Lee Schavrien - SoCalGas · new short-term contract filed with the CPUC by informational letter on February 23, 2000, and also included in the Joint Recommendation, approved pursuant

Lee SchavrienLee SchavrienDirector

Regulatory Case Managementand Tariff Administration

101 Ash StreetSan Diego, CA 92101-3017

Tel: 619 . 696 . 4050Fax: 619 . 696 . 4027

Pager: 619 . 526 . [email protected]

May 19, 2000

SoCalGas Advice No. 2917(U 904 G)

Public Utilities Commission of the State of California

Subject: 1999 BCAP Rate Implementation Filing

Sempra Energy, on behalf of Southern California Gas Company (SoCalGas), hereby submitsfor approval by the California Public Utilities Commission (Commission) revisions to SoCalGas'tariff schedules, applicable throughout its service territory, as shown on Attachment B, to beeffective June 1, 2000.

This filing is made in compliance with Ordering Paragraph (OP) 1 of Decision No. 00-04-060,dated April 20, 2000 in SoCalGas’ 1999 Biennial Cost Allocation Proceeding (BCAP),Application No. 98-10-012.

Purpose

The purpose of this filing is to implement the revenue requirements adopted by theCommission in SoCalGas’ 1999 BCAP. The overall rate change is a decrease in rates of$204.2 million.

Tariff Revisions

In addition to the before mentioned rate decrease, the following are descriptions of the tariffrevisions ordered by various sections of D.00-04-060 that are included with this filing:

Preliminary Statements

Preliminary Statement, Part V, Balancing Accounts

Preliminary Statement, Part V, Balancing Accounts is updated to reflect two aspects of theCommission approved Joint Recommendation in the SoCalGas BCAP case (D.00-04-060,Appendix A). First, the Noncore Fixed Cost Account (NFCA) is updated to reflect a returnto 75%/25% (ratepayer/shareholder) balancing treatment for noncore revenues excludingcertain transactions pursuant to Finding of Fact 9.o. The NFCA will record 75% of thevariance between the seasonally adjusted noncore revenue requirement and recordednoncore revenues. The Noncore Storage Balancing Account (NSBA) is also updated to

Advice No. 2917 - 2 - May 19, 2000

reflect 50%/50% balancing treatment of unbundled storage revenues as defined in Findingof Fact 9.k.

Preliminary Statement, Part VI, Memorandum Accounts

The Environmental Fee Account (EFA) and Fuel Cell Proceeds Memorandum Account(FCPMA) are eliminated consistent with the uncontested testimony of SoCalGas witness,Ronald M. van der Leeden Exhibit 13 and late-filed Exhibit 196 – Table D to update theregulatory account balances.

A new Wheeler Ridge Firm Access Charge Memorandum Account (WRFACMA) is added toprevent the double recovery of Wheeler Ridge facility costs consistent with SoCalGas’Reply Comments to the Proposed Decision.

Preliminary Statement, Part VII, Tracking Accounts

Pursuant to D.99-11-021, Ordering Paragraph (OP) 1, the ITCSA is revised to include aseparate subaccount to record the surcharges from interstate pipeline capacityrelinquishments allocated solely to noncore customers less the noncore’s portion of thecredits from the El Paso settlement.

The Interim Zone Rate Credit Account (IZRCA) and PBR Audit Expense Tracking Account(PBRAETA) are eliminated consistent with the uncontested testimony of SoCalGas witness,Ronald M. van der Leeden Exhibit 13 and late-filed Exhibit 196 – Table D to update theregulatory account balances.

The Noncore Fixed Cost Tracking Account (NFCTA) language is revised to reflect thecontinuation of the account beyond the Global Settlement period.

Preliminary Statement, Part X, Global Settlement

Sections D, E and F of Preliminary Statement, Part X, Global Settlement are no longerapplicable and are therefore eliminated.

Preliminary Statement, Part XI, PBR

The Preliminary Statement, Part XI, PBR is updated as follows:• Section B is updated pursuant to Finding of Fact 111.• Section F.5. and G.4.a. is revised/eliminated to reflect the rolled-in rate treatment for the

Wheeler Ridge facilities pursuant to Findings of Fact 48 and 49.• Section G.3.d. is updated to reflect the exclusion from the PBR sharing mechanism of

the shareholders 25% share of the noncore revenues variance and the shareholders50% share of the unbundled storage revenues variance pursuant to Finding of Fact 9.o.and 9.k., respectively.

• Section L.1.a. is updated pursuant to Finding of Fact 9.p.• Section L.1.c. is added pursuant to Finding of Fact 9.q to describe the revenue

treatment for the Noncore Competitive Load Growth Opportunities.• Section K.2.b. has revised full LRMC transportation rates and class average LRMC floor

rates pursuant to Appendix D of D.00-04-060.

Advice No. 2917 - 3 - May 19, 2000

Residential Schedules

Baseline reduction

Pursuant to Finding of Fact 100, for all residential rate schedules the summer baselineallowance for climate zones 1, 2, and 3 is reduced from 15 therms to 14 therms and thewinter baseline allowance for climate zones 1, 2, and 3 from 50 therms, 65 therms, and 87therms, respectively, to 49 therms, 59 therms, and 69 therms, respectively.

Large Master Metered Tariffs

Pursuant to Finding of Fact 102, Schedule No. GMB, Large Multi-Family Service, andSchedule No. GT-MB, Core Aggregation Transportation for Large Multi-Family Service,have been revised by lowering the annual consumption requirement from 250,000 thermsto 100,000 therms1.

Core Commercial & Industrial Tariffs

G-10 & G-20 Customer Classes Combined

Pursuant to Finding of Fact No. 104, two existing tariff Schedules GN-20 and GT-20 havebeen combined into Schedules GN-10 and GT-10 respectively, and are hereby eliminated,and a $10 customer charge for small commercial customers using less than 1000 thermsannually is adopted. Appropriate changes have been made to Schedule Nos. G-AC andGT-AC, Rule Nos. 30 and 36, and Agreement for Non-Core Status, GN-20 or GT-20 (Form6486) to reflect this revision.

Non-Core Tariffs

Core Subscription

Pursuant to Finding of Fact 106, Schedule No. G-CS for core subscription service hasbeen revised. The fixed monthly reservation charge has been replaced with a volumetricbased reservation charge. Accordingly, the annual true-up of reservation chargespreviously required by Schedule No. G-CS, which accounts for customers utilizing morethan their contracted peak month quantity, will cease upon the effective date of rates in thisproceeding. Coincident with the effective date of rates in this proceeding, core subscriptioncustomers will immediately be billed for any true-up amounts accrued under the priorSchedule No. G-CS.

1 SoCalGas filed on May 11, 2000 an Emergency Petition to Modify Decision No. 00-04-060 to change the

GMB rates using the fully-scaled new customer only methodology. SoCalGas also filed concurrently aMotion for a Partial Stay of D.00-04-060 to prevent the implementation of the BCAP adopted GMB ratesand rate design in case the Emergency Petition to Modify is not acted upon before June 1, 2000.

Advice No. 2917 - 4 - May 19, 2000

Schedules G-CS, GT-F & GT-I

Pursuant to Finding of Fact 29, the exemplary tariff Special Conditions are incorporated in anew Electric Generation section, replacing the Cogeneration Section, and eliminating theCGA.

Pursuant to Finding of Fact 30, the special considerations reserved for cogenerationcustomers during open seasons for transmission service are removed.

Pursuant to Finding of Fact 41, the EG class is segmented above and below 3 milliontherms annually.

Pursuant to Finding of Fact 105, the noncore commercial/industrial customers aresegmented into distribution and transmission subclasses, each of which has a singlecustomer charge and a declining block rate schedule.

Schedule G-ITC

Pursuant to Finding of Fact 53, Schedule G-ITC is modified to eliminate the firm andinterruptible volumetric charges, the zone rate credit, and fuel charge components.

Wholesale Tariffs

New Vernon Tariff

Pursuant to Finding of Fact 8, which approves the Joint Recommendation, a new wholesaletariff for the City of Vernon, GW-VRN, is filed herein. References to Vernon service areaccordingly deleted from the noncore transmission tariffs.

Long Beach, San Diego & Southwest Gas

Pursuant to Finding of Fact 106, Schedule No. G-CS, Core Subscription Natural GasService, has been revised. The Core Subscription sections of each wholesale tariff, GW-LB, GW-SD and GW-SWG, have been revised accordingly (see Core Subscription above)

Additional revisions to GW-LB are also being filed to reflect the changes implemented in thenew short-term contract filed with the CPUC by informational letter on February 23, 2000,and also included in the Joint Recommendation, approved pursuant to Finding of Fact 8.

Storage Tariffs

Pursuant to Finding of Fact 9.k, the ceiling reservation charge specified in G-TBS will be nohigher than 120% of the sum of the individual charges set forth in Schedule No. G-LTS.Additionally, the pricing flexibility is added to Schedules G-BSS and G-LTS.

Pursuant to Finding of Fact 30, the Special Conditions section for Cogeneration Customersis removed from the G-AUC, G-BSS, and G-LTS storage tariffs.

Advice No. 2917 - 5 - May 19, 2000

Revised Rules

Revised Rule 1, Definitions

Pursuant to Finding of Fact 9.q, a definition of Red Team has been added.

Revised Rule 38, Equipment Incentive Program, and Sample Forms

Pursuant to Finding of Fact 9.q, which adopts the proposed treatment of Red Team andRule 38 incentive revenues, Rule 38 is revised accordingly. Required new and revisedSample Form Contracts are filed herein to facilitate these changes.

Incorporated herein as Attachment C is a Summary of Present and Proposed Rates.

Rate Impact by Class of Service

Applicable Net M$Class of Service Rate Schedules Increase/(Decrease)

Core GR, GT-R, GS, GT-S (158,890)GM, GT-M, GMB, GT-MBGRL, GT-RL, GSL, GT-SLGO-SSA, GTO-SSA, GO-SSBGTO-SSB, GO-AC, GTO-AC, GLGN-10, GT-10, GN-10L, GT-10LG-AC, GT-AC, G-EN, GT-ENG-NGV, GT-NGV

Noncore G-CS, GT-F, GT-I (31,901)

Wholesale GT-SD, GW-LB, GW-SD, GW-SWG, (19,795)GW-VRN

International 974

Unbundled Storage G-BSS, G-LTS, G-AUC, G-TBS (6,979)

Unallocated Costs to NSBA 11,187

Net CARE Revenues 1,171______________ ________

SYSTEM TOTAL (204,233)

Total CARE Revenues (27,707)

EOR Revenues (9,839)

Advice No. 2917 - 6 - May 19, 2000

Protests

Anyone may protest this advice letter to the California Public Utilities Commission. The protestmust state the grounds upon which it is based, including such items as financial and serviceimpact, and should be submitted expeditiously. The protest must be made in writing andreceived within 20 days of the date this advice letter was filed with the Commission. There is norestriction on who may file a protest. The address for mailing or delivering a protest to theCommission is:

IMC Branch Program ManagerEnergy DivisionCalifornia Public Utilities Commission505 Van Ness Avenue, Room 4002San Francisco, CA 94102

A copy should also be mailed to the attention of Energy Division-IMC Branch, Room 4005 (atthe address shown above). It is also requested that a copy of the protest be sent via electronicmail and facsimile to Sempra Energy on the same date it is mailed or delivered to theCommission (at the addresses shown below).

Attn: Sid NewsomRegulatory Tariff AdministrationSempra Energy - GT14D6555 West Fifth StreetLos Angeles, CA 90013-1011Facsimile No. (213) 244-4957E-Mail: [email protected]

Attn: C. Richard SwansonRegulatory Tariff ManagerSempra Energy - HQ14C101 Ash StreetSan Diego, CA 92101-3017Facsimile No. (619) 696-4027E-Mail: [email protected]

Questions regarding this advice letter should be directed to Steve Rahon of Sempra Energyat (619) 696-4331.

Effective Date

In accordance with Ordering Paragraph 1 of D.00-04-060, this filing is effective for service onand after June 1, 2000.

Advice No. 2917 - 7 - May 19, 2000

Notice

In accordance with Section III.G of General Order No. 96-A, a copy of this advice letter is beingsent to the parties listed on Attachment A and to the parties in A.98-10-012 and A.98-10-031.

_________________________________LEE SCHAVRIEN

Director -- Regulatory Case Managementand Tariff Administration

Sempra Energy

Attachments

ATTACHMENT A

Advice No. 2917

General Order 96-A Distribution List

Burbank Public Service Department

California Manufacturers Association

City of Anaheim Public Utilities Department

City of Azusa Light and Power Department

City of Banning Municipal Utilities

City of Lompoc

City of Los Angeles

City of Riverside, Public Utilities Department

City of Vernon, Director, Water & Power Department

Colton Bureau of Light & Water

General Services Administration, San Francisco

General Services Administration, Washington D.C.

Glendale Public Service Department

Imperial Irrigation District

Long Beach Gas Department

Los Angeles Department of Water and Power

March Air Force Base

Naval Facilities Engineering Command, Western Division

Pacific Gas and Electric Company

Pasadena Water and Power Department

San Diego Gas & Electric Company

San Gabriel Valley Water Company

Southern California Edison Company

Southwest Gas Corporation

The Utility Reform Network

Vandenberg Air Force Base

Patrick J. Power2101 Webster St., Suite 1500Oakland, CA 94612

Paul M. Premo310 Hazel AvenueMill Valley, CA 94941-5054

Alcantar & ElsesserAlexis K. WodtkeOne Embarcadero, #2420San Francisco, CA 94111

Alcantar & Elsesser LLPEvelyn ElsesserOne Embarcadero Center, #2420San Francisco, CA 94111

Alcantar & Elsesser LLPMichael Peter Alcantar1300 SW Fifth Ave., #1750Portland, OR 97201

BETA ConsultingJohn Burkholder2023 Tudor LaneFallbrook, CA 92028

Barkovich & Yap, Inc.Catherine E. YapP. O. Box 11031Oakland, CA 94611

Berliner, Camdon & JimisonJohn W. Jimison1225 19th St., N.W., Ste. 800Washington, D.C. 20036

Brady & BerlinerThomas Beach2560 Ninth Street, #316Berkeley, CA 94710

Butler & Binion, LLPRichard E. Powers, Jr.1001 Pennsylvania Ave., N.W.Suite 300 SouthWashington, DC 20004

CECScott Tomashefsky1516 Ninth Street, MS-22Sacramento, CA 95814-5512

CECW. William Wood1516 Ninth Street, MS-23Sacramento, CA 95814

CPUCALJ Steven Kotz505 Van Ness Ave., Rm. 5101San Francisco, CA 94102

CPUCLaura Krannawitter505 Van Ness Avenue, #3207San Francisco, CA 94102

CPUC - ALJ DivisionALJ Robert A. Barnett505 Van Ness AvenueSan Francisco, CA 94102

CPUC - ALJ DivisionSteven A. Weissman505 Van Ness AvenueSan Francisco, CA 94102

CPUC - LegalPatrick L. Gileau, Esq.505 Van Ness AvenueSan Francisco, CA 94102

CPUC - Legal DivisionDarwin Farrar505 Van Ness Ave., Rm. 5032San Francisco, CA 94102

CPUC - ORADexter Khoury505 Van Ness Avenue, Rm. 4002San Francisco, CA 94102

CPUC - ORAJoyce Alfton505 Van Ness Ave., Rm 4101San Francisco, CA 94102

CPUC - ORARichard A. Myers505 Van Ness AvenueSan Francisco, CA 94102

CPUC - ORARobert Mark Pocta505 Van Ness AvenueSan Francisco, CA 94102

CPUC - Public Advisor OfficeRosalina White505 Van Ness Ave., #5303San Francisco, CA 94102

California Independent PetroleumWilliam Julian II1127 Eleventh Street, #226Sacramento, CA 95814

Cambridge Energy Research AssociatePeter Moritzburke1999 Harrison St., #950Oakland, CA 94612

Cameron McKenna LLPMichael S. Hindus2175 K Street N.W.Washington, D.C. 20037

Chevron U.S.A.David R. Stevenson1301 McKinney St., Rm. 2236Houston, TX 77010

City of BurbankFred Fletcher164 West Magnolia Blvd., Box 631Burbank, CA 91503-0631

City of VernonKenneth J. de Dario, Director4305 Santa Fe Ave.Vernon, CA 90058

Davis Wright TremaineAnita Taff-RiceOne Embarcadero Center, #600San Francisco, CA 94111

Case Id: A9810012 Case Description: 1999 BCAP Page: 1

Downey Brand Seymour & RohwerDan L. Carroll555 Capitol MallSacramento, CA 95814-4686

Downey, Brand, Seymour & RohwerPhilip A. Stohr555 Capitol Mall, #1050Sacramento, CA 95814

Electric Clearinghouse, Inc.Gregory T. Blue5976 W. Las Positas Bl., #200Pleasanton, CA 94588

Ellison & SchneiderAndrew B. Brown2015 H StreetSacramento, CA 95814-3109

Energy Law Group LLPAndrew J. Skaff1999 Harrison Street, 27th FloorOakland, CA 94612

Goodin MacBride Squeri Schlotz &Brian T. Cragg505 Sansome, Suite 900San Francisco, CA 94111

Goodin, MacBride, Squeri, SchlotzJames D. Squeri505 Sansome St., Suite 900San Francisco, CA 94111

Goodin, MacBride, Squeri, Schlotz &James W. McTarnaghan, Esq.505 Sansome Street, #900San Francisco, CA 94111

Goodin, MacBride, Squeri, Schlotz &Michael B. Day, Esq.505 Sansome Street, #900San Francisco, CA 94111

Harbor Cogeneration CoScott Hawley, Exec. Director18101 Von Karman Ave., #1700Irvine, CA 92612

Imperial Irrigation DistrictRonald B. Cox333 East Barioni Blvd.Imperial, CA 92251

Jeffer, Mangels, Butler & MarmaroEdward W. O'NeillOne Sansome Street, 12th FloorSan Francisco, CA 94104-4430

Jones, Day, Reavis, & PogueNorman A. Pedersen, Esq.555 West 5th Street, #4600Los Angeles, CA 90013-1025

Jones, Day, Reevis & PogueGregory Klatt555 W. Fifth Street, #4600Los Angeles, CA 90013

LADWPRoger Pelote111 North Hope Street, Rm. 1104Los Angeles, CA 90012

Law Office of Richard L. HamiltonRichard L. Hamilton, Esq.100 Howe Ave., #230NSacramento, CA 95825

Luce, Forward, Hamilton & ScrippsJohn W. Leslie600 West Broadway, #2600San Diego, CA 92101-3391

PG&EJennifer Post77 Beale Street, Rm. 3025-B30ASan FRancisco, CA 94105

PG&EKeith T. Sampson77 Beale StreetSan Francisco, CA 94105

PG&ESandy Dickinson77 Beale StreetSan Francisco, CA 94105

Pacific Gas and Electric Co.Frank R. LindhP. O. Box 7442San Francisco, CA 94120

Pasadena - Water and PowerRufus Hightower150 S. Los Robles St., #200Pasadena, CA 91101

Praxair, IncRick Noger175 East Park DriveTonawanda, NY 14151-0044

Reliant Energy Retail, IncRobert B. TaskP. O. Box 4455Houston, TX 77002-52311111 Louisiana St.Houston, TX 77002

Resource Management InternationalCharles Doering225 W. Broadway, #400Glendale, CA 91204

Southern California Edison Co.Gloria M. Ing2244 Walnut Grove Ave.Rosemead, CA 91770

Southwest Gas CorporationJohn C. Walley5241 Spring MountainP. O. Box 98510Las Vegas, NV 89193-8512

Southwest Gas CorporationKeith BrownP. O. Box 98510Las Vegas, NV 89193-8510

Sutherland, Asbill & BrennanKeith R. McCrea1275 Pennsylvania Ave., N.W.Washington, D.C. 20004-2403

TURNMarcel Hawiger711 Van Ness Ave., #350San Francisco, CA 94102


Texaco, Inc.John BeallP. O. Box 4596, 1111 Rusk St.Houston, TX 77210

U. C. A. N.Michael Shames1717 Kettner Blvd., Suite 105San Diego, CA 92101

White & Case LLPJerry R. Bloom2 Embarcadero Center, #650San Francisco, CA 94111-3162

White & Case LLPJoseph M. Karp2 Embarcadero Center, #650San Francisco, CA 94111-3162

White & Case LLPPaul LacourciereTwo Embarcadero Center, #650San Francisco, CA 94111

Williams Companies, Inc.Alex Goldberg1 Williams Center, MD 41-3Tulsa, OK 74172


32485-G Preliminary Statement, Summary of Rates and Charges, Sheet 1 of 13

32453-G


32454-G


32124-G


32125-G & 32455-G


32455-G & 32440-G


32440-G


32127-G


32128-G


31471-G


32456-G


32457-G & 32458-G


32458-G & 32132-G

ATTACHMENT BAdvice No. 2917

Cal. P.U.C.Sheet No. Title of Sheet

Canceling Cal.P.U.C. Sheet No.


32132-G

32498-G Preliminary Statement, Cost Allocation & Revenue Requirement, Sheet 5 of 5

32133-G

32499-G Preliminary Statement, Regulatory Accounts - Balancing, Sheet 1 of 11

29704-G


29705-G


30047-G


29707-G & 29708-G


29708-G & 29709-G


29709-G & 29710-G


29711-G


29712-G


29713-G


29714-G





29715-G

32510-G Preliminary Statement, Regulatory Accounts - Memorandum, Sheet 1 of 14

31897-G* & 31898-G*


31898-G* & 31899-G*


31899-G* & 31900-G*


31900-G* & 31901-G*


31901-G* & 31902-G*


31902-G* & 31903-G*


31903-G* & 31904-G*


31904-G* & 31905-G*


31905-G* & 31906-G*


31906-G* & 31907-G*


31907-G* & 31908-G*





31908-G* & 31908.1-G


31908.1-G & 31909-G*


31909-G*

32524-G Preliminary Statement, Regulatory Accounts - Tracking, Sheet 1 of 6

31044-G


31045-G & 31046-G


31046-G & 31047-G


31047-G & 31048-G


31048-G,31049-G,31050-G


31050-G & 31051-G

32530-G Preliminary Statement, Global Settlement, Sheet 1 of 4

26312-G


26313-G


26314-G





26315-G & 26316-G

32534-G Preliminary Statement, Performance Based Regulation, Sheet 1 of 29

30173-G


30174-G


30175-G


30176-G


30177-G


30178-G


30179-G


30180-G


30181-G


30182-G


30183-G





30184-G


30185-G


30186-G


30187-G


30188-G


30189-G


30190-G


30191-G


30192-G


30193-G


30194-G


30195-G





30196-G





30196-G & 30197-G


30197-G

32563-G Schedule No. GR, Residential Service, Sheet 2 of 4

32459-G

32564-G Schedule No. GR, Residential Service, Sheet 3 of 4

30820-G

32565-G Schedule No. GT-R, CAT Residential Service, Sheet 2 of 4

32135-G

32566-G Schedule No. GT-R, CAT Residential Service, Sheet 3 of 4

31174-G

32567-G Schedule No. GS, Multi-Family Service Submetered, Sheet 1 of 5

32136-G


32460-G





30828-G

32570-G Schedule No. GT-S, CAT Multi-Family Submetered Svc, Sheet 1 of 5

32138-G


32139-G


31177-G

32573-G Schedule No. GM, Multi-Family Service, Sheet 2 of 6

32461-G


30834-G*


30835-G

32576-G Schedule No. GT-M, CAT Multi-Family Service, Sheet 2 of 6

32141-G

32577-G Schedule No. GT-M, CAT Multi-Family Service, Sheet 3 of 6

31181-G

32578-G Schedule No. GMB, Large Multi-Family Service, Sheet 1 of 6

30844-G


32462-G


30846-G*





30847-G


30848-G

32583-G Schedule No. GT-MB, CAT Large Multi-Family Service, Sheet 1 of 6

31185-G


32143-G


31186-G

32586-G Schedule No. GRL, Residential Service, Income-Qualified, Sheet 2 of 5

32463-G

32587-G Schedule No. GRL, Residential Service, Income-Qualified, Sheet 3 of 5

30858-G

32588-G Schedule No. GT-RL, CAT Residential Svc, Income-Qualified, Sheet 2 of 5

32145-G

32589-G Schedule No. GT-RL, CAT Residential Svc, Income-Qualified, Sheet 3 of 5

31191-G

32590-G Schedule No. GSL, Submetered MF Svc, Income-Qualified, Sheet 1 of 6

32146-G


32464-G


30868-G*




32593-G Schedule No. GT-SL, CAT Submetered MF Svc, Income-Qualified, Sheet 1 of 6

32148-G


32149-G


31195-G

32596-G Schedule No. GO-SSA, Summer Saver Rate - Owns Exist. Equip., Sheet 2 of 5

32465-G


31251-G


31252-G

32599-G Schedule No. GTO-SSA, Trans-Only Summer Saver - Owns Equip., Sheet 2 of 5

32151-G

32600-G Schedule No. GTO-SSA, Trans-Only Summer Saver - Owns Equip., Sheet 3 of 5

31256-G

32601-G Schedule No. GO-SSB, Summer Saver Rate - Equip. Purch./Repair, Sheet 2 of 5

32466-G


31261-G


31262-G

32604-G Schedule No. GTO-SSB, Trans-Only Summer Saver - Equip Purch, Sheet 2 of 5

32153-G




32605-G Schedule No. GTO-SSB, Trans-Only Summer Saver - Equip Purch, Sheet 3 of 5

31582-G

32606-G Schedule No. GO-AC, Optional Rate - Air Conditioning, Sheet 2 of 5

32467-G


31275-G


31276-G

32609-G Schedule No. GTO-AC, Trans-Only Optional Rate - Air Condition, Sheet 2 of 5

32155-G


31280-G


31585-G

32612-G Schedule No. GL, Street and Outdoor Lighting Gas Svc, Sheet 1 of 2

32468-G

32613-G Schedule No. GN-10, Core Svc for Small Commerical/Industrial, Sheet 1 of 5

29361-G


29361-G & 32469-G


32469-G & 32470-G


32470-G & 31023-G





31023-G

32618-G Schedule No. GT-10, CAT Core Comm/Indus Service, Sheet 1 of 6

29979-G


29979-G & 32159-G


32159-G


32159-G & 32160-G


32160-G & 29980-G


29980-G

32624-G Schedule No. GN-10L, Core Comm/Indus Svc, Income-Qualified, Sheet 1 of 9

29369-G


29369-G


32471-G


31024-G


31510-G





31511-G


31512-G


31513-G


31514-G

32633-G Schedule No. GT-10L, CAT Comm/Indus Svc, Income-Qualified, Sheet 1 of 9

31515-G*


31515-G* & 32162-G


32162-G & 31517-G*


31517-G* & 31518-G*


31518-G* & 31519-G*


31519-G* & 31520-G*


31520-G* & 31521-G*


31521-G* & 31522-G*





31522-G* & 31523-G*

32642-G Schedule No. G-AC, Core A/C Svc for Commercial/Industrial, Sheet 1 of 6

29392-G


32474-G


29394-G

32645-G Schedule No. GT-AC, Core Trans-Only A/C Svc for Comm/Ind, Sheet 1 of 7

29991-G

32646-G Schedule No. GT-AC, Core Trans-Only A/C Svc for Comm/Ind, Sheet 2 of 7

32168-G

32647-G Schedule No. G-EN, Core Gas Engine Svc for Water Pumping, Sheet 2 of 3

32475-G

32648-G Schedule No. GT-EN, Core Trans-Only Gas Eng Svc for Wtr Pump, Sheet 1 of 3

32170-G

32649-G Schedule No. G-NGV, Natural Gas Svc for Motor Vehicles, Sheet 2 of 3

32476-G

32650-G Schedule No. GT-NGV, Trans Cust-Owned Gas for Motor Vehicle, Sheet 1 of 4

32172-G

32651-G Schedule No. GT-NGV, Trans Cust-Owned Gas for Motor Vehicle, Sheet 2 of 4

32173-G

32652-G Schedule No. G-CS, Core Subscription Service, Sheet 1 of 8

31476-G & 32446-G





32446-G & 32174-G


32174-G & 32175-G


30091-G*


30092-G & 30093-G


30093-G & 31478-G


31478-G & 31479-G


31480-G & 31481-G

32660-G Schedule No. GT-F, Firm Intrastate Transmission Service, Sheet 1 of 8

31482-G & 32176-G


32177-G


30098-G*


30099-G


30100-G





31484-G


31485-G & 31486-G


31486-G,31487-G,31488-G

32668-G Schedule No. GT-I, Interruptible Intrastate Transmission Sv, Sheet 1 of 6

31489-G & 32178-G


32178-G & 32179-G


32179-G & 31492-G


31492-G & 31493-G


31493-G,31494-G,31495-G


31495-G & 31496-G

32674-G Schedule No. GT-SD, Intrastate Transmission Svc-San Diego, Sheet 1 of 4

32180-G

32675-G Schedule No. GW-LB, Wholesale Gas Svc-Long Beach, Sheet 1 of 7

32181-G & 32447-G


32447-G & 32448-G





26348-G & 26349-G


26349-G & 26350-G


26350-G,26351-G,26352-G


26352-G & 26196-G


26196-G

32682-G Schedule No. GW-SD, Wholesale Gas Svc-San Diego, Sheet 1 of 5

32448-G


32183-G


27162-G & 27163-G


27163-G & 27163-G


27164-G & 27197-G

32687-G Schedule No. GW-SWG, Wholesale Gas Svc-Southwest Gas, Sheet 1 of 5

32449-G


32185-G





24514-G


24515-G & 24516-G


24516-G & 27198-G

32692-G Schedule No. GW-VRN, Wholesale Gas Svc-Vernon, Sheet 1 of 6






32698-G Schedule No. G-ITC, Interconnect Access Service, Sheet 1 of 2

31677-G,32186-G*,31679-G

32699-G Schedule No. G-ITC, Interconnect Access Service, Sheet 2 of 2

31679-G

32700-G Schedule No. G-BSS, Basic Storage Service, Sheet 1 of 8

32187-G





32187-G & 32188-G


32188-G & 26729-G


26729-G & 27910-G


27910-G & 27063-G


27063-G & 28090-G


28090-G & 28091-G


28091-G & 24535-G

32708-G Schedule No. G-AUC, Auction Storage Service, Sheet 1 of 8

31922-G


32189-G


26731-G


26036-G


24540-G





27078-G


27079-G & 31923-G


27081-G

32716-G Schedule No. G-LTS, Long-Term Storage Service, Sheet 1 of 8

32190-G


32190-G & 31925-G


31925-G & 32191-G


26780-G & 26781-G


26781-G


26782-G


26783-G


31926-G & 26785-G

32724-G Schedule No. G-TBS, Transaction Based Storage Service, Sheet 1 of 7

32191.1-G




32725-G Schedule No. G-TBS, Transaction Based Storage Service, Sheet 2 of 7

32192-G

32726-G Schedule No. G-CFS, Surcharge for CARE Discount, Sheet 1 of 1

31498-G

32727-G Schedule No. G-LOAN, Hub Loan Service, Sheet 1 of 1

32193-G

32728-G Schedule No. G-PRK, Hub Parking Service, Sheet 1 of 1

32194-G

32729-G Schedule No. G-WHL, Wheeling Service, Sheet 1 of 1

32195-G

32730-G Rule No. 01, Definitions, Sheet 3 of 14 30006-G*

32731-G Rule No. 01, Definitions, Sheet 4 of 14 30007-G*

32732-G Rule No. 01, Definitions, Sheet 5 of 14 30007-G* & 30008-G**

32733-G Rule No. 01, Definitions, Sheet 6 of 14 30008-G** & 30009-G*

32734-G Rule No. 01, Definitions, Sheet 7 of 14 30009-G* & 30010-G**

32735-G Rule No. 01, Definitions, Sheet 8 of 14 30010-G** & 30011-G**

32736-G Rule No. 01, Definitions, Sheet 9 of 14 30011-G** & 30012-G*

32737-G Rule No. 01, Definitions, Sheet 10 of 14 30012-G* & 30013-G

32738-G Rule No. 01, Definitions, Sheet 11 of 14 30013-G & 30014-G*

32739-G Rule No. 01, Definitions, Sheet 12 of 14 30014-G* & 30015-G*




32740-G Rule No. 01, Definitions, Sheet 13 of 14 30015-G* & 30016-G

32741-G Rule No. 01, Definitions, Sheet 14 of 14 30016-G & 30017-G*

32742-G Rule No. 23, Continuity of Svc/Interruption of Delive, Sheet 1 of 12

24642-G**

32743-G Rule No. 30, Transportation of Cust-Owned Gas, Sheet 4 of 12

30586-G

32744-G Rule No. 36, Interstate Capacity Brokering, Sheet 5 of 8

27296-G

32745-G Rule No. 38, Comm/Ind Equipment Incentive Program, Sheet 1 of 5

27945-G


27945-G & 27946-G


27946-G & 27947-G


27947G & 27948-G


32750-G Sample Forms, Contract, Agreement for Non-Core Status, Sheet 1 of 1

19412-G

32751-G Sample Forms, Contract, Equipment Incentive Program, Sheet 1 of 1

27949-G

32752-G Sample Forms, Contract, Equip Incentive




Prog (Attach), Sheet 1 of 1

32753-G Sample Forms, Contract, Equip Incent Prog (Affidavit), Sheet 1 of 1

32754-G Sample Forms, Contract, Red Team Affidavit, Sheet 1 of 1

32755-G Table of Contents, Rate Schedules, Sheet 1 of 3

32479-G


32480-G


32451-G

32758-G Table of Contents, Rules, Sheet 1 of 2 31826-G

32759-G Table of Contents, Rules, Sheet 2 of 2 31202-G

32760-G Table of Contents, Sample Forms, Sheet 2 of 5

31533-G*

32761-G Table of Contents, Sample Forms, Sheet 3 of 5

32028-G*

32762-G Table of Contents, General and Preliminary Statement, Sheet 1 of 2

32481-G

32763-G Table of Contents, General and Preliminary Statement, Sheet 2 of 2

30199-G*




32453-G

32485-G

LOS ANGELES, CALIFORNIA

CAL. P.U.C. SHEET NO.


RevisedRevisedCANCELING

SOUTHERN CALIFORNIA GAS COMPANY

(TO BE INSERTED BY UTILITY) (TO BE INSERTED BY CAL. P.U.C.)

291700-04-060

William L. ReedADVICE LETTER NO.

DECISION NO.

ISSUED BY

VICE PRESIDENTCHIEF REGULATORY OFFICER

MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

PART IISUMMARY OF RATES AND CHARGES

1 13PRELIMINARY STATEMENT

(continued)

Sheet of

RESIDENTIAL CORE SALES SERVICE (1) Commodity Charge (per therm)

Schedules GR, GS & GMBaseline Usage ..................................................................... 57.128¢Non-Baseline Usage ............................................................. 75.112¢Customer Charge: 16.438¢/meter/day

Schedule GMBBaseline Usage ..................................................................... 58.937¢Non-Baseline Usage ............................................................. 68.012¢Customer Charge: $5.304/meter/day

Schedules GRL & GSLBaseline Usage ..................................................................... 48.559¢Non-Baseline Usage ............................................................. 63.846¢Customer Charge: 13.973¢/meter/day

RESIDENTIAL CORE AGGREGATION SERVICE Transmission Charge (per therm)

Schedules GT-R, GT-S & GT-MBaseline Usage ..................................................................... 24.121¢Non-Baseline Usage ............................................................. 42.105¢Customer Charge: 16.438¢/meter/day

Schedule GT-MBBaseline Usage ..................................................................... 25.930¢Non-Baseline Usage ............................................................. 35.005¢Customer Charge: $5.304/meter/day

Schedules GT-RL & GT-SLBaseline Usage ..................................................................... 20.503¢Non-Baseline Usage ............................................................. 35.789¢Customer Charge: 13.973¢/meter/day

(1) The residential core procurement charge as set forth in Schedule No. G-CP is 32.723¢/therm which includes the core brokerage fee.

RR

IIR

RR

RR

IIR

RR

32454-G

32486-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

13PRELIMINARY STATEMENT

(continued)

Sheet of

NON-RESIDENTIAL CORE SALES SERVICE (1) Commodity Charge (per therm)

Schedule GN-10 (2)GN-10: Tier I ................................................................ 71.003¢

Tier II ............................................................... 55.678¢Tier III .............................................................. 42.730¢

GN-10V: Tier I ................................................................ 71.003¢Tier II ............................................................... 52.501¢Tier III .............................................................. 42.730¢

Customer Charge: 32.877¢/meter/day

Schedule GN-10LGN-10L: Tier I ................................................................. 60.353¢

Tier II ................................................................ 47.326¢Tier III ............................................................... 36.321¢


Schedule G-ACG-AC: rate per therm ..................................................... 41.274¢G-ACL: rate per therm ..................................................... 35.083¢Customer Charge: $150/month

Schedule G-ENG-EN: rate per therm ..................................................... 50.780¢Customer Charge: $50/month

Schedule G-NGVG-NGU: rate per therm ..................................................... 43.792¢G-NGC: rate per therm ..................................................... 78.792¢P-1 Customer Charge: $13/monthP-2A Customer Charge: $65/month

(1) The non-residential core procurement charge as set forth in Schedule No. G-CP is 32.723¢/therm which includes the core brokerage fee.

(2) Schedule GL rates are set commensurate with Rate Schedule GN-10.

R | | | | |R

R | |R

RR

I

II

32124-G

32487-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of

NON-RESIDENTIAL CORE AGGREGATION SERVICE Transmission Charge (per therm)

Schedule GT-10GT-10: Tier I ................................................................. 37.996¢

Tier II ................................................................ 22.671¢Tier III ............................................................... 9.723¢

GT-10V: Tier I ................................................................. 37.996¢Tier II ................................................................ 19.494¢Tier III ............................................................... 9.723¢


Schedule GT-10LGT-10L: Tier I .................................................................. 32.297¢

Tier II ................................................................. 19.270¢Tier III ................................................................ 8.265¢


Schedule GT-10NGT-10N: Tier I .................................................................. 34.497¢

Tier II ................................................................. 19.172¢Tier III ................................................................ 6.224¢


Schedule GT-ACGT-AC: rate per therm ................................................... 8.267¢GT-ACL: rate per therm ................................................... 7.027¢Customer Charge: $150/month

Schedule GT-ENGT-EN: rate per therm ................................................... 17.773¢Customer Charge: $50/month

Schedule GT-NGVGT-NGU: rate per therm ................................................... 10.785¢GT-NGC: rate per therm ................................................... 45.785¢P-1 Customer Charge: $13/monthP-2A Customer Charge: $65/month

R | | | | |R

R | |R

N | | |N

RR

I

II

32125-G & 32455-G

32488-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of

NONCORE RETAIL SERVICE

Schedules G-CS, GT-F, & GT-I

Noncore Commercial/Industrial (G-CS3, GT-F3 & GT-I3)

Customer Charge:

G-CS3D/GT-F3D/GT-I3D (Distribution Level):Per month ............................................................................. $350

G-CS3T/GT-F3T/GT-I3T (Transmission Level):Per month ............................................................................. $700

Transmission Charges:G-CS3D/GT-F3D/GT-I3D (Distribution Level):

Tier I 0 - 20,833 Therms ............................................... 10.091¢Tier II 20,834 - 83,333 Therms ...................................... 6.238¢Tier III 83,334 - 166,667 Therms .................................... 3.773¢Tier IV Over 166,667 Therms .......................................... 2.011¢

G-CS3T/GT-F3T/GT-I3T (Transmission Level):Tier I 0 - 166,667 Therms .............................................. 5.448¢Tier II Over 166,667 Therms ........................................... 1.214¢

Enhanced Oil Recovery (G-CS4, GT-F4 & GT-I4)Transmission Charge .......................................................................... 2.596¢Customer Charge: $500/month

Electric Generation (G-CS5, GT-F5 & GT-I5)For customers using less than 3 million therms per year

Transmission Charge ..................................................................... 5.740¢Customer Charge: $50

For customers using 3 million therms or more per yearTransmission Charge ..................................................................... 2.540¢Customer Charge: N/A

T

TD,NDTD,N

TTD,NN |NDTD,NN

I

LN | |NL,RL

32455-G & 32440-G

32489-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


(continued)

Sheet of

WHOLESALE SERVICE

Schedule GW-LB (Long Beach, G-CS7, GT-F7 & GT-I7)Volumetric Charge ........................................................................... 2.160¢ITCS-LB ......................................................................................... 0.789¢

Schedule GW-SD and GT-SD (San Diego Gas & Electric, G-CS8, GT-F8, GT-I8, GT-F11 & GT-I11)Volumetric Charge .............................................................................. 1.448¢ITCS-SD ............................................................................................ 0.789¢

Schedule GW-SWG (Southwest Gas, G-CS9, GT-F9 & GT-I9)Volumetric Charge ............................................................................... 4.318¢Storage Reservation Charge (per year) .......................................... $1,321,752

Schedule GW-VRN (City of Vernon, G-CS10, GT-F10 & GT-I10)Transmission Charge .......................................................................... 1.706¢ITCS-VRN ......................................................................................... 0.789¢

PROCUREMENT CHARGE

Schedule G-CPNon-Residential Core Procurement Charge, per therm ....................... 32.723¢Residential Core Procurement Charge, per therm ............................... 32.723¢

Schedule G-CSCore Subscription Procurement Charge, per therm ............................. 30.662¢

Schedule GW-LB, GW-SD, GW-SWG and GW-VRNCore Subscription Procurement Charge, per therm ............................. 30.515¢

CORE SUBSCRIPTION RESERVATION CHARGE

Schedule G-CS, GW-LB, GW-SD, GW-SWG and GW-VRNRate, per therm ................................................................................... 3.211¢

L,D

IRD

RR

N |N

T

L

L,TD,N

32440-G

32490-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)


(continued)

Sheet of

IMBALANCE SERVICE

Standby Procurement

Core Retail Standby (SP-CR)February, 2000 ......................................................................... 39.216¢March, 2000 ............................................................................. 38.451¢April, 2000 ............................................................................... 45.030¢

Noncore Retail Standby (SP-NR)February, 2000 ......................................................................... 39.281¢March, 2000 ............................................................................. 38.516¢April, 2000 ............................................................................... 45.095¢

Wholesale Standby (SP-W)February, 2000 ......................................................................... 39.092¢March, 2000 ............................................................................. 38.330¢April, 2000 ............................................................................... 44.878¢

Buy-Back Rate

Core and Noncore Retail (BR-R)February, 2000 ......................................................................... 13.005¢March, 2000 ............................................................................. 12.750¢April, 2000 ............................................................................... 14.943¢

Wholesale (BR-W)February, 2000 ......................................................................... 12.942¢March, 2000 ............................................................................. 12.688¢April, 2000 ............................................................................... 14.871¢

L

32127-G

32491-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)


(continued)

Sheet of

STORAGE SERVICE

Schedule G-BSS (Basic Storage Service)Reservation Charges

Annual Inventory, per decatherm reserved ........................................... 21.400¢/yearAnnual Withdrawal, per decatherm/day reserved ................................. $11.584/yearMonthly Injection, per decatherm/day reserved ..................................... 9.425¢/day

Variable Injection Charges (April through November only)In-Kind Energy Charge, percent reduction ............................................. 2.440%Operating and Maintenance Charge

Rate, per therm available for injection ............................................... 0.127¢

Variable Withdrawal Charges (November through March only)Operating and Maintenance Charge

Rate, per therm available for injection ............................................... 0.177¢

Transmission ChargesTransmission Charge for all quantities injected

Rate, per therm ................................................................................. 5.670¢Transmission Credit for storage quantities withdrawn

Rate, per therm ................................................................................. 5.670¢

Schedule G-AUC (Auction Storage Service)Reservation Charges

Annual Inventory, per decatherm reserved ............................................. (1)Annual Withdrawal, per decatherm/day reserved ................................... (1)Monthly Injection, per decatherm/day reserved ...................................... (1)

Variable Injection Charges (April through November only)In-Kind Energy Charge, percent reduction ............................................. 2.440%Operating and Maintenance Charge

Retail, per therm available for injection ............................................. 0.127¢Wholesale, per therm available for injection ...................................... 0.127¢


Retail, per therm available for injection ............................................ 0.177¢Wholesale, per therm available for injection ..................................... 0.177¢

(1) Charge shall be equal to the awarded price bid by the customer.

