public Service. Public Service will furnish, instalL and mamtam the service conductors to the pomt of connection to customer's facilities. The charge to the customer shall be the cost of the facilities furnished and insmlled by Public Service minus the cost of equivalent overhead construction.

Operating Reasons Beyond the Control of Public Service: The customer shall furnish and ID.Stall at his expense and in accordance with the specifications of Public Service, the service conduit and any necessary manholes which will be maintained by Public Service. Public Service will furnish. mstall. and mamtain the service conductors to the point of connection to customer's facilities. Where the distance from the nearest curb line to the point of connection to customer's facilines, measured at right angles to the curb line is 100 feet or less, the service conductors will be furnished m place without charge. If the length of service conductors exceeds I 00 feet, the customer may be required to pay a charge equal to the amount by which the cost of the service conductors exceeds the greater of either $75.00 times the sum of the year* s monthly kilowatts as esnmated by Public Service or the cost of the service conductors which otherwise would be furnished without charge as provided herein.

9

ATIACHMENT 6 PAGE 11OF19

7.4. Tampaing

In the evem it is CS!ablisbcd 1hat Public Service meEm or other equjpmcnt on the cusrmm:r's premises have been tazq>e..:d with, mi. such cmqcring resuhs in iDcorrect measurement of the service supplied. the cost far such electric service under tbc applicable :rate scbedllle. exchmve of aey ~and Capacity Credit, based upon 1he Public Service esrinme from available data and not regisn:red by Public Service me=s shall be paid by tbc beneficiary of such service. In the case of a R'Sidemial alS"'Y"'eT, such unpaid service shall be limill!d 10 not more than ODC year prior to tbe date of comctiDg tbc ra:wpe:ed accouut and far DO more than the unpaid service under tbc applicable me schedule, exclusive of any En=gy and Capacity Credit, alleged 10 be used by su.c:b c:usmmer. The benefir;jacy shall be the cr,mnmer or od:lcr pmy who benefits from such raxnpering. The actual cost of

.investigation, inspection. and dr:1e1 *i* *man of such mwpe:ring, and oibe:r com, such as but not limited 10, the iJ:israDmon of prottctive cqnipment, legal fees, and o1ber COS1S relall:d 10 the admmistrative. civil or criminal pnxccdings, shall be billed 10 the rcspamible pany. The re5pCJDSlble part}' shall be tbe pany who cilhcr' 131J4>ded witb or caused 1he 1ampCriDg with a melC' or o1her cqujpmcm or knowingly n:ceivcd the benefit of cmip:riDg by or caused by anob:r. In the evc:m a R'Sidential customer unknowiDgly received the beocfit of meter or equipment tmij>eriilg, Public Service sball only seek from the hmefiring c:usromer the cost of 1he service provided under the applicable rate scheclule, exclusive of any Energy and Capacity Ucdit, but not the eost ofinvestigation.

These provisions are subject to tbe customer's right 10 pmsuc a bill clisptnc procecdi:Dg pmsuant to NJ.AC. 14:3-7.14.

Tamperiog with Public Service facilities may be puoisbable by fine and/or in::lprisomneat under the New Jersey Code of Criminal Justice.

• 9.9. Budget Plan (Equal Payment Plan): 0JSt0mcrS billed under Rate Schedules RS or RHS or GI..P (whc:re GI..P electric service is used for ~ purposes in buildings of four or fewer' units) shall have the option of paying for therr Public Service charges in equal. estimated monthly installmcn:s.

The total Public Service cbargcs for a twelve-month period will be averaged over twelve months and may be paid in twelve equal monthly i:ostallmclls. A miev.r between the acmal cmt of service and tbe mombly budget amount will be made at least once in the budget plan year. A final bill for a budget plan year shall be issued at the end of the budget plan and shall comam 1hat month's monthly budget amount phls any adjusan:nts will be made if aCUJal charges are more or less 1ban the budget amount billed.

10. COGENERATON OR STA.'l'IDBY SERVICE Electric service from sources other than that delivered by Public Service system shall not be used for the operation of customer*s electncal eqwpment without previous written notice to Public Service.

lo.I. Cogeneration Service: Where the service delivered by Public Service, which shall include all SCMce debvered to the c:ustomer at any one location, is used to supplement cusromer*s pnvate plant sen,ce or any other source of elearic service or motive power through electncal or mecb.amcal means or by means of operations procedures, such service shall constitute cogencrauon service and will be fumished under all rate schedules.

Where CUStOmer with the wrinen consent of Public Service opc:mes private plant service in parallel with the cogenerauon service fumishcd by Public Service, Public Service may re-energizc tbe service, following an interruption. without prior notice 10 the customer.

10.2. Standby Service: Where the service delivered by Public Service, which shall include all service delivered to the customer at any one location. is available in 1he event of failure of customer* s private plant service or any olber source of clearic service or motive power, 10

ATTACHMENT 6 PAGE 12OF19 or wh=e the service in effect scves to relieve or to sustain the effective operation of any other source of power, or where othe:rwise requested by the customer, such sCTVice s.hall constimrc standby service and v.-ill be fumished under all me schedules.

