The URL can be used to link to this page

Home My WebLink AboutUST-REPORT 12/19/2003 --..... , ,- Per Operate" .~ Hazardous Materials/Hazardous Waste Unified Permit it to " !- ~" . ":> . , " .--::<' ~ <> ~ CONDITIONS OF PERMIT ON REVERSE SIDE 10,000 10,000 " , This permit is issued for the following: , :'¡tI~~ardous Materials Plan 'etpround Storage of Hazardous Materials Q,agement Program ,,", Waste ' ....... o PERMIT ID# 015-021-001071 PG&E BAKERSFIELD SERVI,w:, , LOCATION 4101 001 002 UNLEADED GASOLINE DIESEL #2 " - -'- -, . , c - "'- PIPING PIPING PIPING PIPING TYPE TYPE METHOD MONITOR DW F PRESSURE " ALD I' f OW F PRESSURE ALD~,;;-,~ "/' ',> t TANK HAZARDOUS SUBSTANCE CAPACITY , i;; ~~';\'l ,~2;, '''', -'.1, 'f, Bakersfield Fire Department OFFICE OF ENVIRONMENTAL SER VICES 1715 Chester Ave., 3rd Floor Bakersfield, CA 93301 Voice (805) 326-3979 FAX (805)326-0576 Approved by: / I Expiration Date: June 30, 2000 .., ,¿- ~"" ,I ~-~ . . . -- ~ -. .-~ '- - c 1 t d! . CONDITÎONSIPROHIBITIONS: SUM~ARYOF CONDITION/PROHIBITIONS MONITORING REQUIREMENTS: '" I, Thè'facility owner and operator must be familiar with all conditions specified within this pel11lit and must meet any additional requirements to monitor, upgrade, or close the tanks and associated piping imposed by the pel11litting authority, 2, If the operator of the underground storage tank is not the owner, then the owner shall enter into a written contract with the operator, requiring the operator to monitor the underground storage tank; maintain appropriate records; and implement reporting procedures as required by the Department. 3. The facility owner and operator shall ensure that the facility has adequate financial responsi- bility insurance coverage, as mandated for all underground storage tanks containing '-"'.- o~ petroleum, and supply proof of such coverage when requested by the pel11litting authority. '4, The facility owner must ensure that the annual pel11lit fee is paid within 30 days of the invoice date, ' 5. The facility will be considered in violation and operating without a pel11lit if annual pel11lit fees are not received within 60 days of the invoice date. ' 6, The facility owner and/or operator shall review the leak detection requirements provided within this pennit. The monitoring alternative shall be implemented within 60 days of the pennit issue date, 7, The facility, underground storage tanks must be monitored, utilizing the option approved by the pennitting authority until the tank is closed under a valid, unexpired pennit for closure, 8. Any inactive underground storage tank which is not being monitored, as approved by the pennitting authority, is considered improperly closed, proper closure is required and must be completed under a pennit issued by the permitting authority. 9. The facility owner/operator must obtain a modification pennit before: .a. Uncovering any underground storage tank after failure of a tank integrity test. b:Replacement of piping. c. Liniñg the interior of the underground storage tank. '_ ,d.' Any other work which alters the tank or piping. 10. The tank owner must advise the Bakersfield Fire Department within 10 days of transfer of ownership. II. Any chari.ge in state law or local ordinance may necessitate a change in pennit conditiqns. . The owner/operator will be required to meet new conditions within 60 days of notification. ( _ ~:2. The owner and/or operator shall keep a copy of all monitoring records at the facility fora ". minimum of three years, or as specified by the pennitting authority. They may be kept off site if they can be obtained within 24 hours ofa request made by the Incal authority. 13, The owner/operator must report any unauthorized release which escapes from the secondary containment, or from the primaJy containment if no secondary containment exists, which increases the hazard of fire or explosion or causes any deterioration of the secondary containment within 24 hours of discovery. 14, The facility owner and operator are subject to Chapters 6,5, 6,67, 6.7,6,75, & 6.95 of the California Health and Safety Code, including hazardous materials/waste, risk management, and other regulatory requirements, as applicable, I Code Èxplanations: 1(,' , ., Types ofTanJcs and Piping I, Any underground storage tank not utilizing interstitial monitoring or a State approved automated tank gauging method shall be monitored utilizing the following method: a, ständard Inventory Control Monitoring (tank gauging five to seven days per week), If needed fOl11ls can be obtained from the Bakersfield Fire Department.Inventory reconciliation and/or tank gauging shall not be used on any tank for leak detection after December 1998. 2, All tanks shall be tested annually utilizing a tank integrity test which has been certified as being capable of detecting a leak of 0,1 gallon per hour with a probability of detection of95 percent and a probability of false alal11l of 5 percent. All tank integrity tests shall be completed under a valid, unexpired Pel11lit to Test issued by the Bakersfield Fire Department. 3, Manual tank gauging and/or inventory reconciliation for purposes of leak detection shall not be allowed after Decemb~r 1998. 4. All suction piping shall be monitored for the;: presence of air in the pipeline by observing the suction pumping system for the following indicators: a, The cost/quantity display wheels on the metered suction pump skip or jump during operation; b, The suction pump is operating, but no motor vehicle fuel is being pumped; c. The suction pump seems to overspeed when first turned on and then slows down as it begins to pump liquid; and d. A rattling sound in the suction pump and emtic flow, indicating an air and liquid mixture. 5. All underground storage tanks containing motor vehicle fuel shall be retrofitted with overspill containers, over fill protection, automated tank gauging/inventory control and/or interstitial monitoring devices and corrosion protection by December 1998, or shall be removed and replaced with a system that meets new construction standards specified by the State regula- tions, All tanks containing a hazardous substance other than motor vehicle fuel shall have secondary containment and meet all other State standards by December of 1998, 6. All equipment installed for leak detection shall be operated and maintained in accordance with manufacturer's instructions, including routine maintenance and service checks (at least once per year) for operability or running condition perfOl11led by an authorized service representative. ,7. An annual report shall be submitted to the Office of Environmental Services of the Bakers- field Fire Department each year after monitoring has been initiated which includes reciepts and results of the required annual maintentance service checks. ANY QUESTIONS, RELEASE REPORTS, ETC. SHOULD BE SUBMITTED TO THE: OFFICE OF ENVIRONMENTAL SERVICES BAKERSFIELD FIRE DEPARTMENT 1715 CHESTER AVE., BAKERSFIELD, CA 93301 (805) 326 3979 Monitoring Methods I, t-. !- DW= FCS» ,~PT= F=' L= S= SW= Double Wall Fiberglass Clad Steel Lined Piping Trench Fiberglass Liner (exterior) Steel Single Wall LCP== PFP= PVC= swc= GAL= UNK= Interior Lined w/ Cathodic Protection Polyethelene Flexible Piping Poly Vinyl Chloride Steel with Coating Galvanized Steel Unknown AUF ATG= CLM= LTI= MIR= MTG= SIR= TIT= Automatic Leak Detector Automated Tank Gauging Continuous Leak Monitor Line Tightness Testing Manual Inventory Reconciliation (not allowed after December 1998) Manual Tank Gauging , Statistical Inventory Reconciliation Tank Tightness Testing ---'-, ~~~- -- ~_.....-- I ~ I~ ç. 12/19/2003 15:07 - 6618363. ,.1.'t'"" ,/ '_ . () REDWINE TESTING SVCS PAGE 03 CITY OF BAKERSFIELD OFFICE OF ENVIRONMENTAL SERVICES 1715 Chester A vel, Bakersfield, CA (661) 326..3979 APPLICA TION TO PERFORM FUEL MONITORING CERTIFICATION FAcn.ITy -æ 6'1-'G ~ \:;er s t. e.\ ø\ ::!."...."t¿ Q..",..I.e.r ADDRESS~ln\ WLb'~ ~ 7>~kers~.e.\g, QA ~33t3 OPERATORS NAME 'J)('}....,·-e..U ~Q.r~ cq,s.He", OWNERs NAME ?li~~ NAME OF MONITOR MANuFACfURER DOES PACD.JTY}fA VB DISPENSER PANS? V e.e.J.er ~at.tk YES-1L ~ NO_ TANK II , 2. VOLUME ~ ~ CONTENTs ~ ~ NAME OF TESTING COMPANY , ~oclLa"\~ \e.3iI"j :r-frL1t~~1 .x"c. CONTRACTORS UCEN'SE #_ S::~d ~~f- ~ NA-L NAME 8< PHONE NUMBER OF CONTACT PERS ONl)"jiY> -r ....nes. 113<1- ",qqs DATE & TrME TEST IS TO BE CONDUCTED 1.-~O-o3 Ib:Bð 14th Jc (i~ APPROVED BY I,;)· q "'D3 DATE ~µ¡~ SIGNA TURE OF APPUCANT , ' ...---- "", I'T I'T I,..:¡ ru U.S. Postal ServicerM I CERTIFIED MAILM RECEIPT (Dome~tic Mail Only; No In§urance Coverage Provided) , ' '" OFF ',;.Cr;!F. \ . ¡¡ ~--~' S E 1'"", ,L:,... ,1\. , ,,,,,, Postage $ 4042 Postmark Here ~ S DRIVE BAKERSFIELD CA 9~3!J8 Certified Fee Retum Rec/ept Fee (Endorsement Required) Restricted Delivery Fee (Endorsement Required) Total Postage & Fr ! , Mr. Darre1l Hardcastle PG&E (Bakersfield Service Center) 4101 Wible Road Bakersfield, CA 93313 :, I - II I Certified Mail Provides: 1 · A mailing receipt (9SJBA9/:i) ~OOG aunr '009£ wJO, Sd ! · A unique Identifier for your ~ail~iece '. ( · A record of delivery kept b1'the Postal Service for two years I I Iml'.ortsnt Reminders: ' · Certified Mall may ONLY be combine~~ith First-Class Mail® or Priority Mail®'j · Certified Mail is notav"!-ilable for any'dasSlpf international mail, · NO INSURANCE COVERAGE IS PROVIDED with Certified Mail. For, valuables, please consider Insured or Registered Mail. II For an additional fee, a Return Receiptmay be requested to provide proof of delivery, To obtain Return Receipt service, pfease complete and attach a Retum Receipt (PS Form 3811) to the article and add applicable postage to cover the' fee, Endorse mailpiece "Return Receipt Requested", To receive a fee waiver for 1 a duplicate return receipt, a USPS", postmark on your Certified Mail receipt is reqUired. . For an additional fee, delivery may be restricted to the addressee or, addressee's authorized agent. Advise the clerk or mark the mailpiece with the endorsemenL"Restricted1Jelivery", I ~ .. If a postmark on the Certified Mail receipt is desired, please present the arti- ' , cle at the post office for postmarking. If a postmark on the Certified Mail i receipt is not needed, detach and affix label with postage and mail. I ~ IMPORTANT: Save this receipt and present it when making an inquiry. I Internet access to delivery information is not available on mail addressed to APOs and FPOs. ;~ ~ · Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. · Print your name and address on the reveme so that we can return the card to you. · Attach this card to the back of the mail piece, or on the front if space permits. 1. Article Addressed to: Mr. Darrell Hardcastle PG&E (Bakersfield Service Center) 4101 Wible Road Bakersfield, CA 93313 I 2. Article,Number ! (rransfer from service labeQ PS Form 3811. August 2001 3. Service Type l2(eertified Mail 0 Express Mail o Registered 0 Return Receipt for Merchandise o Insured Mall 0 C.O.D. 4. Restricted Delivery? (Extra Fee) 7003 1680 0007 4654 I I I I 2133 -I 102595-02-M-1540 I DYes Domestic Return Receipt UNITED STATES POSTAL SERVICE "'" First-Class Mail Postage & Fees Paid USPS Permit No. G-10 --~ ~ :.... · Sender: Pleàse print your name, address, and ZIP+4 in this box. Bakersfi'8if'i :~, Ire Department PrE"\!:jl" in Services 1715 Che;),.;;;'\!enue, Suite 300 BakersiiE:¡ò, CA 93301 r I I I I I I ~ I .I I I 'I PGE BAKER:'::F I ELD SER\, I CE CENTER 41 I] 1 I¡J I BLE ROAD BAKEF~~3F I ELD. CA '3:3:31:::: NOV 25. 21]1]3 6:1]1] AM INVENTORY REPORT T I :GA~30LI NE VOLUt"1E ULLAGE '30% ULLAGE= TC VOLUr"1E HEIGHT I"IATER VOL WATER THW TANK 91]62 1115 '37 91]12 80"OQ o 0.00 67.8 GALS GALS GALS GAU:; I NCHE:::; GALS INCHES DEG F T 2:DIESEL TANK VOLUME 5613 GALS ULLAGE 4564 GALS 91]% ULLAGE= :3546 GALS TC 'v'OLUtvlE 5574 GALS HEIGHT 51.89 INCHES WATER VOL 14 GALS WATER 1].84 INCHES TEMP 74.6 DEG F ~ ~ ~ ~ ~ END ~ ~ ~ ~ ~ ,'OOR ORIGINAL J *..... . », PGE BAKERSFIELD SERVICE CENTER 41 0 I ~',J I BLE ROAD BAKERSFIELD.CA 93313 NOV 25. 21]03 1 :27 PM SYSTEM STATUS REPORT ------ ALL FUNCT IONS NORr"1AL I N\/ENTORY REPORT T 1: GASOLI NE \/OLUr"1E ULLAGE '30j. ULLAGE= TC VOL Ut"lE = HE IG HT '¡ :~f WATER 'v'OL' '" (",JATER TEt"1P TANK 8568 GALS 161]9 GALS 591 GALS 8517 .GALS 75. ::::4 ~tÙJtHE:::; I] GALS I] . 1]1] I NCHÐ3 68.3 DEG F T 2:DIESEL TANK VOLUME 5385 GALS ULLAGE 4792 GALS 91]% ULLAGE= 3774 GALS TC VOLUr"lE 5:346 GALS HEIGHT 51].21] INCHES WATER VOL 14 GALS WATER 0.84 INCHES TEI"1P 75.1 DEG F ~ ~ ~ ~ ~ END ~ ~ ~ ~ ~ \. \' , ì ,- , '_1 .c CITY OF BAKERSFIELD FIRE DEPARTMENT OFFICE OF ENVIRONMENTAL SERVICES UNIFIED PROGRAM INSPECTION CHECKLIST 1715 Ches(er Ave.. 3rd Floor, Bakersfield. CA 93301 FACILITY NAME ~.~ ~ E INSPECTION DATE~Q1 Section 2: Underground Storage Tanks Program o Multi-Agency 0 Complaint Number of Tanks 1- Type of Piping Oú)ç- ORe-inspection o Routine 0 Combined rst Joint Agency Type of Tank (\WFc..5 Type of Monitoring UIIA ,~ , , OPERA TlON C V COMMENTS .1 Proper tank data on tile V.l Proper owner/operator data on tile V ./ Permit fees current L- / Certitication of Financial Responsibility (/.1 Monitoring record adequate and current L... / / Maintenance records adequate and current V .,/ ...- Failure to correct prior UST violations Has there been an unauthorized release? Yes No ~ Section 3: Aboveground Storage Tanks Program TANK SIZE(Sfùt, uJa.IiIL ():r Type of Tank AGGREGATE CAPACITY Number of Tanks -r~ I, OPERA TlON Y N COMMENTS spec available spec on tile with OES Adequate secondary protection Proper tank placarding/labeling Is tank used to dispense MYF? If yes, Does tank have overtill/overspill protection? c=comPh,,'J V=Viol,,:on y=y" In'P'tto" ". ) (£~ Office of Environmental Services (661) 326-3979 N=NO ~~X- usiness Site Responsible Party Whitc - Fnv, Svcs. Pink - Business Copy < ,I FIRE CHIEF RON FRAZE ADMINISTRATIVE SERVICES 2101 "H" Street Bakersfield. CA 93301 VOICE (661) 326-3941 FAX (661) 395-1349 SUPPRESSION SERVICES 2101 "W Street Bakersfield. CA 93301 VOICE (661) 326-3941 FAX (661) 395-1349 PREVENTION SERVICES FIRE SAFETY SERVICES· EI/VIRONIlEHTAI. SERVICES 1715 Chester Ave. Bakersfield. CA 93301 VOICE (661) 326-3979 FAX (661) 326-0576 PUBLIC EDUCATION 1715 Chester Avè. Bakersfield, CA 93301 VOICE (661) 326-3696 FAX (661) 326-0576 FIRE INVESTIGATION 1715 Chester Ave. Bakersfield. CA 93301 VOICE (661) 326-3951 FAX (661) 326-0576 TRAINING DIVISION 5642 Victor Ave. Bakersfield, CA 93308 VOICE (661) 399-4697 FAX (661) 399-5763 - -. January 22, 2003 PG&E 4101 Wible Rd Bakersfield CA 93313 RE: Upgrade Certificate & Fill Tags Dear Owner/Operator: Effective January 1,2003 Assembly Bill 2481 went into effect. This Bill deletes the requirement for an upgrade certificate of compliance (the blue sticker in your window) and the blue fill tag on your fill. You may, if you wish, have them posted or remove them. Fuel vendors have been notified of this change and will not deny fuel delivery for missing tags or certificates. Should you have any questions, please feel free to call me at 661- 326-3190. Sin~& Steve Underwood Fire InspectorÆnvironmental Code Enforcement Officer Office of Environmental Services SBU/dc ~\~~ de W~ .970p.A0Pe .r~ .A W~"", IÞ - CITY OF BAKERSFIELD FIRE DEPARTMENT OFFICE OF ENVIRONMENTAL SERVICES UNIFIED PROGRAM INSPECTION CHECKLIST 1715 Chester Ave., 3rd Floor, Bakersfield, CA 93301 FACILITY NAME P.~+e INSPECTION DATE (;1 ~ 1I ~ () 'l... Section 2: Underground Storage Tanks Program o Routine 0 Combined 0 Joint Agency Type of Tank iJ<1JF<:'<ì Type of Monitoring èt.,¿;V\ o Multi-Agency 0 Complaint Number of Tanks -:J Type of Piping t:JUJ po ORe-inspection OPERA TION C V COMMENTS Proper tank data on tile V Proper owner/operator data on tile V Pemit fees current t ./ 1/ Certification of Financial Responsibility 1..,.,/ Monitoring record adequate and current v-./ Maintenance records adequate and current L-- Failure to correct prior UST violations J Has there been an unauthorized release? Yes No L/ Section 3: Aboveground Storage Tanks Program TANK SIZE(S)C \ )~..l~ d1 Ll Type of Tank AGGREGATE CAPACITY Number of Tanks OPERA nON Y N COMMENTS SPCC available SPCC on file with OES Adequate secondary protection Proper tank placarding/labeling Is tank used to dispense MVF? If yes, Does tank have overfill/overspill protection? C=Compliance V=Violation Y=Yes N=NO In'p"tn, J¡/ rL4mv Office of Environmental Services (805) 326-3979 White - Env, Svcs, QJ¡¡a~ Business Site Responsible Party Pink - Business Cory NAME OFTESTINO COMPANY hra.vrz.a\ - \ti " ŒÐf'!Jvat::h't:5Y\ CONTRACTORS UCENSE#~ NAME & PHONE Nù"MBER ~F CONTACT PERSON ~v'Ñ...\( ~\'2:h ~~2 2/-iï 1 DATE&TJMETESTISTOBECONDUCTED l?./lO/ö?_ @' q 'illY" ~ ' !_ < ~t1/ ~ Dee 05 02 01:56p .- ." Franzen Hill 5596881467 - '" ..'? ~~ Sep 06 02 02:42p FRANZEN HILL 661 834 4216 CITY OF BAKERSFIELD OFFICE OF ENVIRONMENTAL SERVICES 1715 Chester Ave., Bakersfield, CA (661) 326-3979 APPLICATioN TO PERFORM FUEL MONITORING CERTIFICATION FACILITY ~.(V. ~~ ~~\~ ..'_.,'... ADDRESS- ~ 0_\ W"\ 'V1 \~ 1<d . OPERATORS NAME" ~l)..tjHL ChØ4 +- ~i( -'. .. OWNERSNAME ffi.l'ltt~ -t-fii4t.dr~ . - NAMEOFMONlTORMANUFA~ \lR.~rpl' ~IS ~;Q _ DOES FACD...ITY HA VB DISPENSER PANS? ¥ES--. NO_ TANK # ---L- ~ VOLUME CONTENTS 'Diç~ t LLn 1/4./1£ ti :L ct4Á'H) \ ,.. l r Jr...ß ,-z:Þ I~:::) , . APPROVED BY DATE p.2 . '-. p.3 .. . ":- ,,'." , '. " " . , .... . ~: ~ . .··.;{;·,~1 ~~~.. ...~ ." . .. ~. . . :~.,..:::~ ::';~:'I >:: .:(~ .:. , .. ~ ~. r '. . · Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. · Print your name and address on the reverse so that we can return the card to you. · Attach this card to the back of the mailpiece, or on the front if space permits. 1, Article Addressed to: I (I DARRELL HARDCASTLE ,PG&E : 4101 WIBLE ROAD II BAKERSFIELD CA 93313 I 1"'- I I I D, Is delivery address different from item 1? If YES, enter delivery address below: ì i I ¡ --" 3, Service Type o Certified Mail 0 Express Mail o Registered 0 Return Receipt for Merchandise o Insured Mail 0 C,O.D, 4, Restricted Delivery? (Extra Fee) 2 ^..¡"'I.... ~I. .~~ L 7002 10860 0000 16 41 5 400 , PS Form 3811, August 2001 Domestic Return Receipt DYes I I I I I r I UNITED STATES POSTAL SERVICE -,"", First-Class Mail P 'd Postage & Fees al USPS Permit No. G-10 - ^ - - address, and ZIP+4 in this box · I . Sender: Please print your !'ISme, ~ BAKERSAELD RRE DEPARTMENT OFFICE OF ENVIRONMENTAL SERVICES 1715 Chaster Avenue, Suite 3DO Bakevstleld, CA 93301 L - I~ ILl') 1M I~ 10 Ig Ie 10 Return Receipt Fee I...D (Endorsement Required) o:Q Restricted Delivery Fee o (Endorsement Required) ru Total Posta o r o Sent To '. DARRELL HARDCASTLE f'- ....m..mm~ PG&E Street, Apt. ^ orPOBoxNj 4101 WIDLE ROAD ëiiŸ,·siårë,·Ž¡, BAKERSFIELD CA 93313 '~ C -¡ 1ft,: Postage $ Certified Fee Postmark Here \ P ~:···i ~~:I'""I'W"P:"""""""'" Certified Mail Provides: · A mailing receipt · A unique identifier for your mail piece · A signature upon delivery · A record of delivery kept by the Postal Service for two years I Important Reminders: · Certified Mail may ONLY be combined with First-Class Mail or Priority Mail. · Certified Mail is not available for any class of international mail. · NO INSURANCE COVERAGE IS PROVIDED with Certified Mail. For valuables. please consider Insured or Registered Mail. · For an additional fee, a Return Receipt may be requested to provide proof of delivery, To obtain Return Receipt service, please complete and attach a Return Receipt (PS Form 3811) to the article and add applicable postage to cover the fee, Endorse mail piece "Return Receipt Requested". To receive a fee waiver for a duplicate return receipt, a USPS postmark on your Certified Mail receipt is required. · For an additional fee, delivery may be restricted to the addressee or addressee's authorized agent. Advise the clerk or mark the mail piece with the endorsement "Restricted Delive~ -..., , · If a postmark on the Certified ~ail receipt'is desired, please present the arti- cle at the post office for postmarking. If a postmark on the Certified Mail receipt i~_eeded, detach and affix label with postage and mail. IMPORTA.,.,ve this receipt and present it when making an inquiry. "=' \ PS Form 3800, April 2002 (Reverse) 102595-02-M-1132 FIRE CHIEF RON FRAZE ADMINISTRATIVE SERVICES 2101 "W Street Bakersfield, CA 93301 VOICE (661) 326-3941 FAX (661) 395-1349 SUPPRESSION SERVICES 2101 "W Street Bakersfield, CA 93301 VOICE (661) 326-3941 FAX (661) 395-1349 PREVENTION SERVICES FIRE SAFm SERVICES. ENV1RONIlEHTAL SERVICES 1715 Chester Ave. Bakersfield. CA 93301 VOICE (661) 326-3979 FAX (661) 326-0576 PUBLIC EDUCATION 1715 Chester Avè. Bakersfield. CA 93301 VOICE (661) 326-3696 FAX (661) 326-0576 FIRE INVESTIGATION 1715 Chester Ave. Bakersfield. CA 93301 VOICE (661) 326-3951 FAX (661)326-0576 TRAINING DfVlSION 5642 VIctor Ave. Bakersfield. CA 93308 VOICE (661) 399-4697 FAX (661) 399-5763 - . ~....., 'r; '~'?"~ - - ,~ December 2, 2002 Darrell Hardcastle P.G&E. Bakersfield Service Center 4101 Wible Rd Bakersfield, CA 93313 CERTIFIED MAIL NOTICE OF VIOLATION & SCHEDULE FOR COMPLIANCE RE: Failure to Submit/Perform Annual Maintenance on Leak Detection System Dear Underground Storage Tank Owner: Our records indicate that your annual maintenance certification on your leak detection system was past due on November 8, 2002. You are currently in violation of Section 2641 (J) of the California Code of Regulations. "Equipment and devices used to monitor underground storage tanks shall be installed, calibrated, operated and maintained in accordance with manufacturer's instructions, including routine maintenance and service checks at least once per calendar year for operability and running condition." You are hereby notified that you have thirty (30) days, January 3, 2003 to either perform or submit your annual certification to this office. Failure to comply will result in revocation of your permit to operate your underground storage system. Should you have any questions, please feel free to contact me at 661-326-3190. Sincerely, Ralph Huey Director of Prevention Services bY~ ctkû Steve Underwood Fire InspectorÆnvironmental Code Enforcement Officer Office of Environmental Services cc: Walter H. Porr Jr., Assistant City Attorney ""Y~ ~ W~ g;~.A0Pe §"~ ..Æ W~" "\ -------- ~.. ~ Uec 11 02 10:02a .. Ii /~~~ ,- '</~ Name: Organization: FAX: Phone: From: Date: Subject: Pages: e Franzen Hill e 5596881467 p. 1 Ai Franzen-Hill System Design, Conslrw:1;on &; Maintenance FACSIMILE Steve Underwood-Fire Inspector Environmental Services 661-326-0576 661-326-3979 Summer Walsh Ext. 3002 December 11, 2002 Annual Monitoring System Inspection Results 14- Including Cover Sheet Inspector Underwood: ///---,.~"'~:._.~ please find following the tèst~sults for the lQ)catil?n listed below: PG&E Bakersfield 4101 Wible Road J Bakersfield, CA / / / ank you in advance fOT your coo.B~tion and assistance. ,< Summer Walsh Ext. 3001 .......--. ....-----. -, ... e . ii .'i' ... · Dee 11 02 10:02a Franzen Hill 5596881467 p.2 'Y MONITORING SYSTEM CERTIFICATION o For Use By All Jurisdictions Within the State of Ca/ifomia AZlt'f¡ority Cited: Chapter 6.7. Health and Safety Code; Chapter 16. Division J, Title 23. California Code of Regulations This fonn must be used to document testing and servicing of monitoring equipment. A separate certification or reDort must be precared for each monitorine: svstem control panel by the teclmician who perfom1S the work. A copy of this fonn must be provided to the tank system owner/operator. The owner/operator must submit a copy of this form to the local agency regulating UST systems within 30 d¡¡ys of test date. A. General Information Facility Name: P ~ II- F' Site Address: t.( 10( uI A(¿,' /J:JAoI Ð4H6{H- City: ø~l'Íerq BId N .C ONs:'r g. 0.. 01- Zip: c¡ ~.3þ I Contact Phone No.: ( ) Date of Testing/Servicing: ~II (J IO-z... ., Facility Contact Person: MakeIModel of Monitoring System: T 10: I uAlL Tank ID: ~ (])Jt.. r;.¡ !!;t- Tank Gauging Probe. Model: C!~ c:J.1'j(. Tank Gauging Probe. Model: M A. f I ()"""'þ1inular Space or Vault Sensor. Model:V¡z: j;rU 5a.J&;)f -" ~nular ee or Vault Sensor. Model: '\/9 ðfiÚ ~u. .a'~ Trench Scnsor(s). Model: 'pI'(;; ~ÇðL,... ld"P'ipi Sum Treneb Sensor(s). Model: P'fJI c,.AI:r. .>~ CJ Fill S~nsor(s). Model: T ' Q Fill Sump cnsor(s). Model: ~chanieal Line Leak Detector. Model: Ç-;<" l:.iI-1ÇÏechanical Line Leak Detector. Model: p"JC 2J) o .ßI€'etronie Line Leak Detector. Model: 0 Electronic Line Leak Detector. Model: Ø"'Tank Overfill I High.Level Sensor. Model: 7'5t- ~ ru tr1'ãnk Overfill I High-Level Sensor. Model: T¿J JSU a Other s ecif e ui ment t e and model in Section Eon Pa e 2 . 0 Other (s ceil' e ui ment t e and model in Section E on Pa e 2 . TanklD: wASf'/F 1J/L- TanklD: o JlþJ'ank Gauging Probe. Model: 0 In-Tank Gauging Probe. Model: o--;(nnular Space or Vault Sensor. Model: t..S1 A.. 0 Annular Space or Vault Sensor. Model: ' Q Piping Sump' Trench Sensor(s). Model: 0 Piping Sump' Trench Sensor(s). Model: O· Fill Sump Sensor(s). Model: 0 Fill Sump Sensor(s). Model: o Mechanica1 Line Leak Detector. Model: 0 Mechanical Line Leak Detector. Mode!: o Electronic Line Leak Detector. Model: . 0 Electronic Line Leak Detector. Model: ~k Overfill' High-Level Sensor. Model: (..,5, A- 0 Tank Overfill I High-Lcve] Sensor. Model: :J Other s ecif' e ui ment t and model in Section Eon Pa e 2 . 0 Other 5 eci~ e ui ment t e and modcl in Section Eon Pa e 2 . fJispcnser ID: pr 01'4., t -I=- 2-- ~iS nser ID: GAJ ~o(.fð ~nser Containment Sensor(s). Model: ispenser Containment Sensor(s). Model: ::;}..ßíi~ alvc(s).· er SkEar Valve(s). s cnser Containment Float sand Chaín s . 13""Disl enser Containment Float s and Chain s). Oispenser ID: Dispenser 1D: J Dispenser Containment Sensor(s). Model: 0 Dispenser Containment Sensor(s). Model: J Shear Valve(s). 0 Shear Valve{s). J Dis nser Containment Float s and Chain s . 0 Dis enser Containment Float s and Chain s . )ispenser ID: Dispenser J D: J Dispenser Containment Sensor(s). Model: 0 Dispenser Containment Sensor(s). Model; J Shear Valve(s). ' 0 Shear Valve(s). J Dis cnser Containment' Float s and Chain s , 0 Dis enser Containment Float s and Chain s . 'IC the Cacility contains more tanks or dispensers, copy this Corm. Include inCormation Cor every tank and dispenser atlhe facility. .,... Certification - I certify that t~e equipment IdenUfied In this document was inspected/serviced in ac(ordance wIth the manufacturers' guidelines. Attached to this Certification Is Information (e.g. manufacturers' checklists) necessary fo verlCy that this InformatJoD Is correct and a Plot Plan sbowlng the layout of monitoring equipent. For any equlpmcn capable or generating such reports, I ban also attached a copy of tbe rep~eck all '!rat apply): B"System set-up Alar, history report rechnician Name (print): ~c;1 Signature: . :ertification No.: 3 c{ /3 ~esting Company Name: Fr NY 'Zf::}-J... tf (II ;¡teAddress: ¡lbDil, ~ ~~I G4-- '1})..-7V PhoneNo.:{$9 ) iJW'" Z'!77 Date of Testing/Servicing: ill It) / tJ - i!onitoring System Certification Page 1 oU 03101 " e e 5598881487 p.3 ~ Dee 11 02 10:02a Franzen Hill " F. In~ Tank Gauging I SIR Equipment: :;; (J Check this box jf tank gauging is used only for inventory controL a Check Ihis box if no tank gauging or SIR equipment is installed. This section must be completed if in-tank gauging equipment is used to perfonn leak detection monitoring. Comolete the ollowißl~ checklist: ¡;;Yý es a No· Has aU input wiring been inspected for proper entty and lennination, including testing for ground faulls? g'¥es [J No· Were all tank gauging probes visually inspected for damage and residue buildup? cr Yes [J No· Was accuracy of system product level readings tested? ta'" Yes o No· Was accuracy of system water level readings tested? Ø"'Yes (J No· Were all probes reinstalled properly? rã Yes DNa· Were all items on the equipment manufacturer's maintenance checklist completed? Ci ,þ · In the Section H, below, describe how and when tbese deficiencies were or wm be corrected. G. Line Leak Detectors (LLD): a Check this box ifLLDs are not installed. Co Ie the followln checklist: Yes (J No· o N/A For equipment start-up or annual equipment cØRcation, was a leak simulated to verify LLD perfonnance? (Check all tlrat apply) Simulated leak rate: a-3 g.p.h.; Q 0.1 g.p.h; a 0.2 g.p.h. ::J Yes Were all LLDs confinned operational and accurate within regulatory requirements? Was the testing apparatus properly calibrated? For mechanical LLDs, does'the LLD restrict product flow if it detects a leak? For electronic LLDs, does the turbine automaticaUy shut off if the LLD detects a leak? :J Yes For electronic LLDs, does the turbine automatically shut off if any portion of the monitoring system is disabled or disconnected? For electronic LLDs. does the turbine automatically shut off if any portion of the monitoring system malfunctions or fails a test? For electronic LLDs, have a1l accessible wiring connections been visually inspected? N/A No· Were all items on the equipment manufacturer's maintenance checklist completed? r In the Section H, below, describe how and wh'en these deficiencies were or will be corrected. J :J :I. Comments: ß/~..r~ .s-u~, ~.f4.¿¿¿ A:ANVÞ; ð P Il/,J~ .¿lrs-/ ~~ ~ ~tJA:F ~, tt!i1ifJI . I; Ii I, Page 3 of3 03101 '" e , " I I Dee 11 02 10:02a Franzen Hill :;' " ... ì\ lonitoring System Certification e 5596881467 p.4 '\, Site Address: UST Monitoring Site Plan I: ..:-:-: .~. t,. ;::¡" ~ . " . . f· ~".J~_.:_..':'" . .. .. .. .. .. .. .. . .. .. .. .. .. .. .. .. .. .. .. i '1 . .j. 1 I ,~ .~:~---=-_.. \" . I' . . .\. · ':. ',' .1\. ." ;j..' . . .QrJt1.;~~. . ~ !ltl.,.. · ,",,'1""'" , . . . . " · ., . . . . \. · " . . . .,. .1· . 0 '~.¡"")' . . .f.. t t"¡J,r .. ...... I I 1· ¡', : ¿ : rll: .~U,· . ,. . ./. t:l'\~f! : ~ .~.:.t,.; . ~ 'r,~i ~:{~ .. .. .~ ~ ~ , , ., .; .' '\ j ¡ ¡ ! t . . . :\. "- . . . . . \' · j' .. ¡. · L I · I' · !. , · I' I. :ß tí;;L: : : f~~f. : .. ......., ' :, :IS~jp: '.', .i . . . . . . . .~ .1 . . . . . . . . . . . . . . . . ., . ].1 : : : : : : : : : : : :' : : : : : I : .. .. .. . .. . .. .. .. .. .. .. .. .. .. .. .\. ~-''''''''-''-'''-''~''''-''''-''-' . .;. .. .. .. .. .. .. .. . .. .. .. .. .. .. .. .. .. .. .. " . . . . . . .:..,;' . . , . . . . ,~".. . . . : gf. : : : . s~: : : : : : : r ~ II~I-:f,;: . . . ., ....,.... t . . . . . ",.._ _ ............_.._.,...,J, _ , ' ,,' ." ' I ..~ : . : . : : : : 0 : : : : b<5 ~: .. .." ...........................,..~,. .. \~...'P._'t_......4.._---..-.....·_-................."":~·······";..·_~~....··· ~. .. .. . . .. .. .. .. . .. .. .. .. .. .. ,;t~ .. :' . . . . . :ð' . . . . . . . þ~~ . . . . . . . .Sir. " . . . . . . ',i.l\. . . ,." . ,. ~--_..-.--~.-... -,..,.,-"..._._~~.... . ,. . ':-O'~' . . . . . . , . . . ~-~._~.. . \ . '. ···8,····· . ðe . "\.. ........................ ---I. '\ .~ . . . . . . .¡. t .. .. .. ..~-. : A~.~~tJ. í:;: : Date map was chawn:'.!1./ 10/Ifl:::.. Instructions If you already have a diagram that shows all required information, you may include it, rather than this page, witb your Monitoring System Certification.. On your site plan, show the general layout of tanks and piping. Clearly identify locations of tbe following equipment, if installed: monitoring system control panels; sensors monitoring tank annular spaces, sumps, dispenser pans, spilt containers, or other secondary containment areas; mechanical or electronic line leak detectors; and in.tank liquid level probes (ifused for leak detection). In the space provided, note the date this Site Plan was prepared, pa.. !:t-oriL 05/00 ,- ~ e Dee 11 02 10:03a Franzen Hill " '. e 5596881467 p.5 At Franzen-Hill 8)'dQII Dcs¡p, CcIIt.uudioIIA u.¡,,_ SOURCE TEST RESULTS LEAK DETECTOR TEST F'1I1Q N_ allll AddIua Tea\in¡ Company N~ and Addrc.. f:~6 ð Ú/,I}l/¿ ø".¿ ~tct CÞ q. ~~7Y ~e of Leak Detectors or...'t.ec1 {check one} ___ %LD PIN 116036-5 ___ DLD PIN 116017-5 ~0Uh ~~ ___ ZLP PI. 116035-5 ___ PLD PIN 116030-5 FRANZEN-HILL CORPORATION 1.1.00 North J Street: Tul&re, CA 93274 WON / / I tJ/;), 'r-- service Order # ~{J/(.:> ___ BFLD (XL Mode1) PIN 116039-5 ___ BPLD PIN 116012-5 ~ SZlUAI. # IŒSILXBHCY :I::tME OPEH / G& 1lù V,r.¡Lc:. } ..Pst. ()-5JOCl~S- Mop ~ AlDI tV ;)~ ø-~ - ~ft 'LBAx lŒD1ttKG UstJ'L~S JULD psx 1),IIlIN ~ f4~f ~,V r /)/1(/ , 0... (1- - L fJ ..o~ Õ' 'Õ' , Dee 11 02 10:03a <i', to -i e Franzen Hill I ! e 5596881467 p.6 ~---- S'iSTEM ALAR!"I PAPER OUT DEC 1 Q. 2002 11: 46 Al"1 ----- SYSTEM ALARM ---__ PR [I~TER ERROR DEC 10. 2002 11:46 AM EYSTEr'1 SETUP DEC 10. 2002 11:47 AM SYSTEM U I~ ITS U.S. SYSTa1 LANGUAGE ENGLISH SYSTEI"I DATE/T(I"IE FOR/"IAT "iON DD Y'¡'IN HH :MJ1:SS xl1 ¡:'GE BAJŒRSF I ELD SERVICE CENTER 4101 "'IIBLE ROAD BAKERSFIELD.CA 93313 SHIFT TIME 1 SHIFT TIME 2 SHIFT TIME 3 SHIFT TIME 4 6:00 AM DISABLED DISABLED DISABLED TAN)~ PER TST NEEDED WRN DISABLED TANK ANt, TST NEEDED ~JRN DISABLED L1 NE RE-ENABLE METHOD PASS LINE TEST LINE PER TST NEEDED WRN DISABLED U NE ANN TST NEEDED WRN rJ I BABLED PR I NT TC VOLUI'IES ENABLED TEMP CO,.IF'ENSAT I ON VALUE (DEG F ): 60.0 STICK HEIGHT OFFSET D(SABLED DAYLIGHT SAVING TIME ENABLED START DATE APR WEEK SUN START TI!"tE 2:00 AM END DATE OCT WEEK 6 SUN END TIME 2:00 AM BYSTEt1 SECUR I TY CODE : 000000 I: r- . Il. r- CD .. ... e CXI CXI CD en 11) I: \I) I, I: I I[ II ..... ..... .... J: c: Q e N c: IV L IJ... IV (T) 0 .. 0 ... N 0 ... ... <; .' 0 Q .' : '1' :;.' 0 ~ ~ ~ ~ END * * * ~ r.,,' f' ti;;t,,, f-nJ¡ \ l'~:tj , f ,T~ARM HI STORY REPORT ~.:'~..;:1L__ c.. ~!.:i<;'!i' - ....ENSOR ALARM t, :~:n! 7: WASTE TANK r:::QTHER SENSORS L· ~ F\..IEL ALARN t:::~~tC 1 O. 2002 ::: ;':F,UEL ALARM t':tE8 6. 2002 , ;,¡,: f~'I! (~: ;f ~l*¡ 1·;'i!' 1:":'; II ~ ;¡ '" ,. END * ¡,¡ ,. * f:;;\>;i. f';:'( t <~ :;~ ~ * '" ,. * END ~ irE ,. '" * ALARI"! H I STORY REPORT ALARM HISTORY REPORT ----- SENSOR ALARM L 5;DIESEL PAN DISPENSER PAN FUEL ALARM DEC 10. 2002 9:42 AM ----- SENSOR ALARM L 3:DIESEL TANK ANNULAR SPACE FUEL ALARM DE(: 10. 2002 g: 30 Al'l FUEL ALARI"I OCT 14. 2002 10:57 ~1 FUEL ALARM OCT 10. 2002 5:48 PM FUEL ALARM APR 3. 2002 11:58 AM FUEL ALAR"" APR 3. 2002 11 :57 AM ;¡ ;¡ irE * ,. END . * * ~ * ~ ~ ~ ,. ~ END ~ ,. ~ '" ,. ALARM H I STORY REPORT ----- SENSOR ALAR!'I L 4:DIESEL TANK PIPING SUMP FUEL ALARI'I DEC 10. 2002 9: 43 At-I ALARt'l HISTORY REPORT ----- SENSOR ALARM ----- L 6:GHS PAN DISPENSER PAN FUEL ALARM ~I~ÐEC 10. 2002 9:40 AM i~1~UEL ALARM ',·}iPR 3. 2002 11 :46 AM ~. ::~ -. -;.; l>i-sETUP Df\TA WARNI NG ¡t~APR 3. 2002 11:44 AM I,,~_..", ; '" ~ ~ Dee 11 02 10:03a e IN-TANK ALARM Franzen Hi 1 '" T 3: ~ * ~ ~ ~ ~ END * ~ ~ ~ ~ ALAR,..' H I STORY REPORT ----- SENSOR ALAR,..! L l:GASOLINE TANK ANNULAR SPACE FUEL ALARM DEC 10. 2002 9:18 AM FUEL ALARM NOV 8. 2001 12:47 PM ~ ~ ~ * ~ END ~ * * * * ALARM HISTORY REPORT SENSOR ALARI"' L 2:G~SOLINE TANK PIPING SUMP FUEL ALARI"! DEC 10. 2002 9:45 AM FUEL ALARM FEE 7. 2002 12:11 PM FUEL ALARM FEB 7. 2002 12:11 PM / e i ! 5596881467 \ I ALARM HISTORY REPORT . ----- SYSTEM ALARI"' PAPER OUT AUG 1. 2002 4:12 ÿM PRINTER ERROR AUG 1. 2002 4:12 ~1 BATTERY IS OFF JAN I. 1996 8:00 AM ~ * ~ ~ ~ END ~ ~ ~ ~ ~ ALARM HISTORY REPORT ---- IN-TANK ALARM T 1 :GASOLI NE TANK OVERF I LL ALARt''! NOV 1. 2002 4 :08 ~1 SEP 30. 2002 1:52 P1"1 AUG 20. 2002 3:21 PM LOW PRODUCT ALARM DEC 5'- 2002 2:88 PM OCT 22. 2002 10:27 AM RUG 12. 2002 8:11 AM HIGH PRODUCT ALARM JUL 6. 2001 12:55 PM INVALID FUEL LEVEL JUL 31. 200 I 5: 09 Pt· DELI VERY NEEDED DEC 5. 2002 7:42 AM NOV 25. 2002 7:58 AM NOV 16. 2002 7:21 AM TAN¥. TEST ACTIVE DEC 8. 2002 1:00 AM DEC I. 2002 1:00 AM NOV 24. 2002 1: 00 AI"! ~ * ~ ~ ~ END M W W ~ ~ p.8 ALAR/"1 HISTORY REPORT ____ IN-TANK ALARM T 2:DIESEL TANK OVERFILL ALARM '3 PM BE? 7. 2002 4:2 JUN 18. 2002 3:18 PM AUG 12. 2001 9:22 AM LOW PRODUCT ALARM MAR 18. 2002 9:25 AM FEB 8. 2001 2:56 PM HIGH PRODUCT ALARI"1 SEP 7. 2002 4:30 PM PROBE OUT MAR 18. 2002 9:25 AM MAR 1 8. 2002 9: 07 AM - DEL I VERI, NEEDED MAR 18. 2002 9:25 AM MAR 18. 2002 9:21 AM MAR 18. 2002 9:07 AM MAX PRODUCT ALARM SE? 7. 2002 4:49 PM TANK TEST ACTIVE DEC 8. 2002 1:00 AM DEC 1. 2002 1:00 AM NOV 24. 2002 1:00 AM w ~ ~ ~ ~ END ~ w . w ~ " 'J' ~ , Dee 11 02 10:03a e Franzen Hill '" .. T 2:D1ESEL TANI< INVENTORY INCREASE INCREASE STRRT DEC 5. 2002 4:.:i3 Pt"1 VOLUt'1E HE lGHT "',lATER TEMP 6103 GALS m 55.54 INCHES 0.8c:1 INCHES 79.4 DEG F I ! INCREASE END DEC 5. 2002 4: 56 PI"I VOLUME HEIGHT WATER TE~'IF' 8639 GALS '" 75.98 INCHES 0.84 INCHES 76.9 DEG F GROSS INCREASE'" 2536 Te: NET INCREASE= 2523 T 1 :GASOLINE TANK INVENTORY INCREASE I NCREHSE START DEC 5. 2002 4: 45 Pt'1 VOLUME HEIGHT WATER TEMF' 1902 GALS 23.24 INCHES .. '0.92 INCHES 81 .3 DEG F INCREASE END DEC 5. 2002 5:06 PI"I VOLUME HEIGHT WATER TEMP 7999 GALS = 70.41 INCHES 0.91 INCHES 70.2 DEG F GROSS INCREASE= 6097 TC NET JNCREASE.. 6068 e 5596881467 ----- SENSOR ALAR,"' ----- L 1 : GASOLI NE TANK . ANNULAR SPACE FUEL ALARI"I DEC 10.2002 9:18 AM ----- SENSOR ALARM L 3: D! ESEL TAt-U: ANNULAR SPACE FUEL ALARM DEC 10. 2002 9:80 AM ----- SENSOR ALAR"" L 6:GAS PAN DISPENSER PAN FUEL ALARM DEC 10. 2002 9:40 AM ----- SENSOR ALARt1 L 5:DtESEL PAN DISPENSER PAN FUEL ALARM DEC 10.2002 9:42 AI1 p.9 ----- SENSOR ALARr.., L 4:DIESEL TMNK ' F'IPIN(; SUMP FUEL ALAR!"! DEÇ 1 Q. 2002 9: 43 Al"l ----- SENSOR ALARM L 2: GASi)L! NE THNK PI PING SUr"If' FUEL ALARI1 DEC 10. 2002 9:45 AM ----- SENSOR ALARM L 7:WASTE TANK OTHER SENSORS FUEL ALAR!'I DEC 10. 2002 11 :33 Al'l ----- SENSOR ALARI1 ----- L 8:HJGH LEVEL WASTE TK OTHER SENSORS FUEL ALARM DEC 10. 2002 11:34 AM " '. - > ~ Franzen Hill Dee 11 02 10:04a ~ ALARM HISTORY REPORT ----- SENSOR ALARI'1 L 1 :GASOLINE TANK ANNULAR SPACE FUEL ALARM DEC 10. 2002 9:18 AM FUEL ALAR¡-] NOV 8. 2001 12:47 pt-, ~ ~ ~ * ~ END * w ~ * ~ ALARM HISTORY REPORT ----- SENSOR ALARM L 2: GASOLl NE TANK PIPING SUMP FUEL ALARM DEC 10. 2002 '3:,45 Ai"! FUEL ALARM FEB 7. 2002 12: 11 Pl1 FUEL ALARI"! FEB 7. 2002 12: 11 PM ~ ~ ~ . ~ END ~ ~ ~ * ~ e I I ! e 5596881467 p.l0 ALARM HISTORY REPORT ALARM HISTORY REPORT ----- SENSOR ALARM L 3:DIESEL TANK ANNULAR SPACE FUEL ALAR/"I DEC 10. 2002 9:30 At1 fUEL ALARI' OCT' 1 4. 2002 10: 57 AI1 FUEL AL~RM OCT 10. 2002 5: 48 PI'1 * ~ ~ ~ ~ END ~ ~ ~ ~ ~ ALARI1 HISTORY REPORT ----- SENSOR ALARM L 4:DIESEL TANK P IPI NG SUI'I? FUEL ALARM DEC 10. 2002 9:43 AM FUEL AL.ARM FES 7. 2002 12:10 PM FUEL ALAR!"! FES 7. 2002 12:02 PM * ~ * * ~ END * M M ~ ~ ----- SENSOR ALARM L 5:DIESEL PAN D H3PENSER PAN FUEL ALARr1 DEC 10. 2002 9:42 AM FUEL ALARI1 APR 3. 2002 11:58 AM fUEL ALARM F\PR 3. :2002 11:57 AM w w w w ~ END * ~ ~ ~ * ALAR!"I HISTORV REPORT ----- SENSOR ALAR¡-' L 6:GAS PAN DISPENSER PAN FUEL ALAR¡-! DEC 10. 2002 9:40 AM FUEL ALARr-1 APR 3. 2002 11:46 AM SETUP DATA WARNING APR :3. 2002 11 :44 AM ~ ~ ~ ~ MEND * M M ~ * ALARM HISTORV REPORT ----- SENSOR ALAR¡-I L 7:WASTE TANK OTHER SENSORS FUEL i'lLARM DEC 10. 2002 11:33 At'! FUEL ALARI"I FEB 6. 2002 3:05 PI'! I, I nn I N-T~NK ALAR¡'! ----, RECONCILIATION SETUP OUTPUT RELAY SETuP , I I ----- - - - .... - - - - - - - - - - RLARM HISTORY REpORT ----- IN-TANK ALARM T 2:DIESEL TANK OVERF 1 LL ALARl1 SEP 7. 2002 4:29 PM JUN 18. 2002 3:18 Pl1 AUG'12. 2001 9:22 ~I R 1 :POSITIVE SHUT OFF TYPE: NOI1ENTARY NORI'IALLY OPEN AUTOI"1HTIG DAILY CLOSING· TIME: 2:00 AM PERIODIC RECONCILIATION MODE: MONTHLY TEMP COMPENSATION STANDARD BLS SLOT FUEL 11ET£R TAN)' - - - - - - - - - - - - TANK MAP EMPTY LOW PRODUCT ALARM !'IAR lB. 2002 9:25 AM FES 8. 2001 2:56 PM HIGH PRODUCT ALHRI"I SE? 7. 2002 4:30 PM PROBE OUT MAR 18. 2002 9:25 AM !"fAR 18. 2002 9:07 AI" I' " 'i I' , I Ll QUI D SENSOR ALMS L 1 :FUEL ALARM L 2: FUEL ALARM L 3 :FUEL ALARI'1 L . 4 : FUEL ALARI" L 5 :FUEL ALARM L 6:FUEL ALARM R_2: TYPE: STANDARD NORMALLY OPEN - NO ALARM ASSIGNMENTS - It I' I: Ii II ¡ I, DEL I VERY NEEDED MAR 18. 2002 9:25 ~1 MAR 18. 2002 9:21 ~1 MAR 18, 2002 9: 07 At-I MAX PRODUCT ALARM SEP 7, 2002 4:49 ÞH ALARM HISTO~! REPORT ----- SYSTEM ALARM ----- . PAPER OUT .DEC LO, 2002 11:46 AM PRINTER ERROR DEC 10. 2002 11:46 AM BATTERY IS OFF JAN 1, 1996 8:00 AM TAN}~ TEST AGT I VE DEC 8. 2002 1: aOAtl DEG 1. 2002 1 :00 AM NOV 24. 2002 1:00 AM ALARM HISTORY REPORT ---- IN-TANK ALARr1 T 1 :GASOLI NE TANI< OIJERF I LL ALAR~'l NOV I. 2002 4:08 PM SEP 30. 2002 1:52 PM AUG 20. 2002 3:21 PM LOW PRODUCT ALARM [lEe 5. 2002 2:38 PI1 OCT 22. 2002 10:27 AI1 AUG 1 2. 2002 8: 11 AI1 HIGH PRODUCT ALAR/'I JUL 6. 2001 12:55 PH INVALID FUEL LEVEL JUL 31. 2001 5:09 PH . ~ . . ~ END ~ *.. ~ ~ I: , ¡: I ,i ,I 'I * . ~ * Ä END ~ . * ~ * DEL I VERY N£EIiED DEG 5 . 2002 7 : 42 Ar-I NOV 25. 2002 7 : 58 A~'I NOV 16. 2002 7:21 AN I: TANK, TEST ACT! VE DEC 8. 2002 1 :00 AM DEe 1. 2002 1: 00 Al'l NOV 24. 2002 1 :00 AM ALARM HISTORY RE?ORT I , I I .._:-1 '!) ,! tj (i) /II ~.¡; 0 'i. ... .... 0 N .... 0 0 ~ DI 'T ~e N /II :J ::r ... .... .... (II (II CD ~- ... ~ en -J ." .... ... ~ '-!''':" '~, ~ Dee 11 02 10:04a Franzen Hill .. COMI1UNICATIONS SETUP ------ - - - - :IORT SETTI NGS : NONE FOUND RS-232 END OF MESSAGE DISABLED "'-MI~K :i:I¡:;TUP - - - - - - T l:GASOLINE TANK PRODUCT CODE : 1 THERr1AL (;OEFF : .000700 TANK DIAMETER 96.00 TANK PROFILE J PT FULL VOL 10177 FLOAT SIZE: 4.0 IN, WATER ~JARNI NG : 3.0 HIGH WATER LI/"IIT: 4.0 MAX OR LABEL VOL: 10177 OVERFILL LIMIT 90% 9159 HIGH PRODUCT 95% 9668 DEL I VERY L 1/"11 T 25~ó 2544 LOW PRODUCT : 2000 LEAK ALAR'''! L I M IT : 99 SUDDEN LOSS LIMIT: 99 TANK, TILT : 0.00 MANIFOLDED TANKS Tit: NONE LEA}: M I N PER I OD Ie; 0·' '. o LEAt( HI N ANNUAL 0·,' '. PERIODIC TEST TYPE STANDARD ANNUAL TEST FAIL ALARM DISABLED PERIOD/C 1'EST FAIL ALARr"! DISABLED GROSS TEST FAIL ALARI'1 D I SAELED ANN TEST AVERAGINI~: OFF PER TEST AVERAGING: OFF TANK TEST NOTIFY: ON TNK TST SIPHON BREMK:OFF DELIVERY DELAY' 3 ""IN - o e 5596881467 p.12 LèH~ 'W~, _ _ - - - E-~K~L: : ~LL TANK- TESTWÞo 1 . SUN . 1 '00 AI"! START TA+~E : 0 .20 GAL/HR TEST R . 3 HOURS DURATl~NLu ST'OP'DISABLED TST EA... 1 -' LEA}' TEST REPORT FORMALl"IAT . NOR T' 2:DIESEL T;':¡NJ< PRODUCT CODE THERNAL COEFF TANK D II~r"lETER TANK PROFILE FULL VOL :2 : . 000470 : 96.00 1 PT IOJ77 / I I FLOAT SIZE: 4.0 IN. WATER I.JARN LNG HIGH WATER LIMIT: M~~ OR LABEL VOL: OVERFILL LII"IIT HIGH PRODUCT DELIVERY LIMIT 3.0 4.0 10177 90~ó 9159 95% 9668 ?5~¿ 2544 LOW PRODUCT . LEAK ALARI'1 LIMIT: SUDDEN LOSS LIMIT: TANK Tl LT MANIFOLDED TANKS T: NONE 2000 99 99 0.00 LEAK MIN PERIODIC: 0% o LEAJ~ 1"1 I N ANNUAL 0% o ÞERIODI8 TEST TYPE STANDARD ANNUAL TEST FAIL ALAI\1-¡ DISABLED PERIODIC TEST FAIL ALARM DISABLED GROSS TEST FAlL ALARM DISABLED ANN TEST AVERAG I NO : OFF PER TEST AVERAGING; OFF TANK TEST NOTIFY: ON TNK TST SIPHON BREAK:OFF DELI VERY DELAY 3 1'1 I N LIQUID SENSOR_S:T~P_ - - - - L l:GASOLINE T~~~ FLOAT) b~iË~b~~E:{~~~ULHR SPACE L 2:GASOLIN~ TA~ FLOAT) TRI-STATE. (SpII~~ NG SU"'P CATEGORY . L 3:DIESEL TP,NK E FLOAT> 6~+Ë~¿;'~E : (~M~ttAR SPACE L 4:D(ESEL(ã~~~LE FLOAT) TRI -STATE "'I PI NG SUMP CATEGORY : ~ L 5: DIESEL ~AN~ E FLOAT} ~Ä+Ë~~~~·E: (~i~P~NSER :IAN L 6:~AS PA~SINGLE FLOAT) 6~+Ë~¿~~E: DISPENSER PAN L 7:~,IASTE TANK NORt'IALL Y CLOS¡;:D FiS CATEGORY : OTHER SENSO . L e:HIGH LEVEL WASTE TK ~~~~~~ ~Lg~~~R SENSORS OUTPUT RELAY SETUP - - - - - - - - - . R 1 :P08ITlVE SHUT OFF TVPE: MOMENTARY 1'40Rr1ALL Y OPEN LIQUID SENSOR ALMS L 1: FUEL ALARM L 2: FUEL ALARM L 3:FUEL ALARM L 4: FUEL ALAR/'I L 5:FUEL ALARM L 6: FUEL ALARI'I R 2: TYPE: S'TfiNDARD NORl'lALL'i OPEN -II{) ALARr',¡ ASSI GNl1ENTS - ALARM HISTO~{ REPORT ----- SVSTEM ALARI'I --..-- PAPER OlJI' . DEC 10. 2002 11 :46 AM PRINTER ERROR DEe: 10. 2002 11: 46 A/'I BATTERY IS OFF JAN L 1996 B:OO At'l l ~ ~ ~ ~ ~ END ~ ~ ~ ~ ~ i I I I, AL.ARI"I HI 8TOR'I REPORT t; I N-TANJ{ ALARl1 ____ tD <;- o T 2:DIEBEL TANK ~ RECONCILIATION SETUP - - - - - - - - - - AUTONATIG LlMIL'.' CLOSING TlI"E:2:00 AM PERJODIG RECONCILIATION MOIJE: 1'10NTHLY TEM~ COMPENSATION 5'TANDARD BUS SLOT FUEL I'IET£R TANK OVERFILL ALARM SEP 7, 2002 4:29fPM JUN 18. 2002 3:18 PM AUG 12. 2001 9:22 AM LOW PRODUCT ALARM MAR 18. 2002 9:25 ~1 FES 8. 2001 2:56 PM HIGH PRODUCT ALARM SEP 7. 2002 4:30 PI'! PROBE OUT t~R 18. 2002 9:25 AM I'IAR 18. 2002 9: 07 AM - - - - - - -- - - - - ¡' TANK MAP EMPTY ALARM HISTORY REPORT ---- IN-TANK ALARM ----- DELIVERY NEEDED MAR 18. 2002 9:25 AN MAR lB. 2002 9:21 AM MAR 18. 2002 9:07 ~1 MAX PRODUCT ALARM SEP 7. 2002 4:49 PM o T I:GASOLINE TANK OVERF I LL ALAR/"I NOV I. 2002 4:08 ~1 SEP 30. 2002 1: 52 P/1 AUG 20, 2002 3: 21 Pl1 LOW PRODUCT ALARM DEC 5. 2002 2:38 Pl1 OCT 22. 2002 10:27 AM AUG 12. 2002 8:11 ~1 TANK TEST A(;Tl VE DEe 8. 2002 1 :00 AN DEG I, 2002 1 :00 AM NOV 24. 2002 1:00 AM "i; ~d~ ~ . :.i;. >- ... ... 0, N ... 0 .. 0 ~ III 'T , e III :J N tD :J :I: ..' .... .... (11 (11 ~e IX) ... ~ ~ ~ ~ ~ ~ EtID ~ ~ ~ ~ ~ ~ HIGH PRODUCT ALARM JUL 6. 2001 12:55 Pl1 INVALID FUEL LEVEL JUL 31. 2001 5:09 ~1 DELIVERY NEEDED DEe 5. 2002 7:42 AM NOV 25. 2002 7:58 AM NOV 16. 2002 7:21 AM TANI~ TEST ACT I VE DEC 8. 2002 1 :00 AM DEC 1, 2002 1:00 AM NOV 24. 2002 1 :00 AM ." ALARM HISTORY REPORT ~ w IN-TANK ALARM ----- T 3: ----- SENSOR ALAR~ L 6: GAf:~ PAN DISPENSER Ç,::;N FUEL ÄLARt"! FE8 7. 2002 12:01 M1 SErt30F: réiLAF:t"j L 5:DIESEL PAt, D I f:;PENSEF: PAf"j FUEL ALARt"l FEB 7. 2002 12:01 PM /,-' pOOl_A\., ., "'~-_"---"*" . :3EN:30R AUWf"l L 4:DIESEL TANK PIP I t'K; S Ur"lI' FUEL ALAF:I"] FER 7. 2002 12:02 PM ----- SENSOR ALARM L 2: GAf:;OL I I'.JE TAI',n: rIP I NG SUi"lP FUEL ALARf"] FEB 7. 2602 12:04 PM ---~{ SENSOR ALARM L 6-~HE l'ril,J' ,,-'...----.-= - [I j ~3P£M=;ER ¡:AI, FUEL ALARI'" FEB 7. 2002 12:04 PM ------ :3EN:::;OF: ALARf"l L 6 :GAS PAN DI~3PENSER PAN FUEL ALAR!"l FEB 7. 2002 12:05 H1 l ----- SENSOR ALARM L 4: DIEBEL TAt',n~ PIP 1 NG SUf'1P FUEL ALARI"l FEB 7. 2002 12:10 PM '- . j," = ----- SENSOR ALARM L 2:GABOL1NE TANK Pl PING sur"IP FUEL ALARf"l FEB 7. 2002 12: 11 PI"] . ~, I'·t,· ,', \. . ",'\ \, --~-~ 'št(\:2,¿?, I L 2:GASOLINE T ¡ P r PING SUt"'lP FUEL ALARt., r:'t:'P f""J "'-11- ~L~" --------je., :. ..... " ........ -,~~ - . CITY OF BAK4SFIELD OFFICE OF ENVIRONMENTAL SERVICES 1715 Chester Ave., Bakersfield, CA (661) 326-3979 Facility INSPECTION RECORD POST CARD AT JOB SITE Owner Address Address City,Zip. City, Zip Phone No, Pennit # INSTRUCTIONS: Please call for an inspector only when each group of inspections with the same number are ready, They will run in consecutive order beginning with number I, DO NOT cover work for any numbered group until all items in that group are signed ofT by the Pennitting Authority. Following these instructions will reduce the number of required inspection visits and therefore prevent assessment of additional fees. TANKS AND BACKFILL INSPECTION DATE INSPECTOR Backfill ofTank(s) Spark Test Certification or Manufactures Method Cathodic Protection of Tank(s) Piping & Raceway w/Collc~ction Sump Corrosion Protection of Piping, Joints. Fill Pipe Electrical Isolation of Piping From Tank(s) Cathodic Protection System-Piping Dispenser Pan I"J~'O'L SECONDARY CONTAINMENT, OVERFILL PROTECTION, LEAK DETECTION Liner Installation - Tank(s) Liner Installation - Piping Vault With Product Compatible Sealer Level Gauges or Sensors, Float Vent Valves Product Compatible Fill Box(es) ---.--."- Product Line Leak Detector(s) Leak Detector(s) for Annual Space-D,W, Tank(s) Monitoring Well(s)/Sump(s) - H20 Test t -J J '0 £. JJl Leak Detection Device(s) for Vadose/Groundwater Spill Prevention Boxes ~' 'ì I /1,. -¿, I 0 "L S~U. , ( FINAL / Monitoring Wells, Caps & Locks Ó~ 2 /., /0 7...- ,.tl¡ .', Fill Box Lock , Monitoring Requirements Type ~<':> "3.~a Authorization for Fuel Drop CONTR,ACTOR Frrlt, ~ / ¡-I, lr I LICENSE # CONTACT /;) ,-1 dW\c. ~ ¡,air€; (:)V\ PHONE # · . CITY OF BAKERSFIELD FIRE DEPARTMENT OFFICE OF ENVIRONMENTAL SERVICES UNIFIED PROGRAM INSPECTION CHECKLIST 1715 Chester Ave., 3rd f;'loor, Bakersfield, CA 93301 FACILITY NAME p. ~ 't-~ ADDRESS 410' f l FACILITY CONTACT INSPECTION TIME ad. INSPECTION DATE 'lla.J 0 { PHONE NO. BUSINESS 10 NO. 15-210- NUMBER OF EMPLOYEES Section I: Business Plan and Inventory Program o Routine ~ Combined o Joint Agency o Multi-Agency o Complaint ORe-inspection OPERA TION C V COMMENTS Appropriate permit on hand ,/ Business plan contact information accurate ,/ Visible address V ~ Correct occupancy v ",. Veri fication of inventory materials 1/ Verification of quantities ,/ Verification of location /' V .-- Proper segregation of material Verification of MSDS availability V" ~ .,.. ..-- Verification of Haz Mat training Veri fication of abatement suppl ies and procedures Y' " ..-- Emergency procedures adequate ;/ Containers ,Properly labeled ,/ Housekeeping UÑ I úØJ;.PrL- WI'k:''TE ç.,o1tðGG ,/ 'r~ '60>< V56:> U6:.-¿.ffTußð> Fire Protection Ý Site Diagram r,\dequate & On Hand ./ C=Compliance V=Violation Any hazardous waste on site?: ;8Íres 0 No Explain: g/.~AJd&lX Business Site Responsible Party Questions regarding this inspection? Please call us at (661) 326-3979 White - Env, Svcs, Yellow - Station Copy Pink - Business Copy Inspector: W /;.J'GS . CITY OF BAKERSFIELD FIRE DEPARTMENT OFFICE OF ENVIRONMENTAL SERVICES UNIFIED PROGRAM INSPECTION CHECKLIST 1715 Chester Ave., 3rd Floor, Bakersfield, CA 93301 INSPECTION DATE aÄ,/c;, FACILITY NAME .? ~"é Sc../lJ'L6 cL.A../\6/L-- Section 4: Hazardous Waste Generator Program EPAID# c:.Þo c¡gl 310l"1g o Routine %-combined o Joint Agency o Multi-Agency o Complaint ORe-inspection i OPERATION C V COMMENTS Hazardous waste determination has been made ¡/ Áic C7C-1\o'LS Cl<-' . EPA ill Number (Phone: 916-324-1781 to obtain EP A ill #) / Authorized for waste treatment and/or storage IIV Ä Reported release, fire, or explosion within 15 days of occurrence ,.J 'A Established or maintains a contingency plan and training V Hazardous waste accumulation time frames V Containers in good condition and not leaking Iv Containers are compatible with the hazardous waste V Containers are kept closed when not in use V Weekly inspection of storage area V Ignitable/reactive waste located at least 50 feet from property line ¡J (A. Secondary containment provided ,/ Conducts daily inspecti?n of tanks IV r~ 1 Used oil not contaminated with other hazardous waste ¡/ Proper management of lead acid batteries including labels r/ Proper management of used oil filters V Transports hazardous waste with completed manifest V Sends manifest copies to DTSC V Retains manifests for 3 years V Retains hazardous waste analysis for 3 years 1/ Retains copies of used oil receipts for 3 years 1/ Determines if waste is restricted from land disposal Iv C=Compliance V=Violation ~~1/ad Inspector: Office of Environmental Services (661) 326-3979 White - Env, Svcs, Business Site Responsible Party Pink - Business Copy I~ V;. .r BFD HAZ MAT ~} 11/05/01 12:18 4. J26 0576 liD 002 P....1t No. ß1:~ f) "1' I I CITY OF BAKERSFIELD 7 J. ~z?J '? 7' , OFFICE OF ENVIRONMENTAL SERVICES 1715 Chester Ave., Bakersfield, CA (661) 326-3979 - PERMIT APPLICATION TO CONSTRUCTIMODIFY UNDERGROUND STORAGE TANK TYPE OF APPLICA 110N (CHECK) [ ]NEW FACILITY DQMODIFICATION OF FACILITY []NEW TANK [NSTALLATION AT EXISTING FACILITY STARTING DA TE~~ /2 0 ~ 1 FACILITY NAME & Sere Ctr. FACILITY ADDRESS 4101 Wible Lane TYPE OF BUS[NESS Pnw~r' rnmp:¡Jny TANK OWNER pr: ~ J: ADDRESS 555 Florin Perkin~ Rd CONTRACTOR Fr'="n7~n-l-liII ADDRESS 110n N I Str"'~t PHONE NO. ~~q ~RR-,q77 WORKMAN COMP NO. 442010ROO BRIEFLY DESCRIBE THE WORK TO BE DONE PROPOSED COMPLETION DATE 11/30/01 EXISTING FACILITY PERMIT NO. CIT'( Ba kersfield ZIP CODE 93313 APN# PHONE NO. 707 423-241':; CITY S~cr~mento ZIP CODE C)r;R2~ CA LICENSE NO. lo.mZ CITY Tulare ZlPCODE93274 BAKERSFIELD CITY BUSINESS LICENSE NO. [NSURER . r . ~\f'~ . WATER TO FAClL Y PROVIDED BY DEP,TH TO GROUND WATER SOIL TYPE EXPECTED AT SITE NO. OF TANKS TO BE INSTALLED n ARE THEY FOR MOTOR FUEL YES NO SPILL PREVENTION CONTROL AND COUNTER MEASURES PLAN ON FILE 'X YES NO SEctION FOR M MOR FUEL THE APPLICANT HAS RECEIVED. UNDERST ANDS. AND WILL COMPLY WITH THE ATTACHED CONDITIONS OF THIS PERMIT AND ANY OT HER ST A TEe LOCAL AND FEDERAL REGULATIONS. COMP LETED UNDER PENALTY OF PERJURY. AND TO THE BEST TANK NO. 1 2 VOLUME 10,000 10.000 TANK NO. VOLUME l APPUCA!I<>N ,D~TE .' " UNLEADED X REGULAR PREMIUM DIESEL AVIATION )( SECTION FOR NON MOTOR FUEL STORACE TANKS CHEMICAL STORED (NO BRAND NAME) CAS NO. (IF KNOWN) CHEMICAL PREVIOUSLY STORED FOR OFFICIAL USE ONLY , ' ' 'FACnn'YNO. NO.OPT:ANKS FEES S .' " , ::'1 Bob J _ Hill APPLICANT NAME (PRINT) TIßS APPLICATION BECOMES A PERMIT WHEN APPROVED Jan 08 02 05:15p (~V -C v\¡\ ;. - VJ> \~, ~\... JC?£' ~" lÅ. \ ()\ ~/ Franzen Hill . 6851,,!-60 1467 . p. 1 / FRANZEN-HILL CORPORATION 1100 North J Street Tulare, California 93274 (559) 688-2977 / FAX (559) 688-1467 LETTER OF TRANSMITTAL TO:_Bakersfield Fire Dept. _Bakersfield, CA A TTN: _Steve Underwood Fx: 661 326-0576 WE ARE SENDING YOU 0 Attached via: 0 U.S. Mail Date: _1/8/02 Job No: _01-1001 Re: _PG & E Bakersfield X FAX X Letter o Specifications o Change Order o Plans X Drawings o R.F.I. o Submittal Pack o Sub-Contract o Warranty Info. o Contract o Test Results o Other - See Below COPIES DATE DESCRIPTION 1 1/8/02 Letter 1 1/8/02 Drawina THESE ARE TRANSMITTED as checked below: o For approval X For your use o As requested o For review o Return -..:... corrected prints o FOR BIDS DUE 20 o PRINTS RETURNED AFTER LOAN TO US o Signature and Return by: o COMMENTS: _Please contact James Larson if you have any questions at ext. 3026. Thank you. COpy TO:_PG & E File SIGNED:_Maryanne Camin, Construction Assistant !:\MY FILESIFORMSIL 1RTRANS,doc Jan 08 02 05:15p Franzen Hill 6851460 1467 p.2 ~ -- . tþ ~)) ~ Franzen-Hill Fueling Facilities System Design, Construction & Maintenance California Licensed Contractor No, 304147 January 8, 2002 Steve Underwood Bakersfield Fire Dept. Environmental Services 1 715 Chester Avenue Bakersfield, CA 93301 Dear Steve: We did a test on existing secondary piping at PO & E site. Found clamshell glue separation. Instead of repairing, we will install 1 12" Environ GeoFlex Double Wall Piping. Site plan included. Sincerely, .Jc~ V'V\...u Wl-'L.-Jtl, L I \Ì'\.C James Larson Job 'Foreman JL/mc Enclosure C/ File, PO & E Bakersfield 1100 North J Street, Tulare, California 9327 rI/559-688-2977 / 800-655-3436 / 559-588-1457 FAX .wow} r.Jnhill ,com I franhill@lightspeed,net I Jan 08 02 05:15p Franzen Hill r. e '.€ .; ? c.;, ~ E 8; ~ ,_c-~ ~ ~c.. \ \J L. \0'\ w~ Þ \e.. t?-~~ ß ft)'-- ~)l. ~ +' c.~, \J 70\ =*' ð\-\OO' a F", ,\ , ",_~._. j" ,,' . I 6851460 1467 p.3 . O~\.M("~ V AfOIl. Qf',\\ I ¡yv. ' \'" . / 11/05/01 12:18 '5'6.26 0576 BFD HAZ MAT DIV"'; ... iii! 002 P.....ItN..fSf.>D"111 I CITY OF BAKERSFIELD 71 f------z"3 071 ; OFFICE OF ENVIRONMENTAL SERVICES 1715 Chester Ave., Bakersfield, CA (661) 326-3979 PERMIT APPLICATION TO CONSTRUCTIMODIFY UNDERGROUND STORAGE TANK TYPE OF APPLICATION (CHECK) [ ]NEW FACILITY [)qMODIFICATION OF FACILITY []NEW TANK INSTALLATION AT EXISTING FACILITY STARTING DATE p~ /2 0 ~ 1 ' PROPOSED COMP LETION DATE 11 /30 /01 FACILITY NAME & Ser. Ctr. EXISTING FACILITY PERMIT NO. FACILlTYADDRESS4101 Wible Lane CITY Bakersfield ZIP CODE 93313 TYPE OF BUSINESS Powpr rnrop~ ny APN # TANK OWNER PC: ~ ~ PHONE NO. 707 423-2435 ADDRESS 555 Florin Perkin!'; Rd CITY Sr¡r:rr¡mento ZIPCODE <)5R26 CONTRACTOR Fr;:tn7pn--Hill CALICENSENO. 30414¡ ADDRESS 1'00 N I 5treøt CITY Tulare ZIP CODE 9327 PHONE NO. r; Ii <) 6 R R- ? q 77 BAKERSFIELD CITY BUSINESS LICENSE NO. WORKMAN,COMPNO. g42010ROO INSURER Gulf Underwriters Ins. Co. BRIEFLY DESCRIBE THE WORK TO BE DONE Install dispenser pans with liquid sensor vnrl n~w CAR~ o"er spill. r¡nd vr¡por r¡dr¡ptor. WATER TO FACILITY PROVIDED BY DEPTH TO GROUND WATER SOIL TYPE EXPECTED AT SITE NO. OF TANKS TO BE INST ALLED 0 ARE THEY FOR MOTOR FUEL YES NO SPILL PREVENTION CONTROL AND COUNTER MEASURES PLAN ON FILE X YES NO SECTION FOR MOTOR FUEL TANK NO. 1 2 VOLUME 10.000 10.000 UNLEADED X REGULAR PREMIUM DIESEL AVIATION - X - SECTION FOR NON M OToa FUEL STORAGE TANKS TANK NO. VOLUME CHEMICAL STORED (NO BRAND NAME) CAS NO. (IF KNOWN) CHEMICAL PREVIOUSLY STORED FOR OFFICIAL USE ONLY l APPUCATIONDATE' . , FACILlTYNO. NO. OF TANKS FEES $ '1 THE APPLICANT HAS RECEIVED, UNDERST ANDS, AND WILL COMPLY WITH THE ATTACHED CONDITIONS OF THIS PERMIT AND ANY OT HER ST ATE, LOCAL AND FEDERAL REGULATIONS. TIt'F lIAS BEEN COMP LEfED UNDER PENALTY OF PERJURY. AND TO THE BEST TRU D~O f.: Bob J. Hill APPROVED BY; APPLICANT NAME (PRINT) 11~1 APPLICANT SIGNATURE TIDS APPLICATION BECOMES A PERMIT WHEN APPROVED r.;' ~ Nov 24 '01 05: 29p ,. , ! \.~ '1\ Freen Hill 559-688 1467 . p.3 MONITORING SYSTEM CERTIFICATION For Use By All Jurisdictiol1s Within the State afCalifornia Authority Cited: Chapter 6.7, Health alld Safety c;,ode; Chapter /6, Division 3, Title 23, California Code of Regulations This form must be used to document testing and servicing of monitoring equipment. A separate certification or report must be prepared for each monitoring system cantTol Danel by the technician who perfonlls the work. A copy of this form must be provided to the tank system owner/openÜor. The owner/operator must submit a copy of this foml to the local agency regulating UST systems within 30 days oftest date. A. General Information Facility Name: P G' IE - R~i..lcer 5'¡:¡ e./d S·t!!. ,¿II é-t? C61./'I-e¡- Bldg. No.: Site Address: q It) ( tl./, 61-e rcl; City: ¡/~i.Æ~j'-;.¡:;ek( Zip: 133/3' Facility Contáct Person: b Ú Î r e., I t Ii Cot j.^ cl CA. s thz Contact Phone No.: (b{;./ )?i 99" S "1/ 3 MakeIModel of Monitoring System: Veeclé.r /2ty~T" T¿ S '. ~ 51") Date of Testing/Servicing: //I-.J{JO/ B. Inventory of Equipment Tested/Certified Check,the a ro riate boxes to indicate s eeific e ul ment ins ected/serviced: Tank ID; t!)¡;; --~- O()¡¿J71 '-OaJ/- (jNI-e:Q..c(&~( Tank ID: - In-Tank Gauging Probe. Model: 79'( 0 In-Tank Gauging Probe. Model: 'Ø Annular Space or Vault Sensor. Model: 0 Annular Space or Vault Sensor. Model: 'já. Piping Sump / Trench Sensor( s). Model; 0 Piping Sump / Trench Sensor(s), Mode!: o Fill Sump Sensor(s). Model: 0 Fill Sump Sensor(s). Model: )ii( Mechanical Line Leak Detec[(,r. Model: I. 0 Mechanical Line Leak Detector, Model: o Electronic Line Leak Detector Model: 0 Electronic Line Leak Detector. Model; þí Tank Overfill/ High-Level Sensor. Model: oþ i)..! 6/ 56 0 Tank Overfill / High-Level Sensor. Model: a Other s ecif e ui ment type and model in Section Eon Pa e 2). 0 Other (s ecif e ui ment t e and model in Section Eon Pa e 2. Tank ID: Ð/'., -Ôa:)- ðð/07/-0CJ02-- ,-,~ TankID: 1iÍ In-Tank Gauging Probe. Model: 0 In-Tank Gauging Probe. Model; ':&1: Annular Space or Vault Sensol, Model; 0 Annular Space or Vault Sensor. Model: ;Iil...Piping Sump / Trench Sensor(s). Model.: 0 Piping Sump / Trench Sensor(s). Model: 0. Fill Sump Scnsor(s). Model; a Fill Sump Sensor(s). Model: J(Mechanical Line Leak Detector, Model: JJed.Joi' Ir~T IIb·~ a Mechanical Line Leak- Detector. Model: o Electronic Line Leak Detector. Model: 0 Electronic Line Leak Detector, Model: '§'t Tank Overfill/ High-Level Sensor. Model: ðp t~ (,/ Sl) 0 Tank Overfill / High-Level Sensor. Model: o Other s ecif e ui ment type ;lnd model in Section Eon Pa e 2 . 0 Other (s ecif e ui ment t e and model in Section E on Pa e 2 . Dispenser ID: ()¡V let.-cled t 1 'Þ- Dispenser ID: o Dispenser Containment Sensor(~s). Model: 0 Dispenser Containment Sensor(s). Model: ~Shcar Valve(s). a Shear Valve(s). o Dis cnser Containment Float(s! and Chain s). 0 Dis enscr Containment Float(s and Chain s), Dispenser ID: () / e s e i ~:: f rI Dispenser ID: o Dispenser Containment Sensor(s). Model: 0 Dispenser Containment Sensor(s), Model: ]á Shear Valve(s). 0 Shear Va!ve(s), o Dis enser Containment Float s' and Chain s. 0 Dis enser Containment Float s and Chain s). Dispenser ID: Dispenser ID: o Dispenser Containment Sensor(s). Model: 0 Dispenser Containment Sensor(s). Model: o Shear Valve(s). 0 Shear Valve(s). DDis enser Containment Float(s) and Chain s . 0 Dis enser Containment Float s and Chain s). *Ifthe facility contains more tanks or dispensers, copy this form, Include information for every tank and dispenser at the facility. C. Certification -I certify that the equipment identified in this document was inspected/serviced in accordance with the manufacturers' guidelines. Attachf~d to this Certification is information (e.g. manufacturers' checklists) necessary to verify that this information is correct and a Plot Plan showing the layout of monitoring equipment. For any equipment capable of generating such reports, I have also at~a~hed a copy o~ the ref)~; (clteck all tit at app/y):_ J!1System ~et-up )i4t2arm hÍJJ~~Y re~ort TechnicIan Name (prInt): . iLL 1.) L, úV! ~a I,,'} SIgnature: ~..¿,~-;;l;!--~ , # Certification No.:....5..:22 'S ,~ IC,· I c.¡ Testing Company Name: ~c¡oJ"?el\J - Hi (/ Site Address: I í ó() AJ, J. s t, Tu I a. fe. License. No.: PhoneNo.:(SS7 )c, '6~'-2977 q 32 '7 ¿/ Date ofTes,ting/Servicing: -1iJ ..L!¿."JI Monitoring System Certification Page 1 of3 03/01 .:;; Nov 24 01 05:29p ~ :I' Fr_en Hi 11 559 688 1467 . p.4 D. Results of Testing/Servicing .. lZÐ,02- Sofu\.·are Version Installed: Com lete the following checklist: Yes 0 No· Is the audible alarm 0 erational? Yes 0 No· Is the visual alann 0 erational? Yes [J No· Were all sensors visuall ins ected, functionaIl tested, and confinued 0 erational? a Yes 0 No· Were all scnsors installed at lowest point of secondary containment and positioned so that other equipment will not interfere with their ro er 0 eration? If alarms are relayed to a remote monitoring station, is all conununications equipment (e.g. modem) opera! ional? Por pressurized piping systems, does the turbine automatically shut down if the piping secondary containment monitoring system detects a leak, fails to operate, or is electrically disconnected? If yes: which sensors initiate positive shut-down? (Check all that apply) 0 Sump/Trench Sensors; 0 Dispenser COlitainment Sensors. Did eu confirm ositive shut-down due to leaks and sensor failure/disconnection? [J Yes; 0 No. D No· -Por tank systems that utilize the monitoring system as the primary tank overfill warning device (i.e. no ~ N/A mechailical overfill prevention valve is installed), is the overfill warning alanu visible and audible at the tank fill oi at sand 0 eratin ro erl ? If so, at what ereent oftank ca aci does the alanu tri er? % Was allY monitoring equipment replaced? If yes. identify specific sensors, probes, or other equipmcnt replaced and lis; the manufacturer name and model for all re lacement arts in Section E, below. Was !il¡uid found inside any secondary contairunent systems designed as dry systems? (Check all that apply) (J Product; 0 Water. If es, describe causes in Section E, below. pi' Yes 0 No· Was monitorin s stem set-u reviewed to ensure ro er settin s? Attach set u Yes 0 No· Is all monitorin e uì ment 0 erational er manufacturer's s ecifications? * In Section E below, descrihe how and when these deficiencies were or will be corrected. E. Comments: . MÐ'I.:i/lr-l) (' 1")'0/ <?'y<;'fem J00'é'S ¡VoT tft:.t¡/€? PD':?I'T(I/e stloT~£bW¡1J We to€- 0 'To I:~'ê íÆ Y 5 " o Yes o No· 'j3 N/ A JI No· o N/A DYes DYes DYes· a. No o Yes'" ~No . # '-"- --- Page 2 of 3 03/01 17' ,,!,f 'i> Nov 24 01 05:29p FrtJen Hi 11 559 688 1467 . p.5 F. In-Tank Gauging / SIR Equipment: ~ Check this box if tank gauging is used only for inventory control. o Check this box if no tank gauging or SIR equipment is installed. This section must be completed if in-tank gauging equipment is used to perfonn leak detection monitoring. ComDJete t e 01 OWID~ checklist: DYes 0 No· Has aU input wiring been inspected for proper entry and termination, including testing for ground faults? DYes 0 No· Were all tank gauging probes visually inspected for damage and residue buildup? DYes (J No· Was accuracy of system product level readings tested? o Yes 0 No· Was ac(:uracy of system water level readings tested? DYes CI No· Were all probes reinstalled properly? o Yes CI No· Were alJ items on the equipment manufacturer's maintenance checklist completed? h ~ I ~ * In the Section H, below, describe how and when these deficiencies were or will be corrected. G. Line Leak Detéctors (LLD): ~ Check this box ifLLDs are not installed. ,. ComDlete the roHowmg c ecklist: WYes o No· For equipment start-up or annual equipment certification, was a leak simulated to verify LLD performance? o N/A (Check a!! that apply) Simulated leak rate:)f 3 g.p.h.; 0 0.1 g.p.h; 0 0.2 g.p.h. Yes 0 No'" Were all LLDs confirmed operational and accurate within regulatory requirements? Yes 0 No· Was the testing apparatus properly calibrated? .. Yes o No· For mechanical LLDs, does the LLD restrict product flow if it detects a leak? o N/A DYes o No'" For electronic LLDs, does the turbine automatically shut ofT if the LLD detects a leak? ¡ N/A o Yes o No* For electronic LLDs, does the turbine automatically shut ofT if any portion of the monitoring system is disabled. )( N/A or disconnected? 0 Yes o No· For electronic LLDs, does the turbine automatically shut ofT if any portion of the monitoring system malfunctions jN/A or fails a test? 0 Yes o No· For electronic LLDs, have all accessible wiring cOlmections been visually inspected? jf N/A XYes o No'" \\fere all i1ems on the equipment manufacturer's maintenance checklist completed? h * In the Section H, below, describe how and when these deficiencies were or will be corrected. H. Comments: Page 3 of3 03/01 - -~ - .~- - ~-::---~--- - PC£:: BAKER~:3F 1 ELD f3ER',,/] CE CENTEF.: 41 01 \.,,11 BLE F:OAD 8AKH:~3F I ELD. CA . '3:3313 NOV 21; 20QI 10:18 AM 1)001 o"Gtla\. e' ~;"l;3TH'1 ~:TATU;3 REPORT ------- ALL FUM:TIONS NORMAL I N\.lENH,Æ'l REPCiRT T 1 :CPI~;C'LlIŒ \.lOLut"lE ULLAGE '30% ULLAGE= TC \/OLUI"'lE HEIGHT i,dATEF: \.lOL ",JATEF: TEi'W Ti;NK :31 :39 I ':J8::: 970 B098 72.DI o 0.00 75.9 GALS GALB GALE; GALE I NC HE3 GALS I I'~CHES DEG F T 2: D IÐ3EL TANK VOLUME 6497 ULLAGE - 3680 90% ULLAGE= 2662 TC \.lCHJJt"1E 6420 HEIGHT 58.52 I",IATER '\/OL 16 WATER 0.92 TEMP $5.2 . :.Úi:1 ~=~., GALS' (~A~S INCHES GALS INCHES DEG F ~ ~ ~ * * END ~ M M M ~ , '~j' e CITY OF BAKERSFIELD FIRE DEPARTMENT OFFICE OF ENVIRONMENTAL SERVICES UNIFIED PROGRAM INSPECTION CHECKLIST 1715 Chester Ave., 3rd Floor, Bakersfield, CA 93301 FACILITY NAME ~. (.,. i- t INSPECTION DATE 11{ J {I Ð/ Section 2: Underground Storage Tanks Program o Routine l1í Combined 0 Joint Agency Type of Tank ()WFc.5 Type of Monitoring tl-IV' o Multi-Agency 0 Complaint Number of Tanks á Type of Piping OWl=:; ORe-inspection OPERA nON c v COMMENTS Proper tank data on tile V '" Proper owner/operator data on file V Pen11it fees current \/ Certification of Financial Responsibility / V Monitoring record adequate and current V Maintenance records adequate and current 'V'" Failure to correct prior UST violations V Has there been an unauthorized release? Yes No \/ ~ Section 3: Aboveground Storage Tanks Program TANK SIZE(S ~ ( Type of Tank L. ~ OlAUl1"q-- AGGREGATE CAPACITY '135"0 Number of Tanks '-I OPERA TION Y N COMMENTS SPCC available V spec on tile with OES v' Adequate secondary protection V Proper tank placarding/labeling V Is tank used to dispense MVF? \/ If yes, Does tank have overfill/overspiIl protection? V -i- \ I C=Compliance V=Violation Y=Yes N=NO Insp"tn, _Æ: ddU11£J ~~ Business Site Responsible Party Oftïce of Environmental Services (805) 326-3979 White - Fnv, Svcs, Pink - Business Copy , - '.L_ ~ environ" Dispenser Containment ,- '. -. -. - < __",~~.-~"",,___~_____~O'>-»~~~~~~______~~ Full Selection Environ offers a full line of under-dispenser containers, which are available in both polyethylene and fiberglass. Dispenser sumps and pans are containers which are installed underneath an above ground dispenser. They provide secondary containment, as well as plumbing access for above ground product dispensers. These sumps are available in various sizes to accommodate a wide variety of dispenser models, and can be field cus- tomized to accommodate both flexible and non-flexible piping systems. These under dispenser containers include a plastic container, metal frame assembly, anchor nuts, stabilizer bars and side struts. Additional required items, such as flexible entry boots and other optional components must be ordered separately. Environ offers a variety of under dispenser containers for use with the GeoFlex® piping system. The contairíers, made of polyethylene, include deep dispenser sumps, shallow dispenser sumps, deep dispenser pans, and shallow dispenser pans. Also available are sumps made of fiberglass with separate riser and base sections for easy installation of pipe fittings. / Deep Dispenser Sump Fiberglass Dispenser Sump UL I ULC Listed Environ polyethylene dispenser sumps are Listed with Underwriters Laboratories, Inc., (UL), and have passed the requirements for Canada at Underwriters Laborato- ries of Canada (ULC). The scope of the tests include broad compatibility testing for both petroleum prod- ucts and burial environments as well as physical test- ing to confirm the sumps structural integrity and liquid tightness. Testing of the sump frame confirms that shear valves will activate when properly installed in Environ dispenser sumps. Features · Liquid tight containment · Chemically compatible · Structurally strong · Liquid tight pipe entries · UL / ULC listed Shallow Dispenser Sump Deep Dispenser Pan .F:'.~ . .'. '. ' t~ .--.-.'-.'y-.'' 1:..,..,[" I~ I\; !,! J1 ''''''''" _;.s_*''-<___~:~~~,- __ ~,,_)! Containment Sumps Stabilizer Bars Shallow Dispenser Pan Pipe Entry Boots Benefits · Keeps surface water out · Compatible with petroleum products · Resists forces from backfill and ground movement · Prevents ground water from entering sump · Third party testes and approved ,~ ....-. environ- Dispenser Containment <,>~~~~-=-~~~~_~~~-=-..---="'~~~~_-=<~---',,~-""'_~~~~~""___~_~--=-~~~~c_~~_~_~-'=--____""'>-~~_~__ Product Models Shallow Dispenser Pan This shallow polyethylene dispenser pan requires a contained riser supply pipe to enter through the bottom of the pan only. This contain- ment pan is intended for use with rigid piping systems. Deep Dispenser Pan This deep polyethylene dispenser pan requires a contained riser supply pipe to enter through the bottom' of the pan only. This pan is intended for use with GeoFlex-D piping utilizing coax fittings and jacketed riser supply pipes. Shallow Dispenser Sump This shallow polyethylene dispenser sump requires the supply piping to enter the side wall of the containment sump at high elevations. These sumps are ideal for suction piping systems requiring direct slope back to the tank. Deep Dispenser Sumps This deep polyethylene dispenser sump allows the supply piping to enter and/or exit out of the side wall of the containment sump at very low elevations. These sumps are ideal for pressure piping sys- tems requiring indirect slope back to the tank. Extended dispenser sumps are also available. Please refer to the Environ Products price list for a complete description. Fiberglass Dispenser Sump This two-piece, easy access fiberglass dispenser sump has separate riser and base sections. It permits the supply piping to enter and/or exit out of the side wall of the contain- ment sump at very low eleva- tions. These sumps are ideal for pressure piping systems requiring indirect slope back to the tank. Publication: EPF-0050 Issue Date: 01-22-01 Supersedes; 03-15-00 ~ r " ¡ ì' I, ¡ I I I', , ! ~" P " ",,~, . Product Features Rain Lip Most Environ dispenser containers have a 1" high rim which extends above the surface of the concrete island to prevent surface water from entering the container. Mounting Frame All under dispenser containers include a heavy gauge galvanized steel frame. Anchor bolts are installed through integral mounting holes which secure the above ground product dispenser. Concrete Anchors Frame anchors are installed to secure the sidewall of the container to the concrete island. Anchor Bolts are included to secure the dispenser and container to the concrete island. Adjustable Stabilizer Bar A variety of fully adjustable stabiliz- er bars are available for accurate positioning of shear valves and easy connections of pipe fittings. Flexible Entry Boots Flexible Entry Boots are installed in the wall of the container by means of stud fasteners and compression rings to provide liquid tight pipe and conduit entries. ¡' I ~. I. ~k ¡, I ! I I I" t Sidewall Support An Optional item for all Deep Dispenser Sumps is an expandable and removable Sidewall Support. These supports prevent the side- walls from deflecting due to extreme ground pressures. Fire Extinguisher An optional automatic fire extinguisher, called the Snuffer", is available to extinguish a fire inside an under dispenser container due to dispenser knock-over. -~: :II -~~..._ /A~-<'-o/"'""'.~'''''""",~____''''"""O-''''''''';~'''f'; ii, ~ . ,.~ ~ - ....~ ..~\ :...... . >~ ....."... , .. , c,·,· ~' '. ~-- -'~1; '. ..' ., . ,I" ..-";_·,c_~.-><~",,~~~~~~,,____~*~ ( Ii ,. . I -,.='\\ ~, ~-" if'" 7 ,>"....-' "-~'" ,-" --.~~ - .." ,- "0 1', -",f4.-~~_"",",~"-,*·__.--'-,;-",_~~~_",j,<0Y' J~ . i;,,;t!~ ~r~': ~i' II. \~i ,<- P,O. Box 330· Smithfield, NC 27577-0330. Tel: (919) 359-3400. Customer Service (800) 833-1883· Fax: (919) 359-3687 U,S, Patent 5263794, 5271518, 5297896, 5366318, 5346625, 5398976, Other U,S, and Worldwide Patents Pending. © Copyright 2001 FLE_IBLE ENTRY e e Environ Flexible Entry Boots have proven to be the most popular and environmentally safe pipe and conduit entry seals on the market. This design allows for angled pipe entries and has no exposed metal parts to the underground environment. Made of a chemically compatible Buna-N rubber, this entry boot is available in a variety of sizes and designs to accommodate rigid and flexible piping, ducting and conduit. APPLICATION FLEXIBLE ENTRY BOOT NUTS I j ~ ~ e ~ BAND CLAMP I COMPRESSION RING FLEXIBLE ENTRY BOOT "\ PRODUCT SPECIFICATIONS (~ l" ,- I~ I~ I~ Þ » 3050 3075 3075-A 3100 3150 5150 6150 6200 6300 6350 I',···',···,'··:·, . ~; 7390 7400 7450 8600 e * These boots require a Split Reducer Donut, said separately, but include an airstem to allow for appropriate testing, INSTAllATION INST STEP 1 Locate the center entry point in the flat wall section, of the sump base and drill a 5/16" hole, Install the Entry Boot Template to the sump base wall using a 1/4" bolt and nut. Drill out the appropriate bolt hole circle for the size boot to be installed using the same 5/16" drill bit. After drilling remove the template from the sump base wall. STEP 5 Insert the appropriate sized pipe or conduit into the flexible boot from outside of the sump, After the pipe or conduit has been positioned, install the band clamp around the boot and tighten to 30 in, Ibs, STEP 2 After the bolt hole circle has been drilled, drill out the entry boot opening by using the appropriate size hole saw, After drilling out opening, clean any rough edges with a razor knife, Refer to chart for hole saw sizes, ANGLED ENTRIES The Flexible Entry Boot is flexible enough to permit angled pipe or conduit entries up to 15' in each direction. Angles greater than 15' could prevent the boot from sealing around the pipe or conduit. @ GUIDE SPECIFICATIONS e STEP 3 Install the rubber boot from outside the sump by inserting the studs through the bolt holes, From the inside of the sump, install the compression ring over the studs and install nuts by hand, STEP 4 Using a 7/16" nut driver, tighten all of the nuts evenly and firmly. To prevent deforming boots do not over tighten nuts, If a torque wrench is used, the setting should be 60 in, Ibs, e ROUND SURFACE INSTALLATIONS Flexible Entry Boots may be installed on round surfaces which have a diameter greater than 3D", The installation procedures are the same as described above except the 5/16" bolt holes should be made slightly larger after Initial drilling. This can be accomplished by moving the 5/16" bit from side to side in each boit hole after the Entry Boot Template has been removed. This will enable the entry boot studs to move slightly inward when tightening down the nut fasteners, Tighten down each nut in stages so the boot flange and compression ring can evenly conform to the rounded surf1!-ce, BOOT REPAIR KIT I n the event that a flexible entry boot becomes damaged after installation it @ may be repaired by using the "Boot Repair Kit", The repair requires the partial removal of the flexible entry boot cone and replacement of a flanged cone ~ which is bolted into place, ~ Pipe & Conduit Entries: All containment chambers shall be fitted with pipe and conduit entry seals which are semi-absorbent to ground movement and sufficiently flexible enough to permit angled entries up to 15' off the center line without leaking under liquid head pressures of up to six feet (1 ,8m) No metallic components shall be exposed to the ground. All pipe and conduit entries shall be listed with Underwriters Laboratories, Inc Product Compatibility: All components of the secondarily contained underground liquid distribution system shall be chemically compatible with the products to be _ distributed and with chemicals found naturally in the ground environment. ., Corrosion Resistance: All components of secondarily contained underground liquid distribution system which come in contact with the ground environment shall be made of non-metallic material or protected by materials which prevent corrosion, Environ Products Inc' 252 Welsh Pool Road· Lionville, PA 19341 . Telephone: (610) 594-0297 . Customer Service: (800) 833-1883 . Fax: (610) 594-9042 I' ¡ í I ¡ I I L...L I ' , , ; I ' I I !, ¡ -¡---'-'--i--r--l" i: I ---~-L -+i~+-++ T - -+- I I AI~I r _ I -f +ti~F+-I-i-~-,++-'-~-rl -of - ~-+t---~- i -~! ~:~ ~~-~--t--t- "-~t-l'::..,-.---$1L'1-f~ -=!---- tl--+-~---rtl_--- -1-- I' - - ~'',) I I : I I I 1 I ' I j, I! " I -~4-------"'-" , --f --;---, ''''---:--- ¡ -, . I--j--r-;- ,-¡ i' 'I t---tjl---- T---; - t-- -I-- - -! --- /1--' + d· '-- j ~ '=r--h~± - 1- - d-- P5F-~~ -t---- -~---,- -----+--,----+-- -i---- : --t- -·-f --, '--l-'-f--- ¡ ---- i --,---+----t----~I ~----~---+I --'-~---' +--- - --r-' 41: -- -- -+ ---¡- '-I ¡ ~ -¡----~--- L____,; --- ¡ I : !--' I -+--T-T-+,---t--·!-·~--- 1----- ----: , ' I 1 -j--t' --i---f-- i : ; , I ¡ : , ¡: I I ,.' , I ! 1 ' 1 i t ¡"--r t- -~ --I"¡-: - -1- -!--- -¡T~---_¡~r-1~-- --I - t-- r 1----------1'---, ~~J\~- - --T --------TL: ---, ----r-- ----1'---- -"1' --1- ':-----j -----T--:-----1------~-- - í '----~I:-----:T-- -¡---1--~-' .. ¡---¡----T- tit ---r-1m-" -r-- ----I --t--I---1----¡-- .: 1 -- ---¡- -, --: --- y'- --; -----; - --i --, L ..-- ~ - . .- ..':. -t------t-·· r - -1---·t - - --f/8-ft--· --, ¡ -'-T~t;l:' -i- -'----:¡-----l--.Q-'---r ----t-- L - ~ : ¡ - ; --; ¡ : - i i --: - ¡, J -:-- ! - -.---L-- I" - - - --I ..J ---,: - - r~J~~~£~!L[:~l~~t __ _j_____ !--+--~,.; ---!---.--;, -.~-.-L--~----r-- -,¡-----;---!--..-¡--,-~--j--Ti__+.- __~_~__~_ - -I -5+~~f~j-___LI' ,__1._ ' ¡ ,¡! I 1 , : . , '! ¡ I' ¡ !! ¡ 'f I :' : I : I ¡ : i ' ; ¡ , ¡ ': ; i ! ¡ I ' , : -r----¡--' 7 -"---;, '-¡' - - ,..-'~ -., --¡-- '--~' ! '-, ':-- -:---, ,-.- ----;-·--¡---rct--Re-o:bh: .-- ;'----T-----'--'--t--,---- ---J -- L.. ._-: - -: ,,¡ ~ - : .. - ¡ L-__: - Ii -: ; ¡ -- , i) _1___.. --- - ~,-___ ¡¡~~tf' ! __11_-- ____ .1._ -1-----1 _____1__ J ____ '; ¡:' ¡ : ¡ ,,' ¡ ¡, ¡ ! ' t ! I : " ", I , , , " I,' , I :----7 v, II S1J"ej) ---!