IRR

R

R

RR

RR

32128-G

32492-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)


(continued)

Sheet of

STORAGE SERVICE (continued)

Schedule G-AUC (continued)

Transmission ChargesTransmission Charge for all quantities injected

Rate, per therm ................................................................................. 5.670¢Transmission Credit for storage quantities withdrawn

Rate, per therm ................................................................................. 5.670¢

Schedule G-LTS (Long-Term Storage Service)

Reservation ChargesAnnual Inventory, per decatherm reserved ........................................... 21.400¢/yearAnnual Withdrawal, per decatherm/day reserved ................................. $11.584/yearMonthly Injection, per decatherm/day reserved ..................................... 9.425¢/day

Variable Injection Charges (April through November only)In-Kind Energy Charge, percent reduction, per therm ............................. 2.440%Operating and Maintenance Charge




Transmission Charges Transmission Charge for all quantities injected

Rate, per therm ................................................................................ 5.670¢Transmission Credit for storage quantities withdrawn

Rate, per therm ................................................................................. 5.670¢

IRR

RR

RR

31471-G

32493-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


9

(continued)


(continued)

Sheet of

SURCHARGE TO FUND CALIFORNIA ALTERNATE RATES FOR ENERGY DISCOUNT

Schedule G-CFS

Surcharge, per therm ................................................................................ 0.121¢

SURCHARGE TO FUND PUC UTILITIES REIMBURSEMENT ACCOUNT

Schedule G-SRF

Surcharge, per therm ................................................................................. 0.076¢

TRANSPORTED GAS MUNICIPAL SURCHARGE

Schedule G-MSUR

Surcharge Percentage, Outside the City of Los Angeles ............................... 1.4828%Surcharge Percentage, Within the City of Los Angeles ................................. 2.0000%

T,RD

32456-G

32494-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


10

(continued)


(continued)

Sheet of

RATE COMPONENT SUMMARY

CORE

Residential Sales Service Charge(per therm)

Base Margin 39.721¢Other Operating Costs/Revenues 2.078¢Transition Costs 0.094¢Balancing/Tracking Account Amortization (3.789)¢Core Averaging/Other Noncore (0.999)¢Core Pipeline Demand Charges 3.499¢Procurement Rate (w/o Brokerage Fee) 32.522¢Core Brokerage Fee Adjustment 0.201¢Procurement Carrying Cost of Storage Inventory 0.051¢San Juan Lateral Pipeline Demand Charge 0.233¢

------------Total Costs 73.612¢

Non-Residential - Commercial/Industrial Charge(per therm)

Base Margin 22.135¢Other Operating Costs/Revenues 1.797¢Transition Costs 0.094¢Balancing/Tracking Account Amortization (3.750)¢Core Averaging/Other Noncore 3.047¢Core Pipeline Demand Charges 3.499¢Procurement Rate (w/o Brokerage Fee) 32.522¢Core Brokerage Fee Adjustment 0.201¢Procurement Carrying Cost of Storage Inventory 0.051¢San Juan Lateral Pipeline Demand Charge 0.233¢

------------Total Costs 59.829¢

IIRRIR

RI

R

N

N | | | | | | | |N

N

32457-G & 32458-G

32495-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


11

(continued)


(continued)

Sheet of

RATE COMPONENT SUMMARY (continued)

CORE (continued)

Non-Residential - Air Conditioning Charge(per therm)

Base Margin 11.085¢Other Operating Costs/Revenues 0.014¢Transition Costs 0.094¢Balancing/Tracking Account Amortization (3.726)¢Core Pipeline Demand Charges 3.499¢Procurement Rate (w/o Brokerage Fee) 32.522¢Core Brokerage Fee Adjustment 0.201¢Procurement Carrying Cost of Storage Inventory 0.051¢San Juan Lateral Pipeline Demand Charge 0.233¢

------------Total Costs 43.974¢

Non-Residential - Gas Engine Charge(per therm)

Base Margin 20.119¢Other Operating Costs/Revenues 0.417¢Transition Costs 0.094¢Balancing/Tracking Account Amortization (3.746)¢Core Pipeline Demand Charges 3.499¢Procurement Rate (w/o Brokerage Fee) 32.522¢Core Brokerage Fee Adjustment 0.201¢Procurement Carrying Cost of Storage Inventory 0.051¢San Juan Lateral Pipeline Demand Charge 0.233¢

------------Total Costs 53.391¢

D

IIR |R

RI

R

LL

L,IL,IL,R |L,RLLL,RL,ILL,I

32458-G & 32132-G

32496-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


12

(continued)


(continued)

Sheet of


NON-CORE

Commercial/Industrial Charge(per therm)

Base Margin 4.629¢Other Operating Costs/Revenues 0.100¢Transition Costs 0.547¢Balancing/Tracking Account Amortization 0.172¢

------------Total Transportation Related Costs 5.448¢

Electric Generation Charge(per therm)



Wholesale - City of Long Beach Charge(per therm)



L

IIRR

R

IIRI

R

LL

L,RL,IL,RL,ILL,R

32132-G

32497-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


13

(continued)


Sheet of


NON-CORE (continued)

Wholesale - San Diego Gas & Electric Charge(per therm)



Wholesale - Southwest Gas Charge(per therm)



Wholesale - City of Vernon Charge(per therm)



L

RIRR

R

RIRI

R

N | | | | | | |N

32133-G

32498-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

PART IIICOST ALLOCATION AND REVENUE REQUIREMENT

5

(continued)


Sheet of

B. REVENUE REQUIREMENT: (Continued)

16. GAS MARGIN

This amount shall be the total annual base revenues authorized by the Commission. The authorized gas margin pursuant to Decision No. 00-04-060 effective June 1, 2000 is $1,393,892,000. Of the total revenues $1,196,131,000 is allocated to the core market and $186,575,000 is allocated to the noncore market. The allocated noncore margin includes EOR revenues of $20,014,000, and an unbundled storage cost of $21,000,000. Unallocated costs are $11,187,000.

17. COST AND REVENUE ALLOCATION FACTORS

These factors were determined pursuant to Decision No. 00-04-060, dated April 20, 2000 and are used to allocate costs and revenues to the core and noncore customer classes.

FactorNoncore

Cost Categories: Core (including wholesale)Transition Costs 0.088 0.912Unaccounted-for Gas 0.721 0.279Company Use Gas: Storage 0.657 0.343NGV Balancing Account 0.422 0.578Storage Transition and Bypass Account 0.358 0.642Core Fixed Cost Account 1.000 0.000Enhanced Oil Recovery Account 0.908 0.092

Revenue Categories:Exchange and Interutility Transactions 0.381 0.619Core Brokerage Fee Adjustment 1.000 0.000Noncore Brokerage Fee Adjustment 0.000 1.000Fuel Cell Equipment Revenues 0.889 0.111

T,IR,IRI,N

T

R,II,RR,I |R,I

R,I

R,I

29704-G

32499-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

PART VDESCRIPTION OF REGULATORY ACCOUNTS - BALANCING


(continued)

Sheet of

A. GENERAL

Balancing accounts are those regulatory accounts where authorized expenses are compared with revenues from rates designed to recover those expenses. The resulting under- or overcollection, plus interested calculated in the manner described in Preliminary Statement, Part I, is recorded on the Utility's financial statements as an asset or liability, which is owed from or due to the ratepayers. Balances in balancing accounts are to be amortized in rates.

B. LISTING OF BALANCING ACCOUNTS

Purchased Gas Account (PGA)

Core Fixed Cost Account (CFCA)

Noncore Fixed Cost Account (NFCA)

Enhanced Oil Recovery Account (EORA)

Noncore Storage Balancing Account (NSBA)

California Alternate Rates for Energy Account (CAREA)

Brokerage Fee Account (BFA)

Hazardous Substance Cost Recovery Account (HSCRA)

Natural Gas Vehicle Account (NGVA)

T

29705-G

32500-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)


(continued)

Sheet of

C. DESCRIPTION OF ACCOUNTS

PURCHASED GAS ACCOUNT (PGA)

The PGA is a balancing account. The purpose of this account is to balance the recorded cost of gas bought for the Utility portfolio with revenue from the sale of that gas.

a. The PGA consists of six subaccounts. They are:

1. The Core Subaccount which tracks the cost of gas procured for core customers and revenues from the sale of that gas.

2. The Core-Subscription Subaccount which tracks the cost of gas procured for core-subscription customers and revenues from the sale of that gas.

3. The Noncore Standby Service Subaccount which tracks the cost of gas purchases and the revenues from the sale of gas procured to provide standby procurement service for noncore customers.

4. The Excess Core Supply Subaccount which tracks the cost of gas purchases and the revenues from the sale of excess core supplies.

5. The Take-or-Pay Subaccount which tracks revenue from take-or-pay charges that core-subscription customers incur.

6. The Core Brokerage Fee Subaccount which tracks revenues from the core brokerage fee and the authorized core brokerage fee.

b. The Utility shall maintain the PGA by making entries at the end of each month as follows:

1. A debit entry equal to the recorded gas cost in the Utility Portfolio Account during the month, which includes all gas purchased for procurement customers.

2. Credit entries equal to the procurement revenue from the sale of gas delivered during the month and amortization of the forecasted revision date PGA balance, excluding the allowance for F&U.

T

30047-G

32501-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of

C. DESCRIPTION OF ACCOUNTS (continued)

PURCHASED GAS ACCOUNT (PGA) (continued)

3. A credit entry equal to the brokerage fee charged to core customers less the allowance for F & U.

4. A debit entry equal to 1/12 of the annual core brokerage fee revenue requirement.

5. An entry equal to the interest on the average of the balance in the account during the month, excluding the core-subscription subaccount, calculated in the manner described in Preliminary Statement, Part I, J.

CORE FIXED COST ACCOUNT (CFCA)

The CFCA is an interest bearing balancing account recorded on SoCalGas' financial statements. The purpose of this account is to balance the difference between authorized margin, transition, and other non-gas fixed costs allocated to the core market with revenues intended to recover these costs.

On a monthly basis, SoCalGas maintains this account as follows:

SoCalGas debits this account with the core portion of the following costs: gas margin costs, transition costs, and other non-gas operating costs.

SoCalGas credits this account with the core portion of the following revenues: transmission revenues from core deliveries; revenues from the brokering of underutilized core interstate pipeline capacity; revenues from the sale of core storage capacity rights; base revenues that would have been collected from customers absent the core pricing flexibility program; and other revenues that the Commission has directed SoCalGas to allocate to the core market.

In addition, SoCalGas adjusts this account to amortize previously accumulated overcollected or undercollected balances to reflect payment to, or recovery from, ratepayers. SoCalGas also adjusts this account to reflect volumetric differences associated with the core amortization recorded in other regulatory accounts.

T

29707-G & 29708-G

32502-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of


NONCORE FIXED COST ACCOUNT (NFCA)

The NFCA is an interest-bearing balancing account. The purpose of this account is to record the variance between forecasted and actual noncore and wholesale revenues, excluding Enhanced Oil Recovery (EOR) and unbundled storage revenues. Also excluded are (1) non-tariff contracts for service to DGN, (2) future non-tariff contracts with Sempra Energy affiliates not subject to competitive bidding, and (3) Competitive Load Growth Opportunities for noncore Rule 38 and Red Team incentive revenues.

On a monthly basis, SoCalGas maintains this account as follows:

SoCalGas debits this account with 75% of the seasonally forecasted noncore and wholesale revenues excluding the transactions stated above less F&U.

SoCalGas credits this account with 75% of the actual noncore and wholesale revenues excluding the transactions stated above less F&U.

In addition, SoCalGas adjusts this account to amortize previously accumulated overcollected or undercollected balances to reflect payment to, or recovery from, ratepayers.

ENHANCED OIL RECOVERY ACCOUNT (EORA)

This EORA is a balancing account. The purpose of this account is to balance recorded EOR revenue with forecasted EOR revenues.

The Utility shall maintain the EORA by making entries at the end of each month as follows:

a. A debit entry equal to one-twelfth of the forecasted EOR revenue amount used to offset the revenue requirement in the most recent annual cost-allocation proceeding;

b. A debit entry equal to the amortization of the forecasted revision date EORA balance;

c. A credit entry equal to 3.0 cents per therm plus 75 percent of EOR non-gas revenue under contracts signed on or before December 3, 1986, and an amount equal to the short-run marginal cost plus 95 percent of EOR non-gas revenue under contracts signed subsequent to December 3, 1986. EOR non-gas revenue shall equal revenue from EOR customers excluding the following:

T | | | |TDN | | | | | | | |N

L | | | | | | | | | | | | | | |L

T

29708-G & 29709-G

32503-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


(continued)

Sheet of


ENHANCED OIL RECOVERY ACCOUNT (EORA) (continued)

1. A floor rate of 3.0¢ per therm for contracts signed on or before December 3, l986, and a floor rate equal to the short-run marginal cost for contracts signed subsequent to December 3, 1986,

2. Gas procurement costs, and3. Interutility transportation costs; and4. LUAF, CU and CCSI.

d. An entry equal to interest on the average of the balance in the account during the month, calculated in the manner described in Preliminary Statement, Part I, J.

NONCORE STORAGE BALANCING ACCOUNT (NSBA)

The NSBA is a balancing account. The purpose of this account is to (1) balance the authorized at-risk non-gas costs for unbundled storage service as authorized in Decision No.00-04-060 and the reservation and in-kind energy charge revenues collected from customers who contract for these unbundled storage services, and (2) record the unallocated fully scaled unbundled noncore storage revenue requirement.

The Utility shall maintain the NSBA by making entries at the end of the month as follows:

a. A credit entry equal to 50% of all reservation and variable O&M charge revenues less (a) the revenues collected from the reservation charges resulting from the Utility's sale of core storage capacity rights under Schedule No. G-AUC, (b) the allowance for F&U on net revenue, as applicable, and (c) the reservation charge revenues collected for subscribed unbundled storage service from expansion storage facilities;

b. A debit entry equal to 50% of one-twelfth of the authorized at-risk non-gas costs allocated to unbundled storage service (i.e., $21 million annually pursuant to D.00-04-060), less the allowance for F&U on net revenue, as applicable;

c. A debit entry equal to 50% of Company use fuel and well incidents allocated to the unbundled storage programs,

d. A debit entry equal to the difference between 100% of one-twelfth of the authorized fully scaled unbundled noncore storage revenue requirement and one-twelfth of the $21 million at-risk unbundled storage level pursuant to D.00-04-060, less the allowance for F&U on net revenue, as applicable;

T | |TDT

T,DL | |L

T,LT,DL

N | | | | |N

T

29709-G & 29710-G

32504-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)


(continued)

Sheet of


NONCORE STORAGE BALANCING ACCOUNT (NSBA) (continued)

e. An entry equal to the authorization of the forecasted remaining balance less F&U; and,

f. An entry equal to the interest on the average of the balance in the account during the month, calculated in the manner described in Preliminary Statement, Part I, J.

The balance of the NSBA shall be allocated in the Utility's cost allocation proceedings to all customers.

CALIFORNIA ALTERNATE RATES FOR ENERGY ACCOUNT (CAREA)

The CAREA is a balancing account. The purpose of this account is to balance California Alternate Rates for Energy (CARE) program expenses incurred against revenues received.

Commencing on the effective date of this tariff, Utility shall maintain the CAREA by making entries at the end of each month as follows:

a. A debit entry equal to recorded administrative costs for the CARE program.

b. A debit entry equal to the recorded CARE program discounts billed for the month, excluding F&U.

c. A debit entry equal to revenue shortfalls associated with discounts to the service establishment charge adopted in D.97-04-082 and implemented in D.97-07-054 for CARE customers.

d. A debit entry equal to the revenue shortfall associated with the discounted customer charge adopted for CARE program customers.

e. A credit entry equal to recorded CARE program surcharge billed for the month, excluding F&U.

f. An entry equal to the amortization of the forecasted revision date CAREA balance.

g. An entry equal to the interest on the average of the balance in the account during the month, calculated in the manner described in Preliminary Statement, Part I, J.

T,L

T,LL

T,L

L | | | | | | | | | | | | | | | | | | | | | | |L

T

29711-G

32505-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)


(continued)

Sheet of


BROKERAGE FEE ACCOUNT (BFA)

The BFA is a balancing account. The purpose of the BFA is to balance authorized noncore brokerage fee costs and recorded actual brokerage fee revenues.

Effective January 1, 1995, the Utility shall maintain the BFA by making entries at the end of each month as follows:

Noncore Subaccount

a. A debit entry equal to one-twelfth of the authorized annual noncore brokerage fee costs;

b. A credit entry equal to the monthly recorded revenues collected from the noncore brokerage fee surcharge; and,

c. An entry equal to the interest on the average of the balance in the account during the month using the interest rate described in Preliminary Statement, Part I, J herein.

HAZARDOUS SUBSTANCE COST RECOVERY ACCOUNT (HSCRA)

The HSCRA is a balancing account, which compares covered hazardous substance and insurance litigation costs related to manufacturing gas plant sites, presently identified federal Superfund sites, and other sites identified by the Utility with recoveries from third parties, insurance carriers, and ratepayers as set forth in D. 94-05-020. The HSCRA consists of five subaccounts:

Subaccount A - Hazardous Substance Cost Subaccount - Ratepayer's 90% ShareSubaccount B - Hazardous Substance Cost Subaccount - Shareholder's 10% ShareSubaccount C - Insurance Litigation Cost Subaccount - Ratepayer's 70% ShareSubaccount D - Insurance Litigation Cost Subaccount - Shareholder's 30% ShareSubaccount E - Insurance Recovery Subaccount

Effective June 3, 1994, the following entries are recorded to the HSCRA at the end of each month:

Hazardous Substance and Insurance Litigation Costs

a. A debit entry is recorded to Subaccount A equal to 90% of covered hazardous substance costs.

b. A debit entry is recorded to Subaccount B equal to 10% of covered hazardous substance costs.

T

29712-G

32506-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)


(continued)

Sheet of


HAZARDOUS SUBSTANCE COST RECOVERY ACCOUNT (continued)

Hazardous Substance and Insurance Litigation Costs (continued)

c. A debit entry is recorded to Subaccount C equal to 70% of covered insurance litigation costs.

d. A debit entry is recorded to Subaccount D equal to 30% of covered insurance litigation costs.

Ratepayer Recovery

e. A credit entry is recorded to Subaccount A equal to the revenues collected from customers net of franchise fees and uncollectibles.

Third Party Recovery

f. A credit entry is recorded to Subaccount A equal to 90% of recoveries from third parties.

g. A credit entry is recorded to Subaccount B equal to 10% of recoveries from third parties.

Insurance Carrier Recovery

h. A credit entry is recorded to Subaccount E equal to insurance recoveries net of contingency fees, if any. Each insurance recovery will be recorded separately and distributed against covered hazardous substance and insurance litigation costs on a first-in, first-out basis.

i. A credit entry is recorded to Subaccount C equal to the lesser of 70% of insurance recoveries net of contingency fees paid to outside attorneys to obtain recoveries, if any, or the balance in Subaccount C. Subaccount C cannot have a credit balance.

j. A credit entry is recorded to Subaccount D equal to the lesser of 30% of insurance recoveries net of contingency fees paid to outside attorneys to obtain recoveries, if any, or the balance in Subaccount D. Subaccount D cannot have a credit balance.

k. A credit entry is recorded to Subaccount B equal to the lesser of 90% of the remaining insurance recoveries net of contingency fees paid to outside attorneys to obtain recoveries, if any, not applied in entry i. and j. above or the balance in Subaccount B.

T

29713-G

32507-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


9

(continued)


(continued)

Sheet of



l. A credit entry is recorded to Subaccount A for the lesser of 10% of the remaining insurance recoveries net of contingency fees paid to outside attorneys to obtain recoveries, if any, not applied in entry i. and j. above or 11.111% of the insurance recoveries net of contingency fees paid to attorneys to obtain recoveries, if any, recorded in Subaccount B.

m. A debit entry is recorded to Subaccount E equal to the sum of insurance recoveries allocated to Subaccount A through D in entries i. through l. above.

n. A debit entry is recorded to Subaccount E, 72 months after receiving a specific insurance recovery for one-fifth or 20% of the balance for that specific insurance recovery in Subaccount E. The entry is only recorded if the recovery has not been fully allocated to offset covered hazardous substance and insurance litigation costs.

o. If an entry is recorded for entry n. above, a credit entry is recorded to Subaccount A for 60% of entry n. to recognize the ratepayer's portion of the insurance recovery. The difference between entries n. and o. or 40% of entry n. is the Utility's share of the insurance recovery.

p. A debit entry is recorded to Subaccount E, 84 months after receiving a specific insurance recovery for one-fourth or 25% of the balance for that specific insurance recovery in Subaccount E. The entry is only recorded if the recovery has not been fully allocated to offset covered hazardous substance and insurance litigation costs.

q. If an entry is recorded for entry p. above, a credit entry is recorded to Subaccount A for 60% of entry p. to recognize the ratepayer's portion of the insurance recovery. The difference between entries p. and q. or 40% of entry p. is the Utility's share of the insurance recovery.

r. A debit entry is recorded to Subaccount E, 96 months after receiving a specific insurance recovery for one-third or 33.333% of the balance for that specific insurance recovery in Subaccount E. The entry is only recorded if the recovery has not been fully allocated to offset covered hazardous substance and insurance litigation costs.

s. If any entry is recorded for entry r. above, a credit entry is recorded to Subaccount A for 60% of entry r. to recognize the ratepayer's portion of the insurance recovery. The difference between entries r. and s. or 40% of entry r. is the Utility's share of the insurance recovery.

T

29714-G

32508-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


10

(continued)


(continued)

Sheet of



t. A debit entry is recorded to Subaccount E, 108 months after receiving a specific insurance recovery for one-half or 50% of the balance for that specific insurance recovery in Subaccount E. The entry is only recorded if the recovery has not been fully allocated to offset covered hazardous substance and insurance litigation costs.

u. If an entry is recorded for entry t. above, a credit entry is recorded to Subaccount A for 60% of entry t. to recognize the ratepayer's portion of the insurance recovery. The difference between entries t. and u. or 40% of entry t. is the Utility's share of the insurance recovery.

v. A debit entry is recorded to Subaccount E, 120 months after receiving a specific insurance recovery for any remaining portion of the specific insurance recovery in Subaccount E. The entry is only recorded if the recovery has not been fully allocated to offset covered hazardous substance and insurance litigation costs.

w. If an entry is recorded for entry v. above, a credit entry is recorded to Subaccount A for 60% of entry v. to recognize the ratepayer's portion of the insurance recovery. The difference between entries v. and w. or 40% of entry v. is the Utility's share of the insurance recovery.

x. An entry to Subaccounts A through E equal to interest on the average balance in the account during the month, calculated in the manner described in the Preliminary Statement, Part I, J.

Upon final disposition of all covered hazardous substance and insurance litigation costs and related recoveries, any balance remaining in Subaccounts B and D will be the responsibility of the Utility.

T

29715-G

32509-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


11

(continued)


Sheet of


NATURAL GAS VEHICLE ACCOUNT (NGVA)

The NGVA is an interest bearing balancing account recorded on SoCalGas' financial statements. The purpose of this account is to balance actual natural gas vehicle (NGV) program costs with actual NGV program net revenues. D.92-01-021 (NGV Pilot) established the NGVA, and D.95-11-035 (Low Emission Vehicles) authorized SoCalGas to continue using this account for the six-year NGV program period of December 21, 1995, through December 20, 2001.

In addition to the ratepayer-funded NGV program authorized by D.95-11-035, Resolution G-3191a authorized a throughput sharing mechanism for ratepayers and SoCalGas shareholders. In return for shareholder-funded NGV promotional expenses, shareholders get a portion of the revenue on throughput above a schedule proscribed in Resolution G-3191a.

The NGVA consists of the following two subaccounts: Natural Gas Vehicle Operations Account (NGVOA), and Natural Gas Vehicle Revenue Account (NGVRA). On a monthly basis, SoCalGas maintains these subaccounts as follows:

SoCalGas debits the NGVOA for operation and maintenance costs associated with compressed natural gas (CNG) fueling stations, incremental vehicle lease payments for SoCalGas fleet NGVs, program support activities, labor overhead costs and related taxes, and audit expenses, if any. SoCalGas also makes an entry to amortize prior balances resulting from the net of the NGVRA and NGVOA.

SoCalGas credits the NGVRA with NGV revenues, and debits the NGVRA for the cost of gas, company use and lost and unaccounted for gas costs, and electricity costs associated with making CNG, if any.

For each BCAP filing, SoCalGas will reconcile this account and adjust rates as needed. If there is a balance due from (to) ratepayers, pursuant to Commission order, SoCalGas will increase (decrease) rates to recover the balance. However, since program spending is limited for the six-year period and over-expenditures may not be recovered from ratepayers, shareholders absorb the balance in the event actual expenses exceed authorized levels.

T

31897-G* & 31898-G*

32510-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

PART VIDESCRIPTION OF REGULATORY ACCOUNTS - MEMORANDUM


(continued)

Sheet of

A. GENERAL

Memorandum accounts are special accounts authorized by the Commission for the purpose of tracking certain costs and revenues. Please refer to each individual memorandum account description for the specific accounting treatment applicable to each account.

B. LISTING OF MEMORANDUM ACCOUNTS

Conservation Expense Account (CEA)PCB Expense Account (PCBEA)Research Development and Demonstration Expense Account (RDDEA)Curtailment Violation Penalty Account (CVPA)Economic Practicality Shortfall Memorandum Account (EPSMA)Catastrophic Event Memorandum Account (CEMA)Interconnect Charge Memorandum Account (ICMA)Vernon Avoided Distribution Cost Memorandum Account (VADCMA)Noncore Cost/Revenue Memorandum Account (NCRMA)Interstate Capacity Step Down Account (ICSDA)Vernon Rate Savings Memorandum Account (VRSMA)Vernon Negotiated Core Contract Memorandum Account (VNCCMA)Earthquake Valve Installation Service Memorandum Account (EVISMA)Research Royalty Memorandum Account (RRMA)NGV Research Development & Demonstration Memorandum Account (RDDNGV)Intervenor Award Memorandum Account (IAMA)Z Factor Account (ZFA)Tax Interest Account (TIA)Energy Efficiency/DSM Memorandum Account (EEDSMMA)Applicant Installation Trench Inspection Memorandum Account (AITIMA)Wheeler Ridge Firm Access Charge Memorandum Account (WRFACMA)

C. DESCRIPTION OF ACCOUNTS

CONSERVATION EXPENSE ACCOUNT (CEA)

The CEA is an interest bearing memorandum account recorded on SoCalGas' financial statements. The purpose of this account is to track the difference between authorized costs in rates, and actual demand-side management program costs. This account covers regular and low income demand-side management programs.

D

D

N

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31898-G* & 31899-G*

32511-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)


(continued)

Sheet of


CONSERVATION EXPENSE ACCOUNT (CEA) (continued)

SoCalGas maintains this account by making monthly entries as follows: a) debits for actual demand-side management costs, e.g., conservation costs, low income weatherization ("Direct Assistance Program") costs, and other marketing program costs; and for amortization of balances, if any, due to ratepayers from prior program cycles where actual expenses fell short of authorized levels; and b) a credit entry for the authorized costs being collected in rates.

For each BCAP filing, SoCalGas will reconcile this account and adjust rates as needed. If there is a balance due to ratepayers, pursuant to Commission order, SoCalGas will return the balance plus interest to ratepayers via lower rates or will carry the balance forward to offset expenses in future proceedings. Since program spending is limited and over-expenditures may not be recovered from ratepayers, shareholders absorb the balance in the event actual expenses exceed authorized levels.

PCB EXPENSE ACCOUNT (PCBEA)

The PCBEA is a memorandum account recorded on the Utility's financial statements. The purpose of this account is to record all past and future costs associated with the Transwestern PCB arbitration proceeding, including capital costs. These PCB clean-up costs will be considered for rate recovery after arbitration is concluded, following a reasonableness review in an annual hazardous waste review proceeding.

Utility shall maintain the PCBEA by making entries into the account as follows:

a. Transfer all prior costs and authorized revenues into the account,

b. Make monthly debit entries equal to recorded PCB clean-up costs paid during the month.

RESEARCH DEVELOPMENT AND DEMONSTRATION EXPENSE ACCOUNT (RDDEA)

The RDDEA is an interest bearing memorandum account recorded on SoCalGas' financial statements. The purpose of this account is to track the difference between authorized costs in rates, and actual costs associated with research, development, and demonstration programs. D.97-07-054 (PBR) authorized SoCalGas to continue using this account through the five-year PBR period, December 31, 2002.

SoCalGas maintains this account by making monthly entries as follows: a) debit entries for actual research, development, and demonstration expenses; and for amortization of balances, if any, due to ratepayers from prior program cycles where actual expenses fell short of authorized levels; and b) a credit entry for authorized costs being collected in rates.

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31899-G* & 31900-G*

32512-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of


RESEARCH DEVELOPMENT AND DEMONSTRATION EXPENSE ACCOUNT (RDDEA) (continued)

At the end of the period, SoCalGas will reconcile this account and adjust rates as needed. If there is a balance due to ratepayers, pursuant to Commission order, SoCalGas will return the balance plus interest to ratepayers via lower rates or will carry the balance forward to offset expenses in future proceedings. Since program spending is limited and over-expenditures may not be recovered from ratepayers, shareholders absorb the balance in the event actual expenses exceed authorized levels.

CURTAILMENT VIOLATION PENALTY ACCOUNT (CVPA)

The CVPA is a memorandum account. The purpose of this account is to record actual revenues from the assessment of penalties for violation of curtailment, and expenses associated with installation of electronic metering for curtailment monitoring.

Commencing on August 1, 1991, Utility shall maintain CVPA by making entries at the end of each month as follows:

a. A credit entry equal to all curtailment penalty charges collected, and

b. A debit entry equal to recorded expenditures for installation of electronic metering for purpose of curtailment monitoring.

ECONOMIC PRACTICALITY SHORTFALL MEMORANDUM ACCOUNT (EPSMA)

The EPSMA is a memorandum account. The purpose of this account is to record the shortfall in revenue which occurs in the Core Fixed Cost Account (CFCA) as a result of large core customers being transferred from core service to noncore service by way of economic practicality during the period January 1, 1994 through the revision date of the Utility's next cost allocation proceeding.

Utility shall maintain the EPSMA by making entries at the end of each month as follows:

a. A debit entry equal to the revenue shortfall for the month calculated as the product of (1) all service quantities transferred to noncore service by way of economic practicality during the period of January 1, 1994 and the revision date of the Utility's next cost allocation proceeding and (2) the difference between the otherwise applicable core rate and the applicable noncore rate for such quantities.

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31900-G* & 31901-G*

32513-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of


CATASTROPHIC EVENT MEMORANDUM ACCOUNT (CEMA)

This memorandum account has been established pursuant to CPUC Resolution No. E-3238, dated July 24, 1991. The purpose of CEMA is to allow for the recovery of Utility's costs of restoring Utility services to its customers; repairing, replacing or restoring damaged Utility facilities; and complying with governmental agency orders in connection with events which are officially declared disasters by competent state or federal authorities. The costs recorded in CEMA will be recovered in rates only after request by the Utility and subsequent approval by the Commission as to the reasonableness of such costs.

Should a disaster occur, the Utility shall, if possible, inform the Executive Director of the CPUC by letter within thirty (30) days after the catastrophic event if the Utility has started booking costs in CEMA. Such letter shall specify the declared disaster, date, time, location, service area affected, impact on the Utility's facilities, and an estimate of the extraordinary costs expected to be incurred, with expense and capital items shown separately.

Upon declaration of a disaster or state of emergency, Utility shall maintain CEMA with entries made to this account at the end of each month as follows:

a. A debit entry equal to the amounts recorded in the Utility's Operations and Maintenance and Administrative and General Expense Accounts that were incurred as a result of the disaster and related events.

b. A debit/credit entry equal to:

1. depreciation expense on the average of the beginning and end-of-month balance of plant additions installed to restore service to customers, or to replace, repair, or restore any plant or facilities, or to comply with government agency orders, in connection with events declared disasters, at one-twelfth the annual depreciation rates approved by the CPUC for these plant accounts; plus

2. the return on investment on the average of the beginning and the end-of-month balance of plant additions installed to restore service to customers or replace, repair, or restore any plant or facilities, or to comply with government agency orders, in connection with events declared disasters, at one-twelfth of Utility's annual rate of return; plus

3. the return on the allowance for working capital using the calculations most recently adopted by the CPUC and the rate of return applicable in b.2. above; plus

L | | | | | | | | | | | | | | | |L

31901-G* & 31902-G*

32514-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


(continued)

Sheet of


CATASTROPHIC EVENT MEMORANDUM ACCOUNT (CEMA) (continued)

4. the return on net cost of removal of facilities required as a result of the disaster and related events, using the rate of return applicable in b.2. above; less

5. the return on the average of beginning and end-of-month accumulated depreciation, and an average accumulated net deferred taxes on income resulting from the normalization of federal tax depreciation, using the rate of return applicable in b.2. above.

c. A debit entry equal to federal and state taxes based on in come associated with item b. above, calculated at marginal tax rates currently in effect. This will include all applicable statutory adjustments.

For federal and state taxes, this will conform to normalization requirements as applicable. Interest cost will be at the Utility's most recently adopted percentage of net investment.

d. A credit entry to transfer all or a portion of the balance in the CEMA to other adjustment clauses for future rate recovery, as may be approved by the CPUC.

e. An entry equal to interest on the average balance in the account at the beginning of the month and the balance after the entries from a. through c. above, at a rate equal to one-twelfth the interest rate on Commercial Paper (prime, 3-month) for the previous month, as reported in the Federal Reserve Statistical Release, G.13, or its successor.

Entries in Items a. and b. above, shall be made net of the appropriate insurance proceeds.

The Utility shall record the balance in the CEMA as a deferred debit on its balance sheet with entries to the appropriate income statement accounts, as necessary.

INTERCONNECT CHARGE MEMORANDUM ACCOUNT (ICMA)

The ICMA is an interest bearing memorandum account, the balance of which is recorded on the Utility's financial statements. Pursuant to Decision No. 94-01-048, the purpose of the ICMA is to track charges that would have been assessed for access to the Utility's Wheeler Ridge Interconnection facility under original Schedule G-ITC, Pursuant to Decision No. 94-01-048 the allocation of ICMA costs associated with the period January 1, 1994 through April 13, 1994 are to be recovered through the ICMA surcharge as described in Schedule ITC.

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31902-G* & 31903-G*

32515-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)


(continued)

Sheet of


INTERCONNECT CHARGE MEMORANDUM ACCOUNT (ICMA) (continued)

The Utility shall maintain the ICMA by making the following entries at the end of each month:

a. A debit entry equal to the total charges that would have been assessed under Schedule G-ITC between July 13, 1993 (the original date of Schedule No. G-ITC) and December 31, 1993 and were subsequently refunded to customers pursuant to Decision No. 94-01-048.

b. A debit entry equal to the total charges that would have been assessed under Schedule No. G-ITC between January 1, 1994 and April 13, 1994 (the effective date of revised Schedule No. G-ITC).

c. A credit entry equal to the charges collected through the ICMA surcharge as described in Schedule G-ITC.

d. An entry equal to the interest on the average of the balance in the account during the month, calculated in the manner described in Preliminary Statement, Part I, J.

VERNON AVOIDED DISTRIBUTION COST MEMORANDUM ACCOUNT (VADCMA)

The VADCMA is a memorandum account, established pursuant to D.93-05-008, to record utility distribution costs that are identified as avoided by the service provided to Vernon under Schedules G-CS, GT-F, and GT-I. Allocation of avoided costs will be allocated in the Utility's cost allocation proceeding or whenever there is a Commission-authorized change in gas rates.

The Utility shall maintain the VADCMA by making entries to the account at the end of each month, as follows:

a. A debit entry equal to the value of distribution costs not currently reflected in rates identified as being avoided as a result of service to Vernon under Schedules G-CS, GT-F, and GT-I.

NONCORE COST/REVENUE MEMORANDUM ACCOUNT (NCRMA)

The NCRMA is an interest-bearing memorandum account. The NCRMA balance will only be recorded to the financial statements when the balance exceeds the revenue cap. Pursuant to D. 94-07-064, the variance between forecasted and actual noncore and wholesale revenues, excluding Enhanced Oil Recovery (EOR) and unbundled storage revenues is recorded in the account.

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31903-G* & 31904-G*

32516-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)


(continued)

Sheet of


NONCORE COST/REVENUE MEMORANDUM ACCOUNT (NCRMA) (continued)

The Utility will calculate rates for the five-year period, effective August 1, 1994 through July 31, 1999, for noncore cost allocation, based on 1991 actual throughput, subject to the following adjustments:

a. To reflect normal temperature conditions for the core market;

b. The transfer of UEG loads from Long Beach wholesale service to retail service;

c. The addition of Southwest Gas as a wholesale customer;

d. Core to noncore transfers.

The Utility shall retain 100% of the annual variance applicable only for cases where actual revenues exceed forecasted revenues, up to the annual noncore revenue variance cap, for the period effective August 1, 1994 and through July 31, 1999 as follows:

Year 1: $11 millionYear 2: $13 millionYear 3: $15 millionYear 4: $17 millionYear 5: $19 million

If at the end of any year, the variance, as measured pursuant to the above description, exceeds the annual variance cap for that year, the Utility shall retain 12.5% and credit 87.5% of the excess to the cost of service in the following year.

The utility shall maintain the NCRMA by making entries once the revenue cap has been exceeded as follows:

a. A debit entry equal to one twelfth (1/12) of the authorized annual cost used to develop the effective rates for noncore transportation service (excluding Enhanced Oil Recovery, EOR).

b. A credit entry equal to the recorded revenue from noncore transportation service less F & U (excluding EOR). In the event that the annual recorded revenues exceed the annual forecasted costs by more than the revenue cap, 87.5% of the excess will be recorded to the financial statements as a credit entry.

L | | | | | | | | | | | |L

31904-G* & 31905-G*

32517-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)


(continued)

Sheet of


NONCORE COST/REVENUE MEMORANDUM ACCOUNT (NCRMA) (continued)

c. An entry equal to the interest on the average balance in the account during the month calculated in the manner described in Preliminary Statement I, J.

INTERSTATE CAPACITY STEP-DOWN ACCOUNT (ICSDA)

The ICSDA account was established pursuant to D.95-12-037. The purpose of this account is to track all costs and cost savings and any cost surcharges associated with the relinquishment by SoCalGas of 300 MMcf/d on El Paso's system January 1, 1996 and its relinquishment of 450 MMcf/d (457 MMDth/d) on Transwestern's system November 1, 1996. The ICSDA is an interest bearing account and is not recorded on the Utility's financial statements.

a. Starting in January of 1996 and each month thereafter, the Utility will record to the ICSDA any cost savings associated with relinquishment of firm interstate transportation on El Paso based on the following calculation:

The capacity on El Paso prior to January 1, 1996 of 1,450 MMcf/d times the rate effective on December 31, 1995 minus the capacity at 1,150 MMcf/d multiplied by the current rate. Any adjustment to rates from January 1, 1996, resulting from a decision by the FERC in El Paso's General Rate Case, RP95-363-000, will be recorded to the ICSDA.

b. Pending a decision by the FERC in El Paso's General Rate Case, RP95-363-000, the Utility will record to the ICSDA any cost surcharges associated with relinquishment of firm interstate transportation on El Paso separate from the base rate.

c. Starting in November of 1996 and each month thereafter, the Utility will record to the ICSDA any cost savings associated with relinquishment of firm interstate transportation on Transwestern based on the following calculation:

The capacity on Transwestern prior to November 1, 1996 of 750 MMcf/d (763 MMDth/d) times the rate effective on October 31, 1996 minus the capacity at 300 MMcf/d (306 MMDth/d) multiplied by the current rate.

d. Starting in November of 1996, the Utility will record to the ICSDA any cost surcharges associated with relinquishment of firm interstate transportation on Transwestern separate from the base rate, pursuant to the Transwestern Settlement and Agreement Filing, RP95-271.

L | | | | | | | | |L

31905-G* & 31906-G*

32518-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


9

(continued)


(continued)

Sheet of


INTERSTATE CAPACITY STEP-DOWN ACCOUNT (ICSDA) (CONTINUED)

e. An entry equal to the interest on the average of the balance in the account during the month, calculated in the manner described in Preliminary Statement, Part I, J.

VERNON RATE SAVINGS MEMORANDUM ACCOUNT (VRSMA)

The VRSMA was established pursuant to the SoCalGas-Vernon Stipulation and Settlement Agreement approved in D. 96-09-104. The purpose of this account is to track the core rate savings resulting from the Agreement. The initial balance of the VRSMA will be established at $2.5 million, which is the fixed amount of rate savings afforded to these customers. The VRSMA is a non-interest bearing account and is not recorded on the Utility's financial statements.

a. The core rate savings shall be computed by (1) taking the difference between the applicable GN-10 and GT-10 "V" Tier II tariff rate and the GN-10 and GT-10 Tier II tariff rate applicable for customers not located in Vernon, and (2) multiplying the result by the applicable GN-10 and GT-10 "V" Tier 2 volumes used by customers in Vernon. The core rate savings will be computed on a monthly basis and will be a reduction to the $2.5 million balance in the VRSMA.

b. A corresponding credit adjustment will be made to the CFCA (see Preliminary Statement, Part V, C) for the core rate savings tracked in the VRSMA to ensure that revenue shortfalls are not reallocated to the Utility's core customers. In no event shall the cumulative adjustments made to the CFCA exceed $2.5 million.

VERNON NEGOTIATED CORE CONTRACT MEMORANDUM ACCOUNT (VNCCMA)

The VNCCMA was established pursuant to the SoCalGas-Vernon Stipulation and Settlement Agreement approved in D. 96-09-104. Pursuant to the Agreement, the Utility shall be at risk for any core negotiated contracts with customers in the City of Vernon. Any revenue shortfall resulting from the new Vernon GN-10 or GT-10 rates and the negotiated contract rate will not be applied against the $2.5 million balance in the VRSMA. Utility shall record monthly the net difference between the revenue the Utility receives from the G-10/G-20 customers in Vernon that are served under a negotiated contract and the revenue the Utility would have received at the otherwise applicable tariff rates in Vernon. A corresponding adjustment shall be made to the CFCA (see Preliminary Statement, Part V, C) so that Utility's core customers are not affected by the negotiated core contracts with customers in Vernon.

L | | |LD,LL | | | |L

31906-G* & 31907-G*

32519-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


10

(continued)


(continued)

Sheet of


EARTHQUAKE VALVE INSTALLATION SERVICE MEMORANDUM ACCOUNT (EVISMA)

The EVISMA is a memorandum account recorded on SoCalGas' financial statements. Pursuant to D.96-09-044, EVISMA was established to track all costs and revenues associated with implementing the Earthquake Valve Installation Service Program. The Earthquake Valve Installation Service Program is entirely funded by SoCalGas' shareholders.

The SoCalGas maintains the EVISMA by making monthly entries as follows: a) debits for actual costs associated with program, and b) credits for all revenues collected from customers in the program.

RESEARCH ROYALTY MEMORANDUM ACCOUNT (RRMA)

The RRMA is an interest bearing memorandum account recorded on SoCalGas' financial statements. D.93-12-043 (TY94 GRC) authorized SoCalGas to establish this account to track actual revenues from ratepayer-funded research programs. D.97-07-054 (PBR) added the following revenue sharing program: a) ratepayers get 100% of revenues from projects underway or completed prior to 1/1/98, and b) ratepayers and shareholders equally split the revenues from projects that start after 1/1/98.

SoCalGas maintains this account by making monthly entries as follows: a) debits for funds returned to ratepayers in rates, and b) credit entries for ratepayer's portions of actual research royalties, licensing fees, and other revenues.

For each BCAP filing, SoCalGas will reconcile this account and adjust rates as needed. If there is a balance due to ratepayers, pursuant to Commission order, SoCalGas will decrease rates to return the balance plus interest to ratepayers.

NGV RD&D MEMORANDUM ACCOUNT (RDDNGV)

The RDDNGV is an interest bearing memorandum account recorded on SoCalGas' financial statements. The purpose of this account is to track actual NGV-related research, development and demonstration (RD&D) program costs. D.93-12-043 (TY94 GRC) authorized SoCalGas to track NGV-related RD&D expenses separate from other RD&D costs; and D.95-11-035 (LEV) authorized SoCalGas to use this account for the six-year period December 21, 1995, through December 20, 2001.

SoCalGas maintains this account by making monthly entries as follows: a) a debit for actual NGV-related research, development, and demonstration expenses plus interest; and b) a credit for amortization of costs that are being collected in rates, if any.

DL | | | | | | | | |L

31907-G* & 31908-G*

32520-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


11

(continued)


(continued)

Sheet of


NGV RD&D MEMORANDUM ACCOUNT (RDDNGV) (continued)

For each BCAP filing, SoCalGas will reconcile this account and adjust rates as needed. If there is a balance due from ratepayers, pursuant to Commission order, SoCalGas will increase rates to recover the balance. However, since program spending is limited for the six-year period and over-expenditures may not be recovered from ratepayers, shareholders absorb the balance in the event actual expenses exceed authorized levels.

INTERVENOR AWARD MEMORANDUM ACCOUNT (IAMA)

The IAMA is a memorandum account, the balance of which is recorded on the Utility's financial statements. The purpose of the IAMA is to track intervenor compensation payments authorized by the Commission. The balance in the IAMA will be addressed in the Utility's Biennial Cost Allocation Proceeding (BCAP).

Each month the Utility will debit the IAMA an amount equal to the intervenor compensation payments authorized by the Commission and recorded during the month.

Z FACTOR ACCOUNT (ZFA)

The ZFA is an interest bearing memorandum account recorded on SoCalGas' financial statements. The purpose of this account is to track costs associated with events that are potential "Z Factors." Z Factors are exogenous and unforeseen events largely beyond SoCalGas' control that have a material impact on SoCalGas' costs. D.97-07-054 (PBR), Conclusion of Law 16, authorized SoCalGas to establish the ZFA to allow Z Factor costs to be handled outside the PBR mechanism. Examples of Z Factors include, but are not limited to, accounting rule changes, new government mandates, and tax law changes. For more detail on Z Factors, see Preliminary Statement Part XI, section E.