ID.l.I. Maiat.enance Power: When a FERC Qualifying Facility sc:hedules mamtmance with prior notification to and approval from Public Service for ma:i:ntcDallce power or i:o the event of failure of customer's cogcneration or small power production FERC Qualifymg Facility, that portion of the cusmmer's monthly maximum dc:mand re.lated to this service will not be subj.ect to the Public Service .Kilowatt Charges. Where a cusromer receives electric supply from a third party supplier, the customer will not be subject to the Kilowatt Charges, net of any Capacity and Tr.msmission Credits as designated in the applicable rate schedule.

RATE SCHEDULES RS, GLP, LPL, BPL, PSAL, ~\VHS, RHS, HS, HTS, & RLM ADJUSTMENT CHARGES:

Charges will be made for the estimated January through December annual period average cost per kilowatthour to Public Service of costs associated with each of Societal *Benefits, Non~Utility Generation, and Securitization Transition Charges. Prior to January of each year, the estimated average cost of each charge component listed below will be determined for the succeeding aIJPual period. These estimated average costs will be adjusted for any under- or over-recoveries together with applicable interest thereon. which may have occurred during the operation of the Company's previously approved meclwrism. Interest shall be detemtined monthly on the cumulative under-or over-recoveries average balance for the month utilizing the Company's allowed overall rate of return. The applicable charge will be the total cost in cents per kilsiwatthour adjusted by factors to reflect applicable losses from the sales of electricity and also the addition of Applicable Taxes .

Any net charge or credit will apply to all kilowattbours billed each month of the succeeding annual period. In the event that a maJor change in the total average cost occurs during the annual penod, a revised estimated average cost will be calculated and applied for the remainder of the penod in accordance Wlth the above.

Societal Benefits Charge: _

This charge shall recover costs associated with Societal Benefits including: I) Demand Side Management Programs: 2) EnvJionmental Remediation: 3) Nuclear Decommissioning Funding RequJiements: 4) Nuclear Fuel Disposal Assessment; 5) Uncollectibles; 6) Restructuring Costs;

7) Social Program Costs; and 8) Applicable Taxes .

Non-Utility Generation Charge:

This charge shall recover costs associated with non-regulated generation costs which are

+o /') &Qmp&n8 ef existing (as of July 1. 1997) long term contractual power purchase arrangements approved by the Board and/or established under requirements of the Public Utility Regulatory Policies Act of 1978.

• Securitization Transition Charge :

This charge shall fully recover the bendable stranded costs, and provide for adjustment in a manner approved by the Board of the Initial traDSition bond charge prior to the closing of the related transition bonds to reflect the actual rate of interest thereon and all other costs, including any required overcollaterahzanon. associated with the issuance of such transition bonds .

11

ATTACHMENT 6 PAGE 13OF19 ENERGY AND CAPACITY CREDITS:

A customer may choose to receive electric supply from Public Service or a third pa.ny supplier as defined in Section 15 of the Standard Terms and Conditions oftbis Tariff..

A customer who receives electric supply from a third-party supplier will receive a Market Energy Credit, a Capacity Credit, a Transmission Credit, and an Ancillary Services Credit. collecnvely known as Energy and Capacity Credits, in addition to the above adjustment cllaiges in each billing period. These Credits will be adjusted for losses at secondary voltages .Icustomize voltage reference to particular rate schedule - secondary, primary, sub trans. & trans.. as appropriate} and applicable mxes. Energy and Capacity Credits will be computed as measured or calculated by Public Service in accordance with the following: ( 1) Market Energy Credit is based upon the customer's kilowatthour usage in each hour times the customer's Locational Marginal Price of Energy, (2) Capacity Credit is based upon the customer's peak load contribution (in kilowatts) times the monthly Capacity Revenue Credit determined by Public Service based on PJM's Capacity Credit Market's Market Clearing Prices (on a dollars per kilowatt per month basis), (3) Transmission Credit is based upon the eustomer's transmission obligation (in kilowatts) times Public Service's NctWork Integration Transmission Service rate, or its successor, divided by 12, as contained in the PJM Open Access Transmission Tariff (on a dollars per kilowatt per month basis), and (4) Ancillary Services Credit is based on the customer's kilowatthours usage times the applicable monthly rate for such services.

SPECIAL PROVISIONS:

(XX) Customers who desire to purchase their electric supply from a third p:iny supplier must execute an authorization form and.are subject to Section 15 of the Standard Terms and Conditions _of this Tariff for Electric Service. (XX to be last Special Provision prior to tax provisions)

RATE SCHEDULE GLP SPECIAL PROVISIONS:

(b) Standby Service: When Standby Service, as defined in Section 10.2 of the Standard Terms and Conditions, is delivered, the following charges and provisions shall apply:

(b-1) Standby Service Charge: Where Public Service must provide reserve capacity and stand ready at all omes to deliver electric supply, a standby charge of $3.64 ($3.86 including Su"'T) per kilowan of Standby Capacity shall be applied. Where a customer receives electric supply from a third party supplier, that customer will receive a Standby Credit as pan of the Energy and Capacity Credits. The Standby Credit is based upon the product of the Standby Capacity times the sum of the Capacity Credit plus the Transmission Credit, pmsuant to this Rate Schedule's Section on Energy and Capacity Credits (both in dollars per kilowatt per month),

adjusted by the Board of Public Utilities approved coincidence factor of0.15.