-+----·i------~--~------· '-.. -- ,---1--":--,--+,-,-- ;----''1,-,--1-.--,,--- ...'---- i---i------:-,---.- ..-+--t--. ,--+- -; I ¡,;,I ~ J -L---t - j -- ~_7 -;0-1 t -,.. ~ ~1í :- ¡ -- ,:sUr~1l'.j, ~ - ¡ , __:__.. i ,__ _ __...1. __J__(þ!,__ L, _~,____ _ _~__ __1______ ~_ ,--r--- ,__ - - - -- r- -:- It' -, - '.-- -, I ' " I" I': I ¡ i ¡ '\ ' , , , , : I I I I " 'I I I ¡ I 'I 'rðP~+ '..- -'-'l1 f - 1 -: -: : - ¡ ,1,,-- -'1 .;- _I:' ¡, --¡---- : -..- 'I -- -+ --,t --1-'- ·f-·, '" --'-Î' -- + -, ~ ----rl..----t---- ' : : ' , , : ¡ Ii!' " 7,11(" I I: , ;4 j" I ¡ 'f !; ~' , !,,! ! I' ¡ 1 ¡ , ' " "', > '/~ 12. ' :' I I' " I' \JJ1' ¡; :': K~ 3..â/¿_-;-. ,. ~ - 1--- :-- _1- . - . -' -', - ¡, ¡ t- ---"-,1---- I:! 31, ¡ :" f j : ; 1 : ¡ ¡ , . -: - : -- --~., - -- ' - ' ,,; -I - j -" ¡ ----;- ..L --- --:- ,- .. SŒ_ --..j,.. -----i..-.L---L-li--_L _ j. I, ~! I , ~-I:- ~ -!- ..¡... -: -:- /'..: ¡ [: 1'2. : : I ¡' }__-.,;~,:,' i _ ~ '-, ,--;- "_ i-.,,::-¡._, ' ''VAS , """! '--~,!~~-],' . -, , ., -'-r-,C~t ~C, -T~: ..~_ --- ,~~j~--Illi.'.1;rT= +-~{ .. ·¡~I~t~L,-!-L:--i--.-+-+t~y-¡+ J ',tr,·,%J,·,·,~-'ùJz.j- ,. ,', ," ii,..,;, ' " ,_< I .,1.._,_1__,___ ',,¡, .,," "..,._" =l=r~j . . .,.' ... : ii_+-r=~-.. ¡ ..1 .~-]J... r···~~~:1~:tt\tilt~fir:-..!--::~:r-l-r~1=. LiT--' I ('-~;-,"",,-'-__L~ -;.-~-'---L.""-~....J~......L."'t::;,_Ly_lk..~__;.,__..._L.._..i.....__: L i .........;...-----'.....--!.._l..__J_-'-,........J..,.........J ' 1'2 (l 8929 ROSEDALE HWY., BAKERSFIELD, CA 93312 (661) 589-2774. FAX (661) 589-7504 ..1& II.... "1\ tr...l N ~,. ~,' ",,-"! F-" , ~r /' I.- ........ è). f) CUSTOMER {J G f f kALV-f &vri: JOB # IJI-/DOt· P.O. # C.., ~ DATE JD - ¡V- () / FIRE CHIEF RON FRAZE ADMINISTRATIVE SERVICES 2101 aH" Street Bakersfield, CA 93301 VOICE (661) 326-3941 FAX (661) 395-1349 SUPPRESSION SERVICES 2101 aH" Street Bakersfield. CA 93301 VOICE (661) 326-3941 FAX (661) 395-1349 PREVENTION SERVICES 1715 Chester Ave. Bakersfield, CA 93301 VOICE (661) 326-3951 FAX (661) 326-0576 ENVIRONMENTAL SERVICES 1715 Chester Ave. Bakersfield, CA 93301 VOICE (661) 326-3979 FAX (661) 326-0576 TRAINING DIVISION 5642 Victor Ave. Bakersfield. CA 93308 VOICE (661) 399-4697 FAX (661) 399-5763 . ~' . August 3, 2001 PG&E 4101 Wible Rd Bakersfield CA 93313 RE: Deadline for Dispenser Pan Requirement December 31, 2003 REMINDER NOTICE Dear Underground Storage Tank Owner: You will be receiving updates from this office with regard to Senate Bill 989 which went into effect January 1,2000. This bill requires dispenser pans under fuel pump dispensers. On December 31, 2003, which is the deadline for compliance, this office will be forced to revoke your Permit to Operate, for failure to comply with the regulations. It is the hope of this office, that we do not have to pursue such action, which is why this office plans to update you. I urge you to start planning to retro-fit your facilities. If your facility has been upgraded already, please disregard this notice. Should you have any questions, please feel free to contact meat 661-326- 3190. SinCer%,,/i' ~da£J Steve Underwood Fire Inspector/Environmental Code Enforcement Officer Office of Environmental Services SBU/dm .. .%UÚly ~ Y;;'/N/;U//U(~ '%/" <-.#6ope !Ÿ%OA ./6 g~/lbr/r" FIRE CHIEF RON FRAZE ADMINISTRATIVE SERVICES 2101 "H" Street Bakersfield, CA 93301 VOICE (661) 326-3941 FAX (661) 395-1349 SUPPRESSION SERVICES 2101 "H" Street Bakersfield, CA 93301 VOICE (661) 326-3941 FAX (661) 395-1349 PREVENTION SERVICES 1715 Chester Ave. Bakersfield, CA 93301 VOICE (661) 326-3951 FAX (661)326-0576 ENVIRONMENTAL SERVICES 1715 Chester Ave. Bakersfield, CA 93301 VOICE (661) 326-3979 FAX (661) 326-0576 TRAINING DIVISION 5642 Victor Ave. Bakersfield, CA 93308 VOICE (661) 399-4697 FAX (661) 399-5763 . ,,' . :--~ ¡. January 22,2001 PG&E 4101 Wible Rd Bakersfield Ca 93313 RE: Dispenser Pan Requirement December 31, 2003 Underground Storage Tank Dispenser Pan Update Dear Underground Storage Tank Owner: You will be receiving updates from this office now, and in the future with regard to the Senate Bill 989, which went into effect January 1, 2000. This bill requires dispenser pans under fuel pump dispensers. On . December 31, 2003, which is the deadline for compliance, this office will be forced to revoke your permit to operate, effectively shutting down your fueling operation. It is the hope of this office, that we do not have to pursue such action, which is why this office plans to update you. I urge you to start planning now to retro-fit your facl1ities. If your facility has upgraded already, please disregard this notice. Should you have any questions, please feel free to contact me at 661-326-3190. Since/¡. ..r., e"IY, A I /J /"\ ~~ Steve Underwood, Inspector Office of Environmental Services SBU/dm "7~ ~ W~ ~ vØbOPe.r~ A W~" Nov. 14 2000 4:34PM HP LASER JET 3200 . . p.2 :, I,/~Y .f A-HN ~ Lh~L ~CASíl.G; t>Gf - WJ~e eb ~ fhqQ CAL VALLEY EQUIPMENT 3500 GILMORE AVENUE GAKERSFIELO, CA "30' 681-327-9341 FAX tI 561-325-2529 CONT. UC. .184110 TANK MONITOR INSPECTION DATE: 5', ~o -00 SIT : MAKE: Gllb,..ru~ MOOEL:-r~ ?- / I CONDITION OF UNIT: / 'KONR'roJ / ~ïlAS SOFTWARE VER. SN: J :"J7 q~ All ¡:;J\Jt:hD".,J.c; JlJt'I:1Emð( TANK PROBES: aTY. ::2 TYPE (J, Pr 'P I UNE SENSOR5: QTY. TYPE SUMP SENSORS: QTY. ;;. TYPE LIQ~>ß ANNULAR SENSORS: QTY. d- . TYPE LIQI.!I~ OTHER SENSORS: QTY TYPE PROGRAMMING ACCURACY & COMPLIANCE: (1) READS ACCURATE TO TANK CHART? YES X ,.' NO 12) POSITIVE SHUTDOWN? YES NO Nov. 14 2000 4:34PM HP LASERJET 3200 :-. ~ WI' . p.3 -1 COMMENTS: "soh:- hPl~ dol)..br~p!l kb,ø...r1'''...... ~t'I /.(.~ J.I.\Jn+ an(\¡ tlLlr sçn'-~ _~I:""¡ ~,~J / A-II , . pJp'rtj I~ i~lJuhll".uJQ,f( hhnL.ylPi....~ W J'rs.r "J IJ/T1<j. ""jUhJ/J I , , bl,~ MGh~tJ (3) TANK PROGRAMMING MEET COMPLIANCE? PROGRAM INFORMATION: YES X NO TANK DATA: MANUFACTURER OF TANt(S? D.tJe.;JS C,..""I")'1 Dðubl.- ¡,.j r.d I H fy.r~ In "'> ~ $IZE '0,00';";;< PRODUCT Rt.LL PRODUCT ÒI~~L SIZE to ,000 SIZE PRODUCT sIZe PRODUCT COMMENTS: INSPECTED BY: ~~~--I /:C~. DATE: 5'·- 30 ·-000 í CITY OF BAKERSFIELD ,. OF_E OF ENVIRONMENTAL SevlCES 1715 Chester Ave., Bakersfield, CÀ 93301 (661) 326-3979 UNDERGROUND STORAGE TANKS .INSTALLA TlON CERTIFICATE OF COMPLIANCE One form per tank P8g8 _ d ---_..__.._~-_.._.. ._._--_... ..-------.----- ----- ..-----------...-...-.... ....-----.. I. FACILITY IDENTIFICATION ·?;~~~EG:i~~~~(:::;'~~~:'i _ ~~(c~~fléLÛ S~~-~---Q~~;~_·_-·· ,. - .,...... -.....-.-.---- FACUYIO. ~IOl:~ ~'. =::-.~,~~~.=,_..,~~_..=:~~== - -- ~---~-- ___-___=--e:=_ __-,,_~ _. ;...-~_¡:::=:-__.__ ~_...;._~__~ II. INSTALLATION Check aJJ that apply o The Installer has been certified by the tank and piping manufacturers. o The installation has been Inspec-tAd and certified by a registered professional engineer. . o The installation has been inspected and approved by the City of Bakersfield Office of Environmental Services. o All work listed on the manufacturer's installation checklist has been completed. X The installation contractor has been certffled or licensed by the Contractors State License Board. o Another method was used as allowed by the City of Bakersfield Office of Environmental Services. Identify method: I ; I ! III. TANK OWNERlAGt;NT SIGNATURE I cettJfy tNt !he Inbmdon II'OIItded herein Ia IIUe & __ 10 !he belt ot my IInowIedge SIGNATUfÜfóFT.W(öWÑÊiilAGENT;;;- ;?... / -.----- ---- ~~;y~ 1-;W¡eoFi'ÅÑÏ<õWÑERiÃÖËNT (prtnI)-' -' DAIfÆ&¿¿ 1(4£L1MS7¿é DAfe ...____ ___._.._._...._.._ N .,... , . . - . ..----::¡¡¡- )/7'/#U 4e5 TiTi.ëõ'FTANK·õWNeRiÃÕËÑÏ'-~·_·_---' ,-. ...,. '-: '.-...---.- ¡Ç1/v/ø;yh?1¿-#?,4L ...J/~eJß¿ì.s""7" ' , _. ..--.--- ....--....-.-.----.-.-------- . ---.---..---.---- ..--.-..---. --_.._..-,-.. -..- -..- .7 .~- .:-':':' I7fl Pacific Gas and W~~ Electric Company 4101 Wible RoU Bakersfield, CA 93313 Mailing Address 1918 "H" Street Bakersfield, CA 93301 805.398.5991 Internal: 874,5991 Pager: 805.394,5992 I . \ . Darrell Hardcastle Environmental Specialist '0IIII C J CITY OF BAKERSFIELD _FICE OF ENVIRONMENT.SERVICES 1715 Chester Ave., Bakersfield, CA 93301 (661) 326-3979 ,/ (9 UNDERGROUND STORAGE TANKS - UST FACILITY TYPe OF ACTION (Check 0'" ,"m only) o 1, NEW SITE PERMIT ~, RENEWAL PeRMIT o 4, AMENDED PeRMIT o 5, CHANGE OF INFORMATION (Specify c"'nge . /oeM use only) o e, TEMPORARY SITE CLOSURE Page_of_ o 7, PeRMANENT\. Y CLOSED SITE o e, TANK REMOVED 400 ! BUSINESS NAME (s.m. . FACILITY NAME or DBA . Doing BulIn.. AI) ¡" I. FACILITY I SITE INFORMATION 3 FACILITY 10 . ¿l~\ , NEAREST CROSS ET W ~ '"\6 \A"\\I E.. : ~~NESS 0 1. GAS STATION 0 3. FARM 0 5, COMMERCIAL o 2. DISTRIBUTOR 0 4. PROCESSOR e. OTHER 403. Ii TOTAL NUMBER OF TANKS Ie fecIy on Incbn ~ or "If _ of UST a public agency: name of SUpet\IÎIot of REMAINING AT SITE 1nIIIIanda? dMIIon. section or oIIIce wIIk:h operat.!IIe UST. (TNa is !lie conI8CI person far !lie I8nk recardI.) 401. ~ILITY OWNER TYPE ~. CORPORATION o 2. INDIVIDUAL o 3, PARTNERSHIP ( ~/c I . 0 4. LOCAL AGENCYIDISTRICT" o 5. COUNTY AGENCY" o 6. STATE AGENCY" o 7. FEDERAL AGENCY' 402, ?- 404. Ov_ No 405. 406, - - .--~ - '- -:=:--'-~-;.r- IL PROPER1Y ~ER INFORMATION :".~ 407. Ù'=UJ S6~Vl·C.<E ~T~ PHONE ~fol - 39~ -5'1 408. 409, 410. 412. e¡3313 o 2. INDMOUAL o 3. PARTNERSHIP o 4. LOCAL AGENCY I DISTRICT o 5. COUNTY AGENCY o e. STATE AGEHCY o 7. FEDERAL AGEHCY 413, . '"" 'DL TANK OWNER INFORMATION .' ...~;.. ~,.:"""> . TANK O\MIIER NAME 414. PHONE 415. (S~lY) 6- ^S> MAJUNG OR STREET ADORESS 416, I I I CITY ¡ o ,. CORPOAATION 417. STATE o 4. LOCAL AGENCY I DISTRICT o 5. COUNTY AGENCY 419, TANK OWNER TYPE o 2. INDMDUAL o 3. PARTNERSHIP 418. I ZlPCOOE 06. STATE AGENCY o 7. FEDERAL AGEHCY 420. INDICATE METHOO(S) ., IV. BOARD OF EQUALIZATION U8T STORAGE FEE ACCOUNT NUMBER Call (916) 322-9669 If quesllons arise .. . V. PETROLEUÌl U8TFINÄHCIAL RESPONSIBILITY 421. TV (TK) HQ o 4. SURETY BOND o 5. LETTER OF CREOIT o e. EXEMPTION o 7. STATE FUND o 8. STATE FUND & CFO LETTER 09. STATEFUND&CO o 10. LOCAL GOVT MECHANISM o 99. OTHER: 422. VI. LEGAL NOTIFICATION AND MAILING ADDRESS Check one boa to IndIc8Ie wNdI addr-.1IIouIcI tte UNCI tor legit noIIftcaIIoI. and m8lllng. Legall'IOIIIIc:a1Ion and maIIIngI wtI tte MIlIto !lie ... _ unIeII boa 1 or 2 II c::hec:ked. o 1. FACILITY o 2. PROPERTY OWNER 3. TANK OWNER 423. VII. APPLICANT SIGNATURE CertHIcaIIon: I certify 1hàI!IIe Intorrnøllon ptOWIded IIeIWI is true and ICCUI'IIe 10 !lie IIeIt of my rcnowtecIe. SIGNATURE OF DATE 425, 428, 424. PHONE S" 7j dO &6/- s/'S -5/; ( ICA. [? C;:::/t/V/ÆØ/VI'Y1&v'Z'A¿ 0.; (:ÇC1/1 L/S "7 4rT, TITLE OF 421., 1_ UPGRADIi CERTIFICATe NUMBER (For IouJ 1M only) 429'/1 , STAT! USTFAClUTY NUUIER (Fotlaca/UII 0IIf)t) UPCF (7/99) S:\CUPAFORMS\swrcÞ-a.wpd .~t". .. _.~._. CITY OF BAKERSFIELD . OIllCE OF ENVIRONMENTA~RVICES 1715 Cl1líter Ave., Bakersfield, CA 933m (661) 316-3979 UNDERGROUNDSTORAGIT~NKS.TANKPAGe1 (I. ... - ~ a .. TIWOAAAY,SITI a.o~ CJ 7, PERAWIIHn. Y CLOSED ON SITI CJ e. TANK ftÐotOVm NIlE 0' ACTION a " NIIW tITI PIMIT a .. AMIHDID PERMIT (Cltect _... 0lIl11 ~ 1. IUIIWA&. ~ (___...., . 1M.. UN 0ttIy1 BUSINESS NAIll (..... a 'AC!UTV ~ Of OM . DaIng .... AI) 11 ~~~í 8.G'-iÚe.. )6 S&¿~/(,é ~1í , LOCATION ~ , 4 ì 0 I tv \ f6lk ~ '() ) ~):""(-{lò~ &UJ ,LA O¡ 3?» '3 . L TANK DI!~ as. CHAHOIOfIIWOItMA1'1OH) (... c/IIIIfI·lM.. UN 0lIl11 3 'N:A.rfV 10 ~ i rANK 10. 4:IZ' ~4~~L- Q:I COWNmENTALIZEO TANK OYa 9{No to'flp Ou..TLON . lJ..N$, "-V.'. CQIIIØIIIe _pege rar ..,. I DATE I ( ---- 438 .. ! Lf /91 I 0)000 ' ) AOOfT1OfW. 0ISCAIf'fIDN"..,,,,., _ CIII$1 43- , ~-'-, -",~:rN,S.:r"'lLC--il...~",--:r::~E-N--~-\-L-b \' -,l-I.l-$\'~.J~: ¥,Q c. _~~~ ~_,~", ' . ~= - . -- --~ , & TNIC CON1IN1'8 " I TANKU. _ Nt'RDUIJM1'tPII 4< I ~t. MOTOR VItICUI.... ~&.MCUMUN.IN:II!D o 2. LfAÐI!D o So .I!T FUEl. '. " , . i (11'--' ---~ 'PI C '''' .......wu.\œo o 1. DIIIIEL . " EJ .. A\MTIOH FUEl. , ! CJ 2. NON-FUB. fII1'ADLIUM C 10. YDQfW)Ì UtI.EAÐED O..GA8OHOL o II. OTHER " f o 3~ CHÐICAL PAOOUCT CAS' IHMt HItzMItIuI........ ~,.,.} , I 0 4. HAZAADOUI WAS'I8""'" COMMON'" (101ft,............. ~,.,.} ..., 44: /bed Of} L .~.,.~.~ CJ IS. UNIOIOWN .. TNIC c:aanRUC1'ION .. " , , .., TYPe OF TANK Ct......WM.L "::':!, o So INAØWALL WITH C .. SIG.I! WALl. WITH INI1!RNAL ILADDI!R 8Y8TEM 443 {CMdr _ ... CIII$1 ~WM.L<",,""_:": ' I!XTERIDR "e8lWl! LIN!R 0.. UNCNDWN ,. . n", - _'" ~-I ~ i ,:,', ,"',.' ! TANKaMTÐUAL.,....,IMIC t. IlMES'IE. " ' "" ' " I (CMdr_IIMtClll$1 , 0 2. STAN.ØIS'IE. ' I I TANK aMTERIAL ........, IMI 0 t; lIME S'IE. (CMdr - ..". CIII$1 C 2. ITAINU!II8T&L ., 0... SINOU!WALLlfAVAULT o II. OTHER o 5.CONCAETI! a .. FRf> CiOIPATI8I.E W11~ METHANOL '.'J :~, C t.,IUIIRUtB ' C 2. 'MX'tDLINNI o So F1IIERGLASSI PL4STIC )I( 4. 'STEa CLAD WIFIII!RGLA8S REN=ORœD PL4STIC o So FIBEROI.A8S I PL4STIC [J ... STEEL CLAD M'IIERGLASI RDFOACED PL4STIC (RIP) o .. CONèRIr& o So IPOXV LMG C ... PfeG ICLMG [J.. FRf>coWATl8l.EW1~METHANOL o .. FRf>~JAQŒ1' o to. COATED 8TEB. 0.. UNcNowN " Oll.cmtER ,ÇJ.. ~ l\¡.,_", 0.. oñtŠt' . . '; ~.. . 444 44.5 . ~ , a .. GWlLMG C"UNLINI!D ... ~TI! 1NI1'ALU!D 447 (CItedt _11m CIII$1 SPILL AND 0VfIUIU I (CItedt.. tN, IIIPIY} I . C t. MNoIUFACnIÀID C\1HOOIC , ~C' a.FIIÌERiIJtA8I ~ PIJISTIC" [J 05. ~ PA01'IQIDN" 0 ... U'AES8ID c:uMørr [] II. OTHER C 2. IACNllClALANOOII' 'II!AR INI1'ALLED 450 TYPe ~1oCM'" CIII$1 ~ 1. IPIU. CONrAlNMlNt' I q q ) ~2.~"-- JA q ~ So ."...UUTI I q q c:¿ ..... "., ~TI! 1NI1'ALU!D 4411 {FtN/oQI- 0IIIy} 411 O\IEAFILL PROTECTION EQUIPaotEHT: YEAR 1N8TALU!D 412 o t. AlARM ~3. FlU. TU8ESHUTOFFVALVE M , 0 2. 8AI.L FLOAT ' 0 ... I!XÐPT '" , ""., II/IIIt: CJ t. VISUAL (IXPOIID ~ONLY) a 2. AUTOAMTlCTANKGAUCIINCI(ATO) a J. COHI'INUOUI ATO CJ 4.STATIITICMoIN\/lNTORY AICONCIUATIOH (lit). IIIHMA&. TAHIC'TIITNI ' ,.;M/Ir.LiAK ' : ,_~:;; .~ .:'\..::1)......:;: ". , .', >;::........;..~. .'';: '6~J.' ~.~. ::',.:" ...:!-...~.... . .., : ~. .... ~"'f-\.........", . .0. .'), " ,... .. "", >," ',"., ....,,~;~, ! . . .-.,,~... . .., ·.0...., .,.. .' . DOWU WALL TANK 0" TANK NTH ILADIIIR (Check- In fItI/y: ..... at. WIUAL(IINOLIWAU.INVAULTONLY) ~2. CONTINUOUS INY1RSTrTIAL MONrTOAINQ a 3. MANUAL MONITORING IlTlaMTID DATI LAlTUIID~Y) a L' MANùAL TAHIC OAUGINO (am¡) , C .. VADOII ZONI a 7. GAOUHDWAT!R C .. TANK TUTINO a II. OTHIR V. TANK CLOIUIUI INPOIIIlATIGN I PIJIIIANINT CLOIUU IN PLACII 411 IITIMTID QUNmTV ~ SUllTANCI ~ . .... TAHIC flUID WITH,.,. Mo\TIIUAL? 417 ...... OVa CND UPCF (7198) S:\cUPAPORMS\SWRC8-8·WPO CITY OP BAKERSFIELD A., OPPlCI OP INVIRONMENTAL SERVICE34-S . W' C...... Aw., 1Iù.......ld, CA .3301 ("1) -'-' , - , -' ~, . ~l UIT. +_ 'AGe. ..... '''- " -- VI...... CGNI1RUCTION (Cttå" IIItwM '. , . UNDMQIIOUHD PIfIIHO SYSTEM TYPE "'){" PReSSURe a 2. suCTION CJ 3. OAAvITv 4SI a" PAl!SSURE CONSTRUCTIO~ t, ,SINO&.I! WALL, 0 3. UNI!D TAINCH 0.. OTHrR 4ðO 0" SINGU! WAlL MANUF4CTURER~9".2. 00UIt.I WALL o II. UNKNOWN 0 2.DOUBLI! WAlL ¡ ¡MANUFACTUReR 4411 MAHUF4CTURIR ¡ ;0 I.INU! STÈ!t. 0 I. FAP COWATI&I....1Oft amHANOL 0 I. BARE STEEL I ' . :~TERIAl.S4N002. STAMJ!SSma. a 7. OALVANIZIOSTII!L a 2.'STAlNu!SSSTEEL CORROSION" ¡ I PROTECTION ¡ 0 3. PlASTIC c:oa.ATIILS WITH CONTENTS a II. UNICNOWN 0 3. Pt.Asr1C COMPATIBL£ WITH CONnHTS 10 .. FtIIROLASS a I. F\ØJIIU! (tØ'I) a.. oTHÊR a .. FIBERGLASS ')i(~ STElLVtYCOATINO at. CATHOOICPROTECTION ..... as. STEEL WI COATING VI. ~,LIAK DUECTION {CIIect" IIItwM UNDERGAOUNO PIPIHG i PRESSURIZED PIPING (ChcIt ",., IIJIJ/1): o 1. ELECTRONIC UNI! U!AK DeTECTOR 10 GPH TEST mDiAUfO fIUYI SHUT OFF FOR LEAl<. SYSTEM FAILUAI!. AND SV8TEM OISOOfN!CTION. A&I)BE AND YI8UAI. AlARMS o 2. a.tONntly u GPH TÌsT a 3. NHJA1.1Nt'HRfTY TEST (0.1 GPH) ~SUCTION SVSTDot ,a 5. DAILY VISUAL MONITORING CW ~ SYSTEM. TRIENNIAL....-.ø INÆGRfTY i TEST (0.1 0fIH) I SAFE SUCTION SYSTEMS eNO VALVES IN BELOW GROUND PIPING): o 7. SELF MONrTOAING GRAVI1Y FlOW: o II: BIENNIAL INTEGRITY '!1!ST eO.1 GPH) , RCDNDARlLY' CClfn'AINID.....' PR£SSUAIZEO PIPING (QIIct...., IIJIJ/1): , ',: ~ .. _... 10. COHTNJOUS TUR8INE SUIoP SENSOR mDI AUDIBLE AND VlSUALALAAM8 AND (0Iec:t _) . . o .. AUTO PUMP SHUT OFF \'It'HEN A U!AK OCCURS 0, Þ. AUTO PUMP SHUT OFF FOR LI!AKS. SYSTEM FAlWREAND SYSTEM OISCOfN!CTlON o Co NO AUTO PUMP SHUT OFF o 11. ~T1C LINE U!AK DETECTOR 13.0 GPH TEST) rdD:I FLOW 8HÙToi:F OR , RESTRICTIOH ".,', ' 12. NHJA1.1NTEGRfTY TEST eO.1 ~ SUCTlOt6'GRAVI1Y SYSTEM: , I.~ o 13. COHTNJOUS"'8ENIOR. AUDaI ~Vl8UALALMMI 4IIOVI!GAOUNO PIfIIHO a 2. SUCT10Ñ , 0 15. UNKNOWN . 0 lit. OTHER a 3. OAAVIT'\' - ~; 4f ~ o I. FAP COYtATlIL! WI 10ft MeTHANol o 7. OALVANZIO STEIL ' o 8. FI.£XIII.E (HOPE) 0 lit. one a t. CATHOOICPROTlCTION o II. UNI<NO'M4 4E :..::?~~'):. A80VEGROUND PIPING 4E PRESSURIZED PIPING (CIt«k" INt IIJPIY): o 1. ELeCTRONIC LINE U!AK DETECTOR 3.0 GPH TEST mDiAUfO PUIotP SHUT OFF FOR LEAK. SYSTEM FALUAE. AND SYSTEM DISCONIECTION . AUDI8U! AND VISUAL ALARMS a 2. MONTHLY U GPH TEST a 3. ANNUAL INTEGRÌrY TEST (0.1 GPH) a 4. DALY VISUAL CHEQ( CON\IENT1ONAL SUCTION SYSTEMS (QIIct.....,.",q): . " a 5. DAILY VISUAL MONITORING CW PFING AND PUMPING SYSTEM o I. TRIENNIAL IN1'EGRITY TEST e0.1 GPH) " .. . SAFE SUCTION SYSTEMS NO VALVES IN BELOW GROUND PIPING):, o 7. SELF MONfTORING ., GRAVI1Y FLOW (Chedt""" ¥PlY): a, I. DALY VISUAL MONrTORING. , o t. BIENNIAL IN1'EGRITY TEST (0.1 GPH) '. \ -. "~,< 81!CONDAR1LY'è:oNÎ'ÁÍN!D' ...... PAESSUAIZEO PIPING (Chedt""" IIJIJ/1): 10. CONT1NUOUS TURBIN! SUMP SENSORmDI ~ AND VISUAL ALARMS AND (ctiec:k_) o .. AUTO PUMP SHur OFF WHEN A LEAK OCCURS o Þ. AUTO pUMP SHUT OFf' FOR LI!AKS. SYSTEM FAIWRI! AND SYSTEM DISCONNECTION o c. NO AUTO PUMP SHUT OFF o 11. AU1"OMAT1C U!AK DETECTOR o 12. ANNUAL INT'EGfUTY TEST e0.1 GPH) ,,~, ~. . SUCTIONIGRAVI1Y SYSTEM: o 13. CON1'INUous'" SENSOR . AIJDIIILE ANÒ~v..w. A&AIM '.... -1!NCY~TOMONLY{Cllect"......, . IIIIRGINCYG..aATORIO...V(Ctllct..""wM . , LJ ,.~ 'CO~ SUM' 8ØJSOR~AÜTtn·uw¡HTOí,F..'MlDÏÛN.Ð:--' :;;;,0- 'c:r,'4. 'C:ÔtiríNJOUS s\íMPSêÑãOR~.wrò ~ mOFF. ALioœLeAND VISUAL VISUAL AI.AMt8 AI.ARMS a 15. ~T1C LJNI! LEAK DETECTOR 13.0 GPH TEST) ïdItIIILt FLOW 8HUr OFJI OR a 15. AUTOMAT1C LINE U!AK DETECTOR 13.0 OPH TlST) RESTRICTION o 18. 4NNUALINTEGRlTYTEST(0.1 QPH) o 17, OAIL Y VISUAL CHECK I ¡-- o 18. ANNUAL INTEGRITY TlST(0.1 GAt) o 11. OAILYVlSUALCHECK ~~~;: .~ L./~ >~.:~~'::~ 't." ~~'. /."':i¡~" -'~; " ''T .' " . ..',,,,".-----." ' ...::..~~ ..~'~~.~~~~.-.... ,'_i . :-':. _!t"j.~.~~~. DISPENSeR CONTA/NMIHr C 1. I'LOAT MIØWoIIM THAT IHUl'SCIfP IH&\R VALve OATlINSTAU.eO .... C 2. CON11NUOUIOI8PIN8I!RMi8lH8OÁ'.~ANDVlSUALALAAMS [J 3. CON11NUOUI DIIPINIIÌt PAN __fdDjAUTO SHUT OFF FOR DISPEHSIR . AUOI8U! NÐ VISUAL AI.ARMS DC. OWNIRIOPIRATOR IIGNATURI I cerUfy III.. !lie iIIfarmaIIon IIftMCIed "...,. !lINe n __10 !lie NIt d rnr 1IrtcMIede. SIONATUREOF ~ HAMIl OF O'NN!R.'OPlAATOR (pIfItt14 ZMIl (Ç-LL fÆl4PßUsíl..€ 4. DAILY VISUAL CHECK [J ,I. .TReNCH UNIR I MONrt'ORING a&NONI ." " 4111 471 474 """~'QIII(I'Or,",,"'CM07 47' 1\ DATI ..70 S; 6CtÀÚS7' ..12 IPtmtllIUIIMr (For" 11M only) 413 FImIII ACIIftMd (For IDCIIt "'IW)IJ UPCF (7199) S:\CUPAFORMS\SWRC8-8~wPD I :·1, . ~._~~ ~. .\ e e INVOICE #dg000120 TANK TESTERS, INC. P. O. BOX 95 GARDINER, OREGON 97441 541-271-1124 TEST DATE: 04/20/00 TANK STATUS EVALUATION REPORT ----------------------------- ***** CUSTOMER DATA ***** ***** SITE DATA ***** CAL-VALLEY EQUIPMENT 3500 GILMORE AVE. WIBLE ROAD SERVICE CENTER 4100 WIBLE ROAD BAKERSFIELD, CA. 93398 BAKERSFIELD, CA. 93313 CONTACT: CARTER, PAM PHONE #: 661-327-9341 CONTACT: FISHER, DEE PHONE #: 661-398-5941 ***** COMMENT LINES ***** The services described in this document have been provided in a manner consistent with" the current standards of the profession and to the best of my knowledge comply with all applicable state and local statutes, regulations and ordinances. TANK #1: DIESEL FUEL 2 TYPE: STEEL RATE: .018501 G.P.H. GAIN TANK -IS TIGHT. TANK #2: REG UNLEADED TYPE: STEEL RATE: .015853 G.P.H. GAIN TANK IS TIGHT. OPERATOR: _ DElNNIS-E.. GOODANSIGNATURE: -{) ÞW«- '- }.. . DATE: ------------- _ '! :d_Q ,.j) í) ·S :j' i\, ~ r. t· INVOICE #dg000120 e . TANK TESTERS, INC. P. O. BOX 95 GARDINER, OREGON 97441 541-271-1124 TEST DATE: 04/20/00 TANK STATUS REPORT -- ULLAGE TEST --------------------------------- ***** CUSTOMER DATA ***** ***** SITE DATA **.. *'1< :AL-VALLEY EQUIPMENT 3500 GILMORE AVE. WIBLE RCAD SERVICE CENTE¡"~ 4100 WIELE ROAD :3AKERSFIELD, CA. 13308 BAKERSFIELD, CA. 93313 ::'ONTACT: CARTER, PAM ?HONE #: 661-327-9341 CONTACT: FISHER, DEE PHONE #: 661-398-5941 ***** COMMENT LINES ***** The services described in this document have been provided in a manner consistent with the current standards of the profession and to the best of my knowledge comply with all applicable state and local statutes, regulations and ordinances. '~ANK #1: DIESEL FUEL 2 TYPE: STEEL SN: -.(,7 TANK IS TIGHT. ';~ANK # 2: REG UNLEADED TYPE: STEEL SN: -.10 TANK IS TIGHT. OPERATOR: ~J)~81S~e~~Qº[)"NSIGNATURE: J.f!~~Ç~~~=DATE: ~'t~L)_._,,-ð ;' ^' j', ~'r. '. r. . ******* TAN K D A T A TANK NO. TANK NO. 1 2 TANK DIAMETER (IN) 96 96 LENGTH (FT) 26.59 26.59 VOLUME ( GAL) 10000 10000 TYPE ST ST FUEL LEVEL ( IN) 68 69 FUEL TYPE DIESEL 2 REG UNLD dVOL/dy (GAL/IN) 120.56 119.26 CALIBRATION ROD DISTANCE 1 10.65625 2 26.95313 3 41.93750 4 56.93750 5 74.93750 - ******** TANK NO. 3 TANK NO. 4 '';1 ¡:;,\.."" .' . ******* C U S TOM E R JOB NUMBER CUSTOMER (COMPANY NAME) CUSTOMER CONTACT (LAST, FIRST): ADDRESS - LINE 1 ADDRESS - LINE 2 CITY, STATE ZIP CODE (XXXXX-XXXX) PHONE NUMBER (XXX)XXX-XXXX ******* COM MEN T ******* SIT E SITE NAME (COMPANY NAME) SITE CONTACT (LAST, FIRST) ADDRESS - LINE 1 ADDRESS - LINE 2 CITY, STATE ZIP CODE (XXXXX-XXXX) PHONE NUMBER (XXX)XXX-XXXX GROUND WATER LEVEL (FT) NUMBER OF TANKS LENGTH OF PRE-TEST (MIN) LENGTH OF TEST (MIN) . D A T A ******** 000120 CAL-VALLEY EQUIPMENT CARTER, PAM 3500 GILMORE AVE, BAKERSFIELD, CA. 93308 661-327-9341 L I N E S ******* D A T A ******** WIBLE ROAD SERVICE CENTER FISHER, DEE 4100 WIBLE ROAD BAKERSFIELD, CA. 93313 661-398-5941 20 2 30 180 I "'I~" I t:.~ Il:n~, 11'1'-'. P. O. BOX 95 GARDINER, OREGON 97441 (541) 271·1124 TEST LOCATION: WIBLE ROAD SERVICE CENTER 4100 WIBLE ROAD BAKERSFIELD, CALIFORNIA "' e CAMPO MILLER PL400 PRODUCT LINE TEST RESULTS DATE: 4-21-00 TANK NO, TESTED TEST !NITAL FINAL VOLUME LEAK RATE LEAK RATE TEST RESULTS DURATION PRESSURE PRESSURE DISPLACED PASS I FAIL REG UNLD 1 5 50 49 -4 -0.0095 PASS 2 5 50 46 -7 -0.0167 PASS DIESEL 2 COMMENTS: -e Leak Detectors Functioning Properly? DIESEL 2 YES REG UNLD YES .(/-~ dz I 1-. LY.-L.--n.~ ?( ,. ,dl-< DENNIS E. GOODAN California Lic #91-1000 : ,;-! .. j --- " . ,1~'- . : ~_-_':., ;.ijl~ ß f \c1 '(', . \ ~ - Pacific Gas and Electric Company April 3, 2000 Tammie R. Candelario Manager Environmental Support and Services State Water Resources Control Board Division of Clean Water Programs p, O. Box 944212 Sacramento, CA 94244-2120 ~~c~ /14 i' 0 ~v~O ~NI1~a .? <'000 ~$~ ~~C~$ 271 280 and 77 Beale Street. Room 2437 San Francisco, CA 94105 Mailing Address P'Q, Box 7640 San Francisco. CA 94120 415,9737746 Fax: 415,973,9201 Pacific Gas and Electric Company hereby submits the following documents in support of the use of the financial test to demonstrate financial responsibility for taking corrective action and compensating third parties for bodily injury and property damage caused by sudden accidental releases in the amount of at least $1 nùllion per occurrence and $2 million annual aggregate and nonsudden accidental releases in the amount of at least $3 million per occurrence and $6 nùllion annual aggregate arising rrom operating underground storage tanks: . 1. Letters dated April 3, 2000 rrom PG&E's Chief Financial Officer; 2. PG&E's 2000 Annual Report including Report of Independent Public Accountants; 3. PG&E's FORM 10-K; and 4. Report ofDeloitte & Touche (CPAs) Please contact Mr. Rex Bell of my staff at (415) 973-6904 if you have any questions regarding this matter. Sincerely, J~~.~~ Enclosures RBell(3-6904):rb I ¡~ \' J :; I ~- cc (wi attachments): - - Regional Water Quality Control Boards CUP As / i' e, e Deloitte & ' Touche o Deloitte & Touche LLP Telephone: (415) 783-4000 50 Fremont Street Facsimile: (415) 783-4329 San Francisco, California 94105-2230 INDEPENDENT ACCOUNTANTS' REPORT ON APPLYING AGREED-UPON PROCEDURES Tò the Board of Directors of Pacific Gas and Electric Company San Francisco, California We have performed procedures included in the Code of Federal Regulations (CPR) Title 40, Part 265, Section 143 (40 CPR 265.143), which were agreed to by the Environmental Protection . Agency, the State Water Resources Control Board, Division of Clean Water Programs and Pacific Gas and Electric Company, solely to assist the specified parties in evaluating management's assertion about the Company's compliance with the financial test option as of December 31, 1999, included in the accompanying letter dated April 3, 2000 from Kent M. Harvey, Senior Vice President - Treasurer and Chief Financial Officer of Pacific Gas and Electric Company. This agreed-upon procedures engagement was performed in accordance with standards established by the American Institute of Certified Public Accountants. The sufficiency of these procedures is solely the responsibility of the specified parties. Consequently, we make no representation regarding the sufficiency of the procedures described below, either for the purpose for which this report has been requested or-for any other purpose. The procedures that we performed and related findings are as follows: 1. We compared the amounts included in Items 5 and 6 under Alternative II in the letter referred to above with the corresponding amounts in the audited financial statements of Pacific Gas and Electric Company as of and for the year ended December 31, 1999, on which we have· issued our report dated March 3, 2000, and noted that such amounts were in agreement. 2. We recomputed from, or reconciled to, the financial statements referred to in procedure 1, the information included in Items 5 and 6 under Alternative II in the letter referred to above and noted no differences. ' We were not engaged to, and did not, perform an examination, the objective of which would be the expression of an opinion on the accompanying letter dated April 3, 2000. Accordingly, we do not express such an opinion. Had we performed additional procedures, other matters might have come to our attention that would have been reported to you. This report is intended solely for the information and use of the specified parties listed in the first paragraph, and is not intended to be and should not be used by anyone other than these specified parties. ~, i 7~~ "G/' April 3, 2000 Deloitte Touche Tohmatsu l' e . Deloitte & Touche l.~ ~ DelQitte & Touche LLP Telephone: (415) 783-4000 50 Fremont Street Facsimile: (415) 783-4329 San Francisco, California 94105-2230 INDEPENDENT ACCOUNTANTS' REPORT ON APPLYING AGREED-UPON PROCEDURES , To the Board of Directors of Pacific Gas and Electric Company San Francisco, California We have perfonned procedures included in the Code of Federal Regulations (CPR) Title 40, Part 265, Section 143 (40 CPR 265.143), which were agreed to by the Environmental Protection Agency, the State Water Resources Control Board, Division of Clean Water Programs and. Pacific Gas and Electric Company, solely to assist the specified parties in evaluating management's assertion about the Company's compliance with the financial test option as of December 31, 1999, included in the accompanying letter dated April 3, 2000 from Kent M. Harvey, Senior Vice President - Treasurer and Chief Financial Officer of Pacific Gas and Electric Company. This agreed-ùpon procedures engagement was perfonned in accordance with standards established by the American Institute of Certified Public Accountants. The sufficiency of these procedures is solely the responsibility of the specified parties. Consequently, we make no representation regarding the sufficiency 'of the procedures described below, either for the púrpose for which this report has been requested or for any other purpose. The procedures that we perfonned and related findings are as follows: 1. We compared the amounts included in Items 5 and 6 under Alternative II in the letter referred to above with the corresponding amounts in the audited financial statements of Pacific Gas and Electric Company as of and for the year ended December 31, 1999, on which we have . issued our report dated March 3, 2000, and noted that such amounts were in agreement. 2. We recomputed from, or reconciled to, the financial statements referred to in procedure 1, the infonnation included in Items 5 and 6 under Alternative II in the letter referred to above and noted no differences. We were not engaged to, and did not, perfonn an examination, the objective of which would be the expression of an opinion on the accompanying letter dated April 3, 2000. Accordingly, we do not express such an opinion. Had we perfonned additional procedures, other matters might have come to our attention that would have been reported to you. I ,I This report is intended solely for the infonnation and use of the specified parties listed in the first paragraph, and is not intended to be and should not be used by anyone other than these specified parties. . , . D~ ,~c..L, t¿,a April 3, 2000 Deloitte Touche Tohmatsu ¡.. e e Deloitte & Touche l~ '4Þ' Deloitte & Touche LLP Telephone: (415) 783-4000 .. 50 Fremont Street Facsimile: (415) 783-4329 San Francisco, California 94105-2230 , INDEPENDENT ACCOUNTANTS' REPORT ON APPLYING AGREED,.UPONPROCEDURES To the Board of Directors of Pacific Gas and Electric Company San Francisco, California We have perfonned procedures included in the Code of Federal Regulations (CFR) Title 40, Part 265, Section 143 (40 CFR 265.143), which were agreed to by the Environmental Protection Agency, the State Water Resourèes Control Board, Division of Clean Water Programs and Pacific Gas and Electric Company, solely to assist the specified parties in evaluating management's assertion about the Company's cQrnpliance with the financial test' option as of December 31, 1999, included in theåccompanying letter dated April 3, 2000 from Kent M. Harvey, Senior Vice President - Treasurer and Chief Financial Officer of Pacific Gas and Electric Company. This agreed-upon procedures engagement was perfonned in accordance with standards established by the American Institute of Certified Public Accountants. The sufficiency of these procedures is solely the responsibility of the specified parties. Consequently, we make no representation regarding the sufficiency of the procedures described below, either for the purpose for which this report has been requested or for any other purpose. The procedures that we perfonned and related findings are as follows: 1. We compared the amounts included in Items 5 and 6 under Alternative II in the letter referred to above with the corresponding amounts in the audited financial statements of Pacific Gas and Electric Company as of and for the year ended December 31, 1999, on which we have issued our report dated March 3, 2000, and noted that such amounts were in agreement. 2. We recomputed from, òr reconciled to, the financial statements referred to in procedure 1, the infonnation included in Items 5 and 6 under Alternative II in the letter referred to above and noted no differences. We were not engaged to, and did not, perfonn an examination, the objective of which would be the expression of an opinion on the accompanying letter dated April 3,2000. Accordingly, we do not express such an opinion. Had we perfonned additional procedures, other matters might have come to our attention that would have been reported to you. This report is intended solely for the infonnation and use of the specified parties listed ìn the first paragraph, and is not intended to be and should not be used by anyone other than these specified parties. , J:)~ f 7,..,"'i.c. uf1 April 3, 2000 Deloitte Touche Tohmatsu '1 e e m Pacific Gas and Elecúic Company. Kent.M. Harvey Senior Vice President-Treasurer ànd Chief Financial Officer 77 Beale Street, 32nd Floor San Francisco, CA 94105 Mailing Address Mail Code B32 PO, Box 770000 San Francisco. CA 94177 April 3, 2000 415,973.2393 Fax: 415,973.4343 State Water Resources Control Board Division of Clean Water Programs P. O. Box 944212 Sacnunento,CA 94244-2120 Ladies / Gentlemen: In compliance with Title 23, Section 2809.1, California Code of Regulations, and Subpart H of40CFR Part 280, owners or operators of underground storage tanks must maintain a certification of financial responsibility as one of the recordkeeping and reporting requirements. The following response is therefore provided which will also be sent tò local implementing agencies. CERTIFICATION OF FINANCIAL RESPONSmn..ITY Pacific Gas and Electric . Company hereby certifies that it is in compliance with the requirements of Section 2807, Article 3, Chapter 18, Division 3, Title 23, California Code of Regulations. The mechanisms used to demonstrate financial responsibility as required by Section 2807 are as follows: Underground storage tanks at the Pacific Gas and Electric facilities listed below are assured by the financial test of self-insurance to demonstrate financial responsibility for taking corrective action and compensating third parties for bodily injwy and property damage caused by sudden accidental releases in the amount of at least, $1 million per occurrence and $2 million annual aggregate and nonsudden accidental releases in the amount of at least $3 nùllion per occurrence and $6 million annual aggregate arising from operating underground storage tanks. Pacific Gas and Electric also uses financial tests to demonstrate evidence of financial responsibility under other U.S. Environmental Protection Agency regulations or state programs authorized by the U.S. Environmental Protection Agency under 40 CFR Parts 271 and 145 including the financial assurance for closure (40 CFR Part 265.143), liability requirements (40 CFR Part 265.147), and the financial test of self-insurance (40 CFR Part 280.95). A ril3, 2000 Date Senior Vice President and Chief Financial Officer Title /v/¡W( Signature of witness April 3, 2000 Date Rex Bell Name of witness cc: SWRCB Underground Tank Program Local Implementing Agencies RBell(3-6904):rb 1; e '. m Pacific Gas and Elecúic Company Kent M. Harvey Senior Vice President-Treasurer and Chief Financial Officer 77 Beale Street. 32nd Floor San Francisco. CA 94105 Mailing Address Mail Code B32 PO, Box 770000 San Francisco. CA 94177 April 3, 2000 State Water Resources Control Board Division of Clean' Water Programs P. O. Box 944212 Sacramento, CA 94244-2120 415,973.2393 Fax: 415,973.4343 Ladies / Gentlemen: I am the chief financial officer of Pacific Gas and Electric Company (pG&E). Our business address is located at 77 Beale Street, San Francisco, California. This letter is in support of the use of the financial test of self-insurance to derµonstrate financial responsibility for taking corrective action and compensating third parties for bodily injury and property damage caused by sudden accidental releases in the amount of at least' $1 million per occurrence and $2 million annual aggregate and nonsudden accidental releases in the amount of at least $3 million per occurrence and $6 million annual aggregate arising :ITom operating underground storage tanks. Underground storage tanks at the following facilities are assured by this financial test or a financial test under an authorized State program by this owner or operator: F ACll..ITY NAME AND ADDRESS NUMBER OF TANKS gels Camp 1108 Murphy Grade Road gels Camp, CA 95222 3 tioch Service Center 111 Hillcrest Avenue tioch, CA 94509 3 uberry Hydro Center 3755 Old Mill Road uberry, CA 93602 2 uburn Service Center 43 Sacramento Street uburn, CA 95603 4 akersfield Service Center 101 Wible Road akersfield, CA 93309 2 elmont Service Center 75 Industrial Road San Carlos, CA 94070 3 1" I' e Ie I i I F ACll..ITY NAME AND ADDRESS NUMBER OF TANKS !Burney Service Center 2 Black Rànch Road near Highway 299 !Burney, CA 96013 Caribou Camp I Caribou Road caribou, CA 95954 Chico Service Center 2 11239 Midway Chico, CA 95926 Cinnabar Service Center 3 j08 Stockton Street San Jose, CA 95119 Colma Service Center 3 4-50 Eastmoor Avenue Daly City, CA 94015 Colusa Service Center 1 ?oo and Main Streets Colusa, CA 95932, Concord Service Center 3 1030 Detroit Avenue Concord, CA 94524 Cottonwood Substation 2 Trefoil Lane Cottonwood, CA 96022 Cupertino Service Center 3 10900 N. Blaney Avenue Cupertino, CA 95014 Davis Service Center 4 316 L Street Davis, CA 95616 Diablo Canyon Nuclear Power Plant 2 Near Avila Beach, CA 93401 Edenvale Service Center 6 6402 Santa Teresa Blvd. San Jose, CA 95119 lEI Dorado Service Center 3 ~636 Missouri Flat Road· PIacerville, CA 95667 T':. - r. FACILITY NAME AND ADDRESS NUMBER OF TANKS ureka Service Center 475 Myrtle Avenue ureka, CA 95501 2 2 remont Materials Distribution Center 2 2105 Boyce Road remont, CA 94538 remont Service Center 3 1800 Boscell Road remont, CA 94538 Garberville Service Center 2 1328 Redwood Drive arberville, CA 95540 neral Office Complex. 4 7 Beale Street San Francisco, CA 94106 serville Service Center 2 0880 Geyserville Avenue Geyserville, CA 95441 rass Valley Service Center 3 88 Taylorville Road' , rass Valley, CA 95945 yward Service Center 3 4300 Clawiter Road yward, CA 94545 ey Compressor Station 3 2999 Community Boulevard . nkley, CA elms Pumped Generation Plant 3 725 Helms Circle Shaver Lake, CA 93664· ollister Service Center 2 150 7th Street ollister, CA 95023 ackson Service Center 3 1630 Jackson Gate Road ackson, CA 95650 i' ~ -- e F ACll..ITY-NAME AND ADDRESS NUMBER OF TANKS ettleman Compressor Station 4453 Plymouth Avenue venal, CA 93204 . g City Service Center 04 N. 2nd Street . g City, CA 93930 ivermore Service Center , 797 FirstStreet ivermore, CA 94550 ivermore Training Facility 205 National Drive ivèrmore, CA 94550 s Banos Service Center 40 "I" Street os Banos, CA 93635 . Service Center 31 Schwerin Street aIy City, CA 94014 erced Service Center 60 W. 15th Street erced. CA 95340 odesto Service Center 1524 N. Carpenter odesto, CA 95351 onterey Service Center 311 Garden Road onterey, CA 93940 apa Service Center/Substation 00 Burnell Street apa. CA 94558 orth Valley Materials Distribution. Center. 736 Rancho Road sville, CA 95901 1 1 3 2 1 4 3 2 2 1 3 3 2 i' \ I , -- e F ACll..ITY NAME AND ADDRESS NUMBER OF TANKS akhurst Service Center 0150 Road 426 akhurst, CA 93644 akland Service Center 801 Oakport Street akland, CA 94601 eland Office 10 4th Street eland, CA 95963 roville Service Center 226 Veatch Street roville, CA 95965 etaluma Service Center 10 Corona Road etaluma, CA 94952 oe Dam . ghway 70 10 miles SW/O Storrie Road nincorporated (Butte County), CA ratt Mountain Repeater nd of Pratt Mountain Road nincorporated, CA ed Bluff Service Center 15 Luther Road ed Bluff, CA 96080 · chmond Service Center 1100 South 27th Street · chmond, CA 94804 · dgecrest Service Center 30 S. China Lake Blvd. 'dgecrest, CA 93555 · 0 Vista Service Center · ghway 12 & Virginia Drive · 0 Vista, CA 94571 ogers Flat Hydro Headquarters. · ghway 70 Storrie, CA 95980 ' Sacramento Gas Load Center 001 Front Street Sacramento, CA 95818 2 2 1 1 1 1 1 2 3 2 2 3 2 '. , - tit FACILITY NAME AND ADDRESS NUMBER OF TANKS Sacramento Service Center 3 ~555 Florin-Pèrkins Road Sacramento, CA 95828 , Sacramento Valley Regional Office 1 , ~740 Gateway Oaks Drive Sacramento, CA 95818 , Salinas Service Center 3 1356 E. Alisal Road Salinas, CA 93901 San Francisco Service Center 4 ') 180 Harrison Street San Francisco, CA' 94110. San Luis Obispo Service Center 1 ,.325 S. Higuera Street San Luis Obispo, CA 93401 San Rafael Service Center 2 1220 Andersen Drive San Rafael, CA 94901 . Santa Cruz Service Center 3 615 7tlJ. Avenue Santa Cruz, CA 95062 Santa Maria Service· Center 1 2445 S. Skyway Street Santa Maria, CA 93454 Santa Rosa Compressor Station 1 1820 Piner Road Santa Rosa, CA 95404 Santa Rosa Headquarters 1 111 Stony Circle ~anta Rosa, CA 95401 Santa Rosa Service Center 2 13965 Occidental Road Santa Rosa, CA 95401 Selma Sèrvice Center 2 12139 Sylvia Street Selma, CA 93662 Sonora Service Center 3 14550 Toulumne Street Sonora, CA 95370 .,~ :t - e FACILITY NAME AND ADDRESS NUMBER OF TANKS Stockton Service Center 040 West Lane , StoCkton, CA 95204 4 I 1 I I I I' aft Service Center 50 Gardner Field Road aft, CA 93268 2 empleton Service Center 160 Cow Meadow Place empletoIl, CA 93465 2 opock Compressor Station 14 MlIes Southeast: of Needles, CA eedles, CA 92363 racy Maintenance Station .0. Box 270 racy, CA 95376 1 2 . ah Service Center 541 North State Street . ah, CA 95482 3 acaville Service Center' 158'Peabody Road acaville, CA 95688 3 alIejo Service Center 03 Carlson Street alIejo, CA '94590 2 alnut Creek Service Center 1232 Boulevard Way alnut Creek, CA 94595 3 illow Creek Service Center illow Creek, CA 95573 1 oodland Service Center o Kentucky Avenue oodland, CA 95695 3 ANK TOTALS 190 FEDERAL CLOSURE AMOUNT: 190 Tanks X $36,000ITank = $ 6,840,000 ,.1 ,'t - e Afinancial testis also us~d by this own~r or operator to demonstrate evidence of fÏi1ancial responsibility, in the following amounts under other EP A regulations or state programs authorized by EPA under40 CPR Parts 271 and 145: EP A Regulations Closure (Sections 264.143 and 265.143).............................'.......... ~ost-Closure Care (Sections 264.145 and 265.145)....................... Liability Coverage (Sections 264.147 and 265.147)..... ....,............. Sudden................. ....... Nonsudden....................... . Corrective Action (Section 264.1 01(b )).......... .... ........................... Plugging and Abandonment (Section 144.63)................................ Closure.................................;....................................................... . Post-Closure Care......................................................................... Liability Coverage........:.............................:.................................. Corrective Action.............................................................. t........:... Plugging and Abandonment........................................................... Total.......;.............................. ~..............;....................................... Amount $6,840,000 N/A $2,000,000 $6,000,000 N/A N/A $6,840,000 N/A $8,000,000 N/A N/A $14,840,000 This owner or operator has not received an adverse opinion, a disclaimer of opinion, or a "going concern" qualification trom an independent auditor on his financial statements for the latest completed fiscal year. ' '.'\ .. e Alternative II 1. Amount of annual UST aggregate coverage being assured by a test, and! or guarantee.......................................... Sudden.......... . Nonsudden.... . 2. Amount of corrective action, closure and post-closure care costs, liability coverage, and plugging and abandonment costs covered by a financial test, and! or guarantee............................ , . 3. Sum of lines 1 and 2................................................................ 4. Total tangible assets..... .........:........ ...... ................................... 5. Total liabilities [if any of the amount reported on line 3 is included in total liabilities, you may deduct that amount trom this line and add that amount to line 6]..................................... 6. Tangible net worth [subtract line 5 :fÌ'om line 4]......................~. 7. Total assets in the U.S. [required only if less than 90 percent of assets are located in the U.S.].....................~........................ 8. Is line 6 at least $10 million?.................................................... 9. Is line 6 at least 6 times line 3?................................................ 10. Are at least 90 percent of assets located in the U.S.? [If "No," complete line 11.]..... 11. Is line 7 atleast 6 times line 3?. .'............................................. 12. Current assets..............................;.......................................... 13. Current liabilities.................................................................... 14. Net working capital [subtract line 13 £rom line 12].................. 15. Is line 14 at least 6 times line 3?.............................................. , 16. Current bond rating of most recent bond issue........................ 17. Name of rating service............................................................ e $2,000,000 $6,000,000 $6,840,000 $14,840,000 $21,401,000,000 $15,69Q,000,000* $5,702,000,000* Not required Yes Yes Yes Not required Not required Not required Not required Not required Al Moody's .. . . 18. Date of maturity of bond.. ........................................................ , 19. Have financial statements for the latest fiscal year been :filed with the SEC, the Energy Information Administration, or the Rural Electrification Administration?....................................... * Derived trom 1999 Annual Report e March 1, 2024 Yes; SEC I hereby certify that the wording of this letter is identical to the wording specified in 40 CPR Part 280. 9S( d) as such regulations were constituted on the date shown immediately below. Sincerely, KE M. HARVEY· . Senior Vice President- Treas rer and Chief Financial Officer April ~, 2000 , cc with attachment: Regional Water Quality Control Boards Certified Unified Program Agencies '.' -. . I: . r ! m PG&E Corporation , 1999 Annual Report I I I I Ii I ' Ii Corporate Overview II . PG&E Corporation isa national energy-based holding company with 1999 revenues exceeding $20.8 ~illion and $29.7 billion in assets. It markets energy services and products throughout North America through its National Energy Group, and is the parent company of Pacific Gas and Electric Company, the Northern and Central California utility that delivers natural gas arid electricity service to one in every 20 Am~ricans. Financial Highlights (Unaudited, dollars in millioµS, except per share amounts) Operating Revenues Net Income (loss) Net income from operations Items impacting' comparabilitfl) Reported net income (loss) Earnings (loss) per Common Share, basic and diluted Net income from operations Items impacting comparability(1) Reported net earnings (loss) per common share' Dividends per Common Share Total Assets 'Number of common shareholders Number of common shares outstanding 1999 1998 $ 20,820 $ 19,577 $ 826 $ 742 . (899) (23) , (73) 719 2.24 $ 1.94 (2.44) (.06) (.20) $ 1.88 $ $ $ 1.20 $ 29,715 151,000 384,406,113 $ 1.20 $ 33,234 164,000 382,603,564 I· , ' , (1) Items impacting comparability include the following in 1999: write~.down ofassetsrèlatedto sale of Texas natural gas liquidsánd natur:algas pipèline business of $890 million ($2:42 per share); provision f01: loss on sale of retail energy services unit of $58 million ($.16 per share); adjustment of litigatiòn liability of $35 million ($.10 per share); income from change in accounting principle of $12l11i11ion 'C$.03 per share); and other items of $2 million ($.01 per share). ItemsimpactingcoI!1parabilityin 1998 include loss on sale of Australian energy holdings of $23 million ($.06 per share). 'I Table of Contents 1 Letter to Shareholders 3 PG&E Corporation At A Glance 4 Selected Financial Data 5 Management's Disèussion and Analysis 26 PG&E Corporation and Pacific Gas and Electric Company Consolidated Financial Statements 36 Notes to Consolidated Financial Statements 67 Quarterly Consolidated Financial Data (Unaudited) 68 Independent Auditors' Report 69 Responsibility for Consolidated Financial Statements,' 70 Directors 72 Officers 74 Shareholder Information :1 ;111 [I :1 '[ '; ,I ,I I :[ A Note About This Year's Report Due to regulato¡y delays in our utility unit's General Rate Case, we were unable to print our traditional annual report in enough time to have it reach shareholders for the annual meeting. As a result, we are providing it to you in this fonn. We are preparing a summary report with more infomiation on the Company's accomplishmentS and plans. If you would like a copy, please call 1.800.654.2582 or visit our website at www.pgecorp.com. ·' . e To Our Shareholders: e Your Company delivered strong operating performance in 1999, Net income from operations grew by 11 percent. Operating revenues grew by 6 percent. And, earnings per share from operations grew by 15 percent to $2.24. These results followed strong perforri1ance in each of our businesses. Specifically, our National Energy Group grew its contribution to earnings per share by 42 percent to $0.17 per share, and Pacific Gas and Electric Company's' contribution to earnings per share grew by 14 percent to $2.07. National Energy Group In 1999, we established the PG&E National Energy Group to integrate our national competitive business units. In 1999, this unit both grew and positioned itself for/further growth. The National Energy Group operates an electric generation portfolio of more than 7,000 megawatts;, In 1999, construction continued on the Millennium Power project, a 360-megawatt natural gas-fueled plant in Chárlton, Massachusetts, scheduled for operation in the fourth quarter of 2000, and we started construction of the Lake Road Generating Plånt, a 792-megawatt natural gas-fueled plant in Killingly, Connecticut, scheduled for operation in 2001. Shortly after the new year, we began construction of the 1,048-megawatt natural gas-fueled La Paloma Generating Plant near Bakersfield, California. Also in 1999, we announced development of a 12-megawatt wind generating project, to be located-in New York, one of the first competitive wind power generating facilities in the eastern United States, This project is scheduled to begin construction in May 2000 and to begin operation in September 2000. Our development portfolio includes an additional 7;500 megawatts of new generating projects with planned operàting dates between 2002 and 2004. Our Northwest gas pipeline business delivered strong operational and financial performance in 1999, and we expect that to continue. It is,one of the largest transporters of Canadian gas into the United States and provides about 30 percent of the natural gas supply for California, a market that continues to be among the leaders in terms of growth and demand. In the electric part of our energy trading business, we began realizing the synergies we' anticipated with our New Eriglandgenerating portfolio, providing the platform for our trading business to fInish the year as the number one ,trader in the Northeast. Our energy trading operation was also instrumental in partnering with our generating business to achieve significant portfolio management successes in 1999, leveraging relationships and market expertise to restructure contracts. We also took two actions designed to sharpen the focus of our national energy strategy and improve future earnings: we announced the sale of our Texas natUral gas businesses to El Paso Energy and we took steps to sell our retail energy services business. While these actions had a one-time effect of ($2.58) per share on our 1999 reported earnings, they will result in improved earnings in 2000 and beyond. Pacific Gas and Electric Company Pacific Gas and Electric Company delivers energy to about one of every 20 Americans. ItS Northern and Central California service territory is at the heart of one of the nation's most vibrant economies--one that saw significant gains in per capita income, falling unemployment rates, and continuing strong growth in the high-tech and services sectors last year. This unit received base revenue increases effective in 1999 as a result of the California Public Utilities Commission's decision in its General Rate Case. This decision, along with continued cost management, provides this unit the opportunity to earn its full authorized return on equity for its distribution business. Investments made in recent years to boost the reliability of our electric and gas distribution system are producing strong operating results. In 1999, Pacific Gas, and Electric Company's customers, on average, experienced 12 percent fewer outages than in 1998. And, 91 percent of our customers who responded, when asked to rate the quality of the utility's service, rated it- "good," ''very good," or'''excellent.'' 1 ,! . Our Diablo, can. nuclear generating plant rema~ the beS'erating facility of its kind in the country. Last year, it received an unprecedented seventh consecutive "number one" rating , from the Institute of Nuclear Power Operations, which evaluates nuclear power plants for safety and performance. The plant continues to generate· significant contributions to net income. Specific 1999 ,llighIigbts Across the entire Company, safety performance improved in 1999. The number of lost workday incidents was down by 17 percent from 1998, and the rate of the inCidents was also down. OSHA recordable ineidents also declined, and are nòw at about half the level of five, years ago. Y2K turned but to be a non-event as we transitioned into 2000 without any significant Y2K . issues, culminating several years of preparation. We continued to build the "A" team at PG&E Corporation through learning,' develoþment, and recruiting. In 1999, this included adding two new senior executives to our management team: Thomas, G. Boren as President and Cl)iefExecutive Officer of the NationaL Energy Group, and Peter A. Darbee as Senior Vice President and Chief Financial' Officer. I believe we, have one of the strongest teams in the, energy business, positioning us to deliver increasÏIigvalue to shareholders in 2000 and beyond. . 2000 and Beyond 2000 promises to be an even stronger year for your Company, and here are a few of the reasons we can see today. ~ Since 1997, more than 20 states have moved to open their energy markets to competition, . and We see this trend of ep.ergy deregulation continuing. Our portfolio of generating plants under development is aimed at attractive markets, including those in the Northeast, ~outhwest, and Midwest. . ..:. .'- . Continued groWth in these new generating projects and '. the related trading opportunities, combined with the sale of underperfonning businesses, should boost the National Energy Group's performance. . , And, with the decision in, Pacific Gas and Electric Company's rate case, having resolved the uncertainty about this unit's base revenues, it can focus more attention on continuous, improvement of operations and, customer selVice, with the goal of earning. its full authorized -x:ate of return. ' i i I . Thank You Early in 2000, our dirèctors Richard B. Madden anctRebecca Q. Morganretired. 'We thank them, both for their years of selVice on our Boards of Directors., Stock 'Price I would have preferred to end 1999 with a higher stock price. The efforts of the PG&E Corporation team, no matter how strong and effective, do not m~t the mark unless growing value is delivered to you, our shareholders. We did not do that for you iri 1999. We are redoubling our efforts to provide that value to you in 2000 and beyond. The operating performance and income from' operations we delivered in 1999 are the foundation for tha~ future. Sincerely, ~~'/ Robert D.Glynn, Jr. Chairman of the, Board, 'Chief Executive Officer, and President . March 3, 2000 2 ·' e . PG&E Corporation At A Glance , California Power Exchange $801 million in sales of fossil-fueled generating assets; $213 million in sales of geothermal generation facilities 2,592 high-tech companies, 1,123 wineries, 25 gold mines, 3,335 bakeries, 1,215 shoe stores, 1,926 video rental stores, 607 golf courses, 1,322 florists, and 1,232 ~r washes '218.2 million kilowatt-hours of electricity, or the equivalent to supply 32,200 l).ouseholds 4.7 million therms of natural gas, or the equivalent to supply 7,500 homes · As a result of electric industry deregulation in California, Pacific Gas and Electric Company and other California investor-owned utilities sell all of their generated power to the California Power Exchange (PX), which also obtains power 'from, other generating sources. The PX then distributes power to the utilities based on customer demand. National Energy Group Ii· I í Operating revenues Earnings from operations per common share Products and servicés Operating power plants Power plants in development or construction Energy trading volume in 1999: Gas Power Gas pipelines . Average daily natural gas throughput Pacific Gas and Electric Company Operating revenues Earnings from operations per common share Service area Delivery systems Recent invesunents in infrastructure Sources of power Value of generating assets sold in 1999 A few of the customers served by Pacific Gas and Electric Company Estimated energy savings through energy efficiency programs I' I 1999 $11.6 ,billion $0.17 1998 $10.7 billion $0.12 Power generation Electricity and natural· gas commodity supply Natural gas transportation Energy commodity trading and risk management services Electricity and natural gas for industrial, commercial, and institUtional customers nationwide ' 30, representing more than 6,500 megawatts of capacity 13, representing more than 10,000 megawatts 8.43 billion cubic feet per day 224.7 million megawatt-hours 612 miles in the Pacific Northwest 2.16 billion cubic feet 1999 $9.23 billion $2.07 1998 $8.92 billion $1.82 70,000 square miles in Northern and Central California, with a population of 13 million, about one in 20 Americans 131,000 circuit miles of electric transmission and distribution lines, 43,000 miles of natural gas transmission and distribution pipelines $1.2 billion in 1999, $1.4 billion in 1998 3 ~ e e SELECTED FINANCIAL DATA 1999 . 1998 1997 1996 1995 , $20;820 $19,577 $15,255 $ 9,610 $ 9,622 878 2,098 1,762 1,896 2,763 13 ' 771 745 722 1,269 0.04 2.02 1.82 1.75 2.99 1.20 1.20 1.20 1.77 1.96 $ 19.13 $ 21.08 $ 21.30 $ 20.73 $ 20.77 20.50 31.50 30.31 21.00 28.38 ' . 29,715 , 33,234 31,115 26,237 26,871 6,673 7,422 7,659 7,770 8,049 2,031 2,321 2,611 635 635 750 694 694 $ 9,228 $ 8,924 $ 9,495 $ 9,610 $ 9,622 1,993 1,876 1,820 1,896 2,763 763 702 735 722 1,269 $21,470 $22,950 $25,147 . $26,237 $26,871 4,877 5,444 6,218 7,770 8,049 2,031 2,321 2,611 586 586 694 694 694 (in miIIioos, except per share ;¡mounts) PG&E Corporation(l) For the Year Operating revenues . Operating income Income from continuing operations Earnings per common share from continuing operations, basic and diluted ' Dividends declared per common share At Year-End Book value per common share Common stock price per share. Total assets Long-term debt (excluding current portions) Rate reduction bonds (excluding current portions) Redeemable preferred stock and securities of subsidiaries (excluding current portions) Pacific Gas and Electric Company For the Year Operating revenues Operating income" Income ~vailable for common stock At Year-End . Total assets Long-term debt (excluding current portions) Rate reduction bon~ (excluding current portions) Redeemable preferred stock and securities (excluding current portions) (1) PG&E Corporation became the holding company for Pacific Gas and Electric Comp~y on January 1, 1997. The Selected Financial Data of PG&E Corporation and Pacific Gas and Electric Company (the Utility) for the years 1995 and 1996 are identical because they reflect the accounts of the Utility as the predecessor of PG&E Corporation. Matters relating to certain data above, including discontinued operations and the cumulative effect of a change in an accounting principle are discussed in Management's Discussion and Analysis and in the Notes to Consolidated Financial Statements. . 4 '-J .' \ - . MANAGEMENT'S DISCUSSION AND ANALYSIS PG&E Corporation is an energy-based holdiflg company headquartered in San Francisco, California. PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company (the Utility), provides natural gas and electric service to one of every 20 Americans. PG&E Corporation's National Energy Group provides energy products and services throughout North America. The National Energy Group businesses develop, construct, operate, own, and manage independent power generation facilities that serve wholesale and industrial customers through PG&E Generating Company, LLC (fonnerly U.S. Generating Company, LLC) and its aff1liates (collectively, PG&E Gen); own and operate natural gas pipelines, natural gas storage facilities, and natural gas.processing plants, primarily in the Pacific Northwest and in Texas, through various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission or PG&E GD; purchase and sell energy commodities and provide risk management services to customers in major North American markets, including the other National Energy Group non-utility businesses, unaff1liated utilities, marketers, municipalities; and large end-use customers through PG&E Energy Trading-Gas Corporation, PG&E Energy Trading--power, L.P., and their aff1liates (collectively, PG&E Energy Trading or PG&E ET); and provide competitively priced electricity, natural gas, and related services to industrial, commercial, and institutional customers thro~gh PG&E Energy Services Corporation (PG&E Energy Services or PG&E ES): In the fourth quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the divestiture of PG&E Corporation's Texas natural gas and natural gas liquids business. Also in the fourth quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the divestiture of PG&E Corporation's retail energy services. This is a combined annual report of PG&E Corporation and Pacific Gas and Electric Company. It includes separate consolidated fmancial statements for each entity. The consolidated financial statements of PG&E Corporation reflect the accounts of PG&E Còrporation, the Utility, and PG&E Corporation's wholly owned and controlled, subsidiaries. The consolidated fmancial statements of the Utility reflect the accounts of the Utility and its who,lly owned and controlled subsidiaries. This Management's Discussion and Analysis (MD&A) should be read in conjunction with the consolidated financial statements included herein. This combined annual report, including our Letter to Shareholders and this MD&A, contains forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on assumptions which management believes are reasonable and on infonnation currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements. . Factors that could cause future results to differ materially from those expressed in or implied by the forward- looking statements or historical results include: · the pace and extent of the ongoing restructuring of the electric and natural gas industries across the United States; · operational changes related to industry restructuring, including changes in the Utility's business processes and systems; , · the method and timing of disposition and valuation of the Utility's hydroelectric generation assets; · the timing of the completion of the Utility's transition cost recovery and the consequent end of the current electric rate freeze in California; . · any changes in the amount the Utility is allowed to collect (recover) from its customers for certain costs that prove tobe uneconomic under the new competitive inarket- (called transition costs); · future operating performance at the Diablo Canyon Nuclear Power Plant (Diablo Canyon); · the method adopted by the California Public Utilities Commission (CPUC) for sharing the net benefits of operating Diablo Canyon with ratepayers and the timing of the implementation of the adopted method; · the extent of anticipated growth of transmission and distribution services in the Utility's service territory; · future market prices for electricity; · future fuel prices; 5 l' , . e __ · the success of mariagement's strategies to maximize shareholdeLvalue in PG&E Corporation's National Energy Group, which may include acquisitions or dispositions of assets, or internal 'restructuring; .' the extent to which our current or planned generation development projects are completed and the pace and cost of such completion; . · generating capacity expansion and r~tirements by others; '.. . · the successful integration and performance of acquired assets; · the outcome of the Utility's various regulatory proceedings, inçluding the proposal to auction the Utility's hydroelectric generation assets, the electricttansmission rate case applications, and post-transition period ratemaking proceedings; , , . · .fluctuations in commodity gas, natural gas liquids, and electric prices and our ability to successfully manage such price fluctuations; and ' · the pace and extent of competition in the Cålifornia generation market and its impact on the Utility's costs and resulting collection of transitioJ:? cos~: ' As the ultimate irrÌpactof these and other faCtors is uncertain" these and other factors may cause future earnings to differ materially from results or outcomes we currently seek or expect. Each of these factors is discussed in greater detail in this MO&A. In this MD&A, we first discuss our competitive and regulatory environment. ,We then discuss earnings and changes in our results of operations for 1999, 1998, and 1997. Finally, we discuss liquidity ànd fmancial resources, various uncertainties that could affect future earnings, and our ris~ management activities,. Our MD&A applies to both PG&E Corporation and the Utility. ' , Compe'titive and Regulatory Environment This section provides a discussion of the competitive environment in the evolving energy i~dustry, the California electric industry, the California natura] gas business,' the National' Energy Group, and regulatory matters. I, ,I The Competitive Environment in the Evolving Energy Industry, Historically, energy utilities operated as regulated monopolies within specific service territories where they were essentially the sole suppliers of natural gas ,and electricity services, Under this model, the. energy utilities owned and operated all of the businesses necessary to procure; generate, transport, and'distribute energy. These services were priced on a combined, (bundled) basis, with rates charged by the energy companies designed to include all of the costs of providing these services. Now, energy utilities face intensifying pressures to "unbundle," or price separately, those activities that are no . longer considered natural monopoly services. The most significant of these services are electricity generation and natural gas supply. The driving forces behind these c()mpetitive pressures are customers who believe they caI1 obtain energy at " lower unit prices and competitors who want access to those customers. Regulators and legislators are responding to those customers and competitors by providing for more competitiOi1in the energy industry. Regulators and legislators are requiring utilities to "unbundle" rates (separate their various energy services and the prices of those services). This allows customers to compare unit prices of the Utility and other providers when selecting their energy service provider. In the natural gas industry, Federal Energy Regulatory Commission (FERC) Order 636 required interstate pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate gas pipelines must provide transportation service regardless ~f whether the customer (often a local gas distribution company) buys the gas commodity from the pipeline. , In the electric industry, the Public Utilities Regulatory 'Policies Act of 1978 . (PURPA) specificall)' provided that unregulated companies could become wholesale generators of electricity and that utilities were required to purchase and use power generated by these unregulated c,ompanies in meeting their, customers' needs. The National Energy Policies Act of 1992 was designed and implemented through FERC Orders 888 and 889 to increase competition in the wholesale unregulated generation market by requiring access to ~lectric utility transmission systems by all wholesale unregulated generators; sellers, and buyers of electricity. Now, an increasing humber of states throughout the country either have implemented plans or are considering' proposals to separate the generation froin the transmission and distribution of electricity through some form o(electric industry restructuring. 6 .' ,'- ' To'date, the' states, not the federalgovernment, have taken the initiative on .triC ~dustry restructuring at the retail level. While many bills mandating restructuring of the electric industry have been introduced in Congress, none have passed. As a ~esult, the,pace, extent, and methods for restructuring the electric industry vary widely throughout the country. For instance, as of December 31, 1999, 21 states had enacted electric industry restructuring ! legislation, including California, Tèxas, ,Illinois, PennSylvania, New Jersey, Massachusetts, Rhode Island, New Hampshire, and Connecticut. There also are, some states that have passed legislation precluding or significantly slowing down restructuring. Differences in how individual states view electric industry restructuring often relate to the existing unit cost of energy supplies within each state. Generally, states having higher energy unit costs are moving more quickly to deregulate energy supply markets. Implementation of our national energy strategy depends, in part, upon the opening of energy markets to provide customer choice of supplier. Undue delays by states or federal legislation to deregulate the electric' ' I . generation and natural gas supply business could impact the pace of growth of our National Energy Group. The California Electric Industry In 1998, California became one of the first states in the coúntry to implement electric industry restructuring and establish a competitive market framework for eleCtric generation. Today, most Californians may continue to purchase their electricity from investor-owned. utilities such as Pacm¿ Gas and Electric Company, or they may choose to purchase electricity from alternative generation providers (such as unregulated power generators and unregulated retail electricity¡ suppliers such as marketers, brokers, and aggregators). For those customers who have notchòsen an alternative generation provider, investor-owned utilities, such as the Utility, continue to be the generation providers. Investor-owned utilities continue to provide distribution services to substantially all customers within their service territories, including customers who choose an alternative generation provider. Competitive Market FrameWork: To create a competitive generation market, a Power Exchange (PX) and an Independent System Operator (ISO) began operating on March 31, 1998. The PX provides a competitive auction process to establish market clearing prices for electricity in the markets operated by the PX. The ISO schedules delivery of electricity for all market participants, The Utility continues to own and maintain a portion of the transmission system, but the ISO controls the operation of the system. Unless or until the CPUC determines otherwise, the Utility is required to bid or schedule into the PX and ISO markets all of the electricity generated by its power plants and electricity acquired under contractual agreements with unregulated generators. Also, the Utility is required to buy from the PX all electricity needed to provide serviCe tò retail customers tfu¡t continue to choose the Utility as their electricity supplier. In November 1999, the FERCapproved the extension of the ISO's authority to establish price limitations through 2000. The ISO Board increased the applicable price limitation to $750 per megawatt-hour (MWh) on October 1, 1999, but has the option to decrease it to $500 per MWh or make other changes, in view of the FERC's decision. This limits the amount of volatility that occurs in the California electricity market. However; the ISO will ' review the appropriate level for any price limitations for the summer of 2000 in light of market redesign efforts now being conSidered, including changes to reduce uninstructed deviations from ISO dispatch orders and changes to permit loads to participate by submitting bids for price-responsive demand in energy or ancillary services markets.' ' The Utility is continuing its efforts to develop and implement changes to its business processes and systems, including the customer information and billing system, to accommodate electric industry restructuring. To the extent that the Utility is unable to develop and implement such changes in a successful and timely manner, there could be an adverse impact on the Utility's or PG&E Corporation's future results of operations. Transition Period, Rate Freeze, and Rate Reduction: California's electric industry restructuring established a tranSition period during which electric ratès remain frozen at 1996 levels (with the exception that, on January 1, 1998, rates for small commercial and residential, customers were reduced by 10'percent and remain frozen at this reduced level) andinvestor-owned utiliti~s may recover their transition costs. Transition costs are generation-related costs that prove to be uneconomic under the new competitive structure. The transition period ends the earlier of December 31, 2001, or when the particular utility has recovered its eligible transition costs. 