SoCalGas maintains the ZFA by adding sub-accounts, and making appropriate accounting entries to each sub-account. When a potential Z Factor event occurs, SoCalGas will promptly advise the Commission of its occurrence, and add a new sub-account to the ZFA. Once the sub-account is established, SoCalGas maintains the sub-account(s) by making monthly entries as follows: debits for actual Z Factor costs related to the corresponding event; and credits for the amortization of prior sub-account balances, as authorized by the Commission, if any.

For each BCAP filing, SoCalGas will reconcile this account and adjust rates as needed, taking into consideration the $5,000,000 deductible which is applicable to each qualifying Z Factor event.

L | | | | | | | | | | | | | | | | |L

31908-G* & 31908.1-G

32521-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


12

(continued)


(continued)

Sheet of


TAX INTEREST ACCOUNT (TIA)

The TIA is an interest bearing memorandum account recorded on SoCalGas' financial statements. D.93-12-043 (TY 1994 GRC), Ordering Paragraph 5, authorized SoCalGas to establish the TIA for the sole purpose of tracking costs associated with interest and penalties that may arise as a result of the Supreme Court's Indopco decision.

SoCalGas maintains this account by making monthly entries as follows: debit entries for actual interest and penalties imposed by the IRS or FTB; and credit entries for authorized costs being collected in rates, as authorized by the Commission, if any.

For each BCAP filing, SoCalGas will reconcile this account and adjust rates as needed.

ENERGY EFFICIENCY/DSM MEMORANDUM ACCOUNT (EEDSMMA)

The EEDSMMA is an interest bearing memorandum account established in accordance with Commission Resolution E-3592, dated April 1, 1999. The purpose of the EEDSMMA is to record payments made to the California Energy Commission (CEC) in conducting data studies used for calculating or comparing Energy Efficiency and Demand-Side Management (DSM) cost effectiveness. These studies include the Commercial Building Survey and the Update of the Database for Energy Efficient Resources (DEER). These activities total $2.1 million annually through December 31, 2000. The utilitys portion is $186,000.

The dates and amounts of the electronic transfer of funds to the CEC shall be made in accordance with the table below:

Transfer Date Amount

6/30/99* $93,000

12/31/99 $93,000

6/30/00 $93,000

12/31/00 $93,000

* If Advice No. 2760-C is not approved by June 30, 1999, the first transfer shall occur within 15 days of the approval of Advice No. 2760-C.

L | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |L

31908.1-G & 31909-G*

32522-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


13

(continued)


(continued)

Sheet of


ENERGY EFFICIENCY/DSM MEMORANDUM ACCOUNT (EEDSMMA) (continued)

The utility shall maintain the EEDSMMA by making entries at the end of each month as follows:

a. A debit entry equal to the transfer of funds to the CEC in association with conducting the Commercial Building Survey and the DEER, as specified in the table above.

b. A credit entry shall be made, if any is required, at the end of the expenditure period to reflect any unspent funds that are returned to the utility.

c. An entry equal to interest on the average balance in the account at the beginning of the month and the balance after entries a. and b. above, calculated in the manner described in the Preliminary Statement, Part I, J.

Based on Resolution E-3592, the utility will, at the end of each year, transfer the balance in the EEDSMMA to the Conservation Expense Account (CEA).

APPLICANT INSTALLATION TRENCH INSPECTION MEMORANDUM ACCOUNT (AITIMA)

The purpose of the AITIMA is to record all nonrefundable inspection fees charged by the Utility associated with individual applicant-installed projects under the Applicant Installation Option, Section G, Rule No. 20, Gas Main Extensions, and to record amounts subject to future reimbursement by ratepayers, upon final Commission resolution of the Application for Rehearing of Decision No. 99-06-079.

The AITIMA applies to all applicant-installed projects. First inspection fees will be charged by the Utility and paid by the applicant. Such revenues will be tracked by individual applicant-installed project or project segment within the AITIMA.

The actual first inspection fees charged by the Utility will vary by individual applicant installed project. Such first inspection fees shall be based on the Utility's estimate of the applicant-installed project and actual inspection time required.

The Account will consist of two subaccounts. The first subaccount shall be the Ratepayer Subaccount. The second subaccount shall be the Applicant Subaccount.

L | | | | | | | | | | | | | | | |L

31909-G*

32523-G




OriginalRevisedCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


14

(continued)


Sheet of


APPLICANT INSTALLATION TRENCH INSPECTION MEMORANDUM ACCOUNT (AITIMA) (continued)

The Utility shall maintain the AITIMA by making the following entries at the end of each month:

a. A debit entry will be made to the Ratepayer Subaccount each month for an amount equal to first trench inspection fees paid by applicants during the month.

b. A credit entry will be made to the Applicant Subaccount each month for an amount equal to first trench inspection fees paid by applicants during the month

The initial disposition of the amounts in the AITIMA will be decided at such time as the Commission issues a decision on the Joint Utility Respondent's request for rehearing of Decision No. 99-06-079. Final disposition of amounts recorded in the AITIMA shall be determined in the BCAP or other proceeding expressly authorized by the Commission.

WHEELER RIDGE FIRM ACCESS CHARGE MEMORANDUM ACCOUNT (WRFACMA)

The WRFACMA is an interest-bearing memorandum account recorded on the Utility's financial statements. The purpose of this account is to record the reservation charges for firm access service charged under Schedule G-ITC. The balance in the account will be amortized in accordance with the Utility's cost allocation proceeding.

Utility shall maintain the account by making entries to the account at the end of each month as follows:

a. A credit entry equal to the billed G-ITC firm access reservation charges less franchise fees and uncollectibles (F&U).

b. An entry to amortize the forecasted remaining balance in the account.

c. An entry equal to the interest on the average balance in the account during the month, calculated in the manner described in the Preliminary Statement, Part I, J.

N | | | | | | | | | | | | | |N

31044-G

32524-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

PART VIIDESCRIPTION OF REGULATORY ACCOUNTS - TRACKING


(continued)

Sheet of

A. GENERAL

Tracking accounts reconcile the difference between Commission-authorized forecasted costs and SoCalGas' recorded costs. Balances in the tracking accounts shall be reconciled in revenue requirement in SoCalGas' next BCAP or other appropriate rate proceeding.

B. LISTING OF TRACKING ACCOUNTS

Pitas Point Franchise & Uncollectibles Account (PPF&UA)Other Hazardous Substance Tracking Account (OHSTA)Noncore Fixed Cost Tracking Account (NFCTA)PITCO/POPCO Transition Cost Tracking Account (PPTCTA)Interstate Transition Cost Surcharge Account (ITCSA)Vernon Revenue Tracking Account (VRTA)Zone Rate Credit Limitation Tracking Account (ZRCLTA)Affiliate Transfer Fee Account (ATFA)Catastrophic Event Memorandum Account - Double Refund Tracking Account (CEMA-DRTA)

C. DESCRIPTION OF TRACKING ACCOUNTS

PITAS POINT FRANCHISE & UNCOLLECTIBLES ACCOUNT (PPF&UA)

The PPF&UA is a tracking account recorded on SoCalGas' financial statements. The purpose of the account is to track recorded versus authorized costs associated with franchise fee expenses resulting from the purchase and sale of Pitas Point gas.

Effective January 1, 1992, SoCalGas shall maintain the PPF&UA by making entries at the end of each month as follows:

a. A debit entry equal to the monthly recorded accrual costs associated with franchise fees and uncollectibles expenses resulting from the resale of Pitas Point gas; and

b. A credit entry equal to one-twelfth of the authorized annual Pitas Point franchise fee and uncollectibles expenses.

D

D

T

31045-G & 31046-G

32525-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)


(continued)

Sheet of

C. DESCRIPTION OF TRACKING ACCOUNTS (continued)

OTHER HAZARDOUS SUBSTANCE TRACKING ACCOUNT (OHSTA)

The OHSTA is an interest bearing tracking account which tracks hazardous substance clean-up, third party litigation, and insurance litigation costs relating to sites not included within one of the three defined categories as set forth in D. 94-05-020 (collectively "other hazardous substance costs"). The Company has the option of including the other hazardous substance costs within the new hazardous substance mechanism or the Company may seek full recovery of the other hazardous substance costs through the general rate case, by application, or by any other procedure approved by the Commission.

Effective June 3, 1994, the following entries will be recorded to the OHSTA at the end of each month:

a. A debit entry equal to the other hazardous substance costs incurred associated with other hazardous substance sites. The costs for each site will be recorded separately.

b. A credit entry equal to the hazardous substance costs transferred to the hazardous substance cost recovery account (HSCRA) when the Company elects to use the new hazardous substance mechanism upon approval of an advice letter by the Commission.

c. A credit entry equal to the amount approved by the Commission for recovery from ratepayers when the Company elects to seek full recovery through a process other than the new hazardous substance mechanism.

d. An entry equal to the interest on the average of the account balance during the month calculated in the manner described in Preliminary Statement, Part I, J.

NONCORE FIXED COST TRACKING ACCOUNT (NFCTA)

The NFCTA is a tracking account recorded on SoCalGas' financial statements. The purpose of this account is to track the difference between authorized costs in rates, and the noncore portion of actual carrying costs of gas in storage, take-or-pay costs, and minimum purchase obligation costs. D.94-07-064 (Global Settlement) authorized SoCalGas to use this account.

SoCalGas maintains this account by making monthly entries as follows: a) debits for the noncore portion of actual carrying costs of gas in storage, take-or-pay costs, and minimum purchase obligation costs; and b) a credit for authorized costs being collected in rates. SoCalGas also makes entries to amortize previous balances, if any.

D

L | | | | | | | | | |LL,D

L | |L

T

31046-G & 31047-G

32526-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of


NONCORE FIXED COST TRACKING ACCOUNT (NFCTA) (continued)

For each BCAP filing, SoCalGas will reconcile this account and adjust rates as needed. If there is a balance due from ratepayers, pursuant to Commission order, SoCalGas will increase noncore rates to recover the balance; however, if there is a balance due to ratepayers, SoCalGas will decrease noncore rates to return the balance.

PITCO/POPCO TRANSITION COST TRACKING ACCOUNT (PPTCTA)

The PPTCTA is an interest bearing tracking account, effective January 1, 1994 through December 31, 1998, pursuant to D. 94-07-064, which tracks the ratepayer's portion of the buyout and/or buydown costs of the commercial settlements related to PITCO and POPCO excess gas costs. Pursuant to D. 94-08-010, the interest rate charged on debt for the PPTCTA will be effectuated through a combination of short and intermediate term financing instruments which will cause the underlying interest cost to be variable during the period of outstanding debt.

Effective January 1, 1994 through December 31, 1998, the following entries will be recorded in the PPTCTA at the end of each month:

a. A credit entry equal to one twelfth (1/12) of the annual revenue requirement for amortization of these costs included in the effective rates.

b. A debit entry equal to the ratepayers' share of any PITCO or POPCO transition or excess gas cost incurred during the month.

c. A debit entry equal to the actual interest on the average of the balance in the account during the month as determined by the financing methodology approved in D. 94-08-010. The corresponding interest rate for each month will be submitted to the Commission for informational purposes by no later than the fifth day of the following month.

INTERSTATE TRANSITION COST SURCHARGE ACCOUNT (ITCSA)

The ITCSA is a tracking account. The purpose of the ITCSA is to track the difference between SoCalGas' obligations for interstate pipeline capacity and revenues received by SoCalGas, including credits for payments made directly to the interstate pipelines by SoCalGas' customers for interstate capacity pursuant to the Utility's cost allocation proceeding. The core market's allocable portion of such balance shall be limited as set forth in Core Fixed Cost Account (CFCA) described herein.

L

L | | | | | | | | | | | | | | | | |LT,LL

31047-G & 31048-G

32527-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of


INTERSTATE TRANSITION COST SURCHARGE ACCOUNT (ITCSA) (continued)

The ITCSA consists of three subaccounts. The subaccounts are:

a. the Core Subscription Interstate Capacity Cost Subaccount which tracks the difference between SoCalGas' obligation for interstate pipeline capacity reserved to provide SoCalGas' core subscription service along with reservation charges paid by core subscription customers and any revenues paid to SoCalGas as a result of brokering of such capacity;

b. the Remaining Interstate Capacity Cost Subaccount which tracks the difference between SoCalGas' obligation for pipeline demand charges for SoCalGas' interstate capacity net of the cost of the demand charges for SoCalGas' capacity reserved to provide core and core subscription service and any related revenues paid to SoCalGas as a result of brokering such capacity.

c. the Relinquished Capacity Cost Subaccount which tracks the interstate pipeline capacity costs and revenues that have and will be received under the revenue crediting mechanism in the El Paso Settlement that were reallocated solely to noncore customers pursuant to D.99-11-021.

SoCalGas maintains each subaccount of the ITCSA by making entries at the end of each month as follows:

a. A debit entry equal to the recorded cost, including any other SoCalGas obligations, for interstate pipeline demand charges;

b. A credit entry equal to any revenue paid directly to SoCalGas, including any credits against SoCalGas' obligations, for interstate pipeline demand charges resulting from brokering interstate pipeline capacity;

c. A credit entry for the noncore's portion of revenues that SoCalGas receives under the crediting mechanism in the El Paso Settlement pursuant to D.99-11-021 (applicable to the Relinquished Capacity Cost Subaccount only);

d. A credit entry equal to the reservation charge revenues collected for the core subscription service (applicable to that subaccount only);

e. A credit entry equal to the forecasted Interstate Transition Cost Surcharge (ITCS) cost applicable to the remaining interstate capacity cost subaccount; and,

f. An entry equal to the interest on the average balance in the account during the month calculated in the manner described in Preliminary Statement, Part I, J.

L

T

N |N

LL

T,LL

T,LLL

N |N

T,LL

T,LL

T,LL

T

31048-G,31049-G,31050-G

32528-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


(continued)

Sheet of


INTERSTATE TRANSITION COST SURCHARGE ACCOUNT (ITCSA) (continued)

Note: Revenues paid directly to SoCalGas for brokered interstate pipeline capacity and credits for payments made to the interstate pipeline by SoCalGas' customers will be allocated to the CFCA and the subaccounts described above based upon the costs associated with interstate pipeline capacity available for brokering during the month for each classification and the cost of total brokered capacity for the month.

VERNON REVENUE TRACKING ACCOUNT (VRTA)

The VRTA is a tracking account. The purpose of the VRTA is to track the difference between wholesale revenues recorded for the City of Vernon and those revenues which would have otherwise been generated at SoCalGas tariff rates from customers situated within the City of Vernon.

SoCalGas maintains the VRTA by making entries to the account at the end of each month, as follows:

a. a debit entry equal to the current weighted average SoCalGas retail rate for those customers who have elected to receive service from the City of Vernon, times the volumes of gas delivered under wholesale service to the City of Vernon.

b. a credit entry equal to wholesale revenues received from the City of Vernon.

c. an entry equal to interest on the average of the balance in the account during the month, calculated in the manner described in Preliminary Statement, Part I, J.

ZONE RATE CREDIT LIMITATION TRACKING ACCOUNT (ZRCLTA)

The ZRCLTA was established pursuant to D.95-04-078 and D.97-04-082. The purpose of the ZRCLTA is to record the difference between the adopted BCAP zone rate credit revenue requirement and the zone rate credits provided to eligible shippers utilizing Wheeler Ridge interconnect facilities as described in Schedule No. G-ITC.

On June 1, 1997, the balance in the ZRCLTA will be adjusted to reflect the recorded zone rate credit revenues collected in rates pursuant to D.94-12-052 for the period January 1, 1995 through May 31, 1997, less the zone rate credits actually provided to eligible G-ITC shippers during that same period, less that amount already amortized in rates pursuant to D.97-04-082.

L | | | | | | | | | | | | | |LDL | | | | | | | | |L

T

31050-G & 31051-G

32529-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)


Sheet of


ZONE RATE CREDIT LIMITATION TRACKING ACCOUNT (ZRCLTA) (continued)

Beginning June 1, 1997, SoCalGas maintains this account by making monthly entries as follows: a) a credit equal to recorded zone rate credit revenues collected in rates pursuant to D.97-04-082, or other modifying Commission order; b) a debit equal to the actual zone rate credit provided to customers pursuant to Schedule No. G-ITC; and c) a debit equal to the portion of the balance amortized in rates.

AFFILIATE TRANSFER FEE ACCOUNT (ATFA)

The AFTA is a tracking account recorded on SoCalGas' financial statements. The purpose of the ATFA is to record fees received by SoCalGas from covered affiliates when an employee of SoCalGas is transferred, assigned, or otherwise employed by that affiliate. A covered affiliate is one that is engaged in the provision of a product that uses gas or electricity, or the provision of services that relate to the use of gas or electricity, and is not otherwise exempted. This account is authorized by Ordering Paragraph 1 of D.97-12-088, which adopted Appendix A, Rule V.G.2.c.

SoCalGas maintains this account by making monthly entries as follows: a credit entry equal to fees received by SoCalGas from a covered affiliate when an employee of SoCalGas is transferred, assigned, or otherwise employed by the covered affiliate. As described in Rule V.G.2.c., fees do not apply to all employee transfers, e.g., clerical workers, and the transfer of employees during the initial implementation period.

For each BCAP filing, SoCalGas will reconcile this account and adjust rates as needed.

CATASTROPHIC EVENT MEMORANDUM ACCOUNT - DOUBLE REFUND TRACKING ACCOUNT (CEMA-DRTA)

The purpose of this account is to track the recovery of the 1998 revenue requirement shortfall due to the base margin adopted in D.97-07-054 and the handling of the insurance proceeds related to the Northridge earthquake in D.97-06-064. Entries into this tracking account will be reflected in the Utility's financial statements. Effective December 31, 1998, the following entries will be recorded in the CEMA-DRTA:

1. A one-time debit entry of $1,231,094 will be recorded in December 1998 to reflect a receivable due from ratepayers related to the shortfall that was incurred throughout the 1998 year.

2. In 1999, a monthly credit entry equal to one-twelfth of $1,231,094 will be recorded for revenues collected in rates to amortize the initial balance established in December 1998.

This account shall remain in effect until the shortfall is fully recovered.

L | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |L

T

26312-G

32530-G




RevisedOriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

PART XGLOBAL SETTLEMENT


(continued)

Sheet of

A. GENERAL

Pursuant to D.94-07-064, the Global Settlement establishes ratemaking mechanisms addressing the following matters:

1. The treatment of excess gas and transition costs associated with Pacific Interstate Transmission Company (PITCO), and Pacific Offshore Pipeline Company (POPCO). (See Section B.)

2. Cost Allocation. (See Section C.)

The term of the Global Settlement (Global Settlement Period) shall be either from January 1, 1994 through December 31, 1998 for PITCO/POPCO provisions, or from August 1, 1994 through July 31, 1999 for provisions dealing with cost allocation including discounting and throughput.

B. PITCO/POPCO Excess Gas and Transition Costs

1. Definitions

a. PITCO excess gas costs are those costs associated with long-term gas supply contracts entered into by the Utility with Pacific Interstate Transmission Company (PITCO) which exceed the Utility's adopted weighted average cost of gas (WACOG) (excluding the cost of PITCO/POPCO supplies, Federal offshore supplies, Enron Bank, ARCO, and Meridian long-term contracts, and other California supplies).

b. POPCO excess gas costs are those costs associated with long-term gas supply contracts entered into by the Utility with Pacific Offshore Pipeline Company (POPCO) which exceeds the Utility's WACOG (excluding the cost of PITCO/POPCO supplies, Federal offshore supplies, Enron Bank, ARCO, and Meridian long-term contracts) plus the average cost of the Utility's El Paso and Transwestern interstate pipeline capacity reserved for core customers.

c. PITCO/POPCO transition costs are buyout/buydown payments that PITCO or POPCO makes to third party gas suppliers and pipeline companies (including reasonable financing costs) and accelerated amortization of PITCO/POPCO assets.

D

T

26313-G

32531-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)


(continued)

Sheet of

B. PITCO/POPCO Excess Gas and Transition Costs (continued)

2. All PITCO/POPCO excess gas and transition costs will be recorded to the PITCO/POPCO Transition Cost Tracking Account (PPTCA) and will be included as an annual revenue component over a five-year period, beginning January 1, 1994, to recover these costs according to the allocation percentages contained in Section B.3. Such allocation of costs among customer classes will be on an equal cents-per-therm basis.

a. In recognition of the fact that the effective date of the Global Settlement occurred after January 1, 1994, an amount equal to prorated annual amount of adopted PITCO/POPCO excess gas costs (excluding F&U but including interest) contained in current rates between January 1, 1994 and the effective date of the Global Settlement will be credited to the PPTCA.

b. Authorized and recorded (if any) PITCO/POPCO costs (including interest) recorded during this period will be removed from the PITCO/POPCO Excess Cost Account (PPECA). Any recorded excess PITCO/POPCO costs removed from the PPECA will be debited (with interest) to the PPTCA as of the date of the Global Settlement.

3. PITCO/POPCO excess gas and transition costs shall be allocated to shareholders at the following

percentages, dependent upon the total amount of these costs, with the remainder allocated to ratepayers as set forth in Section B.2.:

Total PITCO/POPCO Excess Percentage Allocated Gas and Transition Costs To Shareholders

$0 - $150,000,000 0%$150,000,001 - $250,000,000 22%$250,000,001 - $650,000,000 27.5%$650,000,001 - $900,000,000 50%

Over $900,000,000 100%

4. The amount of PITCO/POPCO excess gas and transition costs allocated to ratepayers shall not exceed $112 million (including interest) in any one year. If the amount to be recovered in rates exceeds $112 million per year, or $560 million over five years, the unamortized balance shall be recovered as soon as possible in the years subsequent to 1998, subject to the $112 million cap.

5. The Utility shall receive interest on the unamortized portion of costs allocated to ratepayers at a rate approved by the Commission. The Utility shall apply the same interest rate on customer payments that exceed excess gas and transition costs which the Utility has paid.

T

26314-G

32532-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of

B. PITCO/POPCO Excess Gas and Transition Costs (continued)

6. The Utility will request Commission approval of the value of any facilities owned by PITCO/POPCO which are transferred to an independent third party in consideration for settlement of a buyout, buydown, or accelerated depreciation of PITCO/POPCO assets.

7. Shareholders will be able to recover, without reasonableness review, subject to the sharing mechanism percentage for excess costs, amounts paid for PITCO or POPCO gas purchased up through December 31, 1998.

8. Shareholders will be solely at risk for any excess costs above market prices for any gas purchased from PITCO or POPCO after December 31, 1998.

9. Any individual customer may negotiate with the Utility to accelerate their share of PITCO/POPCO excess gas and transition costs in order to have these costs eliminated from their rates on an accelerated basis as follows:

a. The Utility shall negotiate a prepayment equal to the product of the known or expected reduction in rates times a reasonable estimate of the volume likely to be used by the customer during the period, discounted by the interest rate authorized by the Commission for PITCO/POPCO costs.

b. Alternatively, the customer may prepay any amount, based on its own estimate of what its total obligation will be. The Utility shall treat such prepayment as a credit to the customer's account, and shall draw upon this credit for that portion specified by the customer for their bill. The credit shall accrue interest at the rate set forth in Section 6.5 of this Preliminary Statement. When the credit is fully used, the customer's rate will return to the level it would have been in the absence of the prepayment.

c. Cogenerators will be provided with information regarding any UEG's election of a prepayment option and will be offered the same terms adjusted based on the negotiation of the cogeneration customer's throughput. Cogenerators will not be allowed to receive the benefit of a reduced rate without prepayment of these costs.

C. Cost Allocation

1. The Utility will calculate rates for the five year Global Settlement Period, effective August 1, 1994 through July 31, 1999, for cost allocation, based on 1991 actual throughput subject to the following adjustments:

a. To reflect normal temperature conditions for the core market.

T

26315-G & 26316-G

32533-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


Sheet of

C. Cost Allocation (continued)

1. (continued)

b. The transfer of UEG loads from Long Beach wholesale service to retail service.

c. The addition of Southwest Gas as a wholesale customer.

d. Core to noncore transfers.

2. The Utility will calculate the variance between forecasted and actual noncore and wholesale revenues and record such variance to the Noncore Cost/Revenue Memorandum Account (NCRMA). Such calculation will exclude Enhanced Oil Recovery (EOR) and unbundled storage revenues.

a. The Utility shall retain 100% of the annual variance applicable only for cases where actual revenues exceed forecasted revenues, up to the amount of the annual noncore revenue variance cap, which is as follows for the Global Settlement Period:

Year 1: $11,000,000Year 2: $13,000,000Year 3: $15,000,000Year 4: $17,000,000Year 5: $19,000,000

b. If at the end of any year, the variance, as measured per Section C.2.a. exceeds the annual variance cap for that year, the Utility shall credit 87.5% of the excess to the cost of service in the following year.

3. The Utility shall be solely at risk for any under-recovery of the forecasted noncore revenue requirement for each year of the Global Settlement Period. No reduction in the forecast shall be made for bypass or discount shortfalls to avoid bypass, excluding the EOR market.

4. During and subsequent to the Global Settlement Period, the Utility shall be at risk for any noncore discount shortfalls. If the Commission substantially changes the method of setting rates for noncore customers, the Utility may request a waiver of this provision.

5. The EOR and Noncore Storage Balancing accounts will remain in effect during the Global Settlement Period.

6. No exit fees of any kind will be charged to customers who leave the Utility system during the Global Settlement Period.

D

T

30173-G

32534-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

PART XIPERFORMANCE BASED REGULATION


(continued)

Sheet of

A. OVERVIEW

The PBR Indexing Mechanism adjusts allowed margin per customer annually by a formula that includes general gas utility industry cost changes, less a productivity offset. The revenue requirement will be adjusted pursuant to the calculations related to base margin and exclusions as described herein. The main features of SoCalGas' adopted PBR are: (1) the Indexing Formula (inflation less productivity); (2) the quantity indexed; (3) exclusions and adjustments; (4) offramps and termination provisions; (5) service quality, customer satisfaction and safety incentives; and (6) monitoring and evaluation provisions.

B. EFFECTIVE DATE / DURATION

Pursuant to Ordering Paragraph 2 of SoCalGas' PBR Decision No. (D.) 97-07-054, SoCalGas filed Advice No. 2609 on July 23, 1997 and elected that the PBR mechanism become effective on January 1, 1998. The PBR mechanism will continue for a term of five years through December 31, 2002. The mechanism will remain in effect during the initial five year term unless the "Offramp" provisions for rate of return are triggered as described in Section G. The PBR mechanism was subject to a mid-course review in SoCalGas' 1999 BCAP application that was filed in October of 1998.

C. DETERMINATION OF INITIAL BASE MARGIN

The Starting Base Margin for PBR implementation is the amount authorized by the Commission to be used in the calculation of Base Rates that are subject to the PBR Indexing Mechanism as reflected in D.97-07-054 adjusted downward by $8,000 to reflect the 1997 adopted cost of capital. Starting Base Margin includes all SoCalGas expenses except Excluded Items described in Section F. The adopted base margin, stated in 1996 dollars, equals $1,315,333,000.

D. INDEXING MECHANISM

1. Indexing Formula

The adopted PBR indexing method is based on indexing base margin per customer to derive the margin per customer appropriate for the subject year. The appropriate margin per customer is multiplied by the forecasted number of customers for the year in which the margin per customer will apply. The resulting figure is adjusted by a Z Factor adjustment, if any is appropriate, based on the criteria described in Section E. The mechanism can be written as:

Total Base Margin s = Base Margin per Customer s * Forecasted Number of Customers s + any Z Factor adjustments

Where: s = subject year, i.e., year in which the margin per customer will apply.

TT

T

30174-G

32535-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)


(continued)

Sheet of

D. INDEXING MECHANISM (continued)

1. Indexing Formula (continued)

The initial base margin per customer (based on 1996 data) equals:

$1,315,333,000 / 4,763,134 = $276.15

Where 4,763,134 equals average annual number of active meters in 1996.

For subject years 1998 to 2002:

Base Margin Per Customer s = Base Margin Per Customer s-1 (1 + Inflation s - Productivity s)

Where: Inflation equals the Escalation Factor defined in D.2, andProductivity is defined in D.3.

2. Escalation Factor (Gas Utility Price Index)

The Escalation Factor is the inflation rate which shall be used in the PBR Indexing Formula. The Escalation Factor is the annual change in the Gas Utility Input Price Index (GUPI), an index of gas utility input prices. The GUPI is a weighted average of the annual change in prices of gas distribution utility inputs.

The GUPI is composed of three broad price escalation components: 1) labor operations and maintenance (O&M), 2) nonlabor O&M, and 3) capital-related expenses. The three index components are combined using weights based on five-year average expenditures (averaging the years 1991-1995) in each input category of SoCalGas, Pacific Gas & Electric and San Diego Gas & Electric. The weights are as follows: labor O&M (22.12%), nonlabor O&M (29.42%), and capital-related costs (48.46%). These weights are multiplied by the respective price escalators to calculate the overall GUPI index.

a. Labor O&M Escalator - An index based on the average hourly earnings of workers in gas production and distribution (SIC 492) reported by the U.S. Department of Labor, Bureau of Labor Statistics. This aggregate measure of the change in the price of direct labor (excluding fringe benefits) for the gas utility industry is identified as the variable named AHE492NS by DRI/McGraw-Hill.

b. Nonlabor O&M Escalator (including employee benefits) - An index of nonlabor O&M expenses for gas distribution utilities published by the Utility Cost Forecasting Service of DRI/McGraw-Hill. This aggregate measure of the price escalation of O&M inputs other than direct labor is identified as JGTOTALMS by the DRI/McGraw-Hill Forecasting Service.

T

30175-G

32536-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of


2. Escalation Factor (Gas Utility Price Index) (continued

c. Capital-related Cost Escalator - An index of the capital service price for gas distribution utilities on the west coast. The DRI/McGraw-Hill index of the rental price of capital for public utility structures (ICNRCOSTPU) is linked to the gas distribution industry by replacing the chain-type price index of all public utility structures (PCWICNRPU) with the price index of gas distribution capital goods as measured by the Handy-Whitman Index for Gas - Total Plant - Pacific Coast Region (JUG@PCF). The capital-related cost escalator equals ICNRCOSTPU divided by PCWICNRPU and multiplied by JUG@PCF.

The DRI/McGraw-Hill forecast of wage increases for employees in electric, gas, water, and sanitary services, AHE49NS, is used to forecast gas distribution utility wages since DRI/McGraw-Hill does not forecast gas utility wages for SIC 492. The true-up, as shown in the formula below, will be based on the recorded changes in average gas utility wages, AHE492NS. The other two price indexes, capital-related and nonlabor O&M prices, are available from DRI/McGraw-Hill on both a forecast and a recorded basis. This methodology allows for the use of revised forecasts and recorded price index values in subsequent subject years, as described in the formula below.

The formula for the Escalation Factor will be as follows:

Escalation Factor = [(Fs / Fc) * (Fc / Fc) * (Rc-1 / Fc-1) * (RRc-2 / Rc-2)] - 1

Where:

Fs = the forecasted GUPI price index for period s, the subject time periodFc = the forecasted GUPI price index value for period c, the current period,

made in period cFc = the forecasted GUPI price index value for period c made in period c-1Fc-1 = the forecasted GUPI price index value for period c-1, made in period c-1Rc-1 = the recorded GUPI price index value for period c-1Rc-2 = the recorded GUPI price index value for period c-2RRc-2 = the revised recorded GUPI price index value for period c-2

d. The Escalation Factor will start with the 1997 price index value (equal to 100) as a base - The forecast of the Escalation Factor used in the PBR Indexing Mechanism will be submitted annually in an advice letter to the Commission on October 1, based on the latest available forecast and historical data available from the DRI/McGraw-Hill Utility Cost Forecasting Service.

T

30176-G

32537-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of


3. Productivity Offset (X Factor)

An annual productivity offset shall be used in the PBR Indexing Mechanism. The amount will increase incrementally over the initial five-year PBR timetable resulting in an X Factor of 1.1 percentage point (0.011) in Year 1998, 1.2 percentage point (0.012) in Year 1999, 1.3 percentage point (0.013) in Year 2000, 1.4 percentage point (0.014) in Year 2001, and 1.5 percentage point (0.015) in Year 2002. An additional 1% adjustment to account for the decline in rate base will be added each year bringing the final productivity X Factor to be 2.1 percent in year 1998; 2.2 percent in year 1999; 2.3 percent in year 2000; 2.4 percent in year 2001; and 2.5 percent in year 2002.

4. Customer Forecast

The number of customers is measured by the number of active meters. The forecasted number of customers is determined as follows:

Forecasted Customers s = Recorded Number of Active Meters in June c (1 + growth rate c)

Where c = current year, i.e., year before subject year, and where growth rate c equals percentage growth in active meters between June of current year and June of the prior year. The number of active customers will be taken from report E08P25-1 or its future equivalent.

There will be a true-up of base margin using the average recorded number of customers for the year in which the rates were in effect. The true-up adjustment will be included in the following years Shareable Earnings filing as part of the Earnings Sharing Mechanism. For example:

Let 1998 forecast of customers = 5,000,000Let 1998 average annual recorded customers = 4,990,000Let 1998 base margin per customer = $277.59

The adjustment included in the Earnings Sharing Mechanism equals:(5,000,000 - 4,990,000) * $277.59 = $2,775,900

In determining customer growth there will be a status quo on any reconfiguration of meter installations, e.g., where one meter is converted to three individual meters, the meter count will remain at one and correspondingly where three individual meters are combined into one meter, the meter count will remain at three.

In addition, any conversion of mobilehome master meter units into individually metered units as a result of the utility taking over mobilehome park facilities as required by AB 622, will result in a base margin per customer allowance based on the authorized effective avoided cost for submetered credit and not based on the average base margin per customer.

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30177-G

32538-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


(continued)

Sheet of

E. Z FACTOR

1. Definition

Z Factors are exogenous events, unforeseen at the implementation of PBR, largely uncontrollable by management, having a material and disproportionate impact on SoCalGas as described below. Potential Z Factors shall include, but are not limited to the items set forth below:

a. Accounting rule changes promulgated by the Financial Accounting Standards Board (FASB), the Securities and Exchange Commission (SEC) or the California Public Utilities Commission (CPUC);

b. Tax law changes by the federal government, the State Franchise Tax Board, Board of Equalization, or any local jurisdiction having taxing authority;

c. Costs resulting from other mandated state, federal, or local governmental programs or from regional environmental programs;

d. In the event that the Catastrophic Event Memorandum Account (CEMA) is subsequently eliminated, material cost impacts resulting from natural disasters; and

e. Other events meeting the criteria set forth herein.

SoCalGas must promptly notify the Commission of all potential Z Factors in compliance with D.97-07-054. Notice to the Commission shall be by a letter addressed to the Executive Director. Copies of the letter shall be sent to the following at the Commission: the Director of the Energy Division, the Investigations, Monitoring and Compliance Branch Chief, Energy Division, and the Director of the ORA. The letter shall clearly identify the proposed Z Factor to be recorded in the Z Factor Memorandum Account, shall include a detailed description of the event and a forecast of the annual cost impact of such Z Factor. SoCalGas shall then be authorized to record, on a monthly basis, the associated cost in the Z Factor Memorandum Account.

2. Operation of the Z Factor Memorandum Account

SoCalGas shall maintain a separate Z Factor Memorandum Sub-Account for each identified Z Factor. Recorded costs are charged to each sub-account at the end of each month. Revenues authorized by the Commission to amortize the balance are credited to each sub-account at the end of each month. Interest shall accrue on a monthly basis by applying the interest rate, as set forth in Section J of Preliminary Statement Part I, to the average of the beginning and ending balance (either positive or negative) less a $5,000,000 deductible amount which is applicable to each qualifying Z Factor event.

T

30178-G

32539-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)


(continued)

Sheet of

E. Z FACTOR (continued)

3. Measure of Adjustment

a. Z Factor Calculation

The impact of the Z Factor event is net of its impact on the Gas Utility Input Price Index (GUPI) and less the $5,000,000 deductible. DRI/McGraw-Hill publishes detailed price indexes by FERC Account for each non-labor O&M and capital related item. The impact of the Z Factor event above the change incorporated in the GUPI and the $5,000,000 deductible will be the Z Factor used in the Base Rate Indexing Mechanism. The precise calculation is shown in the following formula:

Zs = [ZCs - (ZCc * Ps / Pc) - $5,000,000)]

Where:

Zs = A particular Z Factor for subject year sZCs = Z Factor cost level in subject year sZCc = Z Factor cost level in current year cPs = DRI price index forecast for subject year for FERC Account containing Z Factor

cost amount, ZCs Pc = DRI price index forecast for current year for FERC Account containing Z Factor

cost amount, ZCc

b. Capital Related Z Factor Costs

The formula is identical for capital costs except that the result is multiplied by the Capital Service Price, where the Capital Service Price is defined as the margin requirement for capital related costs determined under traditional cost of service methodology divided by the associated capital costs. Such costs are: return on weighted average rate base (using the current CPUC authorized rate of return), taxes on that return, depreciation expense at the CPUC adopted system average rate, plus authorized franchise fees and uncollectible expense. The precise calculation is shown in the following formula:

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30179-G

32540-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)


(continued)

Sheet of


3. Measure of Adjustment (continued)

b. Capital Related Z Factor Costs (continued)

Zs = {[ZCs - (ZCc * Ps / Pc)] * SPs - $5,000,000)}

Where:

Zs = A particular Z Factor for subject year sZCs = Z Factor cost level in subject year sZCc = Z Factor cost level in current year cPs = DRI price index forecast for subject year for FERC Account containing Z Factor

cost amount, ZCs Pc = DRI price index forecast for current year for FERC Account containing Z Factor

cost amount, ZCc SPs = Capital Service Price in subject year s

c. Subsequent Year Adjustment

In subsequent years the Z Factor will be modified as described in E.4 below.

4. Operation of the $5,000,000 Deductible Feature

To limit recoverable Z Factors to material events, the deductible feature of $5,000,000 was authorized by the Commission in D.97-07-054 to operate as follows:

a. The deductible is a one-time feature applicable to the first $5,000,000 in costs for each Z Factor event. For example, if a qualified Z Factor increased costs by $20,000,000 in each year 1, 2 and 3 above the base level, the deductible will apply in year 1. Thus, the compensable amounts will be $15,000,000, $20,000,000 and $20,000,000 in years 1, 2 and 3, respectively.

b. The deductible is cumulative for each Z Factor event and completes its application in the first year that the cumulative Z Factor costs exceed the deductible amount. For example, if a qualified Z Factor increased costs by $4,000,000, $4,000,000 and $4,000,000 in years 1, 2 and 3 above the base level, the deductible will be fully applied during year 2. Thus, the compensable amounts will be $0, $3,000,000 ($4,000,000 plus $4,000,000 minus $5,000,000) and $4,000,000 in years 1, 2 and 3, respectively. As demonstrated above, once a Z Factor is created and the full deductible is applied, the Z Factor remains compensable in subsequent years even if the amount is less than the one-time deductible.

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30180-G

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291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)


(continued)

Sheet of


4. Operation of the $5,000,000 Deductible Feature (continued)

c. The deductible is applicable to each separate Z Factor event. Thus, in the event of multiple Z Factors, the following table depicts the Z Factor amounts, application of the deductible, and the compensable amounts:

Year ($ Millions) 1 2 3 Z Factor (a) $8 $3 $3 Z Factor (b) 6 6 4 Sub-Total 14 9 7 Deductible (a) (5) - - Deductible (b) (5) - - Compensable Amount $4 $9 $7

As demonstrated above, the deductible is a one-time amount applicable to each individual Z Factor. Again, once the deductible level is exceeded in any year for an individual Z Factor, that Z Factor is fully compensable in subsequent years.

F. EXCLUSIONS TO INDEXING MECHANISM

In compliance with D.97-07-054, the following items are specifically excluded from PBR in order to retain those items as separate regulatory mechanisms or preserve the Commission's discretion to prescribe specific ratemaking treatment at an appropriate time in the future:

1. Catastrophic Event Memorandum Account (CEMA) pursuant to Resolution No. E-3238, dated July 24, 1991.

2. Hazardous Substance Cost Recovery Account (HSCRA) pursuant to D.94-05-020, dated May 4, 1994.

3. Low Emission Vehicle (LEV) Program pursuant to D.95-11-035, dated November 21, 1995.

4. Regulatory Transition Costs authorized for exclusion pursuant to SoCalGas' PBR D.97-07-054, dated July 16, 1997. These transition costs consist of Take-or-Pay (TOP) costs, Minimum Purchase Obligation (MPO) Transition costs, PITCO/POPCO Transition costs, and the Interstate Transition Cost Surcharges (ITCS). These items are consistent with the Commission's definition of transition costs as described in D.87-12-039 (p. 15) and D.86-12-009 (p. 23).

5. Wheeler Ridge Interconnection Costs and Revenues pursuant to D.95-04-078, dated April 1995 through May 31, 2000. Beginning June 1, 2000 pursuant to D.00-04-060, the Wheeler Ridge interconnection costs and revenues are no longer excludable from PBR.

NN

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30181-G

32542-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


9

(continued)


(continued)

Sheet of

F. EXCLUSIONS TO INDEXING MECHANISM (continued)

6. Mandated Social Programs such as California Alternate Rates for Energy (CARE) and the low-income Direct Assistance Program (DAP).

7. Gas Costs (including Company use gas and unaccounted for gas) and Pipeline Demand Charges.

8. Costs imposed by the Commission, such as, Intervenor Compensation Fees and costs related to Commission staff supervised management or financial audits.

9. DSM and "Public Goods" RD&D costs pursuant to SoCalGas' PBR D.97-07-054.

10. DSM shareholder incentives.

G. FINANCIAL PRACTICES AND METHODS

1. Earnings Sharing Mechanism

The earnings sharing mechanism is done on a progressive basis. It shares earnings only within "bands" above a benchmark rate of return (ROR) on rate base. The benchmark ROR will be the last authorized ROR. SoCalGas' authorized ROR is 9.49% (per D.96-11-060). Shareholders will retain 100% of the earnings up to 25 basis points (0.25%) above the benchmark ROR and also any earnings above 300 basis points (3%). Between 25 basis points and 300 basis points above the benchmark there are 8 bands where there will be sharing of earnings between shareholders and ratepayers. Beyond the inner band, from 25 to 300 basis points, the shareholder share of earnings rises stepwise from 25% through 100%, while the ratepayer share correspondingly declines from 75% to 0%. If SoCalGas is able to increase revenues due to expansion of current service offerings unrelated to the provision of natural gas or through offering new products and services, they will be included along with associated costs into the total rate of return calculation.

2. Achieved Base Margin ROR

The equation for determination of the Achieved Base Margin ROR is:

Achieved Base Margin Return / Actual Weighted Average Base Margin Rate Base.

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DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


10

(continued)


(continued)

Sheet of

G. FINANCIAL PRACTICES AND METHODS (continued)

3. Achieved Base Margin Return

Achieved Base Margin Return is defined as: Actual total utility operating revenues minus total utility operating expenses adjusted for items excluded from the final PBR earnings sharing mechanism. Actual Base Margin Return would reflect total results of operations, however the following items are to be excluded and not considered in the Base Margin Return amount subject to the Earnings Sharing Mechanism:

a. Incremental storage or other revenues/costs subject to incremental pricing rules established by the CPUC,

b. Incentive mechanism activity such as DSM, GCIM, RD&D Royalties subject to 50/50 sharing, and Hazardous Waste shareholder costs/awards, or any rewards/penalties adopted as part of this PBR mechanism,

c. Contingent liability adjustments (reserves) required for financial reporting purposes under Generally Accepted Accounting Principles (GAAP), but not authorized by the CPUC for ratemaking purposes, and

d. Such adjustments to CFCA related to Core Pricing Flexibility as may be approved by the Commission, the 25% shareholder portion of the NFCA and the 50% shareholder portion of the NSBA as approved in D.00-04-060.

4. Actual Weighted Average Base Margin Rate Base

Actual Weighted Average Base Margin Rate Base is defined as: actual weighted average rate base adjusted for costs related to the Aliso Canyon Expansion Storage Project subject to incremental pricing under CPUC decisions and therefore excluded from base margin rate base.

To the extent this equation generates an Achieved Base Margin ROR for calendar years beginning after December 31, 1997, that is in excess of the CPUC authorized base margin ROR, such excess will be shared based on the Earnings Sharing Mechanism described above.

NN

TTD

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32544-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


11

(continued)


(continued)

Sheet of


4. Actual Weighted Average Base Margin Rate Base (continued)

To achieve the specific shareholder/ratepayer sharing set forth in the table below on a basis net of tax and F&U, tax and F&U benefits are shared such that the ratio of net benefits to shareholders and ratepayers equals (1-r) / r, where 1-r and r equal the adopted average shareholder and ratepayer sharing percentages. In order to achieve this net benefit ratio the ratepayer credit is "grossed-up" by the factor 1/ (1-r * t).