(b-2) Determination of Standby Capacity: The standby kilowatt capacity shall be equivalent to the difference between the customer's fum capacity and the total load the customer would reqwre mthe event of a failure as determined by Public Service. The total load shall be equivalent to 85% of the customer's kilovoltampae requirement, as rated by Public SCTVlce. The customer may be required to furnish and install, at his own expense, a load-limitmg device, approved by Public Service, which shall be maintained by Public Service at customer's expense. The ma:rjrmmi kilovohampere demand setting of the load-linutmg device shall be under the sole control of and be adjusted 12 - ----- -----

ATTACHMENT 6 PAGE 14OF19 only by Public Service, and shall not be tampered or interfered With in aJJY way by the custamcr. At any time that there is an increase in the standby kilowatt capacity, a new term shall commence; the standby kilowan capacity may not be revised dov:nward during any tcm. *

(b-3) Minimum Charge: In lieu of the minirrrum charge hereinbefore set forth. the minmlID charge in any month shall be the Standby SeIVice Charge. The waiver of minjnnm charge is not applicable.

(b-4) Parallel Operation: Customer shall not, at any time, operate private plant service m parallel with the service furnished by Public Senrice except with the written consent of Public Service. *

(b-5) Maintenance Power: When a FERC Qualifying Facility schedules maintenance with prior notification to and approval from Public Service for maintenance power 01 in the event of failure of customer's cogeneration or small power production FERC Qualifying Facility, that portion of the cusmmer's monthly maximum demand related to this service will not be subject to the Kilowatt Charges h.erembefore set fonb. Where a customer receives electric supply from a third party supplier, the customer will not be subject to the Kilowatt Charges hereinbefore set forth. net of any Capacity and Transmission Credits.

(d) Police Recall or Fire Alarm System Service: Umnetered police recall or fire alarm system service will be fumished for signaling lamps, bells, or horns with an individual rating nor greater tban* 100 watts or 1/8-horsepower. as rated by Public Service, at a charge of 18c (19c including sun per month for each signaling lamp, bell, or ham connected. but the total charge shall in no case be less than S l .81 ($1.92 including SUr) per month. No other energy-using devices shall be connected to the police recall or fire alarm system. The customer shall provide, at bis OVID expense. all necessary equipment and wiring, including the service connection. This Special ProvIS1on is only available with electric supply furnished by Public Service.

(i) Curtailable Electric Service: Cunailable Electric Service will be furnished when and where available. Those customers that re~eive electric supply from a third party supplier may continue to receive service under this Special Provision. If a third party supplied customer chooses to no longer participate. or alternatively is disqualified for this Special Provision because of contmual failure to meet agreed upon load reductions, the customer will be required to pay Public Service. m accordance with Standard Tenns and Conditions, Section 15.6. Metering, for the installed interval metering device. Curtailable Electric Service will be furnished under the following condlnons:

( i-1) A customer agrees to take service under this rate schedule at a single service connection and agrees to curtail his load dunng mnes of curtailment by the amount stated in his Application/Agreement. A credit of $6.11 ($6.48 including SUI') per kilowatt of average actual curtailed demand for each cunailment period will be applied to the cUStomer's bill in a succeeding month. The curtailed demands will be measured as the difference, for each hour; between a customer-specific hourly load curve developed by Public Service for customer's normal business operation and the acrual recorded hourly load during the curtailment period.

The curtailment period will commence a minimum of one hour from the time of notification and end at the time indicated in the restoration call but not later than 8:00 P.M. as indicated in (i-3) below. For each applicable calendar month, the customer's individual cunailmcDt period results will be summed to detemrine the appropriate credit. There will be no penalty for failure to curtail load or meet the agreed upon load reduction when notified. Continued failure by a customer to meet agreed upon load reduction, however, will result in customer's 13

AITACH1\1ENT 6 PAGE 15OF19 disqualification for this Special Provision and Public Service may remove from the customer* s premises the interval metering device installed for this Special Provision.

RATE SCHEDULE LPL SPECIAL PROVISIONS:

(d) Standby Service: When Standby Service, as defined in Section 10.2 of the Standard Terms and Conditions, is delivered, the following charges and provisions shall apply:

(d-1) Standby Service Charge: Where Public Service must provide reserve capacity and stand ready at all times to deliver electric supply , a standby charge of $3.64 ($3.86 including SUT) per kilowatt of Standby Capacity for Secondary Distribution Service or S2.58 ($2.73* including SUT) per .kilowatt of SWldby Capacity for Primary Distribution Service shall be applied. Where a customer receives electric supply from a third pany supplier, that cust0mer will receive a Standby Credit as pan of the Energy and Capacity Credits. The Standby Credit is based upon the product of the Standby Capacity times the sum of the Capacity Credit plus the Transmission Credit, pursuant to this Rate Schedule's Section on Energy and Capacity Credits (both in dollars per kilowatt per month), adjusted by the Board of Public Utilities approved coincidence faetor of0.15.

(d-2) Determination of Standby Capacity: The standby kilowatt capacity shall be equivalent to the difference between the customer's firm capacity and the total load the customer would reqwre in the event of a failure as determined by Public Service.