7 ! ., e tþ-. Revenues from frozen electric rates, provide for the recovery of authorized Utility costs, including transmission and distribution service, public· purpose progranls, nuclear decommissioning, and rate reduction bond debt service. To the extent the revenues from frozen rates exceed authorized Utility costs, the' remaining revenues constitute the competitive transition charge (erC), which recovers the transitiòn' costs. These erC'revenues are being recovered from all Utility distribution customers and are subjecno seasonal fluctuations in the Utility's sales volumes and certain other factors. As the erc is collected regardless of the customer's choice of electricity supplier (i.e., the erc is non-bypassable), the Utility believes that the availability of choice to its customers will not have a material impact on its ability to recover transition costs. ' To pay for the 10 percent rate reduction, the Utility refInanced $2.9 billion (th~ expected revenue reduction from the rate decrease) of its transition costs with, the proceeds from the rate reduction bonds. The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by defening recovery of a portion of these transition costs until after the transition period. During the rate freeze, the rate reduction, bond debt serVice will not increase Utility customers' electric cites. If the transition period· ends before December 31, 2001, the Utility may be obligated to retUrn a portion of the economic benefIts bf the transaction to cUstomers. The timing of any such,return and die exact amount of such portion, if any, have not yet been determined. Transition Cost Recovery: Although most transition costs must be recovered during the trånsition period, certain transition costs can be recovered after the transition period. Except for certain transition costs discussed below, at the conclusion of the transition period, the Utility will be at risk to recover any ?f its remaining generation costs through market-based revenues. Transition costs consist of (1) above-market sunk costS (costs associated with utility generating facilities that are fIXed and unavoidable and that were iricluded in customers' rates on December 20, 1995) and future sunk costs, such as costs related to plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from qualifying facilities (QF) and qther power suppliers, and (3) generation-related regulatory assets and obligations. (In general,· regulatory assets are expenses deferred in the· current or prior periods, to be included in rates, in subsequent periods.) Above-market sunk costs result when the book value of a f~cility exceeds its market value. Conversely, below-market sunk costs result when the market value of a facility exceeds its book value. The total amount of generation facility cösts to be included as transition costs is based on the aggregate of above-market and below- market values. The above-market portion of these costs is' eligible for recovery as a transition cost. The below- market portion öf these costs will reduce other unrecovered transition costs. These above- and below-market sunk costs are related to generating facilities that are classified as either non-nuclear or nuclear sunk costs. The Utility cannot determine the exact amount of above-market non-nuclear sunk costs thàt will be recoverable as transition costs until the valuation of ~e Utility's'remaining non-nuclear generating assets, primarily its hydroelectric generating assets, is, completed. The ~aluation, through appraisal, sale, or either' divestiture, must be completed by December 31, 2001. The value of seven of the Utility's other non~nuclear generating facilities was determined when these facilities were sold to third parties. The portion of the sales proceeds that exceeded the book value of these facilities waS used to reduce other. transition costs. On September 30, 1999, the Utility med an application with the CPUC to determine the market, value of its hydroelectric generating facilities and related assets through an open, competitive auction. (See "Generation Divestiture" below.)The Utility plans to use an auction process similar to the one previously approved by the CPUCand successfully used in the sale of the Utility's fossil ånd geothennal plants. If the market value of the Utility's hydroelectric facilities isdetemiined based upon any method other than a sale of the faèilities to a third party, a material charge to Utility earnings could result. Any excess of mark~t value over book vàlue would be, used to reduce other transition costs. ~See "Generation Divestiture" below.) , For imclear transition costs, revenues provided for transition cost recovery are based on the accelerated recovery 'of the investmentin Diablo Cànyon over a fIve-year periOd ending December 31, 2001. The amount of nuclear generation sunk costs was determined separately through a CPUC proceeding and was subject to a final verification audit that was completed iri August 1998. The audit of the Utility's Diáblo Canyon accounts at ' December 31, 1996, resulted in the issuance of an unqualified opinion. The audit v.erifiéd that Diablo canyon sunk costs at December 31~ 1996, were $3.3 billion of the total $7.1 billion,.construction costs. The independent , , I ' , . accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, that questioned 8 , ' '... ,/ $200 million of the $3.3 billion sunk costs. The CPUC will review the results of 'audit and may seek to make adjustments to Diablo Canyon's sunk costs subject to transition cost recovery. At this time, the Utility canriot predict what actions, if any, the CPUC may take regarding the audit report. CostS aSsociated wim the Utility's ,long-term contracts to purchase electric power are included as transition costs. Regulation requkedthe Utility to enter into such long-tenn agreements with non-utility generators. Prices fIxed under these contracts are now typically above prices for power in wholesale markets. (See Note 14 of Notes to Consolidated Financial Statements.) Over the remaining life of these contracts, the Utility estimates that it will purchase 299 million MWh of electric power. To the extent that the individual contract prices' are above the market price, the Utility is collecting the difference between the contract price and the market price from customers, as a transition cost, over the tenn of the contract. The contracts expire at various dates through 2028. . The total costs under long-term contracts are based on several variables, including the capacity factors of the related generating facilities and future market prices for electricity. During 1999, the average price paid under the Utility's long-tenn contracts for electricity was 6.3 cents per kilowatt-hour (kWh). The average cost of electricity purchased at market rates from the PX for the year ended December 31,1999, was 3.7 cents per kWh. The average cost of electricity purchased at market rates from the PX for the period from March 31, 1998, thePX's establishment date, to December 31, 1998, was 3.2 -cents per kWh. , ' Generation-related regulatory assets and obligations (net generation-related regulatory assets) are included as transition costs. At December 31, 1999 and 1998, the Utility's generation-related net regulatory assets totaled $4 billion and $5.4, billio~, respectively.' ' ' Certain transition costs can be recovered through a non-bypassable charge to diStribution customers after the transition period. These costs include (1) certain employee-related transition costs, (2) above-market payments under existing long-term contracts to purchase power, diScussed above, (3) up to $95 million of transition costs to me extent that the recovery of. such costs during the transition period was displaced by the recovery of electric industry restructuring implementation costs, and (4) transition costs financed by the rate reduction bonds. Transition costs fInanced by the issuance of rate reduction bonds will be recovered over the term of the bonds. In addition, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission the nuclear facility. During the rate freeze, the charge for these costs will not increase Utility customers' electric riites. Excluding these exceptions, the Utility will write off any transition costs not recovered during the transition period. The Utility is amortizing its transition costs, ,including most generation-related regulatory assets, over the transition period in conjunction with the'available erc revenues. During the tranSition period, a reduced rate of return on common equity of 6.77 percent applies to all generation assets, including ,those generation assets reclassified to regulatory assets. Effective]anuary 1, 1998, the Utility started collecting these eligible transition costs through the non-bypassableCfC and generation divestiture. For the years ended December 31, 1999 and 1998, regulatory assets related to electric industry restructuring decreased by $1,359 million and $609 million, respectively, which reflects the recovery of eligible transition costs. ' ' During the transition period, the CPUC reviews the' Utility's compliance with accounting methods established in the CPUC's decisions governing transition cost recovery and the ,amount of transition costs requested for recovery. The CPUC is currently reviewing non-nuclear transition costs amortized during 1998 and the fIrst six months of 1999. "Generation Divestiture: In 1998, the Utility sold three fossil-fueled generation plants for $501 million. These three fossil-fueled plants had a combined book value at the time of the sale of $346 million and had a combined capacity of 2,645 megawatts (MW). ' On April 16, 1999, the Utility sold three other fossil-fueled generation plants for $801 million. At the time of sale, these three fossil-fueled plants had a combined book value of $256 million and had a combined capacity of 3,065 MW. , ' On May 7, 1999, me Utility sold its complex of geothennal generation facilities for $213 million. At the time of sale, these facilities had a combined book value of $244 million and had a combined capacity of 1,224 Mw. 9 J e - , The gains from· the sale of the fossil-fueled generation plants were used to òffset other transition costs. ' Likewise, the loss from the sale of the complex ofgeothennal generation facilities is being recovered as a transition cost. The Utility has retained a liability for required environmental remediation related to any pre-closing soil or groundwàter,contamination at the plants it has sold. On September 30, 1999, the Utility ftled an application with the CPUCto detennine the market value of its hydroelectric generating facilities and related assets through an open, cpmpetitive auction. The Utility proposes to use an auction process similar to the one previously approved by the CPUC and successfully used in the sale of the Utility's fossil and geothermal plants. Under the process proposed in the application, another subsidiary of PG&E Corporation, PG&E Gen, would be permitted to participate in the auction on the same basis as other bidders. , , The sale, of the hydroelectric facilities, would be subject to certain conditions, including the transfer or re-issuance of various, permits and licenses by the FERC and other agencies. In addition, the FERC must approve assignment of the Utility's Reliability Must Run Contract with the ISO for any facility subject to such contract. Under the proposed purchase and sale agreement, the CPUC's approval of the proposed sale on terms acceptable to the Utility in the, Utility's sole discretion is also a condition precedent to the closing of any sale. . .. . , , On January 13, 2000" a scoping memo and ruling was issued that separates the proceeding into two concurrent phases: one, to review the potential environmental impacts of the proposed auction under the California Environmental Quality Act and a second to detennine whether the Utility's auction proposal, or some other alternative to the proposal, is in the public interest. The ruling notes that the divestiture and valuation issuès can best be considered after the environmental impacts of a change in ownership have been reviewed. Potential bidders will also be able to incorporate the costs of any mitigation measures that may be required into their bids. . The ruling sets a procedural schedule which calIs for a fmal decision on the Utility's auctionpropo~al by October 19, 2000, and a final environmental impact report published in Noyember 2000. The ruling also anticipates that a fmal CPUC decision approving the sale would beissueciby May 15, 2001. Finally, theruling prohibits the Utility from withdrawing its application without express CPUC authority. It is uncertain whether the CPUC will ultirrÌately approve the' Utility's auction proposal. At December 31, 1999, the book value of the Utility's net investment in hydroelectric generation assets was approximately $0.7 billion, excluding approximatèly $05 billion of net investment reclassified as regulatory assets. Any excess of market value over the $0.7 billion boOk value would be used to reduce trànsltion costs, includirig the remaining $05 billion of regulatory aSsets related to the hydroelectric generation assets. If the market value of the hydroelectric generation assetS is determined by any methOd other thana sale of the assets toa third party, or . if the winning bidder for any of the auctioned assets is PG&E Gen, a material charge' to Utility earnings could résult. The timing and nature of any such charge is dependent upon the valuation method and procedure adopted, and the method of implementation. As discussed below, it is possible that the CPUC will require an interim .valuation through an estimate of market value of the assetS prior to trans~er, sale, or other divestiture, which could, also result in a material charge. While trànsfer or sale to an affiliated" entity such as PG&E Gen would result ii1 a material charge to income, neither PG&E Corporation nor the Utility believes that the sale of any generation facilities to a third party will have a material impact on, its results of operations. ' The Utility's ability to continue recovering its transition costs depends on several factors, including (1) Ù).e . continued application of the regUlatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC,(3) the determined value of the Utility's hydroelectric generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, and (6) the market price of electricity. Given the curient evaluation of these faCtors, PG&E Corporation believes that ,the Utility will recover its transition costs. However, a change in one or more of these factors could affect ·the probability of recovery of transition costs and result in a material charge. ' . - . ·1 1 Post-Transition Period: In October 1999, the CPUC issued a decision in the UtiIity'spost-transition period rate making proceeding." Among other matters, the CPUC's decision addresses the mechanisms for ending the current electric rate freeze and for establishing post-transition period accounting mecha1ùsms and rates. The decision req':lires Diablo Canyon generation to be priced at prevailing market rates after the transition period. This portion of the decision is further discussed below under "Regulatory Matters - Post-TraJ)SitionPeriod Ratetnaking Proceeding." ·1 I 1 I 10 '. I, I ! I " ' " I , I: , . .. . " '. ' ' ,~, , The CPUC decision requires the Utility to provide quarterly forecasts of whe~ Utility's rate freeze (i.e., transition period) may end based on various assumptions regarding energy prices and the book value of the Utility's remaining generation assets. The Utility is required to notify the CPUC three months before the earliest forecasted end of its rate freeze and provide draft tariff language and sample calculations of the rates that would 'go Ï1).to effect when the rate freeze ends. After the Utility completes its transition cost recovery, it must implement its post-:rate-freeze rate~.' ' The timing of the end of the rate freeze and c01Tesponding transition period will, in part, depend on the timing of the valuation of the Utility's hydroelectric generating assets and the ultimate determined value of such assets since any excess of market value' over the assets' book value would be used to reduce transition costs. If the value of the Utility's hydroelectric generation assets is significantly higher than the related book value, the transition period and the rate freeze could end before December 31, 2001, and potentially could end during 2000. The CPUCis considering the Utility's proposal to auction its hydroelectric assets, although the CPUC could also require the Utility to implement an interim valuation of the assets. In another proceeding (the ,1998 Annual Transition Cost Proceeding (ATCP)), a CPUC administrative law judge issued a proposed decision on January 7,' 2000, which contained a proposed change to the rules previously in place for the amortization of transition costs. Under the final decision, issued on February 17, 2000, on a prospective basis the utilities are required to assess the estimated market value of their remaining non-nuclear generating assets, including the land associated with those assets, on an aggregate basis at a value not less than the net book value of those assets and to credit the Transition Cost Balancing Account (TCBA) with the estimateq value. The decision encourages the utilities to base such estimates on realistic assessments of the market value of the assets. The ftnal decision did not adopt the proposed decision's recommendation to establish a new regulatory asset acçount that would allow a true-up when the estimated market value is greater than actual market value. However, the decision states that crediting the TCBA with the aggregate net book value of the remaining non-nuclear generating assets is a conservative approach and remedies any èoncerns regarding the lack of a true-up. The decision provides that if the estimated market valuation is less than book value for any individual asset, accelerated amortization of the associated transition costs will continue until fmal market valuation of the asset occurs through sale, appraisal, or other divestiture. lEthe fmal value of the assets, determined through sale, appraisal, or other divestiture, is higher than the estimate, the excess amount would be used to pay remaining transition costs, if any. The utilities are required to ftle the adjusted entries to'their respective TCBA based on the estimated market values with the CPUC by March 9, 2000. The fùing will become effective after appropriate review by the CPUC's Energy Division and the TCBA entries are subject to review in the next ATCP. If an estimate of the market value of the non-nuclear generating assets is adopted that exceeds the aggregate net book value of those assets, a charge to earnings would result. " After the rate freeze and transition periods end, the Utility must refund to electric customers any over-collected transition costs (plus interest at the Utility's authorized rate of return) within one year after the end of the rate freeze. The Utility also will be prohibited from collecting after the rate freeze any electric costs incu1Ted during the rate freeze but not recovered during the rate freeze, including costs that are not classified as transition costs. Through the end of i~ rate freeze, the Utility will continue to iilcur certain non'-transition costs and place those costs into balancing and memorandum accounts for future rècovery-. There is a risk that the Utility will be unable to collect certain non-transition costs that, due to lags in the regulatory cost approval process, have not been approved for recovery nor collected when the rate freeze ends. The Utility is unable to predict the amount of such potential unrecoverable costs. ' TheCPUC also has established the Purchased Electric Commodity Account for the Utility to track energy costs after the rate freeze and transition period end. The CPUC intends to explore other ratemaking issues, including whether dollarÆor-dollar recovery of energy costs is appropriate, in the second phase of the post-transition electric ratemaking proceeding. There are three primary' options for the future regulatory framework for utility electric 'energy procurement cost recovery after the rate freeze: (1) a CPUC-defmed procurement practice, that if followed by the Utility, would pass through costs without the need for reasonableness reviews, (2) a pass-through of costs subject to after-the-fact reasonableness reviews, or (3) a procurement incentive mechanism with rewards and penalties determined based on the Utility's energy purchasing performance compared to a benchmark. The Utility proposed adoption of either a defìned procurement practice or a procurement incentive mechanism, neither of , which would involve reasonableness reviews. The volatility of earnings and risk exposure of the Utility related to post-transition period purchases of electricity is dependent on which of these options, or some other approach, is . adopted. . ' I 11 .. ' 4t, ' After the transition period, the Utility's future earnings from its electric distribution will be subject to volatility as a result of sales fluctuations. . Distributed Generation and Electric Distribution Competition: In October 1999, the CPUC issued a decision òutlining how the CPUC, in cooperation with other regulatory agencies and the California Legislature, plans to address the issues surrounding distributed g~neration, electric distribution competition, and the role of the utility distribution companies (such as Pacific Gas and Electric Company) in the competitive retail electric-market. Distributed generation enables siting of electric generation technologies in close proximity to the electric demand (referred to as "load"). The CPUC decision opened a new rulemaking proceeding to exarriïne various issues concerning distributed generation, induding interconnection issues, who can own and operate distributed generation, envirorunental impacts, the role of utility distribution companies, and the rate design and cost allocation' issues associated with the deploymeñt of distributed generation facilities. With respect to electric distribution competition, the CPUC, directed its staff to deliver a report by . April 21, 2000, on the different policy optioris that the CPUC, in cooperation with the California Legislature, can pursue. Following the issuance of the report, the CPUC expects to open one or more' new proceedings to address electric distribution competition and competition in the retail èlectric market. The California Natural Gas Business , ' Restructuring of the natural gas indusuy on both' the national and the state levels has given cþoices to California utility customers to meet their gas supply needs. The Utility offers transmission, distribution, and storage services as separate and distinct services to itS industrial and larger commercial gas (noncore) customers. , Customers have the opportunity to select from a menu of services offered by the TJtility an? 'they pay only for the services that they use. Access to the transmission system is possible for all gas marketers and shippers, as well as noncore end users. The Utility's residential and smaller commercial gas (core) customers can select the commodity gas supplier of their choice. However, the Utility continues to purchase gas as a regulated supplier for those .core customers who. request it, serving 3.8 million core customers in its service territory. The Utility's costs of purchasing gas for core customers through 2002 are regulated by the core procurement incentive mechanism, a form of incentiveratemaking that provides the Utility a ,direct fmanciàl incentive to procure gas and transportation services at the lowest reasonable costs by comparing all procurement costs to an aggregate market-based benchmark. If costs fall within a range (referred to as "tolerance b~m(l") around the benchmark, ' costs are considered reasonable and fully recoverable from ratepayers. If procurement costs fall outside the tolerance band, ratepayers and shareholders share savings or costs, respectively. The Gas Accord settlement agreement, approved by the CPUC in 1997, èstablished gas transmission rates within California for the period from March 1998 through December 2002 for the Utility's core and noncore customers and eliminated regulatory protection against variations in nOI1core transmission revenues. A$ a result, the Utility is at risk for variations between actual and forecasted transmissionthroughp~t volumes. Rates for.gas distribution ~ervices .continue to be 'set'bythe CPUC and are designed to provide the Utility an opportunity to recover its costs of service and include a return on its investment. The regulatory mechanisms for' setting gas distribution rates are discussed below under "Regulatory Matters." , National Enèrgy Group· PG&ECorporation's National Energy Group has been formed to pursue opportunities created by the gradual restructuring of the energy indu~uy across the nation. The National Energy Group integrates our national power generation, gas transmission, and energy tràding and services businesses. The National Energy Group contemplates increasing PG&E Corporation's national market presence through a balanced program of acquisition and development of energy assets and businesses, while at the same time undertaking ongoing portfolio management of its assets and businesses. PG&E Corporation's ability to anticipate and capture profitable business opportunities' created by restructuring will have a significant impact on PG&E Corporation's future operating results. Certain New England states where our National Energy Group operates electric generation facilities were, like California, among the first states in the counuy to introduce electric indusuy restructuring. A$ a result of this restructuring and certain other regulatory initiatives, the wholesale unregulated electricity market in New England features a bid-based market and an ISO. 12 ·-;;;-.~. ~ i: - -- Independent Power Generation: Through PG&E, Gen and its aff1liates, we participate in the development, construction, operation, ownership, and management of non-utility electric generating facilities, that compete in the United States, power generation market. -In September 1998, PG&E Corporation, through its indirect subsidiary USGen New England, Inc." ' (USGenNE), completed the. acquisition of a portfolio of electric generation assets and power supply contracts from the New England Electric System (NEES). The purchased assets include hydÍ'oelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of about 4,000 MW. Including fuel and other inventories and transaction costs" the fmancing requirements for this transaction were approximately $1.8 billion, funded through an aggregate of $1.3 billion of PG&E Gen and USGenNE debt and a $425 million equity contribution from PG&E' Corporation. The net purchase price has been allocated as follows: (1) electric generating assets of $2.3 billion, (2) receivable for support payments of $0.8 billion, and (3) abovè- . market contractual obligations of $1.3 billion, relating to acquired power purchase agreements, gas agreements, and standard offer agreements, As part of thè New England electric industry restructuring, the local utility companies were required to offer Standard Offer Service (SOS) to their retail customers. Retail customers may select alternative suppliers at any time. . The SOS is intended to provide customers with a price benefit (the commodity electric price offered to the retail customer is expected to be less than the market price) for the first several years, foHowed by a price disincentive' that is intended to stiinulate the retail market. ' It I, , Retail customers may continue to t;ecèive SOSthrough June 30, 2002, in New Hampshire (subject to early termination on December 31, 2000, at the discretion of the New Hampshire Public Service Commission), through December 31, ~004, in Massachusetts, and through December 31, 2009, in Rhode Island. However, if customers choose an alternate supplier, they are precluded from going back to the SOS. In connection with the purchase of the generation assets, USGenNE entered into wholesale agreements with certain of the retail, companies of NEES to supply at specified prices the electric capacity and energy requirements necessary for their retail companieS to meet their SOS obligations. These companies are responsible for passing on to us the revenues generated from the SOS. USGenNE currently is indirectly serving a large portion of the SOS ' eleçtric capacity and energy requirements for these companies, except in New Hampshire. For the year ended December 31, 1999, the SOS price paid to generators was $0.035 per Kwh for generation. On March 1, 1999, Constellation Power Source, Inc. (Constellation) won the New Hampshire component of the 50S through a competitive bidding solicitation. On January' 7, 2000, USGenNE paid approximately $15 million to a third party for this third party's assumption of 10percent of the Massachusetts EleCtric Company/Nantucket Electric Company,SOS and 40 percent of the Narragansett SOS. 'like other utilities, New England utilities previously entered irito agreements with unregulated companies (e.g., qualifying facilities under PURPA) to provide energy and capacity at prices that are anticipated to be in excess of market prices. We assumed NEES' contractual rights and duties under several of these power purchase agreements. At December 31, 1999, these agreements provided for an aggregate 470 MW of capacity. However; NEES will make, support payments to us toward the cost of these agreements. The support payments by NEES total $0.9 billion in the aggregate (undiscounted) and are q.ue in monthly installments from September 1998 through January 2008. In 'certain circumstances, with our consent, NEES may make a full or partial lump-sum accelerated payment. Initially, approximately 90 percent of the acquired operating capacity, including capacity and energy generated by other companies and provided to us under power purchase agreements, is dedicated to servicing SOS customers. To the extent that customerS eligible to receive SOS choose alternate suppliers, or as these obligations are sold to other parties, this percentage will decrease. As customers choose alternate' suppliers, or, the SOS obligations are sold, a greater proportion of the output of the acquired operating capacity ~l be subject to market prices. , ' I I, Gas Transmission Operations: PG&E Corporation participates in the "midstream" portion of the gas business through PG&E GT NW. PG&E GT NW owns and operates gas transmission pipelines and associated facilities which extend over 612 miles from the Canada-U.S. border to the Oregon-California border. PG&E GT NW provides firm and interruptjble transporta~on services to third party shippers on an open-access basis. Its customers are principally retail gas 13 I: I ~ e --- distribution utilities, electric utilities that use natural gas ,to generate electricity, natural gas marketing companies, natural, gas producers, and industrial consumers. On January 27, 2000, PG&E Corporation's National Energy Group signed a definitive agreement with El Paso Field Services Company (EI Paso) providing for the sale to EI Paso, a subsidiary of EI Paso Energy Corporation, of the stock of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Tecb, Inc. (collectively, PG&E GTI). The consideration to be received by the National Energy Group includes $279 million irÌ cash subject to a working capital adjustment, the assumption by EI Paso of debt having a book value of $624 million, and other liabilities associated with' PG&E GTT. . In 1999, PG&E COrporation recognized a charge against earnings of $890 million after tax, or $2.42 per share, to reflect PG&E GTT's assets at their fair market value. The compOsition of the pre-tax charge is as, follows: (1) an $819 million write-down of net property, plant, and equipment, (2) the elimination of the unamortized portion of goodwill, in the amount of $446 million, and (3) an accrual of $10 million representing selling costs. Proceeds from the sale will be used to retire short-term debt associated with PG&E GTI's operations and for other corporate purposes.' Closing of the sale, which is expected in -the fIrst half of 2000, is subject to approval under the Hart Scott Rodino Act. " - Energy Trading: Through PG&E ET, we purchase bulk volumes of power and natural gas from PG&E Corporation aff1liates and the wholesale market. We then schedule, transpOrt, and resell these commodities, either directly to third parties or to other PG&E Corporation aff1liates. PG&E ET also provides risk management services to PG&E Corporation's other businesses (except the Utility) and to wholesale CUstomers. (See "Price Risk Management Activities" below; and Note 3 of the Notes to Consolidated Financi:H Statements.) Energy, Services: In December 1999,PG&E CorpOration's Board of Directors approved a plan to dispOse of PG&E ES, its wholly owned subsidiary, through a sale: As of December 31, 1999, the intended disposal has been accounted for as a discontinued operation. In cOnriectionwith this transaction, PG&E Corporation's investment in PG&E ES was 'written down to its estimated net realizable value. In addition; PG&E Corporation provided a reserve for anticipated losses through the date of sale. The total provision for discontinued operations '\,Vas $58 rriillion, net of ' income taxes of $36 million. While there ís no defmite sales agreement, it is expected that the disposition will be completed in 2000. The amounts that PG&E Corporation will ultimately realize from this disposal, could be materially different from the amounts assumed in arrivirig at the estimated loss on disposal of the discontinued operations: The PG~ ES business segment generated net losses of $40 million (or $0.11 per share), $52 million (or $0.14 per share), and $29 million (or $0.07 per share), for the years erided December 31, 1999, 1998, and 1997, respectively. "I - I ", ! Regulatory Matters ' A signifìcant portion of PG&E Corporation's operations are regulated by federal and state regulatory , , commissions. These commissions oversee service levels and, in certain cases, PG&E Corpoiation'spricing for its regulated services. Following are-the percentages of 1999 revenues that fell under the jurisdiction of these various regulatory agencies: . Cost of service-based Market Utility 96.SOA¡ -3.2% Consolidated 42.3% 57.7% . The UtilitY is the only subsidiary with significant regulatory proceedings at this time. Some of the items that . affected repOrted 1999 results, and will affect future Utility authorized revenues, include the '1999 General Rate Case, the year 2000 cost of capital proceeding, the post-transition period ratemaking proceeding, the FERC transmission rate cases, the catastrophic event memorandum account proceeding, the CPUC's gas strategy investigation-Phase 2, and the 1997 and 1998 electric base revenue increase proceeding. These items are discusse;d below. Any requested change in authorized èlectric revenueS resulting from any of the' electric proceedings would not impact the Utility's customer electIic rates through the transition period because these rates are frozen in accordance with the electric tiansition plan. However: the amount of remaining revenues providing for the I 14 ~'. r J ' It ~ " ,. , recovery of transition costs would _ffected. Any change in authorized gas revles resulting from gas proceedings would increase or decrease the Utility's customer gas rates. I ~ . The 1999 General Rate' Case (GRC): In December 1997, the Utility fùed its 1999 GRC application with the CPUc. During the GRC process, the CPUC examines the Utility's costs to determine the amount the· Utility may charge customers for base revenues (non-fuel related costs). The Utility requested distribution revenue increases to maintain and improve natural gas and electric distribution reliability, safety, and customer service. The requested revenues, as updated, included an increase of $445 million in electric base revenues and an increase of $377 million in natural gas base revenues over the 1998 authorized revenues. The Utility received a final decisiön on its, 1999 GRC application on February 17, 2000. This final decision increased electric .distribution revenues by $163 million and gas distribution revenues'by $93 million, as compared to revenues authorized for 1998. This revenue increase is retroactive to January 1, 1999. The impact of these ' increases resulted in an increase in earnings of $153 million, or $0.42'per share, and was reflected in the fourth quarter of 1999. The Utility's GRC application also contained a proposal for an Attrition Rate Adjustment (ARA) to adjust revenues in 2000 and 2001 if a performance-based ratemaking (PBR) mechanism is, not adopted for 2000 or 200l. The fmal decision denies the Utility's ~equest for an ARA to adjust revenues in 2000, but adopts an ARA for 200l. The final decision orders that the CPUC oversee an audit of the Utility's 1999 distribution capital spending, and that the 2001 ARA be subject to modification to take into account the results of the audit. The 2001 ARA will also be subject to modification to recognize ¡¡mounts recorded in a new balancing account that the final decision requirès be established for vegetation management expenses, The Year 2000 Cost of Capital Proceeding: In November 1999, the Utility fùed its 2000 cost of capital application With the CPUC to establish its authorized rates of return on an unbundled basis for electric and natural gas distribution operations. To reflect increasing interest rates, the Utility has requested a return on equity (ROE) of 12.5 percent and~an overall rate of return of 9.76 percent as compared to its 1999 authorized rates of 10.6 percent ROE and 8.75 percent overall rate of return. The Utility has not requested any change in its authorized capital structure for 2000. The Utility's current authorized capital structure is 46.2 percent long-term debt, 5.8 percent preferred stock, and 48 percent common equity. If granted, the, requested ROE would increase ,electric distribution revenues by approximately $127.8 million and natural gas distribution revenues by àpproximately $36.6 million, based on \he rate base authorized in the Utility's 1999 GRC: The Utility requested that a fInal CPUC decision be issued in June 2000. On February 17, 2000, the CPUC issued a decision to allow the final CPUC decision, when it is adopted, to be effective retroactively to February 17, 2000. Consistent with. the rate freeze, there will be no change in electric rates in 2000. Also, the return on the Utility's electric transmission-related assets will be determined by the FERC in 2000. Finally, the return on the Utility's natural gas transmission and storage business was incorporated in rates established in the Gas Accord, Post-Transition Period Ratemaking Proceeding: In October 1999, the CPUC issued a decision in the Utility's post-transition period ratemaking proceeding. Among other matters, the CPUC's decision addresses the mechanisms for ending the current electric rate freeze and for establishing post-transition period accounting mechanisms and rates. The decision prohibits the Utility from continuing to price electric generation from Diablo Canyon based on the incremental cost incentive price (ICIP) after the tranSition period has ended. The ICIP, which has been in place since January 1, ,1997, is a performance-based mechanism that establishes a rate per kWh generated by the facility. The ICIP prices.for 1999, 2000, and 2001 are 3.37 cents per kWh, 3.43 cents per kWh, and 3.49 cents per kWh, respectively~ The average price for base load electric energy (the price received for a constant level of electric generation for all hours of electric demand) sold at market rates to the California PX for the 12-month period ended December 31,1999, was 3.7 cents per kWh. ,The average price for base load electric energy.sold at market rates to the PX from March 31, 1998, the PX's establishment date,to December 31, 1998, was 3.2 ceJ;1ts per kWh. 15 $ .e _ Future market prices may be higher or lower. Under the CPUC's decision, after the transition period; the Utility must price Diablo Canyon generation 'at the prevailing market price for power. Further, pursuant to the 1997 CPUC decision establishing the ICIP, the Utility is required to begin sharing 50 percent of the net benefits of operating Diablo Canyon with ratepayers commencing January 1, 2002. The CPUC may interpret a more recent decision to commence the benefit-sharing at the end of the transition period. The Utility is required to me an application by July 2000 with its proposal for the methods to be used in the valuation . of the benefits associated with the operation of Diablo Canyon, and the mechanism to be used to share these benefits with ratepayers. The Utility and PG&E Corporation are unable to predict what type of valuation and sharing mechanism will be adopted and what the ultiJriate financial impact of the sharing mechanism will have on results of operation or fmancial positi<;>ll. The CPUC's decision also prohibits the Utility from collecting after the rate frèeze any electric costs incurred, but not recovered duriÌ1g the rate freeze, including costs that are not transition costs and are not related to generation assets such as under-collected accounting balances relating to power purchases. Sée the discussion above under "Competitive and Regulatory Envirorunent - The California Electric Industry Post-Transition Period." In November 1999, the Utility med an application for rehearing the CPUC's decision. The ultimate fmancial impact 'of the provisions of the CPUC's decision described above will depend on the d?te the Utility's transition cost recovery is completed and the rate freeze ends, future costs including Diablo Canyon operating costs, future market prices for electricity, the amount of any electric non-transition costs that . have been incurred but not recovered as of the end of the cite freeze, the timing of various regulatory proceedings in which the Utility seeks approval for rate recovery of various costs incurred during the rate freeze, and other variables that PG&E Corporation and the Utility are unable to predict. FERC Transmission Rate Cases: Since April 1998, all electric transmission revenues are authorized by the FERC. During 1998 and 1999, the FERC issued orders that put into effect various rates to recover electric transmissiÖn èosts from the Utility's former bundled rate transmission customers. All 1998 and 1999 rates currently are subject to refund, pending final decisions in the transmission cases. In April 1999, the Utility fùed a settlement with the FERC that, if approved, would allow the Utility to recover $345 million for the period of April 1998 through May 1999. In May 1999, the FERC accepted, subject to refund, the Utility's March 1999 request to begin recovering, as of May 31, 1999, $324 million annually. In October 1999, the FERC accepted, subji7ct to refund, the Utility's request to increase revenues to $370 million annually, I;>eginning in April 2000. The Utility does not expect a material impact on its . fmancial position or results of operations resulting from these matters. Ça~trophic Event Memorandum Account Proceeding: In September 1999; the Utility entered into a Settlement Agreement with the CPUC's Office of Ratepayer Advocates (ORA), and other parties, in ,a proceeding addressing the Catastrophic Events Memorandum Account. The settlement provides for a $59 million increase in electric distribution revenue requirement and an $11 million increase in gas distribution revenue requirement effective January 1, 2000. The increase compensates the UtiÍity for service restoration following several events, beginning with the Oakland Hills fire. of 1991 and endir¡.g with the storms of February 1998. A CPUC decision is expected in early2000. The CPUC's Gas Strategy InveStigation, Phase 2: In January 1998, the CPUC opened a rulemaking proceeding to explore changes in the natural gas industry in California. In July 1999, the CPUC issued a decision identifying promising options for restructuring the natural gas industry. In the decision, the CPUC reaffirmed the basic structure of the' Gas Accord. The <3PUC further stated that it seeks to explore a market structure that maintains the utilities' traditional role of providing fully integrated default service while removing obstacles to competitive unbundled services. The CPUC opened a new investigative proceeding to explore in' more detail the anticipated costs and benefits associated with the different market structure options it has identified. On January 28, 2000, PG&E Corporation and abroad-based coalition of shippers, consumer groups, marketers, and others fùed a settlement with the CPUC which would reafflrm the basic structure of the Gas Accord and contïri.ue the Gas Accord throùgh'tts original term of December 31, 2002. 16 .-, " :.,.'," '. . ., -- Electric Base Revenue Increase Proceeding: Section 368(e) of the California Public Utilities Code was adopted as part of the California electric industry restructuring legislation. It provided for an increase in the Utility's èlectric base revenues for 1997 and 1998, for enhancement of transmission and distribution system safety and reliability. ·Inaccordance with Section 368(e), the CPUC authorized a 1997 base revenue increase of $164 million. For 19Q8, the CPUC authorized an additional base revenue increase of $77 million. Section 368(e) expenditures are subject to review by the CPUC. In July 1999, the ORA filed reports on the Utility's Section 368(e) expenditures recommending a disallowance of $88.4 million in expenditures for 1997 and 1998. In August 1999, The Utility Reform Network (TURN) recommended an additional $14 'million disallowance for a total recommended disallowance for 1997 and 1998 expenditures o( $102.4 million. The Utility opposed the recommended disallowances and hearings were held in . October 1999. A proposed decision is not expected until the ftrst quarter of 2000. Any proposed decision would be subject to comment by the parties and' change by the CPUC before a fmal decision is issued. The Utility does not expect a material impact' on its fmanêia1 position or, results of operations resulting from these matters. Results of Operations In this section, we present the components of our results of operations for 1999, 1998, and 1997. The Utility received a fmal decision on its 1999 GRC application on February 17, 1000. As discussed further in "Regulatory Matters" above, the fmal decision did not increase electric revenues, although it increased the deferral of electric transition costs by $163 million over the amount that would have been deferred under the 1998 revenue requirement. This revenue increase was retroactive to January 1, 1999. The impact of the 1999 GRC resulted in an increase in earnings of $153 million, or $0.42 per share, and was reflected in the fourth quarter of 1999. , The table below shows for 1999, 1998, and 1997, certain items from our Statement of Consolidated Income detailed by Utility and National Energy Group operations of PG&E Corporation. (In the "Total" column, the table shows 'the combined results of operations for these groups.) The information for PG&E Corporation (the "Total" column) excludes transactionS between its subsidiaries (such as the purchase of natural gas by the Utility from the unregulated business operations). Following this table we discuss earnings and explain why the components of our results of operations varied from the year before for 1999 and 1998. r I: , I , / II !' I I: II I: 17 - - Utility National Energy Group· PG&E GT Eliminations & PG&E Gen NW Texas PG&E ET Othd1) , (in millions) 1999 Operating revenues Operating expenses Operating,income Other income, net Interest expense, net Income taxes Income from continuing operations 'Net loss EBITDA (2) 1998 Operating revenues Operating expenses Operating income Other income, net I~terest expense, net Income taxes Income from continuing operations ,Net income' $9,228$1,122 7,235 1,007 $224 $ 1,148 $10,521 104 . 2,446 10,582 $(1,423) , (1,432) $3,523 $ 203 $181 $(1,178)$ (53) $ 19 $8,924 7,048 $ 649 489 $237 $ 1,941 $ 8,509 101 1,996 8,528, $ (683) (683) EBITDA(2) $3,294 $ 200 $177 $ 15 $ (15) $ (7) $9,4:95 $ 148 $233' $ 1,004 $ .4,808 $ (433) 7,675 176 127 1,023 4,840 (348) 1997 Operating revenues Operating expenses Operating income Other ,income, net Interest expense, net Income taxes Income from continuing operations Net income EBITDA (2) $3,606 $ (40). $144 $ 16 $ (29) $57 (1) Net income on intercompany positions recognized by segments using mark-to-marketaccountingis eliminated. Intercompany transactions ar~ also eliminated. (2). EBITDA measures earnings (after preferred dividends) before interest expense (net of interest income), income taxes, depreciation,' and amortization. - ,!, ~! Total $20,820 19,942 878 155 (772) 248 13 $ (73) $ 2,695 $19,577 17,479 2,098 65 (781) 611 771 ,$ 719 $ , 3,664 $15,255 1'3,493 1,762 212 (664) 565 745 $ 716 $ 3,754 Overall Results PG&E Corporation had a net loss in 19990f $73 million, or $0.20 per share. In 1998 PG&E Corporation had riet income of $719 million, or $1.88 per share. The decrease is prit:lc1pally due to the ~te-down to fair value of our natural gas business, in Texas and the accrual for the discontinuance of Operations of our Energy Services segment. The PG&E G1T write-down was approximately $890 million after taxes, and the PG&E ES discontinued operations generated a charge of $58 million after tax. Partially offsetting these charges were increases in Utility income, primarily as a result of the 1999 GRC, an~ an adjustment of a litigation reserve ~sodated with a court- approved settlement proposal. In addition, PG&E' Gen changed its method of accounting for major mairitenance and overhauls at its generating facilities.' Effective Jánuary 1, 1999, PG&E Gen adopted a method that accounts for expenditures associated with major maintenance and overhauls as incurred. Previously, PG&E Gen estimated the cost of major maintenance and overhauls and accrued such costs.in advance in a systematic and rational manner over the period between major maintenance and overhauls. The cumulative effect of the, accounting change resulted in recognition of approximately $12 million of income, net of tax. The Utility's net income available for common stock increased to $763 million in 1999 as compared to 1998 net income of $702 million, primarily because of th~ impacts of the 1999 GRC. How~ver, the,~creases from the 18 I .. I; ,_ II GRC were partially offset by a reduction in the Utility's authorized cost of capital and a lower return on its assets due to the sale of a significant portion 'of its generating assets and recovery of transition costs (see Note 2 of the Notes to Consolidated Financial Statements). Net income for the UtiÚty decreased $33.million in 1998 as compared to 1997 due to the reduced rate of return on generation assets and increased interest expense associated with the rate reduction bonds. Operating Income Operating income for PG&E Corporation in 1999 was $878 million, which includes the charge to write down the investment in PG&E GTI to its net realizable value. Operating income for the Utility was $1,993 million in 1999 as compared to $1,876 million u11998. This inérease is primarily because of the impacts of the 1999 GRC. However, the increases from the GRC were partially offset by a reduction in the Utility's authorized cost of capital ,and a lower return on its assets due to the sale of a significant portion of its generating assets and recovery of transition costs (see Note 2 o(the Notes to Consolidated Financial Statements). Operating'income of the National Energy Group decreased $62 million in 1999 as compared to 1998, excluding the charge to write PG&E GTI down to its net realizable value. The decUne resulted from mild weather in the Northeast, lower interruptible sales Ü1 the Pacific Northwest, less portfolio management activity, and trading' losses in the U.S. gas portfolio. This decline was partially offset by cost containment efforts across the organization and an increase in the differential between natural gas liquids prices and the cost of natural gas. The operating income increase in 1998 as compared to 1997 was primarily due to the growth of the National Energy Group, which contributed $195 million of the increase. The 1998 income from continuing operations also includes a loss on the sale of our Australian energy holdings. Operating Revenues Utility: Utility operating revenues increased $304 million in 1999 as compared to 1998. This increase is primarily due to: (1) a $147 million increase in gas revenues from residential and commercial gas customers due to higher usage, (2) a $93 million increase in gas revenues as a result of the GRC, (3) a $43 million increase in revenues from small and medium electric customers due to increased customers, and (4) a $16 million increase in revenues from an increase in gas transportation volumes. Utility operating revenues decreased $571 million in 1998 as compared to 1997. This decrease is primarily due to: çn a $410 million decrease for the 10 percent electric rate reduction provided to residential and 'small commercial customers, ,which was partially offset by $108 million of higher revenues due to increased consumption of electricity by these customers, (2) a $151 million decrease in revenues from medium and large electric customers, many of whom are now purchasing their electricity directly from unregulated power generators, (3) a $63 million decrease in sales to commercial and agricultural electric customers resulting from the'ir lower demand for irrigation water pumping as a result of heavier rainfall in 1998, and (4) a $100 million decrease for the termination of the volumetric (ERAM) and energy cost (ECAC) revenue balancing ~ccounts. The ERAM and ECAC accounts were replaced with the TCBA, which affects expenses, rather than revenues. . National Energy Group: The National Energy Group's 1999 operating revenues increased $939 million as compared to 1998 operating revenues, principally due to: (1) the PG&E Gen business segment receiving a full year of revenue from the New England assets acquired in September 1998, and (2) increases in trading revenues at PG&E ET reflecting the further maturation of its business. The 1999 operating revenues also reflect revenue increases resu,lting from an improved differential between the natural gas liquids prices and the irÌcoming natural gas. These revenue increases were ,partially offset by (1) a decline in interruptible .revenues in the Northwest due to the lower natural gas prices in the Southwest as compared to Canadian prices, and (2) l,ower transportation revenue on the Texas transmission system. In addition, effective July 1999, certain gas trading activities conducted by PG&E GTI were transferred to PG&E ET, thus contributing to the decline in PG&E GTI revenues. Operating revenues associated with the National Energy Group increased $4,893 million in 1998 as compared. to 1997. This was primarily due to revenue increases from energy trading volumes, 12 months of revenue from the II ., 19 -!.. , ,~. _s -- " . Texas acquisitions versus seven months in 1997, portfolio management activity by PG&E Geri, and the acquisition of the New England generating assets in September 1998. Operating Expenses Utility: The Utility's operating expenses increased $187 nù!lion' in 1999 as compared to 1998. This increase reflects the increased cost of gas due to higher usage and the increased amortization of electric transition costs. ' ' Utility operating expenses in 1998 decreased $627 million as compared to 1997. This de.crease reflects a reduction in the amount of amortizati9n of transition costs, primarily due to lower revenues from residential and small commercial customers discussed above in "Operating Revenues--Utility": Also contributing to the decrease in operating expenses was a reduction in gas transportation demand charges of $134 million, due to the expiration of contracted pipeline capacity.· ' National Energy Group: The National Energy Group's operating expenses increased $2,276 million in 1999 as compared to 1998, due to the charge associated with ~e disposition of PG&E GTI, having a full year of operating expenses associated with the generation facilities in Néw England, and growth of PG&E ET operations. Operating expenseß for the National Energy Group increased $4,613 million in 1998 as compared to 1997. This increase reflects the increase in the volumes of energy commodities purchased, operating costs associated with the New England assets acquired in September 1998 and the gas transportation assets acquired in 1997. I ncome Taxes PG&E Corporation has recorded income tax expense of $248 million for 1999. The effective tax rate primarily results from two factors: (1) electric industry restructuring has resulted in the reversal of temporary differences whose tax benefits were originally flowed through. to customers causing an increase in income tax expense independent of pre-tax income, and (2) the disposition of PG8Œ GTI resulted in a capital loss for taX purposes, wl1!-ch could not be fully recognized. Income taxes in 1998 increased $46 million as compared to 1997. The ove,rall effective tax· rate' increased 1.1 percent in 1998 largely due to accderated book depreciation arid amortizatiõn related to electric industry restructuring. These increases were partially offset by a lowered effective state tax rate resulting from our expanded business operations. Dividends . ' We base our common stock dividend on a number of fuiancial considerations, including sustainability, fmancial flexibility, arÌd competitiveness with invesunent opportunities of similar risk. Our current quarterly common stock dividend is $.30 per common share, which corresponds to an annualized dividend of $1.20 per common share. We continually review the level of our common stOCk dividend, taking into consideration the impact of the changing regulatoryenviroriment throughout the nation, the resolution of asset dispositions, the operating performance of our business units, and our capital andfmancial resources in general. The CPUC requires the Utility to maintain its CPUC-authorized capital structure, potentially limiting the ,amount of dividends the Utility may pay PG&E Corporation. During Í999, theUtilitý has been in compliance with its CPUC-authorized capital structure. PG&E Corporation and the Utility believe that this requirement will not affect PG&E Corporation's ability to pay common ,stock dividends. However, depending:Òh the timing and outcome ()f the valuation of the Utility's hydroelectric facilities discussed in "Generation' Divestiture" :lbove, certain valuation methods could necessitate a waiver of the CPUC's authorized capital structure ,in order to permit PG&E Corporation or the Utility to continue paying common stock dividends at the current level.· 20 ".~ II' i , ,4IIÞ ' Liquidity and Financial Resources Cash Flows from Operating Activities Net cash provided by PG&E Corporation's operating activities totaled $2,287' million, $2,283 million, ~nd $2,618 million in 1999, 1998, and 1997, respectively. Net cash provided by the Utility's operating activities totaled $2,200 million, $2,610 million, and $1,768 million in 1999, 1998, and 1997, respectively. - Ij Ii Cash Flows from Financing Activities PG&E Corporaüon: We fund investing activities from cash provided by opèrations after capital requirements and, to the extent necessary, external fInancing. Our policy is to fInance our investments with 3, capital structure that minimizes . financing costs, maintains financial flexibility, and, with regard to the UtiÌity, complies with regulatory guidelines. Based on cash provided from operations and our investing and disposition activities, we may repurchase equity and long-term debt in order to manage the overall size :¡ò.d balance of our capital structure. During 1999, 1998, and 1997, we issued $54 million, $63 million, and $54 million of common stock, respectively, primarily through the Dividend Reinvestment Plan and the stock option plan component of the Long-Term Incentive Program. During 1997, we also issued $1.Ì billion of common stock to acquire the natural gas assets in Texas. During 1999, 1998, 3,nd 1997, we declared dividends on our common stock. of $460 million, $466 million, 'and $485 million, respectively. During 1999, 1998; and 1997, we repurchased $693 million., $1,158 million, and $804 million of our common stock, respectively. The repurchases made in 1998 and through September 1999 were executed through separate, accelerated share repurchase programs. As :ofDecember 31, 1997, the Board of Directors had auth<?rized the repurchase of up to'$1.7 billion of PG&E Corporation's common stock on the open market or in negotiated transactions. As part of this authorization, in January 1998, we repurchased in a specific transaction 37 million shares of common stock. As of December 31, 1998, approximately $570 million remained available under this repurchase authorization. In February 1999, we used this remaining authorization to purchase 16.6 million shares at a cost of $502 million. In connection with this transaction, we entered into a forward contract with an investment institution. We settled the forward contract and its additional obligation of $29 million in September 1999., We used a subsidiary of PG&E Corporation to make this repurchase, along with subsequent stock repurchases. The stock held by the subsidiary is treated as treasury stock and reflected as Stock Held by Subsidiary on the Consolidated Balance Sheet,ofPG&E Corporation. ' In October 1999, the Board of Directors of PG&E Corporation authorized an additional $500 million for the purpose of repurchasing shares of the Corporation's common stock on the open market. This authorization supplements the approximately $40 million remaining from the amount previously authorized by the Board of Directors on December 17, 1997. The authorization for share repurchase extendS through September 30, 2001. As of December 31, 1999, through our wholly owned subsidiary, we repurchased 7.2 million shares, at a cost of . $159 million under this authorization. Any open market purchases will be made by the wholly owned subsidiary of,PG&E Corporation. During 1999, our National Energy Group retired $128 million of long-term debt. This amount includes PG&E GTI's June 1999 redemption of the outstanding balance of $69 million of its senior notes, which resulted in a gain on redemption of approximately $1.7 million. In 1998, our National Energy Group retired $75 million of long-term debt and retired the notes used in the acquisition of our Australian energy holdings. In 1997, our National Energy Group issued $30 mill~on and retired $109 million of long-term debt. Also in 1997, we assumed $780 million of long-term debt in connection with the acquisition of our natural gas assets in Texas. We maintain a number of credit facilities to support cominercial paper programs, letters of credit, and other short-term liquidity requirements. PG&E Corporation maintains two $500 million revolving credit facilities, one of which expires in November 2000 and the other in 2002. These credit facilities are used to support the commercial paper program and other liquidity needs. The facility expiring in 2000 may be exte1).ded annually for additional one-year periods upon agreement with the lending institutions. There was $450 million of commercial paper outstanding at December 31, 1999. PG&E Corporation introduced a $200 million Extendible Commercial Note (ECN) program during the third quarter of 1999. The ECN program supplements our short-term borrowing capability. there was $76 million of extendible commercial notes outstanding at December 31, 1999, which are not supported by the credit facilities. 'I I, ,I ! ~ I I 21 ~ ,r e e.. PG&E Gen maintains two $550 million revolving credit facilities. One facility expires in August 2000 and the other expires in 2003. The total amount outstanding at December 31, 1999, backed by the facilities, was . $898 million in commercial paper. Of these loans, $550 million is classified as noncurrent in .the Consolidated Balance Sheet of PG&E Corporation. In 1998, USGenNE, a subsidiary of PG&E Gen, established a $100 million revolving credit facility that' expires in 2003. As of December 31, 1999, there is no outstanding balance on this facility. " PG&E GT NW maintains a $100 million revolving creditfacility that expires in 2002, but has an annual renewal option allowing the facility to ,maintain a three-year duration. PG&E GT NW also maintains a $50 million 364-day credit facility that expires in 2000, but can be extended for súccessive 364-dayperiods. At December 31, 1999, PG&E GT NW had an outstanding commercial paper balance of $99 million, which is classified as noncurrent in the Consolidated Balance Sheet of PG&E Corporation. ' PG&E GTI maintains four separate credit facilities that total $250 miÌlion and are guaranteed by PÇJ&E Corporation. At December 31, 1999, PG&E GTf had $176 million of outstanding short-term bank borrowings related to these credit facilities, These lines may be cancelled upon demand and bear interest at each respective bank's quoted money market rate. The borrowings are unsecured and unrestricted as tò use. Utility: In December 1999, 7.6 million shares of the Utility's common stock, with an aggregate purchase price of $200 million, was purchased by a subsidiary of the Utility. This purchase is reflected as stock held by subsidiary in the Consolidated Balance Sheet of Pacific Gas and Electric Company. Earlier in 1999, the Utility repurchased and , cancelled 20 million shares of its common stock from PG&E Corporation for an aggregate purchasepricè of $726 million to maintain its authorized capital structUre. In 1999, 1998, and 1997, the Utility declared dividends on its coinmon stock of $415 million, $300 million, and $699 million, respectively. The Utility's long-term debt that either matured, was redeemed, or was repurchased during 1999 totaled $654 million. Of this amount, (1) $290 million related to the Utility's rate r~duction bonds maturing, (2) $135 million related to the Utility's repurchase of mortgage and various öther bonds, (3) $147 million related to ' maturity of various utility. mortgage bonds, and (4)$82 million related to the maturities and'redemption of various of the Utility's medium-term notes, and other debt. . The Utility's long-term debt that either matured, was redeemed; or was repurchased during 1998 totaled' $1.4 billion. Of this amount, (1) $249 million related to the Utility's redemption of its 8% mortgage bonds due October 1, 2()25, (2) $252 million related to the Utility's repurchase of variou!? other mortgage bonds; (3) $397 rÌ1illion related to the maturity of the Utility's 5%% mortgage bonds, (4), $204 million related to the other scheduled maturities of long-term debt, and (5). $290 million related to rate reduction bonds maturing. ,In 1997, the Utility redeemed or repurchased $225 million of long-term debt to manage the overall balance of its· capital structure. Also in 1997, the Utility replaced $360 million of fIxed interest rate pollu~on control bonds with the same amount of variable interest rate pollution control bonds. During 1999 and 1997, the Utility did not redeem or repurchas¿any of its. preferred stock. In 1998, the Utility redeemed its Series 7.44% preferred stock with a face value of $65 tnillion and its Series 67/8% preferred stOCk with a face value of$43 million. In December 1997, a subsidiary öf the Utility issued $2.9 biÍ1ion òf rate reduction bonds through a spécial- purpose entity established by the California Infrastructure and Economic Development Bank. The proceeds were used by the Utility to retire debt and reduce equity. (See Note 9 of Notes to Consolidated Financial Statements.) . The Utility maintains a'$l billion revolving credit facility, which expires in 2002. The Utility may extend the facility annually for additional one-year periods upon agreement wi¢. the banks. ThiS faciJ.'ity is used to support the Utility's commercial paper program and other liquidity requirements~ The total amount outstanding at ' December 31,1999, backed by this facility, was $449 million in coriunercial paper. There were no bank notes outstanding at December 31, 1999. ' ,', 22 ,.' e :,.;-"';' '-~':."~~ ~ :~'.'-'t -- Cash Flows from Investing Activities Utility: The primary uses of cash for investing activities are additions to property, plant, and equipment, unregulated investments in partnerships, and acquisitions. The Utility's estimated capital spending for 2000 is approximately $L3billion, excluding capital expenditures for divested fossiI"and geothermal power plants. The Utility's capital expenditures were $1,181 million, $1,382 million, and $1,522 million for the years ended December 31, 1999, 1998, and 1997, respectively. During 1999, the Utility sold three fossil-fueled generation facilities and its geothermal generation facilities. These sales closed in April and May 1999, respectively, and generated proceeds of $1,014 million. In 1998, the Utility had proc~ds of $501 million from the sale of three fossil-fueled generation plants. National Energy Group: PG&E Gen is associated with the construction of two natural gas-fueled combined-cycle power plants, and plans to begin construction on a third plant in early 2000. These power plants, refelTed to as "merchant power plants," will sell power as a commodity in the competitive marketplace. The electricity generated by these plants will be sold on a wholesale basis to local utilities and power marketers, including PG&E ET, which, in turn, will sell it to industrial, commercial, and other electricity customers. Millennium Power, a 360-MW power plant located in Massachusetts, is scheduled to begin commercial service in the fourth quarter of 2000. Lake Road Generating Plant (Lake Road), an approximately 790-MW power plant located in Connecticut, is scheduled to begin commercial service irÌ 2001. Lake Road is being ftnanced through a synthetic lease with a third partý owner. PG&E Gen will operate the plant under an operating lease (See Note 14 of Notes to Consolidated Financial Statements). La Paloma Generating Plant, an approximately 1,050-MW power plant, is located in California, and is scheduled to begin commercial service in 2002. The estimated cost to construct ~ese plants is approximately $1.4 billion. In 1998, PG&E Corporation sold its Australian energy holdings for proceeds of approximately $126 million. In 1997, PG&E Corporation sold its interest in International Generating Company, Ltd., resulting in an after-tax gain of approximately $120 million. ' I, Debt Obligations and Rate Reduction Bonds The table below provides information about our debt obligations and rate reduction bonds at December 31, 1999: ' Expected maturity date (dollars in millions) Utility: Long-term debt Variable rate obligations .......,. Fixed rare obligations . . '. . . . . . . . . Average interest rate. . . . . . . . . . . . Rate reduction bonds . . . . . . . . . . . . . Average interest rate: . . . . . . . . . . . National Energy Group: Long-term debt Variable rate obligations ......... Fixed rate obligations . . . . . . . . . . . Average interest rate, . . . . . . . . . . . . II 2000 There- , after Fair Value at Dee. 31, 1999 2001 2002 2004 2003 , Total $200 $100 $738 $310 $- $ $1,348 $1,348 $265 $274 $379 $354 $392 $2,330 $3,994 $3,869 6.6% 8.0% 7.8% 6.3% 6.4% 7.1% 7.1% $290 $290 $290 $290 $290 $ 871 $2,321 $2,265 6.2% 6.2% 6.3% 6.4% 6.4% 6.5% 6.3% $ 44 $ 11 $109 $560 $ 9 $ 87 $ 820 $ 820 $83 $95 $137 ' $ 47 $ 69 $ 672 $1,103 $1,058 '8.5% 9.1% 8.6% 9.8% 9.8% 8.2% 8.5% 23 ,t ,,-. e e Environmental Matters We are subject to laws and regulations established to both maintain and improve the quality ,of the environment. Where our properties contain hazardous substances, these laws and regulations require us to remove those substances or remedy effects on the environment. At December 31, 1999, the Utility has accrued $271 million ($300 million on an undiscountedbasis) for clean-up costs at identified sites. If other responsible parties fail to payor expected outcomes change, then these costs may be as much as $486 million. Of the $271 million, the Utility has recovered $148 million through rates, including $34 million through depreciation and expects to recover another $95 million in future rates. Additionally, the Utility mitigates its cost by seeking recovery from insurance carriers ànd other third parties. (See Note 15 of Notes, to Consolidated Financial Statements.) , The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in the estimate may occur in the near term due to uncertainty concerning the Utility's responsibility; the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is .found to be responsible for clean-up costs at additional sites or expected outcomes change. In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it . had identified a cleaning procedure used at the plant that released heated water from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by 'the Central Coast Regional Water Quality Control Board (Central Coast Board). The purchaser notified the Central Coast Board of its findings and the Central Coast Board requested additional information .from the purchaser. The Utility has initiated an investigation of these activities during the time it owned the' plant. The Central Coast Board has been notified of the investigation and the results will be presented to the Central Coast Board when the investigation is complete. If the identified procedure was performed during the Utility's ownership and was beyorid the scope of the relevant NPDES permits; the Central Coast Board may choose to initiate an enforcement action. If so, the Utility could be subject to significant penalties. Until the investigation is complete and the results discussed with the Central Coast Board, it is not possible to determine whether the Utility will suffer a loss in connection with this matter or to provide a more detailed estimate of such liability. Year 2000 (Y2K) PG&E Corporation successfully transitioned into the Year 2000 without any Y2K-related service disruptions. There is, however, a risk that some compùter-related problems might riot manifest themselves for a period of time and that supplier or business partner Y2K problems may materialize andhåve an adverse impact on our operations. As of December 31, 1999, expenditures to address potential Y2K problems totaled $185 million, of which $93 million is attributed to the Utility. Included are systems replaced or enhanced for general business purposes and for which implementation schedules were critical to our Y2K readiness. Infla.ion Financial statements, which, are prepared in accordance with generally accepted accounting principles, report operating results in terms of historical costs and do not evaluate the impact of inflation. Inflation affects our construction costs, operating expenses, and interest charges. In addition, the Utility's electric revenues will not reflect the impact of inflation due to the current electric rate freeze. However, inflation at currènt levels is not expected to have a material adverse impact on the Utility's or our financial position or. results of operations. Price Risk Management Activities We have established a risk management po~icy that allows derivatives to be used for both hedging and , non-hedging purposes (a derivative is a contract whose value is dependent on or derived from the value of some underlying asset). We use derivatives for hedging purposes primarily to offset underlying commodity price risks. We also participate in markets using derivatives to gather market intelligence, create liquidity, and maintain a market presence. Such derivatives include forward contracts, futures, swaps, and options. Net open positions often exist or are established due to PG&E Corporation's assessment of its response to changing market conditions. To 'I 24 ! " -e the extent that PG&E Corporation has an open position, it is exposed to the risk that fluctuating market prices may adversely impact its financial results. Our risk management policy and the trading and risk management polici~s of our subsidiaries prohibit the use of derivatives whose payment formula includes a multiple of some underlying asset. We prepare a daily assessment of qur portfolio, market risk exposure using value-at -risk and other methodologies that simulate future price movements in the energy markets to estimate the size and probability of future- potential losses. The quantification of market risk using value-at-risk provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions, including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period. We utilize historical data for calculating the price volatility of our positions and how likely the prices of those positions will move together. The model includes all derivative and commodity investments in our non-hedging portfolio and only derivative commodity investments for our hedging portfolio (but not the related underlying hedged position). We express value-at-risk as a dollar amount of the potential loss in the fair value of our portfolio based on a 95 percent confidence level using a one-day liquidation period. Therefore, there is a 5 percent probability that our portfolio will incur a loss in one day greater than our value-at-risk. The value-at~risk is aggregated for PG&E Corporation as a whole by correlating the daily returns of the portfolios for natural gas, natùral gas liquids, and power for the previous 22 trading days. Our daily value-at-risk for commodity price- sensitive derivative instruments as of December 31, 1999 and 1998, for non-hedging activities was $4.4 million and $6.2 million, respectively. Our daily value-at-risk for commodity price-sensitive derivative instruments as qf December 31, 1999 and 1998, for hedging activities was $30,000 and $210,000, respectively. For the year ended December 31, 1999, the average, high, and low value-at-risk amounts for non-hedging activities were $4.3 million, $6.2 million, and $1.3 million, respectively, The average, high, and low value-at-risk amounts over the same reporting period for hedging activities were $0.6 million, $1.7 million, and $0.0 million, respectively. The average, high and low amounts for the reporting period were computed using the vidue-at-risk amounts at the beginning of the reporting period and the four quarter-end amounts. ' Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, inadequate indication of the exposure of a portfolio to extreme price movements, and the inability to address the risk resulting from intra-day trading activities. In June 1999, the Financial Accounting Standards Board (F~B) issued Statement of Financial Accounting Standards (SFAS) No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133," which delayed the implementation of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," by one year to require adoption in years beginning after June 15, 2000. The Statement permits early adoption as of the beginning of any fiscal quarter. PG&E Corporation expects to adopt SFAS No. 133 no later than January 1, 2001. The Statement will require us to recognize all derivatives, as defmed in the Statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges" changes in the fair value of derivatives either will be offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recogIJized in other comprehensive income until the hedged items are recognized in earnings. We currently are evaluating what the effect of SFAS No. 133 will be on the earnings and fmancial position of PG&E Corporation. However, we already use the mark-to-market method of accounting for our commodity non-hedging and price risk management activities. Legal Matters In the normal course of business, both the Utility and PG&E Corporation are named as parties in a number of claims and lawsuits. (See Note 15 of Notes to Consolidated Financial Statements for further discussion of significant pending legal matters.) . I 25 :!. . tit e PG&E Corporation Statement of Consolidated Income (in millions, except per share amounts) Year endedI>ecembCr 31, 1999 1998 1997 Operating Revenues' Utility $ 9,228 $ 8,924 $ 9,495 Energy commodities and services 11,592 10,653 5,760 Total oPerating revenues 20,820 19,577 15,255 Operating Expenses Cost qf energy for utility 3,149 2,942 3,208 Cost of energy commodities and services 10,587 9,852 5,368 Operating and maintenance, net 3,151 3,083 3,066 Depreciation, amortization, and decommissioning 1,780 1,602 1,851 Loss on assets', held for sale 1,275 Total operating expenses 19,942 17,479 13,493 Operating Income 878 2,098 1,762 Interest expense, net (772) , (781) (664) Other income, net 155 65 212 Income Before Income Taxes 261 1,382 1,310 Income taxes 248 611 565 Income from continuing operations 13 771 745 Discontinued operations (Note 5) Loss from operations of PG&E Energy Services (net of applicable income taxes of $35 million, $41 million, and $17 million, respectively) . Loss on disposal of PG&E Energy Services (net of applicable income taxes of $ 36 ' million) , Net income (loss) before cumúJative effect of a change in accolµlting principle (Note 1) ". I . Cumulative effect of a change in an accounting principle (net of applicable income taXes of $8 million) Net Income (loss) Weighted Average Common.Shåres Outstanding Earnings (Loss) Per Common Share~ Basic and Diluted Income from continuing operations Discontinued operations . Cumulative effect of a change in an accounting principle Net income (loss) Dividends Declared Per Common Share (40) (52) (29) . (58) (85) 719 716 12 $ (73) $ 719 $ , 716 368 382 ' 410 $ 0.04 $ 2.02 . $ 1'.82 (0.27) (0.14) (0.07) 0.03 $ (0.20) $ 1.88 $ 1.75 $ 1.20 $ 1.20 $ 1.20 TI;1e accpmpanying Notes to the Consolidated Financial Statements are an integral part of this statement. 26 'Ó' ) e e PG&E Corporation Consolidated Balancè Sheet (in millions, except share amounts) Balance at December 31, 1999 1998 Assets Current Assets Cash and cash equivalents Short-term investments Accounts receivable Customers, net Energy marketing Price risk management Inventories and prepayments Deferred income taxes Total current assets $ 281 $ 286 187 55 1,486 1,856 532 507 607 1,416 598 671 133 3,824 4,791 23,001 24,160 I 1,905 1,967 2,541 ·3,347 436 407 184 127 28,067 30,008 (11,291) (12,026) 16,776 17,982 4,957 6,347 1,264 1,172 2,894 2,942 9,115 10,461 $ 29,715 $ 33,234 Property, Plant, and Equipment Utility Non-utility , Electric generation Gas traI)Smission Construction work in progress Other Total property, plant, and equipment (at original cost) Accumulated depreciation and decommissioning Net property, plant, and equipment Other Noncurrent Assets Regulatory assets , Nuclear decomnússioning funds Other Total noncurrent assets Total Assets I; I . ¡ , 27 , e e PG&E ' çorporation ,Consolidated Balance Sheet (Continued) (in millions, except share amounts) Balance àt December 31, 1999 1998 Liabilities and Equity Current Liabilities Short-term borrowings ' Current portion of long-term debt , Current portion of rate reduction bonds Accounts payable Trade creditors Other Regulatory balancing accounts Energy marketing Accrued taxes Price risk management Other· Total cùrrent liabilities Noncurrent Liabilities Long-term debt Rate reduction bonds Deferred income taxes Deferred tax credits Other Total noncurrent liabilities Preferred Stock of Subsidiaries UtiJity Obligated MandatorilY Redeemable Prèferred Securities of Trost Holding Solely Utility Subordinated Debentures Common Stockholders' EquitY ' Common stock, no par value, authorized 800,000,000 shares, issued, 384,406,113 and 382,603,564 shares, respectively Common stock heid by subsidiary, at cost, 23,815,5ÓO shares Reinvested earnings Total common stockholders' equity Commitments and Contingencies (Notes 1, 2, 3, 4, 5, 14, and 15) Total Liabilities and Stockholders' Equity $ 1,499 $ 1,644 592 338 290 290 708, 1,001 559 443 384 79 480 381 211 103 575 1,412 1,033 1,064 6,331 6,755 6,673 7,422 2,031 :2,321 3,147 3,861 231 283 3,636 3,746 15,718 ' 17,633 480 480 300 300 5,906 5,862 (690) 1,670 2,204 6,886 8,066 $29,715 $33,234 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 28 ...... . I: - e PG&E' Corporation e Statement of Consolidated Cash Flows (in millions) Cash flows from Operating, Activities Net (loss) income Adjustments to reconcile net (loss) income to, net cash provided by operating activities: Depreciation, amortization, and decommissioning Deferred income taxes and tax credits-net , Other deferred charges and noncurrent liabilties Loss (gain) on sale of assets Loss on assets held for sale Loss from discontinued operations Cumulative effect of change in accounting principle Net effect of changes in operating assets and liabilities: Accounts receivable-trade. lnv~ntories and prepayments Price risk management assets and liabilities, net Accounts payable-trade Regulatory balancing accounts payable , Accrued taxes \ Other working capital Other-net Cash provided in discontinued operations Net cash provided by operating activities Cash Flows From Investing Activities Capital expenditures Acquisitions and investments in unregulated projects Proceeds from sale of assets Othèr-Ìlet Net cash used by investing activities Cash Flows From Financing Activities ' Net borrowings (repayments) under credit facilities Long-term debt issued Long-term debt matured, redeemed, or repurchased Proceeds from issuance of rate reduction bonds Preferred stock redeemed or repurchased Conimon stock issued Common stock repurchased Dividends paid Other-net Net cash provided (used) by financing activities Net Change in Cash and Cash Equivalents Cash and Cash Equivalents at January 1 Cash and Cash Equivalents at December 31 Supplemental,disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) Income taxes (net of r~funds) I I I 'I For the year ended December 31, 1999 ·1998 1997 $ (73) $ 719 $ 716 1,780 1,602 1,851 (754) (107) . (160) 102 18 121 23 (120) 1,275 98 52 29 (12) 370 (342) (242) 73 (179) (4) (28) (16) 12 (293) 247 210 305 537 126 108 (123) (54) 159 199 (85) (824) (347) 218 1 2,287 . 