Where: r = the average ratepayer sharing percentage, andt = the combined F&U and income tax factor which equals 0.4190

The following table summarizes the shareholder/ratepayer sharing percentages within the various bands:

AverageBands Basis Points Shareholder % Ratepayer % Ratepayer % Inner 00-25 100% 00% 00.0% 1 25-50 25% 75% 37.5% 2 50-75 35% 65% 46.7% 3 75-100 45% 55% 48.7% 4 100-125 55% 45% 48.0% 5 125-150 65% 35% 45.8% 6 150-200 75% 25% 40.6% 7 200-250 85% 15% 35.5% 8 250-300 95% 05% 30.4% Outer 300-above 100% 00%

The benchmark rate of return is 9.49%. This represents SoCalGas' current authorized amount from the 1997 Cost of Capital Decision No. 96-11-060. This benchmark rate of return will remain in effect throughout the five year PBR period unless revised based on the "MICAM" mechanism.

5. Example of Revenue Sharing Calculation

Let Achieved Base Margin ROR equal 10.59%, i.e., 110 bps above the benchmark ROR.Let Actual Weighted Average Base Margin Rate Base equal $2,700 million.Total Achieved Base Margin Return above the benchmark equals $29.7 million.

T

30184-G

32545-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


12

(continued)


(continued)

Sheet of


5. Example of Revenue Sharing Calculation (continued)

The ratepayer share before grossing-up equals:

($6.75 million * 75%) + ($6.75 million * 65%) + ($6.75 million * 55%) + ($2.7 million * 45%) = $14.375 million

Since r = $14.375 / 29.7 = 0.484, the grossed-up ratepayer credit = $14.375 million / (1 - 0.484 * 0.4190) = $18.032 million

6. Cost of Capital Trigger Mechanism

The mechanism would not be triggered unless (1) actual interest rates (defined as the 12-month trailing average yield on 30 year Treasury Bond) change by more than +150 basis points (1.5%) from the benchmark rate reflected in SoCalGas' 1997 Cost of Capital Decision No. 96-11-060 (6.95%) and, (2) the then-current DRI forecast for 12 months ahead interest rates is at least +150 basis points different from the benchmark interest rate. If the threshold is triggered there will be an automatic adjustment of rates according to the pre-established formula which is the "MICAM" mechanism for rate adjustment that was adopted for SDG&E in D.96-06-055.

When an automatic adjustment is triggered, the costs of capital components would be updated and a new rate of return computed as follows:

a. The return on equity would be adjusted by one-half the change in 30 year Treasury Bond rates that triggered the adjustment.

b. The costs of long-term debt and preferred stock would be updated to reflect actual embedded costs. Interest rate forecasts would not be used.

c. For the calendar years 1998 through 2002, SoCalGas' ratemaking capital structure (i.e., common equity, preferred stock, and debt ratios) would be frozen at the 1997 level adopted in D.96-11-060.

T

30185-G

32546-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


13

(continued)


(continued)

Sheet of


7. Offramp Provisions

a. Rate of Return Offramp: either SoCalGas or ORA may file a motion seeking suspension of the PBR mechanism if for two consecutive years net operating income is 175 basis points (1.75%) below SoCalGas' authorized rate of return. If the motion is granted, suspension of the PBR mechanism would be required. If SoCalGas reports return of 300 or more basis points (3%) above its authorized rate of return for two consecutive years, the PBR mechanism will automatically be suspended, and the Commission will conduct a formal regulatory review to determine what, if any, changes in the ratemaking mechanism are required.

b. Cost of Capital Offramp: in the event of a change equal to or exceeding the cost of capital trigger mechanism, the PBR mechanism will be modified as described in G.6 above.

c. Mid-course Review: in October of 1998 SoCalGas is scheduled to file a BCAP application, which will include a mid-course review of its PBR mechanism. In this proceeding the Commission will consider SoCalGas' throughput forecast, cost allocation & rate design and other issues related to SoCalGas' PBR experience.

H. CUSTOMER SATISFACTION MEASURE, SERVICE QUALITY AND SAFETY

1. Customer Satisfaction - Customer satisfaction with SoCalGas performance on four service attributes will be measured to ensure appropriate service quality levels are maintained under PBR. The four service attributes that will be measured are as follows:

a. Customer satisfaction with the telephone customer service representative;

b. Customer satisfaction with the scheduling of the appointment for a field service call;

c. Satisfaction with the field appliance service representative; and

d. Percentage of on-time arrival for the service call.

The first three attributes will be measured on an annual basis as the percentage of customers responding with an 8, 9, or 10 on a 10 point scale (i.e. "satisfied" with the service provided), to SoCalGas' customer satisfaction telephone survey. The fourth attribute will be measured as the percentage of "yes" responses to the on-time arrival attribute.

T

30186-G

32547-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


14

(continued)


(continued)

Sheet of

H. CUSTOMER SATISFACTION MEASURE, SERVICE QUALITY AND SAFETY (continued)

1. Customer Satisfaction (continued)

Penalty Mechanism - SoCalGas will be penalized for failure to meet the identified targets for Customer Satisfaction, based on the structure contained in Table 1. The annual targets are based upon the average performance for 1994 through 1996 for each of the four service attributes and will remain constant through the PBR period. As long as each performance level remains at or above the one point deadband, SoCalGas will not be penalized. The penalty structure applies to performance on each attribute.

Table 1 - Customer Service Attributes: (1) Satisfaction with telephone service representatives ; (2) Satisfaction with appointment scheduling; (3) Satisfaction with field service representatives ; and (4) On-time arrival.

(1) (2) (3) (4) PenaltyTel Rep Apt Sch Field Rep On-Time Per% 8-10 % 8-10 % 8-10 % Yes Attribute

Target 90.7 79.4 94.2 95.4 $ 0Deadband 89.7 78.4 93.2 94.4 $ 0

89.6 78.3 93.1 94.3 $ 10,000 89.5 78.2 93.0 94.2 $ 20,000 89.4 78.1 92.9 94.1 $ 30,000 89.3 78.0 92.8 94.0 $ 40,000 89.2 77.9 92.7 93.9 $ 50,000 89.1 77.8 92.6 93.8 $ 60,000 89.0 77.7 92.5 93.7 $ 70,000 88.9 77.6 92.4 93.6 $ 80,000 88.8 77.5 92.3 93.5 $ 90,000 88.7 77.4 92.2 93.4 $100,000 88.6 77.3 92.1 93.3 $120,000 88.5 77.2 92.0 93.2 $140,000 88.4 77.1 91.9 93.1 $160,000 88.3 77.0 91.8 93.0 $180,000 88.2 76.9 91.7 92.9 $200,000

T

30187-G

32548-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


15

(continued)


(continued)

Sheet of


2. Service Quality - Telephone Response Time - The annual call center performance standard requires 80% of all telephone calls to be answered within 60 seconds for regular calls and 90% of all leak and emergency telephone calls to be answered within 20 seconds.

Penalty Mechanism - SoCalGas will be penalized for failure to meet the identified targets for telephone response time, based on the structure contained in Table 2. The penalty structure applies to performance on each measure.

Table 2 - Telephone Response Time Measures: (1) Regular Calls; and (2) Emergency and Leak Calls.

(1) (2) Penalty Reg Emg/Leak Per60 Sec 20 Sec Measure

Target 80.0 90.0 $ 0

79.9 89.9 $ 20,000 79.8 89.8 $ 40,000 79.7 89.7 $ 60,000 79.6 89.6 $ 80,000 79.5 89.5 $100,000 79.4 89.4 $120,000 79.3 89.3 $140,000 79.2 89.2 $160,000 79.1 89.1 $180,000 79.0 89.0 $200,000 78.0 88.0 $400,000

3. Employee Safety - The annual employee safety standard establishes a target of 9.3 incidents per 200,000 hours worked as the OSHA Recordable Injury and Illness Rate.

Reward/Penalty Mechanism - SoCalGas will be rewarded for exceeding and penalized for failure to meet the identified target for employee safety, based on the structure contained in Table 3. No reward or penalty will be imposed should performance improve or decline by 1.0 point around the target.

T

30188-G

32549-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


16

(continued)


(continued)

Sheet of


3. Employee Safety (continued)

Table 3 - Employee Safety Standard.

OSHARate Reward Penalty10.8 N/A $100,00010.7 N/A $ 80,00010.6 N/A $ 60,00010.5 N/A $ 40,00010.4 N/A $ 20,000

Deadband 10.3 N/A N/ATarget 9.3 N/A N/ADeadband 8.3 N/A N/A

8.2 $ 20,000 N/A8.1 $ 40,000 N/A8.0 $ 60,000 N/A7.9 $ 80,000 N/A7.8 $100,000 N/A

4. Allocation of Penalty Refunds - Any penalties and/or rewards resulting from performance for Customer Satisfaction, Telephone Response Time, and Employee Safety will be distributed according to the schedule outlined in Section L.3 by core customers class based on the allocation of customer related costs. SoCalGas' rates will be reduced by the amounts shown in Tables 1, 2, and 3, depending on actual performance.

Should the aggregate total of penalties assessed pursuant to the forgoing mechanism (as described in H.1, H.2, and H.3) in any one year reach or exceed $4 million, an investigation by the CPUC would be triggered to consider whether the penalty mechanism is working properly and/or whether appropriate remedies are in place to address service deterioration.

T

30189-G

32550-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


17

(continued)


(continued)

Sheet of

I. TREATMENT OF DSM PROGRAMS

1. Regulatory Treatment of DSM Programs Including Direct Assistance Program (DAP)

a. Applicability of the Commission's DSM Rules & Reporting Requirements

SoCalGas will comply with the Commission's current DSM Rules and Reporting Requirements (D.94-10-059, Attachment 6, and the CPUC DSM Reporting Requirements Manual, dated February 1994) for ratepayer-funded DSM activities. Authorized DSM spending and DSM shareholder incentives are excluded from the PBR Indexing Mechanism. All customer-funded DSM activities are subject to one-way balancing account treatment.

b. Funding Levels

The annualized authorized spending levels for DSM and DAP, for the period August 1, 1997 to December 31, 1997, is $27,068,000 and $11,594,000, respectively. Funding levels for future years will not be subject to the PBR Indexing Mechanism and will be determined by the Commission in annual advice letters or other filings required by the Commission.

J. TREATMENT OF RESEARCH, DEVELOPMENT AND DEMONSTRATION PROGRAMS

1. SoCalGas is authorized to conduct Research, Development and Demonstration (RD&D) activities funded by ratepayers in a one-way balancing account. The funding level is established at $7,800,000 per year and is not subject to DSM tests or prevailing Commission policy prohibiting SoCalGas from shifting RD&D funds between programs. In addition, SoCalGas will fund $500,000 per year for "public goods" RD&D, which is also subjected to one-way balancing account treatment, for an RD&D total of $8,300,000 per year (this does not include transportation RD&D which has been funded separately per LEV Decision No. 95-11-035).

2. Currently, all RD&D royalty income is refunded through a balancing account mechanism. Royalties attributable to RD&D projects underway or completed prior to the implementation of PBR will retain the existing balancing account treatment and be accrued 100% to ratepayers. Royalties from subsequent RD&D activities will be shared equally between ratepayers and shareholders. Royalties will be treated as an exclusion to the revenue sharing mechanism.

T

30190-G

32551-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


18

(continued)


(continued)

Sheet of

K. CORE PRICING FLEXIBILITY

1. Overview

a. D.97-07-054 and D.98-01-040 authorize SoCalGas, at its option, to serve core customers with rates that may be discounted as low as the Commission-authorized floor rates detailed in section K.2 below. Under this arrangement, SoCalGas shareholders are responsible for any reduction in core revenues that may occur under discounting, including any discounting of ITCS, while any revenue gains are shared between ratepayers and shareholders as described below. SoCalGas may use the following two methods to offer alternative rates to core customers:

1. Optional Tariffs - Optional tariff rate schedules apply to all similarly situated customers who meet a certain set of qualifications. At least 10 customers should be potentially eligible.

2. Negotiated Rates - Negotiated rates apply to individual customers, and are established through individually negotiated contracts that may vary from customer to customer.

b. The entire discounting program is subject to review by the Commission if new customer participation approaches 5% of the total core volume adopted in SoCalGas' 1996 BCAP (D.97-04-082).

c. Customers eligible for service under optional tariffs or negotiated rates retain the right to be served under their Otherwise Applicable Tariff rate schedule.

d. To ensure that ratepayers are isolated from any risk of revenue shortfall that may result from SoCalGas offering discounted core rates, the Commission has authorized a Core Fixed Cost Account (CFCA) adjustment mechanism. This mechanism credits the CFCA with revenues equal to those expected absent any optional tariffs or negotiated rates.

e. Revenue gains are shared between ratepayers and shareholders in accord with the PBR sharing mechanism, except as described in section K.5.d.2. SoCalGas will submit documentation on the results of its core pricing flexibility program activity in its annual Shareable Earnings filing.

f. Optional tariffs and negotiated rates are subject to change by the Commission as authorized by General Order 96-A, sections IX and X.

T

30191-G

32552-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


19

(continued)


(continued)

Sheet of

K. CORE PRICING FLEXIBILITY (continued)

2. Class Average Long Run Marginal Cost (LRMC) Floor Rates

a. D.98-01-040, Finding of Fact No. 5, allows SoCalGas the option to discount core transportation rates down to a LRMC floor rate; however, SoCalGas may not discount the cost of gas. For this program, the LRMC floor rate includes the following components: customer related, medium-pressure distribution, high-pressure distribution, transmission, seasonal storage, load balancing, company use transmission, unaccounted for gas, and interstate pipeline demand charges. In addition to these components, the full transportation rate includes the following components: non-marginal costs in base margin, ITCS, PITCO/POPCO transition costs, core averaging costs, and other exclusion costs.

b. The following table lists the full LRMC transportation rates authorized by D.97-04-082, and the class average LRMC floor rates authorized by D.98-01-040. Both rates are updated with new values established in D.00-04-060. The floor rates represent the lowest possible average annual rate by class under which SoCalGas can serve gas. These rates represent a starting point for the program and, pursuant to Commission order, may be modified in future rate proceedings.

Class Full Transportation Rate LRMC Floor RateResidential 40.6 cents/therm 27.7 cents/thermG-10, 0 to 3 Mth 65.2 cents/therm 40.5 cents/thermG-10, 3-50 Mth 25.0 cents/therm 15.1 cents/thermG-10, 50-250 Mth 17.9 cents/therm 10.8 cents/thermG-20 11.7 cents/therm 8.5 cents/thermGas A/C 11.0 cents/therm 10.0 cents/thermGas Engines 20.4 cents/therm 15.4 cents/therm

c. Optional tariffs or negotiated rate contracts that would result in average annual rates below class average LRMC will be subject to Commission approval through the Expedited Application Docket (EAD) process.

d. With prior Commission approval under the EAD process, SoCalGas may discount average annual rates to a floor of customer-specific LRMC that includes the full interstate pipeline reservation charges allocated to core customers (excluding ITCS).

NN

R,RR,RR,RR,RR,RR,RI,I

T

30192-G

32553-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


20

(continued)


(continued)

Sheet of


3. Types of Customers and Contracts

Optional tariffs and negotiated rates are applicable to new or existing customers for the purpose of load growth or load retention.

a. New Customers

A new customer is defined as a new meter measuring volumes not previously served, or a reconnected meter measuring load that has been off the system for at least 12 months.

b. Existing Customers

In addition to customers currently connected, D.98-01-040 defines existing customers as those who have been off SoCalGas' system for less than 12 months.

1. Load Retention

Load retention applies to those existing customers who would use less natural gas if optional tariffs or negotiated rates were not available. In load retention situations, an affidavit (stating the amount of throughput that would be lost absent the load retention agreement) is required.

2. Load Gain

Load gain applies to those existing customers who intend to increase natural gas demand given favorable optional tariffs or negotiated rates.

T

30193-G

32554-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


21

(continued)


(continued)

Sheet of


4. Temperature Sensitive Definition

a. For the purposes of the Temperature Adjustment Mechanism (TAM), the following customers are defined as temperature sensitive: residential customers; all core commercial and industrial customers with an annual consumption of less than 3,000 therms; and individual core commercial and industrial customers who have a seasonal load factor that equals or exceeds the residential load factor of 2.3.

b. The seasonal factor is defined as the ratio of winter (November through April) demand to summer (May through October) demand.

c. The single family residential market's temperature adjustment factor will be used for all customers subject to the TAM.

5. CFCA Adjustment Mechanism

This mechanism is designed to protect core customers by calculating those revenues which represent base revenues that would have been credited to the CFCA absent any optional tariffs or negotiated rates.

a. Unless otherwise noted, base revenues are calculated by multiplying base volumes times the Otherwise Applicable Tariff rate plus the customer charge, where base volumes are the amount of gas the customer would have used in the absence of the optional tariff or negotiated rate.

b. When load being served under optional tariffs and negotiated rates is not separately metered, base volumes are established using the last 12 months recorded usage. In certain cases, base volumes are adjusted, as described in section K.6, for temperature variations.

c. SoCalGas credits the CFCA with aggregate base revenues annually for all customers participating in the optional tariffs and negotiated rate program. This annual credit is calculated as the sum of the monthly base revenues.

T

30194-G

32555-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


22

(continued)


(continued)

Sheet of


5. CFCA Adjustment Mechanism (continued)

d. CFCA Credits

1. New Customers

For a new customer who provides an affidavit stating they would not have become a customer absent the discounted rate, base volume equals zero, and there is no credit to the CFCA. For a new customer who does not provide an affidavit, the base volume equals the actual volume, and the CFCA credit is equal to 100% of the expected revenue under the Otherwise Applicable Tariff [i.e., 100% *(total metered actual volumes * Otherwise Applicable Tariff rate + customer charge)].

2. Existing Customers - Load Retention

The CFCA credit is equal to 95 % of actual revenue [i.e., 95% * (total metered actual volumes * optional tariff rate + customer charge)]; the remaining 5% of actual revenues goes to SoCalGas shareholders.

3. Existing Customers - Load Gain

A. Not Temperature Sensitive

Since customers with an annual load of less than 3,000 therms per year are treated as temperature sensitive, this category applies only to core commercial and industrial customers who use more than 3,000 therms in the base year, and have a seasonal factor less than 2.3. For these customers, base volumes equal the volume for the 12 months preceding the customer's participation in the optional tariff program.

B. Temperature Sensitive

For customers to whom the TAM applies, SoCalGas will use temperature-adjusted base volumes, as described in section K.6.

e. In the event proposed optional tariffs present special circumstances that may cause the CFCA adjustment mechanism to be clearly inappropriate or inaccurate, SoCalGas will propose, by advice letter filing, an alternative CFCA adjustment mechanism. Under such special circumstances, other parties may also propose alternate CFCA adjustment mechanisms.

T

30195-G

32556-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


23

(continued)


(continued)

Sheet of


6. Temperature Adjustment Mechanism (TAM)

The purpose of the TAM is to calculate temperature-adjusted base volumes that isolate the effect of weather changes from the effect of flexible pricing. The temperature-adjusted base volumes for a given month are calculated by multiplying base volumes times the quantity (1 + NF); where NF stands for normalization factor which is calculated as follows:

NF = [0.202*(CDD - BDD)]/[(0.917 * Billdays) + (0.202 * BDD)]

Where,BDD = number of degree days for the base month cycle.CDD = number of degree days for the current year month cycle.0.917 = daily non-temperature sensitive demand for single family residential segment.Billdays = number of billing days in the base period month.0.202 = temperature adjustment coefficient for single family residential segment.

7. Effective Dates

a. Optional tariffs will be effective upon 20 days after filing unless protested on the basis that the price floor is below class average LRMC; parties may protest such filings on any other basis as well.

b. Unless otherwise specified in the tariff, SoCalGas may terminate optional rate schedules upon 60 days notice to customers and the Commission.

8. Term Of Contracts

a. Through December 31, 1999, SoCalGas will not enter into any load retention contracts with a term of more than seven years. After December 31, 1999, SoCalGas will not enter into any load retention contract with a term of five or more years.

b. As provided by D.97-07-054, contracts with a term of five years or longer will be filed for Commission approval under the EAD process.

c. Negotiated contracts with terms of less than five years will be available for inspection at SoCalGas' headquarters, and will be submitted to the Commission's Energy Division for informational purposes.

d. Once a load retention contract is in place for a particular load, the contract cannot be extended or renewed for a period longer than the maximum term permissible at the time the contract was executed.

T

30196-G

32557-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


24

(continued)


(continued)

Sheet of

L. RATEMAKING PROCEEDINGS

The following methods will be used to effectuate rate changes during the PBR period:

1. Biennial Cost Allocation Proceeding (BCAP)

a. The BCAP is the proceeding by which the Commission authorizes the level and allocation of SoCalGas' revenue requirement including regulatory account balances among customer classes for those items not included in the PBR Mechanism. SoCalGas' BCAP application will be filed every other year pursuant to D.94-07-064 (Global Settlement). SoCalGas filed its 1999 BCAP application in October of 1998. Pursuant to D.00-04-060, the 1999 BCAP rates are effective June 1, 2000 and continue in effect through December 31, 2002.

b. In non-BCAP years, SoCalGas will file an advice letter on or before October 15 to update the regulatory account amortization components of rates.

c. Noncore Competitive Load Growth Opportunities - Revenue Treatment

1) Overview

a) D.00-04-060 (Finding of Fact Number 9.q.) authorizes SoCalGas, at its option, to exclude from future cost allocations the expanded load that results from two situations:

1. New negotiated rate contracts that are part of a California Red Team economic development effort.

2. Contracts where Rule 38 shareholder funding has been used.

Under this arrangement, the volumes and revenues from these situations will not be included in determining noncore commercial and industrial revenue requirements.

b) The total volume that can qualify for treatment under this program is capped at 5% of the most recently adopted volume adopted for noncore commercial and industrial throughput in the most recent cost allocation proceeding.

c) Customers with contracts qualifying for this treatment are still eligible for service under their otherwise applicable tariff rate schedule.

NN

N | | | | | | | | | | | | | | | | | | |N

T

32558-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


25

(continued)


(continued)

Sheet of

L. RATEMAKING PROCEEDINGS (continued)

1. Biennial Cost Allocation Proceeding (BCAP) (continued)

c. Noncore Competitive Load Growth Opportunities - Revenue Treatment (continued)

1) Overview (continued)

d) To ensure that ratepayers are isolated from any risk of revenue shortfall that may result from SoCalGas excluding these noncore volumes from other noncore volumes, SoCalGas has instituted a Noncore Fixed Cost Account (NFCA) adjustment mechanism. This mechanism ensures that the NFCA records the revenues equal to those expected absent any special treatment under this program.

e) Earnings are shared between ratepayers and shareholders in accord with the PBR sharing mechanism, except as described in Section G. SoCalGas will submit documentation on the results of its competitive Load Growth revenue program activity in its annual Shareable Earnings filing.

f) Contracts qualifying under this program are subject to change by the Commission as authorized by General Order 96-A, sections IX and X.

2) Contract Terms

a) Contract terms will be as negotiated between SoCalGas and the customer. Negotiated rates cannot be less than adopted short run marginal costs.

b) Contracts involving Rule 38 incentives will be assumed to run for five years, unless stated otherwise in the Contract. Contracts involving California Red Team will be as negotiated. If no term is set, the contract will be assumed to run for five years.

c) SoCalGas may, at its option, file an application with the Commission requesting that a contract receive treatment under this program for a period beyond five years.

N | | | | | | | | | | | | | | | | | | | | | | | | | | |N

T

32559-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


26

(continued)


(continued)

Sheet of




3. Customers

a) Any load associated with a noncore commercial and industrial customer is eligible under this program.

b) Contracts not qualifying for this regulatory treatment are:

1. An existing customer that could economically connect to a bypass pipeline.

2. A new customer (no recorded usage in the previous 12 months) in close proximity to a bypass pipeline.

3. A customer who previously received discounts to prevent fuel switching to a petroleum distillate fuel.

c) SoCalGas shall determine which contracts to include in this program, subject to review by the Commission.

d) A new customer will have a baseload volume of zero.

e) If new equipment is installed at a customer site under a contract qualifying for this program, and the equipment is separately metered, then only the metered volumes and revenues will receive treatment under this program.

f) If the new load is not separately metered, then base load volumes will be calculated as the average annual volume over the previous 24 months. If there are unusual characteristics that would cause the customer's 24 month history to be unrepresentative of average annual expected throughput, SoCalGas will select a different period of time that is more representative.

N | | | | | | | | | | | | | | | | | | | | | | | | | | | | |N

T

32560-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


27

(continued)


(continued)

Sheet of




4) Regulatory Requirements

a) At the end of every calendar year, SoCalGas shall file with the Commission a confidential report showing a summary of activity under this program. The report will show the number of qualifying contracts, qualifying volumes, revenues received for qualifying volumes, and amounts credited to ratepayers for baseload volumes.

b) Customers must sign an affidavit attesting that the contract structure (in case of Red Team contracts) or the incentives (in case of Rule 38) were a material factor in the customer's decision to participate.

c) SoCalGas shall track all volumes that qualify under this program. These volumes will be excluded from forecasts adopted for cost allocation purposes for a period of five years after the start of each contract.

d) Revenues from customers and contracts qualifying under this are separated into two components:

1. Baseload revenues, calculated as the applicable baseload volumes times the otherwise applicable tariff.

2. Load growth related revenues, calculated as total revenues received from the customer minus baseload revenues.

Base load revenues will be credited to the Noncore Fixed Cost Account. Load Growth Related Revenues will be credited to the shareholder. Both revenues will be incorporated into the Earnings Sharing Mechanism as described in Section G.

e) SoCalGas will track any contract specific costs incurred to support volumes qualifying under this program. Any costs incurred for separate metering, service lines, regulators, main extensions, etc. to serve specific locations that qualify under this program would be tracked. As long as the contract volumes are exempt from inclusion in cost allocation proceedings, these costs will not be included in the authorized utility revenue requirement.

N | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |N

T

30196-G & 30197-G

32561-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


28

(continued)


(continued)

Sheet of


2. Annual Rate Adjustments (ARA's)

SoCalGas shall make an annual advice letter filing on or before October 1 to update base margin, according to the Indexing Mechanism (described in Section D), effective January 1 of the following year for each year PBR is in effect. The advice letter will contain detailed information on forecast/true-up data for the Gas Utility Price Index and on customer growth. The filing may also include proposed Z Factor adjustments and a refund if SoCalGas does not meet the Customer Satisfaction Measure standards.

3. Sharable Earnings Filings

Starting in year 2 of the PBR period SoCalGas will file an advice letter providing sharable earnings according to the financial sharing mechanism described in Section G. If there are any shareable earnings these will be included in rates on January 1 of the subsequent year. This filing will also include a report on service quality, customer satisfaction and safety incentives as adopted in D.97-07-054. The time frame that will be followed is:

April 1 - SoCalGas provides a draft sharable earnings advice letter to appropriate Commission staff, which includes workpapers detailing operating results for SoCalGas' base rates.

July 1 - Commission staff can submit a report on its audit or analysis of SoCalGas' draft sharable earnings results.

July 10 - SoCalGas files its final performance advice letter, with supporting workpapers.

July 31 - Protests in accordance with General Order 96-A can be filed.

4. Other Ratemaking Proceedings

Other decisions by the Commission may require rate revisions at times other than those specified herein.

L | | | | | | | | | | | | | | | | | | | | | | | |L

L

T

30197-G

32562-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


29

(continued)


Sheet of

M. MONITORING AND EVALUATION

In compliance with SoCalGas' PBR D.97-07-054, dated July 16, 1997, and in recognition of the various comprehensive monthly, quarterly and annual reports currently required by the Commission and described in D.97-07-054, SoCalGas will maintain the current level of reporting requirements set forth in that decision.

1. D.97-07-054 requires that SoCalGas file an additional annual advice letter to review the performance of the PBR during the previous calendar year as described above in Section L.3.

2. Continuation of the Three-Year Audit Cycle is retained pursuant to Public Utilities Code Section 314.5

3. SoCalGas may preserve the confidentiality of information currently available under Public Utilities Code Section 583 and General Order 66-C upon a showing of good cause.

L | | | | | | | | | | | | |L

T

32459-G

32563-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

RESIDENTIAL SERVICE

2

(continued)

4Schedule No. GR

(continued)

Sheet of

RATES (continued)

Commodity Charges

GR

These charges are for service as defined above and consist of: (1) the monthly residential procurement charge, as set forth in Schedule No. G-CP; (2) the GT-R transmission charges, as set forth in Schedule No. GT-R; (3) the San Juan Lateral interstate demand charge; and (4) the procurement carrying cost of storage inventory charge.

The residential procurement charge is determined as set forth in Schedule No. G-CP, in the manner approved by D.96-08-037, and subject to change monthly as described in Special Condition 7.

Baseline Rate

All usage, per therm, under Special Conditions 2 and 3.

Procurement Charge: G-CPR ............................................ 32.723¢Transmission Charge: GPT-R ........................................... 24.405¢Commodity Charge: GR .................................................. 57.128¢

Non-Baseline Rate

All usage, per therm.

Procurement Charge: G-CPR ............................................ 32.723¢Transmission Charge: GPT-R ........................................... 42.389¢Commodity Charge: GR .................................................. 75.112¢

The number of therms to be billed shall be dtermined in accordance with Rule No. 2.

RR

RR

30820-G

32564-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

RESIDENTIAL SERVICE

3

(continued)

4Schedule No. GR

(continued)

Sheet of

SPECIAL CONDITIONS

1. Baseline Rates: Baseline Rates are applicable only to specific volumes of residential usage.

2. Baseline Usage: The following quantities of gas used in individually metered residences not in a multi-family complex are to be billed at the Baseline rates. Usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates.

Daily Therm AllowancePer Residence for Climate Zones*

1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

3. In multi-family complexes where individual dwelling units receive natural gas service directly from the Utility through separate meters and where other residential services are provided from a separately metered central source, the applicable basic Baseline allowance for each such individually metered dwelling unit, subject to verification, will be as follows:

Daily Therm AllowanceCodes Per Residence for Climate Zones*

1 2 31 Space heating only

Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823

2 Water heating and cooking 0.460 0.460 0.4603 Cooking, water heating

and space heatingSummer 0.457 0.457 0.457Winter 1.624 1.956 2.287

4 Cooking and space heatingSummer 0.085 0.085 0.085Winter 1.246 1.578 1.909

5 Cooking only 0.085 0.085 0.0856 Water heating only 0.375 0.375 0.3757 Water heating and space

heatingSummer 0.372 0.372 0.372Winter 1.538 1.870 2.201

* Climate Zones are described in the Preliminary Statement.

RR

RR

RR

R | |R

RR

32135-G

32565-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONFOR RESIDENTIAL SERVICE

2

(continued)

4Schedule No. GT-R

(continued)

Sheet of

RATES (continued)

Transmission Charge

GT-R

This charge is equal to the core commodity rate less the following four components as approved in D.97-04-082: (1) the weighted average cost of gas; (2) the core brokerage fee; (3) the procurement carrying cost of storage inventory; and (4) the San Juan Lateral interstate demand charge.

Baseline RateAll usage, per therm, under Special Condition 2and Special Condition 3 ................................................................. 24.121¢

Non-Baseline RateAll usage, per therm ........................................................................ 42.105¢

The number of therms to be billed shall be determined in accordance with Rule 2.

SPECIAL CONDITIONS




1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

R

R

RR

31174-G

32566-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONFOR RESIDENTIAL SERVICE

3

(continued)

4Schedule No. GT-R

(continued)

Sheet of

SPECIAL CONDITIONS (continued)

3. In multi-family complexes where individual dwelling units receive natural gas service directly from SoCalGas through separate meters and where other residential services are provided from a separately metered central source, the applicable basic Baseline allowance for each such individually metered dwelling unit, subject to verification, will be as follows:



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823







Upon completion of an application and verification by a state-licensed physician (Form No. 4859-E), an additional Baseline allowance of .822 therms per day will be provided for paraplegic, quadriplegic, or hemiplegic persons, those afflicted with multiple sclerosis or scleroderma, or persons being treated for a life threatening illness or who have a compromised immune system.

Upon completion of an application and verification by a state-licensed physician or osteopath (Form No. 4859-E), an additional uniform daily Baseline allowance will be provided to customers requiring regular use of a medical life-support device, as defined in Rule No. 1, which utilizes mechanical or artificial means to sustain, restore, or supplant a vital function and requires the use of SoCalGas-supplied gas. The amount of the additional allowances will be determined by SoCalGas from load and operating time data of the medical life-support device.

RR

RR

R | |R

RR

32136-G

32567-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

MULTI-FAMILY SERVICE SUBMETERED

1 5Schedule No. GS

(continued)

Sheet of

APPLICABILITY

Applicable to natural gas service for multi-family dwelling units and mobile home parks supplied through one meter on a single premises and submetered to all individual units, supplied from the Utility's core portfolio, as defined in Rule No. 1. The number of qualifying units is subject to verification by the Utility. This schedule is closed to new mobile home parks or manufactured housing communities for which construction has commenced after January 1, 1997.

The minimum term of service hereunder is one month, as described in Special Condition 10.

TERRITORY

Applicable throughout the system.

RATES

The therms in the Baseline block shall be multiplied by the number of qualified residential units. A daily submetering credit of 30.805¢ shall be applicable for each qualified residential unit. However, in no instance shall the monthly bill be less than the minimum charge.

Customer Charge

Per meter, per day ........................................................................ 16.438¢*

* For "space heating only" customers a daily customer charge during the winter of 33.149¢ per d ay applies beginning November 1 through April 30. For the summer period beginning May 1 through October 31, except for closing bills or at the time of a rate increase, usage will be accumulated to at least 20 therms before billing.

The term "space heating only" applies to customers who are using gas primarily for space heating for human comfort as determined by survey or under the presumption that customers who use less than 11 therms per month during each of the regular billing periods ending in August and September are using gas primarily for space heating for human comfort.

Minimum Charge (Per Meter Per Day)

All customers except "space heating only" ......................................... 16.438¢

"Space heating only" customers"

Beginning November 1 through April 30 ....................................... 33.149¢

Beginning May 1 through October 31 ........................................... None

I

32460-G

32568-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

5Schedule No. GS

(continued)

Sheet of

RATES (continued)

Commodity Charges

GS

These charges are for service as defined above and consist of: (1) the monthly residential procurement charge, as set forth in Schedule No. G-CP; (2) the GT-S transmission charges, as set forth in Schedule No. GT-S; (3) the San Juan Lateral interstate demand charge; and (4) the procurement carrying cost of storage inventory charge.


Baseline Rate


Procurement Charge: G-CPR ........................................... 32.723¢Transmission Charge: GPT-S ............................................ 24.405¢Commodity Charge: GS .................................................. 57.128¢

Non-Baseline Rate


Procurement Charge: G-CPR ........................................... 32.723¢Transmission Charge: GPT-S ............................................ 42.389¢Commodity Charge: GS .................................................. 75.112¢


RR

RR

30828-G

32569-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

5Schedule No. GS

(continued)

Sheet of

SPECIAL CONDITIONS


2. Baseline Usage: The following usage is to be billed at the Baseline rate for each submetered multi-family dwelling unit. Usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rate.


1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287



Upon completion of an application and verification by a state-licensed physician or osteopath (Form No. 4859-E), an additional uniform daily Baseline allowance will be provided to customers requiring regular use of a medical life-support device, as defined in Rule No. 1, which utilizes mechanical or artificial means to sustain, restore, or supplant a vital function and requires the use of Utility-supplied gas. The amount of the additional allowances will be determined by the Utility from load and operating time data of the medical life-support device.

3. The meter readings for sub-metered multi-family complexes may be combined for billing purposes when all of the following conditions exist:

a. There is more than one master meter serving the complex.

b A baseline eligible central facility serves sub-metered baseline eligible dwelling units.

c. The sub-metered baseline eligible dwelling units are not provided gas by the same master meter which provides gas to the central facility.

A customer charge will be applied to each meter in the multi-family complex that is combined for billing purposes.

RR

32138-G

32570-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONFOR MULTI-FAMILY SUBMETERED SERVICE

1 5Schedule No. GT-S

(continued)

Sheet of

APPLICABILITY

Applicable to transportation of customer-owned natural gas to multi-family dwelling units and mobile home parks supplied through one meter on a single premise and submetered to all individual units. The number of qualifying units is subject to verification by SoCalGas. Service under this schedule is available to customers that elect to purchase natural gas from ESPs in accordance with Rule No. 32. This schedule is closed to new mobile home parks or manufactured housing communities for which construction has commenced after January 1, 1997.

TERRITORY

Applicable throughout the service territory.

RATES


Customer Charge

Per meter, per day ........................................ 16.438¢*

If the customer charge is collected under another rate schedule, no duplicate charge is collected hereunder.

* For "space heating only" customers, a daily customer charge of 33.149¢ per day applies during the winter period beginning November 1 through April 30. For the summer period beginning May 1 through October 31, except for closing bills or at the time of a rate increase, usage will be accumulated to at least 20 therms before billing.



All customers except "space heating only" ................... 16.438¢"Space heating only" customers:

Beginning November 1 through April 30.................... 33.149¢Beginning May 1 through October 31 .................... None

I

32139-G

32571-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

5Schedule No. GT-S

(continued)

Sheet of

RATES (continued)

Transmission Charges

GT-S


Baseline Rate

All usage, per therm, under Special Condition 2and Special Condition 3 ............................................................. 24.121¢

Non-Baseline Rate

All usage, per therm .................................................................... 42.105¢

Billing Adjustments

Billing adjustments may be necessary to reflect changes in volumes used in developing prior periods' transportation charges.

The number of therms to be billed shall be determined in accordance with Rule No. 2.

R

R

31177-G

32572-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

5Schedule No. GT-S

(continued)

Sheet of

SPECIAL CONDITIONS




1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287





a. There is more than one master meter serving the complex.b. A baseline eligible central facility serves sub-metered baseline eligible dwelling units.c. The sub-metered baseline eligible dwelling units are not provided gas by the same master meter

which provides gas to the central facility.

A customer charge will be applied to each meter in the multi-family complex that is combined for billing purposes.

It is the responsibility of the owner or the owner's agent to demonstrate to SoCalGas' satisfaction the yardline configuration and the number of residential units served by the central facility. Eligibility for service under this provision is available subsequent to notification by the customer and verification by SoCalGas.

RR

32461-G

32573-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

MULTI-FAMILY SERVICE

2

(continued)

6Schedule No. GM

(continued)

Sheet of

RATES (continued)

Commodity Charges

These charges are for service as defined above and consist of: (1) the monthly residential procurement charge, as set forth in Schedule No. G-CP; (2) the GT-ME and GT-MC transmission charges, as set forth in Schedule No. GT-M; (3) the San Juan Lateral interstate demand charge; and (4) the procurement carrying cost of storage inventory charge.


GM-E

Baseline Rate


Procurement Charge: G-CPR ............................................. 32.723¢Transmission Charge: GPT-ME .......................................... 24.405¢Commodity Charge: GM-E ............................................... 57.128¢

Non-Baseline Rate


Procurement Charge: G-CPR ............................................ 32.723¢Transmission Charge: GPT-ME ......................................... 42.389¢Commodity Charge: GM-E .............................................. 75.112¢

GM-C


Procurement Charge: G-CPR ............................................ 32.723¢Transmission Charge: GPT-MC ......................................... 42.389¢Commodity Charge: GM-C .............................................. 75.112¢


RR

RR

RR

30834-G*

32574-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

6Schedule No. GM

(continued)

Sheet of

RATES (continued)


All customers except "space heating only" ................................................ 16.438¢

"Space heating only" customers:

Beginning November 1 through April 30 .............................................. 33.149¢

Beginning May 1 through October 31 ................................................... None

SPECIAL CONDITIONS


2. Baseline Usage: The following usage is to be billed at the Baseline rate for multi-family dwelling units. Usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rate.


1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287


RR

30835-G

32575-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

6Schedule No. GM

(continued)

Sheet of


3. In multi-family complexes where residential services for each or any of the individually metered residential units is provided from a central source and where such central facility receives natural gas service directly through a separate meter, the basic monthly Baseline allowance applicable to that meter will be the number of therms per day times the number of dwelling units receiving service from such central facility. Eligibility for service under this provision is available subsequent to notification by customer and verification by Utility. The Baseline allowances for the central facility service will be as follows:



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823







The meter readings for multi-family complexes may be combined for billing purposes when all of the following conditions exist:

a. There is more than one master meter serving the complex.b. A baseline eligible central facility serves master metered baseline eligible dwelling units.c. The master metered baseline eligible dwelling units are not provided gas by the same master meter


RR

RR

R | |R

RR

32141-G

32576-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONFOR MULTI-FAMILY SERVICE

2

(continued)

6Schedule No. GT-M

(continued)

Sheet of

RATES (continued)


These charges are equal to the core commodity rate less the following four components as approved in D.97-04-082: (1) the weighted average cost of gas; (2) the core brokerage fee; (3) the procurement carrying cost of storage inventory; and (4) the San Juan Lateral interstate demand charge.

GT-ME

Baseline Rate

All usage, per therm, under Special Condition 2and Special Condition 3 ................................................................ 24.121¢

Non-Baseline Rate

All usage, per therm ....................................................................... 42.105¢

GT-MC

All usage, per therm ........................................................................... 42.105¢



The minimum charge shall be the customer charge, which is:

All customers except "space heating only" .......................................... 16.438¢

"Space heating only" customers:

Beginning November 1 through April 30 ................................. 33.149¢

Beginning May 1 through October 31 ...................................... None

Billing Adjustments


R

R

R

31181-G

32577-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONFOR MULTI-FAMILY SERVICE

3

(continued)

6Schedule No. GT-M

(continued)

Sheet of

SPECIAL CONDITIONS




1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

3. In multi-family complexes where residential services for each or any of the individually metered residential units is provided from a central source and where such central facility receives natural gas service directly through a separate meter, the basic monthly Baseline allowance applicable to that meter will be the number of therms per day times the number of dwelling units receiving service from such central facility. Eligibility for service under this provision is available subsequent to notification by customer and verification by SoCalGas. The Baseline allowances for the central facility service will be as follows:



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823







RR

RR

RR

R | |R

RR

30844-G

32578-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

LARGE MULTI-FAMILY SERVICE

1 6Schedule No. GMB

(continued)

Sheet of

APPLICABILITY

"GMB" customers are master metered customers who have averaged at least 100,000 therms of weather-normalized usage for the previous two calendar years, January through December, and will be billed on the "GMB" rate schedules which include the GM-BE, GM-BC, GT-MBE and GT-MBC rates. Sub-metered customers are not eligible for this rate schedule.

Applicable to natural gas service supplied from the Utility's core portfolio as defined in Rule No. 1, for multi-family dwelling units supplying Baseline uses only or in a combination of Baseline uses and common facilities through one meter on a premises, except as otherwise provided in Special Condition 5. Such gas service will be billed on Schedule No. GM-BE. This schedule also applies to accommodations defined in Rule No. 1 as residential hotels. Natural gas supplied through a single meter to common facilities (swimming pools, recreation rooms, saunas, spas, etc.) only, will be billed on Schedule No. GM-BC.

Eligibility for service hereunder is subject to verification by the Utility.


TERRITORY


RATES

The individual unit Baseline therm allocation shall be multiplied by the number of qualified residential units.

Customer Charge

Per meter, per day ................................................................................. $5.304

This charge may be passed on to tenants on an equal amount per qualifying unit basis.

R

R

32462-G

32579-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

6Schedule No. GMB

(continued)

Sheet of

RATES (continued)

Commodity Charges

These charges are for service as defined above and consist of: (1) the monthly residential procurement charge, as set forth in Schedule No. G-CP; (2) the GT-MBE and GT-MBC transmission charges, as set forth in Schedule No. GT-MB; (3) the San Juan Lateral interstate demand charge; and (4) the procurement carrying cost of storage inventory charge.


GM-BE

Baseline Rate


Procurement Charge: G-CPR ............................................. 32.723¢Transmission Charge: GPT-MBE ....................................... 26.214¢Commodity Charge: GM-BE ............................................ 58.937¢

Non-Baseline Rate


Procurement Charge: G-CPR ............................................ 32.723¢Transmission Charge: GPT-MBE ....................................... 35.289¢Commodity Charge: GM-BE ............................................ 68.012¢

GM-BC


Procurement Charge: G-CPR ............................................ 32.723¢Transmission Charge: GPT-MBC ....................................... 35.289¢Commodity Charge: GM-BC ............................................ 68.012¢


II

II

II

30846-G*

32580-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

6Schedule No. GMB

(continued)

Sheet of

RATES (continued)


"GMB" customers ..................................................................................... $5.304

SPECIAL CONDITIONS




1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287


3. In multi-family complexes where residential services for each or any of the individually metered residential units is provided from a central source and where such central facility receives natural gas service directly through a separate meter, the basic monthly Baseline allowance applicable to that meter will be the number of therms per day times the number of dwelling units receiving service from such central facility. Eligibility for service under this provision is available subsequent to notification by customer and verification by Utility. The Baseline allowances for the central facility service will be as follows:

R

RR

30847-G

32581-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

6Schedule No. GMB

(continued)

Sheet of


3. (continued)Daily Therm Allowance

Codes Per Residence for Climate Zones* 1 2 3

1 Space heating onlySummer 0.000 0.000 0.000Winter 1.160 1.492 1.823







The meter readings for multi-family complexes may be combined for billing purposes when all of the following conditions exist:

a. There is more than one master meter serving the complex.b. A baseline eligible central facility serves master metered baseline eligible dwelling units.c. The master metered baseline eligible dwelling units are not provided gas by the same master meter


A Customer Charge will be applied to each meter in the multi-family complex that is combined for billing purposes.