The total load shall be equivalent to 85% of the customer's kilovoltampere requirement, as rated by Public Service. The customer may be required to furnish and install. at his own expense, a load-limiting device, approved by Public Service, which shall be maintamed by Public Service at customer's expense. The maximum kilovoltampere demand setting of the load-limiting device shall be under the sole control of and be adjusted only by Public Service, and shall not be tampered or interfered with in any way by the customer. At any time that there is an increase in the standby kilowatt capacity. a new term shall commence; the standby kilowatt capacity may not be revised downward during any term.*

( d-3) Minimum Charge: In lieu of the minimum charge hcreinbefore set forth. the minimum charge m any month shall be the Standby Service Charge less any Interruptible Service Credit if applicable. The waiver of minimum charge is not applicable.

( d-4) Parallel Operation: Customer shall not, at any time, operate private plant service in parallel with the service furnished by Public Service except with the written consent of Public Service. *

(d-5) Maintenance Power: \Vhen a FERC Qualifying Facility schedules maintenance with prior notificanon to and approval from Public Service for maintenance power or in the event of failllfe of customer's cogeneration or small power production FERC Qualifying Facility, that portion of the customer's monthly maxlmum demand related to this service will not be subject to the Kilowatt Charges hereinbefore set forth. Where a customer receives electric supply from a third party supplier, the customer will not be subject to the K.ilowan Charges hc:reinbefore set forth, net of any Capacity and Transmission Credits.

)4

ATTACHMENT 6 PAGE 16OF19 (e) Interruptible Service : Intmupnble Service will be furnished when and where available to those customers that continue to receive their electric supply from Public Service. In the event that a customer taking service under this provision obtains their electric supply from a third party supplier, they will no longer be eligible for this provision upon the initiation of thlld pafty supplied service. Further, the customer will be required to pay Public Service. in accordance with Siandard Terms and Conditions, Section 15.6, Metering, for the installed interval metering device. lnterrupnble Service will be fimrished under the following conditions:

(i) CDJ1ailable Electric Service: Cunailable Electric Service will be furnished when and where available. Those customers that receive electric supply from a third party supplier may continue to receive service under this Special Provision. If a third pany supplied customer chooses to no longer participate, or alternatively is disqualified for this Special Provision because of continual failure to meet agreed upon load reductions, the customer will be required to pay Public Service, in accordance with Stmdard Terms and Conditions, Section 15.6, Metering, for the installed interval metering device. Cunailablc Electric Service will be furnished under the following conditions:

( i-1) A customer agrees to take service under this r.ue schedule at a single service connection and agrees to curtail his load during times of cunailmcnt by the amount smted in his Application/

Agreement A credit of $6.11 ($6.48 including SUD per kilowatt of average actUal curmiled demand for each cunailment period will be applied to the customer's bill in a succeeding month.

The curtailed demands will be measured as the difference, for each hour, between a customer-specific hourly load curve developed by Public Service for customer's normal business operation and the acrual recorded hourly load during the CU1'13ilment period. The curtailment periC?d will commence a mi:nimum of one hour from the time of notification and end at the time indicated in the restoration call but not later than 8:00 P.M. as indicated in (i-3) below. For each applicable calendar month, the customer's individual curtailment period results will be summed to detmnine the appropriate credit. There will be no penalty for failure to curtail load or meet the agreed upon load reduction when notified. Continued failure by a customer to meet the agreed upon load reduction. however, will result in customer's disqualification for this Special Provision and Public Service may remove from the customer's premises the interVal metering device installed for this Special Provmon.

RATE SCHEDULE HTS SPECIAL PROVISIONS:

(c) Standby Service: 'When Standby Service. as defined in Secnon 10.2 of the Standard Terms and Conditions, lS dehvered. the followmg charges and provisions shall apply:

(c-1) Standb~* Service Charge: Where Public Service must provide reserve capacity and stand ready at all tllnes to deliver electric supply, a standby charge of Sl.31 ($1.39 including SUT) per kilowan of Standby Capacity shall be applied. Where a customer receives electric supply from a third party supplier, that customer will receive a Standby Credit as part of the Energy and Capacity Credits. The Standby Credit is based upon the product of the Standby Capacity times the sum of the Capacity Credit plus the Transmission Credit, pursuant to this Rate Schedule's Section on Energy and Capacity Credits (both in dollars per kilowatt per month), adjusted by the Board of Public Utilities approved coincidence factor of0.15 .

(c-2) Determination of Standby Capacity: The standby kilowatt capacity shall be equivalent to the difference between the customer's firm capacity and the total load 15

ATTACHMENT 6 PAGE 17OF19 the custamer would require in the event of a failure as determined by Public Service.

The total load shall be the* equivalent to 85% of the customer's kilovoltampere requirement, as rated by Public Service. The customer may be required to furnish and install. at his ovm expense, a load-limiting device, approved by Public Service.

which shall be maintained by Public Service at customer's expense. The maximum kilovoltampere demand setting of the load-limiting device shall be under the sole control of and be adjusted only by Public Service, and shall not be tampered or interfered with in any way by the customer. At any time that there is an increase in the su.ndby kilowan capacity, a new term, shall commence; the standby kilowan capacity may not be revised downward during any teml.