2,283 2,618 (1,584) (1,619) (1,822) ~ (1,779) (116) 1,014 1,106 146 453 66 21 (117) (2,226) (1,771) (145) 2,115 (587) 386 (798) (1,552) (961) 2,881 , (108) 54 63 54 (693) (1,158) (804) (465) (470) (524) 4 (3) (39) - (2,043) (1,113) 406 127 (1,056) 1,253 341 1,397 144 '$ 468 $ 341 $ 1,397 $ 727 $ 774 $ 624 723 770 801 : ' The accompanying Notes to the Consolidated Financial Statements are an integral part of this statment. 29 '. e e PG&E· Corpóration Statement of Consolidated Common Stock Equity (in millions, except share amounts) Common Total Additional Stock Common Common Paid-in ' Held by Reinvested Stock Stock Capital Subsidiary Earnings Equity . Balance December 31, 1996 $2,018 $ 3;710 $'- $2,636 $ 8,364 Net income 716 716 Holding company fonnation 3,710 (3,710) Common stock issued (2,302,544 shares) 54 54 Acquisitions (45,683,005 shares) 1,069 1,069 Common stock repurchased (33,823,950 shares) (496) (308) (804) Cash dividends, declared on common stock (485) (485) Other 11 (28) (17) Balance December 31, 1997 6,366 2,53.1 8,897 Net income 119 719 Common stock issued (2,028,303 shares) 63 63 Common stock repurchased (37,090,630 shares) (565) , . (593) (1,158) Cash dividends declared on common stock (466) (466) Other (2) 13 11 Balance December 31, 1998 5,862 2,204 8,066 Net loss (73) (73) " Common stock issued (1,879,474 shares) 54 54 Common stock'repurchased (23,892,425 shares) (2) (690) (1) (693) Cash dividends declared on common stock (460) , (460) Other (8) (8) Balance December 31, 1999 . $5,906 $ - $(690) $1,670 $ 6,886 - - - The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 30 '-- - e Pacific Gas and Electric Company Statement of Consolidated Income (in -millions) Year ended December 31, 1999 1998 1997 Operating Revenues Electric $7,232 $7,191 $7,691 Gas 1,996 1,733 1,804 Total operating revenues 9,228 8,924 9,495 Operating ExpenSes Cost of electric energy 2,411 2,321 2,501 I Cost öf gas 738 621 707 I Operating and maintenance, net 2,522 2,668 2,719 , Depreciation, amortization, and decommissioning 1,564 1,438 1,748 Total operating expenses 7,235 7,048 7,675 Operating Income 1,993 1,876 1,820 Interest expense, net (593) (621) (570) Other income, net 36 103 127 - Income Before Income Taxes 1,436 1,358 1,377 Income taxes 648 629 609 - Net Income 788 729 768 Preferred dividend requirement 25 27 33 - - - Income Available for Common Stock $ 763 $ 702 $ 735 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. I I I 31 It e Pacific Gas arid Electric Company " Consolidated Balance Sheet (in millions,except ,share amounts) Assets Current Assets Cash arid cash equivalents Short-term investments Accounts receivable Customers, net Related parties Inventories Fuel oil Gas stored underground Materials and supplies Prepayments Deferred income taxes Total current assets . Property, Plant, and Equipment Electric Gas Construction work in progress . Total property, plant, and equipment (at original cost) Accumulated depreciation and decommissiòning Net property, plant, and equipment Other' Noncurrent Assets Regulatory- assets Nuclear decommissioning funds Other Total noncurrent assets Total Assets 32 BaJance at December 31, 1999 1998 $ 80 $ 73 21 17 1,201 . 1,383 . 9 14 2. 23 137 130 155 159 34 50 119 1,758 1,849 15,762 17,088 7,239 ' 7,072 214 ',273 23,215 24,433 \ (10,497) (11,397) 12,718 13,036 4,895 6,288 1,264 1,172 835 605 6,994 8,065 $ 21,470 $: 22,950 /~ ! e e Pacific Gas and Electric Company Consolidated Balance Sheet (Continued) (in millions, except share amounts) Ba1ance at December 31, 1999 1998 liabilities arid Equity , " CUrrent liabilities Short-term borrowings Current portion of long-term debt Current portion of rate reduction bonds AccountS payable ' Trade creditors Related parties ,Regulatory bàlancing accounts Other Accrued taxes Other Total current liabilities Noncurrent liabilities Long-term debt Rate reduction bonds . Deferred income taxes Deferred tax credits Other Total noncurrent liabilities Preferred Stock With Mandatory Redemption Provisions 6.300/Ó and 6.57%, outstanding 5,500,000 shares, due 2002-2009 Company Obligated Mandatorily Redeemable Preferred Securities of -Trust Holding Solely Utility Subordinated Debentures 7.90%, 12,000,000 shares due 2025 Stockholders' Equity Preferred stock without mandatory redemption provisions Nonredeemable-5% to 6%, outstanding 5,784,825 shares Redeemable-4.36% to 7.04%, outstanding 5,973,456 shares Common stock, $5 par value, authorized 800,000,000 shares, issued 321,314,760 and 341,353,455 shares, respectively Common stock held by subsidiary, at cost, 7,627,765 shares Additional paid in capital Reinvested earnings Total stockholders' equity Commitments and Contingencies (Notes 2, 6, 14, and 15) Total liabilities and Stockholders' Equity $ 449 $ 668 465 260 290 290 ,577 718 216 60 384 79 333 374 118 2 529 561 ,3,361 3,012 4,877 5,444 2,031 2,321 2,510 3,060 231 283 2,252 2,045 11,901 13,153 137 137 300 300 145 145 149 149 1,606 1,707 (200) 1,964, 2,087 2,107 2,260 5,771 6,348 $21,470 $22,950 The accompanying Notes to the Consolidated Financial Statem~rtts are an integral part of this statement. II 33 .. e 'Pacific. Gas and Electric Company Statement of Consolidated Cash Flows .(in millions) Cash Flows From Operating Activities Net income ' \- Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning Deferred income taxes and tax credits-net Other deferred charges and noncurrent liabilities Net effect of changes in óperating assetS and liabilities: Accounts receivable-trade Inventories and prepayments Accounts payable-trade , ' Regulatory balancing accounts payable Accrued taxes Other working capital Other-net Net cash provided by operating activities Cash Flows From Investing Activities Capital expenditures Proceeds from sale of assets Other-net Net cash used by investing activities Cash Flows From Financing Activities Net borrowings (repayments) under credit facilities; Long-term debt issued ' Long-term debt matured, redeemed, or repurchased PrQceeds from issuance of rate reduction bondS Preferred stock, redeemed or repurchased 'Common stock ~repurchased Dividends paid Other-net Net cash provided '(used) by financing activities Net Change in Cash and Cash Equivalents , Cash and Cash E<IUivalents at January 1 Cash and Cash EquivalentS at December 31 Supplemental disclosures of cash 'flow infomiation ,Cash paid for: Interest (net of amounts capitálized) Income taxes (net of refunds) ~ , -'!'. For the year ended " DeCember 31, 1999 1998 1997 $ 788 $. 729 $ 768 1,564 1;438 1,748 (485) (257) (182) 101 31 133 187 266 (582) 34 (21) 12 15 203 (80) ,305 537 126 116 (227) (62) (73) (50) (128) (352) (39) 15 2,200 2,610 1,768 (1,181) (1,382) (1,522) 1,014 501 234' 40 (117) 67 (841) (1,639) (219) ,668 , (681) 355 (672) (1,413) (852) 2,881 . (108) (926) '(1,600) (440) (444) (739) 1 (5) (1~) (2;256) (2,902) 950' 11 .' (1,133) 1,079 90 1,223 144 $ 101 $ 90, $ '1,223 $ 531$ 600 1,001 1,115 $ 547 841 The accompanying Notes to the Consolidated Financial, Statements are an integral part of this statement. 34 ~-:' ~ e - Pacific Gas and Electric Company . Statement of Consolidated Stockholders' Equity (in millionsl except share amounts) Preferred Stock Common Total Without Additional Stock Common Mandatory Common Paid-in Held by Reinvested Stock Redemption (in millions) Stock Capital Subsidiary Earnings Equity Provisions BaJance Deèember 31,1996 $2,018 $ 3,710 $2,636 $ 8,364 $ 402 Net income 768 768 Holding company fonnation (1,146) (1,146) Cash dividends declared Preferred stock (33) (33) Common stock (699) (699) Other (1) (1) Balance December 31, 1997 $2,018 $ 2,564 $2,671 $ 7,253 $ 402 Net income 729 729 Common stock repurchased " (62,150,837 shares) (311) (481) (808) (1,600) Ii Preferred stock redeemed I, (4,323,948 shares) (7) (3) (10) (98) Ii Cash dividends declared Preferred stock (28) (28) Common stock (300) (300) Other 11 (1) 10 (10) BaJance December 31,1998 $1,707 $ 2,087 $2,260 $ 6,054 $ 294 Net income 788 788 Common stock repurchaSed (27,666,460 shares) (101) (123) (200) (502) (926) ·1 Cash dividends declared Preferred stock (25) (25) Common stock (415) (415) Other 1 1 Balance December 31,1999 $1,606 $ 1,964 $(200) $2,107 $ 5,477 $ 294 The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. I: 35 ! e e Notes to Consolidated Financial Statements Note 1: General Basis of Presentation PG&E Corporation became the holding company of Pacific Gas and Electric Company (the Utility) on January 1, 1997. Prior to that time, the Utility was the 'predecessorofPG&E Corporation: Effective with PG&E Corporation's for:mation, the Utility's interests in its unregulated subsidiaries were transferred to PG&E Corporation. This is a combined annual report of PG&E Corporation and the Utility. Therefore, the Notes to Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's consolidated fmancial statements include the accounts of PG&E Corporation, the Utility, and PG&E Corporation's wholly owned and controlled subsidiaries. The Utility's consolidated fmancial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. All significant intercompany transactions have been eliminated from the consolidated fmancial statements. Certain amounts in the prior years' consolidated financial statements have been reclassified to conform to the 1999 presentation. The preparation of fmancial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, and liabilities and the disclosure of contingencies, Actual results could differ from these estimates. Accounting principles used include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (ffiRQ. ' ' Operations PG&E Corporation is, an energy-based holding company headquartered in San Francisco, California. Its businesses provide energy services throughout North America. PG&E Corporation's Northern and Central California utility subsidiary, Pacific Gas and Electric Company, provides natural gas and electric service to one of every 20 Americans. PG&E Corporation's National Energy Group provides energy products and services throughout North America. The National Energy Group businesses develop, constIuct, operate, own, and manage independent power generation facilities that serve wholesale and industrial customers through PG&EGenerating Company, liC (formerly u.s. Generating Company, liC) and its affùiates (collectivdy, PG&E Gen); own and operate natural gas pipelines, natural gas storage facilities, and natural gas processing plants, primarily in the Pacific Northwest and in Texas, through various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission or PG&E GT); purchase and sell energy commodities and provide risk management services to customers in major North American markets, including the other National Energy Group non-utility businesses, unaffùiated utilities, . marketers, municipalities, and large end-use customers, through PG&E Energy Trading-Gas Corporation, PG&E Energy Trading-Power, L.P., and their affùiates (collectively, PG&E Energy Trading or PG&E ED; and provide competitively priced electricity, natural gas, and related services to industriai, commercial, and institutional customers through PG&E Energy Services Corporation (PG&E Energy Services or PG&E ES). In the fourth quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the divestiture of PG&E Corporation's Texas natural gas and natural gas liquids business. Also in the fourth quarter of 1Q99, PG&E Corporation's Board of Directors approved a plan for the divestiture. of PG&E Corporation's retail energy services. . Regulation and Statements of Financial Accounting Standards (SFAS) No. 71 Thé Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory Commission, among others. The gas transmission business in the Pacific No~west is regulated by the FERC. The gas transmission business in Texas is regulated by the Texas Railroad Commission. PG&E Corporation and the Utility account for the financial effects of regulation in accordance with Statement of Firiancial Accounting Standards (SF AS) No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement allows for the deferral as a regulatory asset costs that otherwise would have been expensed if it is ,"¡i ¡ 36 -'-~-'a"'-'-" '! probable that the costs will be .vered in future regulated revenues. In ad.n, SFAS No. 121, "Accounting for the Irp.pairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires PG&E C<;>fporation and the Utility to write off regulatory assets when they are no longer probable of recovery. On an ongoing basis, PG&E COfporation and the Utility review their regulatory assets and liabilities for the continued applicability of SFAS No. 71 and the effect of SFAS No. 121. Regulatory assets and liabilities are comprised of the following: BaJance at December 31, 1999 1998 (in miIlions) '. , Utility: Generation-related transition costs(l) Unamortized loss, net of gain, on reacquired debt Regulatory' assets for deferred income tax Other, net Total' Utility National Energy Group Regulatory assets Regulatory liabilities (1) See Note 2 of Notes to Consolidated Financial .Statements for further discussion. Regulatory assets and liabilities are amortized over the period that the costs are reflected in regulated revenues. The ~jority of the Utility's regulatory assets are included in generation-related transition costs. The· Utility,is amortizing its eligible 'transition costs, ,including generation-related regulatory assets, over the transition period in conjunction with the available competitive transition charge (erC) revenues. During 1999, regulatory assets related to electric industry restructuring decreased by $1,359 million. This decrease , reflects the recovery of eligible transition costs of $806 million through amortization and $553 million through the gain on the sale of generating plants. $3,996 288 295 316 $4,895 62 $4,957 $ 771 $5,355 289 293 351 $6,288 59 $6,347 $526 'Revenues and Regulatory Balancing Accounts In cònnection with electric industry restructuring, use of the Utility's sales and energy cost balancing accounts for electric utility revenues was discontinued in 1998. These balancing accounts have been replaced wiû~ regulatory adjustment mechanisms that impact expenses instead of revenues. (See Note 2.) For gas utility revenues, sales balancing accounts accumulate differences between authorized and actual base revenues. Further, gas cost balancing accounts accumulate differences between the actual cost of gas and the revenues designated for recovery of such costs. The regulatory balancing accounts accumulate balances until they are refunded to or' received from Utility customers through authorized rate adjustments. Utility revenues included amounts for services rendered but unbilled at the end of each year. I Accounting for Price Risk Management Activities PG&E Corporation, primarily through its subsidiaries, engages in price risk management activities for both non-hedging and hedging pUfposes. PG&E COfporation conducts non-hedging activities principally through its unregulated subsidiary, PG&E ET. Derivative and other financial instruments associated with our electric power, natural gas, natural gas liquids, and related non-hedging activities are accounted for using the mark-to-market method· of accounting. Under mark-to-market accounting, PG&E COfporation's non-hedging conti'acts, including both physical ' contracts and financial instruments, are recorded at market value, which approximates fair value. The market prices used to value these transactions reflect management's best estimates considering various factors including market quotes, time value, and volatility factors of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions. Changes in the market value of these contract portfolios, resulting' primarily from newly originated transactions and the impact of commodity price and interest rate movements, are recognized in operating revenues in the ., 37 I I .1 !' ~' period' of change. Unrealized gain~d losses of thesé contract portfolios are re.ed as assets and liabilities, respectively, from price risk management. In addition to the non-hedging activities discussed above, PG&E Corporation may engage in hedging activities' using futures, forward contractS, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies when there is a high degree of correlation between price movements in the derivative and the, item designated as being hedged. PG&E Corporation accounts for hedge transactions under the deferral method. Initially, PG&E Corporation defers unrealized gains and losses on 'these transactions and classifies them as assets or liabilities. When the hedged transaction occurs, PG&E Corporation recognizes the gain or loss in operating expense. In instances where the anticipated correhÌtion, of price movements does not occur, hedge accounting is terminated and future changes in the value of the derivative are recognized as gains or losses. If the hedged item is sold, the value of the assoCiated derivative is recognized in income. In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Acèounting Standards (SPAS) No. 137, "Accounting for Derivative Instruments and Hedging Activitie~Deferral of the Effective Date of FASB Statement No. 133," which delayed the implementation of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," by one year to require adoption in yeárs beginning afte,r June 15, 2000. The Statement permits early adoption as of the beginning of any fiscal quarter. " PG&E Corporation expects to adopt SFAS No. 133 no later than January 1, 2001. The S~tement will require 'PG&E Corporation to recognize all derivatives, as defmed in the Statement, on the balance sheet at fair value. , Derivatives, or any portion thereof, that are not effective hedges must be adjust~d to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changesin the fair value of derivatives either Will be offset against the change in fair value of the hedged assets, liabilities; or firm commitments through earnings, or will be recognized in other comprehensive income until the hedged items are récogniz<:d, in earnings. We currently are evaluating what effect of SPAS No. 133 will be on the earnings and financial position of PG&E Corporation. However, we already use the mark-to-market method of accounting for our commodity non-hedging and price risk management activities. ' ' ' In compliance with regulatory requirements, the Utility manages price risk independently from the activities in PG&E Corporation's unregulated business. During 1998, the CPUC authorized Pacific Gas and Electric Company to trade natural gas-based' fmancial instruments to manage price and revenue risks associated with its natural gas transmission and storage assets, subject to certain conditions. Also in 1998, the CPUC authorized the Utility to trade natural gas-based fmàncial instruments to hedge the gas commodity ptjce swings in serving core gas customers. In May 1999, the Power Exchange (PX) obtained FERC approval to operate the "block forward market" which offers parties the ability to buy and sell contracts to purchase electricity intÍ1e futUre at prices set in the contracts. The, Utility sought and obtained. CPUC authority to participate in the PXblock forward market for contracts that call for delivery of the purchased electricity by October 31, 2000, as well as to recover costs (such as gains/losses and transaction fees) associated with its participation in thi~ market. Property, Plant, and Equipment . Plant additions and replacements are capitalized. The capitalized costs include labor, materials, construction overhead, ,and capitalized intereSt or an allowance for funds used during construction (AFUDC). AFUDC'is the estimated cost of debt and equity funds used to finance regulated plant additions. The Utility recovers AFUDC in rates through depreciation expense over the useful life of the related asset. Nuclear fuel inventories are included in property, plant, and equipment. Stored nuclear fuel inventory is stated at lower of average cost or market. Nuclear fuel in the reactor is amortized based on the amount of energy output. ' The original çost of retired plant and removal costs less salvage value is charged to ac<::umulated depreciation upon retirement of plant in service for the Utility and the National Energy Group businesse~ that apply SFAS , No. 71. For the remainder of our National Energy Group business operations~ the cost and accumulated depreciation of property, plant, and equipment retired or otherwise disposed of are removed from related accounts and included in the ,determination of the gain or.loss on dispo~ition. ' Property, plant, and equipment is depreciated using a straight-line remaining-life method. PG&E Corporation's composite depreciation rates were 3.60 percent, 3.89 percent, and 3.45 percent for the years ended December 31, 1999,.1998, and 1997, respectively. The Utility'sconiposite'depreciation rates were 3.41 perçent, 3.88 percent, and 3.26 percent for the years ended December 31, 1999, 1998, and 1997, respeCtively. , I 38 ... .f-. -¡~- f.. '~ e Gains and Losses on Reacquired Debt , Any gains and losses on reacquired debt associated with regulated operatio~ that are subject to the provisions of SFAS No. 71 are deferred and amortized over the remaining original lives of the debt reacquired, . consistent with ratemaking principles. Gains and losses on reacquired debt associated with unregulated operations are recognized' in earnings at the' time such debt is reacquired. e Inventories Inventories include material and supplies, gas stored undergròund, coal, and fuel oil. Materials and supplies, coal, and gas stored underground are valued at average cost. Fuel oil is valued by the last-in ftrst-out method. Cash Equivalents and Short-Term Investments Cash equivalents (stated àt cost, which approximates market) include working funds and consist primarily of Eurodollar time depòsits, bankers acceptances, and some commercial paper with original, maturities of three months or less., Income Taxes PG&E Corporation uses the liability method of accounting for income taxes. Income tax expense includes current and deferred income taxes resulting from operations during the, year. Tax éredits are amortized over the life of the related ,property. ' PG&E Corporation files a èonsolidated federal income tax return that includes domestic subsidiaries in which its ownership is 80 percent or more. The Utility and various other subsidiaries are parties to a tax-sharing arrangement with PG&E Corporation. PG&E Corporation files consolidated state income tax returns when applicable. The ,Utility reports taxes on a stand-alone basis. Related Party Agreements In accordance with various agreements, the Utility and other subsidiaries provide and receive various services from their parent, PG&E Corporation. Services include the Utility's provision of general and administrative services. The Utility and other subsidiaries receive general and administrative se~ices and fmancing from PG&E Corporation. Corporate costs, such as administrative costs, interest, and income taxes, are allocated to subsidiaries using a variety of factors, including their share of employees, operating expenses, assets, and other cost causal methOds. Also, the Utility purchases gas commodity and transmission services from PG&E ET and transmission services from PG&E GT NW. 'Intercompaný transactions are eliminated in consolidation and no proftt results from' these transactions. At December 31, 1999, the Utility has a net intercompany payable to affiliates of $207 million, of which $163 million relates to short-term borrowings, including interest. For the years ended December 31, 1999 and 1998, the Utility's significant related party transactions are provided in the table below. (in miUions) UtilitY revenues from: Administrative services provided to PG&E Corporation Transportation and distribution services provided to PG&E ES Gas reservation services provided to PG&E ET Other Utility expenses from: Administrative services received from PG&E Corporation Gas commodity and transmission services received from PG&E ET Transmission services received from PG&E GT NW 1999 1998 $ 23 $17 134 7 1 3 4 66 58 30 1 47 49 39 I .1 . ~ ... e Cumulative Effect of Change in Accounting Method Effective January 1, 1999, PG&E Corporation changed its method of accounting for major maintenance and ' overhauls at the National Energy Group. Beginning January 1, 1999, the cost of major maintenance and overhauls, principally at the PG&E Gen business segment, were accounted for as incurred. Previously, the estimated cost of major maintenance and overhauls was accrued in advance in a systematic and rational manner over the period between major maintenance and overhauls. The change resulted in PG&E Corporation recording income of $12 million net of income tax, ($0.03 per share), reflecting the cumulative effect of the change in accounting principle. The effect on Current year results of operations was immaterial. Accordingly, the unaudited quarterly consolidated information has been restated. (See "Quarterly Consolidated Financial Data (Unaudited)" below.) e The Utility has consistently accounted for major maintenance and overhauls as incurred. Note 2: The California Electric Industry In 1998, California becáme one of the first states in the country to implement electric industry restructuring and establish a competitivê market framework for electric generation. Today, most Californians may continue to purchase their electricity from investor-owned utilities such as Pacific Gas and Electric Company, or they nµy choose to purchase electricity from alternative generation providers (such as unregUlated power generators and unregulated retail electricity suppliers such as marketers, brokers, and aggregators). For those customers who have, not chosen an alternative generation provider, investor-owned utilities, such as the Utility,' continue t9 be the generation providers. Investor-owned utilities continue to provide distribution services to substantially all customers within their service territories, including customers who choose an alternative generation provider.' Competitive Market Framework To create a competitive generation market, a PX and an Independent' System Operator (ISO) began operating on March 31, 1998, The PX provides a competitive auction process to establish market clearing prices for electricity in the markets operated by the px. The ISO schedules delivery bf electricity for all market participants. The Utility continues to own and mamtain a portion of the transmission system, but the ISO controls the operation. of the system. Unless or until the CPUC determines otherwise, the Utility is required to bid or schedule into the PX and ISO markets all of the electricity generated by its power plants and electricity acquired under contractual agreements with unregulated generators. Also, the Utility is required to buy from the .fX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier. In November 1999, the FERC approved the extension of the ISO's authority to establish price limitations through 2000. The ISO Board incrèased the applicable price limitation tò $750 per megawatt-hour (MWh) on' October 1, 1999, but has the option to decrease it to $500 per MWh or make other changes, in view of the FERC's decision. This limits the amount of volatility that occurs in the California electricity market. Howèver, the ISO will review the appropriate level for any price limitations for the summer of 2000 in light of market redesign efforts now being considered, including changes to reduce uninstructed deviations from ISO dispatch orders and changes to permit loads to, participate by submitting bids for price responsive demand in energy or ancillary services markets. . For, the year ended December 31, 1999, and for the period of March 31, 1998 (the PX's establishment date) to December 31, 1998, the cost of electric energy for the Utility, reflected on the Statement of Consolidated Income, is comprised of the cost of PX purchases, ancillary services purchased from the ISO, cost of transmission, and the cost of Utility generation, net of sales to the PX as follows: (in millions) Cost of fuel for electric generation and qualifying facilities (QF) purchases Cost of purchases from the PX - Cost of ancillary services Proceeds from sales to the PX Cost of electric energy Year ended December 31, . 1999 1998 $1,489 $ 2,030 1,114 723 630 617 , (822) (1,049) $2,411 $ 2,321 40 ¡;_r - '. "-! Transition Period, Rate Free, and Rate 'Reduction It California's electric industry restructuring established a transition period during which electric rates remain frozen at 1996 levels (with the exception that, on January 1, 1998, rates for small commercial and residential éustomers were reduced by 10 percent and remain frozen at this'reduced level) and investor-owned utilities may recover their transition costs. Transition costS are generation-related costs that prove to be uneconomic under the new competitive structure. The transition 'period ends the earlier of December 31,2001, or when the particular utility has recovered its eligible transition costs. Revenues from frozen electric rates provide for the recovery of authorized Utility costs, including transmission and distribution service, public purpose programs, nuclear decommissioning, and rate reduction bond debt serVice. , To the extent ,the revenues from frozen rates exceed authorized Utility costs; the remaining revenues constitUte the CTC, which recovers the transition costs. These CTC revenues are being recovered from all Utility distribution customers and are subject to seasonal fluctuations in the Utility's sales volumes ,and certain other factors. As the CTC is collected regardless of the customer's choice of electricity supplier (i.e., theCTC is non-bypassable), the Utility believes that the availability of choice to its customers will not have a material impact on its ability to recover transition costs. To pay for the 10 percent rate reduction, the Utility refInanced $2.9 billion (the expected revenue reduction from the rate decrease) of its transition costs with the pròceeds from the rate reduction bonds. The bonds allow for the rate reduction by lowering the canying cost on a portion of the transition costs and by deferring rec6very of a portion of these transition costs until after the transition period. During the rate freeze, the rate reduction bond debt service will not increase Utility customers' eJectric rates. If the transition period ends before December 31, 2001, the Utility may be obligated to return a portion of the economic benefIts of the transaction to customers. The timing of any such retúrn and the exact amount of such portion, if any, have not yet been determined. Transition Cost Recovery , Although most transition costs must be recovered during thetransitiòn period, certain transition costs can be recovered after the transition period. EXcept for certain transition costs discussed below, at the conclusion of the transition period, the Utility will be at risk to recover any of its remaining generation costs through market-based revenues. ' Transition costs consist of (1) above-market sunk costs (costs associated with utility generating facilities that are fIxed and unavoidable and that were included in customers' rates on December 20, 1995) and future sunk costs, such às costs related to plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from qualifying facilities and other power suppliers, and (3) generation-related regulatory , assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods, to be included in rates in subsequent periods,) , Above-market sunk costs result when the book value of a fa,cility exceeds its market value. Conversely, below-market sunk costs result when the market value ora facility exceeds its book value. The total amount of geq,eration facility costs to be included, as transition costs is, based on the aggregate of above-market and below- market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below- market portion of these costs will reduce other unrecovered transition costs. These above- and below-market sunk . costs are related to generating facilities that are classified as either non-nuclear or nuclear sunk costs. The, Utility cânnot determine the exact amount of above-market non-nuclear sunk costs that will be recoverable as transition costs until the valuation of the Utility's remaining non-nuclear generating assetS, primarily its hydroelectric generating assets, is completed. The valuation, through appraisal, sale,. or other divestiture, must be completed by December 31, 2001. The value of seven of the Utility's other non:nuclear generating facilities was determined when these facilities were sold to third parties. The portion of the' sales proceeds that exceeded the , book value of these facilities was used to reduce other transition costs. On September 30, 1999, the Utility f1!ed an application with the CPUC to determine the market và1ue of its hydroelectric generating facilities and related assets through an open, competitive auction. (See "Generation Divestiture" below.) The Utility plans'to use an auction , process similar to the one previously approved by the CPUC and successfully used in the sale of the Utility's fossil and geothermal plants. If the market value of the Utility's hydroelectric facilities is determined based upon any method other than a sale of the facilities to a third party, a material charge to Utility earnings could result. Any .41 ,~ excess of market value over book v.ould be used to reduce other transition ce. (See "Generation Divestiture" below.) , ' . For nuclear transition costs, revenues provided for trånsition cost r:ecove¡yare based on the accelerated recove¡y of the investment in Diablo Canyon Nuclear Power Plant (Diablo Cányon) over a five-year period ending December 31, 2001. The amount of nuclear generation sunk costs was deteri:nined separately through a CPUC proceeding and was subject to a final verification audit that.was completed in August 199R The audit of the Utility's Diablo Canyon accounts at December 31, 1996, resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs, Theindependent accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, that questioned $200 million of the $3.3 billion sunk costs. ,The CPUC will review the results of the audit and may seek to make adjustments to Diablo Canyon's sunk costs subject to transition cost recòvery. At this time, the Utility caMct predict what actions, if any, the CPUC may take regarding the audit report. , ' . Costs. associated with, the Utility's, long-term contracts to purchase electric power are iñcluded as transition costs. Regulation required the Utility to enter into such long-term agreements with non-utility generators. Prices fixed under these contracts are now typically above prices for power in wholesale markets (See Note 14). O~e~ the remaining life of these contracts, the Utility estimates that it. will purchase 299 million MWh of electric power. To the extent that the individual' contract prices are above the market price, the Utility is collecting the difference between the contract price and the market price from,customers, as 'a transition cost, over the term' of the contract. The contracts expire at various dates' through 2028. ' The total costs under long-term contracts are based on several variables, including ,the capacity factors of the related generating facilities and future market prices for electricity. During 1999, the àverage price paid under the Utility's long-term contracts for electricity was 6.3 cents per kilowatt~hour (kWh). The average cost of electricity purchased at market rates from the PX for the year ended December 31, 1999, was 3.7 cents per kWh. The average cost of electricity purchased' at market rates from the PX for the period from March 31, 1998,the PX's establishment date, to December 31, 1998, was3.2 cents per kWh. . Generation-related'regulato¡y assets and obligations (net generation-relatèd regulato¡y assets) are, included as . transition costS. At Ðecember 31, 1999 and 1998, the Utility's generation-related net regulatory assets totaled $4 billion and $5.4 billion, respectively., , Certain transition costs can be recovered tfuough a non-bypassable cQarge to distributi~ncustomers after the transition period. These costS include (1) certain employee-related transition costs, (2) above-market payments under existing long-term contracts to purchase power, disCussed above, (3) up to $95 million of transition costs to the extent that the recove¡y of such costs during the trarisitiçm period was displaced by the recove¡y, of electric industry restructuring implementation costs, and (4) transition costs fInanced by the rate.'reduction bonds. ' Transition costs fmanced by the issuance of rate reduction bonds will be recovered over the term 'of the bonds. In addition,' the Utility's nuclear decommissioning costs are being recovered through a CPUC-auth6rized charge, . which will extend until sufficient funds exist to decommission the nuclear facility. During the rate freeze, the 'charge for these costs will not increase Utility customers' electric rates. Excluping these exceptions, the Utility will write off any transition costs not recovered during the transition period. , , The Utility is amortizing its transition costs, including most generation-related regulatory assets, over the transition period in conjunction with the available erC'revenues. D\jring the transition period, a reduced rate of return on ~ommon equity of 6.77 percent applies to all generation asSets, including those generation assets reclassified to regulatory assets.. Effective January 1, 1998, the Utility stal1ed collecting these eligible transition costs through the non-bypassable erc and generation divestiture. For the years ended December 31, 1999 and 1998, regulatory assets related to electric industry restructuririg decreased by $1,359 million and $609 million, .. respectively, which reflects the recove¡y of eligible transition coSts, During the transition period, the CPUC reviews the Utility's compliance with accounting methods established in the CPUC's decisions governing transition cost recove¡y and the amount of transition costs requesteci for . recove¡y. The CPUC is currently reviewing non':nuclear transition costs amortized during 1998' and theftrst six months of 1999. . , I 42 ~ ~ e Generation Divestiture, In 1998, the Utility sold three fossil-fueled generation plants for $501 rrúllion. These three fossil-fueled plants had a combined book value at the time of the sale of $346 rrúllion and had a combined capacity of 2,645 megawatts (MW). On April 16, 1999, the Utility sold three other fossil-fueled generation plants for $801 million. At the time of sale; these three fossil-fueled plants had a combined book value of $256 million and had a combined capacity of 3,065 MW. e- On May 7, 1999, the Utility sold its complex of geothermal generation facilities for $213 rrúllion. At the time of sale, these facilities had a combined book value of $244 million and had a combined capacity of 1,224 MW. The gains from the sale of the fossil-fuelecl generation plants were used to offset other tranSition costs. Likewise, the loss from the sale of the' complex òf geothermal generation facilities is being recovered as a transition cost. The Utility has retained a liability for required environmental remediation related to any pre-closing soil or groundwater contamination at the - plants it has sold. On September 30, 1999, the Utility filed an application with the CPUC to determine the market value of its hydroelectric generating facilities and related assets through an open, competitive auction. The Utility proposes to use an auction process similar to the one previously approved by the CPUC and successfully used in the sale of the, Utility's fossil and geothermal plants. Under the process proposed in the application, another subsidiary of PG&E Corporation, PG&E Gen, woùld be permitted to participate in the auction on the same basis as other ~~. ' The sale of the hydroelectric facilities would be subject' to certain conditions, including the transfer or re-issuance of various permits and licenses by the FERCand other agencies. In addition, the FERC must approve assignment of the Utility's Reliability Must Run Contract with the ISO for any facility subject to such contra€t. Under the proposed:purchase and sale agreement, the CPUC's approval of the proposed sale on terms acceptable to the Utility in the Utility's sole discretion is also a condition precedent to the closing of any sale. On January "13, 2000, a scoping memo and ruling was issued that separates the proceeding into two concurrent phases: one to review the potential environmental ,impacts of the proposed auction under the California Environmental Quality Act and a second to determine whether the Utility's auction proposal, or some other alternative to the proposal, is in the public interest. The ruling notes that the divestiture and valuation issues can best be considered after the environmental impacts of a change in ownership have been reviewed. Potential bidders will also be able to incorporate the costs of any mitigation measures that .may be required into their bids. The ruling sets a procedural schedule which calls for a final decision on the Utility's auction proposal by October 19, 2000, and afmal environmental impact report published in November 2000: The ruling also anticipates that a fmal CPUC decision approving the sale would be issued by May 15, 2001. Finally, theruling prohibits the Utility from withdrawing its application without express CPUC authority: It is uncertain whether the CPUC will ultimately approve the Utility's auction proposal. At December 31, 1999, the book value of the Utility's net investment in hydroelectric generation assets was approximately $0.7 billion, excluding approximately $0.5 billion of net investment reclassified as regulatory assets. Any excess of market value over the $0.7 billion book value would be used to reduce transition costs, including the remaining $0.5 billion of regulatory assets related to the hydroelectric generation assets. If the market value of the hydroelectric generation assets is determined by any method other than-a sale of the assets to a third party, or if the winning bidder for any of the auctioned assets is PG&E Gen, a material charge to Utility earnings could result. The timing and nature of any such charge is dependent upon the valuation method and procedure adopted, and the method of implementation. As discussed below, it is possible that the CPUC will require an interim valuation through an estimate of market value of the assets prior to transfer, sale or other divestiture, which could also result ina material charge. While transfer or sale to an affiliated entity such as PG&E Gen would result in a material charge to income, neither PG&E Corporation nor the Utility believes that the sale of any generation facilities to a third party will have a material 'impact on its results' of operations. The Utility's ability to continue recovering its transition costs depends on severa!' factors, inCluding (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the determined value of the Utility's hydroelectric generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, and 43 + . ,.... -- e (6) the market price of electricity. Given the current evaluation of these factors, PG&E Corporation believes that the Utility-will recover its transition costs. However, a change in one or more of these factorS could affect the probability of recovery of transition costs and result in a material charge. . Post-Transition Period In October 1999, the CPUC issued'a decision in the Utility'spost-transition:period ratemaking proceeding., Among other matters, the CPUC's decision addresses the mechànisms for ending the current electric rate freeze and for establishing post-transition period accounting mechanisms and rates, The decision requires Diablo Canyon generation to be priced at prevailing market rates after the transition period. The CPUC decision requires the Utility to provide quarterly forecasts of when the UtilitY's rate freeze (i.e., ,transition period). may end based on various assumptions_regarding energy prices and the book value of the Utility's remaining generation assets. The Utility is required to notify the CPUC three months before the earliest forecasted end of its rate freeze and provide draft tariff language and sample calculations of the rates that would go into effect when the rate freeze ends. Afterthe Utility, completes its transition cost recovery, it must implement its post-rate-freeze rates. The timing of the end of the rate freeze and corresponding transition period will, in part, depend on the timing of the valuation of the Utility's hydroelectric generating ¡lssets and the Ultimate determined value of such assets since any excess of market value over the assets' book value would be used to reduce transition costs. If the value of the Utility's hydroelectric generation assets is significantly higher than tþ.e related book value, the transition period and the rate freeze could end before December 31, 2001, arid potentially could end during ~OOO. The CPUC is considering the UtÜity's proposal to auctiòn its hydroelectric assets, although the CPUC could also require the Utility to implement an interim valuation of the' assets. In another proceeding (the 1998 Annual Transition: Cost Proceeding (ATCP)), a CPUC administrative law judge issued a proposed decision on January 7, 2000, which contained a proposed c~ange to the rules previously in place for the amortization of transition costs. Under the fInal decision, issued on February 17,2000, on a prospective basis the utilities are required to assess the. , estimated market value of their rerriaining non,.nuclear generating assets, including the land associated with those assets; on an aggregate basis at a value 'not less than the net book value of those assets and, to credit the Transition Cost Balancing Account (TCBA) with the estimated val~e. The decision encourages the utilities to base such estimates oil realistic assessments of the ma~ket value of the assets. The final decision did not adopt the proposed decision's recommendation to establish anew regulatory asset account that would allow a true-up when the estimated market value is greater than actual market value, However, the decision states that crediting the TCBA with the a:ggregat~ riet book value of the remaining non-nuclear generating assets is a conservative approach and remedies any concerns regarding the lack of a true-up. The decision provides that if the estimated market valuation is less than book value for any indivi<lual asset, accelerated amortization of the associated transition costs will continue until fInal market valuation of the asset occurs through sale, appraisal, or other divestiture. If the fmal value of .theassets, determined through sale, appraisal, or other divestiture, is higher than the estimate, the excess amount would be used to pay remainmg transitiOIl costs, if any. The utilities are required to file the adjusted entries to their respective TCBA based on the estimated market values with the CPUC by March 9, 2000. The filing will become effective after appropriate review by the CPUC's Energy Division and the TCBA entries are subject to review in the next ATCP. If an estimate of the market value ·of the non-nuclear generating assets is adopted that exceeds the aggregate net book value of those assets, a charge to earnings would result. After the rate freeze and transition periods end, the Utility must refund to electric customers any " over~collected transition costs (plus interest at the Utility's authorized rate of return) within one year after'theerid of the rate freeze. The Utility also' will be prohibited from collecting after the rate freeze any electric costs incurred during the rate freeze but not recovered during the rate freeze, 'including costs that are n,ot classified as transition costs. Through the end of its rate freeze, the Utility will continue to incur certain non-transition costs and place those costs into balancing and 1llemorandum accounts for future recovery., There is a risk that the Utility will be unable to collect certain non-transition costs that, due to lags in the regulatory cost approval process,' have not been approved for recovery nor collected when the rate freeze ends. The Utility is unable to predict the amourit of such potential unrecoverable costs.' , 44 . ~r"_: ..~..." '. ',~~,-¡<c . -, . -! I c' The CPUC also has establish'the Purchased Electric Commodity Accounlr the Utility to track energyc~sts , after the rate freeze and transition period end. The CPUC intends to explore other ratemaking issues, including whether dollar-for-dollar recovery of energy costs is appropriate, in the second phase of the post-transition electric ratemaking proceeding. There are three primary options for the future regulatory framework for utility electric energy procurement cost recovery after the rate' freeze: (1) a CPUC-defined procurement practice, that if followed' by the Utility, would pass through costs .without the need for reasonableness reviews, (2) a pass-through of costs subject to after-the-fact reasonableness reviews, or (3) a procurement incentive mechanism with· rewards and penalties determined based on the Utility's energy purchasing performance compared to a benchmark. The Utility proposed adoption of either a defined procurement practice or a procurement incentive mechanism, neither of which would involve reasonableness reviews. The volatility of earnings and risk exposure of the Utility related to post -transition period purchases of electricity is dependent on which, of these options, or SOme other approach, is adopted. , ( After the i:ránsition period, the Utility's future earnings from its electric distribution will be subject to volatility as a result of sales fluctuations. . " I Note 3: Price Risk Management and'Financiëll Instrum~nts The following table is a summary of the contract or notional amounts and maturities of PG&E Corporation's contracts used for non-hedging activities related to commodity price risk management as of December 31, 1999 and 1998. Short and long positions pertaining to derivative contracts used for hedging activities as of December 31, 1999 and 1998, are immaterial.. Maximum Natural Gas, Electricity, Purchase Sale Term in and Natural ,Gas Liquids Contracts (Long) (Short) Years (billions of MMBtu equiva1ents(J» Non-Hedging Activities-December 31, 1999 Swaps 2.28 2.20 7 Options 0.93 0.85 8 Futures 0.19 0.18 2 Forward contracts 1.47 1.42 12 Non-Hedging Activities-December 31, 1998 Swaps 6.21 6.06 8 Options 1.50 1.28 5 Futures 0.58 0.61 4 Forward contracts 3.70 3.55 5 . (1) One MMBtu is equal to one million British thermal units. PG&E Corporation's electric power contracts, measured in megawatts, were converted to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt-hour. PG&E Corporation's natural gas liquids contracts were converted to MMBtu equivalents using an appropriate çonversion factor for each type of natural gas liquids product. Volumes shown for swaps, futures, and options represent notional volumes that are used to calculate amounts due under the agreements and do not necessarily represent volumes exchanged. Moreover, notional amounts are indicative only of the volume of activity and are not a measure of market risk. PG&E Corporation's net gains (losses) on swaps, options, futures, and forward contracts held during the years ended December31, 1999 and 1998 are as follows: Year' ended December 31, (in millions) Swaps Options ., Futures Forward contracts Net gain (loss) 1999 $ 15 (41) (36) 98 $ 36 1998 $ 69 (49) (63) 101 $ 58 45 l e e The following table discloses the estirriited fair values of price risk management assets and liibilities as of December 31, 1999 and 1998. The ending and average fair values and associated éanying amounts of derivative' contracts used for hedging purposes are not material as of December 31, 199? and 1998, (in millions) Non-Hedging Activities-December 31, 1999 Assets: Swaps Options > Futures Forward contracts Total Average Ending , Fair Value Fair Value Noncurrent portion Current portion Non-Hedging Activities-December 31, 1998 Assets: Swaps Options Futures Forward contracts Total $ 643 $ 244 106 92 175 47 667 596 - - $ 1 ,591 $,' 979 - $ 372 $ 607 $ 592 $ 218 109 81 201 67 561 456 - - $1,463 $ 822 - $ 247 $ 575 $ 494 $ 947 121 154 115 150 342, 499 - $1,072 $1,750 $ 334 ,$1,416 Noncurrent, portion Current portion Liabilities: Swaps OptionS Futures Forward contracts Total Noncurrent portion Current portion Liabilities; Swaps $ 476 $'~ 908 Options 147 201 . . Futures 111 186 Forward contracts 28f 398 Total $1,016 , $1,693 Noncurrent portion $ 281 Current portion' $1,412 PG&E Corporation, primarily through its subsidiaries,engage~ in price risk ffianagement activities for both non-hedging and hedging purposes. Non-hedging activities are conducted principally through its unregulated subsidiary, PG&E ET. In compliance with regulatory requirementS, the Utility manages price risk independently from the activities in PG&E Corporation's unregulated businesses (see Note 1 for further discussion). The Utility primarily: engages in hedging activities which, noted above; 'were immaterial for the years ended December 31, , 1999 and 1998. ' In valuing its electric power, natural gas, andnatural gas liquids portfolios, PG&E Corporation considers a number of market ,risks and estimated costs and continuously monitors the valuation of identified'risks and adjusts them based on present market conditions. Considerable judgment is required to develop the estimates of fair ,value; thus, the estimates provided herein are not necessarily indicative of the amounts that PG&E Corporation could realize· in the current market. Generally, exchange-traded futures contracts require deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. Margin cash reqùirements for over-the-counter fmancial instruments are specified by the particular instrument and often do not require margin 'I 46 ~~ ~ cash and are settled monthly. B.exchange-traded and' over-the-counter oP. contracts require payment! 'receipt of an option premium at the inception of the contract.· Margin cash for commodities futures and cash on deposit with counterparties was immaterial at December 31, 1999. Note 4: Concentrations of Market and Credit Risk Market Risk Market risk is the risk that changes in market prices will adversely affect earnings and caSh flows. PG&E Corporation is primarily exposed to the, market risk associated with energy commodities such, as electric power, natural gas, and natural gas liquids. Therefore, PG&ECorporation's price risk management activities primarily· involve buying and selling fixed-price commodity commitments into the future. Net open positions often exist or are established due to PG&E Corporation's assessment of and response to changing market conditions, To the extent that PG&E Corporation has' an open position, it is exposed to the risk that fluctuating market prices may . adversely impact its financial results. ' Credit Risk The use of financial instruments to manage the risks associated with changes in energy commodity prices creates exposure resulting from the possibility of nonperfonnance by counterparties pursuant to the .terms of their contractual obligation. The counterparties in PG&E Corporation's portfolio consist primarily of investor-owned and municipal utilities, energy trading companies, financial institutions, and oil and gas production companies. PG&E Corporation minimizes credit risk by dealing primarily with creditworthy counterparties in accordance with established credit approval practices and limits. PG&E Corporation routinely assesses the financial strength of its counterparties and may require letters of credit or, parental guarantees when the financial strength of a counterparty is not considered sufficient. PG&E Corporation has experienced no material losses due to the nonperformance ofcounterparties in 1999. The credit exposure of the five largest counterparties comprised approximately $250 million of the total credit exposure associated with financial instruments used to manage price risk. Counterparties considered to be investment grade or higher comprise 70 percent of the total credit exposure. Note 5: Acquisitions and Sales In Janua¡y 1997, PG&E Corporation acquired Teco Pipeline Company for $378 million, consisting of $317 million of PG&E Corporation common stock and the purchase ofa $61 million note. In April 1997, through one of its wholly owned subsidiaries, PG&E Corporation sold its interest in International Generating Company, Ltd., which resulted in an after-tax gain of approximately $120 million. In July 1997, PG&E Corporation completed its acquisition of Valero Energy Corporation's natural gas business and a gas marketing business located in Texas. PG&E Corporation issued approximately 31 million shares of its common stock to acquire Valero along with ,the assumption of $780 million in long-tenn debt, equating to a purchase price of approximately $1.5 billion. The acquisition was accounted for as a purchase and accordingly, the pur<;hase price has been allocated to the assets acquired and the liabilities assumed based on estimated fair values. In September 1997, PG&E Corporation became the sole owner of PG&E Gen, an independent power developer, owner, and manager; PG&E Operating Services Company, PG&E Gen's operations and maintenance affiliate; and USGenPower Services, LP., PG&E Gen's power marketing aff1liate. Additionally, PG&E Corporation has acquired all or part of interest in several power projects that are affùiated with PG&E Gen. In July 1998, PG&E Corporation sold its Australian energy holdings, The sale represents a premium on the price in local currency of PG&E Corporation's 1996 investment in the assets. However, the transaction resulted ina charge of $.06 per share in the second quarter of 1998. This charge was primarily due to tb.e 22 percent currency devaluation of the Australian dollar against the U.S. dollar during 1998 and 1997. In September 1998, PG&E Corporation, through its indirect subsidia¡y USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generating assets and power supply contracts from the New England Electric System (NEES). The acquisition has been accounted for using the purchase method ·of accounting. Accordingly, the purchase price has been allocated to the assets purchased and the liabilities assumed based upon an assessment of the fair values at the date of acquisition. 47 ,~ e e InCluding fuel and other inventories and transaction costs,PG&E Corporation's fmancing requirements for this ,acquisition were approximately $1.8 billion, funded through an aggregate of $1.3 billion PG&E Gen and USGenNE debt and a $425 million equity contribution from PG&ECorporation. The net purchase 'price haS been allocated as follows: (1) electric generating assets of $2.3 billion classified as property, plant, ançl equipment, (2) receivable for support payments of $0.8 billion, and (3) contractUal obligations of $1.3 billion classified as current liabilities and other noncurrent liabilities. The assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of 4,000 MW. In addition, USGenNE assumed 23 multi-year power purchase agreements representing an additional 800 MW of production capacity. USGenNE entered into agreements with , NEES as part of the acquisition, which (1)' provide that NEES shall make support payments over the next 9 years to USGenNE for the purchase power' agreements, and (2) reqùire that USGenNE provide electricity to certain of NEES affiliates under contracts that expire over the next 3 to 10 years. In December 1999, PG&E Corporation's Board of Directors approved a plan'to dispose of PG&E ES, its wholly . owned subsidiary, through a sale. As of December 31, 1999, the intended disposal has been accounted for as a discontinued operation. In connection with this transaction, PG&E Corporation's investment in PG&E ES was written down to its estimated net realizable value. In addition, PG&E Corporation provided a reserve for anticipated losses through the date of sale. The total provision for discontinued operations was $58 million, net of income taxes of $36 million. While there is no definite sales agreement, it is expected that the disposition.will be completed in, 2000. The amounts' that PG&E Corporation will ultimately realize from this disposal could be materially different from the amounts assumed in arriving at the estimated loss on disposal of the discontinued operations. The PG&E ES business segment generated net losses of $40 million (or $0.11 per share), $52 million (or $0.14 per share), and $29 million (or $0.07 per share), for the years ended December 31; 1999, 1998 and 1997, respectively. ' The total assets and liabilities, including the charge noted above, of PG&E ES induded in the PG&E Corporation Consolidated Balance Sheet at December 31, 1999 and 1998, are as follows: Balance at December 31, (in millions) 1999 1998 Assets Current assets $114 $148 Noncurrent assets 83 54 - - Total Assets ,$197 $202 liabilities Current liabilities $61 $72 Noncurrent liabilities 10 9 - To~ liabilities 71 81 - - Net assets 126 121 - , , On January 27, 2000, PG&E CorPoration's National Energy Group signed a defUÍitive agreemerit withEI Paso Field Services Company (El Paso) providing for the sale to EI Paso, a subsidiary of El Pas() Energy Corporation, of the stock of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. (collectively, PG&E GTD. The consideration to be received by the National Energy Group Includes $279 million in cash subject to a working capital adjustment, the assumption by EIPaso of debt having a book value of $624 million, and other liabilities associated with PG&E GTI. ' In 1999, PG&E Corporation recognized a charge against earnings.of $890 million after,.tax, or $2.42 per share, to reflect PG{?Æ GTI's assets at their fair market value. The composition of the pre-tax èharge is as follows: (I) an $819 million write down of net property, plant, and equipment, (2) the elimination of the Unamortized portion of goodwill, in the amount of $446 million, and (3) an accrual of $10 million representing selling costs. Proceeds from the sale will be used to, retire' short-term debt associated with PG&E GTI's operations and for other corporate purposes. Closing of the sale, whiCh is expected in the first half of 2000, is subject ,to approval under the Hart Scott Rodino Act. . 48 '. :t 'e _, . ' The sale of PG&E GTI represents disposal of the PG&E GTI business segment and a portion of the PG&E ET business segment. PG&E GTI's total assets' and liabilities, in:cluding the charge noted above, included in the PG&E Corporation Consolidated Balance Sheet at December 31, 1999 and 1998, are as follows: ·1 Balance at \ December 31, (in millions) 1999 1998 I Assets J $ $ 366 Current assets 229 Noncurrent assets 988 2,346 - Total Assets $1,217 $2,712 Liabilities Current liabilities $ 448 $ 486 Noncurrent liabilities 624 1,174 - Total liabilities 1,072 1,660 Net assets 145 1,052 Note 6: Common Stock PG&E Corporation PG&E Corporation has authorized 800 million shares of no-par common stock of which 384 million and 383 million shares were issued as of December 31, 1999 and 1998, respectively. During the years ended December 31, 1999 and 1998, PG&E Corporation repurchased $693 million and $1,158 million of its common stock, respectively. The repurchases in 1998 and through September 1999 were executed through separate, accelerated share repurchase programs. Under the 1999 agreement, PG&E Corporation repurchased in a specific transaction 16.6 million shares of its common stock at a cost of $502 million. In connection with this transaction, PG&E Corporation entered into a forward contract with an investment institution. PG&E Corporation settled the forward contract and its additional obligation of $29 million in September 1999, A wholly owned subsidiary of PG&E Corporation made this repurchase, along with subsequent stock repurchases. The stock held by the subsidiary is treated as treasury stock and reflected as stock held by subsidiary on the Consolidated Balance Sheet of PG&E Corporation. ' In October 1999, the Board of Directors of PG&E Corporation authorized an additional $500 million for the purþose of repurchasing shares of the Corporation's common stock on the open market. This aµthorization supplements the approximately $40 million remaining from the amount previously authorized by the Board of Directors on December 17, 1997. The authorization for share repurchase extends through September 30, 2001. As of December 31, 1999, a subsidiary of PG&E Corporation has repurchased 7.2 million shares at a cost of $159 million under this authorization. I Utility All of the Utility's outstanding common stock is held by PG&E Corporation and a subsidiary of the Utility. In ' connection with the formation of the holding company, all of the Utility's then-outstanding common stock was converted on a share-for-share basis to PG&E Corporation common stock. The Utility has authorized 800 million shares of $5 par value common stock of which 321 million and 341 million shares were issued as of December 31, 1999 and 1998, respeétivelr· Prior to December 1999, the Utility repurchased 20 million shares of its common stock from PG&E Corporation for an aggregate purchase price of $726 million to maintain its authorized capital structure. In December 1999, 7.6 million shares of the Utility's common stock, with an aggregate purchase price of $200 million, was purchased by a subsidiary of the Utility. This purchase is reflected as stock held by subsidiary in 'the Consolidated Balance , Sheet of Pacific Gas and Electric Company. The CPUC requires the 'Utility to maintain its CPUC-authorizedcapital structure, potentially limiting the amount of dividends the Utility may pay PG&E Corporation..In 1999, the Utility was in compliance with its ' CPUC-authorized capital structure. 49 I' _ e e Note 7: Preferred Stock and Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debentures Preferred Stock of Utility The Utility haS authorized 75 million shares of $25 par value preferred stock which may be issued as redeemable or nonredeemable preferred stock. At December 31, 1999 and 1998, the Utility had issued and outstanding 5,784,825 shares of nonredeemable preferred stock. At December 31, 1999 and 1998, the Utility had issued and outstanding 5,973,456 shares of redeemable preferred stock. The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends Ù1rough the redemption date. Annual dividends and redemption prices per share at December 31, 1999; range from $1.09 to $1.76 and from $25.75 to $27.25, respectively. In 1998, Ù1e Utility redeemed its Series 7.44% preferred stock wiÙ1 a face value of $65 million. Also in 1998, the Utility redeemed its Series 671s% preferred stock with a face value of $43 million.· , -. The Utility's redeemable preferred stock wiÙ1 måndatory redemption provisions consists of 3 million shares of the 6.57% series and 2.5 million shares of the 6.30% series at December 31, 1999. The 6.57% series and 6.30% series may be redeemed at the Utility's option beginning in 2002 and 2004, respectively, at par value plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of stock outstanding. Holders of the Utility's nonredeemable preferred stock 5%, 5.5%, and 6% series have rights to annual dividends per share ranging from $1.25 to $1.50. Dividends on all preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for Ù1e class and series; , Preferred Stock of the National Energy Group Preferred stock of the National Energy Group consists of $57 million of preferred stock issued by a subsidiary of PG&EGen. The prefer:red stock, WiÙ1 $100 par value, has a stated dividend of $3.35 per share, per quarter, and is redeemable when there is an excess of available cash, There were 549,594.shares outstanding at December 31, 1999 and 1998. Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility Subordinated Debenturè's ' , - The Utility, through its wholly owned subsidiary, PG&E Capital I, (Trust), has outstanding 12 million shar~ of 7;90% cumulative quarterly income preferred securities (QUIPS), with an aggregate liquidation value of $300 million. Concurrent with the issuanèe of the QUIPS, the Trust issued to the Utility 371,135 shares of common securities WiÙ1 an aggregate lkluidation value of $9 million. The Trust in turn used the net proceeds from the ' QUIPS offering and issuance of the common stock securities to purchase subordinated debentures issued by the Utility with a face value of $309 million, an interest rate of 7.9%, and a maturity date of 2025. These subordinated debentures are the only assets of the Trust. Proceeds from the sale of the subordinated debentures were used to redeem and repurchase higher-cost preferred stock: The Utility's guarantee of the QUIPS, considered together with the other obligations of the Utility with respect to Ù1e QUIPS, constitute~ a full and unconditional guarantee by the Utility of the Trust's.contractual'obligations under the QUIPS issued by Ù1e Trust. The subordinated debentures may be redeemed at the U~ility's option, ' beginning in 2000 at par value plus accrued interest through the redemption date. The proceeds of any redemption will be used by the Trust to redeem QUIPS in acq>rdance with their terms. Upon liquidation or dissolution of the Utility, holders of these QUIPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to' the date of payment. 50 , 't, .' e Note 8: Long-Term Debt Long-term debt at December 31, 1999 and 1998, consisted of the following: e (in millions) Utility long-term debt First and refunding mortgage bonds Maturity Interest rates 2000-2003 6.25% to 8.75% 2004-2008 5.875% to 6.25% 2009-2021 6,35% to 7.59% 2022-2026 5.85% to 8.80010 Principal amounts outstanding Unamortized discount net of premium Total mortgage bonds P.ollution control loan agreements, variable rates, due 2010-2026 Unsecured medium-term notes, 5.56% to 8.45%; Due 2000-2014 Other Utility long-term debt Total Utility long-term debt Current portion of long-term debt . Total Utility long-terin debt, net of current portion National Energy Group long-term debt First mortgage notes, 10.02% to 11.50010, due 2000-2009 Senior notes, Maturity Interest rates 1999 10.58% 2005 7.10% Medium-term notes, 6.61% to 9.25%, due 2000-2012 Senior debentures, 7.80%, due 2025 Amounts outstanding under credit facilities (See Note 10) Other long-term debt Total National Energy Group long-term debt Current portion of long-term debt, Total National Energy Group long-term debt, net of current portion Total long-term debt Balance at December 31, 1999 1998 $ 816 $ 969 600 615 160 160 2,004 2,117 , 3;580 3,861 (29) (32) 3,551 3,829 1,348 1,348 418 498 25 29 - - 5,342 5,704 465 260 - - 4,877 5,444 333 370 69 250 250 299 298 150 150 649 654 242 265 - - 1,923 2,056 127 78 - - 1,796 1,978 $6,673 $7,422 Utility First and Refunding Mortgage Bonds: First and refunding mortgage bonds are issued in series and bear annual interest rates ranging from 5.85 percent to 8,80 percent. All real properties and substantially all personal properties of the Utility are subject to ,the lien of theboncis, and the Utility is required to make semi-annual sinking fund payments for the retirement of the bonds. Additional bonds may be issued subject to CPUC approval, up to a maximum total amount outstanding of $10 billion, assuming compliance with indenture covenants for earnings coverage and aWlilable property balances as security. " The Utility redeemed or repurchased $281 million and $501 million of the bonds in 1999 and 1998, respectively, with interest rates ranging from 6.25 percent to 8,80 percent. These bonds were to mature from 2002 to 2026. Included in the total of outstanding bonds at December 31, 1999 and 1998, are $345 million of bonds held in trust for the California Pollution Control Financing Authority (CPCFA) with interest rates ranging from 5.85 percent I' II III' 51 '. e e to 6.625 percent and maturity dates ranging from 2009 to 2023. In addition to these bonds, the Utility holds long-term pollution control loan agreements with the CPCFA as described below. Pollution Control Loan Agreements: Pollution control loan agreements from the CPCFA totaled $1,348 million at December 31, 1999 and 1998: Interest rates on the loans vary with average annual interest rates. For 1999 the interest rates rangeçi from 2.36 pèrcent to 3.39 percent. These loans are subject to redemption by the holder under certain circumstances. These loans are secured primarily by irrevocable letters of credit which mature in 2000 through' 2003. National Energy Group Long-term debt of the National Energy Group consists of fIrst mortgage bonds and other secured and unsecured obligations. The first mortgage notes are comprised of three series due annually through 2009, and are secured by mortgages and security interests' in the natural gas transmission and natural gas processing facilities and other real and personal property of PG&E GTI, The mortgage indenture requires semi-annual payments with one-half of each interest payment and one-fourth of each annual principal payment escrowèd quarterly in advance. The mortgage indenture also contains covenants that restrict the ability of PG&E GTI to incur additional indebtedness and precludes cash distributions if certain cash flow coverages are not met. In January 2000, PG&E G1T obtained an amendment that provides PG&E GTI the ability to redeem in. whole or in part, its Mortgage Notes, including the premium set forth in the Mortgage Note Indenture,anytime after January 1, 2000. These notes will be ass\!med by the buyer of PG&E G1T (see Note 5). . Other long-term debt consists of project financing associated with unregulated generation facilities, premiums; and other loans. . , Repayment Schedule At December 31, 1999, PG&E Corporation's combined aggregateamourits of maturing long-term debt and sinking fund requirements, for the years 2000 through 2004, are $592 million, $480 million, $1,363 IÌúllion, $1,271 million; and $470 million, respectively. The Utility's share of those maturities and sinking fund requirements is $465 million, $374 million, $1,117 million, $664 million, and $392 million, respectively. Note 9: Rate Reduction Bonds In December 1997, PG&E Funding LLC (SPE), a special-purpose entity wholly owned by the Utility, issued $2.9 billion of rate reduction bonds to the California Infrastructure and Economic Development Bank Special Purpose Trust PG&E-1 (Trust), a special-purpose entity. The termS of the bonds generally mirror the terms of the pass-through certificates issued by the Trust. The proceeds of the rate reduction bonds were used by the SPE to purchase from the Utility the right, known as','transition property," to be paid a specified amount from a non-bypassable tariff levied on residential and small commercial customers which was authorized by the CPUC pursuant to state legislation. . The rate reduction bonds have maturities ranging from 6 months to 8 years, and bear interest at rates ranging from 6.15 percent to 6.48 percent. The bonds are secured solely by the transition property and there is no recourse to the Utility or PG&E Corporation. At December 31, 1999, $2.3 billion of rate, reduction bonds were outstanding. The combined expected principal payments on the rate reducti~n bonds Jor the years 2000 through 2004 are $290 million for each year. While the SPE is consolid<ited with the Utility for purposes of these fmancial statementS, the SPE is legally separate fromthe Utility. The assets of the SPE are not available to creditors of thè Utility or PG&E Corporation, and the transition property is not legally an asset of the Utility or PG&E Corporation. Note 10: Credit Facilities PG&E Corporation At December 31, 1999 and 1998, PG&E Corporation had borrowed $2,148 million and $2,298 million, respectively, under various credit facilities discussed below.' $649 million and $654 million of these borrowings at December 31, 1999 and 1998, respectively, are classified àslong-term,debt. (See Note 8.) The weighted average interest rate on the short-term borrowings was 5.4 percent and 5.6 percent for 1999 and 1998, respectively. ' 52 .1',. ., , .. e ,e PG&E Corporation maintains two $500 million revolving cr~dit facilities, one of which expires in November 2000 and the other in 2002. These credit facilities are used to support the commercial paper program and other liquidity needs. The facility expiring in 2000 may be extended annually for additional one-year periods upon agreement with the lending institutions. There was $450 million and $683 million of commercial paper outstanding at December31, 1999 and 1998, respectively. PG&E Corporation introduced a $200 million Extendible Commercial Note (ECN) program during the third quarter of 1999. The ECN program supplements our short-term borrowing capability. There was $76 million of ECNs outstandiÌ1g at December 31, 1999, which are not supported· by the credit facilities. , Utility The Utility maintains a $1 billion revolving credit facility which expires in 2002. The facility may be extended annually for additional one-year periods upon agreement with the banks. This facility is used to support the Utility's commercial paper program and other liquidity requirements. The total amount' outstanding at . December 31,1999, backed by this facility, was $449. million in commercial paper. The total amount outstanding at December 31, 1998, backed by this facility was $567 million in commercial paper and $101 million of bank notes. National Energy Group PG&E Gen maiÌ1tains two $550 million revolving credit facilities. One facility expires in August 2000 and the 'other expires in 2003. The amount outstanding at December 31, 1999 and 1998, backed by the facilities, was $898 million and $233 million, respectively in commercial paper. Also outstanding at December 31, 1998, was a $540 million eurodollar loan drawn on one of the revolving credit facilities, which was subsequently paid off in 1999. At D'ecember31, 1999 and 1998, $550 million of these loans is classified as noncurrent in the consolidated balance sheet. In 1998, USGenNE, a subsidiary of PG&E Gen, established a $100 million revolving credit facility that expires in 2003. No amounts were outstanding at December 31,1999. PG&E GT NW maintains a ,$100 million revolving credit facility that expires in 2002, but has an annual ' renewal option allowing the facility to maintain a three-year duration. PG&E GT NW also maintains a $50 million 364-day credit facility which, expires in 2000, bùt may be extended for successive 364-day periods. No amounts were outstanding under either of these credit facilities at December 31, 1999. At December 31, 1999 and 1998, PG&E GT NW had an outstanding commercial paper balance of $99 million and $104 million, re~pectively, which is classified as noncurrent in the Consolidated Balance Sheet of PG&E Corporation. PG&E GTI maintains four separate credit facilities that total $250 million and are guaranteed by PG&E Corporation. At December 31, 1999, PG&E GTI had $176 million of outstanding short-term bank borrowings related to these credit facilities. At December 31, 1998, PG&E GTI had $70 million of outstanding short-term bank borrowings related to two credit facilities. These lines may be cancelled upon demand and bear interest at each , respective bank's quoted mo~ey market rate. The borrowings are unsecured and unrestricted as to use. Note 11: Nuclear Decommissioning Decommissioning of the Utility's nuclear power plants is scheduled to begin for ratemaking purposes in 2015 with scheduled completion in 2034. Nuclear decommissioning means to safely remove nuclear facilities from service and reduce residual radioactivity to a level that pennits termination of the Nuclear Regulatory Commission license and release of the property for unrestricted use. The estimated total obligation for nuclear decommissioning éosts, based on a 1997 site study, is $1.6 billion in 1999 dollars (or $5.1 billion in future dollars). This estirnateassumes after-tax earnings on the tax-qualified and non-tax-qualified decommissioning funds of 6.34 percent and 5.39 percent, respectively, as' well as a future annual escalation rate of 5.5 percent for decommissioning costs. The decommissioning cost estimates are based on the plant location and ,cost characteristics for the Utility's nuclear plants. Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, and costs of labor, materials, and equipment. The estim~ted total obligation is being recognized proportionately over the license term of each facility. For the year ended December 31, 1999, nuclear decommissioning costs recovered in rates were $26.5 million. For the years ended December 31, 1998 ,and 1997, nuclear decommissioning costs recovered in rates were $~3 million þer year, respectively. The CPUC has established a Nuclear Decommissioning Cost Triennial 53 j e e Proceeding to review, every three years, updated decommissioI1ing cost estimates and to establish the annual trust contribution, absent general rate Cases. , At December 31, 1999, the total nuclear decommissioning obligation accrued was $1.3 billion and is included in. the balance sheet classification of accumulated' depreciátion and decommissioning. Decommissioning costs recovered in rates are placed in external trust funds. These funds along with accumulated earnings will be used exclusively for decommissioning and cannot be released from the ,trust funds until authorized by the CPuc. The following table provides a summary of fair value, based on quoted market prices, of these nuclear decommissioning funds: (in millions) u.s. government and agency issues Equity securities Municipal bonds and other Gross unrealized holding gains Gross unrealized holding losses Fair value (net of tax) Year Ended December 31, Maturity Dates 2000-2030 2000-2031 1999 $ 380 223 ·201 474 ~ $1,264 1998 $ 379 246 164 394 (11) ,- $1,172 - The proceeds received from sales of securities were $1.7 billion in 1999, and $1.4 billion in 1998 and 1997. The gross realized gains on sales of-securities heÌd as available-for-sale were $59 million, $52 million, and $40 million in 1999, 1998, and 1997, respectively. The gross realized losses on sales of securities held as available-for-sale were $60 million, $39 million, and $24 million in 1999, 1998, and 1997, respectively. The cost of debt and equity securities sold is detennined by specific identification: Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the . permanent storage and disposal of spent nuclear fuel. The Utility has signed a contract with the DOE to. provide for the disposal of spent nuclear fuel and high-level radioactive waste from the'Utility's nuclear powedacilities. The DOE's current~stimate for an available site to begin accepting physical possessiòn of the spent nuclear fuel is 2010. At the projected level of operation for Diablo Canyon, the Utility's faciliti~s are sufficient to store on-site all , , spent fuel produced through approximately 2006, It is likeÌy that' an interim or pe~eni DOE storage facility will not be availablè for Diablo Canyon's spent fuel by 2006. The Utility is examining options for providing additional temporary spent fuel storage at Diablo Canyon or other facil,i.tíes, pending dispòsal or storage at a DOE facility. Note 12: Employee Benefit Plans Several of PG&E Corporation's subsidiaries provide noncontributory defmed benefit pension plans for their employees and retirees. In addition, these subsidiaries provide contributory defmed benefit medi~l plans' for certain retired employees and theirdigible dependents and noncontributory dërmed benefit life insurance plans for certain retired employees (referred to collectively as otherbenefits). Forboth pension and otlÌer benefit plans, the Utility's plan represents substantially all of the plan assets and, the benefit obligation. 'rhèrefore, all descriptions and assumptions are based on the Utility's, plans. The schedules below aggregate all of the plans employed by PG&E Corporation's subsidiaries. ,'~ I . 54 '!, Thefollowing schedule recaes the plans' funded status (the differencatween fair value of plan assets and the benefit obligation) to~the prepaid or accrued benefit cost recorded on the consolidated balance sheet as of and for the years e~ded December 31, 1999 and 1998: Pension Benefits Other Benefits (in millions) 1999 1998 1999 1998 Change'in benefit obligation Benefit obligation at January 1 $(4,977) $(4,457) $ (949) $(907) Service cost for benefits earned (i2l) (108) (9) (9) Interest cost (347) (333) (69) (64) Actùarial gain (loss) 372 (321) (9) (36) Adopted plan benefits (4) Participant paid benefits (14) Benefits and expenses paid 266 242 104 77 - - - Benefit obligation at December 31 (4,807) (4,977) (970) (949) Change in plan assets , Fair value of plan assets at January 1 7,104 6,419 951 823 Actual return on plan assets 1,331 919 240 173 Company contributions 4 . 27 15 18 Participant paid, benefits 14 13 Benefits and expenses paid (286) (261) (03) (76) - Fair value of plan assets at December 31 8,153 7,104 1,117 951 Plan assets in excess of benefit obligation 3,346 2,127 147 2 (Benefit obligation in excess of plan assets) Unrecognized prior service cost 93 104 17 19 Unrecognized net loss (gain) (2,963) (2,025) (546) (430) Unrecognized net transition obligation 65 79 339 366 - Prepaid (accrued) benefit cOst $ 541 $ 285 $ (43) $ (43) The Utility's share of the plans' assets in excess of the benefit obligation for pensions in 1999 and 1998 was $3,344 million and $2,134 million, respectively. The Utility's share of the prepaid benefit cost for the pensions in 1999 and 1998 was $556 million and $301 million, respectively. The plan assets of the Utility exceeded its share of the benefit obligation for other benefits by $167 million and $24 million in 1999 and 1998, respectively. The Utility's share of the accrued benefit liability for other benefits in 1999 and 1998 was $22 million and $26 million, respectively. Unrecognized prior service costs and the net" gains are amortized on a straight-line basis over the average remaining service period of active plan participants. The transition obligations for pension benefits and other benefits are being amortized over 17.5years from 1987. Net benefit income (cost) was åS follows: Pension Benefits Other Benefits ~31, 1999 1998 1997 1999 1998 1997 (in millions) Service cost for benefits earned $(121) $(108) $(102) $(19) $(19) $(21) Interest cost (347) (333) , (316) (69) (64) (64) Expected return on assets 634 567 486 83 73 60 Amortized prior service and transition cost (25) (26) (22) (27) (28) (28) Actuarial gain recognized 111 114 74 20 22 13 - - - - - - Benefit income (cost) $ 252 $ 214 $ 120 $(12) $(16) $(40) The Utility's share of the net benefit income for pensions in 1999, 1998, and 1997 was $253 million, $215 million, and $123 million, respectively. 55 ·-' ,.- e ,_ The Utility's share of the net benefit cost for other benefits in 1999, 1998, and 1997 was $9 million, $12 million, and $38 million, respectively. Net benefit income (cost) is calculated using an expeCted long-tenp. rate of return on plan assets of 9.0 percent. The difference between actual and expected long-term rate of return on plan assets is included in net amortization and deferral and is considered in the determination of future net benefit income (cost). In 1999, 1998, and 1997, actual retu~ on plan assets exceeded expected return. In conformity with SFAS No. 71, regulatory adjustments have been recorded in the income statement and balance sheet of the Utility which reflect the difference between Utility pension income determined for accounting purposes and Utility pension income determined for ratemaking, which is based on a funding approach. The CPUC also has authorized the Utility to recover the costs associated with its other benefit plans for 1993 and beyond. Recovery is based on the lesser of the animal accounting costs or the annual contributions on a tax-deductible basis to the appropriate trusts. ' The following actuarial ass,umptions were used in determining the plans' funded status and net benefit income, (cost). Year~end assumptions are used to compute funded status, while prior year-end assumptions are used to compute net benefit income (cost). Pension Benefits Other Benefits December 31, 1999 1998 1997 1999 1998 . 1997 Discount rate 7.5% 7.0% 7.5%' 7.5% 7.0% 7.5% Average expected rate of future compensation increases 5.0% 5.00¡Ó 5.0% 5.00/0 5.0% 5.0% Exp.;;cted long-term rate of return on plan assets 8.5% 9.0% 9.00¡Ó 9.0% 9.0% 9.00¡Ó The assumed health care cost trend rate for 2000 is approximately 8.5 percent, grading down to an ultimate rate in 2006 of approximately 6.0 percent. The assumed health care cost trend rate can have a significant effect on the amounts reported for health care plans. A one percentage point change would have the following effects: (in millions) Effect on total service and interest cost components Effect on postretirement benefit obligation I:Percentage ' Point Increase '$ 6, $62 I-Percentage Point Decrease $ (6) $(57) I I' I Long-term Incentive Program PG&E Corporation mainfuins a Long-term Incentive Program (Program) that provides for grants of stock options to eligible particiþants with or without associated stock appreciation rights and dividend equivalents. As of December 31, 1999, 34,389,230 shares of PG&E Corporation common stock have been authorizedJor award with 15,779,821 shares still availableund~r this program. Shares granted in 1999, 1998 and 1997, had approximate, values of $23 million, $27 million, and $1~ million, res~Ctively, using the Black-Scholes valuation method. In addition, PG&E Corporation granted 9,712,900 shares on January 3, 2000 at an option price of $19.8125 and 18,000 shares on February 1, 2000 at an option price of $22.1875, the then-current market prices. . Outstanding stock options become exercisable on a cumulative basis at one-third each year commencing two years from the date of grant and expire ten years and one day after the date of grant. Shares outstanding at December 31, 1999, had option prices ranging from $16.75 to $34.25 and a weighted-average remaining contractual life of 7.8 years. As permitted under SFAS No. 123 "Accounting for Stock-Based Compensation," PG&E Corporation applies Accounting Board Opinion No. 25 in accounting for the program. As the exer<:ise price of all stock options 'are equal to their fair market value at the time the options .are granted, PG&E Corporation ' does not recognize any compensatiòn expense related to the program \jsing the intrinsit value based method. Had compensation expense been recognized using the fair value based method under SFAS No. 123, PG&E Corporation's consolidated earnings would have been reduced by $16 inillion, $10 million·and. $4 million in 1999, , 1998, and 1997, respectively. I I 56 '. ,. I The fOll~Wing table summa. the program's activity as of and for the. ended December 31, 1999, 1998 and 1997:' . ii' i: Ii :i 1999 . 1998 1997 Weighted Weighted Weighted Average Average Average Option Option Option (shares in millions) Shares Price Shares Price Shares Price Outstanding- beginning of year 11.1 $28.35 6.2 $26.21 3.5 $29.56 Granted during year 7.0 $30.94 6.4 $30.53 3.0 $22.55 Exercised during year (0.5) $25.86 (0.7) $29.63 (0.2) $27.36 Cancellations during year 0.2) $29.82 (0.8) $28.16 (0.1) $27.82 Outstanding-end of year 16.4 $29.43 11.1 $28.35 6.2 $26.21 Exercisable-end of year 3.0 $29.08 2.4 $29.06 1.9 $30.84 Note 13: Income Taxes I, The significant components of income tax expense for· continuing operations were: PG&E CÒrporation Utility Year ended December 31, 1999 1998 1997 1999 1998 1997, (in millions) Current $1,002 $718 $ 725 $1,133 $ 886 $ 791 Deferred (702) , (51) (19) (433) (201) (42) Tax credits, net (52) (56) (41) , (52) (56) (40) Income tax expense $ 248 $611 $ 565 $ 648 $ 629 $ 609 - In 1999, the income tax expense of PG&E Corporation was allocated to continuing operations ($248 million), discontinued operations ($71 million tax benefit), and cumulative effect of a change in an accounting principle ($8 million). ' The significant components of net deferred income tax liabilities were: December 31, (in millions) Deferred income tax assets: Customer advances for construction Unamortized investment tax credits Provision for injuries and damages, Deferred contract costs Other Total deferred income tax assets Deferred income tax liabilities: Regulatory balancing accounts Plant in service Income tax regulatory asset Other ' Total deferred income tax liabilities PG&E Corporation Utility 1999 1998 1999 1998 $ 109 $ 68 $ 109 $ 68 118 127 118 127 185 220 185 220 182 242 544 562 442 428 - - - - $1,138 $1,219 $ 854 $ 843 (47) 43 (47) 40 2,827 3,722 2,428 .2,930 297 391 287 381 1,075 968 577 555 - - - 4,152 . 5,124 3,245 3,906 $ 3,014 $3,905 $ 2,391 $3,063 $ (133) $ 44 $ (119) $ 3 '3,147 3,861 2,510 3,060 $3,014 $3,905 $ 2,391 $3,063 II ~II Total net deferred income taxes Classification of net deferred income taxes: Included in current (assets) liabilities Included in noncurrent liabilities Total net deferred income taxes Ii. I 57 " . e' .. . The differences between income taxes and amounts determined by applying ~ federal statutory rate to income before income' tax expense for continuing operations weré: Year ended December 31, Federal statutory income tax rate Increase (decrease) in income tax rate resulting from: State income tax (net 'of federal benefit) Effect of regulatory treatrÍlent of depreciation differences Tax credits--net ' Effect of foreign' earnings at different tax rates Stock sale differences Stock sale valuatiön allowance Other-net Effective tax rate PG&E Corpo~on Utility 1999 1998 1997 1999 1998 1997 35:0% 35.0%35.0% 35.0% 35.0% 35.0% 10.1 3.2 5.2 6.2 6.6 4.6 51.7 9.7 7.9 9.4 9.8 7.5 09.9) (4.0) (3.1) (3.6) (4.1) (2.9) (1.3) 0.6 (2.1) - (6.8) 30.2 , I (4.0) (0.3) 0.2 (1.9) (1.0) 95,0% 44.2% 43.1% 45.1% 46.3% 44.2% Historically, the benefits of certain temporary differences have been utilized to reduce the Utility's customers rates. Accordingly, a regulatory asset has been recorded reflecting the pre-tax amount that will be recovered from customers as the temporary difference reverses. In connection with the California electric restructuring plan, the Utility is collecting the regulatory asset over four years. During 1999, PG&E Corporation generated a capital loss carryfOlward of approximately $225 million, which will expire in 2005. Avaluation allowance of approximately $75 million has been recorded reflecting the estimated net realizable value of this capital loss carryforward. Note 14: Commitments, Utility Letters of Credit and Surety Bonds: The Utility uses $409 million in standby letters of credit and surety bonds. to secure future workers' compensation liabilities. ' Restructuring Trust Guarantees: TaX-exempt restructuring trusts were established to oversee the development of the operatirtg framework for the competitive generation market in California. (See Note 2.) The CPUC has a~thorized California utilities to guarantee bank loans of up to $85 million to be \lsed by the trusts for this purpose. Under the CPUC authorization, the Utility's re~ining guarantee is for up to a maximum of $38 million of the loan. The remaining bank loan will be repaid and the guarantee removed when the trust· obtains proceeds from permanent financing or rate recovery. , Power Purchase Contracts: By federal law, the Utility is required to purchase electric energy and capacity provided by independent power producers that are qualifying facilities (QFs) under the Public Utilities Regulatory Poliçies Act of 1978 (PURPA). ,The ~PUC established a series of QF long-term power purchase ,contracts and set the applicable terms, . conditions, price options, and eligibility requirements. Under. these contracts, the Utility is required to make payments' only when energy is supplied or when capacity commitments are met. Costs associated with these éontracts are eligible ~or recovery by the Utility as transition costs through the collection of the nonbypassable' ere. The Utility's contracts with these power producers expire on various dates through 2028. Deliveries from these power producers account for approximqtely 23 percent of the Utility's 1999 electric ,energy, requirèments, and no single contract accounted for more than five percent of the Utility's energy needs. ' . ' The Utility has negotiated with several QFs for early termination of thei~ power purchase contracts. For other contracts, the Utility has negotiated with QFs to refrain fròmproducing energy during the remaining term of the ' higher fixed energy price period under their contract (a "buy-down") or to curtail energy production for shorter periods of time (a "curtailment"). At December 31, 1999, the total discounted future payments due under the renegotiated contracts that are subject to early termination, buy-down, or curtailment was $16 million, of which " ,I 58 ~-------- r., ~ I: e e $6.6 million has been recovered in rates and the Utility expects to recover the remaining $9.4 nùllion in future rates. II The Utility also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contràcts, the Utility must make specified' semi-annual minimum payments whether or not any energy is supplied (subject to the supplier's retention of the FERC's authorization) and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. Costs associated with these contracts to purchase power are eligible for recovery by the Utility as transition costs through the collection of the nonbypassable crc. At pecember 31, 1999, the undiscounted future minimum payments under these contracts were $32,7 nlillion for each of the years 2000 through 2004 and a total of $247 nùllion for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 5.8 percent of the Utility's 1999 electric energy requirements. The amount of energy received and the total, payments made under all of these power purchase contracts were: I I! (in millioos) Kilowatt-hours received Energy payments . Capacity payments Irrigation district and water agency payments Year ended December 31, 1999 1998 1997 25,910 $837 $539 $ 60 25,994 $943 $529 $ 53 24,389 $1,157 $ 538 $ 56 Natural Gas Transportation Commitments: The Utility has long-term gas transportation service contracts with various Canadian and interstate pipeline companies. . These agreements include provisions for payment of fIxed demand charges for reserving fIrm capacity on the pipelines. The total démand charges that the Utility will pay each, year may change due to changes in tariff rates. The total demand and volumetric transportation charges the Utility paid under these agreements were $97 nùllion, $113 million, and $255 million in 1999, 1998, and 1997, respectively. These amounts include payments made by the Utility to PG&E GT NW of $47 million, $49 million, and $49 million in, 1999, 1998, and 1997, respectively, which are eliminated in the consolidated financial statements of PG&E Corporation. The Utility's obligations related to capacity held pursuant to long-term contracts on various pipelines are as follows: ' (in millioos) 2000 2001 2002 2003 2004 Thereafter Total $100 97 78 78 78 98 $529 As a result of regulatory changes, the Utility no longer procures gas for most of its industrial and larger commercial (noncore) customers, resulting in a decrease in the Utility's need for capacity on these pipelines. Despite these changes, the Utility continues to procure gas for substantially all of its residential and smaller commercial (core) customers and its noncore customers who choose bundled service. To the extent that the Utility's current capacity holdings exceed demand for gas transportation by its customers, the Utility will continue its efforts to broker such excess capacity. National Energy Group Power Purchase Contracts: ' As a part of the acquisition of a portfolio of electric generating assets and power supply contracts from NEES (see Note 5), NEES transferred to PG&E Gen contractual rights and duties under several power purchase contracts with third-party independent power producers. At December 31, 1999, these agreements provided for an aggregate Ii I 59 '~i. _-! e e of 470 MW of capacity. Under the transfer agreement, PG&E Gen is required to, pay to NEES amounts due to the ' third-party power producers under the power purchase contracts. PG&E Gen's payment obligations to NEES àre reduced by NEES's montWy payment obligation, payable in monthly installments from September 1998,through January 2008. In certain circumstances" NEES, with the consent of PG&E Gen, will make a full or partial lump-sum accelerated payment of the monthly payment obligation to such party às PG&E Gen may direct. The approximate dollar amounts under these agreements àre as follows: ' " (in millions) 2000 2001 2002 2003 2004 Thereafter Total Power PurdJase support . Contract Payments $ 233 $)19 228 120 215 121 217 112 220 108 1,804 334 - $2,917 $914 Gas Supply and Transportation Agreements: , PG&E Gen is obligàted to purchase and fuel suppliers ,are required to sùpply all the fuel needed at PG&E Gen's facilities, Fuel requirements include the quality and estimated quantity of fuel needed to operate each facility. The price of fuel escalates annually for the term of each contract. In addition, PG&E Gen has transportation contracts with various entities to deliver the fuel to eaçhfacility. The approximáte'dollarobligations under these gas supply and transportation agreements are as follows: (in millions) 2000 2001 2002 ,2003 2004 Thereafter Total $ 103 , 101 101 ' 102 11 848 51,266 -, standard Offer Agreements: As a part of the acquisition of a portfolio of electric generating assets and power supply contracts from NEES (see Note 5), PG&E Gen entered into agreements to supply the electric capacity and energy 'necessary for certain ' of NEES aff1liates to meet their obligations to provide standard offer service. The agreements'to provide standard offer service range in length from 3 to '10 years. The price per MWh is standard for all agreements.' For the year ended December 31, 1999, the standard offer service price paid generators was $0.035 per Kwh for generation, Operating Leases: PG&E Corporation and the National Energy Group have entered into various long-term lease commitments. PG&E Gen has an agreement to lease Lake Road under a five-year operàting lease agreement which is extendible. The lease term will commence upon the completion of the <::onstruction of a gas-fired generating facility, which is anticipated to be mid-200l. The minimum obligations under this leaseéannot be determined until the commencement of the lease because the minimum rent payments are based on 'the final cost to complete the facility. The approximate obligations below are based on the current estimated total cost of -the facility. USGenNE entered into a $479 m!llion sale-and-Ieaseback transaction whereby USGen!\TE sold and leased back its Bear Swamp facility to a third party. The related lease is being accounted for as an operating lease. The rental expense under this lease in 1999 was $2 million. . PG&E Gen leases the Pittsfield facility from General Electric Credit Corporation. The rental expense for this facility in 1999 was $28 million. 60 '~ ~ P' G&E GTI h . _1 - . '. .' '. ·th e Th f th ' as an' operatmg ease comrmtment m connection WI gas storage. e term 0 e gas storage facility lease and related arrangements run through January 2008 and subject to certain conditions, has one or more optional renewal periods of five years each at fair market value. The rental expense for this gas storage facility in 1999 was approximately $10 million. PG&E 'Corporation and our National Energy Group have leases for office space primarily located in California, Maryland, Oregon, Massachusetts, and Texas. For the year ended December 31, 1999, rent expense for these facilities amounted to $27 million. The approximate obligations under these operating lease agreements are as' follows: (in millions) 2000 2001 2002 2003 2004 Thereafter Total $ 96 110 116 109 124 1,266 $1,821 . I :-! Note 15: Contingencies Nuclear Insurance The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Irisurance Limited (NEIL). Under this insurance, if a nuclear generating facility suffers a loss due to . a prolonged accidental outage, the Utility may be subject to maximum retrospective assessments of $15 million (property damage) and $4 million (business interruption), in each case per policy period, in the event losses exceed the resources of NEIL. The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident, The Utility has secondary financial 'protection which provides an additional $9.3 billion in coverage, which is mandated by federal legislation. It provides for loss sharing among utilities owning nuclear generating facilities if a cosdy incident occurs. If a rlUclear incident results in claims in excess of $200 million, then the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation The Utility may be required to pay for environmental remediation at sites where it has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by it for the storage or disposal of potentially hazardous materials. Under federal and California laws, it may be responsible for remediation of hazardous substances, even if it did not deposit those substances on the site. . The Utility records a liability when site assessments indicate remediation is probable and a rànge of reasonably likely clean-up costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) current technology" (2) .enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and. financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the lower end of this range. The cost of the. hazardous substance remediation ultimatelý undertaken by the Utility is difficult to estimate, A charige in estimate may occurin the near teÌm due to uncertainty concerning the Utility's responsibility, the èomplexity of environmental laws and regulations, and the selection of compliance alternatives. At December 31, 1999, the Utility expects to spend $300 million for hazardous waste remediation costs at identified sites: including Ii 61 ~ divested fossil-fueled po;"er Plan~e UtiHty had an ~ccrued liability of $27t ton and $296 million at December 31, 1999 and 1998, respectively, representing the discounted value of these costs. Of the $271 million accrued liability discussed above, the Utility has recovered $148 million through rates, including $34 million through depreciatioh, and expects to recover another $95 million in future rates. Additionally, the,Utility is mitigating its costs by obtaining recovery of its costs from insurance carriers and from" . other third, parties as appropriate. Environmental remediation at identified sites' may be as much as $486 million if, among other things, other" potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary rèmediation is greater than anticipated. The Utility estimated this upper limit of the range of costs using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for clean-up costs at additional sites or outcomes change. Further, as discussed in "Generation Divestiture" above, the Utility will retain the pre-closing remediation liability associated with divested generation facilities. . , PG&E Corporation believes the ultimate outcome of these matters will not have a material impact on its or the Utility's fInancial position or results of operations. Legal Matters Chromium Litigation: Several civil suits are pending against the Utility in Califòrnia state court. The suits seek an ul;1Specified amount of compensatory and punitive damages for alleged personal injuries resulting from alleged exposure to chromium in the vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and Topock, California. . Currently" there are claims pending on behalf of approximately 900 individuals. The Utility is responding to the suits and asserting aff1fIllittive defenses. The Utility will pursue appropriate legal defenses, including statute of limitations or exclusivity of workers' compensation laws, and factual defènses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. PG&E Corporation believes that the ultimate outcome of these matters will not have a material adverse impact on its or thé Utility's fInancial position or results' of operations. Texas Franchise I'ee Litigation: In connection with PG&E Corporation's acquisition of Valero Energy CorpOration, now known as PG&E Gas Transmission Texas (PG&E GTI), PG&E GTI succeeded to the litigation described,below. PG&E GTI and various of its affilia,tes are defendants in at least two class action suits and fIve separate suits filed by various Texas cities. Generally, these cities allege, among other things, that (1) owners or operators of pipelines occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities, and (2) the gas' marketers failed to pay the cities for accessing and utilizing the pipelines located in: the cities to flow gas under city streets. Plaintiffs also allege various other claims against the defendants for failure to secure the cities' consent. Damages are not quantified. In 1998, a jury trial was held in' the separate suit brought by the City, of Edinburg ( the City). This suit involved, among other things, a particular franchise agreement entered into by a fonner subsidiary of PG&E GTI (now owned by Southern Union Gas Company (SU)) and the City and certain conduct of the defendants. On December 1, 1998, based on the jury verdict, the court' entered a judgment in the City's' favor, and awarded damages of $5.3 million, and attorneys' fees of up to $3.5 million plus interest. The court. found that various PG&E GTI and SU d~fendants were jointly and severally liable for $3.3 million of the damages and all the attorneys' fees. Certain PG&E GTI subsidiaries were found solely liable for $1:4 million of the damages. The court did not clearly indicate the extent to which the PG&E GTI defendants could be found liabie for the remaìning damages. The PG&E GTI defendants are in the process of appealing the judgment. . In connection with the certification of a class in one of. the class actions, the court ordered notice to be sent to all potential class members and setting a~ opt-put deadline of December 31, 1997. Notices were mailed to ' 'approximately 159 Texas cities. Fewer than 20 cities opted out by the deadline. In ,November 1999, the court signed an order dismissing from the class 42 cities because it determined there was no pipeline presence and no 62 ...·T~,' .. --~- '. ".,. e e past or present sales activity, leaving 106 cities in the class. The parties in this class action are negotiating the terms of a settlement agreement. The settlement proposal contemplàtes, among other things, that the PG&E Corporation defendants would pay $12.2 million to the class cities, inclusive of attorney fees, reduced by amounts attributable to opt -out cities. The defendànts retain the right to reject the settlement if the settlement proposal is not appr9ved by certain key cities and by 8()oh of the plaintiff class. Although a significant number of the 106 cities in the plairitiff class already have either approved the settlement or adopted resolutions to pass the ordinance, certain key cities have not yet approved the settlement. The settlement is also subject to court approval. On January 27,2000, the court approved the settlement proposal and established a 144y period whether to accept the negotiated settlement terms or opt out of the settlement. The Court also stated that if Corpus Christi does not accept the settlement proposål, it will be placed in a sub-dass, whose claims will not be fInalized as part of the settlement approval. Corpus Christi has the right to opt out of this subclass. ' PG&E Corporation believes that the ul~te outcome of these matters will not have a material adverse impact on its fInancial position or its results of operatiqns. As discussed above in Note 5; in January 2000, PG&E Corporation's National' Energy Group signed a defìnitive agreement to sell the stock of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. The buyer will assume all liabilities associå.ted with the cases described above. Recorded Uability for Legal Matters: In accordance with SFAS No.5, PG&E Corporation makes a provision for a liability when both it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the 'impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. In the fourth quarter of 1999, PG&E Corporation reduced the amount of the recorded liability for legal matters associated with a court approved settlement proposal and other settlement discussions of certain matters described above. Approximately $55 million of the adjustments, arising from a pre-acquisition contingency related to a purchased business, are reflected in "Other income, net" in PG&E Corporation's Statement of Consolidàted Income. The following table reflects the current year's activity to the recorded liability for legal matters: . (in millions) Beginning Balance, January 1, 1999 Provisions for liabilities Payments Adjustments Ending Balance, December 31, 1999: PG&E Corporation Utility $175 $ 52 16 14 (41) (29) (44) 13 - $106 $ 50 Note 16: General Rate Case In December 1997, the Utility filed its 1999 application with the CPUC During the GRC process, the CPUC examines the Utility's costs to determine the amount the Utility may charge customers for base revenues (non-fuel related costs). The Utility requested distribution revenue increases to maintain and improve natural gas and electric distribution reliability, safety, and customer service. The requested revenues, as updàted, included an increase of $445 million in electric base revenues and an increase of $377 million in natural gas base revenues over the 1998 authorized revenues. The Utility received a fInal decision on its 1999 GRC application on February 17, 2000. This fmal decision increased electric distribution revenues by $163 million and gas distribution revenues by $93 million, as compared to revenues authorized for 1998. This revenue increase is retroactive to January 1, 1999. The impact of these increases resulted in an increase , in earnings of $153 million, or $0.42 per share, and was reflected in the fourth quarter of 1999. I ¡'I I: ,I Note 17: Segment Information PG&E Corporation has identified four reportable operating segments. The Utility is one reportable operating segment and the other three are part of PG&E Corporation's National Energy Group. These four reportable operating segments provide different products and seivices and are subject to different forms of regulation or jurisdictions. PG&E Corporation's reportable segments are described below. . 63 ç-- ,.- Utility: , PG&E Corporation's Northern and Central California enèrgy utility subsidiary, Pacific Gas and Electric Company, provides naturalgas and electric service to. one ,of every 20 Amencans. . e National Energy Group: The National Energy Group businesses develop, conStruct, 'operat~, own, and manage independent power generation facilities that serve wholesale and industrial customers through PG&E Generating Company, liC (formerly u.s. Generating Company,liC) and its afflliates (collectively, PG&E Gen);. own and operate natural gas pipelines, natural gas storage facilities, and natural gas processing plants, primarily in the 'Pacific Northwest and in Texas, through various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission or PG&E GT); and purchase and sell energy commodities and provide risk management services to customers in major North American markets, including the other National Energy Group non-utility businesses, unafflliated utilities, marketers, municipalities, and large end-use customers through, PG&E Energy Trading-Gas Corporation, PG&E Energy Trading-Power, L.P., and their aff1liates (collectively; PG&E Energy Trading or PG&E ET). In the fourth quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the divesti~re of PG&E Corporation's Texas natural gas and natural gas liquids business. Also in the fourth quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the divestiture of PG&E Corporation's retail energy services, conducted through' PG&E ES. PG&E ES had total assets of $197 million, $202 million, and $60'million, as ,of Decémber 31, 1999, 1998, and 1997, respectively. I ! . I 64 ..-~' . !I , e .' ,'. e Segment information for the years 1999, 1998, and 1997 was as follows: utility National Energy Group PG&:E GT EJioünations &: (in mfmoaS) PG8cE Gen NW TeXas PG&E ET Other Total 1999 Operating revenues $ 9,084 $1,116 $ 172 $1,034 $9,404 $ 10 $20,820 Intersegment revenues(l) 144 6 52 114 1,-117 (1,433) -- Total operating revenues 9,228 1,122 224 1,148 19,521 (1,423) 20,820 Depreciation, amortization and decommissioning 1,564 89 41 75 9 2 1,780 Interest expensé2) . (593) , (63) (41) (59) (12) (4) (772) Other income (expense) 11 61 21 53 3 6 155 Income taxesG) 648 16 32 (407) (36) (5) 248 Income from continuing operations 763 97 68 (897) (34) 16 13 Capital expenditures 1,181 323 30 19 14 1,567 Total assets at year-end(4) $21,470 $3,852 $1,160 $1,217 $1,876 $ (57) $29,518 1998 oPerating revenues $ 8,919 $ 645 $ 185 $1,640 $8,183 $ 5 $19,577 Intersegment revenues(l) 5 4 ~~ 326 (688) - Total operating, revenues 8,924 649 237 1,941 8,509 (683) 19,577 Depreciation, amortization and decommissioning 1,438 52 39 65 5 3 1,602 Interest expense(2) (621) (43) (43) (77) (7) 10 (781) Other income (expense) 76 18 3 13 5 (50) 65 'Income taxesG) 629 28 31 (47) (17) (13) 611 Income Go~) from continuing operations 702 106 65 (71) (6) (25) 771 Capital expenditures 1,396 98 49 39 12 1 1,595 Total assets at year-end(4) $22,950 $3,844 $1,169 '$2,655 $2,555 $ (141) $33,032 1997 Operating revenues $ 9,495 $ 148 $ 186 $ ,800 $4,613 $ 13 $15,255 Intersegment revenues(l) 47 204 195 ( 446) -- Total operating revenues 9,495 148 233 1,004 4,808 (433) 15,255 Depreciation, amortization and decommissioning 1,748 19 38 33 3 10 1,851 Interest expense(2) (570) -(5) (41) (26) (2) (20) (664) Other income (expense) 94 (25) 1 13 3 126 212 Income taxesG) 609 (17) 26 (8) (12) (33) 565 Income Goss) from continuing operations 735 (41) 40 (24) (19) 54 745 Capital expenditures 1,529 23 34 45 5 50 1,686 Total assets at year-end(4) $25,147 $ 989 $1,208 $2,800 $1,452 $ (541) $31,055 (1) Intersegment electric and gas revenueS are recorded at market prices, which for the Utility and PG&E GT NW, are tariffed rates prescribed by the CPUC and FERC, respectively. (2) Net interest expense incurred by PG&E Corporation is allocated to the segments using .specific identification. (3) Income tax expense for the Utility is computed on a stand-alone basis. The balance of the consolidated " income tax provision is allocated among the National Energy Group. !! (4) Assets of PG&E Corporation are iricluded in "Eliminations & Other" column exclusive of investment in its subsidiaries. (5) Income from equity-method investees for 1999, 1998, and 1997 was $61 million, $113 million, and $41 million, respectively, for PG&E Gen; and none, $3 million, and $2 million, respectively, for PG&E GTI. 65 'I I ,~ - Note 18: Fair Value of Financial Instruments PG&E Corporationestimatès fàirvalue of its fmancial instruments based on quoted market prices, where available. Fåirvalue of the Ut¥.jty'siå,t,eiecluction. bonc:.ls, and Utility obligated manditorily redeemable preferred. . securities of trust holding solely Utility subordinated debentures are all determined based ,on quoted market þIjce~¡. , Fair value of the Utility's preferred stock with inandatoryprovisions is based ()n indicative market prices. Where quoted or indicative' market prices are not available, the estimated fair válue is determined using other valúation techniques (for example, the present value of future cash flows). Most of PG&E Corporation's and the Utility's debt is determined us'ing quoted market prices, but the fàir value of a small portion of Utility debt is determined using. the present value of future cash flows. The carrying value of PG&E Corporation's short-tenn borrowings approximates fair value. At December 31,1999 and 1998, PG&E Corporation's carrying amount and ending fair value <;>f itsfmancial instruments are: e , (in mil1ions) . PG&E Corporation: Current price risk management assets (see Note 3) Noncurrent price risk management assets (see Note 3) Current price risk management liabilities (see Note 3) Noncurrent price risk management liabilities (see Note 3) Totallong-tenn debt(1) (see Note 8) , Utility: Nuclear deco~~ioniÌ1g funds noncurrent asset (see Note 11) Totallong-tenn debtCl) (see Note 8) Rate reduction bonds(2) (see Note 9) , Preferred stock with mandatory redemption provisions (see Note 7) Utility obligated mandatorily redeemàble preferred securities of trust holding solely Utility subordinated debenturès (see Note 7) , . (1) Totallong-tenn debt includes current portion of long-tenn debt. (2) Rate reductio~ bonds includecurrent portion of rate reduction bonds. 1999 1998 Carrying Fair ' Carrying Fair Amount Value Amount Value $ 607 $ 607 $1,416 $1,416 372 372 334 334 575 575 1,412 1,412 247 247 281 281 7,265 7,095 - 7,760 8,079 1,264 1,264 1,172' 1,172 5,342 5,217 5,704 6,008, 2,321 2,265 2,611 2,676 . 137· . 140 137 143 300 267 300 303 .) II .1 ,i 66 ---:::::::;;;;¡; ft, ~ e e Quarterly Consolidate~Financial Data (Unaudited)" Quarter ended (in millions. except per share amounts) December 31 September 30 June 30 March 31 $4,795 $6,217 $4,682 $5,126 .(579)' 516 ' 480 461 (547) 197 1% 167 (611) 185 182 171 (1.49) 0.54 0.53 0.45 (1.49) 0.54 0.50 0.39 0.30 0.30 0.30, 0.30 26.69 33.25 34.00", 33.69 20.25 25.00 30.56 29.50 $2,323 $2,587 ' $2;233 $2,085 633 486 452 422 272 185 178 .' 153 265 179 172 147 $5,364 $5,208 $4,695 $4,310 485 554 579 .480 208 225 188 150 196 210 174 139 0.54 0.59 0.49 0.39 0.30 0.30 0.30 0.30 35.06 33.44 33.19 33.56 '30.38 19.88 30.06 29.06 $2,218 $2,563 $2,117 $2,026 446 512 494 424 176 205 193 ' 155 169 199 186 148 1999 PG&E Corporation Operating revenues Operating income OOSS)(lX2)(3) Income Ooss) from continuing operations Net income (loSS)(lX2)(3) Earnings Ooss) per co~ôn share from continuing operations, basic Earnings (loss) per common share from continuing operations, dil1.lted . , Dividends declared per cornmon share Cornmon stock price per share High Low Utility Operating revenues Operating income(3) Net inconieC3} Income available for cornmon stock 1998 PG&E Corporation Operating revenues Operating income(l)' Income from continuing operations Net income(l) , Earnings per common share from continuing operations, basic and diluted Dividends declared per common share Cornmon stock price per share High Low Utility Operating revenues Operating income Net income Income available for common stock Ii (1) In the fourth quarter 1999, the National Energy Group adopted a plan to dispose of the PG&E ES segment. 'This planned transaction has been accounted for as a discontinued operation. Results of operations of PG&E ES have been excluded from continuing operations for all periods presented. The operating loss and net loss of PG&E ES for the quarters ending March 31, June 30, and September 30, 1999, were $15 million and $8 million, $23 million and $14 million, and $20 million and $12 million, respectively. The operating loss and net loss for PG&E ES for the quarters ending March 31, June 30, and September 30, 1998, were $17 million and $11 million, $22 million and $14 million, and $27 million and $15 million, respectively. ' (2) Amounts have been restated to reflect the change in accounting for major maintenance and overhauls at the National Energy Group (see Note 1 of the Notes to Consolidated Financial Statements), ånd reclassification of PG&E ES operating results to discontinued operations (see above). The accounting change resulted in a cumulative effect being recorded as of January 1, 1999, of $12 million ($0.03 per share), net of income taxes of $8 million. Operating income previously reported for 1999 was $442 million, $454 million, and $492 million for each of the fIrst three quarters, respectively. Net income previously reported for 1999 was$156 million ($0.42 per share), $180 million ($0.49 per share), and $183 million ($0.50 per share) for the same periods.' ß) In the fourth quarter 1999, the Utility recorded the effects of the outcome of the GRC. This resulted in an increase of $256 million in operating income and an increase of $153 million in net income. Additionally, the National Energy Group recorded an after-tax charge of $890 million reflecting PG&E GIT's assets at their fair market value. (See Notes 5 and 16 of the Notes to Consolidated Financial Statements.) 67 ,~ :" e e , ' INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of PG&E Corporation and Pacific Gas and Electric Company We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries and of Pacific Gas and Electric Company and subsidiaries as of December 31, 1999, and the related statements of consolidated income, cash flows, and common stock equity of PG&E'Corporation and the related statements,of consolidated income, cash flows, and stockholders' equity of Pacific' Gas and Electric Company for the year then ,ended. These fmancial statements, are the responsibility of,managem~nt of PG&E Corporation and of Pacific Gas' and Electric Company. Our responsibility is~ to :express an opinion on these fmancial statementS based on our audits. The c0Ì1S0lidatedfinancial statements for the years ended'December 31, 1998 and 1997 were audited by other auditors whose report, dated February 8, 1999, expressed an unqualified opiniòn on those statements. We conducted our audits in accordance' with generally accepted auditing standards. Those standards require that we plan and perfonn the audits to obtain reasonable assurance about whether the fmancial statements are free of material misstatement. An audit includes examining, 'On a test basis, evidence supporting the amounts and disclosures in the ftruincial statements. AD. audit also includes assessing' the, accounting principles used and, significant estimates made by management, as well as evaluating the overall fmancial statement presentation. We , believe'that our ,audits provide a reasonable basis for our opinion. In our opinion, such 1999 fInancial statementS present fairly, in all material respects, the cons~lidated fmancial position of PG&ECorporation and Pacific Gas and Electric Company as of December 31, 1999, and the results of their consolidated operations and cash, flows for the year then ended in conformity, with generally accepted accounting principles. As discussed in Note 1 of the Notes to Consolidated Financial Statements; in, 1999 PG&E Corporation changed its method of accounting for màjor maintenance and overhauls cost. ' I , I DELOITfE & TOUCHE Il.P San Francisco, California March 3, 2000 , . 68 , --,. "-t", ~ - e RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS At both PG&E Corporation and Pacific Gas and Electric Company (the Utility) management is responsible for the, integrity of the accompanying consolidated fmancial statements. These statements have been prepared in accordance with generally accepted accounting pririèiples. Management considers materiality and uses its, best judgment to ensure that such statements reflect fairly the fmancial position, results of operations, and cash flows' of ,PG&E Corporation and the Utility. PG&E Corporation and the Utility maintain systems of internal controls supported by formal policies and procedures which are communicated throughoutPG&E Corporation and the Utility. These controls are adequate to provide reasonable assurance t:h.at assets are safeguarded from material loss or unauthorized use and that necessary records are produced for the preparation of consolidated fmancial statements. There are limits inherent in all systems of internal controls, based on recpgnition that the costS of such systems should' not exceed the benefits to be derived. PG&E Corporation and the Utility believe that their systems of internal control provide this appropriate balance. PG&E Corporation management also maintains a staff of internal auditors who evaluate the adequacy of, and assess the adherence to, these controls, policies, and procedures for all of PG&E Corporation, including the Utility. Both PG&E Corporation's and the Utility's 1999 consolidated financial statements have been audited by Deloitte $L Touche LLP, PG&E Corporation's independent auditors: The, audit includes consideration of internal accounting controls and performance of tests necessary to support an opinion. The auditors' report contains an independent informed judgment as to the fairness, in all material respects, of reported results of operations and fmancial position. . Thè Audit Committee of the Board of Directors for ÞG&E Corporation meets regularly with management, internal auditors, and Deloine & Touche, jointly and separately, to review internal accounting controls and auditing and fmancial reporting matters. The internal auditors and Deloitte & Touche LLP have free access to the Audit Committèe, which consists of five outside directors. The Audit Committee has reviewed the fmancial data contained in this report. , PG&E Corporation and the Utility are committed to full compliance with all laws and regulations and to conducting business in accordance with high standards of ethical conduct. Management has taken the steps necessary to ensure that all employees and other agents understand and support this commitment. Guidance for corporate compliance and ethics is provided by an officers' Ethics Committee and by a Legal, Compliance and .Business Ethics organization. PG&E Corporation and the Utility believe that these efforts provide reasonable assurance that each of their operations is conducted in conformity with applicable laws and with their commitment to ethical conduct. 69 '! e - Boards of Directors of '. PG&E C.orp«;»ration, and , Pacific Gas 'and Electric Company(1) ", Richard .A. Clarke Chairman of the Board, Retired, Pacific Gas and Electric Company . Harry M. COnger ' Chairman of the Board and Chief Executiv.e' Officer, Emeritus, Homestake Mining Company David .A. Coulter Partner, Beacon Group, L.P. C. Lee Cox " Vice Chairman, Retired, AirTouch Communications, Inc. and President and Chief Executive Officer, Retired, AirTouch Cellular William S. Davila President Emeritus, The Vons Companies, Inc. (retail grocety) Robert J). Glynn, Jr. , Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation and Chairman of the Board, . Pacific Gas and Electric Company David M. Lawrence, MD ChairInan and Chief Executive Officer, Kaiser Foundation Health Plan, Inc. and Kaiser Foundation Hospitals . . Richard B. Madden(2) Chairman of the Board and Chief ,Executive' Officer, Retired, Podatch CorporatioI1 (diversified forest products) Mary S. Metz President, S. H. Cowell Foundation Rebecca Q. Morgan(2) , President and Chief Executive Officer, Retired, Joint Venture: Silicon Valley Network (nonprofit collaborative addressing critical issues facing Silicon Valley) . Carl E. Reichardt Chairman of the Board'and Chief Executive Officer, Retired, Wells Fargo & Company and Wells ,Fargo Bank, N,A. John C. Sawhill . President and Chief Executive Officer, The Nature Conservancy (international environmental organization) Gordon R. Smith(l) President and Chief Executive Officer, Pacific Gas and Electric Company Barry Lawson wmiam~ President, Williams Pacific Ventures, Inc. (business consulting and mediation) (1) . The composition of the Boards of Directors is the same, except that Gordon R. Smith is a director of the Pacific Gas and Electric Company Board of Directors only. ' (2) Retired as a direçtor of PG&E Corporation and Pacific Gas and Electric Company on Februaty 16, 2000. 70 . ·~t , - e Permanent Committees of PG&E Corporation and Pacific Gas and Electric . Cornpany(1) Executive Committees Within limits, may exercise powers and perform duties of the Boards. Robert ,D. Glynn, Jr., Chair Hany M. Conger Mary S. Metz Carl E. Reichardt Gordon R. Smith(l) Bany Lawson Williams Audit Committee Reviews fmancial statements and internal audit and control procedures with independent public accountants. Hany M. Conger, Chair C. Lee Cox William S. Davila Mary S. Metz Bany Lawson Williams Finance Committee Reviews long-term financial and capital investment policies and objectives, and actions required to achieve those objectives. Bany Lawson Williams, Chair Richard A. Clarke David A. Coulter Carl E. Reichardt John C. Sawhill Nominating and Compensation Committee ' Recommends candidates for nomination as direCtors, recommends compensation and employee benefit policies and practices, and reviews planning for executive development and succession. CarlE. Reichardt, Chair David A. Coulter C. Lee Cox David M. Lawrence, MD John C. Sawhill Public Policy Committee· Reviews public policy issues which could significantly affect customers, shareholders, employees, or the ' communities served, and recommends plans and programs to address such issues, Mary S. Metz, Chair Richard A. Clarke William S. Davila John C. Sawhill (1) The committee membership shown is effective February 16, 2000. Except for the Executive Committee, all committees listed above are committees of the PG&E Corporation Board of Directors. The Execµtive Committees of the PG&E Corporation and Pacific Gas and Electric Company Boards have the samè members, except that Gordon R. Smith is a member of the Pacific Gas and Electric Company Executive Committee only. 71 '1 -- e Officers PG&E Corporation Robert D. Glynn, Jr. Chairman of the Board, Chief Executive Officer, and President Thomas G. Boren Executive Vice President Peter A. Darbee Senior Vice President, Chief Financial Officer, and Treasurer Tony F. DiStefano Senior Vice President Scott w. Gebhardt Senior Vice President Thomas W. High Senior Vice President, Administration and EXternal Relations P. Chrisman Iribe' Senior Vice President Thomas B. King Senior Vice President L E. Maddox Senior Vice President Gordon R. Smith Senior Vice President G. Brent Stanley ~enior Vice President, Human Resources Bruce R. worthington Senior Vice President and General Counsel Leslie H. Everett Vice President and Corporate Secretary Christopher P. Johns Vice President and Controller Steven L Kline Vice President, Federal Governmental and Regulatory Relations Jacka1yne Píannenstiel Vice President, CorPOrate Initiatives Greg S. Pruett Vice President, Corporate Communications .. Daniel D. Richard, Jr. Vice President, Governmental Relations 72 - --- - ----=-=~ .~~ " I, M. Richard Smith Vice President, Corporate Development - ·tt National Energy Group Thomas G. Boren President ~nd Chief Executive Officer Scott W. Gebhardt President and Chief Executive Officer, PG&E Energy SelVices P. Chrisman Iribe President and Chief Operating Officer, PG&E Generating I I; , " Thomas B. King President and Chief Operating Officer, PG&E Gas Transmission L E. Maddox President and Chief Executivè Officer, PG&E Energy Trading Pacific Gas and Electric Company i:> Gordon R. Smith President and Chief Executive Officer Kent M. Harvey , Senior Vice President, Chief Financial Officer, Controller, and Treasurer Roger J. Peters Senior Vice President and General Counsel James K. Randolph Senior Vice President and General Manager, Transmission, Distribution, and Customer SelVice Business Unit Daniel D. Richard, Jr. Senior Vice President, Public Affairs Gregory M. Rueger Senior Vice President and General Manager, Nuclear Power Generation Business Unit Russell M. Jackson Vice President, Human Resources 73 I ,I ! ,,' _. - Shareholder Information For f111ancial and other information aboutPG&E Corporation and Pacific Gas and Electric Company, please visit our websites, www.pgecorp.com and www.pge.com. ' . ' If you have questions about your PG&ECorporation common stock accoµnt or Pacific Gas and Electric Company preferred stock account, or need copies of PG&E Corporation's or Pacific Gas and Electric Company's publicationS, please write or call ChaseMellon Shareholder Services: ChaseMellon Shareholder Services P.O. Box 3310 (Securities Transfer) P.O. Box 3315 (General Correspondence) P.O. Box 3316 (Change of Address) P.O. Box 3317 (Lost Certificate Replacement) P.O. Box 3338 (Dividen.d Reinvestment) South Hackensack, NJ 076<?6 , Toll-free Telephone Services: 1.800.719.9056 Website: www.chasemellon.com If you have general questions about PG&E Corporation or Pacific Gas and Electric Company, please write or call the Vice President and Corporate Secretary's Office: Vice President and Corporate Secretary Leslie, H. Everett PG&E Corporation P.O. Box 193722 San Francisco, CA 94119-3722 415.2{$7.7070 Fax 415.267.7268 Securities analysts, portfolio managers, or other 'representatives of the investment community should write or call the Investor Relations Office:, Manager of Investor Relations Jamie Fenton PG&E Corporatlòn One Market, Spear Tower, Suite 2400 San Francisco, CA 94105 415.267.7080 Fax 415,267.7265 PG&E CorpOration General Information 415.267.7000 Pacific Gas and Electric Company . General Infonnation 415.973;7000 74 '!; ! ' , Stock Exchange listings PG&E Corporation'~common, stock is traded on,th~ New Y()rk, Pacific, ancl swiss stock exchanges. The official New York Stock ExGhange sYJI1QoI is "PCG" ,but PG&E Corporation commonstock is listed 41 daily ne,wspapers under "PG&E" or "PG&E Cp."(l) e 'e Pacific Gas and Electric Company has 11 issues of preferred stock, and one preferred security; all of which ~e listed on ',the American and Pacific stock exchanges. Issue , First Preferred, Cumulative, Par Value $25 Per Share Redeemable: 7.04% 6.57% 6.30% 5.00% 5.000/Ó Series A 4.80% 4.50% 4.36% Non-Redeemable: 6.00% 5.50% 5.000/Ó Cumulative Quarterly Income Preferred Securities: 7.90% Series A Newspaper SymbolU>' PacGE pfU PacGE pfY PacGE pfZ PacGE pfD PacGE pfE PacGE pfG PacGE pfH PacGE pfI PacGE pfA PacGE pfB PacGE pfC PG&E Cap pfA 2000 Dividend Payment Dates PG&E Corporation Common Stock Pacific Gas and Electric Company Preferred Stock February 15 May 15 August 15 November 15 January 15 April 15 July 15 October 15 Stock Held in Brokerage Accounts ("Street Name") When you purchasè your stock and it is held for you by your broker, the shares are listed with ChaseMellon Shareholder Services in the broker's name, or "street name." ChaseMellon Shareholder Services does not know the identity of the individual shareholders who hold their shares in this manner-they simply know that a broker holds a number of shares which may be held for any number of investors. If you hold your stock in a street name account, you receive all dividend payments, tax forms, publications, and proxy materials through your broker. If you are receiving unwanted duplicate mailings, you should contact your broker to eliminate; the duplications. PG&E Corporation Dividend Reinvestment Plan If you hold PG&E Corporation or Pacific Gas and Electric Company stock in your own name, rather than through a broker, you may automatically reinvest dividend payments from common and/or preferred stock in shares of PG&E Corporation common stock through the Dividend Reinvestment Plan (the "Plan"). You may obtain a Plan prospectus and enroll by contacting ChaseMellon Shareholder Services. If your certificates are held by a broker (in . '~street name"), you are not eligible to participate in the Plan. (1) Local newspaper symbols may vary. I I 75 ,~' e· e I I Direct Deposit of Dividends If you hold stock in your own name, rather than through a broker, you may have your common and/or preferred dividends transmitted to your bank electronically. You may obtaiIi a direct deposit authorization form by contacting ChaseMellon Shareholder ServiceS. Replacement of Dividend Checks' If you hold stock in your own name and do not receive your dividend check within seven business days after the payment date, or if a check is lost or destroyed, you should notify ChaseMellon Shareholder Services so that payment can be stopped on the check and a replacement mailed. Lost or Stolen Stock Certificates If yo~ hold stock in your own name and your stock certificate has been lost, stolen, or in some way destroyed, you should notify ChaseMellon Shareholder Services immediately. PG&E Corporation Pacific Gas and Electric Company Annual Meetings of Shareholders Date: April 19, 2000 Time: 10:00 a.m. Location: Four Seasons Hotel-Boston 200 Boylston Street Boston, Massachusetts A joint notice of the annual meetings, joint proxy statement, and proxy fonn are being mailed with this annual report on or about March 13, 2000, to all shareholders of record as of February 22, 2000. lO-K Report If you would like a copy of the 1999 Fonn 1Q-K Report to Ø1e Securities and Exchange Commission, please contact the Office of the Vice President and COIporate Secretary, or visit oúr websites, 'WWW.pgecorp.com and .WWW.pge.com. 76 ·'.... SECue:IES AND EXCHANGE COMMISS4Þ Washington, D.C. 20549 FORM lO-K (Mark One) !81 o ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31,1999 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ,Commission File Number Exact Name of Registrant as specified in its charter State of Incorporation IRS Employer' Identification Number 1-12609 1-2348 PG&E CORPÒRA TION California PACIFIC'GAS AND ELECTRIC COMPANY California Pacific Gas and Electric Company PG&E Corporation 77 Beale Street One Market, Spear Tower P.O. Box 770000 Suite 2400 San Francisco, California San Francisco, California (Address of principal executive offices) (Address of principal executive offices) 94177 94105 (Zip Code) (Zip Code) (415) 973-7000 (415) 267-7000 (Registrant's telephone number, including area code) (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Which Registered 94-3234914 94-0742640 II' Title of Each Class PG&E Corporation Common Stock, no par value New York Stock Exchange and Pacific Exchange Pacific Gas and Electric Company First Preferred Stock, cumulative, par value $25 per share: , Redeemable: 7.04%,5% Series A, 5%~ 4.80%, 4.50%; 4.36% Mandatorily Redeemable: 6.57%, 6.30% Nonredeemable: 6%, 5.50%, 5% 7.90% Cumulative Quarterly Income Preferred Securities, Series A (liquidation preference $25), issued qy PG&E Capital I and guaranteed by Pacific Gas and Electric Company Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15( d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. . Yes ~ No 0 Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form lO-K or any amendment to this Form 1O-K. 0 ' Aggregate market value of the voting stock held,by non-affiliates of the registrant as of February 22, 2000: PG&E Corporation Common Stock $8,095 million Pacific Gas' and Electric Company First Preferred Stock $331 million Common StOCk outstanding as of February 22, 2000: ' PG&E CorPoration: 384,825,799 Pacific Gas and Electric Company: Wholly owned by PG&E Corporation The market values of certain series of First Preferred Stock, for which market prices as of a date within 60 days prior to the date of filing were not available, were derived by dividing the annual dividend rate of each such series ofstoc¡C by the average yield of all of Pacific Gas and Electriè Company's Preferred Stock outstanding for which market prices were available. DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. , (1) Designated portions of the combined Annual Report to Shareholders for the year ended December 31, 1999. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . American Stock Exchange and Pacific Exchange American Stock Exchange and Pacific Exchange ' Part I (Item 1), part II (Items 5, 6, 7, 7 A, and 8) Part IV (Item 14) (2) Designated portions of the Joint Proxy Statement relating to the 2000 Annual Meetings of Shareholders. . . . . . . . . . . . . . . . . . . . . . . . . ; . . , . . Part III (Items 10, 11, 12, and 13) ," e e -.. Item 1. e e TABLE OF CONTENTS Pag~ Glossary of Terms. . . . ; . . . . . . . . . . . . . . .. . . .', . . . : . . . . . . . . . . , , . . . . . . . . . . . . . . . . iii PART I Business , , ............................................................................................................................ .. GENERAL . . .. . . . . . . . , . . . . . . . . . . .. . . . . ... . . . . . . , .. . . . . . . . . . . . . . . . . . . . . . . . Corpo~ate Structure and Business . . . . . . . . . . . . . : . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , Competition and the Changing Regulatory Environment . .. . . . . . . . . . . . . . . . . . . . . . . . . . . Regulation of PG&E Corporation . . . . . . : .'. . . . . , . . . . . . . . . . . . . . , . . . . . . . . . . . . . .. . . Regulation of Pacific Gas and Electric Company, . , . . . . . . ~ . . . . . . . . . . . .. . . . . . . : . . . . . ,State Regulation. , . . . . . . . . . . . . . . . . . " . . . . : . . . . . . . . . . . . . . . , , . . . . . . . . . . . . . . . Federal Regulation , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . 'Licenses and Permits .'. . . . . . . . . . . . . . . . . . . . . . .~. . . . . . . . . . . . . , ',' , . . . . . . . . . . . . Regulation of the National Energy Group . . . . . . . . . . . . . . . . . . " . . , . . . . . . . . . . . . . . . . . . Risk Management Programs, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . .'. . . . . . . . . . . . . . UTILITY OPERATIONS. . , . . .. . . . . . , . : , . . . . . : . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ratemaking Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . ',' . . . . . . . , . . . . . . . . . . . . . . . . Electric Ratemaking . . . ',' . . . . . . . . . . . . . . . . : . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . Gas Ratemaking . . . . . . . . . . . . . . . .'. . . . . . . . . . . . . .'. . . . . . . . . . . . . . . . . . . . . . . . . . . Electric Utility Operations . . . . . . . . . . . . .. . . . . ',: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . California Electric Industry Restructuring . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . The California Independent System Operator and the California PO'wer Exchange . . . . . . . Voluntary Generation Asset Divestiture. . . . . .'. . . . . . : . . .. . . , . , , . . , . . . . . . . . . . . . Recovery of Transition Costs .......... '. . , . . . . . .. . . . . . . . . , . . . . .. . . . . . . . . . . Retail DirectAccess . . . . . . . . . . . . . . . . . . . . . . . . , . . . .. . . . . . , . , . . . : . . '. . . . . . . . Rate Levels and Rate Reduction Bonds . . . . . . . . . . . . . . . . .. . .. . . . . . . . . . . . . . . . . . Public Purpose Programs ..........................:...............:..... Distributed Generation and Electric Distribution Competition. . . . ... . . . . . . . . . . . . . . . Electric Operating Statistics . . . . . . . . . . . . . . . . .. .'. . . . . '. . . . . . . . . . . . . . . . . . . . . . . . . . Electric Generating Capacity .............:. , . . . . . . . . . . . . . . . , , . . . . . . . . . . . . . . . . Diablo Canyon ....,........................,...........,..................... Diablo Canyon Operátions . . .. . . . . . . . . . . . . . ',' . . . . . . . . . . .. . , . , . . . . . . . . . . . . . . Diablo Canyon Raiemaking .... . . . . . . . . . . : , . . . . . . . . . . . . . . , , . . . . . . . . . . . . . . . '. Nuclear Fuel Supply and Disposal ........................................... Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . '. . . . . . . . . . . . . . . . . . . . . . . . . . . Decommissioning ..............................,......"................. Other Electric Resources .. . . . . . . . . . . . . . . .'. . . . . . . . . . . . .'. . .. . . . . . . . . . . . . . . . . . . QF Generation and Other Power Purchase Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Electric Transmission and Distribution . . . . . . . . . . . . . . . .'. . . . . . . . , , , . . . . . . . . . . . . . . . Gas Utility Operations . . , . . . . . . . .. . . , . . . . . . . . , . . . . . . , . . . . . . , , . . . . . . . . . . . . . . . Gas Operating Statistics. . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . Natural Gas Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ~ . , . . . . . . , . . . . . ',' . . . . . . . . Gas Regulatory Framework . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . , '. . . . . . . . . . . . .. . . Transportation Commitments. .-. . . . . . : , . . .. . . . . . . . . . . . . . . . . . . , . . . , . . . . . . . . . . . . Core Procurement Incentive Mechanism. . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . , NATIONAL ENERGY GROUP. . . . . . ., . . . . . . . . . , . . . . . . . . .. . , . . . . . . . . . . . . . . . . . Gas Transmission Operations . . . . . . . .- . . . . . . . . . . . . . . . . . . . . . . . , . , . . . . . . . . . . . . . '. . 1 1 2 3 4 4 4 4 4 5 7 7 8 11, 12 12 12 13 14 14 15 15 15 16 17 18 18 19 19 20 20 21 21 22 23 24 25 25 26 27 28 28 I I, Item 2. Item 3. Item 4. Item 5, Item 6. Item 7. Item 7 A. Item 8. Item 9. Item 10. Item 11. Item 12. Item 13. e - - .~ Page 28 29 30 30 31. 32 32 33 34 34 34 34 35 36 , I 37 I 38 I 38 I 38 39 I 39 ' 39 I 40 42 43 46 46 46 46 46 47 47 47 47 47 PART IV 'Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. . . . : . : . . ~ . ... . . . . . . . 48 Signatures. . . : . . . . . . . . . . . . . . . . . . . . . . . . . . '. . . . . . . . . . . . . . . . . .'. . . . . . . . . . . . ." . 52 lridependent Auditors' Report (Deloitte & Touche LLP) . . . . . . . . . , . . . . . . . . . . . .. . . . , . 53 Independent Auditors' Report (Arthur Andersen LLP) ................... ... . . . . . . . 54 Report of Independent Pùblic Accountants (Arthur Andersen LLP) . . . . . . . . . . . . . . . . . . . .' 55 TABLE OF CONTENTS-(Continued) PG&E Gas Transmission, Texas. . . .. . . . . . . . . . . .- . . . . . . . . . . . . . .. : . . . . .. . . . . . . PG&E GT -Northwest ............... '. . . :. . . . .... . . . . . .'~ . . . . '," . . .'. . . . . . . . Independent Power Generation ..............................:,.............. New England Operations. . . . . . . . . . . . . . . . . ',' . . . . . . . . . . . . . . . ",' .. .. . . . . . . . . Portfolio of Operating Generating Plants .. '. . . . . . . . . . . ., . . . . . . . . . . . .. , . . . .. . . . . . Generation Development Projects.,. . . , . . . . . . . . . . . . . . . . . '. . . . . . . . . . .". . . . '. . . . . . Energy Trading. . . . . . . . . . . ',' ~ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . '. . . . . . . . : . . . . Energy Services ................,. '. . . .'. .- . . . . . . . . . . . . . . " . . . . . . . . . . . .'. . . . . . . ENVIRONMENTAL MAITERS ....' ','" ,.................. .,... .,........... 'Environmental'Matters .........'........,....... ..,. . . . . . . . . ... . '. . . . . . . .. . . . . . Environmental Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... . . . . . . ',' . . . _Air Quality: . . . . . . . . . . . . . . . . . . . . . . . . . . .'. . . . . . . . . ... . . . . . . . . . ò . . . . . . . . . . Water Quality . . . . . . .' . . . . . . .'. . . . . . . . '. . . . . . . " . . . . . . .'. . . . . . . . . . ". . ',' '. . . . . . Hazardous Waste Compliance ând Remediation. . . . . . . . . . . . . . . . . . . . . . . . . '. . . . . .. Potential Recovery of Hazardous Waste Compliance and Remediation Costs, . . . . . . . . . . Compressor Station Litigation. . .. . .. '. . . . . . . . . , . . . . . . . . . .. . . , .. . . . . : . . . . . . . , Electric and Magnetic Fields .. . . . . . . . . . ... . .' . .. . . . . . . . . . . . . . .. . . . . . . . . . ., . . Low Emission Vehicle Programs.. . : . . . . . . .. . . . . . . . . . . . . . . . .... . .. . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . '. . . . . . : . . . . . . . . . . . Legal ,Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . ',' . . . ',: . . . . . . Compressor Station Chromium Litigation. . . . . . . . . . . . . . . .. .'. . . . . .. . . . . . . . . . . . . . . Texas Franchise Fee Litigation ... ò. . . . . '. . . . . . . . ò . . . . . .. . . . . : .. . . . . . . . . . . : . . . Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . . . . . . . . .. . . EXECUTIVE OFFICERS OF THE REGISTRANTS.............................. PART II Market for the Registrant's Common Equity and Related Stockholder Matters .. . . . . . . . . . . Selected Financial Data. . . . . . . . . . . . .. . . . ò . . .. . . . . . ',' . . . . . . . . : . . . . . . . . . . . . . . Management's Discussion and Analysis of Financial Condition and Results of Operations . . . Quantitative and Qualitative Disclosures About Market Risk. . " . . . . . . . . . . . .. . . . . .. . . . Financial Statements and Supplementary pata . .'. . . . . . . . . . . . . . . . . . . . . . .: . . ... . . . . , Changes in and Qisagreements with Accountants on Accoimting,and, Financial Disclosure. . . PART III Directors and Executive Officers of the Registrant .. . . . . . . . . . . . . . . . . . . .. :. . . . . . . . . Executive Compensation. . . . . . : . .. '. . : .. . . . . . . . . . . . .. . . . . . " . . . .. . . . . . .-. . .'. . . Security Ownership of Certain Beneficial Owners and Manag<::ment ................... Certain Relationships and Related Transactions .,.. .,.'.. ..... ......:....., .,'........... II r. ," - AB 1890. . . .. . . . .. . . . . . . . . AEAP ................... ATCP................... . BCAP ............ .'...... bcf..................... . BRPU .. ..;.. ........'.... B'TA..... ....... .:.. '" ..: Btu..................... . CARE ...................., CCAA .....,.............. CEC..., ....'. ..... ..'....: CEMA .............:.....' , , Central Coast Board .. . . . . . . . CERCLA . . . . . . . .. . . . . . . . . core customers . . . . . . . . .. : . . core subscription customers. . . . CPIM................. .'.. CPUC ................... ·CTC...:................ . Diablo Canyon . . . . . . . . . . . . . DOE .........;.......... DSM ......,.............. EDRA .............:.'.... El Paso, . , . . . . . . . . . . . . . . . . EMF .................:.. EPA.............. .'. .-'....' ERCA . .,..... ..... ....... FERC...............;... . Gås Accord. . . . . . . . " . . . . . . Geysers ..:............... ORC .........,.....:.... Holding Company Act ....... Humboldt, . .. . . . . . . . :' . . . . . HWRC.........,.......... ICIP.................... . IPP..................... . ISO. .,.'.................. kY............ ..... ..... kYa ..,.-................. kW.. :.,.................. kWh.... ..... ........ ...., LEy,.... .....'... ..... .... Mcf.................... . MDt.... ..'............... MMcf.... ..... .... ....... MMcf/d . . . .. . . . . . . . .'. . . . . MW..............'....... MWh.,...:.............-... NEES................... . NEIL .................... . GLOSSARY OF TERMS Assembly Bill 1890, the California electric industry restructuring legislation Annual Earnings Assessment Proceeding Annual Transition Cost Proceeding Biennial Cost Allocation Proceeding billion cubic feet Biennial Resource Plan Update best technology available British thermal unit California Alternate Rates for Energy California Clean Air Act California Energy Commission Catastrophic Event Memorandum Account Central Coast Regional Water Quality Control Board . Comprehensive Environmental Response, Compensation, and Liability Act residential and smaller commercial gas customers noncore customers who choose bundled service core procurement incentive mechanism California Public Utilities Commission competition transition charge Diablo Canyon Nuclear Power Plant United States DepartÌnent of Energy demand side management Electric Deferred Refund Account EI Paso Natural Gas Company electric and magnetic fields United States Environmental Protection Agency Electric Restructuring Costs Account Federal Energy Regulatory Commission Gas Accord Settlement The Geysers Power Plant General Rate Case Public Utility Holding Company Act of 1935 Humboldt Bay Power Plant ' hazardous waste remediation costs Incremental Cost Incentive Price Independent power producer Independent System Operator kilovolts kilovolt-amperes kilowatts kilowatt-hour low emission vehicle thousand cubic feet thousand decatherms . m,illion cubic feet million cubic feet per day megawatts megawatt-hour New England Electric System Nuclear Electric Insurance Limited Ul NGL ...................'