It is the responsibility of the owner or the owner's agent to demonstrate to the Utility's satisfaction the yardline configuration and the number of residential units served by the central facility. Eligibility for service under this provision is available subsequent to notification by the customer and verification by the utility.

RR

RR

R | |R

RR

30848-G

32582-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

6Schedule No. GMB

(continued)

Sheet of


3. (continued)



4. It is the responsibility of the customer to advise the Utility within 15 days following any change in the submetering arrangements or the number of dwelling units or mobile home spaces provided gas service.

5. This schedule is closed as of July 13, 1978 for gas service to:

a. New residential mobile home parks where such mobile home tenants use gas directly in gas appliances in each occupancy.

b. New multi-unit residential structures where such multi-unit tenants use gas directly in gas appliances in each occupancy and which requires venting.

6. Seasonal Changes: Bills reflecting Baseline allowances will be prepared in the May and November billing periods using the applicable daily allowance from each respective seasonal period.

7. Customers receiving service hereunder with usage at each facility in excess of 100,000 therms per year may qualify for transportation service under a special contract. Additionally, customers may aggregate their gas volumes to qualify for transportation service under Schedule No. GT-MB.

8. The "GMB" rate schedules, which include the GM-BE, GM-BC, GT-MBE and GT-MBC rates, will become effective for eligible customers on the first day of the customers' next billing cycle following the effective annual date of the rate, June 1, and will remain in effect for 12 monthly billing cycles, regardless of usage. Customers will be evaluated once a year to qualify for the rate. Customers will qualify for the rate if the applicability criteria of this tariff are satisfied. Customers who are on the rate will be dropped off the rate if they do not meet the criteria during the annual evaluation period.

R

T

31185-G

32583-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONFOR LARGE MULTI-FAMILY SERVICE

1 6Schedule No. GT-MB

(continued)

Sheet of

APPLICABILITY

"GMB" customers are master-metered customers who have averaged at least 100,000 therms of weather-normalized usage for the previous two calendar years, January through December, and will be billed on the "GMB" rate schedules which include the GM-BE, GM-BC, GT-MBE and GT-MBC rates. Sub-metered customers are not eligible for this rate schedule.

Applicable to the transportation of customer-owned natural gas to multi-family dwelling units supplying Baseline uses only or a combination of Baseline uses and common facilities through one meter on a premise, except as otherwise provided for in Special Condition 5. Such gas service will be billed at the GT-MBE rate. The GT-MBE rate shall also apply to accommodations defined in Rule No. 1 as residential hotels. Natural gas supplied through a single meter to common facilities (swimming pools, recreation rooms, saunas, spas, etc.) only, will be billed at the GT-MBC rate. Service under this schedule is available to customers that elect to purchase natural gas from ESPs in accordance with Rule No. 32.

Eligibility for service hereunder is subject to verification by SoCalGas.

TERRITORY


RATES

The individual unit Baseline therm allocation shall be multiplied by the number of qualified residential units.

Customer Charge

Per meter, per day .................................................................................. $5.304


This charge may be passed on to tenants on an equal amount per qualifying unit basis.

R

R

32143-G

32584-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

6Schedule No. GT-MB

(continued)

Sheet of

RATES (continued)



GT-MBE

Baseline Rate

All usage, per therm, under Special Condition 2and Special Condition 3 .................................................................. 25.930¢

Non-Baseline Rate

All usage, per therm ........................................................................ 35.005¢

GT-MBC

All usage, per therm ........................................................................ 35.005¢



The minimum charge shall be the customer charge, which is:

"GMB" customers ............................................................................. $5.304

Billing Adjustments


I

I

I

R

31186-G

32585-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

6Schedule No. GT-MB

(continued)

Sheet of

SPECIAL CONDITIONS




1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

3. In multi-family complexes where residential services for each or any of the individually metered residential units is provided from a central source and where such central facility receives natural gas service directly through a separate meter, the basic monthly Baseline allowance applicable to that meter will be the number of therms per day times the number of dwelling units receiving service from such central facility. Eligibility for service under this provision is available subsequent to notification by customer and verification by SoCalGas. The Baseline allowances for the central facility service will be as follows:



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823







RR

RR

RR

R | |R

RR

32463-G

32586-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

RESIDENTIAL SERVICE, INCOME-QUALIFIED

2

(continued)

5Schedule No. GRL

(continued)

Sheet of

RATES (continued)

Commodity Charge

GRL

These charges are for service as defined above and consist of: (1) the discounted monthly residential procurement charge, as described below; (2) the GT-RL transmission charges, as set forth in Schedule No. GT-RL; (3) the discounted San Juan Lateral interstate demand charge; and (4) the discounted procurement carrying cost of storage inventory charge.

The residential procurement charge is determined as set forth in Schedule No. G-CP, in the manner approved by D.96-08-037, and subject to change monthly as described in Special Condition 9. The procurement charge shown below has been discounted by 15 percent.

Baseline Rate


Procurement Charge: G-CPRL .......................................... 27.815¢Transmission Charge: GPT-RL .......................................... 20.744¢Commodity Charge: GRL ................................................ 48.559¢

Non-Baseline Rate


Procurement Charge: G-CPRL .......................................... 27.815¢Transmission Charge: GPT-RL .......................................... 36.031¢Commodity Charge: GRL ................................................ 63.846¢


RR

RR

30858-G

32587-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

RESIDENTIAL SERVICE, INCOME-QUALIFIED

3

(continued)

5Schedule No. GRL

(continued)

Sheet of

SPECIAL CONDITIONS




1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

3. In multi-family complexes where individual dwelling units receive natural gas service directly from the Utility through separate meters and where other residential services are provided from a separately metered central source, the applicable basic Baseline allowance for each such individually metered dwelling unit, subject to verification, will be as follows:



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823







RR

RR

RR

R | |R

RR

32145-G

32588-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONRESIDENTIAL SERVICE, INCOME-QUALIFIED

2

(continued)

5Schedule No. GT-RL

(continued)

Sheet of

RATES (continued)


GT-RL

This charge is equal to the discounted core commodity rate less the following four components as approved in D.97-04-082: (1) the discounted weighted average cost of gas; (2) the discounted core brokerage fee; (3) the discounted procurement carrying cost of storage inventory; and (4) the discounted San Juan Lateral interstate demand charge.

Baseline RateAll usage, per therm, under Special Condition 2and Special Condition 3 ............................................................... 20.503¢

Non-Baseline RateAll usage, per therm ..................................................................... 35.789¢

Billing Adjustments



SPECIAL CONDITIONS

1. Baseline Rates: Baseline Rates are applicable only to specific volumes of residential usage .

2. Baseline Usage: The following quantities of gas used in individually metered residences not in a multi-family complex are to be billed at the Baseline rate. Usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rate.


1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

R

R

RR

31191-G

32589-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONRESIDENTIAL SERVICE, INCOME-QUALIFIED

3

(continued)

5Schedule No. GT-RL

(continued)

Sheet of


3. In multi-family complexes where individual dwelling units receive natural gas service directly from SoCalGas through separate meters and where other residential services are provided from a separately metered central source, the applicable basic Baseline allowance for each such individually metered dwelling unit, subject to verification, will be as follows:



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823









RR

RR

R | |R

RR

32146-G

32590-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

SUBMETERED MULTI-FAMILY SERVICE, INCOME-QUALIFIED

1 6Schedule No. GSL

(continued)

Sheet of

APPLICABILITY

Applicable to natural gas service for multi-family dwelling units and mobile home parks supplied through one meter on a single premises and submetered to all individual units, supplied from the Utility's core portfolio, as defined in Rule No. 1. Eligibility for service hereunder is limited to income-qualified households that the meet the requirements for California Alternate Rates for Energy as defined in Rule No. 1 and Special Condition 9. This schedule is closed to new mobile home parks or manufactured housing communities for which construction has commenced after January 1, 1997.


The number of qualifying units is subject to verification by the Utility.

TERRITORY


RATES


Customer Charge

Per meter, per day ................................................................................... 13.973¢*



I

32464-G

32591-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

6Schedule No. GSL

(continued)

Sheet of

RATES (continued)

Minimum Charge (Per Meter Per Day)*

All customers except "space heating only" .............................................. 13.973¢"Space heating only" customers:

Beginning November 1 through April 30 ........................................... 28.177¢Beginning May 1 through October 31 ................................................ None

* Applicable if customer is not billed on Schedule No. GS.

Commodity Charge

GSL

These charges are for service as defined above and consist of: (1) the discounted monthly residential procurement charge, as described below; (2) the GT-SL transmission charges, as set forth in Schedule No. GT-SL; (3) the discounted San Juan Lateral interstate demand charge; and (4) the discounted procurement carrying cost of storage inventory charge.

The residential procurement charge is determined as set forth in Schedule No. G-CP, in the manner approved by D.96-08-037, and subject to change monthly as described in Special Condition 13. The procurement charge shown below has been discounted by 15 percent.

Baseline Rate


Procurement Charge: G-CPRL .......................................... 27.815¢Transmission Charge: GPT-SL ........................................... 20.744¢Commodity Charge: GSL ................................................. 48.559¢

Non-Baseline Rate


Procurement Charge: G-CPRL .......................................... 27.815¢Transmission Charge: GPT-SL ........................................... 36.031¢Commodity Charge: GSL ................................................. 63.846¢


RR

RR

30868-G*

32592-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

6Schedule No. GSL

(continued)

Sheet of

SPECIAL CONDITIONS




1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287








It is the responsibility of the owner or the owner's agent to demonstrate to the Utility's satisfaction the yardline configuration and the number of residential units served by the central facility. Eligibility for service under this provision is available subsequent to notification by the customer and verification by the Utility.

RR

32148-G

32593-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONSUBMETERED MULTI-FAMILY SERVICE, INCOME-QUALIFIED

1 6Schedule No. GT-SL

(continued)

Sheet of

APPLICABILITY

Applicable to transportation of customer-owned natural gas to multi-family dwelling units and mobile home parks supplied through one meter on a single premise and submetered to all individual units. The number of qualifying units is subject to verification by SoCalGas. Service under this schedule is available to customers that elect to purchase natural gas from ESPs in accordance with Rule No. 32. Eligibility for service under this schedule is limited to income-qualified households as defined for California Alternate Rates for Energy as defined in Rule No. 1 and Special Condition 8. This schedule is closed to new mobile home parks or manufactured housing communities for which construction has commenced after January 1, 1997.

TERRITORY


RATES


Customer Charge

Per meter, per day ........................................ 13.973¢*




I

32149-G

32594-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

6Schedule No. GT-SL

(continued)

Sheet of

RATES (continued)

Minimum Charge (Per Meter Per Day)*

All customers except "space heating only" ...................... 13.973¢"Space heating only" customers:

Beginning November 1 through April 30 ................... 28.177¢Beginning May 1 through October 31 ........................ None

* Applicable if customer is not billed on Schedule No. GS.


GT-SL


Baseline RateAll usage, per therm under Special Condition 2 ............................. 20.503¢

Non-Baseline RateAll usage, per therm ...................................................................... 35.789¢


Billing Adjustments

Billing adjustments may be necessary to reflect charges in volumes used in developing prior periods' transportation charges.

R

R

31195-G

32595-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

6Schedule No. GT-SL

(continued)

Sheet of

SPECIAL CONDITIONS




1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287








It is the responsibility of the owner or the owner's agent to demonstrate to SoCalGas' satisfaction the yardline configuration and the number of residential units served by the central facility. Eligibility for service under this provision is available subsequent to notification by the customer and verification by SoCalGas.

RR

32465-G

32596-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

SUMMER SAVER OPTIONAL RATEFOR OWNERS OF EXISTING GAS EQUIPMENT

2

(continued)

5Schedule No. GO-SSA

(continued)

Sheet of

RATES (continued)

Commodity Charges (continued)

The transmission charges are the GPT-R transmission charges for billing periods during the months of November through April. For billing periods for the months of May through October, the transmission charges are the GPT-R transmission charges for all usage less than or equal to the base year volume. Base volumes are the customer's volumes in the same billing period in the base year, the year prior to program sign-up. For non-baseline usage in the current year above base volumes in the billing period, the customer receives a SummerSaver credit equal to a discount of twenty cents ($0.20) per therm off the GPT-R non-baseline transmission charge.

The base year is defined as the 12 months preceding the beginning of the customer's participation in the SummerSaver optional rate program and remains unchanged as long as the customer is receiving service under this Schedule.

GO-SSA

Baseline Rate


Procurement Charge: G-CPR .............................................. 32.723¢Transmission Charge: GPT-R .............................................. 24.405¢Commodity Charge: GR .................................................... 57.128¢

Non-Baseline Rate



SummerSaver Rate

All non-baseline gas usage above base year volumes in billing periods from May to October will be discounted by 20 cents per therm. The discount be shown on the customer's bill as a credit.

RR

RR

31251-G

32597-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of

RATES (continued)

Minimum Charge

The minimum monthly charge shall consist of the Monthly Customer Charge.


SPECIAL CONDITIONS

1. Definitions of the principal terms used in this schedule are contained in Rule No. 1. Incremental non-baseline usage is defined as additional gas load above the base volume, the non-baseline usage in each billing period in the 12-month period prior to signing the Agreement. Base volumes remain unchanged as long as the customer remains on this Schedule.


3. Baseline Usage: The following quantities of gas used in individually metered residences not in a multi-family complex are to be billed at the Baseline rates. Usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates. Non-baseline usage in excess of base year non-baseline volumes will receive the SummerSaver credit for the months of May to October.


1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

4. In multi-family complexes where individual dwelling units receive natural gas service directly from the Utility through separate meters and where other residential services are provided from a separately metered central source, the applicable basic Baseline allowance for each such individually metered dwelling unit, subject to verification, will be as follows. Usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates. Non-baseline usage in excess of base year non-baseline volumes will receive the SummerSaver credit for the months of May to October.



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823

2 Water heating and cooking 0.460 0.460 0.460


RR

RR

31252-G

32598-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of




3 Cooking, water heatingand space heating

Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287






6. The Utility will file core procurement rate changes on or before the fifth business day of each month, with the rates to become effective for service one business day thereafter.

7. The customer may cancel participation within 72 hours of submission of the request to participate in the SummerSaver optional rate program.

8. As a condition precedent to service under this schedule, an executed Optional Rate Program Application and Agreement shall be required.

9. All contracts, rates, and conditions are subject to revision and modification as a result of CPUC order.

10. The contract term for service under this rate schedule shall be for four years, but the customer or the utility may terminate participation by at any time with 30 days notice.

11. Unless otherwise stated in this Schedule and Agreement, all other conditions of Schedule No. GR shall remain in effect.

RR

R | |R

RR

32151-G

32599-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSPORTATION-ONLY SUMMER SAVER OPTIONAL RATEFOR OWNERS OF EXISTING GAS EQUIPMENT

2

(continued)

5Schedule No. GTO-SSA

(continued)

Sheet of

RATES (continued)


The transmission charges are the GT-R transmission charges for billing periods during the months of November through April. For billing periods for the months of May through October, the transmission charges are the GT-R transmission charges for all usage less than or equal to the base year volume. Base volumes are the customer's volumes in the same billing period in the base year, the year prior to program sign-up. For non-baseline usage in the current year above base volumes in the billing period, the customer receives a SummerSaver credit equal to a discount of twenty cents ($0.20) per therm off the GT-R non-baseline transmission charge.


GTO-SSA

Baseline RateAll usage, per therm, under Special Conditions 3 and 4 ................... 24.121¢

Non-Baseline RateAll usage, per therm ....................................................................... 42.105¢

SummerSaver RateAll non-baseline gas usage above base year volumes in billing periods from May to October will be discounted by 20 cents per therm. The discount be shown on the customer's bill as a credit.

Billing Adjustments



SPECIAL CONDITIONS


R

R

31256-G

32600-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSPORTATION-ONLY SUMMER SAVER OPTIONAL RATEFOR OWNERS OF EXISTING GAS EQUIPMENT

3

(continued)

5Schedule No. GTO-SSA

(continued)

Sheet of





1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287




Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823







RR

RR

RR

R | |R

RR

32466-G

32601-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

SUMMER SAVER OPTIONAL RATEFOR CUSTOMERS PURCHASING NEW GAS EQUIPMENT

OR REPAIRING INOPERABLE EQUIPMENT

2

(continued)

5Schedule No. GO-SSB

(continued)

Sheet of

RATES (continued)



GO-SSB

Baseline Rate



Non-Baseline Rate



SummerSaver Rate


Minimum Charge



RR

RR

31261-G

32602-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED



3

(continued)


(continued)

Sheet of

SPECIAL CONDITIONS





1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287




Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823




RR

RR

RR

31262-G

32603-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED



4

(continued)


(continued)

Sheet of










7. The customer may cancel participation within 72 hours of submission of the request to participate in the SummerSaver optional rate program.

8. As a condition precedent to service under this schedule, an executed SummerSaver Program Application and Agreement shall be required. As part of the Agreement, the customer certifies that he qualifies under the terms and conditions of this Schedule.




R | |R

RR

32153-G

32604-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSPORTATION-ONLY SUMMER SAVER OPTIONAL RATEFOR CUSTOMERS PURCHASING NEW GAS EQUIPMENT


2

(continued)

5Schedule No. GTO-SSB

(continued)

Sheet of

RATES (continued)

GTO-SSB

Baseline RateAll usage, per therm, under Special Conditions 3 and 4 ................... 24.121¢

Non-Baseline RateAll usage, per therm ...................................................................... 42.105¢

SummerSaver RateAll non-baseline gas usage above base year volumes in billing periods from May to October will be discounted by 20 cents per therm. The discount be shown on the customer's bill as a credit.

Billing Adjustments



SPECIAL CONDITIONS

1. Definitions of the principal terms used in this schedule are contained in Rule No. 1. Incremental non -baseline usage is defined as additional gas load above the base volume, the non-baseline usage in each billing period in the 12-month period prior to signing the Agreement. Base volumes remain unchanged as long as the customer remains on this Schedule.

2. Baseline Rates: Baseline Rates are applicable only to specific volumes of residential usage .



1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

R

R

RR

31582-G

32605-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSPORTATION-ONLY SUMMER SAVER OPTIONAL RATEFOR CUSTOMERS PURCHASING NEW GAS EQUIPMENT


3

(continued)

5Schedule No. GTO-SSB

(continued)

Sheet of





Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823








6. Customers may make service arrangements through an Aggregator, as defined in Rule No. 1, and as provided for in Rule No. 32.

7. As a condition precedent to service under this schedule, a Core Aggregation Transportation Authorization (Form No. 6568-A) executed prior to the implementation of D.98-02-108 or a Direct Access Service Request (DASR) submitted by an ESP pursuant to D.98-02-108 is required.

RR

RR

R | |R

RR

32467-G

32606-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

OPTIONAL RATEFOR CUSTOMERS PURCHASING

NEW GAS AIR CONDITIONING EQUIPMENT

2

(continued)

5Schedule No. GO-AC

(continued)

Sheet of

RATES (continued)


GO-AC

Baseline Rate

All usage, per therm, under Special Condition 2.


Non-Baseline Rate



Gas AC Rate (May through October)


Minimum Charge



SPECIAL CONDITIONS

1. Definitions of the principal terms used in this schedule are contained in Rule No. 1. Incremental usage is defined as additional gas load above the base volume, the usage based on average residential daily non-temperature sensitive load.

RR

RR

31275-G

32607-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED



3

(continued)

5Schedule No. GO-AC

(continued)

Sheet of


2. Baseline Rates: Baseline rates are applicable only to specific volumes of residential usage. Gas AC Rates: Gas AC rates are applicable only to volumes in excess of base amounts: 0.917 therms per day for single family dwellings, and 0.722 therms per day for multi-family dwellings.

3. Baseline Usage: The following quantities are to be billed at the Baseline rates. All winter usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates. Summer usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates until the base volume level is reached. Usage in excess of base volumes will receive the Gas AC credit for the months of May through October.


1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

4. In multi-family complexes where individual dwelling units receive natural gas service directly from the Utility through separate meters and where other residential services are provided from a separately metered central source, the applicable basic Baseline allowance for each such individually metered dwelling unit, subject to verification, will be as follows. All winter usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates. Summer usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates until the base volume level is reached. Usage in excess of base volumes will receive the Gas AC credit for the months of May through October.



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823





RR

RR

RR

RR

31276-G

32608-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED



4

(continued)

5Schedule No. GO-AC

(continued)

Sheet of









7. The customer may cancel participation within 72 hours of submission of the request to participate in the Gas AC optional rate program.

8. As a condition precedent to service under this schedule, an executed Gas AC Agreement shall be required. As part of the Agreement, the customer certifies that he qualifies under the terms and conditions of this Schedule.




RR

RR

32155-G

32609-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSPORTATION-ONLY OPTIONAL RATEFOR CUSTOMERS PURCHASING


2

(continued)

5Schedule No. GTO-AC

(continued)

Sheet of

RATES (continued)

Transmission Charges (continued)

GTO-AC

Baseline Rate

All usage, per therm, under Special Condition 3 .............................. 24.121¢

Non-Baseline Rate

All usage, per therm ....................................................................... 42.105¢

Gas AC Rate (May through October)


Billing Adjustments



SPECIAL CONDITIONS

1. Definitions of the principal terms used in this schedule are contained in Rule No. 1. Incremental usage is defined as additional gas load above the base volume, the usage based on average residential daily non-temperature sensitive load.

2. Baseline Rates: Baseline rates are applicable only to specific volumes of residential usage. Gas AC Rates: Gas AC rates are applicable only to volumes in excess of base amounts: 0.917 therms per day for single family dwellings, and 0.722 therms per day for multi-family dwellings.

R

R

31280-G

32610-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED



3

(continued)


(continued)

Sheet of


3. Baseline Usage: The following quantities are to be billed at the Baseline rates. All winter usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates. Summer usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates until the base volume level is reached. Usage in excess of base volumes will receive the Gas AC credit for the months of May through October.


1 2 3Summer 0.457 0.457 0.457Winter 1.624 1.956 2.287

4. In multi-family complexes where individual dwelling units receive natural gas service directly from the Utility through separate meters and where other residential services are provided from a separately metered central source, the applicable basic Baseline allowance for each such individually metered dwelling unit, subject to verification, will be as follows. All winter usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates. Summer usage in excess of applicable Baseline allowances will be billed at the Non-Baseline rates until the base volume level is reached. Usage in excess of base volumes will receive the Gas AC credit for the months of May through October.



Summer 0.000 0.000 0.000Winter 1.160 1.492 1.823





RR

RR

RR

RR

31585-G

32611-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED



4

(continued)


(continued)

Sheet of










8. If the customer and the ESP have met all of the requirements set forth in Rule No. 32, service will be effective in accordance with the schedule established in Rule No. 32.

9. All provisions of Rule No. 32, Core Aggregation Transportation, shall apply to customers receiving service under this schedule.

10. All terms and conditions of Rule No. 30 shall apply to the transportation of customer-owned gas under this schedule.

11. Transportation Imbalance Service shall be provided to the customer's Aggregator under Schedule No. G-IMB.

12. Customers with multiple facilities (under the same customer name) whose total requirements are at least 250,000 therms per year may participate in the Program, but must designate a single account under which charges for imbalance services are to be billed.

RR

RR

32468-G

32612-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

STREET AND OUTDOOR LIGHTINGNATURAL GAS SERVICE

1 2Schedule No. GL

(continued)

Sheet of

APPLICABILITY

Applicable to natural gas service supplied from the Utility's core portfolio, as defined in Rule No. 1, for continuous street and outdoor lighting in lighting devices approved by the Utility. Service under this schedule is conditional upon arrangements mutually satisfactory to the customer and the Utility for connection of customer's lighting devices to Utility's facilities.


TERRITORY


RATES

The charges are based upon the monthly non-residential procurement charge as set forth in Schedule No. G-CP; and the GN-10 class average transportation rate.

The non-residential procurement charge is determined as set forth in Schedule No. G-CP, in the manner approved by D.96-08-037, and subject to change monthly as described in Special Condition 3.

Rate "X" Lighting only serviceCharge

Per Lamp Per Month($)

Hourly Lamp Rating in Cu.Ft.1.99 cu.ft. per hr. or less .................................................................... 8.902.00 - 2.49 cu.ft. per hr ..................................................................... 10.082.50 - 2.99 cu.ft. per hr ..................................................................... 12.323.00 - 3.99 cu.ft. per hr ..................................................................... 15.684.00 - 4.99 cu.ft. per hr ..................................................................... 20.165.00 - 7.49 cu.ft. per hr ..................................................................... 28.007.50 - 10.00 cu.ft. per hr .................................................................... 39.20For each cu.ft. per hour of total

capacity in excess of 10 cu.ft. per hour ........................................... 4.48

R | | | | |R

R

29361-G

32613-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE SERVICE FOR SMALL COMMERCIAL AND INDUSTRIAL

1 5Schedule No. GN-10

(continued)

Sheet of

APPLICABILITY

Applicable to non residential natural gas service not provided under any other rate schedule.


TERRITORY


RATES

Customer Charge

Per meter, per day:

Annual usage of less than 1,000 therms per year:

All customers except "space heating only" ............................................... 32.877¢*"Space heating only" customers:

Beginning December 1 through March 31 .......................................... $0.99174*Beginning April 1 through November 30 ............................................ None

Annual usage of 1,000 therms per year or more:

All customers except "space heating only" ............................................... 49.315¢*"Space heating only" customers:

Beginning December 1 through March 31 ........................................... $1.48760*Beginning April 1 through November 30 ............................................. None

* The applicable monthly charge shall be determined on the basis of the customer's GN-10 usage for the most recent twelve-month period. For customers with less than twelve months of historical usage, the customer charge shall be determined on a pro rata basis using the months for which usage is available.

The term "space heating only" applies to customers who are using gas primarily for space heating for human comfort as determined by survey or under the presumption that customers who use less than 11 therms per month during each of the regular billing periods ending in August and September are using gas primarily for space heating for human comfort. Except for closing bills or at the time of a rate increase, usage will be accumulated to at least 20 therms before billing.

T

D

N

N | |N

N

T | |T

N | |ND

TTL

T

29361-G & 32469-G

32614-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

5Schedule No. GN-10

(continued)

Sheet of

RATES (continued)

Minimum Charge

Per meter, per day:



Beginning December 1 through March 31 .......................................... $0.99174Beginning April 1 through November 30 ........................................... None



Beginning December 1 through March 31 ......................................... $1.48760Beginning April 1 through November 30 ........................................... None

Commodity Charges

GN-10

These charges are for service as defined above and consist of: (1) the monthly non-residential procurement charge as set forth in Schedule No. G-CP; (2) the GT-10 transmission charges, as set forth in Schedule No. GT-10; (3) the San Juan Lateral interstate demand charge; and (4) the procurement carrying cost of storage inventory charge.


Tier I Rate, per therm, for the first 100 therms used during summer months and the first 250 therms used during winter months.

Procurement Charge: G-CPNR .......................................... 32.723¢Transmission Charge: GPT-10 ........................................... 38.280¢Commodity Charge: GN-10 ............................................. 71.003¢

L

L

N

N | |N

N

L | |L

RRL

T

32469-G & 32470-G

32615-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

5Schedule No. GN-10

(continued)

Sheet of

RATES (continued)


GN-10 (continued)

Tier II Rate, per therm, for usage above Tier I quantities and up to 4167 therms per month.


Tier III Rate, per therm, for all usage above 4167 therms per month.


GN-10V

These charges are for service as defined above for those customers who are located in the City of Vernon, as defined in Special Condition 6. The charges consist of: (1) the monthly non-residential procurement charge as set forth in Schedule No. G-CP; (2) the GT-10V transmission charges, as set forth in Schedule No. GT-10; (3) the San Juan Lateral interstate demand charge; and (4) the procurement carrying cost of storage inventory charge.



Procurement Charge: G-CPNR ......................................... 32.723¢Transmission Charge: GPT-10V ....................................... 38.280¢Commodity Charge: GN-10V ......................................... 71.003¢


Procurement Charge: G-CPNR ......................................... 32.723¢Transmission Charge: GPT-10V ........................................ 19.778¢Commodity Charge: GN-10V .......................................... 52.501¢

L

LL,RL,R

L

LL,RL,R

RR

RRL

T

32470-G & 31023-G

32616-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

5Schedule No. GN-10

(continued)

Sheet of

RATES (continued)


GN-10V (continued)


Procurement Charge: G-CPNR ......................................... 32.723¢Transmission Charge: GPT-10V ........................................ 10.007¢Commodity Charge: GN-10V .......................................... 42.730¢

Under this schedule, the winter season shall be defined as December 1 through March 31 and the summer season as April 1 through November 30.


SPECIAL CONDITIONS

1. Definitions of the principal terms used in this schedule are contained in Rule No. 1.

2. Customer may receive service under this schedule (a) separately, or (b) in combination with another rate schedule(s) through a single meter installation. Where service is rendered under (b), a separate monthly customer charge shall be applicable for service under each schedule unless otherwise stated.

3. In the event of curtailment, customers under this schedule will be curtailed in accordance with Rule No. 23, Continuity of Service and Interruption of Delivery.

4. Customers served hereunder may elect to be reclassified as noncore. Eligibility requirements are defined in Rule No. 1. Customers electing noncore service status must sign the required natural gas service agreement and have electronic meter reading equipment installed at the customers expense as a condition of noncore service.

5. Customer receiving service under this rate schedule may elect to aggregate their gas quantities to receive service under Schedule No. GT-10.

6. The rate savings afforded customers under Schedule No. GN-10V shall only apply to those customers served under this schedule and located within the City of Vernon consistent with the SoCalGas-Vernon Stipulation and Settlement Agreement approved by D. 96-09-104. In addition, the Utility may negotiate rates other than those set forth herein for those customers located in the City of Vernon and served under this rate schedule, pursuant to the Agreement and D.96-09-104.

L

LL,RL,R

L | |L

T,NN |N

L

T

31023-G

32617-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

5Schedule No. GN-10

Sheet of


7. The minimum term for service hereunder is one month, except when a customer has ended service under the Core Aggregation Transportation program and elects to return to Utility procurement service, in which event the minimum term is one year, and then month-to-month thereafter, unless the customer executes an authorization form with another aggregator within the 90-day interim period pursuant to Rule No. 32, Section B.4.b.

8. The Utility will file core procurement rate changes on the last business day of each month to become effective on the first calendar day of the following month.

9. In the event customers make any material change, either in the amount or character of their gas appliances or equipment, written notice to the Utility must be made in accordance with Rule No. 29, Change of Customer's Apparatus or Equipment.

10. If the customer splits its gas requirements between service under this schedule and noncore service under Schedule Nos. G-CS, GT-F, and/or GT-I, the customer shall be required to specify a fixed monthly quantity for service hereunder by month for the term of the customer's contract.

L | | | | | |L

N |N

N |N

T

29979-G

32618-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATIONFOR CORE COMMERCIAL AND INDUSTRIAL SERVICE

1 6Schedule No. GT-10

(continued)

Sheet of

APPLICABILITY

Applicable to non residential Core Transportation Service in accordance with Rule 32. Also applicable for use at each non-residential core facility classified in Rule 23 as priority 2A that elect the optional large core transportation service in accordance with Rule 30.

TERRITORY


RATES

Customer Charge

Per meter, per day:


All customers except "space heating only" ................................................ 32.877¢*"Space heating only" customers:

Beginning December 1 through March 31 ......................................... $0.99174*Beginning April 1 through November 30 ........................................... None


All customers except "space heating only" ................................................ 49.315¢*"Space heating only" customers:

Beginning December 1 through March 31 ........................................... $1.48760*Beginning April 1 through November 30 ............................................. None

If the applicable customer charge is collected under another rate schedule, no duplicate charge is collected hereunder.

* The applicable monthly charge shall be determined on the basis of the customer's GT-10 usage for the most recent twelve-month period. For customers with less than twelve months of historical usage, the customer charge shall be determined on a pro rata basis using the months for which usage is available.

T,NNN

D

N | |N

T | |T

N | |NDL

T

29979-G & 32159-G

32619-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

6Schedule No. GT-10

(continued)

Sheet of

RATES (continued)

Customer Charge (continued)


Minimum Charge

Per meter, per day:


All customers except "space heating only" .............................................. 32.877¢*"Space heating only" customers:

Beginning December 1 through March 31 ......................................... $0.99174*Beginning April 1 through November 30 .......................................... None



Beginning December 1 through March 31 ........................................ $1.48760*Beginning April 1 through November 30 .......................................... None


Core Aggregation Transportation Service

GT-10


L |LL,TL,T

L

L

N

N | |N

N

L | |L

T

L

T

32159-G

32620-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

6Schedule No. GT-10

(continued)

Sheet of

RATES (continued)


Core Aggregation Transportation Service (continued)

GT-10 (continued)

Rate, per therm

Tier I* ................................................................................... 37.996¢

Tier II* .................................................................................. 22.671¢

Tier III* ................................................................................. 9.723¢

* Tier I quantities shall be the first 100 therms used during summer months and the first 250 therms used during winter months. Tier II quantities shall be for usage above Tier I quantities and up to 4167 therms per month. Tier III quantities shall be for all usage above 4167 therms per month.

Optional Large Core Transportation Service

GT-10N

These charges are equal to the GT-10 rates above for Core Aggregation Transportation Service, less SoCalGas' embedded interstate pipeline demand charges allocated to the core.

Rate, per therm

Tier I* ............................................................................... 34.497¢

Tier II* .............................................................................. 19.172¢

Tier III* ............................................................................. 6.224¢


L

L,R

L,R

L,R

L||L

N | | | | | | | | | | | | | | | | |NL

T

32159-G & 32160-G

32621-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

6Schedule No. GT-10

(continued)

Sheet of

RATES (continued)


City of Vernon

GT-10V

This charge is for customers as defined above and located within the City of Vernon, as defined in Special Condition 14. This charge is equal to the core commodity rate less the following four components as approved in D.97-04-082: (1) the weighted average cost of gas; (2) the core brokerage fee; (3) the procurement carrying cost of storage inventory; and (4) the San Juan Lateral interstate demand charge; and also less an amount to implement the SoCalGas-Vernon Stipulation and Settlement Agreement approved by D. 96-09-104.

Rate, per therm

Tier I* ................................................................................... 37.996¢

Tier II* .................................................................................. 19.494¢

Tier III* ................................................................................. 9.723¢




Billing Adjustments


Rates may be adjusted to reflect any applicable taxes, franchise or other fees, regulatory surcharges, and interstate or intrastate pipeline charges that may occur.

L | | | | | | | |L

R

R

R

NNL

T

32160-G & 29980-G

32622-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

6Schedule No. GT-10

(continued)

Sheet of

SPECIAL CONDITIONS


2. Customers may receive service under this schedule (a) separately, or (b) in combination with another rate schedule(s) through a single meter installation. Where service is rendered under (b), a separate monthly customer charge shall may be applicable for service under each schedule unless otherwise stated.


4. Customers served hereunder may elect to be reclassified as noncore. Eligibility requirements are defined in Rule No. 1. Customers electing noncore status must sign the required natural gas service agreement and have electronic meter reading equipment installed at customer's expense as a condition of noncore service.

5. Customers may make service arrangements through an aggregator or ESP, as defined in Rule No. 1, and as provided for in Rule No. 32. Customers consuming 250,000 therms per year or more may make service arrangements either with a core aggregator pursuant to Rule Nos. 30 and 32 or a marketer/shipper pursuant to Rule Nos. 30 and 35.

6. Customers electing optional large core transportation service, GT-10N, shall be required to sign a service contract. The contract term for service under this schedule shall be a minimum of 30 days. After the initial 30-day term, the contract will continue on a month-to-month basis until terminated by either party on 15 day's written notice.

7. All provisions of Rule No. 32, Core Transportation Service, shall apply to customers receiving service through an aggregator under this schedule.


9. Transportation Imbalance Service shall be provided to the customer, the customer's ESP or marketer/shipper under Schedule No. G-IMB.

10. Customers with multiple facilities (under the same customer name) who comply with provisions for becoming an ESP may participate as an ESP, but must designate a single account under which charges for imbalance services are to be billed.

L | | | | | | | | |L

L,TL,NNN

TN |NDN | |N

T

T

T

T

L

T

29980-G

32623-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)

6Schedule No. GT-10

Sheet of


11. In the event the ESP or marketer/shipper defaults on any payments to SoCalGas, the ESP's or marketer/shipper's customers shall be responsible for SoCalGas' billings, excluding any Procurement Management Charges, as defined in Rule No. 1, regardless of any billing arrangements the customer has with the ESP, marketer/shipper, or any third parties.

12. SoCalGas shall continue to read customer meters, send customers legally required notices and bill inserts pursuant to Public Utilities Code 454(a), and provide customers with all other regular SoCalGas services. This includes direct billing, unless the customer specifies in the Core Aggregation Transportation Authorization (Form No. 6568-A), executed prior to the implementation of D.98-02-108, or in the electronic Service Request DASR effective with the implementation of D.98-02-108, that SoCalGas bill the ESP or marketer/shipper for all charges.

13. The rate savings afforded customers under Schedule No. GT-10V shall only apply to those customers served under this schedule and located within the City of Vernon, consistent with the SoCalGas-Vernon Stipulation and Settlement Agreement approved by D. 96-09-104. In addition, SoCalGas may negotiate rates other than those set forth herein for those customers located in the City of Vernon and served under this rate schedule, pursuant to the Agreement and D. 96-09-104.

14. Customers having existing gas exchange arrangements with SoCalGas must exchange the maximum amount of gas allowable under those arrangements prior to the delivery of customer-owned natural gas to SoCalGas for transportation, unless otherwise agreed to by SoCalGas.

15. In the event customers make any material change, either in the amount or character of their gas appliances or equipment, written notice thereof must be made to SoCalGas in accordance with Rule No. 29, Change of Consumer's Apparatus or Equipment.

16. If the customer splits its gas requirements between service under this schedule and noncore service under Schedule Nos. G-CS, GT-F, and/or GT-I, the customer shall be required to specify a fixed monthly quantity for service hereunder by month for the term of the customer's contract.

17. As a condition of transportation service under this schedule, the customer or its ESP or marketer/shipper shall be required to take assignment of the interstate capacity reserved by SoCalGas on the customer's behalf in accordance with the provisions of Rule No. 36. The customer or its ESP or marketer/shipper shall be required to execute the necessary contracts with the applicable interstate pipelines and shall ultimately be held financially responsible to SoCalGas for all applicable pipeline demand charges, at the full as-billed rate, associated with the customer's reserved capacity. In the event the customer or its ESP or marketer/shipper does not qualify for and take full assignment of the interstate pipeline capacity reserved by SoCalGas on the customer's behalf, the customer or its ESP or marketer/shipper shall not qualify for transportation service and shall be served under the applicable SoCalGas sales service schedule.

L,TL | | | | | | | | | | | | | |L

N | | | | | | | | | | | | | | | | | | | |N

T

29369-G

32624-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE COMMERCIAL AND INDUSTRIAL SERVICE, INCOME-QUALIFIED

1 9Schedule No. GN-10L

(continued)

Sheet of

APPLICABILITY

Applicable to natural gas core service, as defined in Rule No. 1, for uses at each Facility classified in Rule No. 23 as Priority 1, with usage not exceeding 250,000 therms per year (or 20,800 therms per month during the season when gas is used).

Eligibility for service hereunder is limited to Nonprofit Group Living Facilities and Qualified Agricultural Employee Housing Facilities (migrant farmworker housing centers, privately-owned employee housing, and agricultural employee housing operated by nonprofit entities) that meet the income requirements for California Alternate Rates for Energy as defined in Rule No. 1, and Special Conditions 7 and 8. Eligibility information provided by the Applicant is subject to verification by the Utility.


TERRITORY


RATES

Customer Charge

Per meter, per day:


All customers except "space heating only" ............................................. 27.945¢*"Space heating only" customers:



All customers except "space heating only".............................................. 41.918¢*"Space heating only" customers:

Beginning December 1 through March 31 ....................................... $1.26446*Beginning April 1 through November 30 ......................................... None

D

DDN

N | |N

N

T | |TL

T

29369-G

32625-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

9Schedule No. GN-10L

(continued)

Sheet of

RATES (continued)


* The applicable monthly customer charge shall be determined on the basis of the customer's GN-10L usage for the most recent twelve-month period. For customers with less than twelve months of historical usage, the customer charge shall be determined on a pro rata basis using the months for which usage is available.


Minimum Charge

Per meter per day:



Beginning December 1 through March 31 .......................................... $0.84297Beginning April 1 through November 30 ............................................ None



Beginning December 1 through March 31 .......................................... $1.26446Beginning April 1 through November 30 ............................................ None

N | |N

L |LL,TT

N

N | |N

N

T | |T

T

32471-G

32626-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of

RATES (continued)

Commodity Charges

GN-10L

These charges are for service as defined above and consist of(1) the discounted monthly non-residential procurement charge, as described below; (2) the GT-10L transmission charges, as set forth in Schedule No. GT-10L; (3) the discounted San Juan Lateral interstate demand charge; and (4) the discounted procurement carrying cost of storage inventory charge.

The non-residential procurement charge is determined as set forth in Schedule No. G-CP, in the manner approved by D.96-08-037, and subject to change monthly as described in Special Condition 6. The procurement charge shown below has been discounted by 15 percent.


Procurement Charge: G-CPNRL .......................................... 27.815¢Transmission Charge: GPT-10L ........................................... 32.538¢Commodity Charge: GN-10L ............................................. 60.353¢


Procurement Charge: G-CPNRL .......................................... 27.815¢Transmission Charge: GPT-10L ............................................ 19.511¢Commodity Charge: GN-10L .............................................. 47.326¢


Procurement Charge: G-CPNRL .......................................... 27.815¢Transmission Charge: GPT-10L ............................................ 8.506¢Commodity Charge: GN-10L .............................................. 36.321¢



RR

RR

RR

T

31024-G

32627-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of

SPECIAL CONDITIONS

GENERAL



3. Customers served hereunder may be reclassified as noncore by way of economic practicality, as defined in Rule No. 1.

4. Customers receiving service under this schedule may elect to aggregate their gas quantities to receive service under Schedule No. GT-10L.

5. The minimum term for service hereunder is one month, except when a customer has ended service under the Core Aggregation Transportation program and elects to return to Utility procurement service, in which event the minimum term is one year, and then month-to-month thereafter, unless the customer executes an authorization form with another aggregator within the 90-day interim period pursuant to Rule No. 32, Section B.4.b.

6. The Utility will file core procurement rate changes on the last business day of each month to become effective on the first calendar day of the following month.

NONPROFIT GROUP LIVING FACILITIES

7. The Utility shall offer the CARE discount to facilities that qualify as follows:

a. Facility Eligibility Requirements: The CARE discount shall apply to nonprofit group living facilities and non-licensed, separately metered affiliated facilities such as homeless shelters, women's shelters, transitional housing (e.g., for drug rehabilitation, a half-way house, etc.), short- or long-term care facility (hospice, nursing homes, seniors' or children's homes), a group home for physically or mentally disabled persons, or nonprofit residential facility whose construction was government subsidized and meets all other applicable criteria. Student housing/dorms, military barracks, fraternities/sororities, government-owned and privately-owned "for profit" government-subsidized housing are excluded. The exclusion of government-owned and government-subsidized housing does not apply to homeless shelters.

The discount shall apply to non-licensed, separately metered affiliates of qualifying nonprofit group facilities so long as the customer of record is the qualifying nonprofit facility.

T

31510-G

32628-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


(continued)

Sheet of


NONPROFIT GROUP LIVING FACILITIES (continued)

7. (continued)

a. Facility Eligibility Requirements (continued)

Each resident (100%) must meet the CARE income-eligibility standards for a single-person household for the facility or the non-licensed, separately metered facility to qualify under this schedule. A caregiver who lives in the facility is not a resident for purposes of determining eligibility. At least 70% of the energy consumed on the CARE rate must be used for residential purposes.

The Utility shall require the facility to provide a copy of its IRS Nonprofit Tax ID Form 501(c)(3), and state business license, conditional use permit or any other proof satisfactory to the Utility. Facilities that have been qualified by the Utility under self-certification or self-recertification and are receiving the rate discount may be subject to random post-enrollment verification by the Utility.

An authorized representative of the facility shall sign Form No. 6571 certifying that any savings derived from the discount shall be used for the direct benefit of the residents. Such direct benefit may be in the form of improved quality of care or improved food services.

Customers who are found to be ineligible or fail to timely notify the Utility when they no longer qualify for the rate discount may be subject to corrective rebilling under the appropriate rate schedule.

Upon completion of Form No. 6571 and acceptance, eligible facilities or their affiliates shall receive the discount commencing with the next regularly scheduled bill.

b. Residents' Income-Eligibility Requirements: The total annual household income (from all sources (taxable and non-taxable) shall not be more than $17,700 for each resident of the facility, and the resident shall not be claimed on another person's income tax return.

The owner or authorized representative of the facility shall notify the Utility within 30 days following any change that may impact the facility's eligibility for the discount.