(c-3) Minimum Charge: In lieu of the mininmm charge hereinbefore set forth, the minimum charge in any month shall be the Standby Service .Charge less any Interruptible Service Credit if applicable. The waiver of minimum charge is not applicable.

( c-4) Parallel Operation: Customer shall not, at any time, operate private plant service in parallel with the service furnished by .Public Service except with the wrinen consent of Public Service.

(c-5) Maintenance Power: 'When a FERC Qualifying Facility schedules maintenance with prior notification to and approval from Public Service for maintenance power or in the event of failw-e of customer's cogeneration or small power production FERC Qualifying Facility. that portion of the customer's monthly maximum demand related to this service will not be subject to the .Kilowatt Charges hereinbefore set forth. Where a customer receives electric supply from a third party supplier. the customer will not be subject to the .Kilowan Charges hercinbefore set forth, net of any Capacity and Transmission Credits. *

( d) Interruptible Service : Intenuptible Service will be furnished when and where available to those customers that continue to receive their electric supply from Public Service. In the event that a customer taking service under this provision obtains their electric supply from a third pany supplier, they will no longer be eligible for this provision upon the initiation of third party supplied service. Funher. the customer wlII be required to pay Public Service, in accordance with Standard Terms and Conditions. Section 15.6. Metering, for the installed interval metering device. lntenuptible Service will be furnished under the following conditions:

(i) Curtailable Electric Service: Cunailable Electric Service will be furnished when and where available. Those customers that receive electric supply from a third party supplier may contmue to receive service under this Special Provision. If a third party supplied customer chooses to no longer participate. or altemanvely is disqualified for this Special Provision because of continual failure to meet agreed upon load reductions, the customer will be required to pay Public Service. in accordance with Standard Terms and Conditions, Section 15.6, Metering, for the mstalled mterval metenng device. Curtailable Electric Service will be furnished under the follo\\llllg condicons:

(i-1) A customer agrees to take service under this rate schedule at a single service connection and agrees to curtail his load during mnes of c:unailment by the amount stated in his Application/

Agreement. A credit of $6.11 ($6.48 including SUI") per kilowatt of average: actual c:unailed demand for each curtailment penod will be applied to the customer's bill in a succeeding month.

The cun:ailed demands will be measured as the difference, for each hour, between a customer-specific hourly load curve developed by Public Service for cusromer's normal business operation and the actual recorded how-ly load during the c:unailment period. The curtailment period will 16

ATIACHMENT 6 PAGE 18OF19 commence a nrintamm of one hour from the time of notification and c:nd at the time indicated in the restaration call but not later than 8:00 P .M. as indicated in (i-3) below. For each applicable calendar month, the custamcr's individual c:unailmem period results will be summed to detcmUne the appropriate credit There will be no penalty for failure to curtail load or meet the agreed upon load reduction when notified. Com:inucd failure by a customer to meet the agreed upon load reduction, however, will result in customer's disqualification for this Special Provision and Public Service may remove from the customer's premises the interval metering device insWled for this Special Provision.

17

ATIACHMENT 6 PAGE 19OF19 BUILDING UTILIZATION ELECTRIC SERVICE APPUCABLE TO:

Customers receiving serVice under Electric Rate Schedules HTS, LPL and GLP.

CHARACTER OF SERVICE:

Commitments for service under this provision will be made available to qualifying customers until July 31, 1999.

CREDIT:

A credit equal to the customer's total distribution service demand charge(s) for the newly leased or purchased space, as detemlined by Public Service, will be applied to the customer's monthly electric bills for twelve consecutive billing months. The credit must commence within nine months after receiving 'Written commitment from Public Service for Building Utilization Electric Service. In no case shall application of this Service and the Area Development Service Special Provision of Electric Rate Schedules HTS, LPL or GLP result in a negative charge for demand.

For new customers, the credit shall apply to all kilowatts, as measured by Public Service. A new customer, for purposes of this service, shall be defined as a customer whose newly leased or purchased space is separately metered.

For existing customers, the credit shall apply only to those kilowatts, as measured by Public Service, which are in excess of comparable demands in the same month established in a base year period, which period shall be defined as the twelve calendar months immediately preceding the first months service is provided under Building Utilization Electric Service. An existing cµstomer for pUiposes of this Service shall be defined as a customer whose newly leased or purchased space is not separately metered from his existing service.

ELIGmILI1Y:

Each customer will be required to sign an Application for Building Utilization Electric Service including an estimate of additional demand, and within 90 days of application for electric service. Applicants must submit evidence of. a comprehensive energy audit of the customer's facility to Public Service prior to receiving the credit. Upon verification of eligibility, Public Service will provide the customer with a written commitment for Building Utilization Electric Service.

To be eligible, a customer must lease or purchase vacant space for manufaCturing, research and development, office or warehousmg. The effective date of the lease or purchase must be between August 1, 1992 and July 31, 1999. The total additional leased or purchased building space must equal or exceed 15.000 square feet..