. noncore customers .......... NOx.,................... . NRC ............ ......... 'Nuclear Waste Act. . . . . . . . .. ORA ..........,... ...... PBR.... .'................ PG&E Expansion .. , . . . . . . , . PG&E ET . . . . . . . . . . . . . . . . . PG&E ES . . . . . . . . . . . . . . . . . PG&E Gen. . . .'. . . . . . .'. . . . . PG&E GT ......,......... PG&E GT-Northwest . . . . . . . . PG&E GT NW'Expansion . . . . . I' PG&E GTT ..... . . . . . . . . . . . PG&EOSC ....,.......... Pipèline Expansion . . . : . . . . . . PPPs .................... PRP.. .'...... .,.,......... PURP A ............:-..... PX.............;..... .'.. QF..... ..:..:.... ,. .'.... RAP.... ............ ..... RRC... .... ...... ........ SEC............. .'....... ' SOS.................... . Teco................. '.... TCBA '. ............ .'..... TRA.............:...... . Transwestern .............. USGenNE ......:...,..... Utility ................... Valero ................... . 'e GLOSSARY OF TERMS-(Continued) natural gas liquids industrial and larger commèrcial g~s customers oxides of nitrogen Nuclear Regulatory C'ommission Nuclear Waste Policy Act of 1982 Office of Ratepayer, Advocates, a division of the California Public Utilities Commission perfonnance-based ratemaking . the Pacific Gas and Electric Company portion of the Pipeline Expansiòn PG&E Corporàtion's energy commodities activities, J:>G&E Energy Trading or PG&E ET PG&E Corporation's energy services operations, PG&E Energy Services or PG&E ES PG&E Generating Company, LLC and its affiliates PG&E Corporation's gas tr!insmission operations, PG&E Gas Transmission or PG&E GT PG&E Gas Transmission, Northwest Corporation fonnerly.lmown as ,Pacific Gas Transmission Company PG&E Gas Transmission, Northw~st C~tporation's portion of the Pipeline Expansion ' PG&E Gas Transmission, Texas Corporation PG&E Opèrating Services Company PG&E GT NWIPG&E Pipèline Expansion public purpose programs' . potentially responsible party. Public Utility Regulatory Policies Act of 1978 California Power Exchange ,qualifying facility ,Revenue Adjustment Proceeding , The Railroad Commission of Texas Securities and Exchange Commission Standard Offer Service . Teco Pipeline Company Transition Cost Balancing Account Transition Revenue Account Transwestern Pipeline Company US Gen New England, Inc. Pacific Gas arid Electric Company and it subsidiaries Valero Energy Corporation IV ~ j, I '!, .~ - e PART I f ITEM 1. Business. ,GENERAL Corporate Structure and Business PG&E 'Corporation is an energy-based holding company headquartered in San' Francisco, California. Effective January 1, 1997, Pacific Gas and Electric Company (sometimes referred to herein as the "Utility") and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility engaged principally in' the business of providing electricity and natural gas distribution and transmission services throughout most of Northern and Central California. The Utility is primarily regulated by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). In the holding company reorganization, Pacific Gas and Electrié, Company's outstanding common stock was converted on a share-for-share basis into PG&E Corporation common stock. Pacific Gas and Electric Company's debt securities and preferred stock were unaffected and remain securities of Pacific Gas and Electric Company. The consolidated financial statements of PG&E Corporation incorporated herein include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries (collectively, PG&E Corporation). The consolidated financial statements of Pacific Gas and Electric Company incorporated herein include the accounts of Pacific GaS and Electric Company and its wholly owned and controlled subsidiaries. The principal executive offices of PG&ECorporation are located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive offices of Pacific Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. In addition to the regulated utility business of Pacific Gas and Electric Company, PG&E Corporation's National Energy Group provides energy products and services throughout North America. The National Energy Group businesses develop, construct, operate, own, and manage independent power generation facilities that serve wholesale and industrial customers through PG&E Generating Company, LLC (formerly U.S. Generating Company, LLC) and its affiliates (collectively, PG&E Gen); own and operate natural gas pipelines, natural. gas storage facilities, and natural gas processing plants, primarily in the Pacific Northwest and Texas, through various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission or PG&E GT); purchase and sell energy commodities and provide, risk management services to customers in major North American markets, including the National Energy Group's non-utility businesses, unaffiliated utilities, marketers, municipalities, and large end-use customers through PG&E Energy Trading-Gas Corporation, PG&E Energy Trading-Power, L.P., and their affiliates (collectively, PG&E Energy Trading or PG&E ET); and provide competitively priced electricity, natural gas, and related services to industrial, commercial, and institutional customers through PG&E Energy Services Corporation (PG&E Energy Services or PG&E ES). In the fourth, quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the divestiture of PG&E Corporation's Texas natural gas and natural gas liquids business. Also in the fourth quarter of 1999, ·PG&E Corporation's Board of Directors approved a plan for the divestiture of PG&E Corporation's retail energy services. See "National Energy Group- Gas Transmission Operations" and "National Energy Group-Energy Services" below. As of December 31, 1999, PG&E Corporation had $29.7 billion in assets. PG~E Corporation generated $20.8 billion in operating revenues for 1999. As of December 31, 1999, PG&E Corporation and its subsidiaries and affiliates had 22,433 employees. As of December 31, 1999, Pacific Gas and Electric Company had $21.4 billion in assets. The Utility generated $9.2 billion in operating revenues for 1999. As of December 31, 1999, the Utility had 18,935 employees. The gas and electric utility operations of Pacific Gas and Electric Company represent the largest component of PG&E Corporation's business, contributing 44% of PG&E Corporation's total revenues in 1999. ~, ;,.' e - PG&E Corporation has identified four reportable operating segments. The Utility is one reportable operating segment and the other three are part of PG&E Corporation's National Energy Group (PG&E Gen, PG&E GT, and PG&E ET). Financial information about each reportable operating segment is provided in "Management's. Discussion and Analysis" in the 1999 Annual Report to Shareholders and in Note 17 of the "Notes to Consolidated Financial Statements" beginning on page 63 of PG&E Corporation's 1999, Annual Report to Shareholders, portions of which are filed as Exhibit 13 to this report. The following report includes forward-looking statements about the future that involve a number of risks and uncertainties. These statements are based on assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as""estimates," "expects, " "anticipates," "plans," "believes, "andother similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements. Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results; some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements include: the pace and extent of the ongoing restructuring of the electric and natural gas industries across the United States; operational changes related to industry restfucturing, including changes to the Utility's business processes and systems; the method and timing of disposition and valuation of the Utility's hydroelectric generation assets; the timing of the completion of the Utility's transition cost recovery and the consequent end of the current electric rate freeze in California; any changes in the àmount the Utility is allowed· to collect (recover) from its customers for certain costs which prove to be uneconomic under the new competitive market (called transition costs); future operating performance at the Utility~s Diablo Canyon Nuclear Power Plant (Diablo Canyon); the method adopted by the CPUC for sharing the· net benefits of operating Diablo Canyon with ratepayers' and the timing of, the implementation of the adopted method; the extent of' anticipated groWth of transmission and distribution services in the Utility's·service territory; future market prices for electricity; future fuel prices; the success of management's strategies to maximize shareholder value in PG&E Corporation's National Energy Group which may include acquisitions or dispositions of assets or internal restructuring; the extent to which current or planned generation development projects are completed and the pace and cost of such completion; generating capacity expansion and retirements by others; tlÌe successful i~tegration and performance of acquired assets; the outcome of the Utility's various regulatory proceedings; including the the proposal to auction the Utility's hydroelectric generation assets, the electric transmission rate case applications, and post- transition period ratemaIdng proceedings; fluctuations in commodity gas, natural gas liquid, and electricity prices' and the ability to successfully manage such price fluctuations; and the pace and extent of competition in the California generation market and its impact on the Utility's costs and resulting collection of transition costs. As the ultimate impact of these and other factors is uncertain, these and other factors may cause future results to differ materially from ,results or outcomes currently expected or sought by PG&E Corporation. Competition and the Changing Regulatory Environment . The electric and gas industries are continuing' to undergo significant change. Under traditional regulation, utilities were provided the opportunity' to earn a fair, return on, theþ' invested, capital in exchange for a commitment to serve all customers within a designated service territory. The objective of this regulatory policy Was to provide universal access to s~fe and reliable utility service~. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices. ' In 1998, California became one of the first states in the country to implement electric industry restructuring and establish a competitive market framework for electric generation. Today, most Califo~ians may continue to purchase their electricity from investor-owned utilities (such as Pacific Gas and Electric Company) or they may choose to purchase electricity from alternative generation providers (such as unregulated power generators ,and unregulated retail electricity suppliers such as marketers, brokers, and aggregators). For those customers who have not chosen an· alternative generation provider, investor-owned utilities,. such as Pacific Gas and Electric Company, continue to be the generation providers. Investor-owned utilities continue to provide distribution services to substantially all customers within their serVice territories, including those customers who choose an alternative generation provider. The framework for electric industry restructuring was established in Assembly 2 , ',' -,Y-'," ~~ ~ I: e e Bill 1890 (AB 1890) passed by the California Legislature and signed by the Governor in 1996. For information about California electric industry restructuring, see "Utility Operations-Electric Utility Operations-California Electric Industry Restructuring" below. Although the initial stages of restructuring have focussed on competition among suppliers of generation, the CPUC also is studying the effect of distributed generation (where the electric energy source is located in close proximity to electric demand) in the California generation market and possible changes in the electric distribution function of traditional utilities. See "Utility Operations-Electric Utility Operations--California Electric Industry Restructuring-Distributed Generation and Electric Distribution Competition" below. Restructuring of the natural gas industry on both the national and the state level has given choices to California utility customers to meet their gas supply needs. In August 1997, the CPUC approved the Gas Accord settlement agreement (Gas Accord) which restructured the Utility's gas services and its role in the gas market. Among other matters, the Gas Accord separated, or "unbundled," the rates for the Utility's gas transmission services from its distribution services. As a result, the Utility's customers may buy gas directly from competing suppliers and purchase transmission-only and distribution-only services from the Utility. Most of the Utility's industrial and larger commercial customers (noncore customers) now purchase their gas from marketers and brokers. Substantially all residential and smaller commercial customers (core customers) buy gas as well as transmission and distribution services from the Utility as a bundled service. For more information aboutthe Gas Accord and regulatory changes affecting the California natural gas industry, see "Utility Operations-Gas Utility Operations-Gas Regulatory Framework " below. ' Additional information concerning competition and the changing regulatory environment is provided in "Management's Discussion and Analysis" in the 1999 Annual Report to Sharehòlders, beginning on page 5, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 40 of the 1999 Annual Report to Shareholders, which information is hereby incorporated by reference. ' Regulation of PG&E Corporation PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (Holding Company Act). At present, PG&E Corporation has no expectation of becoming a registered holding company under the Holding Company Act. , I PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the CPUC. However, the CPUC approval authorizing Pacific Gas and Electric Company to form a holding company was granted subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that the Utility is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC, the Utility's dividend policy shall continue to be established by the Utility's Board òf Directors as though Pacific Gas and Electric Company were a stand-alone utility company, and the capital requirements of the Utility, as detennined to be necessary to meet the Utility's service obligations, 'shall be given first priority by the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company. The conditions also provide that the Utility shall maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility's equity ratio by 1 % or more. The CPUC also has adopted complex and detailed rules governing transactions betwêen California's natural gas local distribution and electric utility companies and their non-regulated affiliates.' The rules permit non- regulated affiliates of regulated utilities (such as PG&E Energy Services, the non-regulated energy marketing subsidiary of PG&E Corporation) to compete in the affiliated utility's service territory, and also to use the name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUc. The rules also address the separation of regulated utilities and their, non-regulated affiliates and information I, 3 I I I . ..i' It - exchange among the affiliates. The rules prohil?it the utilities from engaging in certain practices, which would discriminate against energy service providers that compete with the utility's non-,regulated affiliates. The CPUC has also established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations. Regulation of Pacific Gas and Electric Company State Regulation The CPUC has jurisdiction to regulate the following utility functions within California: electric distribution service, gas distribution service, and gas transmission service. The CPUC regulates Pacific Gas and Electric Company's rates and conditions of service, sales of securities, dispositions of utility property, rates of return, rates of depreciation, and long-term resource procurement. T~e CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as, deregulation, competition, and the . environment, in order to determine its future policies. The CPUC consists of five members, appointed by the Governor and confirmed by the State Senate for six-year terms. The Cålifornia Energy Commission (CEC) has the responsibility to make electric-demand forecasts for th~ state and for specific service territories. Based upon these forecasts, the CEC.determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a statewide plan of action iIÌ case of energy shortages. In addition, the CEC certifies power plant sites and related facilities within California. The CEC also administers funding for public purpose research and development, and renewable technologies programs. Federal Regulation The FERC regulates electric'transinission rates and access, operation of the California Independent System Operator (ISO) and the California Power Exchange (PX), uniform systems of accounts, and electric contracts involving sales of electricity for resale. The FERC also has jurisdiction over the Utility's electric transmission revenue requirements and rates. The FERC also regulates the iriterstate transportation of natural gas. Further, , most of the Utilitis hydroelectric facilities are subject to licenses issued by the FERC. The Nuclear Regulatory CominissiOll (NRC) oversees the licensing" construction, operation, and' decommissioning of nuclear facilities, including Diablo Canyon and the nuclear generating unit at Humboldt Bay Power Plant (Unit 3). NRC regulations require extensive monitoring and review of the safety, radiological, and environmental aspects of these facilities: ' Lkenses and ,Permits Pacific Gas and Electric Company obtains a number of permits, authorizations, and licenses in connectiön with the construction and operation' of its generating plants, transmission lines, and gas ,compressor station facilities. Discharge permits, various Air Pollution Control District permits, United States Department of Agriculture-Forest Service permits, FERC hydroelectric facility and transmission line licenses, and NRC licenses are the most significant exampies. Some licenses and permits may be revoked or modified by ,the granting agency if facts develop or events occur that differ significantly from the facts and projections 'assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility., Licenses and permits may require perrodic renewal, which may result in additional requirements being imposed by the granting agency. Pacific Gas and J;:lectric Company currently has ten hydroelectric projects and one transmission line project undergoing FERC license renewal. Regulation of the National Energy Group In addition to Pacific Gas and Electric Company, certain of PG&E CorÌ>o~ation's other subsidiaries that conduct interstate gas transmissiòn and storage and electric wholesale power marketing operations' are subject to 4 4; - 1'.. .t~. . - - ',FERC jurisdiction. The FERC also has authority to regulate rates for natural gas transportation and storage in interstate commerce. The FERC also regulates certain transportation and storage transactions on the intrastate pipelines pursuant to Section 311 of the Natural Gas Policy Act of 1978. ' The Railroad Commission of Texas (RRC) regulates gas utilities, including those owned by PG&E Corporation through PG&E Gas Transmission, Texas Corporation (PG&E GTI), PG&E Gas Transmission Teco, Inc., and other affiliates operating in Texas. The RRC's gas proration rules govern the \\,ellhead production and purchase of gas. Intrastate pipelines can provide intrastate gas transportation at negotiated rates that are presumed jùst and reasonable. If the criteria for negotiated rates cannot be met, the RRC may assess a cost-of-service-based rate. The RRC also may regulate certain sales of gas. Currently, the price of natural gas sold under a majority of PG&E GU's gas sales contracts is not regulated by the RRC.All transportation and gathering of gas is subject to the RRC Code of Conduct which prohibits undue discrimination among similarly situated shippers. Further, all transportation of gas, processing of gas, and transportation of natural gas liquids is subject to safety regulations enforced by the RRC and the Texas Natural Resource Conservation ComÌnission. In addition, the power generation projects that PG&E Gen develops, manages, or owns are subject to differing types of fèderal regulation depending on the regulatory status of the particular project. Some of these projects are exempt wholesale generators (EWG) under the National Energy Policy Act of 1992, which status exempts the project from regulation under the Holding Company Act. EWG status is granted by the FERC upon application by the project. Some projects have received authority from the FERC to charge market-based rates for the power they sell, rather than traditional cost-based rates. Many of PG&E Gen's affiliated projects are qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA). QF status exempts the project from regulation under various 'federal and state laws concerning the electric industry. PG&E Gen' s projects are also' subject to various federal, state, and local regulations concerning siting and environmental matters. PG&E Corporation's indirect subsidiary USGen New England, Inc. (USGenNE) acquired the electric generating facilities of the New England Electric System (NEES) in September 1998. USGenNE also is subject to numerous federal, state, and local statutes and regulations. USGenNE sells at wholesale all of the electricity it generates, as well as electricity it purchases from third parties under existing power sales agreements. Under the Federal Power Act (FPA), the FERC regulates these wholesale sales. The FERC has approved USGenNE's rate schedule as a market-based schedule and, accordingly, the FERC granted USGenNE waivers of certain other requirements that otherwise are imposed on utilities with cost-based rate schedules. In addition, USGenNE owns and operates a number of hydroelectric and pumped storage projects that are licensed by the FERC. These licenses expire periodically and the projects must be relicensed at that time. USGenNE's licenses for these hydroelectric projects expire over a period from 2001 to 2020. Before expiration of anyone of the hydroelectric licenses, there is an opportunity for the existing licensee (as well as others interested in owning and operating the projéct) to apply for, and obtain, a new license. USGenNE also is subject to limited regulation by certain state public utility commissions located instates where USGenNE owns and operates electric generating facilities. This regulation does not extend to its rates, which are regulated exclusively by the FERC, and the scope of this regulation has been substantially limited by various legislative initiatives. Other regulatory matters are described throughout this report. Risk Management Programs PG&E Corporation has an officer-level Risk Management Committee and has adopted a Risk Management Policy, approved by the Board of Directors of PG&E Corporation, for trading and risk management activities. The Risk Management Committee oversees implementation of the policy, approves the trading and risk management policies of subsidiaries, and monitors compliance with the poli~y. 5 ~ ·f It - The Risk Management Policy allows derivatives to be used for both hedging and non-hedging purposes. (A derivative is a contract whose value is dependeI).t on or derived from the value of some underlying asset.) PG&E Corporation uses derivatives for hedging purposes prImarily to offset underlying commodity price risks. PG&E Corporation also participates in markets using derivatives to gather market intelligence, create liquidity, maintain a market presence, and take a market view. Such derivatives include forward contracts, futures, swaps, and, options. The Risk Man"agement Policy and the trading and risk management policies of PG&E Corporation's subsidiaries prohibit the use of derivatives whose payment formula includes a multiple of some underlying asset. The Risk Management Committee also monitors the trading and risk management of PG&E ET, consistent with PG&E Corporation's Risk Management Policy. See "National Energy Group-Energy Trading." " The CPUC has authorized Pacific Gas and Electric Company to trade natural gas-base~ financial instruments to. manage price and revenue risks associated with its natural gas transmission and storage assets, subject to certain conditions. The CPUC also has authorized the Utility to tradè natural gas-based financial instruments to hedge the gas commodity price swings in serving core gas customers. In May 1999, the PX obtained FERC , approval to operate the "block forward market" which offers parties the ability to b.uy'and sell contracts to purchase electricity in the future at prices set in the contracts. The Utility sought and obtained CPUC authority to participate in the PX block forward market for contracts that call for delivery of the purchased electricity by October 31, 2000, as well as to recover costs (such as gainllosses and transaction fees) associated with its participation in this market. Additional information concerning risk management activities and the financial impact of risk management activities on PG&E Corporation and Pacific Gas and Electric Company ispròvided in "Management's Discussion ánd Analysis" in the 1999 Annual Report to Shareholders, beginning on page 5 and iIi Notes 1, 3, and 4 of the "Notes to Consolidated Financial Statements" beginning on pages 36, 45 and 47, respectively, of the 1999 Annual Report to Shareholders, which information is hereby incorporated by reference. 6 I ' , ,.. .~ - tit UTILITY OPERATIONS . Pacific Gas and Electric Company provides regulated electric and gas distribution and transmission services in Northern and Central California. The Utility's service territory covers 70,000 square miles with an estimated population of approximately 13 million and includes all or portions of 48 of California's 58 counties. The area's diverse economy includes aerospace, electronics,' financial : services, f~od processing, petroleum refining, agriculture, and tourism. Ratemaking Mechanis~ The rate making mechanisms affecting both electricity and gas distribution operations are discussed below. General Rate Case. The CPUC authorizes ail amount, known as "base revenues," to be collected from ratepayers to reCover Pacific Gas and Electric Company's basic business and operational costs fòr its gas and electric distribution operations. Base revenues, which include non-fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital,currently are authorized by the CPUC in General Rate Case (GRC) proceedings. During the GRC, which occurs every three years, the CPUC exàmines the Utility's costs and 'operations to detennine the amqunt of base revenue requirement the Utility is authorized to collect from customers through base revenues. The revenue requirement is forecasted on the basis of a specified test year. (The return component of the Utility's' revenue requirement is computed using the overall cost of capital authorized in other proceedings.)' Following the revenue requirement phase of a GRC, the CPUC conducts a rate design phase.. which allocates revenue requirements and establishes rate levels for the different classes of custoI:llers. On February 17,2000, the CPUC issued a decision in the ,Utility's GRC for the period 1999-2001, further discussed below. The decision also orders that the Utility file a 2002 GRC, so that the revenue , requirements established in the 2002 GRC will be the starting point for a future performance based ratemaking (PBR) mechanism (discussed below) that is intended to eventually replace the GRC mechanism and cost of capital proceedings. Cost 'oj Capital. 'Each year, the Utility files an application with the CPUC to determine the authorized rate of return that the Utility may earn on its electric and gas distribution assets and recover from ratepayers. In November 1999, the Utility filed its '2000 cost of capital application. To reflect inèreasing interest rates, the Utility has requestèd a return on equity (ROE) of 12.5% and an overall rate of return of 9.76% as compared to its 1999 auth~rized rates of 10,6% ROE and 8,75% overall rate of return. The Utility has not requested any change in its current authorized capital structure of 46.2% long-term debt, 5.8% preferred stock, and 48% common equity. If granted, the requested ROE would increase electric distribution revenues by approximately $36.6 million and natural gas distribution revenues by, approximately $127.8 million baSed upon the rate base authorized ,in the 1999 GRC. The Utility requested that a final CPUC decision be issued in June 2000. On February 17, 2000, the CPUC issued a decision to allow the final CPUC decision, when it is adopted, to be effective retroactively to February 17,2000. The return on the Utility's electric transmission-related assets will be detennined by the FERC in 2000. The return on the Utility's natural gas transmission and storage business was incorporated in rates established in the Gas Accord settlement. See "Gas Ratemaking-Gas Accord" below. The authorized ROE for the Utility's remaining generation assets, including Diablo Canyon, is 6.77% throughout the transition period. Electric and Gas Distribution Performance-Based Ratemaking. In November 1998, the Utility filed an application with the CPUC to establish performance-based ratemaking (PBR) tor electric and gas distribution services. The 'proposed distribution PBR would establish electric and gas distribution re~enue requirements for the year in which PBR is approved to 2004 taking the place of the GRC and cost of capital proceedings for these years. The Utility proposèd that the revenue requirement for the year 2000 be determined by applying a formula, based principally on inflation and productivity factors, to the 1999 GRC authorized revenue requirement. In sûbseq~ent years, thé formula would be applied to the previous year's authorized revenue requirement. The proposed PBR also includes a sharing mechanism for earnings that are significantly above or below the authorized cost of capital, and a framework for rewards and penalties based upon the achievement of varÍous performance measures. 7 I I ~ f e - The final decision in the GRC requires the Utility to go forward with the performance rewards/penalties framework of its PBR proposal, but it requires a 2002 GRC before implementing the PBR mechanism that determines future revenue requirements based principally on inflation and productivity"factors. The starting point for the PBR mechanism will be the revenue requirements established in the required 2002 GRC In any event, after the transition period, the Utility's earnings from'its electric distribution operations will be subject to, volatility as a result of sales fluctuations. Annual Earnings Assessment Proceeding. The Annual Earnings Assessment Proceeding' (AEAP) determines shareholder incentives tO,be earned for Pacific'Gas and Electric Company's demand side management (DSM) .programs. The Utility was authorized to collect $15.9 million in incentive payments during 1999. The Utility has filed an application seeking $28.7 million in incentive payments relating to 1998 energy.efficiency and low-income assistance programs, and DSM programs from other years to be paid iIi 2000. After consolidating the adjusted incentive payment installments from prior years, the net revenue change in 2000 from DSM shareholder incentives should be an electric increase of approximately $2.47 million and a gas decrease of approximately $0.75 million assuming the Utility's incentive claims are approved. The 1999 AEAP decision is expected in the second quarter öf 2000. Catastrophic Event Memoråndum Account. The Catastrophic Event Memorandum Account (CEMA) allows Pacific Gas and Electric Company to track costs 'incurred in connection with catastrophic évents. On January 7,1999, the Utility filed an application with the CPUC in its firstCEMA proceeding requesting increases in electric and gas revenue requirements of $60.1 million and $15.8 million, respectively, for costs incurred for several emergencies, including the 1991 Oakland Hills Fire and 1998 storms. In September 1999, the 'Utility entered into a settlement' agreement providing 'for a $59 million increase in electric distribution revenue requirement and a $11 million increase in gas distribution revenue requirement effective January 1, 2000. A CPUC decision is expected in early 2000. Electric Ratemaking The California electric' industry restructuring legislation provided for a transition period during which electric customer rates remain frozen. Any change in the Utility's electric revenue requirements resulting' from the items discussed below will not change electric customer rates. Under the electric Jate freeze, the portion of total actual revenue that exceeds authorize? base revenues and certain other authorize<i revenue requirements and costs is available to recover transition costs during the ,transition period. Transition costs are certain generation- related costs' that prove to be uneconomic under the new competitive generation market. (See' "Electric Utility Operations-California Electric Industry Restructuring-Recovery of Transition Costs.") Therefore, increases in base revenues would reduce the amount of revenue available to recover transition costs. Conversely, decreases in base revenues would increase revenue avroJable from frozen rates for recovery of transition costs. The transition period will end the earlier of December 31, 2001, or when the Utility has recovered its eligible transition costs. The electric rate freeze will end the earlier of March 31, 2002, or when the Utility has recovered its eligible transition costs. , , General Rare Case. . On February 17, 2000, the CPUCissued a decision in the Utility's GRC for the period 1999-2001. The decision is retroactive to January 1, 1999. The CPUC authorized increases in base revenues for the Utility's electric distribution function of $377 million over base revenues authorized in 1996. Revenue Adjustment Proceeding. . On January 1, 1998, the Transition Revenue Þ,.,écount (TRA) was established. The TRA is credited with total revenue collected' from ratepayers through frozen fates. From this total revenue the following items are subtracted: (1) revenues colÌected for transmission services and for the payment of rate reduction bond debt service: (2) the authorized revenue requirement for distribution services, public purpose programs, and nuClear, decommissioning. costs, and (3) electric industry restructuring implementation costs, energy procurement costs, and other costs. R~maining revenues, if any, are transferred to the Transition Cost Balancing Account (TCBA) tò offset transition costs. The CPUC established a separate annual proceeding, the Revenue Adjustment Proceeding (RAP), to review and verify the amounts recorded in 8 -;:..,..~ .- -,. , ,-';;;'.''1 ~ '., - e the TRA, and to verify each electric utility's authorized revenue requirements; including any necessary adjustments to reflect the revenue requirements which are approved in other proceedings. The RAP also establishes revenue allocation and rate design, and identifies all electric balancing and memorandum accounts for continued retention or elimination. In June 1999, the CPUC issued a decision in the Utility's first RAP that, among other things, adopted an agreement between the Utility and the CPUC's Office of Ratepayer Advocates (ORA) that resolved several rate allocation and rate design issues, eliminated certain balancing and memorandum accounts, and allows the recovery of entries made into the TRA from January 1 through May 31, 1998 and certain other balancing accounts, subject to CPUC audit. On August 9, 1999, the Utility filed its application in the 1999 RAP addressing revenues and costs recorded in the TRAfrom June 1, 1998 through June 30, 1999. A CPUC decision on this application is expected in late 2000. Annual Transition Cost Proceeding. The Annual Transition Cost Proceeding (A TCP), applicable to all California investor owned electric utilities, was established to verify the accounting and recording of costs and revenues in the TCBAand 'ensure that only eligible transition costs have been entered. The TCBA tracks the revenues available to offset transition costs, including' the accelerated recovery of plant balances, and other generation-related assets and obligations. Transition costs will receive a limited "reasonableness" review. On September 1, 1998, the Utility file4 its application in the 1998 ATCP requesting that ,$1.8 billion of costs recorded in the TCBA from January 1 through June 30, 1998 be approved as eligible for recovery as transition costs. In July 1999, PG&È and ORA filed a joint motion with the CPUC for approval of a settlement that recommends that the CPUC approve substantially all costs requested by the Utility. On February 17,2000, the CPUC issued a decision which accepts the settlement in its entirety, and decides most of the other issues in the case in the Utility's favor. Under the final decision, on a prospective basis, the utilities are required to assess the estimated market value of their remaining non-nuclear generating assets, including the land associated with those assets, on an aggregate basis at a value not less than the net book value of those assets and to credit the TCBA with the estimated value. The decision encourages the utilities to base such estimates on realistic, assessments of the market value of the assets. The final decision, did not adopt a recommendation contained in a previously issued proposed decision to establish a new regulatory asset account that would allow a true-up when the estimated market value is greater than actual market value. However, the decision states that crediting the TCBA with the aggregate net book value of the remaining non-nuclear generating assets is a conservative approach and remedies any concerns regarding the lack of a true-up. The decision provides that if the estimated market valuation is less than book value for any individual asset, accelerated amortization of the associated transition costs will continue until final market valuation of the asset occurs through sale, appraisal, or other divestiture. If the final value of the assets, determined through sale, appraisal or other divestiture, is higher than the estimate, the excess amount would be used to pay remaining transition costs, if any. The utilities are required to file the adjusted entries to their respective TCBA based on the estimated market values with the, CPUC by March 9, 2000. The filing will become effective after appropriate review by the CPUC's Energy Division and the TCBA entries are subjecttóreview in the next ATC:p. On September 1,1999, the Utility filed its 1999 ATCP application requesting that $2.6 billion recorded in the TCBA from July 1, 1998, through June 30, 1999, be approved as eligible for recovery as transition costs. Electric Industry Restructuring Implementation Costs. Under AB 1890, certain electric industry restructuring implementation costs found reasonable by the CPUC may be recovered from electric customers. In May 1999, the CPUC approved a multi-party settlement agreement that, among other things, permits the Utility to recover 1997 and 1998 restructuring implementation costs of $41.3 million (reflecting a reduction of $iO million from the Utility's requested revenue requirement). In addition, the Utility is authorized to recover in its TRA costs related to the Consumer Education Program and the Electric Education TrUl¡t funded by the Utility and FERC-approved ISO and PX development and start-up costs. 'At the end of the transition period, if recovery of these restructuring implementation costs recorded in the TRA displaces r~covery ôf transition costs recorded in the TCBA, the Utility may recover up to $95 million of such displaced transition costs after the transition period. As part of the settlement agreement, the CPÚC also authorized the Utility to, establish the Electric Restructuring Costs Account (ERCA) to record the restructuring implementation costs that were removed from its 1999 GRC revenue requirement request, any unanticipated restructuring costs incurred às a result of directives, 9 .! .' e - from the CPUC or the FERC, and certain other costs. The teas~nableness of the entries made in the ERCA and the reèovery of these costs will be made through a separate application by the Utility in 2000. I Revenues from Must-Run Contracts. The ISO has designated certain units at electric generation facilities as necessary to remain available to maintain the reliability of the electric transmission system. These units are called "must-run" units. In general, the ISO dispatches these units under cost-based contracts regulated by the , FERC that allow the ownersJo recover a portion of fixed and operating costs of the must-run units. The owners of must-run units choose among two different fonns of must-run contract, both of which cover operating costs. One fonn provides payments of a percentage of the unit's fixed cost revenue requirement and does not limit . market participation. The other fonn provides 100% fixed cost recovery but allows only very restricted market participation. The Utility's two remaining fossil-fueled power plants (Hunters Point and Humboldt' Bay) and three of its hydroelectric generation facilities are under must-run contracts. The fonn of must-run contract chosen' for all of these facilities (except Hunters Point) is the one that does not lin:út market participation. The Utility currently receives approximately $100 million per year as payments under these must-run contracts, plus fuel costs. In addition, the Utility has the opportunity to earn market revenues for all of these plants except Hunters Point when the ISO has not dispatched the plant. The Utility has filed an application w~th the CPUC to determine the market value of its hydroelectric generation facilities and related assets throùgh an open competitive auction. , ' FERC Transmission Owner Rate Case. Thè ISO controls most ofthe state's electric transmission facilities. The Utility serves as the scheduling coordinator to schedule transmission with the ISO to facilitate continuing service under wholesale transmission contracts that the Utility entered into before the ISO was established. The , ISO bills the Utility for providing certain services associated with these contracts. These ISO charges are referred to as the "scheduling coordinator costs." As part of the Utility's Transmission Owner rate case filed at the FERC, the Utility established a balancing account, the .Transmission Revenue Balancing Account (TRBA), to record these scheduling coordinator costs in order to recover these costs through transmission rates. Certain transmission-related revenues collected by the ISO and paid ,to the Utility are also recorded in the TRBA. Through December 31, 1999, the Utility has recorded approximately $39 million of these scheduling coordinator costs in the TRBA. (The Utility has also disputed approximately $22.5 million of these costs as incorrectly billed' by the ISO. Any refunds that ultimately may be made by the ISO would be credited to the TRBA.). On September 1, 1999, a proposed decision was issued denying recovery of these scheduling coordinator costs. The proposed decision is subject to change by the FERC in its final decision. The FERC is expected to issue a final decision sometime in 2000. On January 11,2000, the FERC accepted.a proposal by the Utility to establish the Scheduled Coordinator Services (SCS) Tariff which would act as a back-up mechanism for recovery of the scheduling coordinator costs if the FERC ultimately decides that these costs may not be recovered in the TRBA. The FERC also conditionally granted the Utility's request that the SCS Tariff be effective retroactive to March 31, 1998, but the FERC suspended the procedural schedule until the final decision is issued regarding the inclusion of scheduling coordinator costs in the TRBA. AB 1890 Electric Base Revenue Increase. AB 1890 provided for an increase in the Utility's electric base revenues for 1997 and 1998, for enhancement of transmission and distribution system safety and reliability. The CPUC authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC authorized an additional base revenue increase of $77 million. The CPUC will detennine how much of the authorized increases were actually spent on system safety and reliability during 1997' and 1998, and; adjust the amounts downward if necessary. The Utility claims that it overspent the 1997 authorized revenue requirement by approximately $11.8 million and that the Utility underspeilt 1998 incremental revenues by approximately $6.5 million~ The Utility has proposed that the underspent amount be credited to TRA revenues. The CPUC's' Office of Ratepayer Advocate (ORA) has recommended that $88.4 million in expenditures for 1997' and 1998 be disallowed. The Utility Refonn Network (TURN), has recommended an additional $14 million disallowance for a total recommended disallowance for 1997 and 1998 expenditures of $102.4 milliòn. The Utility opposed the recommended disallowances and hearings were held in October 1999. A proposed decision is not expected ùritil the first quarter of 2000. Any proposed decision would be subject to comment by the parties and change by the CPUC before a final decision is issued. 10 i'- ·-·l',!··· -- --;----;;:-..'-·"'v." . . .'-~' , -- ,¡-- ,\ 'ò ,I -- e Electric Transmission Revenues. Since April 1998; all electric transmission revenues are authorized by the FERC. During 1998 and -1999, the FERC issued orders that put into effect various rates to recover electric transmission costs from the Utility'sfonner bundled rate transmission customers. All 1998 and 1999 rates are subject to refurid, pending final decisions. In April 1999, the Utility filed a settlement with the FERC which, if approved, would allow the Utility to recover $345 million for the period of April 1998 through May 1999. In May 1999, the FERC accepted, subject to refund, the Utility's March Ì999 request to begin recovering, as of May 31, 1999, $324 million annually. In October 1999, the FERC accepted, subject to refund, the Utility's September 1999 request to increase revenues to $370 million annually beginning in April 2000. Electric Deferred Refund Account (EDRA). In December 1996, the CPUC issued a decision establishing , an EDRA. The CPUC ordered the Utility to place into the EDRA credits for CPUC-ordered electric disallowances, the utility electric generation share of gas disallowances' ordered by the CPUC or the FERC, and amounts resulting from reasonableness disputes or fuel-related cost refunds made to the Utility based on regulatory agency decisions, plus interest charges. In February 2000, the Utility refunded approximately '$25 million of EDRA refunds to customers, which included a refund of unspent research, development, and demonstration funds. Post-Transition Period Raiepzaki':lg Proceeding. - In October 1999, the CPUC issued a decision in the Utility's post-transition period ratemaking proceeding. Among other matters, the CPUC decision addresses the mechanisms for ending the current electric rate freeze and for establishing post-transition period accounting mechanisms and rates. The decision prohibits the Utility from collecting after the ràte freeze any electric costs incurred during the rate freeze but not recovered during the rate freeze, including costs that are not transition costs and not related to generation assets such as under-collected accounting - balances relating to power purchases~The decision also requires the discontinuance of Diablo Canyon's perfonnance-based ratemaking, the incremental cost incentive price (ICIF) mechanism, at the end of the transition period. Instead, after the transition period, Diablo Canyon generation must be sold at the preyailing market price for power. The Utility has filed an application for rehearing of the CPUC's decision. In the decision, the CPUC also established the Purchased Electric Commodity Account (PECA) for the Utility to track energy costs after the rate freeze and transition period end. The CPUC intends to explore other ratemaking issues, including whether dollar-for-dollar recovery of energy costs i~ appropriate, in the second phase of the post-transition electric ratemaking proceeding. There, are three primary options for the future regulatory framework for utility electric energy procurement cost recovery after the rate freeze: (1) a CPUC- defined procurement practice, that if followed by the Utility, would pass through costs without the need for reasonableness reviews, (2) a pass through of costs subject to after-the-fact reasonableness reviews, or (3) a procurement - incentive mechanisms, with rewards and penalties determined based on the Utility's energy purchasing perfonnance compared to a benchmark. The Utility proposed adoption of either - a defined procurement practice or a procurement incentive mechanism, neither of which would involve reasonableness reviews. The volatility of earnings and risk exposure of the Utility related to post-transition period purchases of electricity is dependent on' which of these options, Or some other approach, is adopted. A decision in the second phase of the proceeding is expected in the first quarter 2000, addressing certain other post-transition period ratemaking issues including, among others, incentive mechanisms for commodity purchases and the allocation of certain transition costs that are recoverable after the transition period. Additional infonnation about the financial impact of the end of the rate freeze and the end of the transition period on the Utility and PG&E Corporation is provided in "Management's Discussion and Analysis" in the 1999 Ànnual Report to Shareholders, beginning on page 5. I Gas Ratemaking Gas Accord. The Gas Accord separated or "unbundled" the Utility's gas transmission services from its distribution services, changed the tenns of service and rate structure for gas transportation, increased the opportunity .for core customers to purchase gas, from competing sÜppliers, established a fonn of incentive 11 .: e It mechanism to measure the reasonableness of core procurement costs, and established gas transmission and storage rates through 2002. Additional information about the Gas Accord is provided below in "Utility Operations-Gas Utility Operations" and in "Management's Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning on page 5. General Rate Case. On February 17, 2000, the CPUC issued a decisio'n in the Utility's GRC for the period 1999-2001. The decision is retroactive to January 1, 1999. The CPUC àuthorized increases in base revenues for the Utility's gas distribution function of approximately $9~ million over base revenues authorized in 1996. The Biennial Cost Allocation Proceeding (BCAP). The BcAp remains ,the, proceeding in which 'distribution costs and balancing account balances are allocated to customers: The BCAP normally occurs every two years and is updated in the interim year for purposes. of· amortizing any accumulation in the balancing accounts. Balancing accounts for, natural gas costs accumulate differences between the actual 'recovery of gas costs arid the revenues designed for recovery ,of such costs. Balancing accounts for sales volumes accumulate differences between authorized and actual base revenues. In June 1998, the CPUC adopted a decision ,in the 1998· BCAP granting an annual $97.8 million revenue requirement decrease effective September I, 1998, compared tó revenues established by the Gas Accord on March 1, 1998. The overall annual revenue requirement for the two- year BCAP period (September 1, 1998, through August 31, 2000) is approximately $1.5 billion, of which an annual average of approximately $102 million is allocated for the collection' of bal<incing accounts. The Utility. plans to file its 2000 BCAP application in the first half of 2000. . Electric Utility Operations California Electric Industry Restructuring As a result of California el~ctric industry restructl)ring, the electric generation function of traditional utilities has been opened up to competition, giving electric customers of investor-owned utilities (such as Pacific Gas and Electric Company) the choice of continuing to purchase 'electricity from investor-owned utilities or purchasing electricity from alternative' providers (including unregulated power generators and unregulated retail electricity providers such as marketers; brokers, and aggregators). Purchasing electricity from an alternative generation provider is cailed "direct access." For those customers who have not chosen an alternative generation provider, investor-owned utilities continue to be the generation provider. Investor-owned utilities continue to' provide distribution services to substantially all customers within their sèrvice territories, including those customers who choose direct access. I I The California Independent System· Operator and the California Power Exchange. To create a competitive generation market, the PX and the ISO were established and began operating on March 31; 1998. the FERC has jurisdiction over both the ISO and the PX. ' The ISO operates and controls most of the state's electric transmission facilities (which continue to be owned and maintained by the CaÍifornia utilities) and provides comparable open access to electric transmission service. The ISO accepts balanced supply and load schedules from market participants and maI1ages the availability of electric transmission on a statewide basis for these transactions. The ISO also purchases necessary generation and ancillary services to maintain grid reliability. The ISO is required to ensure reliable transmission sei:vices consistent with planning and operating reserve criteria no less stringent than those established by the Western Systems Coordinating Council and the North Amerián Elèctric Reliability. Council¡ Oversight of utility distribution systems remains with the CPUc. The PX provides a competitive auction process to establish transparent márkétclearing prices for electricity in the markets operated by the PX. During the transition period, the Utility is required to sell into the i>x all of its generated electric power. "Must-take" generation resources, such as nuclear generation from Diablo Canyon, electric power generatéd by QFs and electricity that the Utility is required to purchase under existing contractual commitments, al~o are· scheduled through the PX. During the transition period, thè :Utility must purchase. all :1 12 .;_~ ,-;-;;;-~c_, 'ì ~ e e electric power for its retail customers through the PX. Customers who buy power directly from non-regulated suppliers pay for that generation based upon negotiated contracts. The PX sets a market-clearing' price for electricity by matching all demand load bids with supply bids ranked from lowest to highest: The highest- accepted generation supply bid used to serve load sets the PX market-clearing price for electricity. I: After the transition period, the Utility may continue to schedule its must-take generation resources into the px. It is unsettled whether the Utility will be required to continue purchasing its electric power for its retail customers through the PX after the transition,period. The Utility expects that the CPUC will address the issue of whether the purchase obligation will continue through December 31,2001, if the Utility's rate freeze ends before that date, in the second phase of the Utility's post-transition period ratemaking proceeding in the first quarter of 2000. Some parties have argued that the utilities' purchase obligation may need to continue beyond December 31, 2001, depending on market conditions. See "Ratemaking Mechanisms-Electric Ratemaking- Post-Transition Period Ratemaking Proceeding" above. The ISO and PX are California public benefit non-profit corporations. Each has a Governing Board that includes representatives of investor-owned utility transmission systems, publicly owned utility transmission systems, non-utility electricity sellers, public buyers and sellers, private buyers and sellers, industrial end-users, commercial end-users, residential end-users, agricultural end-users, public interest groups, and non-market participant representatives. The ISO and PX currently are overseen by a five-member Electricity Oversight Board (BOB) that appoints the members of the ISO and PX Governing Boards. However, this appointment power was rejected by the FERC. Subsequently the California Legislature passed, and the Governor signed, Senate Bill (SB) 96 which redefined the relationship between the EOB and the ISO and PX. SB 96 limits the EOB's appointment power to representatives of those classes that represent California consumers' interests. The ISO or PX Governing Boards confirm all other appointments. SB 96 has been accepted in principle by the FERC. Bylaw amendments implementing SB 96 are pending before the FERC for the PX and the ISO currently is circulating draft bylaw amendments among its stakeholderS. Voluntary Generation Asset Divestiture. California utilities, including Pacific Gas and Electric Company, have voluntarily begun divesting some of their generation assets. In 1998, the Utility sold three of its fossil-fueled electric generating plants located at Morro Bay, Moss Landing, and Oakland, California. In 1999, the Utility also sold three fossil-fueled generating facilities (the Pittsburg and Contra Costa power plants located in Contra Costa County, and the Potrero power plant in San Francisco) and its geothermal generating facilities (The Geysers Power Plant located in Lake and Sonoma Counties). The Utility has retained liability for required . environmental remediation of any pre-closing soil or groundwater contamination at these plants. In September 1999, the Utility filed ari application' with the CPUC to determine the market value of the Utility's hydroelectric generation facilities and related assets through an open competitive auction. The Utility proposes to use an auction process similar to the one previously used in the sale of the Utility's fossil fueled and geothermal plants. Under the process proposed in the application. PG&E Gen would be permitted to participate in the auction on the same basis as other bidders. The sale of the hydroelectric facilities would be subject to certain conditions, including the transfer or re-issuance of various permits and licenses by the FERC and other agencies. On January 13, 2000; the CPUC issued a ruling which separates the proceedIng into two concurrent, phases: one to review the potential environmental impacts of the proposed au~tion under the California Environmental Quality Act (CEQA) and a,second to determine whether the Utility's auction proposal, or some other alternative to the proposal, is in the public interest. The ruling sets a procedural schedule which calls for a , final CPUC decision on the Utility's auction proposal by October 19, 2000, and a final environmental impact report published in November 2000. The schedule calls for the auction, if approved, to begin in early November 2000 and end in early January 2001. The schedule anticipates that the divestiture process would be closed by June I, 2001. Finally, the ruling prohibits the Utility from withdrawing its application without express CPUC authority. It is uncertain,whether the CPUC will ultimately approve the Utility's auction proposal. Additional information about the potential financial impact of the proposed auction ~n the Utility and PG&E Corporation is provided in "Management's Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning on page 5. 13 .~ to e -- As required by AB 1890, Utilìty employees, under two-year operations and maintenance agreements with the new owners, will continue to operate and maintain the power plants that have been sold. To the extent that payments to the Utility under these agreements exceed the Utility's cost of operating the plants,- the additional revenue would be given to ratepayers. Conversely, to the extent the Utility's operating costs exceed the revenues from these agreements, the Utility absorbs these losses in earnings. Recovery of Transition Costs. As market-based revenues may not be sufficient to recover certain of the Utility's generation costs, AB 1890 provides the investor-owned utilities the opportunity 'to recover such uneconomic generation costs (called transition costs) for a certain period of time (the transition period). Some transition costs may be recovered after the transition period. Costs eligible for recovery as transition costs, as determined by the CPUC, include (1) above-market sunk costs (i.e., costs associated with utility generating facilities that are fixed and unavoidable and that" were included in customer rates on December 20, 1995) and future sunk costs, such as costs related to'plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from QFs and other power suppliers, ançl (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods to be included in rates in subsequent periods.) Transition costs are eligible for recovery from all customers (with' certain exceptions) through a nonbypassable comþetition transition charge, or CTC, included as part of rates. Transition ,costs that are disallowed by the CPUC for collection from customers will be written off. As a prerequisite to any consumer obtaining direct access servicès, the' consumer must agree to pay its applicable nonbypassable CTC. Most tránsition costs must be recovered by December 31, 2001, although certain transition costs may be recovered after December 31, 2001. These costs include (1) certain employee-related' transition costs, (2) above-market payments' under existing long-term contracts to purchase power, (3) up to $95 million of transition costs to the, extent that the recovery of such costs during the transition period was displaced by the recovery of electric industry restructuring implementation costs, and (4)' transition costs financed by the issuance of rate reduction bonds. In addition, nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission the nuclear facility. The total amount of sunk costs to be included as transition costs will be based on the aggregate of above- market and below-market values of utility-owned generation assets and obligations. Under AB 1890, valuation of generation-related assets through appraisal, sale, or other divestiture must be completed by December 31, 2001. The value of seven of the Utility's power plants was established when these facilities were sold to third parties. In October 1998, the CPUC ruled that the market value of the Hunters Point power plant is zero. In September 1999, the Utility filed an application with the CPUC to determine the market value of the Utility's hydroelectric generating facilities and related costs through an open competitive auction. Retail Direct Access. Customers participating in direct access may purchase their electric ,power directly either through (1) competing non-utility retail electric providers such as brokers, marketers, aggregators, or other retailers, or (2) direct negotiated contracts with electric generators. All cÍlstomers (with limited exceptions), whether they chöose direct access or' not, must pay the nonbypassable CTC, whiCh will be collected by their distribution utility in connection with recovery of the utilities'· transition costs. Utilities began accepting requests " for direct access in November 1997 to become ,effective after direct access began. As of February 17,2000, Pacific Gas and Electric Company had transferred 94,454 customers to direct access. The CPUC requires that electric customers with an electricity demand, or load, of 50 kilowatts (kW) or more must have meters that are capable of providing hourly data 'in order to participate in direct access. Those customers with a load less than 50 kW may participate in direct access either through "load' profiling" or by installing an, hourly meter. (Load profiling approximates the pattern of electricity usage for a given customer'class and provides the equivalent of ,hourly meter reads.) The customer is responsible for the cost of the meter and the meter installation. Energy service providers supplying the direct access, market may choose one of three billing options: (1) consolidated energy supplier'billing, under which the utility bills the energy. supplier for the services provided directly by the utility to the customer, and the supplier, in turn, provides a consolidated bill to the customer, (2) consolidated distribution company billing, under which the utility places the supplier's energy charge on a 14 .~.. ;;: .;":;';;0;;-; c;-o-------;:¡:- '; j - e distribution bill, or (3) dual billing, under which the energy supplier and the utility bill separately for their own services. Since January 1, 1999, energy service providers may provide metering to all of their customers. During 1999, the Utility continued its efforts to develop ånd implement changes to its business processes and systems, including customer information and biiling systems, to accommodate direct access. To the extent 'the Utility is unable to successfully and timely develop and implement such changes, there could be an adverse impact on,PG&E Corporation's and the Utility's future results of operatións. Rate Levels and RateReduction Bonds. As required by AB 1890, electric rates for all customers have been frozen at the level in effect on June 10, 1996, and, beginning January 1, 1998, rates for residential and small commercial customers were reduced by 10% from 1996 levels. The electric rate freeze and electric rate reduction will continue throughout the transition period. In 1997, the Utility refinanced the expected 10% rate reduction with the proceeds from rate reduction bonds. On December 8, 1997, a special purpose èntityestablished by the California Infrastructure and Economic Development Bank issued $2.9 billion (the expected revenue reduction from the rate deèrease) of rate reduction bonds on behalf of a wholly owned subsidiary of the Utility. The bonds were issued in eight classes with maturities ranging from 10 months to 10 years, and bearing interest at rates ranging from 5.94% to 6.48%. The Utility is collecting from residential and small commercial customers a separate nonbypassable charge on behalf of the bondholders to recover principal, interest, and related costs over the life of the bonds. The bond proceeds were used by the wholly, owned subsidiary to purchase from the Utility the right to be paid the'revenues from this separate charge. The bonds are secured by the future revenue from the separate charge and not by the Utility's assets. While the bonds are reflected as long~term debt on the Utility's balance sheet, the Utility's creditors do not have any recourse to the revenues from the separate charge. The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of these transition costs until after the transition period. During the rate freeze, the rate reduction bond debt service will not increase the Utility customers' electric rates. If the transition period ends before December 31,2001, the utility may be obligated to return a portion of the economic benefits of the transaction to customers. The timing of any such return and the exact amount of such portion, if any, have not yet been determined. Public Purpose Programs. Under AB 1890, the Utility is authorized to collect not less than $198 million in a separate nonbypassable charge included in frozen electric rates to fund Utility and other entities' investments in four public purpose programs: (1) cost-effective energy efficiency and energy conservation programs, (2), research, development and demonstration programs, (3), renewable energy resources programs, and (4) low- income electricity programs including targeted energy efficiency services and rate discounts. Low-income energy efficiency programs are funded at the level of need, but are not to be funded at less than the 1996 level of expenditures. Under this provision of AB 1890, the Utility is obligated to fund through electric rates energy efficiency and conservation programs in an amount not less than $106 million per year, public interest research and development programs at not less than $30 million per year, renewable energy technologies at not less than $48 million per year, and low-income energy efficiency programs' at not less than $14 million per year. The Utility also collects funds for the California Alternate Rates for Energy (CARE) 10w-il1cóme discount rate, a rate subsidy paid for by the Utility's other customers, which is currently about $31 million per year. Under the o~ersight of theCPUC, the Utility administers both the cost-effective energy efficiency and low- income energy efficiency programs. These two programs are reviewed annually in the Annual Earnings Assessment Proceeding. In March 1999, the CPUC determined that these programs should continue to be administered by investor-owned utilities, subject to CPUC oversight, through 2001. Effective January 1, 2000, Section 327 of the California Public Utilities Code requires utilities to continue to adminiSler low-income energy efficiency programs. In accordance with AB 1890, the California Energy Resources Conservation and Development Commission, (also called the California Energy Commission (CEC)) administers both the public interest research and development program and the renewable energy program on a statewide basis. The Utility transfers $78 million per year to the CEC for these two programs. ' Distributed Generation and Electric Distribution Competition. In October 1999, the CPUC issued a decision outlining how the CPUC, in cooperation with other regulatory agencies and the California Legislature, I 15 ; e -- plans to address the issues surrounding distributed generation, electric distribution competition, and the role of the utility distril:mtioncompanies (such as Pacific Gas and Electric Company) in the competitive retail electricity market. Distributed generation enables siting of electric generation technologies in close proximity to the electric demand (referred to as "load"). The CPUC decision opened a new i:ulemaking procéeding to examine various issues concerning distributed generation, in<:;luding interconnection issues, who can own and operate distributed generation, environmental impacts, the role of utility distribution companies, and the .rate design and cost allocation issues associated with the deployment of distributed generation facilities. With respect to electric distribution competition, the CPUC directed its staff to deliver a report by April 21, 2000 on the different policy options that the CPUC, in cooperation with the California Legislature" can pursue. Following the issuance of the report, the CPUC expects to open one or more new proceedings to address electric distribution competition and competition in the retail electric market. \, Electric Operating Statistics At December 31, 1999, Pacific Gas and Electric Company served approximately 4.6 million electric distribution customers. During the transition perIod, the Utility' is required to buy from the PX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier. The following table shows the Utility's operating statistics (excluding subsidiaries) for electric energy, including the classification of sales and revenues by type of service. 1999 1998 1997 1996 1995 Customers (average for the year):, Residential ..................... .-... 4,017,428 3,962,318 3,915,370 3,874,223 3,825,413 Commercial. . . . . . . . . . '. . . . . . .. . . . . 474,710 469,136 465,461 459,001 454,718 Industrial . . . . . . . . . . . . . . . . . . . . . . . . 1,151 1,093 1,121 1;248 1,253 Agricultural . . . . . . . . . . . . . . . . , . . . . . 85,131 ' 85,429 86,359 87,250 88,546 Public street and highway lighting ....: 20,806 18,351- 17,955 17,583 17,089 Other electric utilities. . . . . . . . . . . . . . . 0 14 47 28 35 Total . . . . . . . . . . . . . . . . . . . . . . ~ 4,599,226 4,536,341 4,486,313 4,439,333 4,387,054 Sales-kWh (in millions): Residential ...................... .. 27,739 26,846 , 25,946 25,458 24,391 Commercial. . . . . . . . . . . . . . . . . . . . '. . 30,426 28,839 28,887 27~868 27,014 Industrial(l) .......................... .... 16,722 16,327 16,876 15,7~6 16,879 Agricultural(l) . -' . . .. . . . . . . . .. .'. . . " 3,739 3,069 3,932 3,631 3,478 Public street and highway lighting. . . .'. 437 , '445 ,446 438 425 , Other electric utilities. . . . , . . . . .. . . . . 167 2,358 3;291 1,213 3,172 Total energy delivered ................ .. 79,230 77 ,884 79,378 ' 74,394 75,359 Revenues (in thousands): Residential .................. °0'"..................... $2,961,788 $2,891,424 . $3,082,013 $3,033,613 $2,979,590 Commercial. . . . . . . . .'. . . . . . . . . . . '. . 2,837,111 2,793,336, 2,932,560 2,840,101 2,964,568 , ' Industrial. . . . . . . . . . . . :, . .... .. . . . . . 863,951 933,316 1,028,378 1,005,694 1,160,938 Agricultural. . . . . :. . . . . . . . . . . . . . . , 391,876 350,445 413,711 ~96,469 395,531 Public street and highway lighting .. . . " 49,209 51,195 53,183 55,372 56,154 'I Other electric utilities. . . . . . . . .. . . . . . 16,501 50,166 ,118,781 81,855 133,566 I Revenues from energy deliveries. . . 7,120,436 7,069,882 7,628,626 7,413,104 7,690,347 Miscellaneous . . . . . . . . . . . . . . . . . . . .' 162,105 161,156 (9,439) 112,303 92,538 Regulatory balancing accounts . . . . . . . . (50,780) (40,408) 71,441 (365,192) (396,578) Operating revenues. . . . . . . . . . ~ . . $7,231,761 $7,190,630 $7,690,628 $7,160,215 $7,386,307 16 ,. .. I , I I , , I I' I, i e e The following table shows certain customer infonnation: Selected Statistics: 1999 1998 1997 1996· 1995 Average annual residential usage (kWh) .................. -.... 6,905 6,776 6,627 6,571 6,377 Average billed revenues per kWh (cents per kWh): Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.68 10.77 11.88 11.9~ 12.22 Commercial ................................................... . 9.32 9.69 10.15 10.19 10.97 Industrial(l) ....... ....................................... 5.17 5.72 6.09 6.37 6.88 Agricultural( 1) ........................................ . 10.48 11.42 10.52 10.92 11.37 Net plant investment per customer ($) . . . . . . . . . . . . . . . . . . . . . . . 2,388 2,705 3,027 3,198 3,228 (1) Beginning April 1998, the sales-kWh and average billed revenues per kWh include electricity provided to direct access customers where the Utility does not earn commodity charges. Electric Generating Capacity , At the beginning of 1999, the Utility's electric generation facilities included five primarily natural gas-fueled steam power plants with 15 units, four combustion turbines, two nuclear power reactor units at Diablo Canyon, 67 hydroelectric powerhouses with 107 units, and ,the Helms hydroelectric pumped storage plant (Helms) with three units. In 1998, the Utility sold three of its fossil-fueled power plants. In April and May 1999, the Utility sold three of its five remaining fossil-fueled power plants, which include 10 steam units and three combustion turbines, and its geothennal energy complex of 14 units. Together, the seven divested power plants represented 91 % of the Utility's fossil-fueled generating capacity and all of its. geothennal generating capacity. The facilities generated approximately 31 % of the Utility's total electric energy production. The Utility is committed under long-tenn contracts to purchase power produced by other generating entities that use a wide array of resources and technologies, including hydroelectric, wind, solar, biomass, geothennal, and cogeneration. In addition, the Utility is interconnected with electric power systems in 14 western states and British Columbia, Canada, for the purposes of buying, selling, and transmitting power. During the transition period, the Utility is required to bid or schedule into the PX and ISO markets all of the electricity generated by its power plants and electricity acquired, under conti-actual agreements with unregulated generators. 17 :, ;; e e Except as otherwise noted below, as of December 31, 1999, Pacific Gas and Electric Company owned and operated the following generating plants, all located in California, listed by energy source: ' Generation Type County Location Number of Units Net Operating _ Capacity kW Hydroelectric: Conventional Plants(l) .........:..,.......... 16 counties in Northern and ,Central California Fresno 107 3 110 2,684,100 1,212,000 , 3,896,100 Helms Pumped Storage Plant(I). . . . . . . . , . . . . . . . . Hydroelectric Subtotal . . . . . . . . . . . . . . . . . . . . , Steam Plants': Humboldt Bay. . . . . . . . .. . . . . . . . . . . . . . . . . . . .. Hunters Point(2) . . . . .'. . . . . . . . . . . : . . . . . . . . . . . Steam Subtotal. . . . . . .. . . . . . . . . . . . . . . . . . . Combustion Turbines: Hunters Point(2) . . . . . . . . . . . . .'. . . . . . . : . . . . . . . Mobile Turbines(3) . .- . . . . . . . . . . . . . . . . . . . . . . . , Combustion Turbines Subtotal ....... . . . . . . . Nuclear: Diablo Canyon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total....... .. .,....................... Humboldt Sail Francisco San Luis Obispo . 