T

31511-G

32629-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)


(continued)

Sheet of



7. (continued)

c. Self-Certification and Self-Recertification Requirements: Nonprofit group living facilities must provide proof of the appropriate state license to care for residents who, either temporarily or permanently, cannot function normally outside of the group home environment and certification from the appropriate state agency showing what services, besides lodging, are provided or any other documentation the Utility may reasonably require. Primary facilities must meet the licensing and certification requirements, but not their separately-metered affiliated facilities.

Homeless shelters must provide verification that at least six (6) beds each day or night are provided during a minimum 180 days each year for persons who have no alternate residence, and must provide proof of a valid municipal or county conditional-use permit or any other documentation the Utility may reasonably require. Nonprofit group living facilities are not required to be licensed or certified.

d. Self-Recertification Requirements: Facilities will be required to recertify on an annual basis. At the time of each annual self-recertification, the Utility shall require the facility to certify how it intends to pass on the rate discount.

e. Random Post-Enrollment Verification: The self-certification and self-recertification applications for CARE benefits, and certification of the flow-through of the rate discount, shall be made under penalty of perjury by the same individual who is responsible for the annual renewal of the facility's license from the appropriate state agency, when applicable. The accuracy of the self-certification or self-recertification applications may be subject to random post-enrollment verification by the Utility .

QUALIFIED AGRICULTURAL EMPLOYEE HOUSING FACILITIES

8. The Utility shall offer the CARE discount to migrant farmworker housing centers; privately-owned employee housing, or agricultural employee housing operated by nonprofit entities that qualify as follows:

a. Facility Eligibility Requirements:

(1) Migrant Farmworker Housing Centers: The CARE discount shall apply to housing provided pursuant to Section 50710 of the Health and Safety Code. For facilities with individually-metered usage, all usage (100%) must be residential. For master-metered facilities, at least 70% of the energy consumed on the CARE rate must be used for residential purposes.

T

31512-G

32630-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)


(continued)

Sheet of


QUALIFIED AGRICULTURAL EMPLOYEE HOUSING FACILITIES (continued)

8. (continued)

a. Facility Eligibility Requirements: (continued)

(2) Privately-Owned Employee Housing: The CARE discount shall apply to housing conforming to Section 17008 of the Health and Safety Code (the Employee Housing Act), that is licensed and inspected by state and/or local agencies pursuant to Part I (commencing with Section 17000) of Division 13. Energy usage in all facilities (100%) must be residential and individually metered.

(3) Nonprofit Agricultural Employee Housing: The CARE discount shall apply to housing conforming to Subdivision (b) of Section 1140.4 of the Labor Code, that has an exemption from local property taxes pursuant to subdivision (g) of Section 214 of the Revenue and Taxation Code. For facilities with individually-metered usage, all usage (100%) must be residential. For master-metered facilities, at least 70% of the energy consumed on the CARE rate must be used for residential purposes.

Employees operating and/or managing the facility who live in the facility are not considered residents for purposes of determining eligibility.

Energy used by offices, maintenance shops, or agriculture is not residential. Only residential and commercial usage, in the proportions defined above, qualifies for this rate.

The Applicant must be the customer of record for the facility. The Applicant is responsible for determining that each resident household meets the applicable income-eligibility standards. The Applicant must attest to this on Form No. 6632, under penalty of perjury.

An authorized representative of the facility shall sign Form No. 6632 certifying that any savings derived from the discount shall be used for the direct benefit of the residents. Such direct benefit may be in the form of improved quality of care or improved food services, reduced rent or result in no rent of increase in rent or a reduced rate of increase in rent .


Facilities that have been qualified by the Utility under self-certification or self-recertification and are receiving the rate discount may be subject to random post-enrollment verification by the Utility.

T

31513-G

32631-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)


(continued)

Sheet of



8. (continued)

a. Facility Eligibility Requirements: (continued)

Customers who are found to be ineligible or fail to timely notify the Utility when they no longer qualify for the rate discount may be subject to corrective rebilling under the appropriate rate schedule.

b. Income-Eligibility Requirements for Resident Households: An income-qualified household has total annual income from all sources (taxable and non-taxable) that is no more than shown in the table below for the number of persons in the household.

Number of Persons Total Annual In Household Household Income

1 or 2 $17,7003 $20,9004 $25,1005 $29,3006 $33,5007 $37,700

For households with more than seven persons, add $4,200 annually for each additional person living in the household.

No person claimed on another person's income tax return shall be eligible for this rate.

The owner or authorized representative of the facility shall notify the Utility within 30 days following any change that may impact the facility's eligibility for the discount.

c. Self-Certification and Self-Recertification Requirements: The Applicant must also provide copies of the following:

(1) Migrant Farmworker Housing Centers: the facility's current contract with the Office of Migrant Services, Department of Housing and Community Development.

(2) Privately-Owned Employee Housing: a valid permit or license issued to the facility pursuant to Section 17030 of the Health and Safety Code.

T

31514-G

32632-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


9

(continued)


Sheet of



8. (continued)

c. Self-Certification and Self-Recertification Requirements: (continued)

(3) Nonprofit Agricultural Employee Housing: the facility's IRS Nonprofit Tax ID Form 501(c)(3), and proof of the facility's local property tax exemption from the County Assessor where the facility is located.

In the initial application, the facility must attest to how it intends to pass on the rate discount for the direct benefit of the facility's residents in the upcoming year.

d. Self-Certification and Self-Recertification Requirements: Facilities will be required to recertify on an annual basis. At the time of each annual self-recertification, the Utility shall require that the facility certify: (1) how it passed on the rate discount in the prior year, and (2) how it intends to pass on the rate discount in the upcoming year. An Applicant must show that a direct benefit was conferred on the facility's residents by demonstrating where the savings from the CARE rate will or has been reallocated.

The Applicant must provide documentation showing how the CARE rate was used to directly benefit the facility's residents. Such supporting documentation includes, but is not limited to, accounting entries, dated receipts, and memoranda and letters to the residents describing the benefits conferred.

e. Random Post-Enrollment Verification: The self-certification and self-recertification applications for CARE benefits, and certification of the flow-through of the rate discount, shall be made under penalty of perjury by the same individual who is responsible for the annual renewal of the facility's license from the appropriate state agency, when applicable. The accuracy of the self-certification or self-recertification applications are subject to random post-enrollment verification by the Utility.

T

31515-G*

32633-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AGGREGATION TRANSPORTATION COMMERCIAL AND INDUSTRIAL SERVICE, INCOME-QUALIFIED

1 9Schedule No. GT-10L

(continued)

Sheet of

APPLICABILITY

Applicable to aggregated Core Transportation Service for uses classified in Rule No. 23 as Priority 1. Service under this schedule is available to customers that elect to purchase natural gas from ESPs in accordance with Rule No. 32.

Eligibility for service under this schedule is limited to Nonprofit Group Living Facilities and Qualified Agricultural Employee Housing Facilities (migrant farmworker housing centers, privately-owned employee housing, and agricultural employee housing operated by nonprofit entities) that meet the income requirements for California Alternate Rates for Energy (CARE) eligibility as defined in Rule No. 1, Definitions, and Special Conditions 13 and 14, respectively. Eligibility information provided by the Applicant is subject to verification by SoCalGas.

TERRITORY


RATES

Customer Charge

Per meter, per day:



Beginning December 1 through March 31 ......................................... $0.84297*Beginning April 1 through November 30 ........................................... None


All customers except "space heating only: ............................................. 41.918¢*"Space heating only" customers:


If the applicable customer charge is collected under another rate schedule, no duplicate charge is collected hereunder.

D

N

N | |N

N

T | |T

D

31515-G* & 32162-G

32634-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

9Schedule No. GT-10L

(continued)

Sheet of

RATES (continued)


* The applicable monthly customer charge shall be determined on the basis of the customer's GT-10L usage for the most recent twelve-month period. For customers with less than twelve months of historical usage, the customer charge shall be determined on a pro rata basis using the months for which usage is available.



GT-10L


Rate, per therm

Tier I* ...................................................................................... 32.297¢

Tier II* ..................................................................................... 19.270¢

Tier III* .................................................................................... 8.265¢




N | |N

L |LL,TT

R

R

R

L

32162-G & 31517-G*

32635-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of

RATES (continued)

Billing Adjustments


Minimum Charge

Per meter, per day:


All customers except "space heating only"............................................... 27.945¢"Space heating only" customers:

Beginning December 1 through March 31......................................... $0.84297Beginning April 1 through November 30........................................... None


All customers except "space heating only"............................................... 41.918¢"Space heating only" customers:

Beginning December 1 throuigh March 31....................................... $1.26446Beginning April 1 through November 30.......................................... None

.SPECIAL CONDITIONS

GENERAL



3. Customers served hereunder may be reclassified as noncore by way of economic practicality, as defined in Rule No. 1.


L | | | | | |L

N

N | |N

N

L | |L

L

31517-G* & 31518-G*

32636-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of


GENERAL (continued)


6. If the customer and the ESP have met all of the requirements set forth in Rule No. 32, service will be effective in accordance with the schedule established in Rule No 32.

7. All provisions of Rule No. 32, Core Transportation Service, shall apply to customers receiving service under this schedule.


9. Transportation Imbalance Service shall be provided to the customer's ESP under Schedule No. G-IMB.

10. Customers with multiple facilities (under the same customer name) who comply with provisions for becoming an ESP may participate in the Program, but must designate a single account under which charges for imbalance services are to be billed.

11. In the event the ESP defaults on any payments to SoCalGas, the ESP's customers shall be responsible for SoCalGas' billings, excluding any ESP Procurement Management Charges, as defined in Rule No. 1, regardless of any billing arrangements the customer has with the ESP or any third parties.

12. SoCalGas shall continue to read customer meters, send customers legally required notices and bill inserts pursuant to Public Utilities Code 454(a), and provide customers with all other regular SoCalGas services. This includes direct billing, unless the customer specifies in the Core Aggregation Transportation Authorization (Form No. 6568-A), executed prior to the implementation of D.98-02-108, or in the electronic Service Request DASR effective with the implementation of D.98-02-108, that SoCalGas bill the ESP for all charges.

L | | | | | | | | | | | | | | | | | | | | | |L

L

31518-G* & 31519-G*

32637-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


(continued)

Sheet of


NONPROFIT GROUP LIVING FACILITIES

13. SoCalGas shall offer the CARE discount to facilities that qualify as follows:

a. Facility Eligibility Requirements: The CARE discount shall apply to nonprofit group living facilities and non-licensed, separately metered affiliated facilities such as homeless shelters, women's shelters, transitional housing (e.g., for drug rehabilitation, a half-way house, etc.), short- or long-term care facility (hospice, nursing homes, seniors' or children's homes), a group home for physically or mentally disabled persons, or nonprofit residential facility whose construction was government subsidized and meets all other applicable criteria. Student housing/dorms, military barracks, fraternities/sororities, government-owned and privately-owned "for profit" government-subsidized housing are excluded. The exclusion of government-owned and government-subsidized housing does not apply to homeless shelters.

The discount shall apply to non-licensed, separately metered affiliates of qualifying nonprofit group facilities so long as the customer of record is the qualifying nonprofit facility.

Each resident (100%) must meet the CARE income-eligibility standards for a single-person household for the facility or the non-licensed, separately metered facility to qualify under this schedule. A caregiver who lives in the facility is not a resident for purposes of determining eligibility. At least 70% of the energy consumed on the CARE rate must be used for residential purposes.

SoCalGas shall require the facility to provide a copy of its IRS Nonprofit Tax ID Form 501(c)(3), and state business license, conditional use permit or any other proof satisfactory to SoCalGas. Facilities that have been qualified by SoCalGas under self-certificatin or self-recertification and are receiving the rate discount may be subject to random post-enrollment verification by SoCalGas.

An authorized representative of the facility shall sign Form No. 6571 certifying that any savings derived from the discount shall be used for the direct benefit of the residents. Such direct benefit may be in the form of improved quality of care or improved food services.

Customers who are found to be ineligible or fail to timely notify SoCalGas when they no longer qualify for the rate discount may be subject to corrective rebilling under the appropriate rate schedule.


L | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |L

L

31519-G* & 31520-G*

32638-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)


(continued)

Sheet of



13. (continued)

b. Residents' Income-Eligibility Requirements: The total annual household income (from all sources (taxable and non-taxable) shall not be more than $17,700 for each resident of the facility, and the resident shall not be claimed on another person's income tax return.

The owner or authorized representative of the facility shall notify SoCalGas within 30 days following any change that may impact the facility's eligibility for the discount.

c. Self-Certification and Self-Recertification Requirements: Nonprofit group living facilities must provide proof of the appropriate state license to care for residents who, either temporarily or permanently, cannot function normally outside of the group home environment and certification from the appropriate state agency showing what services, besides lodging, are provided or any other documentation SoCalGas may reasonably require. Primary facilities must meet the licensing and certification requirements, but not their separately-metered affiliated facilities.

Homeless shelters must provide verification that at least six (6) beds each day or night are provided during a minimum 180 days each year for persons who have no alternate residence, and must provide proof of a valid municipal or county conditional-use permit or any other documentation SoCalGas may reasonably require. Nonprofit group living facilities are not required to be licensed or certified.

d. Self-Recertification Requirements: Facilities will be required to recertify on an annual basis. At the time of each annual self-recertification, SoCalGas shall require the facility to certify how it intends to pass on the rate discount.

e. Random Post-Enrollment Verification: The self-certification and self-recertification applications for CARE benefits, and certification of the flow-through of the rate discount, shall be made under penalty of perjury by the same individual who is responsible for the annual renewal of the facility's license from the appropriate state agency, when applicable. The accuracy of the self-certification or self-recertification applications may be subject to random post-enrollment verification by SoCalGas.

QUALIFIED AGRICULTURAL EMPLOYEE HOUSING FACILITIES

14. SoCalGas shall offer the CARE discount to migrant farmworker housing centers; privately-owned employee housing, or agricultural employee housing operated by nonprofit entities that qualify as follows:

L | | | | | | | | | | | | | | | | | | | | |L

L

31520-G* & 31521-G*

32639-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)


(continued)

Sheet of



14. (continued)

a. Facility Eligibility Requirements:

(1) Migrant Farmworker Housing Centers: The CARE discount shall apply to housing provided pursuant to Section 50710 of the Health and Safety Code. For facilities with individually-metered usage, all usage (100%) must be residential. For master-metered facilities, at least 70% of the energy consumed on the CARE rate must be used for residential purposes.

(2) Privately-Owned Employee Housing: The CARE discount shall apply to housing conforming to Section 17008 of the Health and Safety Code (the Employee Housing Act), that is licensed and inspected by state and/or local agencies pursuant to Part I (commencing with Section 17000) of Division 13. Energy usage in all facilities (100%) must be residential and individually metered.

(3) Nonprofit Agricultural Employee Housing: The CARE discount shall apply to housing conforming to Subdivision (b) of Section 1140.4 of the Labor Code, that has an exemption from local property taxes pursuant to subdivision (g) of Section 214 of the Revenue and Taxation Code. For facilities with individually-metered usage, all usage (100%) must be residential. For master-metered facilities, at least 70% of the energy consumed on the CARE rate must be used for residential purposes.

Employees operating and/or managing the facility who live in the facility are not considered residents for purposes of determining eligibility.

Energy used by offices, maintenance shops, or agriculture is not residential. Only residential and commercial usage, in the proportions defined above, qualifies for this rate.

The Applicant must be the customer of record for the facility. The Applicant is responsible for determining that each resident household meets the applicable income-eligibility standards. The Applicant must attest to this on Form No. 6632, under penalty of perjury.

An authorized representative of the facility shall sign Form No. 6632 certifying that any savings derived from the discount shall be used for the direct benefit of the residents. Such direct benefit may be in the form of improved quality of care or improved food services, reduced rent or result in no rate if increase in rent or a reduced rate of increase in the rent.

L | | | | | | | | | | | | | | | | | | | | |L

L

31521-G* & 31522-G*

32640-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)


(continued)

Sheet of



14. (continued)

a. Facility Eligibility Requirements (continued)


Facilities that have been qualified under self-certification or self-recertification and are receiving the rate discount may be subject to random post-enrollment verification by SoCalGas.

Customers who are found to be ineligible or fail to timely notify SoCalGas when they no longer qualify for the rate discount may be subject to corrective rebilling under the appropriate rate schedule.

b. Income-Eligibility Requirements for Resident Households: An income-qualified household has total annual income from all sources (taxable and non-taxable) that is no more than shown in the table below for the number of persons in the household.

Number of Persons Total Annual In Household Household Income

1 or 2 $17,7003 $20,9004 $25,1005 $29,3006 $33,5007 $37,700

For households with more than seven persons, add $4,200 annually for each additional person living in the household.

No person claimed on another person's income tax return shall be eligible for this rate.

The owner or authorized representative of the facility shall notify SoCalGas within 30 days following any change that may impact the facility's eligibility for the discount.

L | | | | | | | | | | | | | | | | | | | | | | |L

L

31522-G* & 31523-G*

32641-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


9

(continued)


Sheet of



14. (continued)

c. Self-Certification and Self-Recertification Requirements: The Applicant must also provide copies of the following:

(1) Migrant Farmworker Housing Centers: the facility's current contract with the Office of Migrant Services, Department of Housing and Community Development.

(2) Privately-Owned Employee Housing: a valid permit or license issued to the facility pursuant to Section17030 of the Health and Safety Code.

(3) Nonprofit Agricultural Employee Housing: the facility's IRS Nonprofit Tax ID Form 501(c)(3), and proof of the facility's local property tax exemption from the County Assessor where the facility is located.

In the initial application, the facility must attest to how it intends to pass on the rate discount for the direct benefit of the facility's residents in the upcoming year.

d. Self-Recertification Requirements: Facilities will be required to recertify on an annual basis. At the time of each annual self-recertification, SoCalGas shall require that the facility certify: (1) how it passed on the rate discount in the prior year, and (2) how it intends to pass on the rate discount in the upcoming year. An Applicant must show that a direct benefit was conferred on the facility's residents by demonstrating where the savings from the CARE rate will or has been reallocated.

The Applicant must provide documentation showing how the CARE rate was used to directly benefit the facility's residents. Such supporting documentation includes, but is not limited to, accounting entries, dated receipts, and memoranda and letters to the residents describing the benefits conferred.

e. Random Post-Enrollment Verification: The self-certification and self-recertification applications for CARE benefits, and certification of the flow-through of the rate discount, shall be made under penalty of perjury by the same individual who is responsible for the annual renewal of the facility's license from the appropriate state agency, when applicable. The accuracy of the self-certification and self-recertification applications may be subject to random post-enrollment verification by SoCalGas.

L | | | | | | | | | | | | | | | | | | | | | | | | |L

29392-G

32642-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE AIR CONDITIONING SERVICEFOR COMMERCIAL AND INDUSTRIAL

1 6Schedule No. G-AC

(continued)

Sheet of

APPLICABILITY

Applicable to natural gas core service for qualifying gas cooling uses, as defined in Rule No. 1, at each Facility classified in Rule No. 23 as Priority 1 and 2A or receiving service under Schedule No. GN-10 or Schedule No. GN-10L supplied from the Utility's core portfolio, as defined in Rule No. 1. In addition, this schedule is applicable to all qualifying core Priority 1 and 2A uses at each Facility served in combination with noncore service.


Qualifying usage under this schedule is any gas used by small or large nonresidential core customers, or the core gas-cooling load of noncore customers, to fuel high-efficiency gas cooling absorption chillers with two- or three-stage generators, designed and built by the original equipment manufacturers, and rated as double-effect or triple-effect units. The cooling output of the absorption chillers must equal at least 90% of the Btu input at the higher heating value of gas. Qualifying usage under this schedule also includes gas used by small or large non-residential core customers, or the core gas-cooling load of noncore customers, to fuel high-efficiency gas engine-driven chillers.

Eligibility for service under the G-ACL rate is limited to Non-Profit Group Living Facilities that meet the income requirements for California Alternate Rates for Energy as defined in Rule No. 1 and Special Condition 14.

TERRITORY


RATES

Customer Charge

Per Month....................................................................................... $150.00

If the applicable customer charge is collected under Schedule No. GT-AC, no duplicative charge is collected hereunder.

D

32474-G

32643-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

6Schedule No. G-AC

(continued)

Sheet of

RATES (continued)

Commodity Charges

G-AC

This charge is for service as defined above and consists of: (1) the monthly non-residential procurement charge as set forth in Schedule No. G-CP; (2) the GT-AC transmission charge, as set forth in Schedule No. GT-AC; (3) the San Juan Lateral interstate demand charge; and (4) the procurement carrying cost of storage inventory charge.


Rate, per therm.Procurement Charge: G-CPNR ........................................... 32.723¢Transmission Charge: GPT-AC ........................................... 8.551¢Commodity Charge: G-AC ................................................ 41.274¢

G-ACL

This charge is for service as defined above and consists of: (1) the discounted monthly non-residential procurement charge, as described below; (2) the GT-ACL transmission charge, as set forth in Schedule No. GT-AC; (3) the discounted San Juan Lateral interstate demand charge; and (4) the discounted procurement carrying cost of storage inventory charge.

The non-residential procurement charge is determined as set forth in Schedule No. G-CP, in the manner approved by D.96-08-037, and subject to change monthly as described in Special Condition 10. The procurement charge shown below has been discounted by 15 percent.

Rate, per therm.Procurement Charge: G-CPNRL ......................................... 27.815¢Transmission Charge: GPT-ACL ......................................... 7.268¢Commodity Charge: G-ACL .............................................. 35.083¢

Rate Limiter Provision

The cumulative percentage rate of change in the customer charge and transmission-charge portion of the commodity charge will not exceed the national rate of inflation as measured by the Consumer Price Index as defined in Rule No. 1. This provision expires October 31, 1998.

RR

RR

29394-G

32644-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

6Schedule No. G-AC

(continued)

Sheet of

RATES (continued)

Minimum Charge



SPECIAL CONDITIONS

General


2. Customer may receive service under this schedule (a) separately, or in (b) combination with another rate schedule(s) through additional meter installations. Where service is rendered under (b), a separate monthly customer charge shall be applicable for service under each schedule unless otherwise stated, and usage shall be the sum of all meters for billing purposes and priority classification under Rule No. 23.


4. As a condition precedent to service under this schedule, an executed Master Service Contract (Form No. 6597) and Addendum I, Gas Air Conditioning Services (Form No. 6597-9) is required. All contracts, rates, and conditions are subject to revision and modification as a result of Commission order.

5. The contract terms for service under this schedule shall be for a minimum of 30 days. After the initial 30-day term, the contract will continue on a month-to-month basis until terminated by either party upon 15-day written notice.

6. The Utility at its option may use either of the following means to accurately measure gas usage for nonresidential core cooling (a) install a separate metering facility, or (b) use a subtracting meter. Such meters will be installed at the customer's expense. Where service is rendered under (a), the customer's usage will be the sum of all meters.

7. In the event customers make any material change, in either the amount or character of their gas air conditioning appliances or equipment, written notice to the Utility must be made within 30 days.

8. Customers receiving service under this rate schedule may elect transportation service under Schedule No. GT-10, Schedule No. GT-10L, or Schedule No. GT-AC. D

29991-G

32645-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE TRANSPORTATION-ONLY AIR CONDITIONINGSERVICE FOR COMMERCIAL AND INDUSTRIAL

1 7Schedule No. GT-AC

(continued)

Sheet of

APPLICABILITY

Applicable to the transportation of customer-owned natural gas for qualifying gas cooling uses, as defined in Rule No. 1, at each Facility classified in Rule No. 23 as Priority 1 and 2A or receiving service under Schedule No. GT-10 or Schedule No. GT-10L. In addition, this schedule is applicable to all qualifying core Priority 1 and 2A uses at each Facility served in combination with noncore service. Qualifying usage under this schedule is for any gas used by small or large nonresidential core customers, or the core gas-cooling load of noncore customers, to fuel high- efficiency gas cooling absorption chillers with two-or three-stage generators, designed and built by the original equipment manufacturers, and rated as double-effect or triple-effect units. The cooling output of the absorption chillers must equal at least 90% of the Btu input of the higher heating value of gas. Qualifying usage under this schedule also includes gas used by small or large non-residential core customers, or the core gas-cooling load of noncore customers, to fuel high-efficiency gas engine-driven chillers.

Eligibility for service under the GT-AC rate shown below is limited to customers who elect to purchase natural gas from ESPs in accordance with Rule No. 32, and meet the requirements specified under Special Conditions 8 through 16, or with usage exceeding 250,000 therms per year (or 20,800 therms per month during the season when gas is used), and meet the requirements specified under Special Conditions 18 through 25.

Eligibility for service under the GT-ACL rate is limited to Non-Profit Group Living Facilities that meet the income requirements for California Alternate Rates for Energy as defined in Rule No. 1, Definitions, and specified in Special Condition 17, and meet the requirements specified in Special Conditions 8 through 16.

TERRITORY


RATES

Customer Charge

Per Month ............................................................................. $150.00

If the applicable customer charge is collected under Schedule No. G-AC, no duplicative charge is collected hereunder.

D

32168-G

32646-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE TRANSPORTATION-ONLY AIR CONDITIONINGSERVICE FOR COMMERCIAL AND INDUSTRIAL

2

(continued)

7Schedule No. GT-AC

(continued)

Sheet of

RATES (continued)


GT-AC


Rate, per therm ............................................................................. 8.267¢

GT-ACL


Rate, per therm ............................................................................. 7.027¢

Rate Limiter Provision

The cumulative percentage rate of change in the customer charge and transmission charge is not to exceed the national rate of inflation as measured by the Consumer Price Index, as defined in Rule No. 1. This provision expires October 31, 1998.

Minimum Charge



R

R

32475-G

32647-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE GAS ENGINE SERVICEFOR WATER PUMPING

2

(continued)

3Schedule No. G-EN

(continued)

Sheet of

RATES (continued)


G-EN (continued)


Rate, per therm

Procurement Charge: G-CPNR ......................................... 32.723¢Transmission Charge: GPT-EN ......................................... 18.057¢Commodity Charge: G-EN .............................................. 50.780¢

Minimum Charge



SPECIAL CONDITIONS

General


2. Customers must receive service under this schedule separately from their other non-qualifying usage requirements. Any additional service and measurement related facilities deemed necessary by the Utility to separately measure service hereunder shall be installed, owned, and operated by the Utility and the installation of such facilities shall be at the customer's expense.


4. In the event customers make any material change, either in the amount or character of their gas equipment, written notice to the Utility must be made in accordance with Rule No. 29, Change of Customer's Apparatus or Equipment.

II

32170-G

32648-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE TRANSPORTATION-ONLY GAS ENGINESERVICE FOR WATER PUMPING

1 3Schedule No. GT-EN

(continued)

Sheet of

APPLICABILITY

Applicable to the transportation of customer-owned natural gas for qualifying gas engine water pumping uses, as defined in Rule No. 1, at each Facility classified in Rule No. 23 as Priority 1 and 2A who (1) elect to purchase natural gas from ESPs in accordance with Rule No. 32; or (2) meet a minimum transportation requirement of 250,000 therms at the Facility and elect transportation-only service hereunder. Service under this schedule is optional for all Priority 1 qualifying usage. For facilities classified as Priority 2A, service under this schedule is optional subject to the contract terms set forth herein. Current noncore customers with usage that would otherwise qualify for service under this schedule may elect by written notice to SoCalGas to be served hereunder for such usage. In such an event the customer shall become a core customer for such usage and any grandfathered noncore status the customer may have shall terminate. In the event a Priority 2A or noncore customer elects service under this schedule, such election shall apply to all of the customers qualifying usage at the facility.

TERRITORY


RATES

Customer Charge

Per Month ............................................................................................. $50.00

If the applicable customer charge is collected under Schedule No. G-EN, no duplicative charge is collected hereunder.


GT-EN


Rate, per therm ............................................................................. 17.773¢ I

32476-G

32649-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

NATURAL GAS SERVICE FOR MOTOR VEHICLES

2

(continued)

3Schedule No. G-NGV

(continued)

Sheet of

RATES (continued)


Customer-Funded Fueling Station (continued)

G-NGU (continued)

Rate, uncompressed per therm.

Procurement Charge: G-CPNR ........................................... 32.723¢Transmission Charge: GPT-NGU ........................................ 11.069¢Commodity Charge: G-NGU ............................................. 43.792¢

Utility-Funded Fueling Station

G-NGC Compression Surcharge per therm .......................................... 35.000¢

The G-NGC Compression Surcharge will be added to the G-NGU Uncompressed rate per therm as indicated in the Customer-Funded Fueling Station section above. The resultant total compressed rate is:

G-NGC, compressed per therm ..................................................... 78.792¢

Compression of natural gas to the pressure required for its use as motor vehicle fuel will be performed by the Utility from a Utility-funded fueling station.

For billing purposes, the number of therms, compressed at a Utility-funded or a customer/Utility-funded station, will be compiled from a Summary of Transactions recorded by the dispensing unit for the customer during the month.

Co-funded fueling stations, customer/Utility-funded, will be billed at the above listed G-NGU and G-NGC rates based on the percentage level of co-funding. The agreement and associated rate will be filed with the Commission by separate contract.

Any applicable taxes, franchise or other fees will be billed separately on the customer's bill.

Minimum Charge

The minimum monthly charge shall consist of the monthly customer charge.


II

I

32172-G

32650-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSPORTATION OF CUSTOMER-OWNED GAS FOR MOTOR VEHICLE SERVICE

1 4Schedule No. GT-NGV

(continued)

Sheet of

APPLICABILITY

Applicable to the transportation of customer-owned gas for use in motor vehicles for customers who (1) elect to purchase natural gas from ESPs in accordance with Rule No. 32; or (2) meet a minimum transportation requirement of 250,000 therms at the Facility and elect transportation-only service hereunder as a self-aggregator and meet the requirements set forth in Rule No. 32. In accordance with Rule No. 23 service under this schedule shall be classified as end-use priority 1 or 2A.

TERRITORY


RATES

Customer Charge

P-1 Service, per month ......................................................................... $13.00

P-2A Service, per month ....................................................................... $65.00

If the customer charge is collected under Schedule No. G-NGV, no duplicative charge is collected hereunder.


Customer-Funded Fueling Station

Compression of natural gas to the pressure required for its use as motor vehicle fuel will be performed by the customer using customer's equipment at the customer's designated premises.

GT-NGU


GT-NGU, uncompressed per therm .......................................... 10.785¢ I

32173-G

32651-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSPORTATION OF CUSTOMER-OWNED GAS FOR MOTOR VEHICLE SERVICE

2

(continued)

4Schedule No. GT-NGV

(continued)

Sheet of

RATES (continued)


Utility-Funded Fueling Station

GT-NGC Compression Surcharge per therm ...................................... 35.000¢

The GT-NGC Compression Surcharge will be added to the GT-NGU uncompressed rate per therm as indicated in the Customer-Funded Fueling Station section above. The resultant rate is:

GT-NGC, compressed per therm .................................................. 45.785¢

Compression of natural gas to the pressure required for its use as motor vehicle fuel will be performed by SoCalGas from a Utility-funded fueling station.

Co-funded fueling stations, customer/Utility-funded, will be billed a proportionate compression charge based on the customer's level of co-funding. The agreement and associated rate will be filed with the Commission by separate contract.

Any applicable taxes, franchise or other fees will be billed separately on the customer's bill.

Minimum Charge

The minimum monthly charge shall consist of the monthly customer charge.


SPECIAL CONDITIONS


2. As a condition precedent to service under this rate schedule, an executed Master Services Contract, Schedule A, Intrastate Transmission Service (Form Nos. 6597 and 6597-1) shall be required for priority 2A customers. All contracts, rates, and conditions are subject to revision and modification as a result of Commission order.

3. The contract term for service under this rate schedule shall be for a minimum of one year. After the initial one-year term, the contract will continue on a year-to-year basis until terminated by either party upon 15-days written notice.

I

31476-G & 32446-G

32652-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CORE SUBSCRIPTION NATURAL GAS SERVICE

1 8Schedule No. G-CS

(continued)

Sheet of

APPLICABILITY

Applicable for core subscription service for (1) commercial and industrial, and enhanced oil recovery use at each facility classified as noncore, as defined in Rule No. 1, and (2) electric generation plants.

TERRITORY


RATES

Customer Charges

G-CS3D, Commercial/Industrial Distribution Level, per month ........................ $350

G-CS3T, Transmission Level, per month ......................................................... $700

G-CS4, Enhanced Oil Recovery, per month ...................................................... $500

G-CS5, Electric Generation using less than 3 million therms per yearPer month ................................................................................................... $50

The applicable G-CS5 monthly customer charge shall be determined on the basis of the customer's G-CS5 usage (combined with GT-F5 and GT-I5 usage, if applicable) for the most recent twelve-month period. For customers with less than twelve months of historical usage, the customer charge shall be determined on a pro rata basis using the months for which usage is available.

If the applicable customer charge is collected under Schedule No. GT-I or GT-F, no duplicative charge shall be collected hereunder.

Procurement Charges

Cost of Gas, per therm ................................................................................. 30.396¢Brokerage Fee, per therm ............................................................................. 0.266¢

Total Procurement Charges, per therm ......................................................... 30.662¢

D

DN

N

L

N | | | | |N

LL

L | |L

T

32446-G & 32174-G

32653-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

8Schedule No. G-CS

(continued)

Sheet of

RATES (continued)

Procurement Charges (continued)

The procurement charge will be filed on the last business day of each month to become effective on the first calendar day of the following month. The procurement charge is comprised of (1) the weighted average cost of gas (WACOG) for the current month, derived in the manner approved in D.98-07-068, including authorized franchise fees and uncollectible expenses, and any applicable adjustments; and (2) an authorized brokerage fee.

Interstate Transition Cost Surcharge (ITCS)

ITCS-GCS, per therm .................................................................................. 0.793¢

The ITCS, as defined in Rule No. 1, recovers certain interstate capacity costs and applies to all service under this schedule except for that service identified in Rule No. 1 as being exempt. The ITCS under this schedule shall include an additional allocation of any capacity costs that are associated with core subscription service.

Reservation Charges

Rate, per therm ............................................................................................ 3.211¢

The core subscription reservation charge is determined on all volumetric basis and is calculated based on actual gas usage in therms.


G-CS3D, Commercial/Industrial Distribution Level

Rate, per therm

Tier I 0 - 20,833 Therms ...................................................... 10.091¢Tier II 20,834 - 83,333 Therms .............................................. 6.238¢Tier III 83,334 - 166,667 Therms ............................................ 3.773¢Tier IV Over 166,667 Therms ................................................. 2.011¢

R

LDN | |N

LDN | | | | | |N

T

32174-G & 32175-G

32654-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

8Schedule No. G-CS

(continued)

Sheet of

RATES (continued)


G-CS3T, Transmission LevelRate, per therm

Tier I 0 - 166,667 Therms ...................................................... 5.448¢Tier II Over 166,667 Therms ................................................... 1.214¢

G-CS4, Enhanced Oil RecoveryRate, per therm ...................................................................................... 2.596¢

G-CS5, Electric Generation*

For customers using less than 3 million therms per yearRate, per therm ................................................................................. 5.740¢

For customers using 3 million therms or more per yearRate, per therm ................................................................................ 2.540¢

The applicable G-CS5 transmission charge shall be determined on the basis of the customer's G-CS5 usage (combined with GT-F5 and GT-I5 usage, if applicable) for the most recent twelve-month period. For customers with less than twelve months of historical usage, the transmission charge shall be determined on a pro rata basis using the months for which usage is available.

* The amount of gas applicable under the electric generation rate is determined in accordance with the provisions stated in Special Condition 16 herein.

Minimum Charge

For commercial/industrial, enhanced oil recovery and electric generation using less than 3 million therms per year service, the minimum monthly charge shall be the monthly customer charge. For electric generation customers using 3 million therms or more per year, the minimum monthly charge shall be the G-CS3T customer charge.



LN

TTD

I

DN | | | | | | | |N

TT

DN | |N

30091-G*

32655-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

8Schedule No. G-CS

(continued)

Sheet of

SPECIAL CONDITIONS

GENERAL


2. Customers may receive service under this schedule (a) separately, or (b) in combination with another rate schedule(s). Where service is rendered under (b), a separate monthly customer charge will be applicable for service under each schedule with a customer charge unless otherwise stated. Utility sales gas shall be considered the first gas through the meter.

3. As a condition precedent to service under this schedule, an executed Master Services Contract, Schedule A, Intrastate Transmission Service (Form Nos. 6597 and 6597-1) is required. All contracts, rates and conditions are subject to revision and modification as a result of Commission order.

4. The contract term for service under this schedule shall be two years.

5. In the event of curtailment, customers served hereunder will be curtailed in accordance with Rule No. 23. Penalties for violation of curtailment shall apply as set forth in Rule No. 23.

6. In the event customers make a material change, either in the amount or character of their gas appliances or equipment, written notice thereof must be made to the Utility in accordance with Rule No. 29, Change of Consumer's Apparatus or Equipment. Customers who do not meet historical usage criteria for noncore rate classification under this schedule may conditionally qualify for noncore rate status by submitting a written request to the Utility and providing therein certified evidence documenting the customer's load increases which will meet the minimum consumption requirement on a permanent basis. The customer's written request must further acknowledge that if usage following conditional reclassification is less than the required minimum, the customer shall be rebilled in accordance with the rate schedule otherwise applicable to its usage. The Utility reserves the right to accept or reject any such request.

7. Customers receiving service under this schedule or other commercial/industrial noncore rate schedule as of September 29, 1993 may continue to receive service hereunder regardless of size consistent with the grandfathering of noncore customers established in D.93-09-082. Such customers who elect core service or close their facilities (excluding changes in name or ownership) will no longer be eligible for service under this schedule unless they meet the size requirements set forth for noncore customers under Rule No. 23.

D

T

30092-G & 30093-G

32656-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

8Schedule No. G-CS

(continued)

Sheet of


FULL REQUIREMENTS SERVICE

8. Customers may elect full requirements service under this schedule or in combination with firm intrastate transmission service under Schedule No. GT-F. Full requirements customers are not required to contract for a stated annual quantity.

9. Full requirements customers are prohibited from using alternate fuels or bypass pipeline service except (1) in the event of curtailment, (2) to test alternate fuel capability, or (3) where the Utility has provided prior written authorization for the use of alternate fuels or bypass for temporary periods.

10. In the event of any unauthorized alternate fuel use or bypass, customers must provide the Utility written notice thereof quantifying the extent to which alternate fuel or bypass use occurred. Such notice must be provided prior to the end of the month in which the usage took place. Any unauthorized alternate fuel or bypass use will be subject to a use-or-pay charge equal to 80% of the applicable transmission charge. No other use-or-pay charges are applicable to full requirements service.

PARTIAL REQUIREMENTS SERVICE

11. A customer not electing full requirements service must contract for an annual quantity of gas applicable each contract year during the term of the two-year reservation period. The annual contract quantity may not be changed during the term of the contract. The Utility reserves the right to accept or reject such quantities after considering the customer's historic usage and other evidence provided by the customer regarding operational changes affecting consumption.

12. If at the end of a contract year, the partial requirements customer's annual usage is less than 75% of the customer's annual contract quantity, the customer will pay (1) take-or- pay charges equal to: 14% of the procurement charge for the last billing month of the contract year times the difference between the customer's actual usage and the 75% threshold; plus (2) use-or-pay charges equal to 80% of the transmission charge for the last billing month of the contract year times the difference between the customer's actual usage and the 75% threshold.

13. Take-or-pay and Use-or-pay charges for partial requirements service shall only be forgiven to the extent the customer's reduced consumption is specifically due to Force Majeure, as defined in Rule No. 1, intrastate curtailment, or service interruptions imposed by the Utility.

T

DT

T

T

D

T

T

L

T

30093-G & 31478-G

32657-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)

8Schedule No. G-CS

(continued)

Sheet of


ELECTRONIC METER-READING

14. Customers electing noncore service status must have electronic meter-reading equipment installed at Customer's expense as a condition of noncore service.

TAKE-OR-PAY/USE-OR-PAY AGGREGATION

15. Individual customers served under this schedule may aggregate their core subscription service at their facilities for the purpose of take-or-pay and use-or-pay penalty determination. In the event a customer aggregates core subscription service provided at different transmission rates, any applicable use- or-pay penalties shall be assessed at a weighted average transmission charge based on the proportion of the customer's annual contract quantities for such rates. For take-or-pay and use-or-pay aggregation, core subscription service may only be aggregated under contracts with concurrent contract year periods. As a condition of service aggregation, customers shall be required to designate in their contracts the applicable facilities and services to be aggregated.

ELECTRIC GENERATION

16. Subject to Special Condition 19, the amount of gas to be billed under the electric generation rate for customers having both electric generation and non-electric generation end use use on a single meter will be the lesser of:

a. Total metered throughput, or

b. An amount of gas equal to the customer's recorded power production in kilowatt-hours (kWh) times the average heat rate for their electric generation facilities. The difference between total meter throughput and the volume limitation specified herein will be charged the rate applicable to the other end use served off the meter.

17. When required, as a condition of service under the electric generation rate, electric generation customers will provide the utility with the average heat rate for electric generation equipment as supported by documentation from the manufacturer. If not available, operating data shall be used to determine customer's average heat rate.

L

L,TL

L

L,TL | | | | |L

T

T |T

TDN | | | | | | |NL

T

31478-G & 31479-G

32658-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)

8Schedule No. G-CS

(continued)

Sheet of


ELECTRIC GENERATION (continued)

18. Electric generation customers receiving electric generation service will make available upon request any measurement devices required to directly or indirectly determine the kilowatt-hours generated, or the average heat rate for the electric generation equipment. The Utility shall have the right to read, inspect and/or test all such measurement devices during normal business hours. Additional gas and/or steam metering facilities required to separately determine gas usage to which the electric generation rate is applicable may be installed, owned and operated by the Utility at its expense in accordance with normal service rules; however, the Utility may, at its sole discretion, utilize estimated data to determine such gas usage.

19. All electric generation customers receiving service at the electric generation transmission rate shall be separately metered unless it can be demonstrated that a separate meter is not economically feasible.

20. A Cogeneration Contract Addendum (Form No. 5058) will be required as a condition of electric generation service for cogeneration customers under this schedule in those cases where dedicated main facilities are necessary to serve the customer.

21. Cogeneration facilities with standby boilers will be treated as one customer for purposes of assessing customer charges, providing the customer has signed an affidavit (Form No. 6419) to the effect that its boiler system only operates when the cogeneration system is not operating.

COMMERCIAL/INDUSTRIAL

22. Commercial and industrial customers served under this schedule shall be assigned a rate classification based on the type of facilities from which the customer receives service. Customers served from the Utility's distribution-related facilities shall be classified as distribution (G-CS3D). Customers served from the Utility's transmission-related facilities, as established by the Utility's capital accounting records, shall be classified as transmission (G-CS3T). Customers served from transmission facilities or a combination of transmission and distribution facilities may, at their option, elect transmission or distribution rate status.

23. For commercial and industrial customers served under this schedule through multiple meters on a single premises, as defined in Rule No. 1, the Utility shall combine all such meters, excluding meters serving cogeneration equipment, for billing purposes in accordance with the provisions of Rule No. 17.

L,TLL,TLLL,TL,TL

N |N

T

T

T | | | | |T

T

D

T

31480-G & 31481-G

32659-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)

8Schedule No. G-CS

Sheet of


RESIDUAL LOAD SERVICE

24. Customers who receive gas transportation service from an alternate service provider may be subject to the provisions of the Residual Load Service Tariff, GT-RLS.

D

T

T

31482-G & 32176-G

32660-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

FIRM INTRASTATE TRANSMISSION SERVICE

1 8Schedule No. GT-F

(continued)

Sheet of

APPLICABILITY

Applicable for firm intrastate transmission-only service for (1) commercial and industrial, and enhanced oil recovery use at each facility classified as noncore, as defined in Rule No. 1, and (2) electric generation plants.

TERRITORY


RATES

Customer Charges

GT-F3D, Commercial/Industrial Distribution Level, per month ........................ $350

GT-F3T, Transmission Level, per month ......................................................... $700

GT-F4, Enhanced Oil Recovery, per month ..................................................... $500

GT-F5, Electric Generation using less than 3 million therms per yearPer month .................................................................................................. $50

The applicable GT-F5 monthly customer charge shall be determined on the basis of the customer's GT-F5 usage (combined with G-CS5 and GT-I5 usage, if applicable) for the most recent twelve-month period. For customers with less than twelve months of historical usage, the customer charge shall be determined on a pro rata basis using the months for which usage is available.

If the applicable customer charge is collected under Schedule Nos. G-CS or GT-I, no duplicative charge shall be collected hereunder.