Qualifying building space must be vacant for a minimum of three months, as detctmined by Public Service, pnor to receivmg a commitment for Building Utilization Electric Service. The space must require no significant additional mvestment in facilities by Public Service, defmed as 50% of the estimated first year annual distribution service revenue.

18

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 APPENDIX5 BPU Summary Order

APR-21-99 14:54 FROM: BPU - ENERGY DIVISION IO: 9736487420 PAGE Agenda Date: 4/21/99 STA TE OF NEW JERSEY Board of Public Utilities Two GOltwoy C11111r ft/niiark., NJ 01102 ENERGY IN THE MATTER OF PUBLIC SERVICE )

SUMMARY

. ORO.ER ELECTRIC AND GAS COMPANY'S RA TE )

UNBUNDLING, STRANDED COSTS AND ) BPU DOCKET NOS. E097070461, RESTRUCTURING FILINGS ) E097070462, AND E097070463 (SERVICE LIST ATTACHED)

BY THE BOARD:

This Summary Order memorializes in summary fashion the action taken by the Board of Public Utilities ("Board") in these matters at its April 21, 1999 public agenda meeting. The Board will issue a more detailed Decision and Order in these matters in the near future, which will provide a full discussion of the issues as well as the reasoning for the Board's determinations.

These matters come before the Board on a record developed in hearings before Administrative Law Judge ("ALJ") Louis G. McAfoos, who issued an Initial Decision

("ID") on August 14, 1998, and in hearings conducted before Commissioner Carmen J.

Armenti from April 27, 1998 through May 28, 1998. Subsequent to the ALJ's ID and the hearings before Commissioner Armenti, the Legislature passed and Governor Whitman signed into law on February 9, 1999 the Electric Discount and Energy Competition Act

("the Act"). Negotiations were conducted during the latter part of February and the first half of March 1999. A comprehensive settlement was not reached, but on March 17, 1999 a Stipulation was filed by Public Service Electric and Gas Company ("PSE&G") on behalf of a number of parties to the proceedings. On March 29, 1999 an alternative joint proposal was submitted by the Division of the Ratepayer Advocate (Advocate} on behalf a number of other parties to these proceedings. Comments directed at the two competing proposals were solicited by the Board and submitted by numerous parties on April 5 and April 7, 1999, respectively.

APR-21-99 14:54 FROM: BPU - ENERGY DIVISION ID: 9736487420 PAGE 2 Based on its review of the extensive.record in these proceedings, as well as the comments submitted, the Board is not fully satisfied that either proposal in its entirety represents an appropriate resolution of these proceedings. However, the Board finds the March 17, 1999 Stipulation sponsored by PSE&G and others to be overall more financially prudent and consistent with the Act's requirements, consistent with the record and, with the modifications and clarifications set forth hereinbelow, provides the framework for a reasonable resolution of these matters based upon the record before

• us. Conversely, we find the Stipul.ation sponsored by the Advocate and others to be, in many significant areas, not supported by the record, reliant upon miscalculations and inappropriate assumptions or conclusions, and not reflective of a balanced consideration of all the issues in these matters. However, the proponents of the Advocate-sponsored stipulation and other parties have raised a number of legitimate concerns regarding the PSE&G-sponsored Stipulation which merit serious consideration and which, where appropriate, have been addressed by the modifications and clarifications set forth below.

Accordingly, except as specifically noted below, and as will be further explained in a detailed order which shall be issued we hereby incorporate by reference as if completely set forth herein, as a fair resolution of the issues in these proceedings the elements of the Stipulation filed by PSE&G and others, and to the extent the Initial Decision is inconsistent herewith, as it is modified to conform herewith .

The modifications and clarifications to the Stipulatjon are summarized as follows:

Paragraph 1.b): We find that all rate reductions after the August 1, 1999 statutorily mandated rate reduction should not be subject unconditionally to implementation of the transition bond charge. The 7% estimated aggregate rate reduction in January 2000, as well as the 8.25% aggregate rate reduction (as adjusted below) in August 2001, does include achievement of an estimated 2% overall savings from securitization in addition to the 1% securitization savings subsumed in the initial 5% rate reduction in August 1999. Accordingly, to the extent that securitization is not implemented, those middle rate reduction steps would appropriately be reduced by 2%. The final rate reduction in August 2002of13.9%

(10% from the level of April 30, 1997 rates), is required by the Act and shall not be conditioned upon implementation of securitization.

Paragraph 1.c): Subject to the foregoing, we modify the August 1. 2001 rate reduction from 8.25% to 9.00%.

DOCKET NOS. E097070461, 2 E097070462, AND E097070463

APR-21-99 14:55 FROM: 8PU - ENERGY DIVISION ID: 973848742111 PAGE 3 Paragraphs 1.e) and 3: We accept the manner In which the Stipulation applies the rate reductions to customer bills during the transition period, but are concerned that the removal of the rate reduction credit in year 5 will lead to an undue bill impact, since removal of the entire rate reduction credit would appear to result in a total customer bill which substantially exceeds the sum of the unbundled rate components, including the distribution rate, SGS rate (including transmission), STC, NTC, and SBC which will remain, prior to a.djustment, in year 5. Moreover, we are concerned that the particular unbundled rate components, particularly with respect to distribution charges, as provided in Attachment 2 will, after the expiration of the rate reduction credit, result in a shift in cost responsibility between and among customer classes. We therefore DIRECT the Company to file, by no later than March 1, 2000, a revised distribution rate design, for Board review and approval, which does not result in a shift of

• 1~.

cost responsibility betwe.en or among customer classes. Moreover, we QJBECT the Company to file, by no later than August 1, 2002, the proposed unbundled rate components which it proposes be implemented at the expiration of the transition period on August 1, 2003.