2 105,000 3 377 ,000 - 5 482,000 1 52,000 3 45,000 - A 97,000 2 2,160;000 - 121 6,635,100 - San Francisco Humboldt and Mendocino (1) In September 1999, the Utility filed an application with the CPUC to detennine the market value of the Utility's hydroelectric generating facilities and related assets through an open competitive auction. (See "Utility Operations-Electric Utility Operations-'Califomia Electric Industry Restructuring" above.) (2) In July 1998, the Utility reached an agreement with the City and County .of San Francisco regarding the Hunters Point fossil-fueled power plant, which the ISO has designated as a "must run" facility. The agreement expresses the Utility's intention to retire the plant when it is no longer needed by the ISO. (3) Listed to show capability; subject to relocation withiri the system as required. Diablo Canyon· Diablo Canyon Operations Diablo Canyon consists of two nuclear power reactor units, each capable of generating up to approximately 26 million kilowatt-hours (kWh) of electricity per day. Diablo Canyon Units 1 and 2 began comniercial operation in May 1985 and March 1986, respectively. The operating license expiration dates for Diablo Canyon Units 1 , and 2 are September 2021 and Apri12025, respectively. As of December 31, 1999, Diablo Canyon Units 1 and 2 had achitwed lifetime capacity factors of82% and 83%, respectively. The table belòw outlines Diablo Canyon's refueling schedule for the next five years. DiabloCanyon refueling outages typically are scheduled every 19 to 21 months. The schedule below assúmes that a refueling outage for a unit will last approximately thirty days, depending on the scope of the work required for a particular outagè. The schedule is subject to change in the event of unscheduled plant outages. 2000 2001 2002 2003" 2004 -' Unit 1 Refueling . . . . . . . . . . . . . . . . . Startup . . .. . . . . . .. . . . . . . .'. Unit 2 Refueling. . . . . . . . . . . . . '. . . . Startup.. . . . . . . . . . . . . . . . . . . October November ' May June February March May June February March October November 18 - !I I i! ~ Î tit , Diablo Canyon Ratemaking Since January 1, 1997, the Utility's surikcosts in Diablo Canyon are recovered from ratepayers through a sunk cost revenue requirement, at a reduced return on common equity equal to 6.77% that will remain in effect through the end of the transition period. (Sunk costs are costs associated with the facility that are fixed and unavoidable.) The Diablo Canyon sunk costs revenue requirement is being recovered as a transition cost through the TCBA. In connection with the new ratemaking, the CPUC ordered that a finàncial verification audit of Diablo Canyon plant accounts be perfonned by àIl independent accounting finn, and that the CPUC hold a proceeding to review the results of the audit, including any proposed adjustments to Diablo Canyon accounts, following the completion of the audit. On August 31, 1998, an independent accounting finnretained by the CPUC completed its financial verification audit of the December 31, 1996 Diablo Canyon plant accounts. The audit resulted in the issuance of an unqualified opiQion. The audit verified that Diablo Canyon sunk costS at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. The independent accounting finn also issued an agreed~ upon special proc~dures report, requested by the CPUC, which questioned $200 million of the $3.3 billion sunk costs. The CPUC will review the results of the audit and may seek to make adjustments to Diablo Canyon sunk costs subje¡;t to transition cost recovery. At this time, what action the CPUC may take regarding the audit, 'if any, cannot be predicted. Àlso since January 1, 1997, a perfonnance-based Incremental Cost Incentive Price (ICIP) mechanism has been used to recover Diablo Canyon's operating costs and the cost of capital additions incurred after December 31, 1996. The ICIPmechanism establishes a rate per kWh generated by the facility for the period 1997 through 2001. The CPUC-authorized ICIP prices and revenue requirement for Diablo Canyon for 2000 and 2001 are shown below. The ICIP revenues are based on an assumed capacity factor of 83.6%. Estimated Total Revenue Requirement 2000 2001 ICIP (cents per kWh) . . . . . . . . . .. . . . . . . . . . : . . . . . . . . . . . . . . . Sunk Cost Recovery ($ in millions) . . . . . , . . . . .' . . . . . . . . . . . . . . ICIP Revenues ($ in millions) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Revenue Requirement ($ in millions) . . . . . . . . . . . . . . . . . . .. 3.43 3.49 S 1,197 $1,135 542 552 - - $1,739 $1,687 - - Any variance between ICIP revenues and related costs is reflected in earnings. In October 1999, the CPUC issued a decision that will discontinue the ICIP mechanism after the transition period. After the transition' period, Diablo Canyon generation must be sold at the prevailing .market price for power. The Utility has filed' an application for rehearing of this decision. Further, pursuant to the 1997 CPUC decision establishing the IClP, the , Utility is required to begin sharing 50% of the net benefits of operating Diablo Canyon with ratepayers beginning January 1,2002. The CPUC may interpret a more recent CPUC decision to require sharing to begin at the end of " the transition period. The Utility is required to file an application with the CPUC in July 2000 with its proposal for the methods to be used in the valuation of the benefits associated with the operation of Diablo Canyon and the mechanism to be used to share these benefits with ratepayers. (See "Utility Operations-Ratemaking Mechanisms-Electric Ratemaking-PoshTransition Period Ratemaking Mechanisms" above.) Additional infonnation concerning the financial impact of Diablo' Canyon ratemakin~ is included in '''Management's Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning on ,page 5, and in Note 2 of the "Notes to Consolidated Financial Statements" beginning on page 4;0 of the 1999 Annual Report to Shareholders: ' Nuclear Fuel Supply and Disposal Pacific Gas and Electric Company, has purchase contracts for, and inventories of, uranium concentrates, uranium hexaflouride, and enriched uranium, as well as one contract for fuel fabrication. Based on current Diablo Canyon operations forecasts and a combination of existing contracts and inventories, the requirement for uranium 19 ,I ',' ~' . 'e e supply will be met through 2004, the requirement for the conversion of uranium to uranium hexaflouride will be met through 2001, arid the requirement for the ,enrichment of the uranium hexaflouride to enriched uranium will be met through 2002., The fuel fabrication contract for the two units will supply their requirements for the next , " seven operating cycles of each unit. These contracts are intended to ensure long-term fuel supply, but permit the Utility the flexibility to take advantage of short-term supply opportunities. In most cases,~e Utility's nuclear fuel contracts are requirements-based, with the Utility's obligations linked to the continued operation of Diablo Canyon. Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S. Department of Energy (DOE) is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities areiequired to provide interim storage facilities untif' permanent storage facilities ~e provided by the fedenil government. The Nuclear Waste Act mandates that one or more such permanent disposal sites be in operation by 1998. Consistent,with the law, Pacific Gas and Electric Company signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site,' the DOE has been unable to meet its contract commitment to begin accepting spent fuel by January 1998. Further, under the DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may not be accepted by the DOE for interim or permanent storage before 2010, at the earliest. At the projected level of operation for Diablo Canyon, the Utility's facilities are sufficient to store ,on-site all spent fuel produced through approximately 2006 while maintaining the capability for a full-core off- load. It is likely that an interim or permanent DOE storage facility will not be ayailable for Diablo Canyon'-s spentfuel by 2006. The Utility is, eXamining. options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility. In July 1988, the NRC gave final approval to the Utility to store radioactive waste from the nuclear. generating unit (Unit 3) at Humboldt Bay Power Plant (Humboldt) at Humboldt before ultimately decommissioning the unit. . The Utility has agreed to remove all spent fuel when the federal disposal site is available. Insurance Pacific Gas and Electric Company has insurance coverage for property damag~' and b~isiness interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). NEIL, which is owned by utilities with nuclear generating facilities, provides insurance coverage against property damage, decontamination, decommissioning, and business interruption and/or extra expenses during prolongedaccidentaI oùtages for reactor units in commercial operation. Under these insurance policies, if the imcleargenerating facility of a member utility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective premium assessments of $15 million (properly damage) 'and '$4 million (business interruption), in each case per one-Year policy period, if losses exceed the resources of NEIL. . The Utility has purchased primary insuran~e of $200 million for public liability claims resulting from' a nuclear incident. An additional $9.3 billion of coverage is provided by secondary' financial protection requi~ed by federal law and provides for loss sharing among utilities ownirig:nudear generating facilities if a costly incident occurs. If a nuclear incident res,ults in claims.in excess 0($200 million, the Utility maý be assessed up to $176 million per incident, with payments in each year' limited to a maximum of $20 million per incident. . Decommissioning Pacific Gas and Electric Company's estimated total obligation to decommission and dismantle its nuClear power facilities is $1.6 billion in 1999 dollars ($5.1 billion in future dollars). This estimate, which includes labor, materials, waste disposal charges, and other costs, is based on a 1997 decommissioning cost study. A. contingency to capture engineering, regulatory, and business environment changes is included in the total. estimated obligation. ACtual decommissioning costs ar~ expected to vary' from, this estimate because of changes in the assumed dates of decommissioning, regulatory requirements, and technology, as well as differences in the 20. .....,y-- .-- -:; '-,:ì - -- amount of labor, materials, and equipment needed to complete decommissioning. The estimated total obligation needed to complete decommissioning is recognized proportionately over the li~ense term of each facility. Nuclear decommissioning costs recovered in ratés are placed in external trust funds. These funds: along with , accumulated earnings, will be 'used exclusively for decommissioning and dismantling the nuclear facilities. The trust funds maintain substantially all of their investments in debt and equity securities. All earnings on the trust fund, net of authorized disbursements from the trUsts and management and administrative fees, are reinvested. Monies may not be released from the external trust funds until authorized by the CPUc. In' December 1997, the CPUC granted the Utility's request for authority to disburse up to $15.7 million from the Humboldt Bay Power 'Plant decommissioning trust funds to finance three partial nuclear decommissioning projects at Humboldt Bay Power Plant Unit 3. Accordingly, as of December 31; 1999, $9.3 million (net of taxes) has been disbursed from thè Humboldt Bay Power Plant Unit 3 non-tax-qualified trust to reimburse the Utility for nuclear decommissioning expenses associated with the partial decommissioning projects. The remaining $6.4 million of the approved expenses is expected to be funded with associated tax savings. In its 1999 GRC, Pacific Gas and Electric Company sought approval from the CPUC to use the tax savings resulting from the payment of tax-deductible nuclear decommissioning expenses from the Humboldt Bay Power Plant Unit 3 non-tax-quallfied trust to fund nuclear decommissioning work. The CPUC found that the Utility's recommended approach of using the tax benefit to fund decommissioning activity was reasonable and approved the Utility's request. As of December 31, 1999, the Utility had accumulated external trust funds with an estimated fair value of $1.3 billion, based on quoted market prices and net of deferred taxes on unrealized gains, to be used for the decommissioning of thè Utility's nuclear facilities. . The amount recovered in rates for nuclear decommissioning costs is authorized by the CPUC as part of the GRC. The CPUC considers the trusts~ asset levels, together with revised earnings and decommissioning cost assumptions, to determine the amount of decommissioning costs it will authorize in rates for contribution to the trusts. The monies contributed to the decommissioning trusts, together with existing trust fund balances and projected earnings, are intended to satisfy the estimated future obligation for decommissioning c'osts. For the year ended December 31, 1999, annual nuclear decommissioning trust contributions collected in rates were $26.47 million. Since January 1, 1998, nuclear decommissioning costs, which are not transition costs, have been recovered through a nonbypassable charge that will continue until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. The CPUC has established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and to establish the 'annual revenue requirement and attrition factors over subsequent three-year periods when and if GRCs are discontinued. Other Electric Resources QF Generation and OtherPower Purchase Contracts By federal law, Pacific Gas and Electric Company is required to purchase electric energy and capacity provided by independent powerproducers that are qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA). The CPUC established a series of QF long-term power purchase contracts and set the applicable terms, conditions, price options, and eligibility reqUirements. Under the~e contracts, the Utility is required to make payments only when energy is supplied (an "energy payment") or when capacity commitments are met (a "capacity payment"). Costs associated with these contracts to purchase power are eligible for recovery by the Utility as transition costs through the collection of the nonbypassable CTC. The Utility's contracts with these power producers expire on various dates through 2028. Deliveries from these power producers account for approximately 23% of the Utility's 1999 electric energy requirements and no' single contract accounted for more than 5% of the Utility's energy needs. 21 -~"",,-------=------------- ~ --~ . e The Utility has negotiated with several QFs for early termination of their power purchase contracts. For other contracts, the, Utility has negotiated with QFs to refrain from producing energy during tlÍe remaining term of the higher fixed energy price period under their contract (a "buy-down") or to curtail energy production for shorter periods of time (a "curtailment"). At December 31, 1999, the total discounted future payments due under the renegotiated contracts that are subject to early termination, buy-dòwn or curtailment, was $16 ~illion. Of the $16 million, the Utility has recovered $6.6 million in rates and expects to recover the remaining $9.4 million in future rates. As of December 31, 1999, the Utility had commitments to purchase approximately 5,200 MW of capacity under CPUC-mandatedpower purchase agreements. Of the 5,200 MW, approximately 4,500 MW are operational. Development of the majority of the balance is uncertain arid it is' estimated that very few of the remaining contracts will become operational. The 4,500 MW of operational capacity consists of 2,800 Mw from co-generation projects, 700 MW from wind projects, and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. The Utility also has contracts with various irrigation districts and wátet agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the supplier's retention of the FERC's authori~tion) and, variable payments for operation and maintenance costs incurred by the suppliers. These conti-acts expire on various dates from 2004 to 2031. Costs associated with these contracts to purchase power are eligible for recovery by the Utility as transition costs through the collection of the nonbypassable CTC. At December 31, 1999, the undiscounted future minimum payments under these contracts are approximately $32.7 million for each òf the years 2000 through 2004 and a total of $280 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 5.8% of the Utility's 1999 electric energy requirements. The amount of energy received and the total payments made under all these power pùrchase contracts were: 1999 1998 1997 ---- , Kilowatt-hours received. . . . .. .- . . . . . . . . . . . . . . . . ... .-. . . Energy payments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capacity payments ....................:.........'... Irrigation district and water agency payments . . . . . . . . . . . . . . (in millions) 25,91025,994 24,389. $ 837 $ 943 $1;157 $ 539 $ 529 $ 538 $ 60 $ 53. $ ,56 Electric Transmission and Distribution To transport energy to load centers,P~cific Gas and Electric Company as of December 3Í, 1999, owned approximately 18,624 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and . transmission substations having a capacity of approximately 42,106,600 kilovolt-amperes (kVa), including spares, excluding power plant interconnection facilities; Energy is distributed to customers through approximately 113,289 circuit miles of distribution system and distribution substations having a capacity of' approximately 23,773,000 kVa. In 1998, the utilities relinquished control; but not ownership, of their transmission facilities to the ISO. The ISO commenced operations on March 31, 1998. The ISO, regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminaiorybasis. In 1998, the FERC approved the various forms of agreements for must-run facilities that have beenentêred into between the utilities and the ISO to ensure grid reliability. . The FERC also has approved a proposal from Pacific Gas and Electric Company and the other California utilities that distinguishes between local distribution facilities and transmission facilities. The FERC will have jurisdiction over the transmission facilities as defined in the order and over the transmissiori aspects of direct access. Most of the Utility's distribution services remain subject to CPUCjurisdiction. · 22 'v - e' " I I The CPUC is considering whether it should pursue further reforms in the stI'4cture and regulatory framework governing electricity distribution service. See "Utility Operations~Electric Utility Operations- California Electric Industry Restructuring" above: . Duririg 1999, the Utility and various other parties, including the ISO and the C~UC, issued reports on their investigation into the power outage that occurred on December 8, 1998, in the San Francisco Bay area. In March' 1999~ the ISO issued its report on the outage that concluded that the Utility's system was designed in accordance with industry standards and responded as expected under the circumstances. The ISO's report identified a number of measures for the Utility to undertake to minimize the likelihood of a similar event occurring in the future. Reports by other parties, including the CPUC, have also recommended corrective measures. Since the outage, the Utility has revised its grounding and switching procedures as preventive measures to minimize the risk that the type of initiating event that caused the outage could occur in the future. On October 20, 1999, the Utility subm.ïtted a report to the CPUC describtng how its corrective actions implements the ISO's recommendations, and responds to th~ other parties' recommendations. The CPUC is currently holding workshops to address the issues in the proceeding. After the conclusion of the workshops, the CPUC plans to convene another prehearing conference to discuss how to address any remaining issues. Gas Utility Operations I Ii I I' I Pacific Gas and Electric Company owns and operates an integrated gas transnussIOn, storage, and distribution system in California. The Utility served approximately 3.8 million gas customers at December 31, 1999. Most of these customers continue to obtàin gas supplies from the Utility under regulated tariff rates. At December 31, 1999, the Utility's system, in~luding the PG&E Expansion (Lin~ 401), consisted of approximately 6,225 miles of transmission pipelines, three gas storage facilities, and approximately 37,487 miles of gas distribution lines. The PG&E Expansionis the Utility's portion of an expansion of the interconnected natural gas transmission systems of the Utility and PG&E Gas Transmission, Northwest Corporatio? (PG&E GT- Northwest) which extends from the Canadian border into California (Pipeline Expansion). Including the portion owned by PG&E GT-Northwest (PG&E GT-NW Expansion), the 840-milecombined Pipeline Expansion provides, an additional 148 million cubic feet per day (MMcf/d) of firm capacity to the Pacific Northwest and an additional ,851 MMcf/d of capacity to Northern and Southern California. The Gas Accord resolved various issues concerning the PG&E Expansion and also established certain rules for ratemaking and terms of service applicable to th~ PG&E Expansion. The Utility's peak day send-out of gas on jts integrated system in California during the year ended December 31, 1999, was 3,503 million cubic feet (MMcf)~ The total volume of gas throughput during 1999 was . approximately 840,000 MMcf, of which 309,000 MMcf was sold to direct end-use or resale customers, . 47,000 MMcf was used by the Utility primarily for its fossil-fueled electric generating plants, and 484,000 MMcf was transported as customer-owned gas. !:' Ii , i I The California Gas Report, which presents the outlook for natural gàs requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and gas utilities as a result of a CPUC order. A comprehensive biennial report is prepared in even-numbered years with a supplemental report in intervening odd-numbered years updating recorded data for the previous year. , . . The 1998 California Gas Report updates the Utility's annual gas requirements forecast (excluding bypass volumes) for the years 1999 through 2015, forecasting average annual growth in gas throughput served by the Utility of approximately 1.5%. The'gas requirements forecast is subject to many uncertainties and there are many factors that caninfiuence the demand for natural gas, including weather conditions, level of utility electric generation, fuel switching, and new technology~ In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, may have the ability to use unr~gulated private pipelines or interstate pipelines, bypassing the Utility's system entirely. 23 . Gas Operating Statistics 'I' - , The following table shows Pacific Gas and Electric Company's operating statistics (excluding subsidiaries) for gas, including the classification of sales and revenues by type of service. ' Customers (average for the year): Residential ,................ '. . , , . . , , . . . , . . . . . , . . . . . Commercial ............,..........,.,...". '. . . . . . . . Industrial ....,.....,.................,.....,.,..... Other gas utilities ...................................,. Total.....'........."...,.·····,·,··,,···· . Gas supply-thousand cubic feet (Mcf) (in thousands): Purchased from suppliers in: Canada .,..,.,..'...,............,...........:..' California ,.".",.,.,......,........,.-..",..... Other states. . . . . . , . . . . , . , . . . . . . . . . . . , . . . . . , . . , . . Total purchased .....",.,.....,..,.,...,.,... Net (to storage) from storage. . . . . . , , . , . ... . , . . , ., . . . , , . . , Total.,...............·········:,·····,··, , Pacific Gas and Electric Company use, losses, etc.(1) . . . . . . . .-- . Net gas for sales. . . . . . , , . . . . '. . . . . . . . . . . . . . . . . , Bundled gas sales and transportation servicé-Mcf (in thousands): Residential ..,......,...... '. , . . : , . . . : . . . . . . . . . . . . , . , Commercial ....,......,................,.........., Industrial ......,...........,......,.......-.....,..,' Other gas utilities .,....",......,..,. " . . . " . . . . " . , . . , . Total ,.,....,........ ': ; . . , , . . . , . . . . . , '. , . . . . Transportation service only-Mcf (in thousands): . Vintage system (Substantially all Industrial)(2) . . . . , . , . '.',' .': , , PG&E Expansion (Line 401) . . . . . . . . . . . . . . .. . . . . . , . . . . . . Total ........,..,.....,..",...'...., - . . - . . ~ - , Revenues (in thousands): Bundled gas sales and transportation service: Residential. . . . . . . , . . . . . . .. . . : ',' . , . . . . , . , . , . . .. .. Commercial. . . . . . . . ; . , . . . . . . . . . . . . . . . . . . . . . .-. . . . Industrial. . . . . . . . . . . . . . . . . " , .. . . . . . ; . . . . . . . , . ., " Other gas utilities. . . . . . . : . . . ',' . . . . . . . . . . . . . . . . . . . . , Bundled gas revenues . . . . . . . . . . , . . . . . . " . . , , . . , Transportation only revenue: Vintage system (Substantially all Industrial) . ...... '. . . , . PG&E Expansiqn (Line 401) ..........,.....,.....,.,. Transportation service only revenue . . . . . . . . . . . . . ' . . . . . . . ,,, 'Miscellaneous, . . . . . . . . . . . . . . . '.' ' . . . . . . . . . . , , . " ' . . . , . Regulatory balancing accoúnts . . . . . . , . . , , . . , . . . , . , .- . . . . . . Operating revenues . . . . . . . . : . . . . . . . : . . : . . . . ; . . . Years Ended December 31, 1999 1998' 1997 . 1996 1995 , 3,593,355 3,536,089 3.491,963 3,455,086 3,417,556 203,342 200.620 198,453 198,071 ,197,939 , 1,625 1,610 1,650 1,500 1,500 4' 5 3 2 2 3,798,326 . 3,738,324 3,692,069 3,654,659 3,616,997 230,808 298,125 280,084 253,209 261,800 18.956 17,724 10,655 28,130 31.158 107,226 122,342 131,074 110,604 117,538 356,990 ' 438,191 421,813 391,943 410,496 (980) ( 14,468) 14,160 6,871 ',(10,921) 356,010 423,723 435,973 398,814 399,575 47,152 129,305 173,789 134,375 129,671 308,858 294,418 262,184 264,439, 269,904 233,482 ' 223,706 191,327 190,246 191,724 70,093 66,082 60,803 62,178, 64,135 5;255 4,616 10,054 12,015 14,045 28 14 0 0 0 308,858 294,418 262,184 264,439 269,904 ' 447,867 ' 319,099 218;660 189,695 143,921 36,351 77,773 233,269 237,776 240,506 484,218 396,872 ' 451,929 427,471 384,427 $1,542,705 $1,414,313 $1,170,135' $1,109,463 $1,205,223 448,655 426,299 374,084 362,819 421,397 24,638 24,634 46,592 42,520 42,106 . 77 1,072 3,701 510 0 2,016,075 1,~66,318 1,594,512 . 1,515,312 1,668,726 267,544 232,q~8 207,160 180,197 167,325 19,091 42,194 . 90,180 85,144 82,904 286,635 274,232 . 297,340 .. 265,341 250,229 (47,311) 41,364 50.295, (9,271) (18,018) (259,648) '(448,351 ) (137,787) 57,864 (43,771) , $1,995,751 $1,733,563,. $1,804,360 $1,829,246 $1,856,499 I I :1 ,I 'I 1 I ¡., (1) Primarily includes fuel for Pacific Gas and Electric Company'sfossil-fueledgeneratÌIig plants. (2) Does not include on-system tiansportation volumes transported on the PG&E Expansion of 1,251 MMcf. 34,169 MMcf, 72,958 MMcf. , 78,552 MMcf, and 100,207 MMcffor 1999, 1998, 1997,,1996, and 1995, respectively. I I' I 24 : I I · .:. .,r'·" _ ~: e' - Years Ended December 31, 1999 1998 1997 1996 1995 65 63 55 55 56 108.5 93.0 71.7 75.7 75.3 $ 6.61 $ 6,32 $ 6.12 $ 5.83 $ 6,29 6.40 6.45 6,15 5.84 6.57 4,69 5.36 4,63 3.54 3.00 0.66 0.66 0.71 0.67 0.69 0.53 0,54 0.39 0.36 0.34 $1,011 $1,040 $1,031 $1,061 $1,025 Selected Statistics: Average annual residential usage (Mcf) , . . . . . . , . . . . . . . . . .. , . . . , . . . . . . , . . . . . . . . . Heating temperature-% of normal (I) .. . . . . . . . . . . . . . . . . . , . . , , , , , , . .. .."." Average billed bundled gas sales revenues per Mcf: Residential. . . . . . . . , . . , . , , , , . , , , . . , . . . . . . . . . . . . . . . . ',' , . . , . . , . , . . . , . . . Commercial. . . . . . . . . . . . , , . .'. , . . , . . . . . . . . . , . . . . . , . . . . . , . . . , . . . . . . . . . . Industrial, . . . , . . , . , . . . , . , . , , . . . . , ; . . . . . , . , . , . . , . . . . . . , . , . . . . , . . , . , . , Average billed transportation only revenue per Mcf: Vintage system. . . . . . , . . . . , . . , . , . . . , . . , . . , . . , , . . . . . . . . . . . . . . . . . . . . . . . . PG&E Expansion (Line 401) ,.,.,..,.,.....,...,...,...............,.... Net plant investment per customer (2) . , , , . , . . . . . . , . . , , . . . . . . . , : . . .- . . . . . . . . . (1) Over 100% indicates colder than normal, Natural Gas Supplies The òbjective of Pacific Gas and Electric Company's Gas Procurement Department is to maintain a balanced supply portfolio that provides supply reIü\bility and contract flexibility, minimizes costs, and fosters competition among the Utility's gas suppliers. To ensure a diverse and competitive mix of natural gas supplies to serve the Utility's customers, the Utility purchases gas directly from producers and marketers in both Canada and the United States. I! I ,I Under current CPUC regulations, the Utility purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. During the year ended December 31, 1999, approximately 65% of the Utilitis total purchases of natural gas consisted of Canadian-sourced gas transported by Canadian pipeline companies and PG&E GT-Northwest and Rocky Mountain-sourced gas transported by PG&E GT-Northwest, approximately 5% was purchased in California, approximately 22% was purchased in the U.S. Southwest and was transported primarily by the EI Paso Natural Gas Company and Transwestem Pipeline Company pipelines, and approximately 8% was purchased in the Rocky Mountains and transported by Kern River Gas Transmission Company. California purchases include supplies from various California producers and supplies transported into California by others. The following table shows the total volume and average price of gas in dollars per thousand cubic feet (Mct) purchased by the Utility from these sources during each of the last five years. I, I 1999 1998 1997 1996 1995 Thousands Avg. Thousands Avg. Thousands Avg, Thousands Avg. Thousands Avg. of Mcf Price(l) of Mcf Priee(l) of Mef Price(l) of Mcf Priee(l) of Mef Priee( 1) Canada,.......... 230,808 $2.50 298.125 $2.00 280,084 $1.77 253.209 $1.57 261,800 $1.34 California .. . . .. . . . 18,956 2.45 17,724 2.44 10,655 2.12 28.130 1.90 31,158 1.32 Other states (substantially all U.S. Southwest) . . . 107,227 2.42 122,342 2.62 131,074 3.75 110,604 3.72 117,538 2.64 Tota1lW eighted 391,943 Average ..,:.... 356,991 $2.47 438,191 $2,19 421,813 $2.39 $2.21 410,496 $1.71 - - - - - - - - - - 'I (1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges, and other pipeline assessments, including direct bills allocated over'the quantities received at the California border. Beginning March 1; 1998, the average price for gas also includes intrastate pipeline dem:nd and reservation charges. These costs previously were bundled in gas rates. ' I I Gas Regulatory Framework In August 1997, the CPUC approved the Gas Accord, which restructured Pacific Gas and Electric Company's gas services and its role in the gas market. Among other matters, the Gas Accord separates, or "unbundles," the rates for the Utility's gas transmission services from its distribution services. As a result of I' I 25 e ~ " " e the Gas Accord, the Utility's customers may buy gas directly from competing suppliers and purchase transmission- only and distribution-only seryic~s from the Utility. Most of the Utility's industrial and larger commercial customers (noncore customers) now purchase their gas from marketers and brokers. ,Substantially all residential and smaller commercial customers (core customers) buy gas as well as traÌlsmission and distribution services from the Utility as a bundled service. Customer rates for gas are updated on a monthly basis to reflect changes in the Utility's gas procurement costs. The Gas Accord established an incentive mechanism (the core procurement incentive mechanism or CPIM) for recovery of the Utility's core gas procurement costs as described below. The Gas Accord also established gas transmission and storage rates for the period from March 1998 through December 31, 2002. Rates for gas distribution service còntinue to be set by the CPUC in BCAP proceedings, and are designed to provide the Utility an opportunity to recover its costs of service and includé a return on investment. See "Utility Operations-California Ratemaking Mechanisms~as Ratemaking-:-The, Biennial Cost Allocation Proceeding (BCAP)." The CPUC is considering further changes in California's natural gas industry. Additional information concerning gas industry restructuring, and the fmancial impact of these changes on PG&E Corporation, is provided, in "Management's Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning.on page 5. Transportation Commitments . ' Pacific Gas and Electric Company has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm capacity on, the pipelines. The total demand charges that the Utility wilL pay each year may change due to changes in tariffrates. The total demand and volumetric transportation charges paid by the Utility UIìder these agreements were approximately $97 million in 1999. This amount includes payments madè to PG&E GT~ Northwest of approximately $47 million in 1999, which are eliminated in the consolidated finançial statements of PG&E Corporation. ·1 II As' a result of regulatory changes, the Utility nò longer procures gas for most of its noncore customers, resulting in a decrease in thè Utility's need for firm transportation capacity for its gas purchases. Thè Utility' continues to procure gas for almost all of its core customers and those noncore customers who choose bundled service (core subscription customers). The Utility is continuing its efforts to broker or assign any of its remaining contracted-for but unused interstate and Canadian transportation capacity, including unused capacity held for its core and core-subscription customers. . . Under a firm transportation agreement with PG&E GT-Northwest that runs through October 31,2005, the Utility currently retains capacity of approximately 600 MMcf/d on the PG&E GT-Northwest system to support its core and core-subscription customers. The Utility hàs been able to broker its unused capacity on PG&E GT- Northwest's system, when not needed for core and core-subscription customers. In 1992, the Utility entered into a firm transportation agreement with, Transwestern Pipeline Company (Transwestern). which expires in 2007, to hold capacity to meet core gas sales demands and electric generation needs. Since the Utility has sold most of its fossil-fueled generating plants in connection with electric industry restructuring and no longer needs natui-al gas for electric generation, the Utility permanently released 50 MMcf/d of firm capacity under ,this contract. As a result, the demand charges associated with the entire Transwestern capacity currently approximate $22 million per year. The Utility may recover de¡pand charges through the CPIM ' and through brokering activities. I :1 " I I :26 ":} .¡ II I I' " I' ,I j' " I i - e Core Procurement Incentive Mechanism ,The Utility's core gas procurement costs through 2002'are recoverable in rates under the CPIM, which provides the Utility with a direct financial incentive to procure gas and transportation services at the lowest reasonable costs. Under the CPIM, all Utility procurement costs are compared to an aggregate market-based benchmark.. If costs fall within a range (tolerance band) around the benchmark, co~ts 'are deemed reasonable and fully recoverable from ratepayers. If procurement costs fall outside the tolerance band, the Utility's ratepayers and shareholders share savings or costs, respectively. Under the Gas Accord and CPIM mechanism, all Utility procurement costs from June I, 1994 to October 31, 1998, were approved by theCPUC as reasonable. For the period from December 1, 1997 to October 31, 1998, the CPUC, with ORA support, has recognized savings outside of the tolerance band, and for that period' has awarded, approximately $2 million of the savings to shareholders. In January 20QO, the Utility filed a CPIM perfonnance report for the period of November 1, 1998, through October 31, 1999. The report detennined that all gas commodity and transportation costs for the period were within the tolerance band, and therefore should be deemed reasonable and recoverable in full from ratepayers. 27 ! " e e NATIONAL ENERGY GROUP PG&E Corporation's National Energy Group has been formed to pursue opportunities created by the gradual deregulation of the energy industry across the'nation. The National Energy Group integrates PG&E Corporation's national power generation, gas transmission, and energy trading and services businesses. The National Energy Group contemplates increasing PG&E Corporation's national market presence through a balanced program of acquisition and development of energy assets and businesses, while at the' same time undertaking ongoing portfolio manàgement of its 'assets and businesses. PG&E Corporation's ability to anticipate and capture profitable business opportunities created by deregulaÙon will have a significant impact on PG&E Corporation's future operating results. Gas Transmission Operations PG&E Corporation participates in the "midstream" portion of the gas business through PG&E GT. PG&E GT consists of three principal entities: PG&E Gas TransmÍssion, Texas Corporation, PG&E Gas Transmission Teco, Inc., and PG&E GT -Northwest. PG&E Gas Transmission, Texas COIporation and PG&E Gas Transmission Teco, Inc. are referred to collectively as PG&E Gas Transmission, Texas (PG&EGTI). The "midstream" gas business includes (1) gas gathering, processing, st()rage, and transportation of natural gas andnatural gas liquids (NGLs), and (2) the marketing of natural gas and NGLs. PG&E GT's gas transmission facilities are operated ,through offices in various cities, including Houston and San Antonio, Texas and Portland, Oregon. I I . PG&E GT competes with" among others, major' interstate and intrastate pipeline companies in the transportation of natural gas and NGLs. The principal elements of competition among pipeline companies are rates, terms of service, flexibility, and reliability of service. Natural gas competes with other forms of energy available to PG&E GT's customers and end-users, including electricity, coal, and fuel oils. A significant competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the ' level of business activity, conservation, legislation, 3;nd governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas. PG&E GT also competes with, among others, major integrated' energy companies, the -marketing affiliates of the major interstate and intrastate pipelines, national and local' gas gatherers, brokers, marketers, and distributors for natural gas supplies, in gathering and processing natural gas and in marketing natural gas and NGLs. Competition for natural gas supplies is based on a number of factors, including flexibility in contract terms and conditions, reliability, availability of transportatlon, and price for the natural gas and NGLs. Competition for sales customers is based upon, among other factors, flexibility of contract terms and conditions, reli~bility and price of delivered natural gas, and NGLs. PG&E Gas Transmission, Texas PG&E GTI owns and operates gas gathering, transportation, and processing facilities, and NGL pipelines. The NGL business inCludes the gathering óf natural gas, the extraction of NGLs from natural gas, the fractionation of mixed NGLs into component products (e.g., ethane, propane, butáne, and natural gasoline), and the transportation and marketing of NGLs. The Texas operations include approximately 6,700 miles of natural gas pipelines and joint ownership or leasehold interests in approximately 1,300 miles of pipelines, including pipelines from Waha. in west Texas to the Katy area near Houston, Texas. These pipeline ,systems have the capacity to transport more than 3 billion cubic feet (bcf) of gas per day. The Texas assets also include approximately 536 miles of NGL pipelines and nine natural gas processing plants with a còmbined capacity of approximately 1.6 bcf per day of gas throughput, capable of producing approximately 100,000 barrels per day of NGLs, and a long-term lease of 7.2 bcf of storage capacity. PG&E GTI participates in all areas of the midstream portion of the gas business.' PG&E GTI markets g~s to gas distribution companies, electric utilities, municipalities, marketers, in,dependent power producers, and end-use customers. It also transports natural gas for these customers, producers, and other pipelines, and markets and transports NGLs to various customers, including end-use customers. . 28 4" -t e e On January 27, 2000, PG&E Corporation's National Energy Group signed a definitive agreement with EÏ Paso Field Services Company providing for the sale to EI Paso Field Services Company, a subsidiary of EI, Paso Energy Corporation, of the stock of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. (collectively PG&E GTT). Closing of the sale, which is expected near the end of the first half of 2000, , is subject to approval under the Hart Scott Rodino Act. . Additional infonnation concerning the sale of PG&E GTI is provided in "Management's Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning on page 5, and in Note 5 of the "Notes to Consolidated Financial Statements" beginning on page 47 of the 1999 Annual Report to Shareholders. PG&E GT-Northwest PG&E GT-Northwest owns and operates gas transmission pipelines .and associated facilities which extend over 612 nples from the Canada-U.S. border to the Oregon-California border. PG&E GT-Northwest participates in the midstream portion of the gas business by providing finn and interruptible transportation services to third party shippers on an open access, nondiscriminatory basis. Its customers are principally retail gas distribution utilities, electric utilities that use natural gas to generate electricity, natnral.gas marketing companies, natural gas producers, and industrial companies. PG&E GT-Northwest's largest customer in 1999 was Pacific Gas and Electric Company, accounting for approximately $49 million, or 23.5% of its transportation revenues. PG&E GT-Northwest's mainline system is composed of two parallel pipelines with 12 compressor stations totaling approximately 408,660 International Standards Organization (ISO) installed horsepower and ancillary facilities, including metering, regulating facilities, and a communications system. The dual pipeline system consists of approximately 639 miles of 36-inch diameter gas transmission line (612 miles of single 36-inch diameter pipe and 27 miles of 36-inch diameter pipeline looping) and approximately 590 miles of 42-inch diameter pipe. In addition, in 1995, PG&E GT-Northwest constructed two lateral pipeline extensions, adding approximately 84 miles of 12-inch diameter pipe, and 22 miles of 16-inch diameter pipe to serve its customers on those laterals. PG&E GT-Northwest's total transportation quantities for 1995 through 1999 are set forth in the following table. Year Quantities (in thousand decathenns (MDt» 885,186 934,029 969,257 1,003,266 839;778 .1995 . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . ',' ,1996 ................ .............. ............ .............. 1997 :.....:.... ......... .'... .... ... ................ ........ 1998 ........... ...... ..............;. .'..................... 1999 .. ......... ................. ................. .'......... PG&E GT-Northwest's current rates were set in a rate settlement approved by the FERC in September 1996. In 1998, petitions filed by various parties for rehearing of the FERC order approving the settlement were denied. Three parties have appealed the FERC's denial of these rehearing petitions to the U.S. Court of Appeals for the District of Columbia Circuit. On February 1, 2000, the appellate court denied the petitions for review and reáffinned the FERC settlement. Additional infonnation concerning PG&E Corporation's gas transrmSSlOn operations is provided in "Management's Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning on page 5" and in Note 17 of the "Notes to Consolidated Financial Statements" beginning on page 63 of the 1999 Annual Report to Sharehoiders. ' . 29 ~. '" e e Independent Power Generation Through PG&E Gen and its affiliates, PG&E Corporation participates in, the development, construction, operation, ownership, and management of non~utility electric generating facilities that compete in the United States power generation market. PG&E Gen is headquartered in Bethesda, Maryland., As of December 31,1999, PG&E Gen affiliates had ownership interests in 30 operating plants in 10 states. The total generating capacity of th~se 30 plants is approximately 6,560 MW. Ten of these plants operate as QFs with a combined capacity of 2,128 MW which is sold at fixed ,prices under long-tenn power purchase agreements. The remaining plants with a combined capacity of 4,435 MW are operated as merchant power plants that sell their power directly to wholesale customers (including other PG&E Corporation affiliates) at prevailing market prices. PQ&E Corporation;s combined net equity ownership and leased interest in these plants as of December3l, 1999, represented approximately 5,200 MW. The plants were financed largely with a combination of non-recourse debt and equity or equity commitments from the project sponsors. PG&E Gen. throligh its affiliate, PG&E Operating Services Company (PG&E OSC), provides contract operations and' maintenance services to many of these facilities. PG&E Gen also manages power purchase agreements with an aggregate of 789 MW of capacity. PG&E Gen and its affiliated or managed facilities,sold 29,187,905 megawatt':hours (MWh) of electricity in 1999. PG&E Gen also is engaged in the "greenfield" development of ' new merchant power plants, as discussed below. PG&E Gen competes with unaffiliated utilities and other independent power producers. New England Operations In 1998, PG&E Corporation, through its indirect subsidiary, USGenNE, purchased from the New England Electric System (NEES) a portfolio of electric generating assets with a combined generating capacity of about 4,000 MW. In addition, USGenNE assumed NEES' obligations to purchase power from various independent power producers (IPPs). As of December 31, 1999 these power purchase obligations represented an additional 470 MW of production capacity. NEES is required to make annual support payments to USGenNE through early 2008 to offset the cost of power associated with the~e abòve-market contracts. Finally, in connection with the NEES acquisition, USGenNE obtained the right to purchase NEES's nuclear generated electric energy, capacity, and associated products at market prices up to the entire amount available. In December 1999, USGenNE sold these nuclear entitlements. I , Three of the four states in which USGenNE operates generation facilities (Massachusetts, 'Rhode Island,' and New Hampshire) were, like California, among the first states in the COUlltry to introduce retail competition. As part of electric industry restructuring in these New England states, local utility companies were required to offer, standard offer service (SOS) to their retail customers. Retail customers may select alternate suppliers at any time. The SOS is intended to provide customers with a price benefit (the commodity electric price offered to the retail customer under SOS is expected to be less than the market price for the first several years), followed by a price disincentive that is intended to stimulate the retail market. Connecticut also has passed retail competition,legislation. " The New England assets are located within the New England Power Pool (NEPOOL)., The wholesale' electricity market in New England features a bid-based, real-time pricing structure. Traditionally,NEPOOLhas operated as a "tight power pool," one in which the utilities within the pool dedicate their generation resources to be centrally dispatched. Dispatch starts with the lowest-cost generation, and ends with the highest-cost generation. An independent system operator for the New England states, (ISO-NE) provides' central dispatch service and operates the power pool as a competitive wholesale marketplace. The duties of the ISO-NE include scheduling the operations of the regional transmission systems and, importantly, operating a power exchange for seven generation products (the "Interchange"). These products are energy, installed (monthly) capacity" operable (hourly) capacity, three types of reserves, and automatic generation control (adjustment of geneT'"" meet the second-to-second changes in electric load). 30 J .' e "~'!:l-~.--~ n~.' " ,-. ..- .; -..... , '.·of ;:'~"':.:...-' '. Additional information concerning the New England electricity market and the Corporation's New England operations is provided in "Månagement' s Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning on page 5." " Portfolio of Operating Generating Plants The following table sets forth, information regarding the operating generating plants in wmch PG&E Gen affiliates have an ownership or leasehold interest. Except as otherwise noted, PG&E Gen affiliates also manage or operate, or both manage and operate, power plant operations. Plant Ii ! Bear Swamp Facility(1),(2) Pumped Storage 2 Units. . . . . . . . _ Fife Brook . . . . . . . . . . . . . . . . . . . . Brayton Point Station(2) Unit Nos. 1,2, and 3 ........... Unit No.4. . . . . . . . . . . . . . . . . . . Diesel Generators ................. Carneys Point ............... . . . . . Cedar Bay . . . . . . . . .' . . . . . . . . . . . . . '. Connecticut River(2) Hydroelèctric 26 Units . . . . . . . . . . Deertìeld River(2) Hydroelectric 15 Units . . . . . . . . . . Herrniston . . . . . . .'. . . . . . , . . . . . . . . . Indiantown ...................... Logan . ',' . . . . . . . . . . . . , . . . . . . . . . . Manchester, St. Station(2) 3 Combined Cycle Units. . . . . . . . . MASSPOVVER ... .... ............ Northampton . . . . . . . . . .. . . . . . . . . . . Pittsfield( 1) . . . . . . . . . . . . . . ~ . .'. . . '. . Salem Harbor Station(2) Unit Nos. 1, 2, and 3 ........... Unit No.4. . . . . . . . . . . . .. . . . . . Scrubgrass . . . . . . . . . . . . . . . . . . . . . . . Selkirk ......................... Total MVVs/Operating Plants. . PG&E Gen Affiliate Investments: Colstrip(3) . . . . . . . . . . . . . . . . . . . . . . . Panther Creek(3) . . . . . . . . . . . . . , . . . . Total MVVs from Investments. . Total MVVs in Operation(4) . ~ . I I, II I' 11 MWs 1,130 446 10 260 250 314 400 83 345 6,443 37 83 120 ·6,563 - Fuel 588 10 Hydro Hydro Location . Date Placed in Commercial Service I 1 ~I Coal OiVGas Diesel Oil Coal Coal 484 Hydro Massachusetts 1974 1974 84 474 330 225 Hydro Natural Gas Coal Coal Massachusetts 1963, '64,,'69 1974 N/A 1994 1994 495 240 110 165 Natural Gas Natural Gas Waste Coal Natural Gas New Jersey Florida Ne~ HampshireN ermont 1909-1957 1912-1927 1996 1995 1995 Coal Oil Waste Coal Natural Gas Waste Coal Waste Coal MassachusettsN ermont Oregon Florida New Jersey Rhode Island Massachusetts Pennsylvania Massachusetts 1995 1993 1995 1990 Massachusetts 1952, '52, '58 1972 1993 1992, '94 Pennsylvania New York Montana Pennsylvania 1990 1992 (1) Unlike other operating facilities in whichPG&E Gen affiliates have ownership and management interests, the Bear Swamp Facility and the Pittsfield plant are owned by third parties through a single-investor lease arrangement. PG&E Gen maintains full management and operating responsibility for the facilities and is entitled to the output. (2) Acquired from NEES on September 1, 1998. (3)PG&E Gen affiliates have an ownership or leasehold interest in these plants, but donot manage power plant operations. (4) Of the total of 6,563 megawatts in operation, PG&E Gen' s net equity ownership and leased percentage interest in the total is 5,225 megawatts. 31 - !- ",- e Generation Development Projects Nationwide, PG&E Gen's greenfield power plant development activities exceed 10,000 MW in 9 states. The table below lists PG&E Gen's development projects, The Millennium Project in Charlton, Massa:::husetts (360 MW) and the Lake Road Project' in Killingly, Connecticut (792 MW) are under construction. The La Paloma Project . in McKittrick, California (1,048 M~) has been approved by PG&E Corporation's Board of Directors and the . California Energy Commission. The other development projects 'listed below are in the early stages of the development process. The completion of these planned projects is subject to many factors, including but not limited to various regulatory and environmental approvals, adequate financing on satisfactory terms, competitive conditions including the expansion and retirement plans of others, market prices for electricity, and future fuel pnces. Plant Millennium. . . . " . : . . . . . Lake Road ...... .. . . . . . . La .t'aloma .... '. . . . . . . . . Madison . . . . . . . . : . . . . . .- Brayton V . . : . . . . . . . . . . . Athens . . . . , . . . . . . . . . . '. Covert '................- Badger . . .. . . . . . . . . . . . . Liberty . . . . . . . . . . . . . . . . Mantua Creek'. . . . .'. . . . . . Otay Mes¡¡ ,............ Harquahala . . . . . . . . . . . . . Okeechobee ..........., Estimated start of commercial MW Fuel Location service 360 Natural gas . Massàchusetts 4Q2000 792 Natural gas Connecticut 2Q 2001 1,048 Natural gas California 1 Q 2002 12 Wind New York 3Q 2000 -800 ,Natural gas Massachusetts . '4Q 2002 1,080 Natural gas New York 1 Q 2002 1,02~ Na~ural gas Michigan 3Q 2002 1,022 Natural gas Wisconsin ., 3Q 2002 , 1,048 Natural gas New Jersey 3Q 2002 800 Natural gas New Jersey 1 Q 2902 510 Natural gas California 3Q 2002 1,000 Natural gas Arizona 3Q 2003 550 Natural gas , Florida, 2Q 2004, Energy Trading PG&E Energy Trading-Gas Corporation and PG&E Energy Trading-Power, L.P. (also collectively referred to as' PG&E ET), headquartered in Houston, Texas, purchase electric power from PG&E Corporation affiliates and the wholesale market and natural gas from producers, marketers, and .other parties. PG&E ET then scÞ.edules, transports, and resells these commodities, either to third parties or to other PG&E Corporation affiliates (except the Utility). PG&E ET also provides risk management services to PG&E Corporation"s other businesses (except the Utility) and to unaffiliated wholesale customers. For more information, see "General~Risk Ma~agement Programs" above. ' , ~ ; I I PG&E ET competes with, among others; major integrated energy companies, marketing affiliates of major interstate pipelines, brokers, gas marketers, and gas distributors for natural gás supplies and/or in marketing natural gas. In addition, PG&E ET competes with ~naffiliat~ eiectric utilities, marketers, and other ,entities in purchasÍng and selling electric power arid other energy commodities. Competition in' the energy marketing business is driven by various factors, induding the price of commodities and services delivered along with 'quality and reliability of services delivered. ' Additional information concerning the wholesale operations 'of PG&E torpor~tion's 'affiliates is provided in ,"Management's Discussion and Analysis" in the 1999 Amiual Report to Shareholders, beginning on page 5, and in Note 17 of the "Notes to Consolidated I:ina~cial Statements" beginning on page 63 of the 1999 AnImal Report to Shareholders. ' ' . 'I I, 32 .; .. I I ~ Ii I I' I I e e Energy Services PG&E Energy Services (PG&E ES), headquartered in San Francisco, California, provides retail gas and electric commodities nationwide, where pennitted under applicable laws, and provides energy-related value- added services, ,including billing and infonnation management services, energy efficiency and other energy managem~nt services, regulatory and rate analysis, and power quality solutions. PG&E ES targets primarily industrial, commercial, and institutional customers, offering comprehensive energy management solutions to reduce their energy costs and improve their productivity. PG&E ES has 20 offices nationwide to súpport its sales activities. PG&E ES currently competes with other non-utility electric retailers in California for direct access customers. See "Utility Operations-Electric Utility Operations-California Electric Industry Restructuring" above. In December 1999, PG&E Corporation's Board of Directors approved a plan to dispose of PG&E ES, its wholly owned subsidiary, through a sale: The intended disposal has been accounted for as a discontinued operation in PG&E Corporation's 1999 financial statements. While there is no definitive sales agreement, it is expected that the disposition will be completed by June 2000. Additional infonnation concerning PG&E ES is provided in "Management's Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning on page 5, and in Notes 5 and 17 of the "Notes to Consolidated Financial Statements" beginning on pages 47 and 63, respectively, of the 1999 Annual Report to Shareholders. 33 .~. -- e ENVIRONMENTAL MATTERS Environmental Matters The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of envirònmental compliance. This information below reflects current ,estimates, which are periodically evaluated and revised. Future estimates and actual results may differ materially.from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, and the availability of recovèries or contributions from third parties. PG&E Corporation, the Utility, PG&E Gen and its affiliates (including USGenNE), and other PG&E Corporation subsidiaries' and affiliates are subject to a number of federal, state, and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, air and water pollution, and treatment, storage, and disposal of hazardous, or toxic materials. These laws and regulations affect futùre planning' and existing operations, including environmental protection and remediation activities. The Utiliry has undertaken compliance efforts with specific emphasis on its purchase, use, and disposal of hazardO\,ls materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of the Utility's bulk waste handling and storage facilities. , ' The costs of compliance with environmental laws and regulations generally have been recovered in rates. Although the Utility has sold most of its fossil-fueled power plants and its geothermal generation facilities in connection with electric industry restructuring, the Utility has retained liability for certain required environmental remediation of pre-closing soil or groundwater contamination for fossil and geothermal generation facilities that have been sold. See "Utility Operations-Electric' Utility Operations-California Electric Industry Restructuring-Voluntary Generation Asset Divestiture" above. Environmental Protection Measures The estimated expenditures of PG&E Corporation's subsidiarie's for- environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. It is likely that the stringency of environmental regulations will increase in the future. As a result of the Utility's divestiture of most of its fossil-fueled power plants and its geothermal generation facilities, the Utility's oxides of nitrogen '(NOx) emission reµùction compliance costs have been reduced significaÍ1tly. Air Quality Pacific Gas and Electric Company's thermal electric generating plants are subject to numerous air pollution control laws, including the California Clean Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal Clean Air Act, two of the local air districts in which the Utility owns and opei-ates ~ossil-fueled generating plants have adopted final rules that require a reduètion in NOx emissions from the power plants of approximat~ly 90% by 2004 (with numerous interim compliance deadlines). The Gas Accord authorizes $42 million to be included in rates through 2002, for gas NOx retrofit projects related to natural gas compressor stations on Pacific Gas and Electric Company's Line 300, which delivers gas from the Southwest. Other air districts are considering NOx rules that would apply to the Utility's other natural gas compressor stations in California. Eventually the rules are likely to require NOx reductions of up to 80% at many of these natural gas compressor stations. The Utility currently estimates that the total cost of complying with these ~arious NOx rules will be up to $51 million over three years. Substantially all of these costs will be capital costs. 34 '....~:} - ,-..,'........ P'~:~, U"<,-,~,.'('~¡,,,.~.,,. '''';'- . e e Ii I I, Ii I' .! PG&E Gen's compliance with certain future regulatory requirements limiting the total amount of NOx emissions from its fossil-fueled power plants is expected to be achieved through installation of additional controls, fuel switching, and purchase of NOx allowances. USGenNE has agreed to be bound by a number of state and regional initiatives that will require it to achieve significant reductions of sulfur dioxide (S02) and NOx emissions by the time its olderofossil-fueled power plants have been in operation for 40, years or by 2010, whichever comes first. It IS expected that USGenNE can meet these requirements· through utiliZation of allowances it currently owns, installation of additional controls, or purchase of additional allowances. (S02 allowances are emission credits that are traded in a national market under the United States Environmental Protection Agency's (EP A) Acid Rain Program. NOx allo~ances are emission credits that are traded in a regional market consisting of seven Northeast states known as the Ozone Transport Region.) It is estimated that USGenNE's total cost of complying with these requirements will be up to $4 million through the year 2001. ' I .1 I: I 'I II I, Water Quality I " 1 , , Pacific Gas arid Electric Company's existing power plants, including Diablo Canyon, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility's fossil- fueled power plants comply in all material respects with the discharge constituents standards and either comply . in all material respects with or are exempt from the thermal standards. A therrÌ1al effects study at Diablo Canyon was completed in May 1988: and was reyiewed by the Central Coast Regional Water Quality Control Board (Central Coast Board). The Central Coast Board did not make a final decision on the report and requested that the Utility continue its thermal effects monitoring program. In 1995, the Central Coast Board requested that the Utility prepare an updated comprehensive assessment of Diablo Canyon's thermal effects and approved a reduced environmental monitoring program. A comprehensive statistical analysis of Diablo Canyon's thermal effects was submitted to the Central Coast Board in December 1997 and a regulatory assessment was submitted in November 1998. If the Central Coast Board finds that Diablo Canyon's existing thermal limits are not protective of beneficial uses of the marine waters, major modifications (e.g., cooling towers) resulting in additional construction expenditures, or reduced power operation, could be required. I: ,I Pursuant to the federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction, and capacity of power plant cooling water intake structures reflect the best techilology available (BTA)for IDinimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility hàs submitted detailed studies of each power plant's intake structure to various governmental agencies. Each plant's existing,watet intake structure was found to meet the BTA requirements. The Utility currently is completing a new study for Diablo Canyon. The study is scheduled to be submitted to the Central Coast Board for review in 20oo~ If the Central Coast Board fin~s that Diablo Canyon's cooling water intake structure does not meet the BTA requirements, additional expenses for construction o~ mitigation could be required. In addition, the promulgation or modificiition of statutes, regulations, or water quality control plans at the federal, state, or regional'level may "impose increasingly stringent cooling water discharge requirements on the Utility's remaining power plants in the future. Costs to comply with renewed permit conditions required to meet any more stringent . requirements that might be imposed cannot be estimated at ,the present time. In December 1999, the Utility was notified by the purchasèr of its former Moss Landing power plant that that it had identified a cleaning procedure used at, the plant that released heated water from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Board. The purchaser notified the Central Coast Board of its findings and the Central Coast Board requested additional information from the purchaser. The Utility has initiated an investigation of these activities during the time it owned the plant. The Central 'Coast Board has been notifÍed of the investigation and the results will be presented to the Central Coast Board when the investigation is complete. If the identified procedure was performed during the Utility's ownership and was beyond the scope of the relevant NPDES permits, the Central Coast Board may choose to initiate an enforcement action. If so, the Utility could be subject to significant penalties. Until the investigation is comph~te and the results discussed with the Central Coast Board, it is not possible to determine whether the Utility will suffer a loss in connection with this matter or to provide a more detailed estimate of such liability. I 35 i . - PG&EGen's existing power plants, .including USGenNE facilities, are subject to federal and state water quality standards with respect to discharge constituents and thennal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating in compliance with NPDES pennits that have expired. As to the facilities for which the NPDES pennit has expired, new pennit applications are pending, and it is anticipated that all three facilities will be able to êontinue to operate under existing tenns 'and conditions until new pennits are issued. USGenNE has submitted a pennitrenewal application and is negotiating with EPA on ongoing studies and pennit conditions. It is estimated that USGenNE's cost tq comply with these conditions could be as much as $5 million through the year 2001. 'Hazardous Waste CoìnplÙl;nce and Remediation PG&E Corporation subsidiaries assess, on an ongoing, basis, measures that may need to be taken to comply . with laws and regulations related to hazardous materials and hazardous waste compliance and remediation" activities. The Utility has a comprehensive program to comply with màny hazardous waste storage, handling~ and disposal requirements promulgated by the EP A under the Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along'withother state hazardous waste'laws and other environmental requirements. ' One part of this program is aimed at assessing whether and t() what extent remedial action may be necessary~ to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation, manufactured gas plants produced lampblack and tar residues, byproducts of a process that Pacific Gas and Electric Company, its predecessor companies, and other utilities used as early as the 1850s to ,manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Utility'š manufactured gas plants were, removed from serviCe. The residues that II).ay remain at some 'sites contain chemical compounds 'that now are classified as hazardous. The Utility has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites that operåted in the Utility's service territory: The Utility owns all or a portion of 29 of these manufactured gas plant sites. The Utility has a program, in coopération with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites that the Utility owns. It is estimated that the Utility's program may result in . expenditures of approximately $5 million in 2000. The fulllong~tenn costs of the program cannot be detennined accurately until a closer study of each site has. been completed. It is expected that expenses will increase as remedial actions related to these sites are approved by regulatory agencies or if the Utility is found to be responsible for cleanup at sites it currently does not own. - In addition to the manufactured gas plant sites, the Utility may be required to take remediaÌ action at certain other disposal sites if they are detennined' to present' a significant threat to human health and the environment because of an actual or potential release of hazardous substances. The Utility has been designated as a potentially responsible party (PRP) under CERCLA (the federal Superfund law) with respect to the PRC Patterson site in Patterson, California, and the Industrial Waste Processing site near Fresno, California. With respect to' the Casmalia site near Santa Maria, California, the Utility and several other generators of waste sent to the site have' entered into a court-approved· agreement with, the EP A that requires these generators, to' perform certain site investigation and mitigation measures, and provides a release from liability for' certain other site cleanup obligations. Although the Utility has not been fonnally designated a PRP with respect to the Geothennal Incorporated site in Lake County; California, the Central Valley Regional' Water Quality Control Board and the California Attorney General's office have directed the Utility and other pàrties to initiate measures with respect' to the study and remediation of that site. In addition, Pacific Gas and Electric Company has been named as a, defëndant in several civil lawsuits in ,which plaintiffs allege that the Utility is responsible for peIfonning or paying for remedial action a1 sites the Utility no longer owns or never owne,d. The cost of hazardous substance remediation ultimately undertaken by Pacific Gas and Electric Company is difficult to estimate. It is reasonably possible that a change in the estimate may occur in the near tenn' due to 36 ~ 'v . ! II I I ,I ., I .1 ! I ... ...; e e uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. At December 31, 1999, the Utility expects to spend $300 million for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants, where such costs are probable and quantifiable. (Although the Utility has sold most of its fossil-fueled power plants, the Utility has retained pre-closing environmental liability with respect to these plants.) The Utility had an accrued, liability of $271 million at December 31, 1999, representing the discounted value of these costs. Environmental remediation at identified sites may be as' much as $486 million if, among other things, other PRPs are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Utility is responsible. The Utility estimated the upper limit of the range of costs using assumptions least favorable to the Utility based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for cleanup costs at additional sites or identifiab.1e possible outcomes change. PG&E Gen acquired the onsite environmental liability associated with USGenNE's acquisition of electric generating facilities from NEES, but did not acquire any offsite liability associated with the past disposal practices at the acquired facilities. PG&E Gen has obtained pollution liability and environmental remediation insurance coverage to limit the financial risk associated with the onsite pollution liability at all of its facilities. Potential Recovery of Hazardous Waste Compliance and Remediation Costs In 1994, theCPUC established a ratemaking mechanism for hazardous waste remediation costs (HWRC). That mechanism assigns 90% of the includable hazardous substance cleanup costs to uti~ty ratepayers and 10% to utility shareholderS, without a reasonableness review of such costs or of underlying activities. Under the HWRC mechanism. 70% of the ratepayer portion of Pacific Gas and Electric Company's cleanup costs is attributed to, its gas department and 30% is attributed to its eleëtric department. Insurance recoveries are assigned 70% to shareholders and 30% to ratepayers until both are reimbursed for the costs of pursuing insurance recoveries. The balance of insurance recoveries are allocated 90% to shareholders and 10% 'to ratepayers until shareholders are reimbursed for their 10% share of cleanup costs. Any unallocated funds remaining are held for five years and then distributed 60% to ratepayers and 40% to shareholders over the next five years. The Utility can seek to recover hazardous substance cleanup costs under the HWRC in the rate proceeding it deems most appropriate. In connection with electric industry restructuring, the HWRC mechanism may no longer be used to recover electric generation-related cleanup costs for contamination caused by events occurring after January 1, 1998. For each divested generation facility where the Utility retained environmental remediation liabilities, the plant's decommissioning cost estimate was adjusted by the Utility's estimated forecast of environmental remediation costs. (The buyers assumed the non-environmental decommissioning liability for these plants.) The CPUC ordered that excess recoveries of environmental and non-environmental decommissioning accruals related to the divested plants be used to offset other transition costs. As of December 31,'1999, the Utility has recovered from ratepayers approximately $114 million for environmental decommissioning accrual related to the divested plants. This amount will earn interest at 3% per year that will be used to meet the future environmental remediation costs for the divested plants. The net decommissioning accruals recovered from ratepayers attributable to the non-environmental liability for the divested plants was approximately $53 million. Because the Utility no longer has this non-environmental decommissioning liability, it has used this excess recovery amount to reduce other transition costs; Of the $271 million accrued liability, discussed above, the Utility has recovered $148 million through rates, including $34 million through depreciation, and expects to recover $95 million in future rates. Additionally, the Utility is mitigating its costs by seeking recovery of its costs from insurance carriers and from other third parties as' appropriate. In 1992, Pacific Gas and Electric Company filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. The Utility previously had notified its insurance carriers 37 -l" " e e that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In general, the Utility's carriers neither admitted nor denied coverage, but requested additional information from the Utility. Although the Utility has received some amounts in settlements with certain of its insurers (approximately $71 million through December 31, -l999), the ultimate amount of recovery from , insurance coverage, either in the aggregate9r with respect to a particular site, cannot be quantified at this time. Compressor Station litigation Several cases hàve been brought against Pacific Gas and Electric Company seeking damages from alleged chromium contamination at the Utility's Hinkley, Topock, and Kettleman Compressor Stations. See Item3, "Legal Proceedings-Compressor Station ClÍromium Litigation" below, for a description of the pending litigation. Electric and Magnetic Fields In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with electric and magnetic fields (EMF) from utility facilities. In its order instituting the investigation, the CPUC acknowlèdgedthat the scientific community has nöt reached consensus on the nature of any health impacts from contact with EMF, but went on to state that a body of evidence has been compiled that raises, the ' question of whether adverse health impacts might exist. In November 1993, the CPUC adopted an interim EMF policy for California energy utilities tha~, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMF from new and upgraded utility facilities. California energy utilities are required to fund a $1.5 million EMF education program and a $5.6 million EMF research program managed by the California Department of Health Services. It is expected that the CPUC and the California Departinentof Health Services will complete its EMF research program by December 2001. As part of its effort to educate the public about EMF, Pacific Gas and Electric' Company provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings. The Utility currently is not involved in third party litigation concerning EMF. ,In August 1996',the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMF from power lines. The Court expressly,limited its holding to property value issues, leaving open the , question as to whether lawsuits for alleged personal injury resulting from exposure tò EMF are similarly barred. The Utility was a defendant in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMF. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongfuÌ death claims arising from allegations of harmful exposure to EMF and' barred plaintiffs' personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case. If the scientific community reaches a consensus thatEMF presents a health hazard and further detennines that the impact of utiÍity-related EMF exposures can be isolated from other exposures, the Utility may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot qe estimated with any certainty at this time. However, such costs eQuId be significant, depending on the particular mitigation measures undertaken, especially i(relocation of existing power lines ultimately is required. Low Emission Vehicle Programs In December 1995, the CPUC issued its decision in the Low Emission Vehicle (LEV) proceeding, which approved approximately $42 million in funding for Pacific Gas and Electric Company's LEV program for the 38 ':¡'¡ ..~ e e six-year period beginning in 1996. The CPUC's decision on electric industry restructuring found that the costs of utility LEV programs should continue to be collected by the utility for the ,duration of the six-year period. The Utility continues to run its LEV program as funded. ITEM, 2. Properties. Information concerning Pacific Gas and Electric Company's electric generation units, electric and gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All of the Utility's real properties and substaritially all of the Utility's personal properties are subject to the lien' of an indenture that provides security to the holders of the Utility's First and Refunding Mortgage Bonds. Information concerning properties and facilities owned by other PG&E Corporation subsidiaries is included in the discussion under the heading of this report entitled "National Energy Group." I, ITEM 3. Legal, Proceedings. ' See Item 1, Business, for òther proceedings pending before governmental and administrative bodies. In addition to the fol1òwing legal proceedings, PG&E Corporation and Pacific Gas and Electric Company are subject to routine litigation incidental to their business. CompreSsor Station Chromium Litigation Pacific Gas and Electric Company is currently a defendant in three civil actions pending in California courts. These cases are (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in Los Angeles County Superior Court, (2) Aguilar v.' Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, and (3) Acosta, et al. v. Betz Laboratories, Inc., Pacific Gas and Electric Company, et al., filed November 27, 1996, in Los Angeles County Superior Court. These cases are collectively referred to as the "Aguayo;Litigation.'; There are approximately 900 plaintiffs in the Aguayo Litigation. Each of the complaints in the Aguayo Litigation alleges personal injuries and seeks compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of the Utility's gas compressor stations at Kettleman, Hinkley, and Topock, California. The plaintiffs in the Aguayo Litigation include current and former Utility employees, relatives of current and former employees, residents in the' vicinity of the compressor stations, and persons who visited the gas compressor stations. The plaintiffs also include spouses or children of these plaintiffs who cl3im loss of consortium or wrongful death. All discovery and discovery motion practice in the Aguayo Litigation have been referred by .the judge to a discovery referee. The discovery referee has set the procedures for selecting 18 trial test plaintiffs and two alternates in the Aguayo Litigation. Ten of these trial test plaintiffs were selected by plaintiffs, seven trial test plaintiffs were selected by defendants, and one trial test plaintiff and two alternates were selected at random. . The trial date has been set for November 17,2000 in Los Angeles Superior Court. ' The Utility is responding to the complaints and asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations or exclusivity of workers' compensation laws, and factual defenses including lack of exposure to chromium and the inability of chrorriium to cause certain of the illnesses alleged. At this stage of the proceedings, there is substantial uncertainty concerning the claims alleged. The Utility is attempting to gather information concerning' the alleged type and duration òf exposure, the nature of injuries alleged by individual plaintiffs, and the additional ~acts necessary to support its legal defenses, in order to better evaluate and defend this litigation: I: 1 I, PG&E Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its or Pacific Gas and Electric Company's financial position or results of operations. 39 1 -of b.' -- e Texas Franchise Fee Litigation , On July 31, 1997, PG&E Corporation acquired Valero Energy COi-poration (Valero), now known as PG&E Gas Transmission, Texas Corporatiòn. PG&E' Gas Transmission, Texas Corporation and its affiliates (PG&E GTI) succeeded'to the cases described below, which were pending at-the time of the acquisition against Valero and its affiliates. A lawsuit was also pending at such time thàt hàd been filed by the City of Pharr, but no PG&E GTI entity has been served in this case. These cases are collectively referred to as the "Texas Franchise Fee Litigation." These actions were brought by various cities in Texas arising out of several Texas statutes and citý ordinances involving the following: (a) what rights, if any, Texas cities may have to require companies engaged in the gathering, production, distribution, transmission, and/or sale of natural gas to obtain consent from, and pay fees to, the cities within which such activities are being conducted, (b) what form any such consent, if required, must take, (c) what-constitutes "use" of city property, and (d) what types of charges, if any, a Texas city properly can assess against gas pipeline and marketing companies for use of that city's property. There were seven cases pending against Valero entities at the time of the acquisition: (1) City of Edinburg v. Rio Grande Valley Gas Co. (RGVG), Valero Energy Corporation (now known asPG&E GTI), Valero Transmission Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known as PG&E Texas Natural Gas CompaQY), Reata Industrial Gas Company a!kJa Valero Gas Marketing Company (now known as PG&E Energy Trading Holdings Corporation); Valero Transmission, L.P. (now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.), . Southern Union Company and its unincorporated division, Southern Union Gas Co. (Southern Union), and Merca5io Gas Services, Inc., filed August '31, 1995, in the 92nd State District Court, Hidalgo County, TexaS, (2) Cities of San Benito, Primera, and Port Isabel v.RGVG, Valero Energy Corporation (now known as PG&E GTI), Southern Union, et al., filed December 31, 1996, in the 107th State District Coùrt, Cameron County, .' Texas, (3) City of Mercedes v. Reata Industrial Gas, L.P, (now known as PG&E Reata Energy, L.P.), and Valero Gas Marketing Company (now known as PG&E Energy Trading Holdings Corporation), filed April 16" 1997, in the 92nd State District Court in Hidalgo çounty, Texas, (4) Cities öf Alton and Donnav. RGVG, Valero Energy Corporation (now known as PG&E Gas Transmission, Texas Corporation), Valer9 Transmission Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known asPG&E TexasNatural Gas Company), Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation), Valero Transmission, L.P. (now known as PG&E Texas Pipeline~ L.P.), and Reata Industrial Gas, L.P.. (now known as PG&E Reata Energy,L.P.), Southern Union Gas Co., and Mercado Gas Services, Inc., filed July 18, 1996, in the 92nd State District Court, Hidalgo County, Texas, (5) City of La Joya v. RGVG, Vaiero Energy Corporation (now known as PG&E GTI), Southern Union Company, et aI., filed December'27, 1996, in the 92nd State District Court, Hidalgo County, Texas, (6) Cities of San Juan, La Villa, PeÌ1itas, Edcouch. and Palmview v. RGVG, Valero Energy Corporation (now known as PG&E Gas Transmission, Texas Corporation), Southern Union Company, et al., filed December 27, 1996, in the 93rd State District Court, Hidalgo County, Texas, and (7) City of Weslaco v. Valero Natural Gas Company (now known as PG&E Texas NaturàI Gas Company), Valero Gas Marketing Co. (now known as PG&E Energy Trading Holdings Corporation), and Reata . Industrial Gas, L.P. (now known as PG&E Reata Energy L.P.) filed April 17, 1997, in the 92nd State District Court, Hidalgo County, Texas~ The lawsuits involving the City of La Joya (item ~umber 5 above) and the Cities of San ~uan, La Villa, Penitas, Edcouch, and Palmview (item number 6 above)'were voluntarily dismissed on July 13, 1999, and February 23, 2000, respectively~ However, all of these cities are class. members in the San Benito class action (item number 5 above) as are the Cities of Alton and Donna. The trial in the City of Edinburgcase began on June 15,1998. On August 14, 1998, a jury returned a verdict in favor of the City of Edinburg, and awarded damages in the approximate aggregate am~unt of $9.8million, plus attorneys' fees of approximately $3.5 million, against PG&E GTI, Southern Union and various affiliates of PG&E GTI and Southern Union. The jury refused to award punitive' damages against the PG&E GTI defendants. On Decembèr I, 1998, based on the jury verdict, the court entered a judgment in the City's favor, and awárded damages of $5.3 million, attorneys' fees of up to $3.5 million (to the extent that the City is successful on appeal), prejudgment .interest of $1.6 million, and post-judgment interest at, th~ rate of 1O<n- per year, compounded annually, from December 1, 1998. The court found that various PG&E GTI, and Southern 'j :1 I , 40 '-.":;"~_!>'. .~-"'. nOr''''!,· .-!...¡;;>,,_~.. -' .. -- - Union defendants were jointly and severally liable for $3.3 million of the damages, prejudgment interest in the amount of $1.1 million, and all the attorneys' fees. Certain PG&E GTI subsidiaries were found solely liable for $1.4 million of the damages and prejudgment interest of $440,000. The court did not clearly indicate the extent to which the PG&E GTI defendants could be found liable for the remaining damages. The judgment also decreed that (1) certain pipelines owned by PG&E Texas Pipeline, L.P. (fonnerly known as Valero Transmission, L.P.) el,lcroached on the City's property without the City's consent and (2) based on certain jury findings, PG&E GTI was vicariously liable for certain conduct of the local distribution company; RGVG, from October I, 1985, to September 30, 1993 (the date Valero, PG&E GTI's predecessor, sold RGVG to Southern Union). The PG&E GTI defendants are appealing the j'ldgment. ' , On November 4, 1997, the lawsuit filed in Cameron County, Texas, by the cities of San Benito, Primera, and Port Isabel was amended to name as defendants PG&E GTI and all of its subsidiaries (excluding its Canadian gas trading and power trading subsidiaries), PG&E Gas Transmission Teco, Inc. and its subsidiaries, and PG&E Energy Trading Corporation (now knòwn as PG&E Energy Trading-Gas Corporation) (collectively these defendants are referred to as the "PG&E Corporation Texas defendants"). In November 1997, the court ordered a state-wide class certified and granted plaintiffs' request to dismiss' RGVG and the Southern ,Union defendants. In connection with the certification of a class in this case, the court ordered notice to be sent to all potential class members and setting an opt-out deadline of December 31, 1997. Notices were mailed to approximately 159 Texas cities. Fewer than 20 cities opted out by the deadline. Some of the cities opting out include Austin, Brownsville, Houston, and San Antonio. The city of Los Indios has been severed from the class and its claims separately docketed in Cameron County, Texas. On November 22, 1999, the court signed an order dismissing from the class 42 cities because it determined there was no pipeline presence andno past or present sales activity in such cities, leaving 106 cities in the class. The parties are negotiating the terms of a final settlement agreement. The settlement proposal contemplates, among other things, that the PG&E Corporation Texas defendants would pay a total of not more than $12.2 million to the settling class cities, inclusive of attorney fees and expenses, which amount may be reduced by amounts attributable to certain opt-out cities. The defendants retain the right to reject the settlement if the settlement proposal is not approved by certain key cities ,and by 80% of the overall plaintiff class. Although a significant number of the 106 cities in the plaintiff class already have either approved the settlement by enacting the consent ordinance or have adopted resolutions to pass the ordinance, certain key cities have not yet approved the settlement. The settlement is also subject to final court approval. On January 27,2000, the court approved the settlement proposal and established a 14-day period for the cities to decide whether to accept the negotiated settlement tenns or opt out of the settlement. The court also stated that if the City of Corpus Christi does not accept the settlement proposal, it will be placed in a single city sub-class and its claims will not be finaìized as part of the settlement approvaL Corpus Christi has the right to opt out of this subclass. Although the 14-day period expired on February 11, 2000, certain cities· have requested and received additional time to decide whether to opt out. In July 1996, the lawsuits originally filed by the cities of Alton ar.d Donna as intervening actions in the City of Edinburg case were severed from the Edinburg lawsuit. Thë claims asserted by the cities of Alton and Donna are substantially similar to the San Benito litigation claims, except that no Glass claims are asserted. Damages are not quantified. Defendants' motion to transfer venue of both cases to Bexar County, Texas, is currently pending. The Cities of Alton and Donna are also members of the San Benito class, and will be required to dismiss their claims against PG&E GTI in this separate lawsuit if they agree to accept the settlement of the San Benito class action. ' On September 4, 1997, the City of Mercedes amended its petition to include clåss action claims and requested to be named as class representative for a statewide class consisting of all Texas municipal corporations, municipalities, towns, and villages, excluding the cities of Edinburg' and Weslaco (both of which have filed separate actions), in which any of the defendants have sold or supplied gas, or used public rights-of-way to transport gas. The City of Mercedes has requested a damage award, but has not speCified an amount. On November 26, 1997, defendants' motion to recuse the presiding judge was granted. Plaintiffs' request for class certification is still pending. 41 I -!' './.- - - I The causes of action alleged in -the case brought by the City of Weslaco are identical to those alleged in the City of Mercedes case, except that no class claims are asserted. Damages are not quantified. A motion similar to . the motion filed in Mercedes, seeking ,to recuse the judge of the 92nd State District Court; was filed but not ruled upon. On May 12, 1999, this case was transferréd to the 370th State District Court of Hidalgo, County, : Texas. Defendants' motion to transfer venue to Bexar County, Texas, is currently pending. In addition to the cases described above, during May 1996, a petition in intervention was filed in the Edinburg case by the City of Pharr. On June 24, 1996, the court severed Pharr from the Edinburg case, certified the severed case as a class action against Southern Union Company and RGVG, and named Pharr as class representative for a class consisting of those Texas cities, excluding Edinburg and McAllen, that have or had natural gas franchise agreements with RGVG or Southern Union. The, Pharr class was certified as to two claims: breach of contract and declaratory relief· dealing with the rights, status, and legal relationship between plaintiff, the class members, and the local,distribution company regarding payment of franchise fees and use of granted easements. Plaintiffs' original petition also sought injunctive relief, but the class order does not include injunctive relief. Plaintiffs seek actual damages, exemplary damages, attorneys' fees, costs, and pre- and post-judgment interest, but have not specified any amounts. On January 26, 1998, the court added the Cities of Mercedes and Weslaco as class representatives. None of the PG&E Corporation Texas entities have ever been servedin the Pharr litigation.' On December 30, 1997, in affimúng the Pharr class certification, the appellate court specifically found that the PG&E GIT entities were not parties to ,the Pharr class action. However, the same 29 PG&E Corporation Texas entities that are class defendants in the San Benito litigation have subsequently been named and served as defendants in two ancillary suits brought during 1998 by the Pharr class plaintiffs. These ancillary suits seek only injunctive relief, for the stated purpose of "protecting" the Pharr class from alleged interference by the San Benito class. PG&E Corporation believes that the ultimate outcome of this matter.will not have a material adverse impact on its financial position or results of operations. As discussed above under "Item I-National Energy Grou~ Gas Transmission Operations," in January 2000, PG&E Corporation's National EnergyGroup signed a definitive agreement to sell the stock of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc., the National Energy Group subsidiaries which conduct gas transmission operations in Texas. The buyer will assume all liabilities associated with the cases described above. ITEM 4. Submission of Matters to a Vote of Security Holders. Not applicable. 42 y . e I 1,1 I I ! ! - -,- ,'r. ~1 .''':,;' e EXECUTIVE OFFICERS OF THE REGISTRANTS "Executive officers," as defined by Rule 3b-7 of the General Rules, and Regulations under the Securities and Exchange Act of 1934, of PG&E Corporation are as follows: Age at December 31, 1999 57 50 , Name R. D. Glynn, Jr.. .............. T. G. Boren. . . . , . . . . . . . . . .. .. . P. A. Darbee ................. S. w.Gebhardt ............... T. W. High .................. p, C. Iribe .. . . . . , , . . . . . . . . . . ,. T. B. King. . . . . . . . . . . . . ',' . . . . L. E. Maddox ................ G. R. Smith . . , . . . . .. . . . . . . . . . . G. B. Stanley. . . . , . . . . . . ,. . . . . B. R:Worthington , . . . . . . . . . . . . Chainnan of the Board, Chief Executive Officer, and President ,Executive Vice President; President and Chief Executive Officer, PG&E National Energy Group, Inc. Senior Vice President, Chief Financial Officer, and Treasurer Senior Vice President; President and Chief Executive Officer, PG&E Energy Services Corporation Senior Vice President, Administration and External Relations Senior Vice President; President and Chief Operating Officer, PG&E Generating Company Senior Vice President; President and Chief Operating Officer, PG&E Gas Transmission Corporation Senior Vice President; President and Chief Executive Officer, PG&E Energy Trading Corporation Senior Vice President; President and Chief Executive Officer, Pacific. Gas and Electric Company Senior Vice President, Human Resources Senior Vice President and General Counsel 47 48 52 49 38 .,44 51 53 50 Position All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation. . Name R. D. Glynn, Jr. .. ',. . . .. . . . , . , T. G. Boren. . . . . . . . , . . . .', . . . . P. A, Darbee . . . . . . . , . . . . . . . . . S. W. Gebhardt .......... -.... Position Chainnan of the Board, Chi~f Executive Officer. and President Chainnan of the Board of Directors, Pacific Gas and Electric Compàny President and Chief Executive Officer President and Chief Operating Officer President and Chief Operating Officer, Pacific Gas and Electric Company Executive Vice President, Pacific Gas and Electric Company Executive Vice President President and Chief Executive Officer, PG&E National Energy Group, Inc. President and Chief Execùtive Officer, Southern Energy, Inc. Executive Vice President, Southern Company Senior Vice President, Southern Company Vice President, Southern Company Senior Vice President, Chief Financial Officer, and Treasurer Vice President and Chief Financial Officer, Advance Fibre Communications, Inc. Vice President, Chief Financial Officer, and Controller, Pacific Bell, Senior Vice President President and Chief Executive Officer, PG&E Energy Services Corporation Executive Vice President, PennUnion Energy Services Vice President, Enron Capital & Trade Resources 43 Period Held Office January I, 1998, to present January 1, 1998, to present June 1, 1997, to present December 18, 1996, to May 31,1997 June I, 1995, to May 31, 1997 July 1, 1994, to May 31, 1995 August 1, 1999, to present August 1, 1999, to present February 18, 1992, to July 31. 1999 June 1, 1999, to July 31, 1999 February 16, 1998, to May 31.1999 July 17, 1995, to February 15. 1998 September 20, 1999, to present June 30,1997, to September 19. 1999 January 10, 19Q4, to June 30, 1997 April I, 1997, to present April I, 1997, to present April 1, 1996, to March 28, 1997 January 1, 1993, to December 31. 1995 Name T. W. High .................. . P. C. Iribe .. . . .. . . . . . . . . . .- . . . T. B. King. . . . , . . . , . . . . . . . , . . L. E. Maddox ................... . G. R. Smith . . , . . . . . '~ . . . . . . . . . G. B. Stanley. , . ,. ; , . . , . . . . . . . B. R. Worthington. . . . . .. . . . . . .- - Position Senior Vice President, Administration and , External Relations Senior Vice President, Corporate Services, Pacific Gas and Electric Company Vice President and Assistant to the Chief Executive Officer, Pacific Gas and Electric Company Senior Vice President , President and Chief Operating Officer, PG&E Generating Company (fonnerly ,known as U.S. Generating Company) Executive Vice President and Chief Operating Officer, U.S. Generating . Company Executive VicèPresident, Marketing, Development, and Asset Manàgement;· , U.S. Generating Company Senior,Vice President President and Chief Operating Officer, PG&E Gas Transmission Corporation President and Chief Operating Officer, Kinder Morgan Energy Partners, L.P, Vice President, Commercial Operations- Midwest Region, Enron Liquid Services , Corporation Vice President, Gathering Services, Northern Natural Gas Company and Transwestern Pipeline Company Senior Vice President Presidènt and Chief Executive Officer, PG&E Energy Trading Corporation President, PennUnion Energys Services, L.L.C. President, Brooklyn Interstate Natural Gas Corp. Senior Vice PreSident (please refer to description of business experience for executive offlcersof Pacific Gas and Electric Company below.) Sènior Vice President, Hu~ Resources: ' Více President, Human Resources , Vice President, Human Resources, Pacific Gas and Electric Company Self-employed (human resources consultant) , Senior Vice President and General Counsel General Counsel Senior Vice President and General Counsel, Pacific Gas and Electric Company Vice President and General Counsel, Pacific' Gas and Electric Company 44' , ~, '-- e , Period Held Office June' 1, 1997, to present June 1, 1995, to May 31,.,1997 . July 1, 1994, to May 31, 1995 January I, 1999, to present November 1, 1998, to present September I, 1997, to October 31, 1998 May 17; 1994, to September 1,1997 January I, 1999, to present November 23, 1998, to present' , February 14, 1997, to November 22, 1998 July I, 1995, to February ,14, 1997 July 1994, to July I, 1995 June I,' 1997, to present May 12, 1997, to present May 1995 to May 1997 January 1993 to May 1995 January 1, 1999. to present January 1. 1998, to present June 1, 1997, to 'December 31, 1997 July 1,1996, to May 31,1997 January 1995, to June 1996 ,/ June 1,.1997, to present, December 18, 1996, to May 31, 1997 June 1, 1995, to June 30, 1997 December 21, 1994, to May 31, 1995 -0 .þ e - "Executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of Pacific Gas and Electric Company are as follows: Name G, R. Smith. . , . . . . . . . . , , . . . . , K. M, Harvey .....,.,...,..,. R. J. Peters ...., " . . . . . , , . , , . . J. K. Randolph. , . , . . . . , , , , , , , . D, D. Richard, Jr" . . , , , . . , .., . , , G, M.Rueger. , . . , . , , , , , , . , . , , President and Chief Executive Officer Senior Vice President, Chief Financial Officer, Controller, and Treasurer Senior Vice President and General Counsel Senior Vice President and General Manager, Tran'smission, Distribution and Customer Service Business Unit Senior Vice President, Governmental and Regulatory Relations Senior Vice President and General Manager, Nuclear Power Generation Business Unit Age at December 31, 1999 51 41 45 55 49 49 Position All officers of Pacific Gas and Electric Company serve at the pleasure of the Board of Directors. During the past five years, the executive officers of Pacific Gas and Electric Company had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company. Name G, R, Smith. , . , . , . , , ' , , , , '. . . K. M, Harvey ............... . R. J, Peters ,."..",.."".,. J. K. Randolph.,.........,..:. D. D. Richard, Jr. . , , , . . , , , . , . , . G, M. Rueger, . , . . , . . . . . .. . , . . " PosiÙòn President and Chief Executive Officer Chief Financial Officer, PG&E Corporation Senior Vice President and Chief Financial Officer Vice President and Chief Financial Officer Senior Vice President, Chief Financial Officer, Controller. and Treasúrer Senior Vice President, Chief Financial Officer, and Treasurer Vice President and Treasurer Treasurer Senior Vice President and General Counsel Vice President and General Counsel Chief Counsel, Regulatory Senior Vice President and General Manager, Transmission, Distribution and Customer Service Business Unit Vice President and General Manager, 'Power Generation, Business Unit Vice President, Power Generation Senior Vice President, Governmental and Regulatory Relations Vice President, Governmental Relations, PG&E Corporation Vice President, Governmental Relations Executive Vice President and Principal, Morse, Richard, Weisenmiller & Assoc., Inc, (energy, project finance, and environmental consulting) Senior Vice President and General Manager, Nuclear Power Generation , Business Unit ' 45 Period Held Office June 1. 1997, to present December 18,1996, to May 31, 1997 June I. 1995, to May 31, 1997 November 1, 1991, to May 31, 1995 January 1, 2000, to present July I, 1997, to December 31. 1999 ,June I, 1995, to June 30, 1997" August 1, 1993, to May 31, 1995 January I, 1999, to present July 1. 1997, to December 31,1998 January 1, 1993, to June 30, 1997 July I, 1997, to present January 1, 1997, to June 30, 1997, November I, 1991, ,to December 31, 1996 July 1. 1997, to present July I, 1997, to present January I, 1997, to June 30, 1997 January 1993. to December 1996 Nòvember 1, 1991, to present ."L . e PART IT ITEM 5. Market for the Registrant's Common Equity and Related Stockholder Matters. ' Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth on page 67 under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 1999 Annual Report to Shareholders, which information is hereby iIÌcorporated by reference and filed as part of Exhiþit 13 to this report. As of February 22, 2000, there were 149,708 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York, Pacific, and Swiss stock exchanges. The discussion of dividends with respect to PG&E Corporation's comm~n sto~kis hereby incorporated by reference from "Management's Discussion and Analysis-Dividends" on page 20 of the 1999 Annual Report to Shareholders. Neither Pacific Gas and Electric Company norPG&E Corporation made any sales of unregistered equity securities during 1999, the period covered by this report. ITEM 6. Selected Financial Data. A summary of selected financial information for each of PG&E Corporation and Pacific Gas and Electric Company foreach of the last five fiscal years is set forthonpage 4 under the heading "Selected Firìan'cial Data" in the 1999 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. Pacific Gas and Electric Company's ratio of earnings to fixed charges for the year ended December 31, 1999, was 3.25. Pacific Gas and Electric Company's ratio of earnings to combined fixed charges and preferred stock dividends for the year ended December 31, 1999, was 3.08. The statement of the foregoing ratios, together . with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstànding. ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated results of . operations and financial condition is set forth on pages 5 through 25 under the heading "Management's Discussion and Analysis" in the 1999 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 7 A. Quantitative and Qualitative Disèlosures About Market Risk. Information responding to Item 7 A appears in the 1999 Annual Report to Shareholders on page 23 under , the heading "Management's Discussion and Analysis-Debt Obligations and Rate Reduction Bonds," on pages 24 and 25 under the heading "Management's Discussion and Analysis-Price Risk Management Activities," and on pages 37, 38,45, and 47 under Notes 1,3, arid 4 of the "Notes to Consolidated Financial Statements" of the 1999 Annual Report to Shareholders, which information'is hereby incorporated by ref~rence and filed as part of Exhibit 13 to this report. ITEM 8. Financial Statements and Supplementary Data. Information responding to Item 8 appears on pages 26 through 69 of the t999 Annual Report to Shareholders under the following headings for PG&E Corporation: "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows;" and "Statement of Consolidated Common Stock Equity;" under the following headings for Pacific Gas and Electric Company: ' "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," and 46 II; I ~ ,1 I ~ Iii I', 11 ' Ii I: " 'I !i -.',.:rr"....,,-\. .-.. . ¡ ~...~ ..~ 7',,'J.,' , ,'. - e "Statement of Consolidated Stockholders' Equity;"and under the following headings for PG&E Corporation , and Pacific Gas and Electric Company jointly: "Notes to Consolidated Financial Statements," "Quarterly Consolidated Financiill Data (Unaudited)," "Report of Independent Public Accountants," and "Responsibility for Consolidated Financial Statements," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ' ITEM 9. ~hanges in and Disagreements with Accountants on Accounting and Financial Disclosure. Information responding to Item 9 has been previously reported by PG&E Corporation and Pacific Gas and Electric Company in a current report on Form 8-K dated February 17, 1999, and filed on February 23, 1999, as, amended by a Current Report on Form 8-K/Afiled on June 11, 1999. PART III ITEM 10. Directors and Executive Officers of the Registrant. Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is iricluded in a separate item captioned "Executive Officers of the Registrant" contained on pages 43 through 45 in Part I of this report. Other information responding to Item 10 is included on pages.3 through 6 under the heading "Item No.1: Election of Directors of PG&E Corporatiòn and Pacific Gas and Electric Company" and page 38 under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the 2000 Joint Proxy Statement relating to the 2000 Annual Meetings of Shareholders, which information is hereby incorporated by reference. ' ITEM 11. Executive Compensation. Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included on pages 9 and 10 under the heading "Compensation of Directors" and on pages 30 through 35 under the headings "Sunimary Compensation Table," "OptionlSAR Grants in 1999," "Aggregated OptionlSAR Exercises in 1999 and Year-End OptionlSAR Values," "Long-Term Incéntive Plan-Awards in 1999," "Retirement Benefits,"and "Termination of Employment and Change In Control Provisions" in the 2000 Joint Proxy Statement relating to the 2000 Annual Meetings of Shareholders, which information is hereby 'incorporated by reference. ' ITEM 12. Security OWnership of Certain Beneficial Owners and Management. Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included onþages11 and 12 under the heading "Security Ownership of Management" and on page 38 under the heading "Principal Shareholders" in the 2000 Joint Proxy Statement relating to the 2000 Annual Meetings of Shareholders, which information is hereby incorporated by reference. , ITEM 13. Certain Relationships and Related Transactions. Information responding to Item 13, for each of PG&E Corporation and Pacific Qas and Electric Company, is.included on page 10 under the heading "Certain Relationships and Related Transactions" in the 2000 Joint Proxy Statement relating to the 2000 Annual Meetings of Shareholders, which information is hereby incorporated by reference. . 47 ~' .... . e PART IV ITEM 14. Exhibits, Financial Statement Schedules, and Reports, on Forni 8~K. (a) - The following documents are filed as a part of this report: 1. The following consolidated financial statements, supplemental information, and report of independent public accountants contained in the 1999 Animal Report to Shareholders, which have been incorporated by reference ,in this report: , . Statements of Consolidated Income forthé Years Ended December 31,1999, 1998, and 1997, for each of PG&E Corporation and Pacific Gas and Electric Company. Statements of Consolidated Cash Flows for the Years Ended December 31, 1999, 1998, and ,1997, for each of PG&E Corporation and Pacific Gas an'9- Electric Company. Consolidated Balance Sheets at December 31, 1999, and 1998 for each ofPG&E Corporation and Pacific Gas and Electric Company. . Stàtement of Consolidated Common StoCk Equity for the Years Ended December 31, 1999, 1998, and 1997, for PG&E Corporation. Statement ,of Consolidated Stockholders' Equity for the Years Ended December 31; 1999, 1998, arid 1997, for Pacific Gas and Electric Company. . Notes to Consolidated Financial Statements. Quarterly Consolidated Financial Data (Unaudited). ' Independent Auditors' Report (Deloitte & Touche LLP). 2. Independent Auditors' Report (Deloitte & Touche LLP) included at p~ge 53 of this Form 1O-K. 3. Report of Independ~nt Public Accountants (Arthur Andersen LLP) included at page 54 of this Form 1O-K. .,' 4. Report of Independent Public Accountants (Arthur Andersen LLP) included at page 55 of this FOIm 1O~K. '5. Financial statement schedules: , . I -Condensed Financial Information of Parent for the Years Ended December 31, 1999 and 1998. ll-Consolidated Valuation and Qualifying Accounts for each of- PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 1999, 1998 and 1997. Schedules not included are omitted because of the absence of conditions under which they ar'e required or because the required information is. provided in the consolidated financial statements including the notes thereto. 6. Exhibits required to be filed by Item 601 of Regulation S-K: , ' 3.1 Restated Articles of Incorporation, of PG&E Corporation effective as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 3.1). ' 'By-Laws of PG&E Corporation amended as of february 16, 2000. Restated Articles. of Incorporation' of Paéiflc Gas and Electric Company effective as of May 6, ·1998 (Pacific Gas and Electric Company's Form 10:Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1). ' 3.2 . ,3.3 3.4 By-Laws of Pacific Gas and Electric Company amended as of February 16,2000. 4. First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1;1941, September 1, 1947, May 15, 1950, MaY'l, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, Janliary 1, 1975, June 1, 1979, August 1, 1983, and 48 Description of Compensation Arrangement between PG&E Corporation and Thomas G.· Boren. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.2). Description of Compensation Arrangement between PG&E Corporation and Peter Darbee. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3). *10.5PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998. (PG&E Corporation's Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2). - '.Y .. II 'I 11 1 I " 10. 10.1 *10.2 * 1 0.3 I *10.4 ,e '. December I, 1988 (Registration No. 2-1324, Exhibits B-1, B-2, B-3; R~gistration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registrati'on No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B;Registration No. 2-54302, Exhibit2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; Pacific Gas and Eleètric Company's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2). . The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055. (PG&E Corporation and Pacific Gas and Electric Company's Form lO-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit No. 10.2). Stock Purchase Agreement By and Between PG&E National Energy Group, Inc. and E1 Paso Field Services çompany, dated as of January 27, 2000. PG&E Corporation Supplemental Retirement Savings Plan dated as of January 1, 2000. *10.6 Description.of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 1999. (PG&E Corporation's Form 10-K for the year ended December 31, 1998 (File No. 1-12609), Exhibit 10.6). *10.7 Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1,2000. *10.8 Supplemental Executive Retirement Plan of the Pacific Gas and Eleètric Company, effective January 1, 1998 (PG&E Corporation's Form lO-K for the year ended December 31, 1998 (File No. 1-12609), Exhibit 10.7). *10.9 Pacific Gas and Electric Company RelocationAssistance Program for Officers (Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16). *10.10 Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (Pacific Gas and Electric Company's Form lO-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16). * 10.11 PG&E Corporation Retirement Plan for Non-Employee Directors, as amended and terminated January 1, 1998. (PG&E Corporation Form lO-K for the year ended December 31, 1997, (File No. 1-12609), Exhibit No.10.l3). *10.12 PG&E Corporation Long-Term Incentive Prograni, as amended February 16, 2000, including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and Non- Employee Director Stock Incentive'Plan. 49 ,~' '" - e *10.13 PG&E Corporation Executive Stock Ownership Program, amended as of February 16, 2000. *10.14 PG&E Corporation Officer Severance Policy, amended as of July 21, 1999. (pG&E Corporation's FormlO-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.1). . *10.15 PG&E Corporation Director Grántor Trust Agreement dated April 1, 1998 (PG&E Corporation:s Form 10-Q for the quarter ended March 31,1998 (File No. 1-12609), . Exhibit 10.1). *10.16 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998 (PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.2). 11. Computatiòn of Earnings Per Common Share. 12.1 Computation of Ratios of Earnings to' Fixed Charges for Pacific Gas and Electric Company. . 12.2 Computation of Ratios of Earnings to Combined FÍxed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company. 13. 1999 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company-portions of the 1999 Annual Report, to Shareholders under the headings . "Selected Financial Data," "Management's Discussion and Analysis," "Independent' Auditors' Report," "Responsibility for Consolidated Financial Statements," financial statements of PG&E Corporation entitled "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity," financial, statements of Pacific Gas and Electric Company entitled "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Stockholders' Equity," "Notes to Consolidated Financial . Statements" and "Quarterly Consolidated Financial Data (Unaudited)" are included only. (Except for those portions that are expressly incorporated herein by reference, such" i 999 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein.) 18. Letter re change in Accounting Principles. 21. Subsidiaries of the Registrant. 23.1 Consent of Deloitte & Touche LLP. 23.2 Consent 'of Arthur Andersen LLP. 24.1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and, Electric 'Company authorizing the execution of the Form 10- K. 24.2 Powers of Attorney. 27.1 Financial Data Schedule for the year ended December 31, 1999, for PG&E.. Corporation. 27.2 Financial Data Schedule for the year ended December 31,1999, for Pacific Gas ánd Electric' Company. Management contract or compensatory plan or arrangement required'to be filed as an exhibit to this report pursuant to Item 14(c) of Form 1O-K. * 50 ·,}... . '.. e . The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants' reasonable expenses in furnishing such exlÌibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights .of long-term debt holders not otherwise required to be filed hereunder. ' (b) Reports on Form 8-K Reports on Form 8-K(J) during the quarter ended December 31, 1999, and through the date hereof: . 1. October 1, 1999 Item 5. Other Events-Reporting the filing of an application relating to the proposed auction of Pacific Gas and Electric Company's hydroelectric generation assets 2. October 20, 1999 Item 5. Other 'Events-Proposed decision in Pacific Gas and Electric Company's General Rate Case 3. October 21, 1999-Filed by PG&E Corporation only Item 5. Other Events- A. Share Repurchase B. Proposed amendments to Articles of Incorporation and Bylaw Amendments 4. November 5, 1999 Item 5. Other Events- A. Pacific Gas and Electric Company's Post-transition Period Ratemaking Proceeding B. Pacific Gas and Electric Company's 2000 Cost of Capital Proceeding 5. December \, 1999 Item 5. Other Events-Performance Goals and Implementation Strategy 6. January 21, 2000 Item 5. Other Events- A. Pacific Gas and Electric Company's General Rate Case Proceeding B. Proposed Auction of Pacific Gas and Electric Company's Hydroelectric Generating Assets C. 1998 Annual Transition Cost proceeding , 7. January 31, 2000 Item 5. Other Events-Sale of Texas Gas Transmission Companies 8. February 23, 2000 Item 5. Other Events- A. Pacific Gas and Electric Company's General Rate Case Proceeding B. 1998 Annual Transition Cost Proceeding C. Disposition of PG&E Energy Services Corporation (1) Unless otherwise noted, all reports were filed under Commission File Number 1-2348 (Pacific Gas and Electric Company) and Commission File Number 1-12~09 (PG&E Corporation) 51 . . SIGNATURES ,4', '~.:..... Pursuant to the requirements of Seciion, 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the underSigned, thereunto duly authorized, in the City and County of San Francisco, on the 6th day of March, 2000. PG&E CORPORATION (Registrant) By Isl GARY P. ENCINAS (Gary P. Enèinas, Attorney-in-Fact) PACIFIC GAS AND ELECTRIC COMPANY (Registrant) By Isl GARY P. ENCINAS (Gary p, Encinas, Attorney-in-Fact) Pursuant to the rèquirements of the Securities Exchange Act of 1934, this report has been signed , ' below by the following persons on behalf of the registrants and. in the capàcities and on the dates indicated. Signature A. Principal Executive Officers *ROBERT D. GLYNN, J~. *GORDON R. SMITH B. Principal Financial Officers *PETER A. DARBEE *KENT M. HARVEY C. Principal Accounting Officers *CHRISTOPHER P. JOHNS *KENT M. HARVEY D. Directors *RICHARD A. CLARKE *HARRY M. CONGER *DA VID A. COULTER *c. LEE COX *WILLIAM S. DAVILA *ROBERT D. GLYNN, JR. *DA VID M. LAWRENCE, M.D. *MARY S. METZ *CARL E. REICHARDT *JOHN C. SAWHILL *GORDON R. SMITH '. (Director of Pacific Gas'and Electric Company, only) *BARRY LAWSON WILLIAMS *By Isl GARY P. ENCINAS (Gary P. Encinas, Attorncy-in-Fact) Title Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation) President and Chief Executive Officer (Pacific Gas and Electric Company) Senior Vice President, Chid Financial Officer, and Treasurer' (PG&E Corp,oration) Senior Vice President, Chief Financial Officer, Controller, and Treasurer (Pacific Gas and Electric Company) Vice President and Controller (PG&E Corporation) Senior Vice President, Chief Financía1 Officer, Control1er,and Treasurer (Pacific Gas and Electric Company) . Directors of PG&E Corporation and, Pacific Gas and Electric Company, except as noted 52 Date ,March 6, 2000 March 6, 20QO March 6, 2000 March 6, 2000 March 6, 2000 March 6, 2000 , March 6, 2000 J- ~~ I, Ii , ,I I I!, e - INDEPENDENT AUDITORS' REPORT To the Shareholders and the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company: We have audited in accordance with generally accepted auditing standards, the consolidated financial statements as of and for the year ended December 31, 1999 included in the PG&E Corporation and Pacific Gas and Electric Company Annual Report to Shareholders incorporated by reference in this Form lO-K, and have issued our report thereon dated March 3, 2000. Our audits were made,for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in Part IV, Item 14. (a)(5) in this Form 10-K are the responsibility o,f the management of PG&E Corporatión and of Pacific Gas and Electric Company and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to,be set forth therein' in relation to the consolidated financial statements taken as a whole, DELOITIE & TOUCHE LLP San Francisco, California March 3, 2000 \, 53 ...~ fv ~ -h.,. - - REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and the Board of Directors of PG&E Corporation and Pacific Gas and Electric Company: We have audited in accordance with generally accepted auditing standards, the consolidated financial statements as of December 31, 1998, and for each of the two years in the period ended December 31, 1998 included in the PG&E Corporation and Pacific Gas and Electric Company Annual Report to Shareholders incorporated by reference in this Fonn lO-K, and have issued our report thereon dated February 8, 1999. Our audits were made for the purpose of fonning an opinion on the basic consolidated financial statements taken as a whole. The Condensed Financial Infonnation of Parent, for the Year Ended December 31, 1998 and the Consolidated Valuation and Qualifying Accounts for each of PG&E Corporàtion and Pacific Gas and Electric Company for the Years Ended December 31,1998 and 1997, are the responsibility of the management of PG&E Corporation and of Pacific Gas and Electric Company. These schedules are for purposes of complying with the Securities and Exchange Commission's rules and are not part of the' basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set fortli therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP San Francisco, California February 8, 1999 1- 54 ..J.- ~.., ~' ".., e - REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS I. To the Shareholders and the Board of Directors of PG&E Corporation and Pacific Gas and Electric Company: We have audited the accompanying consolidated balance sheets of PQ&E, Corporation (a 'California corporation) and subsidiaries and Pacific Gas and,Electric Company (a California corporation) and subsidiaries as of December 31, 1998, and the relàted statements of consolidated income, cash flows, arid commqn stock equity of PG&E Corporation'and subsidiaries arid the related statements of consolidated income, cash flows and stockholders' equity of Pacific Gas and Electric COI1.lpany and subsidiaries for each of the two years in the period ended December 31, 1998. These financial statements are the responsibility of the management of PG&E Corporation and Pacific Gas and Electric Company. Our responsibility is to express an opinion on these financial statements based on our audits. ' We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a tèst basis; evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial positions of PG&E Corporation and subsidiaries, and, of Pacific Gas and Electric Company and subsidiaries, as of December 31, 1998, 'and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1998"in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP San FranCisco; California February 8, 1999 ' 55 '- "-. -- e tfi..... <_"'r'- ".~, SCHEDULE I~CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEETS Assets: , , ' Cash and cash equivalents. , . . . . . . . . . . . . . . . . , . . . . . . . . . .. . . . . . . .'. . ; . Advances to affiliates . . . . . , . . . . . . . . . , . . . . . . . . .. . . . . .. . . . . . .. . . . . . Other current assets ......,..,.................................... Total current assets . ; . . . . . . . . . , . . . ; . . . . . . . . . . . . . . . . . . . .. . . ." - Equipment,. . . . . . . . .' . . : . . . . . .'.'. . . . . . . . . '~ . .. . . . . . . . . : . . . . . . . . . . . Accumulated depreciation. . . . .. . . . ',' . . . . ; . .. . .. . ',' . . . . . . . . . . .. . . .. Net equipment. . . . . . . . . . . . .. . '. . . . . , . . . . . . . ',' . . . . . . : . . . . . . . . '. . . " Investments in subsidiaries . . . , . . . . . , . . . . ; . . . ... . .:,' . . . . . . . . . . . . . . . . , 'Other investments. . . . . . ... . . . . . . . . . . . . . . . . . . ..'.' ., . . . . . . . . . . .'. " . . . . Deferred ip.come taxes ..... " .'. . . . . . . . . , . . . . . . . . , . .'. . . . . . . . . . . . . '. . Other deferred charges .... ,. . . . . . , . , , . . , . . . .. . . . . .. . . . . . . . . . .. . . . Total Assets. . . . . . . . . . . . . . . . .. . , . . . . . . . . ... . . . . . . . . . . . . . . : Liabilities and Stockholders' Equity: Current Liabilities Short-term borrowings, . . . . . . . . : . . . . . . . . . . . . . . .. :. . . . . . . ; . . . . . Accounts payable - related parties ........-,... ,. . . . . . . . . . . . , . . .. . Accounts payable - trade . . . . . . ,. . . . . . ..' . . . . . . . . . . . . , . . . . . . . . . . Accrued taxes . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. " .- Dividends payable. . . . .'. . . . .. . . . . . . . . . . . . . . . '. . . . . . . . '. . . . . . . . . Other.. . . . . . . . . . . . . . . . . . '... . . . . .. . , . . . . . . . . . . . .'. . . . . . . . . . " ' Total CWTent liabilities. . . . . . . . . . . . , . , . . , . . . . . . . . . . . . . .- . . . . . Noncurrent Liabilities Deferred income taxes. . . . .'. . . , . . . . . . . , , . . . . . . .: . :' . .. . . . . ': . . " . Other . . . . . . . . . . . . . , . . . . . . . . . . , . ',' , . ... . . . . . . . , . . '. . . . . . . . . . Total noncurrent liabilities ........ ,........... 0,_..... ","..... Stockholders' Equity Common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . .-.- .- . . . . . . . . . . . . . '. Reinvested earnings. . . .'. . . . . . '. . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . Total stockholders' equity .......................... .'. . . . . . Total Liabilities and Stockholders' Equity. '.' . . . . . . . . . . . . . . . .. . . December 31, 1999 1998 - . (in millions) $ 155 $ 9 299 448 2 - 454 ',459 16 8 (3) , (1) 13 7 7,621 8,780 52 41 396 - 'I 1 - $8,536 $9,288 I - $526 $ 683 76 221 10 9 117 155 110 115 112 16 'I - 951 1,199 19 5 4 - - 5 23 5,906 5,862 1,674 2,204 7,580 8;066 $8,536 $9,288 - - , I , --f-- -"'-.- , ;"~ I I I; I: I, I' I! e -- SCHEDULE I-CONDENSED FINANCIAL INFORMATION OF PARENT-(Continued) CONDENSED StATEMENTS OF INCOME For the Years EndeØ December 31,1999,1998 and 1997 1999 1998 1997 (in millions, except per share amounts) Equity in earnings of subsidiaries . . , . . . , . . . . . . . . . . . .. . , . . . . Operating expenses " . . . , . . . . . . . . . . . , . . . . . . . . . . . . . . . , . . Loss on assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . Interest expense . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . , . . . . Other income ...................;.............'....... Income Before Income Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Income taxes ......,................,.....,.,.... Income from continuing operations.. . . , . . . . . " ... .. .. . . . , . . Discontinued operations. .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cumulative effect of a change in an accounting principJe .,...,.. Net income (loss) before intercompany elimination, , , . , , . . . . , , . Elimination of intercompany (pro tit) loss .. . . . . , . . . . , , ,. , . . . . Net income (loss) ...................'........,......... Weighted Average Common Shares Outstanding. . . . . , , . . . . . . . . Earnings Per Common Share, Basic and Diluted . . . . . . . . ~ . . . . . . $ 853 $ 736 $ 772 (4) I (21) (1,275) (30) (52) (23) 16 5 - - (440) 690 728 (447) (83) (17) - $ 7 $ 773 $ 716 (98) (52) (29) 12 - $ (79) $ 721 $ 716 6 (2) - $ (73) $ 719 $ 716 - - - 368 382 410 - - $ (.20) $ 1.88 $ 1.75 - CONDENSED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1999,1998 and 1997 1999 1998 1997 Cash Flows From Operating Activities Net income (loss) ..................................... Adjustments to reconcile net income to net cash provided by operating activities: Equity in earnings of subsidiaries . . . . . . . . . . . . . . . . . . . . . . Deferred taxes .. . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . Loss on assets held for sale. . . . . . . . . . . . ~ . . . . . . . . . . . . . . Dividends received from consolidated subsidiaries. . . . . . . . . . Other-net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided (used) by operating activities . . . . . . . . . . . . . . . Cash Flows From Investing Activities Capital expenditures. . . . . . . . , . . . . . . . . . . . . ,. . . . . . . . . . Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . Return of capital by Utility (share repurchases) . . . . . . . . . . . . Other-net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . , Net cash provided by investing activities ................ ,. . . Cash Flows From Financing Activities Common stock issued. . . . . . . . . ... . . . . . . . . . . . . . . . . . . . . Common stock repurchased .......................... Short-tenn debt issued (redeemed)-net ..........,...... Dividends paid. . . . . . . . . . . . . . . . . .. . . . . . . . . . , . , . . . . . Other-net. . . . . . . . . . , . . . . . . , . . . . . . . . . . . . . . . . . ... . . Net cash used by financing activities .....................,. Net Change in Cash and Cash Equivalents . . . . . . . . . . . . . . . . . . . Cash and Cash Equivalents at January I . . . . . . . . . . . . . . . . . . . . . Cash and Cash Equivalents at December 31 .....",..,.'.,.,. '~ - -' (in millions) $ (73) $721 $ 716 (853) (736) (772) (415) 19 1,275 527 ' 445 763 77 (574) (605) - - $ 538 $ (125) $ 1,312 (8) (8) (722) (575) (150) 926 ],600 (J 2) $ J84 $ 1,017 $ (150) 54, 63 (3) (1,158) (804) (157) 683 (465) (470) (367) (5) (2) 10 $ (576) $ (884) $ (1,161) ]46 8 1 9 1 - $ 155 $ 9 $ - - - - PG&E CORPORATION SCHEDULE II-CONSOLIDATED V ALUA TION AND QUALIFYING ACCOUNTS For the Years Ended Dec~mber 31, 1999, 1998, and 1997 . Column A ,Column B Column C Column D Column E Additions Balance at Charged Charged Balance Beginning to Costs to Other at End of Description of Period and Expenses Accounts ' Deductions Period (in thousands) Valuation and qualifying accounts deducted from assets: 1999: Allowance for uncollectible accounts (2). .' $58,577 $25,243 $ (183) $18,509(1) , $65,128. 1998: Allowance for uncollectible accounts (2) . . . $72,912 $10,978 $(2,893) $22,420(1). $58,577 1997: Allowance for uncollectible accounts (2) . . $57,904 $42,500 $ - $27,492~1) $72,912 - . (1) Deductions consist principally of write-offs, net of colléctions of receivables previously written off. (2) Allowance for uncollectible accounts are deducted from "Accounts receivable~ustomers, net" ~d "Accounts receivable-Energy Marketing." ,-'- - ~ =-- "i,o- - .1 , I I I . I I I e a ., I - -;;')'.--'1 ~, j Ii PACIFIC GAS AND ELECTRIC COMPANY SCHEDULE II-CONSOLIDATED V ALUA TION AND QUALIFYING ACCOUNTS For thc ycars cndcd Dcccmbcl' 31,1999, 1998, and 1997 ' Column A Column B Column C Column D Column E Additions Balance at Charged Charged Balance Beginning to Costs to Other at End of of Period and Expenses Accounts Deductions Period (in thuusands) Description Valuation and qualifying accounts deducted from ass~ts: I i 1999: Allowance for uncollectible accounts (2) 1998: Allowance for uncollectible accounts (2) $47,347 $17,011 $ 44 $17,981(1) $46,421 - $59,608 $"10;007 $ 152 $22,420(1ì $47,347. - - ,i 1997:' Allowance for uncollectible accounts (2) .. $57,904 $30,718 $( I ,836) $27, 178( I) $59,608 - II Ii (1) Deductions consist principally of write-offs, net of collections of receivables previously written off, (2) Allowance for uncollectible accounts are deducted from "Accounts receivable-Customers, net." II I I II I, ·1 " ',,-- -~~ ;.:T -- __u '~. CITY OF BAKERSFIELD Ó.CE OF ENVIRONMENTAL.RVICES 1715 Chester Ave., Bakersfield, CA 93301 (661) 326-3979 ~ UNDERGROUND STORAGE TANKS - UST FACILITY TYPE OF ACTION (Check one ,tem only) ì/......3' RENEWAL PERMIT o 4, AMENDED PERMIT o 1, NEW SITE PERMIT o 5, CHANGE OF INFORMATION (Specify cllange . local use only) o 6, TEMPORARY SITE CLOSURE BUSINESS NAME (Same as FACILITY NAME or DBA· Doing Business As) I. FACILITY I SITE INFORMA:rION 3 FACILITY ID # . 1\c..i ç, ~~/'€> NEAREST CROSS STREET . -~t\\l~Gl-n 51 401, I FACILITY OWNER TYPE ~ 1, CORPORATION o 2, INDIVIDUAL o 3, PARTNERSHIP w ,~, TE \..J'\NE. ~~~NESS 0 1. GAS STATION o 2. DISTRIBUTOR TOTAl NUMBER OF TANKS REMAINING AT SITE o 3, FARM 0 5, COMMERCIAL o 4. PROCESSOR 6. OTHER 403, Is facility on Indian ReseMIIion or ·If owner at UST a public agency: name c:J supetlliSOl' at InJSIIandS? division. section or ofIIce which operates the UST, (This is the conlac:t person for the lank records.) 2- 404. 405, s '-t 10 W\Q, ~ 1\0 ! CITY !3~~~16:1.J) PROPERTY OWNER TYPE ~ 1. CORPORATION 410. STATE 411. CA o 2. INDMDUAl o 3. PARTNERSHIP o 4, LOCAl AGENCY I DISTRICT o 5. COUNTY AGENCY TANK OWNER NAME I' MAILING OR STREET ADDRESS , I I CITY 417, I STATE . 0 4, LOCAl AGENCY I DISTRICT o 5, COUNTY AGENCY TANK OWNER TYPE o 2. INOMDUAl o 3. PARTNERSHIP o 1. CORPORATION TY(TK)HQ . IV., BOARD Of EQUALIZATION UST STORAGE FEE ACCOUNT NUMBER Call (916) 322-9669 if questions arise . Ý. PETROLEUM U8TFlNANClAL RESPONSIBILITY . INDICATE METHOO(S) o 7, STATE FUND o 8, STATE FUND & CFO LETTER o 9. STATE FUND & CO, 1, SELF-INSURED o 2. GUARANTEE ' o 3, INSURANCE o 4. SURETY BOND o 5. LETTER OF CREDIT o 6. EXEMPTION Page _ of _ o 7, PERMANENTLY CLOSED SITE o 8, TANK REMOVED 400,' 00/071 o 4, LOCAL AGENCYlOlSTRICr o 5, COUNTY AGENCY" o 6, STATE AGENCY· o 7, FEDERAL AGENCY· 402. 406. PHONE <06\- 30¡f6- Sqq 408, 409, ZIP CODE ~ ~3 } :3 412. o 6, STATE AGENCY , o 7, FEDERAL AGENCY 413, PHONE 415, 416, 418'1 ZIP CODE 419. o 6, STATE AGENCY o 7, FEDERAL AGENCY 420, 421, o 10, LOCAl GOVT MECHANISM o 99, OTHER: VI. LEGAL NOTIFICATION AND MAILING ADDRESS 422. Check one box to indale wh/d'l acIcItesa should be used for legal notillcatlons and mailing. Legal nollflca1Jons and mailings will be MIll 10 the 18nk owner unless box 1 or 2 is checked. o 1, FACILITY o 2. PROPERTY OWNER 3, TANK OWNER 423, VII. APPLICANT SIGNATURE DATE 425, /2/z. '-/1'1' TITLE OF APPLICANT (;AIV/P>N)11ÊIV(;øL .5: félÅÚ~) 4XT, NAME OF APPLICANT (print) lJ~,r~~ 114¡eD4Ic5rä~ 426, 424, PHONE C6/-3"1ff-5'7'7 429, UPCF (7/99) S:\CUPAFORMS\swrcb-a.wpd TYPe OF ACTION (C/Iec. 0""_ OtPIJ .. CITY OF BAKERSFIELD. OFFæ'E OF ENVIRONMENTAL S ~ VICES 1715 Chester Ave., Bakersfield, CA 93301 (661) 326-3979 UNDERGROUND STORAGE TANKS· TANK PAGE 1 <e o 5. CHANGe OF INFORMATION) P-ve t:I o e. TEMPOAAAY SITE Ct.OSllRe 07,Pe~VCt.O~DON~ o e. TANK R£MOV£D 4: . - Î>t\\(f.~~i f::. l..j 10 I to\~L~ ~~í) \ ~~}(~S~iGLD) CJ\, <13313 L TANK DESCRIPTION AN I . I lOA I I "Ii c¡ I I ACOIT1ONAI. CESCRPTION (Ffw..... ody . . ~Sl~lLC.-<L't ¡ TANK USI! 431 I~ 1. MOTORVEHlCUfIUEL i 71f _'*-d. ~"...... 7)pe) ! 0 2. NON-FUEI. PeTROlEUM ¡ 0 3. CHÐoICAL PRODUCT I 0 4. HAZARDOUS WASrE (~ /bed Of) o 95. UNICNOWN r TYPE Of' TANK I (Cheek - iIIm ody ¡ 4:3 ~4-4l\lO \" \N"-. c....Ò't.~1ATioM IN 4:37 OOW~~~DTANK Ov. ~ " -V.". earn.. _ page for 8KII CGmØ8I1menl Q.¡ 10 000 I 438 ÇQj\?:.E~-H "lL . T \I\~~f~ C':..A .. TANK CONTIH'IS " 'w:J' PETROL£UM TVPI! "i& REGUI.AR UNU!AŒO 0 Z. LEADED 01'" PADtUUUNU!AŒO 03. DIESEL o 1c. YDGRAœ UNLEADED 0 4. GASOHOl COMMON NAMe /hmHlzMbø ~ '-'IotyP9) [J 1. DG.I! WALL X 2. DQ8.I! WALL ! TANK Mo\ TERIAI. " IItIMIy ** [J ,.. BAAl! STEEL ! (Ch«k - am ody [J z. STAItUSS STEEL (ChKlt _ am 0tIIy) SPILL AND oveRFILL i I (Check" lllat IIJPIYJ TANK Mo\TERIAI.. -*'Y ** [J 1. BAAl! STEEL (Cheek - ..", ody [J Z. ITAItUSS STEEL [J 1. AUIII!R LN!D [J 2. ALKVO LHNG 44Q o S. JET FUEL EJ ..' AVIATION FIÆL 011. O'ßŒR 441 CAS' (fIom HaIMIbuI.....,.,. *--Y ¡»ge) 442 a TANK COII8TRUC11ON o 3. 8INOLE WALL WITH EXTERIOR MSØWE LINER 04. SlNGU!WALLIfAVAULT o 3. FI8EROlASS, PlASTIC )it 4. STEEL CtAO Wl'18ERGLASS , A£NOORœO PlASTIC o 3. FI8EROlASS, PlASTIC o 4. STEEl. CtAO WJFI8ERGLA8S A£NOORœO PlASTIC (FAP) o S. CONCAETE o 3. EPOXY LINING o 4. PHI!NCUC UNN3 o 5. 8INOLE WALL WITH INTEANAL aADDER SYSTEM ON. UNKNOWN o II. OTHER o 5. CONCAETE 0 IS. UNICNOWN o .. FAI" CIOMPATIIIU! WI100% METHANOl 0 II. OTHER .... 443 o .. FAI" CIOMPATI8U! WI100% METHANOl o .. FAI" NOH-COARODI8U! JACKET o to. COATED STEEL ON. UNKNOWN o II. OTHER 445 TANK INTEIUOR LNNO OR COATING o .. Gt.A881JNNO ~ N. UNICNOWN o .. UNLINED 0 II. OTHER 441 DATE INSTALU!D 447 o 3., FItERGI.ASS REJNfORCED PlASTIC 0 N. UNKNOWN o 4. U'AESSED CURReNT 0 II. OTHER IoceIIIN DATE INSTAU.ED 448 [J 1. MANUf'ACTUA!DCATHOOIC PROTICTION o Z. SACRIFICIAl. AHoœ YEAR INSTALLED J1. 1. SPILL CONTAINMENT ( Q'11 ~ z. OAOP T\JII , 'i q~ 3. STRIICIR P\ATI I q t: ~ 441 (FtN IoceIIIN 0tIIy) 451 OVERFIU. PROTECTION EQUAENT: YEAR INSTAU.ED 462 0,. AlARM ø. 3. FILL TUBE SHIITOFF VAt..V£'Jjj"g, o Z. 8AU. FLOAT 0 4. I!XBPT' 450 TYPE (FtN /oUI.". onIyJ I -. ,::J~Pr.~ L8AK IP StNOLI WALl. TANK (CItecII.. fIlM 1MJ/1J: o I. VlSlIAt.. (IXPOIIO PORTION OM. V) o 2. AUTOMo\T1CTANKCWJGIHQ(ATO) o J. CONTINUOUtATO o 4, 9TATISTlCALINVIN1'ORYIœCONCIUATION(SIR). BIeNNIAl. TANK TUTINO , IISTlMo\ TID OATe LAST U8ID ('mfMOIDAV) ,UPCF (7199) 411 :-.:-.'.....:.. :~?·f..·~;-:.:~·: "'~:). .......... .::/t~;;:·. " DOUIIUI WALL TANK OR TANK WITH IILADDIR (Checfr _ ".", ody: ... o 1. VISUAL(SINOL!WALLINVAULTONLV) 2. OONTINUOU8 INTERSTITIAl. MONlTORINQ o 3. MAHU~ MONITORING o 5. MANUAL TANI< GAUGING (MfO) o .. VADOSE ZONE 07. OAOUNOWATEA o .. TANK TESTINO [J", OTHeR V. TANK CLOIUItIIN'ORMATIOH I P.llMANINT CLOIUII.'N PLACI UTlMATID QUNmTY OF SlIIITAHCI RIttWNINO 4M TANI< FILLID WITH INIRT Mo\TlAIAI.? 467 ..... o v. 0 No S:\CUPAFORMS\SWRCs-ø.WPO ~ ;. ~-,!.: '"!~. . CITY OF BAKERSFIELD OFFICE OF ENVIRONMENTAL SERVICES 1 - 5 Chester Ave., Bakersfield, CA 93301 (881) 328. Page UST. TANK PAGE 2 01 I i SYSTEM TYPE UNDERGROUND PIPING ABOVEGROUND PIPING VI. PIPING CONSTRUCTION (Check" /llet apply) 1. PRESSURE 0 2_ SUCTION 0 3, GRAVITY 458 0 1, PRESSURE 1, SINGLE WALL 0 3, LINED TRENCH 0 99, OTHER 460 0 1, SINGLE WALL 2, DOUBLE WALL 0 95, UNKNOWN 0 2, DOUBLE WALL MANUFACTURER 461 MANUFACTURER o 1, BARE STEEL 0 6, FRP COMPATIBLE WI 100% METHANOL 0 1, BARE STEEL o 2, STAINLESS STEEL 0 7, GALVANIZED STEEL 0 2, STAINLESS STEEL o 3, PlASTIC COMPATIBLE WITH CONTENTS 095, UNKNOWN 0 3, PlASTIC COMPATIBLE WITH CONTENTS o 4, FIBERGLASS 0 8, FLEXIBLE (HDPE) 0 99, OTHER 0 4_ FIBERGLASS 5, STEEL WI COATING 0 9, CATHODIC PROTECTION 464 0 5, STEEL WI COATING viLPU,N9 i.EAKDETECTION (Checka,inatapp/y) , I I CONSTRUCTION/ , MANUFACTURER I MATERIALS AND I CORROSION PROTECTION UNDERGROUND PIPING SINGLE WALL PIPING 468 PRESSURIZED PIPING (Check all that aØPIY): o 1, ELECTRONIC LINE LEAK DETECTOR 3,0 GPH TEST ïLmi AUTO PUMP SHUT OFF FOR LEAK. SYSTEM FAILURE. AND SYSTEM DISCONNECTION + AUDIBLE AND VISUAL ALARMS o 2. MONTHLY 0,2 GPH TEST o 3, ANNUAL INTEGRITY TEST (0,1 GPH) CONVENTIONAL SUCTION SYSTEMS: o 5, DAILY VISUAL MONITORING OF PUMPING SYSTEM + TRIENNIAL PIPING INTEGRITY TEST (0,1 GPH) SAFE SUCTION SYSTEMS (NO VALVES IN BELOW GROUND PIPING): o 7, SELF MONITORING GRAVITY FLOW: o 9. BIENNIAL INTEGRITY TEST (0.1 GPH) SECONDARILY CONTAINED PIPING PRESSURIZED PIPING (Check all that apply): 10, CONTINUOUS TURBINE SUMP SENSOR ~ AUDIBLE AND VISUAL ALARMS AND (Check one) o a, AUTO PUMP SHUT OFF WHEN A LEAK OCCURS o b, AUTO PUMP SHUT OFF FOR LEAKS. SYSTEM FAILURE AND SYSTEM DISCONNECTION o C. NO AUTO PUMP SHUT OFF o 11. AUTOMATIC LINE LEAK DETECTOR (3,0 GPH TEST) ïi!I!:I FLOW SHUT OFF OR RESTRICTION 12, ANNUAL INTEGRITY TEST (0.1 GPH) SUCTION/GRAVITY SYSTEM: o 13. CONTINUOUS SUMP SENSOR + AUDIBLE AND VISUAL ALARMS EMERGENCY GENERATORS ONLY (Check all /llet apply) o 14, CONTINUOUS SUMP SENSOR ~ AUTO PUMP SHUT OFF + AUDIBLE AND VISUAL AlARMS o 15, AUTOMATIC LINE LEAK DETECTOR (3,0 GPH TEST) ~ FLOW SHUT OFF OR RESTRICTION o 16, ANNUAL INTEGRITY TEST (0.1 GPH) o 17 , DAILY VISUAL CHECK , 0 3, GRAVITY 459 o 2, SUCTION 095, UNKNOWN o 99, OTHER 46: 463 o 8, FRP COMPATIBLE WI 100% METHANOL o 7. GALVANIZED STEEL o 8, FLEXIBLE (HOPE) 0 99. OTHER o 9, CATHODIC PROTECTION o 95, UNKNOWN 465 ABOVEGROUND PIPING SINGLE WALL PIPING 467 PRESSURIZED PIPING (Check aU that apply): o 1, ELECTRONIC LINE LEAK DETECTOR 3,0 GPH TEST ~ AUTO PUMP SHUT OFF FOR LEAK. SYSTEM FAILURE. AND SYSTEM DISCONNECTION + AUDIBLE AND VISUAL AlARMS o 2. MONTHLY 0.2 GPH TEST o 3, ANNUAL INTEGRITY TEST (0,1 GPH) o 4, DAILY VISUAL CHECK CONVENTIONAL SUCTION SYSTEMS (Check aI/that apply): o 5, CAlLY VISUAL MONITORING OF PIPING AND PUMPING SYSTEM o 8. TRIENNIAL INTEGRITY TEST (0,1 GPH) SAFE SUCTION SYSTEMS (NO VALVES IN BELOW GROUND PIPING): o 7, SELF MONITORING GRAVITY FLOW (Check all that aØPIY): o 6, DAILY VISUAL MONITORING o 9. BIENNIAL INTEGRITY TEST (0,1 GPH) SECONDARILY CONTAINED PIPING PRESSURIZED PIPING (Check aU /llat aØPIY): 10. CONTINUOUS TURBINE SUMP SENSOR ~ AUDIBLE AND VISUAL ALARMS AND (check one) o a. AUTO PUMP SHUT OFF WHEN A LEAK OCCURS o þ, AUTO PUMP SHUT OFF FOR LEAKS. SYSTEM FAILURE AND SYSTEM DISCONNECTION o C, NO AUTO PUMP SHUT OFF o 11. AUTOMATIC LEAK DETECTOR 012. ANNUAL INTEGRITY TEST (0,1 GPH) SUCTION/GRAVITY SYSTEM: o 13. CONTINUOUS SUMP SENSOR + AUDIBLE AND VISUAL ALARMS EMERGENCY GENERAToRS ONLY (Check all /llat apply) o 14, CONTINUOUS SUMP SENSOR ~ AUTO PUMP SHUT OFF + AUDIBLE AND VISUAL ALARMS o 15, AUTOMATIC LINE LEAK DETECTOR (3,0 GPH TEST) ",:..~.~~,~~:~~~trt~&t~t;j~Pff({,~,{~~}i¿¡8;é;:;:;¡;:¡~~}~§W;~i~t~¡~H-T~1B';;:;;MH(,~ f ,·';~:~:~1~~~; o 16, ANNUAL INTEGRITY TEST (0,1 GPH) o 17. DAILY VISUAL CHECK DISPENSER CONTAINMENT DATE INSTALLED 468 o 1, FLOAT MECHANISM THAT SHUTS OFF SHEAR VALVE o 2. CONTINUOUS DISPENSER PAN SENSOR + AUDIBLE AND VISUAL AlARMS o 3, CONTINUOUS DISPENSER PAN SENSOR ïLmi AUTO SHUT OFF FOR DISPENSER + AUDIBLE AND VISUAL ALARMS IX.'OWNERJOPERATOR SIGNATURE 4, DAILY VISUAL CHECK o 5. TRENCH LINER I MONITORING o 8. NONE 469 UPCF (7/99) 471 DATE /2/ . £. ' 7Zo/'71' TITLE OF OWNER/OPERATOR C-' &vv,l,e¿YN /J"1~"y'¡íf¿ ~.i ~e.¿"'bJJ.f 470 472 S:\CUPAFORMS\SWRCS-B.WPD l1 J ,,:~,' I' ~iIIC!"1t$ ~ ~~. roo"'" ;: AUTHORIZEO,BV '....;:;%¡. '1 . , I CUSTOMER ''R~ <:f-~ ~S;t::e...¡ I (.J£ c.tE'NíÐ?. - W, bl cE: ¡!!.Q JOB LOCATION r 410 I It\J. hie (ê.O =:21, 'r' \ UA\C~~\1åG CP\ Q330o., I' CAL- VALLEY EQUIPMENT 3500 Gilmore Ave. · Bakersfield, Calif. 93308-6299· Phone: (661) 327-9341·Pax (661) 325-2529 Cont.lie. #750103' ' ORDER NO. DATE~ 2"?¡ CfC, ARRIVAL TIME) , 8 : 00 DEPARTURE TIME I (): .30 -- ;, ,~ CITY ~~~ NOTIFICATION TO W & M CONFIRMATION # PART NUMBER AND DESCRIPTION I 1) Parts I 2) Sales Tax 1 3) Freight :1 4) Labor Total 3.0 I 5) Mileage Total ';LO 1 6) Equipment Rental 1 7) Outside Repairs 1 TO~AL ~MOUNT ,I 'I ...-: JOB_ OFFICE -- . MODEL SERIAL NUMBER QTÝ G 11.b~rzco RoNAN I, ' REPORTED PROBl M ~' 1 1/ I r, I t ! ' , ;,i i PRIMARYCAU~E/CfRRECTIONS MADE ,,' , I" ..c', GD ' --s,A-T1 C~P(~ A I' rlu.h"\0<:2~)~5 ri' I 'Z R: Fól-¡Q-J\ A- ('IV' I.(A- ( I I I I 5-A4 137 '3 N\ Ke. P~IZ.M F~~ - - ,A.-.--JK 16.:ST " I,: q- TPrn~trn ,øn.. ; -"~ :.~ ¡~:~ " d :'~1 :~~ j :,} ", ;':~ ('" .~~ It is understood ~nd agreed that in event this bill becomes overdue and the seller commences legal action for the collection o{ :sarrl'e, the buyer will pay all costs of collection including attorney's fees. The title to the property deScribed h~u'einl!shall remain the property of the seller, and title shall not pass to purchaser until paid. A service charge of 2"ln,_eq¡ual to 24% per year, charged on past due accounts. SERVICE WCF.<:,:j:::::,;:-;'::': CAL V~LL¡;Y FiEPRES:::N,ATIVE I·~ ?:J I) ~;1 ::1 ...-? ~,~Û'o.rz.. 7~/lßlqq --- ,~ ~, I' II , c DATE .----- , , 'c ~ 4 0 6 " - VE- ,") 0 i¡: Î OOKHEID TOKHelM OISTAIBu;rOR @/P.MJ '. .:.---C[;;iJ I P.M. --- -- 13q I GO CXJ c¡ 00 I I I I ,--- IJ ···r·'· ., '-''; '''-' '-.' ,- ~ ........-: .:..;. ~.......---:---;. ~... ...."..: \. ,',....i--¡~1.~. . _.,' ~.;.., .... '.~ ~. ..~..'..,,_........;.,:.._,:":""',..~.:;,....:...- ;. . ~ ....... e . ~.... ... , , , " .c:SAN JOAQUIN, VALLEY, UNIFIED:AIR POlLUTIQN-,.,CONTROL DISTRICT' ',.>..'-." ,- , .. _.,~ " '. _ - .._.~.,-.;. ~:_ .,- . ,'~;:. -if'}" . . [ 1 Nortt'1èrn'R.egional Office 4320'Ki~rnanAve.. Ste 130., " Modesto. Ca~ 95356, (209) 545-7000 , , . ~ . . . . .' ',k'f SoutheniRegio~al Office' . . 2700 M:St, Ste,27.5:- ' Bakersfield; Ca~'9330t -(89sr662-:526{) , (' t:,;;.",,) "3' 2-<Ø ~9 00 . "". Gasoline Dispensing Facility Performance Test Report , ' [ lC:entral Regional'OffiCe' ,: 1999 Tuolumne St; Ste. 200 '. Fresno;Ca; 93721 (209) 497-1000 r- llnitial·Test Facility Name,: Location Address: .J .1 Contact: /1./ />.' /' (/ ,;:' &<l Retest .¡z: Date: .-, h..f> /~q .;:..:::- (~ ~ '7 I ~'-+ /;ì /\,oV ¡,~(.,e= 'f" ,,/~-:/~> Title: PTO#: 'CI·ty·. r~ ,:} ~' .,-~' æ Ç" r::-:. '6' (..' l_) ....j'.. i;.:;>/::~ / ,/.' , Phone # F,:2,./, ,:'.M;¿-:-R.bõñë-# ,j....., 'Ò ('..r ç". ;~ _ -Source Test Corilpany C>¡ ¡ ;/ ,j'L.,'; b7'\r" ' 'Technician 4ï~,-'d/"';/5~;;;"~~ 1 .. -...'. '. Tank Size' 1. /v 0002. Gasoline Dispensing Equipment 3: 4. Number of Nozzles -z.. Phase I Vapor,Recovery,?yste'm Type Phase II Vapor Recovery System Type , . r!-Q" . Å--'X:- I s: Co (e..,,,.., 'Ç.¿ , , CARB Executive Order , ~' --70 - 0 4=- . CARB Executivé Oraer f!.. -""""<:)- '3Ç::. 1<>"'0 Q?>J/ [ ] [ ] [ ] , ,( ] " , [ , 1, [ ] . ' , Performance Tests ' . Static~r~ssurelntegrity Test (Sr:·30) , .. . @ass* Static Pressure IntegrityTest (ST-38)' r ]Pass* Dynamic Bac~ pressure Test (ST-27) [ ] Pass* Air,toLiquid Volume Ratio Test (AIL) [J Pass* Red Jacket System Calibration ['] Pass*·, 'Healy Vacuum Test (G-70-70 Exhibit 5) [ ] Pass* , ' Hirt Vapor Leak Test (G-70-139) .. r 1 Pass* . . !iMD~'.''''' · [ ] Fail [ ] Fail [] Fail ['LFail [ ] ·Fail [] .Fail [ ] Fail, .-. ... .- .- Comments: ' "Disfrict ObserVer:' f'~ \. . t1.'\ /) 'I / .I ! '. ,'~- ",.,ll ',~-i, ,Recei,"ed By' /,,' ¡ ,1.- i .-/ ,,"r"'" .' t _ . _~_~._:.-.:.-_: ' . :r .I ,.- j "" (:;;t.~" * Pen,ding Receipfof Test Results adftestrot8/96 .r.... -__.";,,.~ ~).__'.~.-...~..~-¡...'_" '.. ~~.:....i_~.·_'.: "'.~,.:':..,:.-.:--------. ".,~ \ .;:"~:::.;:~:-~ ....;. "J....~..:.:~.:_.;._: ---..~:':'..-:;..:....._~";;'::';;..:..____....... .. ,;~w~-..1...·., .. e . """ : ~..,~ f J . .' . ,San Joaquin Valley Unified Air Pollution Control-District .' ." ;" :~.' - ~.~ . ¡1. _~.','k. STATIC LEAK TEST RESULTS - PROCEDURE ST-30 : STATION INFORMATION TESTING ÒOMPANY INFORMATION NAME :_PG +z. W, bl~ ~vlæ '~ NAME: {fi,C {o..ll~ m\.old:>mC\+ ADDRESS: --Y I 0 I W( ble fGD ADDRESS: ~SOõ' Q, I~Oo("'e.. A-ue ðA~(5HeLd CAÒ,330<1 ~Sf1¿¡,J CA q3=o8' . FACILITY NUMBER: 53QG,-1-2 SIGNATURE:~~_ ~~~-: ... " TELEPHONE: APCD WITNESS: .- . ßAlA('I <"12- . .. 1-Z'iS~q Cj PHASE II SYSTEM TYPE: DATE OF TEST: , TANKS MANIFOLDED? f'.0 I OF NOZZLES:' ~ PV VENT MODEL. I: mOT{. 749 Source Test; Results and Comments: TANK HUMBER ONE TWO THREE . TOTAL l. Product Grade íG.Lc 2.' Actual Tank Capacity, Gallons IOI5~ 3. Gasoline Volume, Gallons , '-¡ ~q y 4. Ullage, Ga1.lon~_(./2, minus' 13) "2..750 5. Phase I \ System Type Ú>Prx 6. Initial Test Pressure, Inches H2O 2iO 7. Pressure After 1 Minute I,QS 8. Pressure After 2 Minutes , ,. qo 9. Pre'ssure After 3 Minutes 1.85 ~ 10. Pressure After 4 Minutes I . ?!í J 1l. Final Pressure After 5 Minutes 1.74> 12. Allowable Final Pressure From Tables ',$"0 13. Test Status (Pass or Fail) PASS Comments: " Northern Regional Office ,,:1.230 KiernanAve.,Ste. 130' Modesto, CA. 95356, (209) 51.5-7000 Central Re9io~al Office, 1999 Tuolurne«,St., Ste. 200 Fresno, CA. 93721, (209) 497·1000, ' Southern Reg iona l Off i ce 2700 "M" St., Ste. 275 Bakersfield" CA. 93301 (605) 662-5200 -. ,ri e - P~£. ' , k\ bìd;'5ez.v\¿-k4t. 4 (0 I Wlb\e._í2D BA~e,z:sÇìe:c.J CA . .";':"';..:;'," cal-Vaney Equipment 3500 ,Gilmore Avenue Bakersfield. CA 93308 (805) 327-9341 Fax: . (805) 325-2529 Cant. Lic. #750103 "';;¡-'. TANK MONITOR INSPECTION MAKE: G \ I b:u-co / eoNAN , MODEL: TIYI 2., / X 7fß5 -A:J I SN 137q3 CONDmON OF UNIT UPON ARRIVAL: G ,/ ba ("'0"'1 ~('\v ('(Y)("\\ +0 'r I ~ I N .£t cod I-Joz.,¿, ~l ð~De:n- KONAN Plp''"'9 :5e1"l-50f~'S¡:rf'~ II\J.,C}ex'X:\ WO~¡¿("\4 OrD€v ~~~.' .' TANK PROBES: SENSORS QTY. QTY. _~, , ,.QTY. n'PE ~A~ I· . . TYPE teo~A-9-.J ··TYPE PROGRAMMING ACCURACY & COMPLIANCE: U) READS ACCURATE TO TANK¡CHART1:';'i<iYES ~ NO , ,,,,-,--. . (2) POSITIVE.8mm>oWN WORK PROPERLY1"?,YES CO~:(:!?ONA-N ' <Sel\SOit.?: Pr(L~" \je+ +0 ~~'-{ ?o~ ,.\-, "f:-S;h(..(.+d.owÑ K£~ NO Conhe.c..b( (3) TANK TEST PROGRAMMING MEET COMPLIANCE? YES RECOMMENDATIONS: 'Cu..oh>IY\eR- ~5 ,1+[ ~) ~ iZ... MN \L. k61- re-©u I æp !JuuLá- NO N/A , {JðÆ~_~kJL .. '- INSPECTED BY: Æ~-"'/7!.~.-ÆLv1 DATE: 7-'2/2>' '19 _.u .. .-'.' . Íl¡j1H~t[) Tokheim & Gasboy Prod4Òts, Lincoln Lube Equipment, OPW Products, Red Jacket Pumps UNCOLN -, - ----: ----.---....--- -,- .." -~~-~--~~- -- ------- . '. . _"~~"'.'.-. - . . ,....~.~:.;.;.~-......;;-;: ,. e . ." , Ii INVOICE"#BGO(}Q557 TEST DATE: 08/25/99 UNDERGROUND TANK TESTERS 15806 AVE. 288 YISALIA, CA. 93292 (209)747-5220 I; Ii TANK STATUS EVALUATION REPORT - - -.- - - ~ - - - - - - - - - - - - - - - - - - - - - - ***** CUSTOMER DATA ***** ***** ,SITE DATA ***** GAL-VALLEY EQUIPMENT 3500 GILMORE AVE. PG&E SERVICE CENTER 4101 WIBLE ROAD BAKERSFIELD, CA. 93308 BAKERSFIELD, CA. 93308 CONTACT: PHONE #: 661-327-9341 CONTACT: PHONE #: ***** COMMENT LINES ***** CURRENT EPA STANDARDS DICTATE THAT FOR UNDERGROUND FUEL TANKS; THE MAXIMUM ALLOWABLE LEAK/GAIN RATE OVER THE PERIOD OF ONE HOUR IS .05 GALLONS. TANK #1: DIESEL FUEL 2 TYPE: STEEL RATE: .028924 G.P.H. LOSS TANK IS TIGHT. TANK #2: REG UNLEADED TYPE: STEEL RATE: .010511 G.P.H. LOSS TANK IS TIGHT. , :1 I ! OPERATOR: . P:OO ¢If~ ~TH ' v U··,.d'¡.:I UG #91-1431 "~' SIGNATUIŒ: Zi4~~___ÐArE:f/(].,:q'J'L .. : : , f . ------~-~~-_._---~--- J.~~'~':; .:J.:. ,D~;"·...-· :' ;;-... '. :'Ú;...~ ~":.:. ~;,. ~..''::.:~~!':'.:.'.,:~~';.-::~ ,': .<,'.~ .1:.·i\"'!~ ',~.' ~".~"- ':'-::,'" ._,,"'~' ~ ,:. :... ':'.'~ :.''''ó, :.; '....: ,..;. .... :-.. ." ~. '.. u " .~ ~.. ,.:~t-{i:1,~:;;;'-:-~'': ..... ''; '.,,," , ".:...., ~;'_":::::":ø~ _~:,,.;~ '::;"¡:':~"" ,'. ~:""""".-.":"~.-'~ .:i..::.:::,:-:.;.',"" '-'¡ ,. e e .' ;. ~ ":...."......'-'.-!.~ -' ******* TAN K D A T A ******** TANK NO. TANK NO. TANK NO. 1 2, 3 TANK DIAMETER (IN) 96 96 LENGTH (FT) 26.59 26.59 VOLUME (GAL) 10000 10000 TYPE ST ST FUEL LEVEL ( IN) 68 72 FUEL TYPE DIESEL 2 REG UNLD dVOL/dy (GAL/ IN) 120.57 114.80 CALIBRATION ROD DISTANCE 1 10;65625 2 26.95313 3 41. 93750 4 56.93750 5 74.93750 TANK NO. 4 , I I 'I :1 ....,.,;., ...,..-" ... .~ .,.- ,-,...... .~...-". '. .... -'~ , . e " i .', ..... <.~. --------- ,., e ******* C U S TOM E R D A T A ***~**** I" , JOB NUMBeR CUSTOMER (COMPANY NAME) CUSTOMER CONTACT (LAST, FIRST}.,:, ADDRESS - LINE 1 . ,ADDRESS - LINE 2 CITY; STATE ZIP CODE (XXXXX-XXXX) PHONE NUMBER (XXX) xxx -:- XXXX .' 000557 CAL-VALLEYEQUIPMENT 3500 GILMORE AVE. BAIŒRSFIELD, CA. 93308 661-327-9341 ******* COM MEN T L I N E S ******* ******* SIT E D A T A ******** I II SITE NAME (COMPANY NAME) SITE CONTACT (LAST, FIRST) ADDRESS - LINE 1 ADDRESS - LINE 2 CITY, STATE ZIP CODE (XXXXX-XXXX)· PHONE NUMBER (XXX) xxx - XXXX ,GROUND WATER LEVEL (FT) NUMBER OF TANKS I: I: LENGTH OF PRE-TEST (MIN) LENGTH OF TEST (MIN) ¡ . PG&E SERVICE CENTER . 4101 WIBLE ROAD BAKERSFIELD, CA. 93308 o 2 30 180 ..,.-.,.' ·,:,.'";c-,;:'ìÍ.:.·..u-_. - ...,~,..-'...-_..._._~......~ -, .-1 I :;J ':¡'1 'c/', ::'>1 "',I' \ ;, .. ~ ~ I,:J ...~ i ."1 r ~ . . 1 ','- '.:'1 I' ,'f'; ", ',~ }~; /' e ,/ I ( 'I ~:- ," 'e is.·'; :1 I;,:' ':C', I' '1 ,¡ ,"j I~" I'.; '-, I'] '~ " , ¿ " I 1 I,' .,' r' . ,'. ~ " - - 'UNDERGROUNP TANK ,TESTERS' p~o~ BOX 3710 ' VISAUA, CA. ,93278~371 0 (559) 747-5220 PIPING TIGHTNESS DETERMINATION; PL400 FORMAT TEST LOCATION: ' PG&ESERVICE CENTER ,,' 4101 WIEBLE RD. ," !> BAKERSFIELD, 9}. 9~3?ß TEST OPERATOR: ~~.4"~ . . BOBBY . SMITH OTTL LlC 91-1431 DATE: 08/25/99 -- TEST INITIAL ,FINAL , VOLUME. LEAK RATE LEAK RATE DURATION PRESSURE PRESSURE DISPLACED ~ i· PASS FAIL , DIESEL 2 REG UNLD 'SUP UNLD DIESEL 2 . , 1 30 50 46 6 -.0143 X . , 1 30 50 39, 11 -.0262 X 1 ; 'I COMMENTS: -- I I~- 'I 1 LEAK DETECTOR/S FUNCTIONING PROPERLY YES, " - " "" 't - e INVOICE #dg000120 TEST DATE: 04/20/00 TANK TESTERS, INC. P. O. BOX 95 GARDINER, OREGON 97441 541-271-1124 ***** CUSTOMER DATA ***** RT ***** SITE DATA CAL-VALLEY EQUIPMENT 3500 GILMORE AVE. WIBLE ROAD SERVICE CENTER 4100 WIBLE ROAD BAKERSFIELD, CA. 93308 BAKERSFIELD, CA. 93313 CONTACT: CARTER, PAM PHONE #: 661-327-9341 CONTACT: FISHER, DEE PHONE #: 661-398-5941 The services described in this document have been provided in a manner consistent with the current standards of the profession and to the best of my knowledge comply with all applicable state and local statutes, regulations and ordinances. TANK #1: DIESEL FUEL 2 TYPE: STEEL RATE: .018501 G.P.H. GAIN TANK IS TIGHT. TANK #2: REG UNLEADED TYPE: STEEL RATE: .015853 G.P.H. GAIN TANK IS TIGHT. OPERATOR: P~N~~J¡ºQºAK SIGNATURE: O~r)J~~-~~-- DATE: _'i:~:f-¡) i¡l ,~ - e INVOICE #dg000120 TEST DATE: 04/20/00 TANK TESTERS, INC. P. O. BOX 95 GARDINER, OREGON 97441 541-271-1124 TANK STATUS REPORT -- ULLAGE TEST --------------------------------- ***** CUSTOMER'DATA ***** ***** SITE DATA ***** CAL-VALLEY EQUIPMENT 3500 GILMORE AVE. WIBLE ROAD SERVICE CENTER 4100 WIBLE ROAD BAKERSFIELD, CA. 93308 BAKERSFIELD, CA. 93313 CONTACT: CARTER, PAM PHONE #: 661-327-9341 CONTACT: FISHER, DEE PHONE #: 661-398-5941 ***** COMMENT LINES ***** The services described in this document have been provided in a manner consistent with the current standards of the profession and to the best of my knowledge comply with all applicable state and local statutes, regulations and ordinances. TANK #1: DIESEL FUEL 2 TYPE: STEEL SN: -.07 TANK IS TIGHT. TANK #2: REG UNLEADED TYPE: STEEL SN: -.10 TANK IS TIGHT. OPERATOR: _ D.E8MS£-GOODAN SIGNATURE: _ _ _ _ _ _ _~:-_ _ _ _ _ __ _ _ _ _ DATE: -------- ~ '~ - ******* TAN K D A T A TANK NO. TANK NO. 1 2 TANK DIAMETER (IN) 96 96 LENGTH (FT) 26.59 26.59 VOLUME ( GAL) 10000 10000 TYPE ST ST FUEL LEVEL (IN) 68 69 FUEL TYPE DIESEL 2 REG UNLD dVOL/dy (GAL/IN) 120.56 119.26 CALIBRATION ROD DISTANCE 1 10.65625 2 26.95313 3 41.93750 4 56.93750 5 74.93750 - ******** TANK NO. 3 TANK NO. 4 ~.~ ~. - ******* C U S TOM E R JOB NUMBER CUSTOMER (COMPANY NAME) CUSTOMER CONTACT (LAST, FIRST): ADDRESS - LINE 1 ADDRESS - LINE 2 CITY, STATE ZIP CODE (XXXXX-XXXX) PHONE NUMBER (XXX)XXX-XXXX ******* COM MEN T ******* SIT E SITE NAME (COMPANY NAME) SITE CONTACT (LAST, FIRST) ADDRESS - LINE 1 ADDRESS - LINE 2 CITY, STATE ZIP CODE (XXXXX-XXXX) PHONE NUMBER (XXX)XXX-XXXX GROUND WATER LEVEL (FT) NUMBER OF TANKS LENGTH OF PRE-TEST (MIN) LENGTH OF TEST (MIN) e D A T A ******** 000120 CAL-VALLEY EQUIPMENT CARTER, PAM 3500 GILMORE AVE. BAKERSFIELD, CA. 93308 661-327-9341 L I N E S ******* D A T A ******** WIBLE ROAD SERVICE CENTER FISHER, DEE 4100 WIBLE ROAD BAKERSFIELD, CA. 93313 661-398-5941 20 2 30 180 0}- ~ ....". __ 10 tI) Lù :t () Z - Q o , ~ ...J ~ ...J Z w -5 '" z < :I: Ü -10 I ~ i: -15 o I' I 15 5 o - - .1ØØ29 -,lØIla IAJ( RAIE: ,81858 GPH GAIN PTALL. VlJlSIOIt 3.81 15 30 , - - - - _. - e CI': 45 6û i::f " ". ~ 10 en w J: Ü :z ... o o . ........ ...J 0 ~ ...J Z w -5 ø z -< :I: Q -10 -15 o 15 5 - e Cr: STAHl TIllE: 11 :38:28:88 CUJUlEttT rllE:12: 3Ð : 28: 8Ø a·-~ aa ."\.-t.J<" - ".} - ,ØØØ68 -.8ØØ37 .81585 GPH GIll" PTALL, UERSI(II 3.11 15 30 45 6() TANK TESTERS, INC. P. O. BOX 95 GARDINER, OREGON 97441 (541) 271-1124 TEST LOCATION: WIBLE ROAD SERVICE CENTER 4100WIBLE ROAD BAKERSFIELD, CALIFORNIA e· CAMPO MILLER PL400 PRODUCT LINE TEST RESULTS DATE: 4-21-00 TANK NO, TESTED TEST INITAL FINAL VOLUME LEAK RATE LEAK RATE TES RESULTS DURATION PRESSURE PRESSURE DISPLACED PA$S I FAIL DIESEL 2 REG UNLD I 1 5 50 49 -4 -0.0095 PASS I 2 5 50 46 -7 -0.0167 PASS I I e COMMENTS: Leak Detectors Functioning Properly? DIESEL 2 YES REG UNLD YES Q~~,~ DENNIS E. GOODAN California Lic ¥l91-1 000 I ....'~ '. i ~ -..r""", .,-'1, - -- '-.9<:1\1'1.0 -.J-"¡.'\::) . PLOT PLAN JOBSITE LOCATION /,JiM;; !1-0ð¡tJ S'eNUtC£ C.e-reA. "(DoW.6Le; /lo.6-¡I.) 1]I}Kt.....J .ç, ¡;; Cd. (Ð. ./ '" t '-' V\ ~\ "i!r. , <. ~ '- o -s: ~ .1 N w E S ~, '- . .. ... - ~(Q)A i0;þ March 29, 2000 PG&E 4101 Wible Rd Bakersfield, CA 93313 Dear Underground Tank Owner: Your permit to operate the above mentioned fueling facility will expire on June 30, 2000. However, in order for this office to renew your permit, updated forms A, B & C must be filled out and returned prior to the issuance of a new permit. Please make arrangements to have the new forms A, B & C completed and returned to this office by May 15,2000. For your convenience, I am enclosing all three forms which you may make copies of. Remember, forms B & C need to be filled out for each tank at your facility. Should you have any questions, please feel free to contact me at (661) 326-3979. Sincerely, Steve Underwood, Inspector Office of Environmental Services SU/dlm Enclosure