GT-F3D, Commercial/Industrial Distribution LevelRate, per therm

Tier I 0 - 20,833 Therms .......................................................... 10.091¢Tier II 20,834 - 83,333 Therms ................................................. 6.238¢Tier III 83,334 - 166,667 Therms ............................................... 3.773¢Tier IV Over 166,667 Therms ..................................................... 2.011¢

D

DN

N

L

N | | | | |N

LL

LDN | | | | |N

T

32177-G

32661-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

8Schedule No. GT-F

(continued)

Sheet of

RATES (continued)


GT-F3T, Transmission LevelRate, per therm

Tier I 0 - 166,667 Therms ......................................................... 5.448¢Tier II Over 166,667 Therms ...................................................... 1.214¢

GT-F4, Enhanced Oil RecoveryRate, per therm ........................................................................................ 2.596¢

GT-F5, Electric Generation*

For customers using less than 3 million therms per yearRate, per therm ................................................................................... 5.740¢

For customers using 3 million therms or more per yearRate, per therm ................................................................................... 2.540¢

The applicable GT-F5 transmission charge shall be determined on the basis of the customer's GT-F5 usage (combined with G-CS5 and GT-I5 usage, if applicable) for the most recent twelve-month period. For customers with less than twelve months of historical usage, the transmission charge shall be determined on a pro rata basis using the months for which usage is available.


Interstate Transition Cost Surcharge (ITCS)ITCS, per therm ......................................................................................... 0.793¢

The ITCS, as defined in Rule No. 1, recovers certain interstate capacity costs and applies to all service under this schedule except for that service identified in Rule No. 1 as being exempt.

Minimum Charge

For commercial/industrial, enhanced oil recovery and electric generation using less than 3 million therms per year service, the minimum monthly charge shall be the applicable monthly customer charge. For electric generation customers using 3 million therms or more per year, the minimum monthly charge shall be the GT-F3T customer charge.

N | | |ND

I

DN | | | | | | | | |N

R

T | |T

T

30098-G*

32662-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

8Schedule No. GT-F

(continued)

Sheet of

RATES (continued)



SPECIAL CONDITIONS

GENERAL


2. Customers may receive service under this schedule (a) separately, or (b) in combination with another rate schedule(s). Where service is rendered under (b), a separate monthly customer charge will be applicable for service under each schedule with a customer charge unless otherwise stated.


4. The contract term for service under this schedule shall be two years.


6. In the event customers make a material change, either in the amount or character of their gas appliances or equipment, written notice thereof must be made to the Utility in accordance with Rule No. 29, Change of Consumer's Apparatus or Equipment. Customers who do not meet historical usage criteria for noncore rate classification under this schedule may conditionally qualify for noncore rate status by submitting a written request to the Utility and providing therein certified evidence documenting the customer's load increases which will meet the minimum consumption requirement on a permanent basis. The customer's written request must further acknowledge that if usage following conditional reclassification is less than the required minimum, the customer shall be rebilled in accordance with the rate schedule otherwise applicable to its usage. The Utility reserves the right to accept or reject any such request.

T

30099-G

32663-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

8Schedule No. GT-F

(continued)

Sheet of


SERVICE ELECTIONS


8. All terms and conditions of Rule No. 30 and Schedule No. G-IMB shall apply to the transportation of customer-owned gas under this schedule.

9. Customers having existing gas exchange agreements with the Utility must exchange the maximum amount of gas allowable under those agreements prior to the delivery of customer-owned gas for transportation under other service agreements, unless otherwise agreed to by the Utility.


10. Customers may elect full requirements service under this schedule or in combination with core subscription service under Schedule No. G-CS. Full requirements customers are not required to contract for a stated annual quantity.

11. Full requirements customers are prohibited from using alternate fuels or bypass pipeline service (1) except in the event of curtailment, (2) to test alternate fuel capability, or (3) where the Utility has provided prior written authorization for the use of alternate fuels or bypass for temporary periods.

12. In the event of any unauthorized alternate fuel use or bypass, customers must provide the Utility written notice thereof quantifying the extent to which alternate fuel or bypass use occurred. Such notice must be provided prior to the end of the month in which the usage took place. Any unauthorized alternate fuel or bypass use will be subject to a use-or-pay charge equal to 80% of the applicable transmission charge. No other use-or-pay charges are applicable to full requirements service.

T

30100-G

32664-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

8Schedule No. GT-F

(continued)

Sheet of



13. A customer not electing full requirements service must contract for an annual quantity of gas applicable each contract year during the term of the customer's contract. The annual contract quantity may not be changed during the term of the customer's contract. The annual contract quantity must be broken down by month into fixed service quantities for each contract year during the term of the contract. The customer may request changes to the monthly quantities on a month-to-month basis, however, the total of the monthly contract quantities for the contract year must equal the annual contract quantity. The monthly contract quantity breakdown may be established on the basis of seasonal variations in the customer's usage in accordance with the customer's historic usage pattern. The Utility reserves the right to accept or reject such requested quantities after considering the customer's historic usage pattern and other evidence provided by the customer regarding operational changes affecting the customer's consumption.

14. If at the end of a contract year, the partial requirements customer's annual usage is less than 75% of the customer's annual contract quantity, the customer will pay a use-or-pay charge equal to 80% of the transmission charge for the last billing month of the contract year times the difference between the customer's actual usage and the 75% threshold.

15. Use-or-pay charges applicable to partial requirements service shall only be forgiven to the extent the customer's reduced consumption is specifically due to intrastate curtailment or an event of force majeure, as defined in Rule No. 1, on either the interstate or intrastate systems.

FIRM INTRASTATE TRANSMISSION

16. Utility shall offer firm intrastate transmission service to customers whose volumes qualify as follows:

a. Firm Interstate Customers: Firm intrastate transmission shall be available for customers' volumes delivered through firm interstate capacity rights or where customers purchase or receive (1) gas delivered to Utility interconnection with an interstate pipeline on a firm basis, (2) intrastate California supplies delivered directly into the Utility's system, or (3) supplies which are delivered from the Utility's storage facilities, provided that the Utility has sufficient capacity to receive and redeliver all such volumes on a firm basis.

b. Interruptible Interstate, Existing Capacity: Firm intrastate transmission shall be available for volumes delivered by customers or customers of shippers to the Utility on an interruptible basis through interstate pipeline capacity in existence as of November 6, 1991 to the extent and so long as (1) the capacity of the interstate pipeline is not expanded so as to create a mismatch of interstate and intrastate capacity, and (2) the Utility has adequate intrastate system capacity to receive and redeliver all such volumes on a firm basis.

T

31484-G

32665-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)

8Schedule No. GT-F

(continued)

Sheet of



16. (continued)

The Utility shall have no obligation to build new facilities to provide firm intrastate service for customers' volumes delivered to the Utility on an interruptible basis through interstate pipeline capacity in existence as of November 6, 1991.

c. Interruptible Interstate, New Capacity: Firm intrastate transmission service shall be available for customers' volumes delivered to the Utility on an interruptible basis across a new interstate pipeline or an expansion of an existing pipeline (as of November 6, 1991) provided that (1) the customer has given assurances acceptable to the Utility that any costs associated with enhancements of the Utility's intrastate system which are necessary to provide firm intrastate service will be recovered by the Utility, (2) required enhancements are approved by the CPUC and are constructed and placed in service, and (3) the Utility has determined that it can physically provide firm intrastate service for all such volumes.


17. Customers electing noncore service status must have electronic meter-reading equipment installed at Customer's expense as a condition of noncore service.

USE-OR-PAY AGGREGATION

18. Individual customers served under this schedule may aggregate their firm intrastate transmission service at their facilities for the purpose of use-or-pay penalty determination. In the event a customer aggregates firm intrastate transmission service provided at different transmission rates, any applicable use-or-pay penalty shall be assessed at a weighted average transmission charge based on the proportion of the customer's annual contract quantities for such rates. For use-or-pay aggregation, firm intrastate transmission service may only be aggregated under contracts with concurrent contract year periods. As a condition of service aggregation, customers shall be required to designate in their contracts the applicable facilities and services to be aggregated.

D

T

31485-G & 31486-G

32666-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)

8Schedule No. GT-F

(continued)

Sheet of


ELECTRIC GENERATION

19. Subject to Special Condition 22, the amount of gas to be billed at the electric generation rate for customers having both electric generation and non-electric generation end use on a single meter will be the lesser of:

a. Total metered throughput; or

b. An amount of gas equal to the customer's recorded power production in kilowatt-hours (KWH) times the average heat rate for their electric generation facilities. The difference between total meter throughput and the volume limitation specified herein will be charged the rate applicable to the other end use served off the meter.


21. Electric generation customers receiving electric generation service will make available upon request any measurement devices required to directly or indirectly determine the kilowatt-hours generated or the average heat rate for the electric generation equipment. The Utility shall have the right to read, inspect and/or test all such measurement devices during normal business hours. Additional gas and/or steam metering facilities required to separately determine gas usage to which the electric generation rate is applicable may be installed, owned and operated by the Utility at its expense in accordance with normal service rules; however, the Utility may, at its sole discretion, utilize estimated data to determine such gas usage.




N

T | | | | | | | |TDN | |NDT

T

T

NN

L |L

T

31486-G,31487-G,31488-G

32667-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)

8Schedule No. GT-F

Sheet of


COMMERCIAL/INDUSTRIAL

25. Commercial and industrial customers served under this schedule shall be assigned a rate classification based on the type of facilities from which the customer receives service. Customers served from the Utility's distribution-related facilities shall be classified as distribution (GT-F3D). Customers served from the Utility's transmission-related facilities, as established by the Utility's capital accounting records, shall be classified as transmission (GT-F3T). Customers served from transmission facilities or a combination of transmission and distribution facilities may, at their option, elect transmission or distribution rate status.

26. For commercial and industrial customers served under this schedule through multiple meters on a single premises, as defined in Rule No. 1, the Utility shall combine all such meters, excluding meters serving electric generation equipment, for billing purposes in accordance with the provisions of Rule No. 17.

LONG-TERM DISCOUNTED CONTRACTS

27. Pursuant to the provisions of Decision No. 92-11-052, the Utility may negotiate discounted contracts for a service term of five years or longer with customers served under this schedule. Such contracts must be filed for prior CPUC approval under the CPUC's Expedited Application Docket (EAD) procedure as adopted in Decision No. 92-11-052.



L,D

T | | | | |T

L,TL |LDL

L,TL |L

L

L,TL

31489-G & 32178-G

32668-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

INTERRUPTIBLE INTRASTATE TRANSMISSION SERVICE

1 6Schedule No. GT-I

(continued)

Sheet of

APPLICABILITY

Applicable for interruptible intrastate transmission-only service for (1) commercial and industrial, and enhanced oil recovery use at each facility classified as noncore, as defined in Rule No. 1, and (2) electric generation plants. All such noncore customers shall be eligible to receive interruptible intrastate transmission service under this schedule.

TERRITORY


RATES

Customer Charges

GT-I3D, Commercial/Industrial Distribution Level, per month .................... $350

GT-I3T, Transmission Level, per month ..................................................... $700

GT-I4, Enhanced Oil Recovery, per month .................................................. $500

GT-I5, Electric Generation using less than 3 million therms per yearPer month .............................................................................................. $50

The applicable GT-I5 monthly customer charge shall be determined on the basis of the customer's GT-I5 usage (combined with G-CS5 and GT-F5 usage, if applicable) for the most recent twelve-month period. For customers with less than twelve months of historical usage, the customer charge shall be determined on a pro rata basis using the months for which usage is available.

If the applicable customer charge is collected under Schedule Nos. G-CS or GT-F, no duplicative charge shall be collected hereunder.


GT-I3D, Commercial/Industrial Distribution LevelRate, per therm

Tier I 0 - 20,833 Therms .......................................................... 10.091¢Tier II 20,834 - 83,333 Therms ................................................. 6.238¢Tier III 83,334 - 166,667 Therms ............................................... 3.773¢Tier IV Over 166,667 Therms ..................................................... 2.011¢

D

DN

N

N | | | | |N

TD

N | |N

T

32178-G & 32179-G

32669-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

6Schedule No. GT-I

(continued)

Sheet of

RATES (continued)


GT-I3T, Transmission LevelRate, per therm

Tier I 0 - 166,667 Therms ........................................................ 5.448¢Tier II Over 166,667 Therms .................................................... 1.214¢

GT-I4, Enhanced Oil RecoveryRate, per therm ........................................................................................ 2.596¢

GT-I5, Electric Generation*

For customers using less than 3 million therms per yearRate, per therm ................................................................................... 5.740¢

For customers using 3 million therms or more per yearRate, per therm ................................................................................... 2.540¢

The applicable GT-I5 transmission charge shall be determined on the basis of the customer's GT-I5 usage (combined with G-CS5 and GT-F5 usage, if applicable) for the most recent twelve-month period. For customers with less than twelve months of historical usage, the transmission charge shall be determined on a pro rata basis using the months for which usage is available.



ITCS, per therm .......................................................................................... 0.793¢


N

NN

I

N | | | | | | | | | |N

R

T

32179-G & 31492-G

32670-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

6Schedule No. GT-I

(continued)

Sheet of

RATES (continued)

Minimum Charge

For commercial/industrial, enhanced oil recovery and electric generation using less than 3 million therms per year service, the minimum monthly charge shall be the applicable monthly customer charge. For electric generation customers using 3 million therms or more per year, the minimum monthly charge shall be the GT-I3T customer charge.



SPECIAL CONDITIONS

GENERAL


2. Customers may receive service under this schedule (a) separately, or (b) in combination with another rate schedule(s). Where service is rendered under (b), a separate monthly customer charge will be applicable for service under each schedule with a customer charge unless otherwise stated.


4. The minimum contract term for service hereunder shall be one month.


6. In the event customers make a material change, either in the amount or character of their gas appliances or equipment, written notice thereof must be made to the Utility in accordance with Rule No. 29, Change of Consumer's Apparatus or Equipment. Customers who do not meet historical usage criteria for noncore rate classification under this schedule may conditionally qualify for noncore rate status by submitting a written request to the Utility and providing therein certified evidence documenting the customer's load increases which will meet the minimum consumption requirement on a permanent basis. The customer's written request must further acknowledge that if

T | |T

L

T

31492-G & 31493-G

32671-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

6Schedule No. GT-I

(continued)

Sheet of


GENERAL (continued)

6. (continued)

usage following conditional reclassification is less than the required minimum, the customer shall be rebilled in accordance with the rate schedule otherwise applicable to its usage. The Utility reserves the right to accept or reject any such request.



9. Customers having existing gas exchange agreements with the Utility must exchange the maximum amount of gas allowable under those agreements prior to the delivery of customer-owned gas for transportation under other service agreements, unless otherwise agreed to by the Utility.


10. Customers electing noncore status must have electronic meter-reading equipment installed at Customer's expense as a condition of noncore service.

NEGOTIABLE TRANSMISSION CHARGES

11. By mutual agreement, the Utility and the customer may negotiate interruptible intrastate transmission charges for a term of service of less than five years without CPUC approval. Any such negotiated transmission charges shall be set forth in the customer's service contract. All such service contracts must be submitted by letter to the CPUC and made available for public inspection. No other charges under this schedule shall be negotiable unless CPUC approval is first obtained.

12. All contracts for a term of service of five years or longer ("long-term") meeting the guidelines set forth in Decision No. 92-11-052 must be filed for prior CPUC approval under the CPUC's Expedited Application Docket (EAD) procedure adopted in Decision No. 92-11-052. All other long-term contracts must be filed by advice letter for prior CPUC approval.

L | | | | | | | | | | | | | | | | |L

T

31493-G,31494-G,31495-G

32672-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

6Schedule No. GT-I

(continued)

Sheet of


ELECTRIC GENERATION

13. Subject to Special Condition 16, the amount of gas to be billed at the electric generation rate for customers having both electric generation and non-electric generation end use on a single meter will be the lesser of:

a. Total metered throughput; or

b. An amount of gas equal to the customer's recorded power production in kilowatt-hours (KWH) times the average heat rate for their electric generation facilities. The difference between total meter throughput and the volume limitation specified herein will be charged the rate applicable to the other end use served off the meter.


15. Electric generation customers receiving electric generation service will make available upon request any measurement devices required to directly or indirectly determine the kilowatt-hours generated or the average heat rate for the electric generation equipment. The Utility shall have the right to read, inspect and/or test all such measurement devices during normal business hours. Additional gas and/or steam metering facilities required to separately determine gas usage to which the electric generation rate is applicable may be installed, owned and operated by the Utility at its expense in accordance with normal service rules; however, the Utility may, at its sole discretion, utilize estimated data to determine such gas usage.




T | | | | | | | |TDN | |NDT

T

NN

D

31495-G & 31496-G

32673-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)

6Schedule No. GT-I

Sheet of


COMMERCIAL AND INDUSTRIAL

19. Commercial and industrial customers served under this schedule shall be assigned a rate classification based on the type of facilities from which the customer receives service. Customers served from the Utility's distribution-related facilities shall be classified as distribution (GT-I3D). Customers served from the Utility's transmission-related facilities, as established by the Utility's capital accounting records, shall be classified as transmission (GT-I3T). Customers served from transmission facilities or a combination of transmission and distribution facilities may, at their option, elect transmission or distribution rate status.

20. For commercial and industrial customers served under this schedule through multiple meters on a single premises, as defined in Rule No. 1, the Utility shall combine all such meters, excluding meters serving electric generation equipment, for billing purposes in accordance with the provisions of Rule No. 17.



T | | | | |T

T

D

T

T

32180-G

32674-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

INTRASTATE TRANSMISSION SERVICE

1 4Schedule No.GT-SD

(continued)

Sheet of

APPLICABILITY

Applicable for firm and interruptible intrastate transmission service for delivery to San Diego Gas & Electric Company ("SDG&E") Rainbow receipt point.

TERRITORY

The Rainbow meter delivery point shall be as specified as the sole point of delivery in the Master Services Contract, Schedule A, Intrastate Transmission Service.

RATES

Customer Charge

Per month ................................................................................................ $150


ITCS-SD, per therm ................................................................................. 0.789¢

The ITCS, as defined in Rule No. 1, recovers certain interstate capacity costs and applies to all service under this schedule.


The transmission charges below are applicable for firm intrastate transmission service (GT-F11) and interruptible intrastate transmission service (GT-I11).

GT-F11 Rate, per therm ........................................................................ 1.448¢GT-I11 Rate, per therm ........................................................................ 1.448¢

Rates may be adjusted to reflect any applicable taxes, franchise or other fees, regulatory surcharges, and interstate or intrastate pipeline charges or penalties that may occur.

The number of therms to be billed shall be all transportation quantities nominated for delivery by or on behalf of the customers into the utility system that are scheduled for delivery to the utility system.

R

RR

32181-G & 32447-G

32675-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

WHOLESALE NATURAL GAS SERVICE

1 7Schedule No. GW-LB

(continued)

Sheet of

APPLICABILITY

Applicable for core subscription, firm intrastate transmission, and interruptible intrastate transmission service for the City of Long Beach ("Customer").

TERRITORY

Delivery points shall be as specified in the Master Services Contract, Schedule A, Intrastate Transmission Service ("Contract").

RATES


G-CS7, Core Subscription

Rate, per therm .................................................................................... 2.160¢

GT-F7, GT-I7, Firm & Interruptible Intrastate Transmission

Rate, per therm .................................................................................... 2.160¢


ITCS-LB, per therm ................................................................................ 0.789¢

The ITCS, as defined in Rule No. 1, recovers certain interstate capacity costs and applies to all service under this schedule except for that service identified in Rule No. 1 as being exempt. The ITCS under this schedule may include an additional allocation of any capacity costs associated with service hereunder as provided in Special Condition 22.

Procurement Charge


Cost of Gas, per therm ........................................................................ 30.249¢Brokerage Fee, per therm .................................................................... 0.266¢

Total Procurement Charge, per therm ................................................. 30.515¢

I

I

R

TDL | | | | | |L

T

32447-G & 32448-G

32676-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

7Schedule No. GW-LB

(continued)

Sheet of

RATES (continued)

Procurement Charge (continued)

The procurement charge will be filed on the last business day of each month to become effective on the first calendar day of the following month. The procurement charge is comprised of (1) the weighted average cost of gas (WACOG) for the current month, derived in the manner approved in D.98-07-068, including authorized franchise fees and any applicable adjustments; and (2) an authorized brokerage fee.

Reservation Charges


Rate, per therm .................................................................................... 3.211¢

The core subscription reservation charge is determined on an all volumetric basis and is calculated based on actual gas usage in therms..



SPECIAL CONDITIONS

GENERAL



3. In the event of curtailment, Customer will be curtailed in accordance with Rule No. 23. Penalties for violation of curtailment shall apply as set forth in Rule No. 23. If service to Customer's Priority 1 and 2A customers is in jeopardy, such customers shall be served in parity with Utility's Priority 1 and 2A customers as set forth in Rule No. 23.

L

D,N

D,NN

L | | | | | | | | | | | | | | | | | |L

T

26348-G & 26349-G

32677-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

7Schedule No. GW-LB

(continued)

Sheet of


GENERAL (continued)


5. Customer's core load can be out of balance for a period up to twelve months in length. The maximum amount by which quantities purchased to serve the Customer's core market can be out-of-balance is limited to: (1) a quantity equal to the percentage of the Utility's storage capacity equivalent to the percentage of total storage costs assessed to the core customers of Customer as adopted in the most recent cost allocation proceeding; and (2) by any operational constraints experienced by the Utility.

SERVICE ELECTIONS

6. Prior to the implementation date of the CPUC's Capacity Brokering Rules, the Utility shall conduct an open season, as described in Rule No. 35, wherein Customer shall be required to designate the extent to which it will take core subscription service (G-CS7) and/or firm intrastate transmission service (GT-F7). If Customer fails to notify the Utility of its service elections, then Customer shall be assigned to interruptible intrastate service (GT-I7) with the exception that Customer's current core subscription requirements shall default to core subscription service.

CORE SUBSCRIPTION

7. Subsequent to the Utility's initial interstate capacity brokering open season, described in Rule No. 35, the Customer may request additional core subscription service. The Utility shall accept such a request along with the requests of other customers on a first-come first-served basis to the extent Utility determines it is operationally feasible to provide such service. If access to core subscription service becomes restricted, Utility shall maintain a list of the customers requesting such service (by time and date of request) and shall provide service in the order of the customer list in the event additional core subscription capacity becomes available.


8. The contract term for firm intrastate transmission service shall be two years.

L

L | | | | | |L

LDL,TL | | |LL,D

L

L,T

T

26349-G & 26350-G

32678-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

7Schedule No. GW-LB

(continued)

Sheet of


FIRM INTRASTATE TRANSMISSION (continued)

9. Utility shall offer firm intrastate transmission service only to customers whose volumes qualify as follows:



The Utility shall have no obligation to build new facilities to provide firm intrastate service for customers' volumes delivered to the Utility on an interruptible basis through interstate capacity in existence as of November 6, 1991.

c. Interruptible Interstate, New Capacity: Firm intrastate transmission service shall be available for customers' volumes delivered to Utility on an interruptible basis across a new interstate pipeline or an expansion of an existing pipeline (as of November 6, 1991) provided that (1) the customer has given assurances acceptable to the Utility that any costs associated with enhancements of the Utility's intrastate system which are necessary to provide firm intrastate service will be recovered by the Utility, (2) required enhancements are approved by the CPUC and are constructed and placed in service, and (3) the Utility has determined that it can physically provide firm intrastate service for all such volumes.

10. Pursuant to the provisions and guidelines of Decision No. 92-11-052, the Utility may negotiate a discounted contract with Customer for a service term of five years or more. Such a contract must be filed for prior CPUC approval under the CPUC's Expedited Application Docket (EAD) procedure as adopted in Decision No. 92-11-052.

LT

L | | | | | | | | | | | | | | | | |L

L,TL |L

T

26350-G,26351-G,26352-G

32679-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

7Schedule No. GW-LB

(continued)

Sheet of



11. For its core subscription and/or firm intrastate transmission service, Customer may elect full requirements service only for that portion of such usage serving (1) its own core customers' requirements, on an aggregate basis, and/or (2) the requirements, on an individual basis, of those noncore customers designated by Customer as requesting such service; as set forth in the Customer's Contract. Customer must provide Utility sufficient information to establish the usage requirements of its designated full requirements load.

12. Customer's full requirements service loads are prohibited from being displaced through use of alternate fuels or bypass pipeline service except (1) in the event of curtailment, (2) to test alternate fuel capability, (3) or where the Utility has provided prior written authorization for the use of alternate fuels or bypass for temporary periods. The Utility shall have the right to review the Customer's records in order to determine compliance hereunder.

13. In the event of any unauthorized alternate fuel use or bypass which displaces Customer's full requirement load, Customer must provide the Utility written notice thereof quantifying the extent to which alternate fuel or bypass use occurred. Such notice must be provided prior to the end of the month in which the usage took place. Any unauthorized alternate fuel or bypass use will be subject to a use-or-pay charge equal to 80% of the applicable transmission charge. No other use-or-pay charges are applicable to full requirements service.


14. For both its core subscription and firm intrastate transmission service (excluding Customer's full requirements load, if applicable), Customer must contract for a separate annual quantity of gas applicable for each contract year during the term of the Contract. The annual contract quantity may not be changed during the term of the Contract and must be broken down by month into fixed service quantities for each contract year during the Contract term. Customer may request changes to the monthly contract quantities on a month-to-month basis, however, the total of the monthly contract quantities for a contract year must equal the annual contract quantity. The monthly quantity breakdown may be established on the basis of seasonal variations in accordance with Customer's historic usage pattern. The Utility reserves the right to accept or reject any requested contract quantities after considering Customer's historic requirements and other evidence provided by Customer regarding operational changes affecting its consumption.

L,TL | | |LDT

T

L

L,TL | | | | | | | |L

T

26352-G & 26196-G

32680-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)

7Schedule No. GW-LB

(continued)

Sheet of


PARTIAL REQUIREMENTS SERVICE (continued)

15. If at the end of a contract year, Customer's partial requirements core subscription usage is less than 75% of the core subscription contract quantity, Customer will pay (1) take-or-pay charges equal to 14% of the procurement charge for the last month of the contract year times the difference between Customer's actual usage and the 75% threshold; plus use-or-pay charges equal to 80% of the transmission charge for the last billing month of the contract year times the difference between the Customer's actual usage and the 75% threshold.

16. Take-or-pay and Use-or-pay charges applicable to partial requirements core subscription service shall only be forgiven to the extent Customer's reduced consumption is specifically due to Force Majeure, as defined in Rule No. 1, intrastate curtailment, or service interruptions imposed by the Utility.

17. If at the end of a contract year, Customer's partial requirements firm intrastate transmission usage is less than 75% of the firm intrastate transmission contract quantity, Customer will pay use-or-pay charges equal to 80% of the transmission charge for the last billing month of the contract year times the difference between the Customer's actual usage and the 75% threshold.

18. Use-or-pay charges applicable to partial requirements firm intrastate transmission service shall only be forgiven to the extent Customer's reduced consumption is specifically due to intrastate curtailment or a Force Majeure event on either the interstate or intrastate systems.

INTERRUPTIBLE INTRASTATE TRANSMISSION

19. Customer may elect interruptible intrastate transmission service for all or part of its requirements. The minimum contract term for such service shall be one month.

20. By mutual agreement, the Utility and Customer may negotiate interruptible intrastate transmission charges for a term of service of less than five years without CPUC approval. Any such negotiated transmission charges shall be set forth in the Customer's Contract. Any such contract must be submitted by letter to the CPUC and made available for public inspection. No other charges for service under this schedule shall be negotiable unless CPUC approval is first obtained.


LT

T

T

T

L

L,TL

L,TL | |L

L,TL |L

T

26196-G

32681-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)

7Schedule No. GW-LB

Sheet of


FIRM INTERSTATE PIPELINE CAPACITY

22. At any time prior to five (5) business days before commencement of the Utility's initial open season for the brokering of firm interstate pipeline capacity conducted pursuant to the provisions of Rule No. 36, Customer may request an assignment of such capacity for Customer's core requirements. Capacity shall be provided to Customer on a pro rata basis between the El Paso and Transwestern pipeline systems and charged at the full as-billed interstate rate. Such capacity shall be assigned to Customer for a term from the implementation date of the CPUC's Capacity Brokering Rules until the expiration of the Utility's firm capacity contracts with El Paso and Transwestern. If Customer does not provide such a request prior to the 5-day deadline, Utility will reserve sufficient firm interstate pipeline capacity, split 70% on El Paso and 30% on Transwestern, to meet Customer's core load requirements. Interstate capacity allocated to Customer for its core requirements shall be at the full as-billed rate for pipeline demand charges.

23. In the event Customer relinquishes all or a part of its reserved firm interstate capacity, or the capacity reserved by Utility on Customer's behalf, Customer shall be solely responsible for any shortfall between the as-billed interstate pipeline demand charges and the actual revenue the Utility obtains from its subsequent brokering of the relinquished capacity.


24. Customer may be subject to the provisions of the Residual Load Service Tariff, GT-RLS, if it receives gas transportation service from an alternate service provider.

L

T

T

T

T

32448-G

32682-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


1 5Schedule No. GW-SD

(continued)

Sheet of

APPLICABILITY

Applicable for core subscription and intrastate transmission service for San Diego Gas & Electric Company ("Customer").

TERRITORY

Delivery points shall be as specified in the Customer's Master Services Contract, Schedule A, Wholesale Intrastate Transmission Service.

RATES

Procurement Charges

G-CS8, Core Subscription Service


Total Procurement Charges, per therm ................................................. 30.515¢


Reservation Charges

G-CS8, Core Subscription Service

Rate, per therm ...................................................................................... 3.211¢

The core subscription reservation charge is determined on an all volumetric basis and is calculated based on actual gas usage in therms.

D,N

D,NN

T

32183-G

32683-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

5Schedule No. GW-SD

(continued)

Sheet of

RATES (continued)


ITCS-SD, per therm ................................................................................. 0.789¢



The transmission charges below are applicable for any core subscription service (G-CS8), firm intrastate transmission service (GT-F8), and interruptible intrastate transmission service (GT-I8).

G-CS8 Rate/Therm .................................................................................. 1.448¢GT-F8 Rate/Therm .................................................................................. 1.448¢GT-I8 Rate/Therm .................................................................................. 1.448¢


The number of therms to be billed shall be the number of therms determined in accordance with Rule No. 2 less the number of therms billed to customers under Schedule No. GT-SD for the same applicable billing period.

SPECIAL CONDITIONS



3. In the event of curtailment, the Utility shall provide service to Customer in accordance with the provisions of Rule No. 23.

4. The transportation imbalance will be calculated by aggregating the confirmed transportation deliveries for the customer with the confirmed transportation deliveries for customers taking service under Schedule No. GT-SD less the actual usage recorded by the Utility at the SDG&E system receipt points. All other terms and conditions of Rule No. 30 and Schedule No. G-IMB shall apply to the transportation of customer-owned gas under this schedule.

R

R |R

T

27162-G & 27163-G

32684-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

5Schedule No. GW-SD

(continued)

Sheet of




a. Firm Interstate Customers: Firm intrastate transmission shall be available for volumes delivered through firm interstate capacity rights or where Customer purchases or receives (1) gas delivered to Utility interconnection with an interstate pipeline on a firm basis, (2) intrastate California supplies delivered directly into the Utility's system, or (3) supplies that are delivered from the Utility's storage facilities, provided that the Utility has sufficient capacity to receive and redeliver all such volumes on a firm basis.

b. Interruptible Interstate, Existing Capacity: Firm intrastate transmission shall be available for volumes delivered by Customer or Customer's shipper to the Utility on an interruptible basis through interstate pipeline capacity in existence as of November 6, 1991 to the extent and so long as (1) the capacity of the interstate pipeline is not expanded so as to create a mismatch of interstate and intrastate capacity, and (2) the Utility has adequate intrastate system capacity to receive and redeliver all such volumes on a firm basis.

The Utility shall have no obligation to build new facilities to provide firm intrastate service for Customer's volumes delivered to the Utility on an interruptible basis through interstate pipeline capacity in existence as of November 6, 1991.

c. Interruptible Interstate, New Capacity: Firm intrastate transmission service shall be available for Customer's volumes delivered to the Utility on an interruptible basis across a new interstate pipeline or an expansion of an existing pipeline (as of November 6, 1991) provided that (1) Customer has given assurances acceptable to the Utility that any costs associated with enhancements of the Utility's intrastate system which are necessary to provide firm intrastate transmission service will be recovered by the Utility, (2) required enhancements are approved by the CPUC and are constructed and placed in service, and (3) the Utility has determined that it can physically provide firm intrastate service for all volumes.

7. For its core subscription and/or firm intrastate transmission service, Customer may elect full requirements service only for that portion of such usage serving (1) its own core customers' requirements, on an aggregate basis, and/or (2) the requirements, on an individual basis, of those noncore customers designated by the Customer as requesting such service; as set forth in the Customer's Contract. The Customer must provide the Utility sufficient information to establish the usage requirements of its designated full requirements load.

DT

T

L,TL | | |L

T

27163-G & 27163-G

32685-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

5Schedule No. GW-SD

(continued)

Sheet of


8. Customer's full requirements service loads are prohibited from being displaced through use of alternate fuels or bypass pipeline service except (1) in the event of curtailment, (2) to test alternate fuel capability, or (3) where the Utility has provided prior written authorization for the use of alternate fuels or bypass for temporary periods. The Utility shall have the right to review the Customer's records in order to determine compliance hereunder.

9. In the event of any unauthorized alternate fuel use or bypass which displaces Customer's full requirements load, Customer must provide the Utility written notice thereof quantifying the extent to which alternate fuel or bypass use occurred. Such notice must be provided prior to the end of the month in which the usage took place. Any such unauthorized use will be subject to a use-or-pay charge equal to 80% of the applicable transmission charge. No other use-or-pay charges are applicable to full requirements service.

10. For both its core subscription and firm intrastate transmission service (excluding Customer's full requirements load, if applicable), Customer must contract for a separate annual quantity of gas applicable for each contract year during the term of the Contract ("partial requirements"). The annual contract quantity may not be changed during the term of the Contract and must be broken down by month into fixed service quantities for each contract year during the Contract term. Customer may request changes to the monthly contract quantities on a month-to-month basis, however, the total of the monthly contract quantities for a contract year must equal the annual contract quantity. The monthly quantity breakdown may be established on the basis of seasonal variations in accordance with Customer's historic usage pattern. The Utility reserves the right to accept or reject any requested contract quantities after considering Customer's historic requirements and other evidence provided by Customer regarding operational changes affecting its consumption.

11. If at the end of a contract year, Customer's partial requirements core subscription usage is less than 75% of the core subscription contract quantity, Customer will pay (1) take-or-pay charges equal to 14% of the procurement charge for the last month of the contract year times the difference between Customer's actual usage and the 75% threshold; plus (2) use-or-pay charges equal to 80% of the average transmission charge for the last billing month of the contract year times the difference between the Customer's actual usage and the 75% threshold.


L,DT

T

L,TL | | | | | | | |L

L,T | | | |L

L,TL |L

T

27164-G & 27197-G

32686-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

5Schedule No. GW-SD

Sheet of


13. If at the end of a contract year, Customer's partial requirements firm intrastate transmission usage is less than 75% of the Customer's firm intrastate transmission contract quantity, Customer will pay use-or-pay charges equal to 80% of the average transmission charge for the last billing month of the contract year times the difference between the Customer's actual usage and the 75% threshold.






LL,TL |L

L,TLL

L,TL

T

T

T

L

T

32449-G

32687-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


1 5Schedule No. GW-SWG

(continued)

Sheet of

APPLICABILITY

Applicable for core subscription, firm intrastate transmission, and interruptible intrastate transmission service, and long-term storage service for Southwest Gas Corporation ("Customer") to Customer's service territory in southern California.

TERRITORY

Delivery points shall be as specified in the California Wholesale Gas Transportation and Storage Service Agreement ("Contract").

RATES


G-CS9, Core SubscriptionRate, per therm .................................................................................... 4.318¢

GT-F9, GT-I9, Firm & Interruptible Intrastate TransmissionRate, per therm .................................................................................... 4.318¢

The transmission charges set forth above shall be escalated annually as of each January 1 during the Contract term in accordance with the transmission charge escalation provisions set forth in the Contract. A 0.3¢ per therm surcharge will be added to the above transmission charges for the total quantities of gas to be delivered by exchange in the Big Bear and Victor Valley Districts. The transmission charges set forth above include an Interstate Transition Cost Surcharge (ITCS) component of 0.532¢ per therm pursuant to D.95-12-060.

Procurement Charges





T

32185-G

32688-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

5Schedule No. GW-SWG

(continued)

Sheet of

RATES (continued)

Core Subscription Reservation Charges


Rate, per therm ...................................................................................... 3.211¢


Storage Reservation Charges

Rate, per year ................................................................................. $1,321,752

The annual storage reservation charge set forth above shall be escalated annually as of each January 1 during the Contract term in accordance with the storage reservation charge escalation provisions set forth in the Contract. The annual reservation charge shall be billed in twelve equal monthly installments.

The above storage reservation charge shall be in lieu of the reservation charges set forth in Schedule No. G-LTS. The variable charges set forth in Schedule No. G-LTS shall be applicable to storage service hereunder.

Minimum Charge

The minimum monthly charge shall be the core subscription reservation charge, if applicable.

Billing Adjustments

Billing adjustments may be necessary to reflect changes in quantities used in developing prior periods' transportation charges.



D,N

D,NN

T

24514-G

32689-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of

SPECIAL CONDITIONS

GENERAL


2. As a condition precedent to service under this schedule, an executed California Wholesale Gas Transportation and Storage Service Agreement is required. The minimum term of such Contract shall be fifteen (15) years. All contracts, rates and conditions of service are subject to revision and modification as a result of Commission order.

3. In the event of curtailment, Customer will be curtailed in accordance with Rule No. 23. Penalties for violation of curtailment shall apply as set forth in Rule No. 23. If service to Customer's Priority 1 and 2A customers is in jeopardy, such customers shall be served in parity with Utility's Priority 1 and 2A customers as set forth in Rule No. 23.


STORAGE SERVICES

5. The Utility shall provide the Customer with storage service rights in the following capacities:

Annual firm withdrawal: 60 MMcfd

Annual firm inventory: 1.5 Bcf

Monthly firm injection: 12.5 MMcfd (April through September only)

6. On a daily or monthly basis, the Customer's storage service injections or withdrawals may exceed the capacities set forth above by up to ten percent (10%) so long as the Customer's scheduled injections plus total storage quantity in inventory does not exceed 1.5 Bcf at any time.

7. All terms and conditions of Schedule No. G-LTS, Long-Term Storage Service, shall apply to the storage services provided under this schedule except where such provisions would conflict with the charges and conditions set forth in this schedule or in the Customer's Contract.

T

24515-G & 24516-G

32690-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of


CORE SUBSCRIPTION

8. The service period for core subscription service under the Customer's Contract shall be two years.

9. Subsequent to the core subscription open season, the Customer may request additional core subscription service. The Utility shall accept such a request along with the requests of other customers on a first-come first-served basis to the extent Utility determines it is operationally feasible to provide such service. If access to core subscription service becomes restricted, the Utility shall maintain a list of the customers requesting such service (by time and date of request) and shall provide service in the order of the customer list in the event additional core subscription capacity becomes available.


10. The minimum service period for firm intrastate transmission service under the Customer's Contract shall be two years.





DT

T

T

L | | | | | | | |L

T

24516-G & 27198-G

32691-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


Sheet of


FIRM INTRASTATE TRANSMISSION (continued)

11. (continued)




TL

DL

L,TL

T

32692-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


1 6Schedule No. GW-VRN

(continued)

Sheet of

APPLICABILITY

Applicable for core subscription, firm intrastate transmission, and interruptible intrastate transmission service for the City of Vernon ("Customer").

TERRITORY

Delivery points shall be as specified in the Master Services Contract, Schedule A, Intrastate Transmission Service ("Contract").

RATES


G-CS10, Core Subscription Rate, per therm .................................................................................... 1.706¢

GT-F10, GT-I10, Firm & Interruptible Intrastate TransmissionRate, per therm .................................................................................... 1.706¢



ITCS-VRN, per therm ................................................................................ 0.789¢


Procurement Charges




32693-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

6Schedule No. GW-VRN

(continued)

Sheet of

RATES (continued)

Procurement Charges (continued)


Reservation Charges


Rate, per therm ...................................................................................... 3.211¢


Minimum Charge

The minimum monthly charge shall be the core subscription reservation charge if applicable.

Billing Adjustments

Billing adjustments may be necessary to reflect changes in quantities used in developing prior periods' transportation charges.



32694-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)


(continued)

Sheet of

SPECIAL CONDITIONS

GENERAL



3. In the event of curtailment, Customer will be curtailed in accordance with Rule No. 23. Penalties for violation of curtailment shall apply as set forth in Rule No. 23.








32695-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)


(continued)

Sheet of


FIRM INTRASTATE CUSTOMERS (continued)

6. (continued)


7. Pursuant to the provisions and guidelines of Decision No. 92-11-052, the Utility may negotiate a discounted contract with Customer for a service term of five years or more. Such a contract must be filed for prior CPUC approval under the CPUC's Expedited Application Docket (EAD) procedure as adopted in Decision No. 92-11-052.


8. For its core subscription and/or firm intrastate transmission service, Customer may elect full requirements service only for that portion of such usage serving (1) its own core customers' requirements, on an aggregate basis, and/or (2) the requirements, on an individual basis, of those noncore customers designated by Customer as requesting such service; as set forth in the Customer's Contract. Customer must provide Utility sufficient information to establish the usage requirements of its designated full requirements load.

9. Customer's full requirements service loads are prohibited from being displaced through use of alternate fuels or bypass pipeline service except (1) in the event of curtailment, (2) to test alternate fuel capability, (3) or where the Utility has provided prior written authorization for the use of alternate fuels or bypass for temporary periods. The Utility shall have the right to review the Customer's records in order to determine compliance hereunder.

10. In the event of any unauthorized alternate fuel use or bypass which displaces Customer's full requirement load, Customer must provide the Utility written notice thereof quantifying the extent to which alternate fuel or bypass use occurred. Such notice must be provided prior to the end of the month in which the usage took place. Any unauthorized alternate fuel or bypass use will be subject to a use-or-pay charge equal to 80% of the applicable transmission charge. No other use-or-pay charges are applicable to full requirements service.

32696-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)


(continued)

Sheet of



11. For both its core subscription and firm intrastate transmission service (excluding Customer's full requirements load, if applicable), Customer must contract for a separate annual quantity of gas applicable for each contract year during the term of the Contract. The annual contract quantity may not be changed during the term of the Contract and must be broken down by month into fixed service quantities for each contract year during the Contract term. Customer may request changes to the monthly contract quantities on a month-to-month basis, however, the total of the monthly contract quantities for a contract year must equal the annual contract quantity. The monthly quantity breakdown may be established on the basis of seasonal variations in accordance with Customer's historic usage pattern. The Utility reserves the right to accept or reject any requested contract quantities after considering Customer's historic requirements and other evidence provided by Customer regarding operational changes affecting its consumption.

12. If at the end of a contract year, Customer's partial requirements core subscription usage is less than 75% of the core subscription contract quantity, Customer will pay (1) take-or-pay charges equal to 14% of the procurement charge for the last month of the contract year times the difference between Customer's actual usage and the 75% threshold; plus use-or-pay charges equal to 80% of the transmission charge for the last billing month of the contract year times the difference between the Customer's actual usage and the 75% threshold.


14. If at the end of a contract year, Customer's partial requirements firm intrastate transmission usage is less than 75% of the firm intrastate transmission contract quantity, Customer will pay use-or-pay charges equal to 80% of the transmission charge for the last billing month of the contract year times the difference between the Customer's actual usage and the 75% threshold.


32697-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)


Sheet of


INTERRUPTIBLE INTRASTATE TRANSMISSION






31677-G,32186-G*,31679-G

32698-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

INTERCONNECT ACCESS SERVICE

1 2Schedule No. G-ITC

(continued)

Sheet of

APPLICABILITY

Applicable for natural gas transportation deliveries nominated and confirmed by or on behalf of intrastate shippers ("customers") into the Utility's intrastate system at the Wheeler Ridge and/or Kern River Station points of receipt ("interconnects") with the interstate pipeline systems of Kern River Gas Transmission Company, Mojave Pipeline Company and the Pacific Gas and Electric Company Expansion project. The charge is also applicable to volumes for storage and for core aggregation service. Schedule G-ITC is closed to new customers.

TERRITORY


RATES

Firm Access Service Reservation Charge

Daily Rate, per decatherm per day of annual firm access capacity reserved ........... 1.03¢

The customer shall be billed a firm access reservation charge each month and such charge shall be equal to the above rate times the number of days in the month, times the amount of annual firm access capacity reserved by or on behalf of the customer, as set forth in the Access Agreement. All firm access reservation charges are applicable whether such service is used or not.

SPECIAL CONDITIONS

1. The definitions of the principal terms used in the Utility's tariff schedules are contained in Rule No. 1.

2. As a condition precedent to firm access service under this schedule, an executed Access Agreement (Form No. 6600) shall be required.

3. The minimum term of firm access service under the Access Agreement shall be thirteen (13) years.

4. Service under this schedule shall be subject to the provisions of Rule No. 30 and the conditions set forth herein.

N

T

DL | | | | | | | | | |L

T

31679-G

32699-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

INTERCONNECT ACCESS SERVICE

2

(continued)

2Schedule No. G-ITC

Sheet of


5. All transportation nominations for deliveries at the Wheeler Ridge and/or Kern River Station interconnects into the Utility's system in an amount up to the customer's reserved firm access capacity, as set forth in the customer's Access Agreement, shall be considered to be nominations for firm access under this schedule. All transportation nominations at these interconnects in excess of the customer's reserved firm access capacity shall be considered to be nominations for interruptible access. In the event the customer has not reserved firm access capacity, all of the customer's nominations shall be considered to be for interruptible access.