Paragraph 1O: The Board concludes that the Company should be provided with the opportunity to recover up to $2.940 billion net of tax stranded costs, through securitization of $2.400 billion and an opportunity to recover up to $540 million of its unsecuritized generation related net of tax stranded costs on a present value basis, subject to a true-up on the collection of the unsecuritized generation related stranded costs as provided in Paragraph 17 of the Stipulation. As well, the overrecovery in the LEAC as of July 31, 1999 totaling approximately $60 million (as estimated in the Stipulation net of taxes) should not be used as a mitigation tool for the Company; rather, it should be returned lo ratepayers and utilized to offset the stranded.costs otherwise recoverable from ratepayers. This shall be accomplished by applying the overrecovery as a credit to the starting deferred balance for the NTC.

Paragraph 11: The Board clarifies the language concerning the use of the net proceeds of securitization, to indicate that the refinancing or retirement of debt and/or equity shall be done in a manner that will not substantially alter the Company's overall capital structure.

DOCKET NOS. E097070461, 3 E097070462, AND E097070463

APR-21-99 14:55 FROM: BPU - ENERGY DIVISION IO: 9738487420 PAGE "l

• Paragraph 11.a): The Board will issue a financing order, consistent with the provisions of the Act, to authorize the Company to issue up to $2.525 billion of transition bonds representing $2.400 billion of net of tax generation-related stranded costs and an estimated $125 million of transaction costs. The taxes related to securitization, which reflect the grossed up revenue requirement number associated with the $2.400 billion in net of tax stranded costs being securitized, are legitimate recoverable stranded costs, however they should not be collected through the transition bond charge;* rather, such taxes shall be collected via a separate MTC. The duration of this separate MTC shall be 15 years, identical to the duration of the transition bond charge. An MTC of a shorter duration will prevent the achievement of the mandated rate reductions.

Paragraph 13: We believe that, on the condition that the Genco transfer is implemented, and the unsecuritized generation stranded costs level, once established, is not subject to true-up, other than as provided in Paragraph 17 (as modified), PSE&G should only be afforded the opportunity to recover $540 million on a net present value basis (not including the tax-related MTC addressed in Paragraph 11 (a)) of unsecuritized generation-related stranded costs, net of taxes, over the Transition Period.

Paragraph 14: Consistent with our modifications to paragraph 13, references to $600 million shall be modified to $540 million. In addition.

we modify the stipulation and clarify that any payrhentS to PSE&G resulting from BGS being bid out for year 4 of the transition period pursuant to paragraph 17 shall be credited to the deferred SBC balance for purposes of establishing the SBC rate in Year 5, and shall in no event be retained by the Company or remitted to Genco or otherwise utilized to recover unsecuritized generation~related stranded costs.

Paragraph 21.c: With respect to the fixed transmission rights, we clarify that the transfer of authority to Genco to act as PSE&G's agent for the purpose of scheduling, electing and/or using such rights, is solely for the purpose of Genco meeting its obligations under the BGS contract, incl1,1ding the removal of price volatility .

Paragraph 23: We believe that there should be an equal sharing of the gains from any sale of the transferred generating facilities which occurs within 5 years of August 1, 1999, rather than within four years as proposed in the Stipulation.

DOCKET NOS. E097070461, 4 E097070462, AND E097070463

APR-21-99 14:5S FROM: BPU - ENERGY DIVISION ID: 9736487420 PAGE S Paragraph 28: We clarify that it is our belief that. under the terms and conditions of our Order, and the resultant facts and circumstances, section 7 of the Act concerning the sharing of net revenues is not applicable.

Paragraph 29: We clarify that, for purposes of implementing the Stipulation, the Board will retain jurisdiction over and will monitor whether Genco is making good faith efforts to sell excess capacity into the PJM system at market rates.

• Paragraphs 30 and 30A: The Board accepts neither proposed standards of conduct in the Stipulation, but instead indicates that it has released draft affiliate relations standards for comment, and will be adopting interim .

affiliate relations standards pursuant to the Act prior to the completion of the transfer. and that such standards will be applied to the relationship between Genco and PSE&G, except as such relationship is defined in the BGS contract. The Company shall file the proposed BGS contract for the Board's review for compliance with the provisions of its Decision and Order in this matter.

Paragraph 34: The Third Party Supplier Agreements are subject to an ongoing generic working group under the Board's restructuring dockets.

Accordingly, we do not approve or give any particular weight to the tariff modifications in Attachment 6 to the Stipulation; we will determine the contents and substance of the Third Party Supplier Agreement and accompanying tariffs within the context of that generic proceeding. We encourage the parties to work cooperatively to resolve those issues in a collaborative manner.

In summary, subject to the conditigns embodied herein, the rate discounts provided by PSE&G relative to current rates shall be as follows, assuming 3% savings from securitization:

August 1, 1999 5%

January 1, 2000 (est'd) 7%

August 1. 2001 (est'd) 9%

August 1, 2002 13.9%

DOCKET NOS. E097070461, S E097070462, AND E097070463

APR-21-99 14:56 FROM: 8PU - ENERGY DIVISION ID: 973S487420 PAGE 6 The average shopping credits shall be as follows:

is.as 2Q..QO. 2001 200.2 200.3 RS 5.71 5.86 5.86 5.86 5.86 GLP 5.30 5.35 5.39 5.44 5.44 LPL-S 4.84 4.88 4.93 4.97 4.97 LPL-P 4.54 4.58 4.62 4.66 4.66 HTS-SubT 4.30 4.35 4.40 4.44 4.44 HTS-HV 4.12 4.16 4.21 4.25 4.25 Overall 4.95 5.03 5.06 5.10 5.10 The opportunity for recovery of up to $2.940 billion is afforded via $2.400 billion of securitization and the opportunity for up to $540 million to be recovered via the MTC, the retained retail adder and the depreciation reserve amortization and subsequently remitted to Genco, per the terms of the stipulation as modified.

The total opportunity for recovery of net of tax generation stranded costs is set at $2.940 billion, with the implementation of the Genco transfer, resulting from an increase in the net transfer value for the generating assets of $135 million from $1. 768 billion to $1.903 billion.

The amount of generation stranded costs which is authorized for securitization is

$2.400 billion. The Company is also authorized to securitize up to the estimated $125 million of reasonably incurred bond transaction costs.

The amount of unsecuritized net of tax stranded cost which the Company is permitted an opportunity to recover is $540 million, with the implementation of the Genco transfer per the terms of the Stipulation as modified herein. and subject to the true-up provisions provided in paragraph..-17 of the Stipulation as modified herein.

Within five (5) days of the date of this Order, the Company is HEREBY DIRECJCQ to submit to the Board schedules that show all accounting entries that will be required as a result of this Order, for both PSE&G and Genco. including the entries that will be required on the dates the securitization and Genco proceeds are projected to be received by the Company. In all cases, the information is to include all tax effects, both current and deferred, and the disposition of the accumulated balance of investment tax credits associated with the assets transferred and related annual amortization, if any, and all of the information, for both the Company and Genco. is to DOGKET NOS. E097070461, 6 E097070462, AND E097070463

APR-21-99 14:57 FROM: BPU - ENERGY DIVISION ID: 973648742121 PAGE 7

• be quantified reflecting the findings of this Order, as set forth above. The Company shall consult with Staff to assure the adequacy of the required submissions.

BLIC UTILITIES HERBERT H. TATE PRESIDENT CAR~~'"\;""'

COMMISSIONER

~J, FREDERICK F. B COMMISSIONER

• ATTEST:

RTIFV th11t tt't* ""ltttln I HrRl.'BV CE rtV of the 01\g\nll dor111*N1n1 ' 9 "lrll~:rd of Publl~

In 1111* hleti of the u~-v* -cl=-----

DOCKET NOS. E097070461, 7 E097070462, AND E097070463

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 APPENDIX6 Reorganized Corporate Affiliate Structure

PS Enterprise PSE&G PSEG Power PSEG Nuclear PSEGERT PSEG Fossil (EWG) (EWG)

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 APPENDIX7 Overview of Affiliate Relationship

PAYMENT STRUCTURE PSEG Power Holdings PSEG PSEG Full Output MW Energy Full Output MW p SEG Fossil Resources Nuclear Fuel+ & Trade $ Payment for actual

$ Payment for costs incurred actual costs incurred BGS+ Full Req.

MTC$ Contract Energy PJM Markets PSE&G ISO

1) All financial reporting for PSEG Fossil, PSEG Nuclear, and PSEG Energy Resources & Trade will be rolled up to the PSEG Power level.

All financing will occur at the PSEG Power level. PSEG Power will provide financial guarantees for PSEG Energy Resources & Trade's market contracts.

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 APPENDIX8 Annual Financial Reports The annual financial reports for PSE&G for the past three years were submitted via the following letters:

LR-N97226, dated April 8, 1997; LR-N98176, dated April 13, 1998; and LR-N99168, dated April 14, 1999.

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 APPENDIX9 Estimated Operating Costs - PSEG Nuclear CONTAINS PROPRIETATY INFORMATION WITHELD FROM PUBLIC DISCLOSURE

License Nos. DPR-70 Docket Nos. 50-2 72 DPR-75 50-311 NPF-57 50-354 APPENDIXlO Income Statement, Cash Flow Projection, and Nuclear Revenue Projection - PSEG Power CONTAINS PROPRIETATY INFORMATION WITHELD FROM PUBLIC DISCLOSURE

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 APPENDIX 11 Market Price and Capacity Factor Assumptions CONTAINS PROPRIETATY INFORMATION WITHELD FROM PUBLIC DISCLOSURE

License Nos. DPR-70 Docket Nos. 50-272 DPR-75 50-311 NPF-57 50-354 APPENDIX12 Report on Nuclear Decommissioning Trust Fund Status