6. In the event transportation nominations for deliveries into the Utility's system under this schedule for firm access are greater than available capacity, nominations shall be accepted on a pro rata basis.

7. The reservation surcharge applicable to firm access service under this schedule was determined by the Commission in Decision No. 95-04-078.

L

DT

D

T

32187-G

32700-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

BASIC STORAGE SERVICE

1 8Schedule No. G-BSS

(continued)

Sheet of

APPLICABILITY

Applicable for unbundled firm basic storage service to retail noncore customers. All noncore customers shall be eligible to receive storage service under this schedule subject to the availability of the Utility's reserved basic storage capacity. Basic storage service utilizes existing storage facilities only.

TERRITORY

Applicable for gas stored by the Utility within its service territory.

RATES

Reservation Charges

The Utility has pricing flexibility to charge different rates than those stated below provided the reservation charge is no higher than the maximum reservation charge allowed in the G-TBS tariff.

Annual Firm Inventory

Reservation Charge for annual inventory capacity reserved

Rate, per decatherm ....................................................................... 21.400¢

The above reservation charge shall apply to the customer's annual amount of reserved basic storage inventory and shall be billed in twelve equal monthly installments during the storage year.

One-Month Firm Injection

Reservation Charge for injection capacity reserved for one month

Rate, per decatherm ...................................................................... 9.425¢

The above reservation charge shall apply to the customer's reserved basic storage monthly injection capacity rate for the month reserved multiplied by the number of days in that month and shall be billed in twelve equal monthly installments during the storage year.

NN

I

R

L

32187-G & 32188-G

32701-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

8Schedule No. G-BSS

(continued)

Sheet of

RATES (continued)

Reservation Charges (continued)

Annual Firm Withdrawal

Reservation Charge for withdrawal capacity reserved for year

Rate, per decatherm/day .............................................................. $11.584

The above reservation charge shall apply to the customer's reserved basic storage annual withdrawal capacity and shall be billed in twelve equal monthly installments during the storage year.

All reservation charges for firm basic storage service are applicable whether the storage service is used or not and shall not be prorated under any circumstances.

Variable Charges

Injection Service

Peak Season, April through November

In-Kind Energy Charge for quantity delivered for injection

Rate, percent reduction .............................................................. 2.440%

O&M Injection Charge for quantity injected (less In-Kind Charge)

Rate, per therm ........................................................................... 0.127¢

Off-Peak Season, December through March

Variable storage charges shall not be applied for off-peak storage injection service provided under this schedule.

L

L

L,R

L |L

R

L

32188-G & 26729-G

32702-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

8Schedule No. G-BSS

(continued)

Sheet of

RATES (continued)

Variable Charges (continued)

Withdrawal Service

Peak Season, November through March

O&M Withdrawal Charge for quantity withdrawn

Retail, per therm ......................................................................... 0.177¢

Off-Peak Season, April through October

Variable storage charges shall not be applied for off-peak storage withdrawal service provided under this schedule.

For the storage year beginning April 1, 1993, the above-listed variable storage charges shall be based on the Utility's embedded cost. Effective April 1, 1994, all variable storage charges shall be based on the Utility's long-run marginal cost. Variable storage charges shall be established in the Utility's cost allocation proceedings.

Billing Adjustments

Billing adjustments may be necessary to reflect changes in quantities applicable under this schedule or changes in costs used in prior period's storage charges.


Transmission Charge for all quantities injected (less In-Kind Charge)

Rate, per therm ...................................................................................... 5.670¢

All gas delivered by the Utility for injection into storage under this schedule shall be assessed a transmission charge as shown above. This charge shall also be applied to all storage customers who (1) inject gas by imbalance trade under the provisions of Schedule No. G-IMB, or (2) receive a storage inventory transfer from another customer.

L

L

L

L,R

L

LL

L

26729-G & 27910-G

32703-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

8Schedule No. G-BSS

(continued)

Sheet of

RATES (continued)


Transmission Credit for all storage quantities withdrawn

Credit, per therm ................................................................................... 5.670¢

For all gas withdrawn by the Utility for storage service under this schedule, the customer shall receive a credit as shown above. This credit shall also be applied to all storage service customers who (1) withdraw gas by imbalance trade, or (2) who transfer inventory to another storage customer.

All other charges for transmission service shall be applied by the Utility in accordance with the provisions of the applicable tariff schedules.

SPECIAL CONDITIONS

General


2. Storage service under this schedule shall be curtailed in accordance with the provisions of Rule No. 23.

3. All terms and conditions of Rule No. 30 and Schedule No. G-IMB shall apply to the transportation of customer-owned gas in conjunction with the storage services provided under this schedule.

4. As a condition precedent to service under this schedule, an executed Master Services Contract, Schedule D, Basic Storage Service (Form Nos. 6597 and 6597-4) is required. All contracts, rates and conditions are subject to revision and modification as a result of Commission order.

5. The contract term for service hereunder shall be one year and shall begin on either April 1 or October 1 and continue thereafter for a twelve month period. The twelve month period beginning April 1 shall be termed the Spring storage year, and the twelve month period beginning October 1 shall be termed the Fall storage year with the term "storage year" referring to either a Spring or Fall storage year as appropriate.

L | | | | | | | | | | |L

L

27910-G & 27063-G

32704-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

8Schedule No. G-BSS

(continued)

Sheet of


6. The storage year shall be comprised of seasonal periods as follows:

Peak Season Off-Peak Season

Injection: April - November December - March

Withdrawal: November - March April - October

7. For transportation customers served hereunder, any storage gas remaining in inventory at the conclusion of the customer's storage contract term shall be considered an imbalance subject to the provisions of Schedule No. G-IMB, unless such inventory is rolled-over by the customer into the next storage year under the provisions of Special Condition 20 herein. For 100% core subscription customers served under this schedule, the Utility shall credit the customer at the applicable core subscription procurement charge, plus brokerage fee, then in effect for any such excess storage gas in inventory, unless such inventory is rolled-over by the customer under the provisions of Special Condition 20.

8. In the event any customer's storage contract is terminated, for whatever reason, prior to the completion of the term of such contract, the Utility may at its option immediately purchase any remaining inventory quantities from such customer at the applicable Buy-Back Rate stated in Schedule No. G-IMB. The Buy-Back purchase amount paid to the customer may be reduced by any outstanding amounts owed by the customer for any other services provided by the Utility.

Storage Nominations

9. Storage customers must provide the Utility with their monthly nominations for storage injections and/or withdrawals concurrently with their monthly nominations for transportation service made pursuant to Rule No. 30. During the month, storage customers may request changes to their storage nominations upon two days notice to the Utility. At its discretion and subject to its operational feasibility, the Utility may accept nominations for storage service withdrawals on less notice than set forth above.

10. Basic storage service customers may designate an agent to act on their behalf for the purpose of making storage nominations for their service under this schedule. Such agents may not aggregate the storage rights of the basic storage customer with the rights of any other storage customer.

L | | | | | | | | | | | | | | | | | | | |L

L

27063-G & 28090-G

32705-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)

8Schedule No. G-BSS

(continued)

Sheet of


Storage Imbalance Trading

11. Except during any period of system curtailment of transportation service, as described in Rule No. 23, storage customers may use their available storage inventory capacity and quantities to (1) offset the customer's own transportation imbalances, or (2) trade with other customers for their transportation imbalances, under the imbalance trading provisions set forth in Schedule No. G-IMB.

12. For storage injections and withdrawals performed through imbalance trading, the customer shall not be required to have storage injection or withdrawal rights but shall be assessed the variable charges set forth herein for such storage operations. For such storage trading activity, the storage transaction will be considered as occurring at the time the imbalance trade is completed by the Utility.

13. If gas is to be injected by the storage customer as a result of an imbalance trade, the customer must have sufficient available inventory space at the time the trade is completed by the Utility. If storage gas is to be withdrawn through an imbalance trade, the storage customer must have sufficient gas in inventory at the time the trade is completed.

Storage Inventory Transfers

14. Storage customers may mutually request to transfer gas in inventory from one customer's storage account to another. Such requests must be made by both parties to the inventory transfer and are limited to the inventory quantity available for transfer and the available inventory capacity of the receiving customer at the time the transfer is completed by the Utility. All transfers may be accepted or rejected, in whole or in part, by the Utility and shall not be deemed accepted until such time as the Utility notifies both customers of the completion of the transfer.

Basic Service Storage Rights

15. The Utility shall offer a basic storage service package to all of its retail noncore customers. The basic service package shall provide such customers with a limited amount of firm storage inventory, injection and withdrawal capacity. The maximum amount of capacity available for an individual customer under basic storage service shall be based on the customer's average winter daily usage. The average winter daily usage shall be equal to the higher amount of the customer's noncore usage from December 1 through March 31, divided by the average number of operating days of the customers facility during this time period, for the prior two calendar years.

16. Under basic storage service, noncore customers may contract for firm storage withdrawal capacity. The awarded withdrawal capacity shall be stated as a daily capacity rate and shall be available to the customer throughout the storage year.

L | | | | | | | | | | | | | | | | | | | | | | |L

L

28090-G & 28091-G

32706-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)

8Schedule No. G-BSS

(continued)

Sheet of


Basic Service Storage Rights (continued)

17. In addition to withdrawal capacity, the basic storage service customer may contract for storage inventory capacity up to seven times the customer's awarded basic service withdrawal capacity. This inventory capacity shall be available to the customer throughout the storage year.

18. The basic storage service customer must also contract for one month of firm storage injection capacity. The customer must contract for that amount of injection capacity necessary to fill the customer's awarded inventory capacity over a one month period.

19. Basic service injection capacity shall be limited to those peak season injection months the Utility is able to make such service available. Prior to the start of the storage year, customers shall be required to designate their order of preference for the available injection months. If a customer's primary choice month is oversubscribed, the customer's awarded injection capacity for that month shall be prorated downward to a level consistent with the injection capacity available. The customer's remaining injection capacity shall be allocated to the customer's second and then third designated choice of injection month and awarded in the same manner as for the primary month. Once established, the customer's awarded injection capacity shall be stated in the customer's contract as a daily capacity rate by month and shall only be available for the designated month or months.

Year-to-Year Participation

20. At the end of each storage year, current basic storage customers will automatically have their contracted basic storage service rights rolled over to the following storage year, including any quantities in inventory at the end of the storage year. The amount of the customer's basic storage rights eligible to be rolled over to the next storage year shall be restricted to the limitations on capacity rights described above.

21. Also on or before March 1 of each year for the Spring storage year and September 1 of each year for the Fall storage year, customers not currently receiving basic storage service may request to receive such service for the following storage year. For such customers, service availability shall be limited to that reserved basic service capacity remaining after the requirements of current basic storage customers are met.

L | | | | | | | | | | | | | | | | | | | | | | | | | |L

L

28091-G & 24535-G

32707-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)

8Schedule No. G-BSS

Sheet of


Year-to-Year Participation (continued)

22. Once the Utility has initially established the basic storage service capacity to be awarded to both new and current basic service customers for the upcoming storage year, any unsubscribed annual firm withdrawal capacity, and the corresponding inventory and injection capacity rights, shall then be offered on a pro rata basis to all customers who were initially awarded withdrawal capacity in an amount less than their average winter daily usage. If accepted, the additional capacity award shall be reflected in the customer's storage contract.

Core Subscription Storage

23. Core subscription customers may receive basic storage service under this schedule. The Utility shall inject such customer's core subscription storage quantities in the month or months designated in the customer's contract.

24. For the customer's contracted core subscription injection quantities, the customer shall be charged the core subscription procurement rate, plus brokerage fee, in effect during the month such quantities are injected. For core subscription withdrawal quantities, the customer shall be charged the full cost of core subscription service and shall receive a credit based on the core subscription procurement charge, plus brokerage fee, in effect during the period such quantities are withdrawn.

25. For basic storage service customers who are 100% core subscription, storage inventory may only be withdrawn during periods of curtailment of the customer's transmission service.

26. For basic storage service customers who split their requirements between core subscription service and transportation service, the customer's core subscription storage gas shall be treated as customer-owned gas and may be (1) used together with the customer's transportation deliveries to storage, or (2) traded under the imbalance trading provisions set forth in Schedule No. G-IMB.

Secondary Market

27. Basic storage customers may assign their contract storage rights in full to another noncore customer upon 90 days written notice to the Utility.

L | | | | | | | | | | | | | | | | | | | | | | | | | |LD

T

31922-G

32708-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

AUCTION STORAGE SERVICE

1 8Schedule No. G-AUC

(continued)

Sheet of

APPLICABILITY

Applicable for unbundled as-available storage service to noncore customers, contracted marketers, marketer/agents, and core transportation customers; and to wholesale customers, core aggregators, and the Utility's gas supply department for any storage capacity that is additional to their allocated core storage rights. All eligible participants are collectively referred to herein as "customers" unless otherwise specified.

TERRITORY


RATES

Reservation Charges

Firm Inventory

Reservation Charge for inventory capacity reserved

The inventory reservation charge shall be equal to the customer's actual price and capacity bid for inventory, as set forth in the customer's storage contract, and shall be billed in twelve equal monthly installments during the storage year, unless Special Condition 25 applies.

As-Available Injection

Reservation Charge for as-available injection capacity bid

The injection reservation charge shall be based on the customer's actual price and capacity rate bid for as-available injection service, as set forth in the customer's storage contract, and shall be billed in twelve equal monthly installments during the storage year, unless Special Condition 25 applies.

As-Available Withdrawal

Reservation Charge for as-available withdrawal capacity bid

The withdrawal reservation charge shall be based on the customer's actual price and capacity rate bid for as-available withdrawal service, as set forth in the customer's storage contract, and shall be billed in twelve equal monthly installments during the storage year, unless Special Condition 25 applies.

T

T

T

T

32189-G

32709-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

8Schedule No. G-AUC

(continued)

Sheet of

RATES (continued)


The reservation charges for firm inventory and as-available injection and withdrawal capacity under auction storage service shall be set annually by customer bid through an open season to be conducted by the Utility prior to the start of the storage year, as described in Special Condition 15 herein. The reservation charge for inventory capacity under this schedule is applicable whether the service is used or not. The reservation charges for as-available injection and withdrawal service under this schedule are applicable whether the services are made available by the Utility or not. Reservation charges shall not be prorated under any circumstances.

Variable Charges

Injection Service



Rate, percent reduction .............................................................. 2.440%


Retail, per therm ....................................................................... 0.127¢

Wholesale, per therm ................................................................. 0.127¢



Withdrawal Service



Retail, per therm ........................................................................ 0.177¢

Wholesale, per therm .................................................................. 0.177¢

T

RR

RR

T

26731-G

32710-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

8Schedule No. G-AUC

(continued)

Sheet of

RATES (continued)

Variable Charges (continued)



For the storage year beginning April 1, 1993, the variable storage charges shown herein shall be based on the Utility's embedded costs. Effective April 1, 1994, all variable storage charges shall be based on the Utility's long-run marginal costs. Variable storage charges shall be established in the Utility's cost allocation proceedings.

Billing Adjustments




Rate, per therm .................................................................................... 5.670¢

All gas delivered by the Utility for injection into storage under this schedule shall be assessed a transmission charge as shown above. This charge shall also be applied to all storage customers who (1) inject gas by imbalance trade under the provisions of Schedule No.G-IMB, or (2) receive a storage inventory transfer from another storage customer.

Transmission Credit for all quantities withdrawn

Credit, per therm ................................................................................. 5.670¢

For all gas withdrawn by the Utility for storage service under this schedule, the customer shall receive a credit as shown above. This credit shall also be applied to all storage service customers who (1) withdraw gas by imbalance trade, or (2) who transfer inventory to another storage customer.


T

26036-G

32711-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

8Schedule No. G-AUC

(continued)

Sheet of

SPECIAL CONDITIONS

General


2. Service under this schedule shall be curtailed in accordance with the provisions of Rule No. 23.


4. As a condition precedent to service under this schedule, an executed Master Services Contract, Schedule E, Auction Storage Service (Form Nos. 6597 and 6597-5) is required. All contracts, rates and conditions are subject to revision and modification as a result of Commission order.

5. The contract term for service under this schedule shall be one year and shall begin on April 1 and continue thereafter for a twelve month period. This twelve month period shall be termed the storage year.

6. The storage year shall be comprised of seasonal periods as follows:

Peak Season Off-Peak SeasonInjection: April - November December - MarchWithdrawal November - March April - October

7. For customers served under this schedule, any storage gas remaining in inventory at the conclusion of the customer's storage contract term shall be considered an imbalance subject to the provisions of Schedule No. G-IMB, unless the customer obtains sufficient inventory capacity rights for the following storage year.

8. In the event the customer's storage contract is terminated, for whatever reason, prior to the completion of the term of such contract, the Utility may at its option immediately purchase any remaining inventory quantities from such customer at the applicable Buy-Back Rate stated in Schedule No. G-IMB. The Buy-Back purchase amount paid to the customer may be reduced by any outstanding amounts owed by the customer for any other services provided by the Utility.

T

24540-G

32712-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

8Schedule No. G-AUC

(continued)

Sheet of


Storage Nominations

9. Storage customers must provide the Utility with their monthly nominations for storage injections and/or withdrawals concurrently with their monthly nominations for transportation service made pursuant to Rule No. 30, or their targeted sales nominations made pursuant to Schedule No. G-TARG. During the month, storage customers may request changes to their nominations upon two days notice to the Utility.

10. Auction storage service customers may designate an agent to act on their behalf for the purpose of making storage nominations for their service under this schedule.




13. If gas is to be injected by the storage customer as a result of an imbalance trade, the customer must have sufficient available inventory space at the time the trade is completed by the Utility. If storage gas is to be withdrawn through an imbalance trade, the storage customer must have sufficient gas in inventory at the time the trade is completed.



T

27078-G

32713-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)

8Schedule No. G-AUC

(continued)

Sheet of


Auction Service Open Seasons

15. The Utility shall announce its auction service availability and solicit bids for firm storage inventory, as-available injection capacity and as-available withdrawal capacity during an annual open season to be held each February. The annual open season shall be conducted in accordance with the provisions of the Utility's Annual Auction Storage Service Bid Package. The Utility must receive all bids for auction storage service by the announced end of the open season. All submitted bids must include an executed Auction Storage Service contract.

16. For auction inventory service, the bid must indicate a reservation price and the corresponding inventory quantity, in decatherms, requested by the customer at such bid price. There shall be no minimum quantity limit on inventory capacity bids and customers may make multiple bids at varying reservation bid prices. The Utility shall notify all successful bidders of their awarded storage inventory capacity no later than one week after the announced end of the open season.

17. For as-available injection and withdrawal service, all bids must indicate a reservation price and the corresponding capacity rate, in decatherms per day, requested by the customer at such bid price. There shall be no minimum capacity rate limit for injection and withdrawal capacity bids and customers may make multiple bids at varying reservation bid prices. All bids for as-available injection and withdrawal capacity shall be awarded and the price bid by customers shall establish the priority queue for each service. Customers bidding for as-available injection and/or withdrawal service may, however, designate as part of their bid that the Utility reject the bid in the event that their bid for auction inventory is not awarded. The Utility shall notify all successful bidders of their awarded as-available injection and/or withdrawal priority queue positions no later than one week after the announced close of the open season.

18. From time to time, the Utility may announce special auction service availability. The open seasons for such special auction service shall be conducted in accordance with the provisions of the Utility's Special Auction Storage Service Bid Package. The applicable service term and any service restrictions shall be set forth in the Bid Package. All other provisions of this Schedule No. G-AUC shall apply unless otherwise provided for in the Bid Package.

As-Available Priority Queue

19. For as-available injection and withdrawal capacity, the Utility shall maintain a queue for each service establishing the order of priority for all such auction storage customers. The as-available priority queue shall list all as-available service customers in order of their reservation bid price, from highest to lowest, for the particular type of as-available capacity.

D

T

27079-G & 31923-G

32714-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)

8Schedule No. G-AUC

(continued)

Sheet of


As-Available Priority Queue (continued)

20. The Utility shall post the priority queue for as-available injection and withdrawal service on its GasSelect system. The order of such auction service customers shall be indicated by an identifier code with the applicable storage capacity rate, in decatherms per day, shown for each such code. The corresponding customer name and reservation bid price for each code shall not be indicated.

21. Prior to the start of each month, the Utility shall notify all auction storage customers of the amount of as-available injection or withdrawal capacity expected to be made available beginning on the first day of the month. Such notice shall be made at least nine (9) business days prior to the start of the month. Auction storage customers must provide the Utility with their nominations for as-available injections or withdrawals concurrently with their nominations for transportation service. The Utility shall accept such storage nominations in the order of the as-available priority queue up to the amount of capacity expected to be available. If necessary, customer storage nominations for the last queue position accepted shall be prorated.

22. At any time during the month, the Utility may reduce or eliminate the amount of injection or withdrawal capacity made available under this schedule. In such an event, the Utility shall reduce customer storage nominations accepted for such capacity in reverse order of the applicable as-available priority queue.

23. Customers may revise their storage nominations for as-available service upon two days notice subject to service availability and their position on the priority queue. In the event new or revised storage nominations reduce the availability of injection or withdrawal storage capacity to other auction service customers, the Utility shall adjust the storage nominations of such affected customers downward and provide notice thereof accordingly.

24. In the event additional injection or withdrawal capacity becomes available during the month for service under this schedule, the Utility shall provide notice of such additional service availability to those auction storage customers whose most recent storage nominations were not accepted in full.

Advance Reservation Charges

25. Customers, other than end-use customers of the Utility, awarded service under this schedule shall be required to pay one-quarter (25%) of their total annual reservation charge in the first month of the storage year. The balance of the total annual reservation charge shall be billed in equal monthly installments over the remaining storage year.

DL

L,TL |L

T

27081-G

32715-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)

8Schedule No. G-AUC

Sheet of


Secondary Market

26. Auction storage customers may assign their contract storage rights in full to another customer upon 90 days notice to the Utility.

T

T

32190-G

32716-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

LONG-TERM STORAGE SERVICE

1 8Schedule No. G-LTS

(continued)

Sheet of

APPLICABILITY

Applicable for unbundled firm long-term storage service to noncore customers, contracted marketers, marketer/agents, core transportation customers and off-system customers, as defined in Rule No. 1; and wholesale customers and core aggregators for any storage capacity that is additional to their allocated core storage capacity. All eligible participants are collectively referred to herein as "customers" unless otherwise specified.

TERRITORY


RATES

Reservation Charges

The Utility has pricing flexibility to charge different rates than those stated below provided the reservation charge is no higher than the maximum reservation charge allowed in the G-TBS tariff.

Annual Firm Inventory

Reservation Charge for annual firm inventory capacity reserved

Rate, per decatherm ....................................................................... 21.400¢

The above reservation charge shall apply to the customer's reserved annual firm inventory and shall be billed in twelve equal monthly installments for each storage year during the long-term contract, unless Special Condition 22 applies.

Monthly Firm Injection

Reservation Charge for monthly firm injection capacity reserved

Rate, per decatherm per day .......................................................... 9.425¢

The above reservation charge shall apply to the customer's reserved monthly injection capacity for the contracted month multiplied by the number of days in that month and shall be billed in twelve equal monthly installments for each storage year during the long-term contract, unless Special Condition 22 applies.

NN

I

T

R

TL

T

32190-G & 31925-G

32717-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

8Schedule No. G-LTS

(continued)

Sheet of

RATES (continued)


Annual Firm Withdrawal

Reservation Charge for exisiting annual firm withdrawal capacity reserved

Rate, per decatherm per day ........................................................ $11.584

Reservation Charge for expansion annual firm withdrawal capacity reserved

Base rate, without risk premium, per decatherm per day ............... $14.060

Maximum risk premium, per decatherm per day ........................ $5.766

The charge for expansion annual firm withdrawal capacity shall be equal to the base rate shown above plus a risk premium negotiated by the Utility and the customer. The negotiated risk premium shall not be more than the maximum rate set forth above. The customer's total rate for expansion withdrawal capacity, base rate plus risk premium, shall be set forth in the customer's storage contract.

For long-term storage contracts executed prior to January 1, 1995, the Utility has indicated in the advice letters previously filed for these contracts whether withdrawal service is provided from existing or expansion storage capacity.

For long-term storage contracts executed on and after January 1, 1995, the Utility shall indicate in the contract whether withdrawal service is to be provided from existing or expansion storage capacity.

The above reservation charge shall apply to the customer's reserved annual firm withdrawal capacity and shall be billed in twelve equal monthly installments for each storage year during the long-term contract, unless Special Condition 22 applies.

All reservation charges for firm long-term storage service are applicable each storage year for the entire term of the customer's long-term contract, whether the contracted storage services are used or not.

L

L,R

T

L

T

31925-G & 32191-G

32718-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

8Schedule No. G-LTS

(continued)

Sheet of

RATES (continued)

Variable Charges

Injection Service



Rate, percent reduction ................................ 2.440%


Retail, per therm ......................................................................... 0.127¢

Wholesale, per therm ................................................................... 0.127¢



Withdrawal Service



Retail, per therm ......................................................................... 0.177¢

Wholesale, per therm ................................................................... 0.177¢



The variable storage charges set forth in this schedule are based on the Utility's long-run marginal costs. For service under Schedule Nos. G-BSS and G-AUC, the variable storage charges for the storage year beginning April 1, 1993 shall be based on the Utility's embedded costs. Effective April 1, 1994, all variable storage charges shall be based on long-run marginal costs. Variable storage charges shall be established in the Utility's cost allocation proceedings.

L | | |L

R

R

R

R

T

26780-G & 26781-G

32719-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

8Schedule No. G-LTS

(continued)

Sheet of

RATES (continued)

Billing Adjustments




Rate, per therm ........................................... 5.670¢

All gas delivered by the Utility for injection into storage under this schedule shall be assessed a transmission charge as shown above. This charge shall also be applied to all storage customers who (1) inject gas through imbalance trading under the provisions of Schedule No. G-IMB, or (2) receive a storage inventory transfer from another storage customer.

Transmission Credit for all quantities withdrawn

Credit, per therm ......................................... 5.670¢

For all gas withdrawn by the Utility for storage service under this schedule, the customer shall receive a credit as shown above. This credit shall also be applied to all storage customers who (1) withdraw gas by imbalance trade, or (2) who transfer inventory to another storage customer.

The above provisions shall not apply to off-system customers storing gas for ultimate use east of California. The transmission charges for such storage service shall be set forth in the off-system customer's long-term storage contract.


SPECIAL CONDITIONS

General


2. Storage service under this schedule shall be curtailed in accordance with the provisions of Rule No. 23.

T

26781-G

32720-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

8Schedule No. G-LTS

(continued)

Sheet of


General (continued)


4. As a condition precedent to service under this schedule, an executed Master Services Contract, Schedule F, Long-Term Storage Service (Form Nos. 6597 and 6597-6) is required. All contracts, rates and conditions are subject to revision and modification as a result of Commission order.

5. The minimum contract term for service under this schedule shall be three years and the maximum contract term shall be fifteen years.

6. The storage year for long-term contract service shall begin on April 1 and continue thereafter for a twelve month period. Eligible customers may contract for long-term storage service anytime during this period but the annual reservation charges applicable for the initial storage year shall not be prorated unless otherwise agreed to by the Utility. The storage year shall be comprised of seasonal periods as follows:

Peak Season Off-Peak Season

Injection: April - November December - MarchWithdrawal: November - March April - October

7. For customers served under this schedule, any storage gas remaining in inventory at the conclusion of the customer's storage contract term shall be considered an imbalance subject to the provisions of Schedule No. G-IMB, unless the customer has obtained sufficient inventory capacity rights for the following storage year.

8. In the event the customer's storage contract is terminated, for whatever reason, prior to the completion of the term of such contract, the Utility may at its option immediately purchase any remaining inventory quantities from such customer at the applicable Buy-Back Rate stated in Schedule No. G-IMB. The Buy-Back purchase amount paid to the customer may be reduced by any outstanding amounts owed by the customer for any other services provided by the Utility.

T

26782-G

32721-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


6

(continued)

8Schedule No. G-LTS

(continued)

Sheet of


Storage Nominations

9. Storage customers must provide the Utility with their monthly nominations for storage injections and/or withdrawals concurrently with their monthly nominations for transportation service made pursuant to Rule No. 30, or their targeted sales nominations made pursuant to Schedule No. G-TARG. During the month, storage customer may request changes to their storage nominations upon two days notice to the Utility.

10. Long-term storage service customers may designate an agent to act on their behalf for the purpose of making storage nominations for their service under this schedule.




13. If gas is to be injected by the storage customer as a result on an imbalance trade, the customer must have sufficient available inventory space at the time the trade is completed by the Utility. If storage gas is to be withdrawn through an imbalance trade, the storage customer must have sufficient gas in inventory at the time the trade is completed.



T

26783-G

32722-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


7

(continued)

8Schedule No. G-LTS

(continued)

Sheet of


Contract Approval

15. All contracts for service under this schedule shall be filed by advice letter for CPUC approval. The Utility and the customer may negotiate special provisions for long-term storage service. Such provisions may include reservation charges other than those stated in this schedule. Any such special provisions or reservation charges shall be set forth in the customer's long-term storage contract filed with the CPUC.

Service Availability

16. Service under this schedule shall be subject to the availability of the Utility's existing unsubscribed firm storage capacity. The Utility shall not be obligated to provide firm long-term storage service in the event the Utility would have to expand its storage capacity in order to provide such service.

17. Customers may request the Utility to expand its firm storage capacity and thereby provide long-term firm storage service under this schedule. Any such expansion of the Utility's storage capacity shall be subject to the requesting customer providing sufficient financial guarantees, to the sole satisfaction of the Utility, for the recovery of any and all costs associated with the expansion of the Utility's storage facilities.

Core Subscription Storage

18. Core subscription customers may receive long-term storage service under this schedule. The Utility shall inject such customer's core subscription storage quantities in the month or months designated in the customer's long-term storage service agreement.

19. For the customer's contracted core subscription injection quantities, the customer shall be charged the core subscription procurement rate, plus brokerage fee, in effect during the month such quantities are injected. For core subscription withdrawal quantities, the customer shall be charged the full cost of core subscription service and shall receive a credit based on the core subscription procurement charge, plus brokerage fee, in effect during the period such quantities are withdrawn.

20. For long-term storage service customers who are 100% core subscription, storage inventory may only be withdrawn during periods of curtailment of the customer's transmission service.

21. For long-term storage service customers who split their requirements between core subscription service and transportation-only service, the customer's core subscription storage gas shall be treated as customer-owned gas and may be (1) used together with the customer's transportation deliveries to storage, or (2) traded under the imbalance trading provisions set forth in Schedule No. G-IMB.

T

31926-G & 26785-G

32723-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


8

(continued)

8Schedule No. G-LTS

Sheet of


Advance Reservation Charges

22. Customers, other than end-use customers of the Utility, awarded service under this schedule shall be required to pay one-quarter (25%) of their total annual reservation charge in the first month of the storage year. The balance of the total annual reservation charge shall be billed in equal monthly installments over the remaining storage year.

Creditworthiness

23. For service under this schedule, the customer shall be required to undergo a creditworthiness check whereby the Utility shall establish the customer's credit limit. Customers shall be required to pay the Utility $500 per year for an annual credit check to be performed by an agency of the Utility's choice. The credit review will establish a credit limit for the customer based upon the customer's expected annual participation for long-term storage service. If the customer's credit limit is less than the customer's obligations for service under this schedule, the Utility shall require the customer to advance a larger portion of the reservation charges hereunder to compensate for such credit deficiency.

Secondary Market

24. Long-term storage customers may assign their contract storage rights in full to another customer upon 90 days notice to the Utility. Such assignment shall be subject to the storage assignee meeting all of the Utility's creditworthiness requirements.

D

T

T

L

L,TLL

T

32191.1-G

32724-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSACTION BASED STORAGE SERVICE(Experimental)

1 7Schedule No. G-TBS

(continued)

Sheet of

APPLICABILITY

Applicable for unbundled firm inventory and firm or as-available injection and withdrawal storage services to noncore transportation customers, wholesale customers, contracted marketers, and marketers/agents; and to core transportation customers; core aggregators, and the Utility's gas supply department for any storage capacity that is additional to their allocated core storage rights. All eligible participants are collectively referred to herein as "customers" unless otherwise specified.

Under this storage service rate schedule, the Utility shall provide unbundled storage services for a minimum term of one month and not more than three years. The storage service package and associated charges shall be negotiated on a transactional basis between the customer and the Utility dependent on market conditions and customer needs (Special Conditions 8 through 12 of this schedule provide a description of this process).

This is an experimental rate schedule under which the Utility may offer service until such time as a new storage program is implemented by the Commission in OII 99-07-003. On this date, the Utility will discontinue offering any future service under this schedule and will only provide service to those customers with Contracts executed prior to this date and only until the expiration date of such Contracts.

TERRITORY


RATES

Storage service rates under Schedule G-TBS consist of Reservation Charges, Variable Charges and Transmission Charges/Credits.

Reservation Charges

Firm Storage Service

The reservation charge, or price, for G-TBS storage service will be established between the customer and the Utility on a transactional basis dependent upon market conditions and the specific storage service to be provided to the customer. The price established for such service shall be no more than 120% of the sum of the individual charges set forth in Schedule No. G-LTS for firm inventory, injection and withdrawal services and no less than $0.01 per decatherm of inventory capacity reserved. Based on the current reservation charges in Schedule No. G-LTS the maximum reservation charge under G-TBS shall be no more than $14.271 per decatherm of inventory capacity reserved. The price shall be set forth in the Contract and shall be billed in equal monthly installments over the term of the Contract, unless Special Condition 13 applies. The price under this schedule is applicable whether the service is used or not.

T

I

32192-G

32725-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSACTION BASED STORAGE SERVICE(Experimental)

2

(continued)

7Schedule No. G-TBS

(continued)

Sheet of

RATES (continued)


As-Available Injection and Withdrawal

Reservation charges for as-available injection and withdrawal capacity provided under this schedule shall not be applicable unless otherwise established in the Contract.

Variable Storage Charges

Injection Service

Peak Season (April through November)

In-Kind Energy Charge, applied to all quantities delivered for injectionRate, percent reduction ............................................................. 2.440%

O&M Injection Charge, applied to all quantities injected (less In-Kind Charge)Retail, per therm ...................................................................... 0.127¢Wholesale, per therm ................................................................ 0.127¢

Off-peak Season (December through March)

Variable charges shall not be applied for off-peak storage injection service provided under this schedule unless otherwise set forth in the Contract.

Withdrawal Service

Peak Season (November through March)

O&M Withdrawal Charge, applied to all quantities withdrawnRetail, per therm ....................................................................... 0.177¢Wholesale, per therm ................................................................. 0.177¢

Off-peak Season (April through October)

Variable charges shall not be applied for off-peak storage withdrawal service provided under this schedule unless otherwise specified in the Contract.

RR

RR

31498-G

32726-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

SURCHARGE TO FUND CALIFORNIA ALTERNATE RATES FOR ENERGY DISCOUNT

1 1Schedule No. G-CFS

Sheet of

APPLICABILITY

Applicable to all gas sales and transportation services rendered under all tariff rate schedules authorized by the Commission with the exception of Electric Generation including cogeneration, Enhanced Oil Recovery, low-income discount sales, Wholesale service, negotiated contract services executed prior to September 7, 1989, and street lighting.

TERRITORY

This schedule is applicable within the entire territory served by SoCalGas.

RATES

Surcharge

For all service, per therm, per meter, per month .......................................... 0.121¢

D

T,RD

32193-G

32727-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

HUB LOANING

1 1Schedule No. G-LOAN

Sheet of

APPLICABILITY

Applicable for Loaning service provided to qualified users of Utilities' Hub service. Qualification requirements, characteristics of service and operational requirements are defined in Rule No. 37. As described in Rule No. 37, Hub Service is available on an interruptible-only basis. Hub Loaning service definitions are set forth in Rule No. 1. If a transaction occurs involving the Loaning of gas, necessitating an additional gas Wheeling transaction, a Wheeling rate charge, as described under Schedule No. G-WHL, shall also apply.

RATES

Loaning rate, minimum charge ............................................ $50 minimum Loaning rate, maximum charge ........................................... *63.49¢ per decatherm maximum

Loaning rates will be set on an individual transaction basis and shall depend upon market conditions. The rate set forth for the transaction shall fall within the minimum charge and maximum charge set forth above. The maximum charge set forth above reflects the following costs: 1) a storage inventory reservation fee of 32.70¢/Dth as cited in Schedule No. G-LTS, plus 2) variable injection and withdrawal costs of 1.95¢/Dth and 2.72¢/Dth, respectively, plus 3) fixed injection and withdrawal costs of 14.40¢/Dth and 11.72¢/Dth, respectively. The minimum rate of $50 reflects the incremental administrative and overhead costs necessary to carry out a Loaning transaction.

* An additional fuel charge may be levied if the requested service will cause an incremental fuel cost

for compression. Customers will be notified, in advance of any service being provided, of the need for incremental fuel, in which case service users shall pay an in-kind fuel charge of 2.44%.

I

IR,II,I

32194-G

32728-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

HUB PARKING

1 1Schedule No. G-PRK

Sheet of

APPLICABILITY

Applicable for Parking service provided to qualified users of Utilities' Hub Service. Qualification requirements, characteristics, of service and operational requirements are defined in Rule No. 37. As described in Rule No. 37, Hub Service is available on an interruptible-only basis. Hub Parking service definitions are set forth in Rule No. 1. If a transaction occurs involving the Parking of gas, necessitating an additional gas Wheeling transaction, a Wheeling rate charge as described under the Schedule No. G-WHL, shall also apply.

RATES

Parking rate, minimum charge ............................................... $50 minimumParking rate, maximum charge .............................................. *63.49¢ per decatherm maximum

Parking rates will be set on an individual transaction basis and shall depend upon market conditions. The rate set forth for the transaction shall fall within the minimum charge and maximum charge set forth above. The maximum charge set forth above reflects the following costs: 1) a storage inventory reservation fee of 32.70¢/Dth as cited in SoCalGas' Schedule No. G-LTS, plus 2) variable injection and withdrawal costs of 1.95¢/Dth and 2.72¢/Dth, respectively, plus 3) fixed injection and withdrawal costs of 14.40¢/Dth and 11.72¢/Dth, respectively. The minimum rate of $50 reflects the incremental administrative and overhead costs necessary to carry out a Parking transaction.

* An additional fuel charge may be levied if the requested service will cause an incremental fuel cost for compression. Customers will be notified, in advance of any service being provided, of the need for incremental fuel, in which case service users shall pay an in-kind fuel charge of 2.44%.

I

IR,II,I

32195-G

32729-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

HUB WHEELING SERVICE

1 1Schedule No. G-WHL

Sheet of

APPLICABILITY

Applicable for Wheeling service provided to qualified users of Utilities' Hub Service. Qualification requirements, characteristics of service and operational requirements are defined in Rule No. 37. As described in Rule No. 37, Hub Service is available on an interruptible basis only. Wheeling service definitions are set forth in Rule No. 1.

RATES

Wheeling rate, minimum charge ........................................... $50 minimumWheeling rate, maximum charge ........................................... 55.69¢ per decatherm maximum

Wheeling rates will be set on an individualized basis, depending upon market conditions and will fall within the minimum and maximum charges. The maximum rate set forth above reflects the following costs: 1) the average rate for the noncore class defined as equal to the total transportation revenue for the class divided by the average yearly throughput for that class, and 2) an allocation for the California Alternate Rates for Energy (CARE) Surcharge. The minimum rate of $50 reflects the incremental administrative and overhead costs necessary to carry out a Wheeling transaction.

R

30006-G*

32730-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

3

(continued)

14Rule No. 01

(continued)

Sheet of

Contract Quantity, Monthly: The monthly natural gas delivery quantity contracted for during each contract month as set forth in the customer's applicable service agreement. This quantity is based on the customer's historical usage or negotiated based on the customer's operational forecast.

Core Subscription Service: Utility procurement service available to noncore customers. Core subscription service requires a two-year contract term commitment as identified in the customer's applicable rate schedule.

Core Service: Service to end-use Priority 1 or Priority 2A as set forth in Rule No. 23. Priority 1 core service includes: (1) all residential usage regardless of size; and (2) all commercial and industrial customers whose usage does not exceed 20,800 therms per active month on an annualized basis for a period of any 12 contiguous months within the most recent 24-month period, excluding usage for electric generation and usage reclassified to noncore service pursuant to economic practicality prior to September 29, 1993. An active month is defined as any month during which the customer's usage exceeds 1,000 therms. Priority 2A core service includes all commercial and industrial customers whose usage is 20,800 therms per active month or greater on an annualized basis for a period of any 12 contiguous months within the most recent 24-month period. Priority 2A customers have the option of electing noncore service, in whole or in part.

Critical Customer: One where danger to human life, health or safety is involved, and includes customers such as hospitals, other state-licensed health care facilities, medical research facilities, medical facilities at military installations and detention facilities, municipal water pumping plants and sanitation facilities.

Curtailment: Utility initiated suspension of natural gas service. Utility may temporarily reduce the daily quantity of gas it will transport or deliver or terminate service entirely for certain service categories as needed for operational requirements. Curtailment is implemented when, in the Utility's judgment, there exists a restriction or limitation on Utility transmission or distribution pipelines necessary for the acceptance, transportation or subsequent redelivery of natural gas resulting in Utility being unable to meet its operational, contractual or gas customers' requirements or when the Utility has a deficiency of natural gas supply available to meet its operational, contractual or sales customers' requirements.

Curtailment Year: The period October 1 of each year through September 30 of the next calendar year.

Customer: The person or entity in whose name service is rendered as evidenced by the signature on the application, contract, or agreement for that service, or in the absence of a signed instrument, by the receipt and payment of bills regularly issued in his name.

Customer-Owned Gas: Natural gas transported by the Utility for customer's own use where title to such natural gas is held by the customer and is not a part of the Utility-owned system supplies.

T

30007-G*

32731-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

4

(continued)

14Rule No. 01

(continued)

Sheet of

Day: A period commencing at 12:00 midnight (Pacific time) on any calendar day and ending at 12:00 midnight (Pacific time) on the next succeeding calendar day. Such period shall be twenty-four (24) consecutive hours except on days when changing to or from Daylight Savings Time.

Decatherm: Ten therms or 1,000,000 British Thermal Units (Btus).

Direct Access Service Request (DASR): On-line transmission of a Service Request (customer enrollment), Termination Request or Cancellation for the Transportation Service Program, also known as Core Aggregation Transportation (CAT.) The DASR transaction is outlined in Rule No. 32 was implemented pursuant to CPUC Decision D.98-02-108.

Economic Practicality: Economic Practicality is the application process by which a commercial/industrial core customer can qualify for noncore status. Reclassification to noncore service pursuant to economic practicality requires Utility approval and customers must be willing to curtail service when required by the Utility.

To qualify for noncore service through Economic Practicality, customers using less than 250,000 therms per year (or 20,800 therms per month during the season when gas is used) must have actual alternate fuel facilities installed, permitted and capable of operating on a sustained basis with a fuel supply capability of at least one week of normal operation and the cost of using alternate fuel must be lower than the cost of core service.

Customers using more than 250,000 therms per year (or 20,800 therms per month during the season when gas is used) must provide documentation that installing alternate fuel capability would be economically viable. For customers using more than 250,000 therms per year, reclassification requires CPUC approval.

As a condition of reclassification, both types of customers are required to execute a Master Services Contract, Schedule G, Noncore Reclassification Agreement (Form Nos. 6597 and 6597-7).

Electric Generation: The use of natural gas to generate electricity, either directly or indirectly, including natural gas used for cogeneration or solar electric generation projects.

Electric Utilities' Startup and Igniter Fuel: Electric utility natural gas use where no alternate fuel capability exists for: (1) heating the boiler system adequately during start-up to enable efficient oil burning to meet pollution standards; and (2) insuring continuous-ignition and flame-stabilization within the boiler.

Electronic Data Interchange (EDI): The sending and receiving of data and/or funds in a structured electronic format, commonly involving information technology and telecommunications technology.

NN

L

30007-G* & 30008-G**

32732-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

5

(continued)

14Rule No. 01

(continued)

Sheet of

Energy Services Provider (ESP) : Also known as an "aggregator." ESPs are individuals, companies or consortiums that arrange for natural gas procurement related activities (procurement, interstate transportation and balancing) on behalf of core customers. ESPs must enter into a standard agreement with SoCalGas and must meet certain credit requirements. They must comply with Rule No. 32 and all other tariffs which address the transportation and management of customer-owned gas.

Enhanced Oil Recovery: Any operation which includes the use of natural gas to pressure, cycle, or inject a substance into a well for the purpose of increasing oil production from that well, specifically including natural gas used for cogeneration to promote these operations.

Equivalent Margin: Equivalent margin is defined as the margin embedded in the Commission's rate design. Margin is the amount of revenue the Commission allows a utility to earn over a one-year period without consideration of fuel costs, Gas Exploration and Development Adjustments and Conservation Cost Adjustments.

Exchange Gas: Natural gas which is produced by a customer and redelivered under a natural gas exchange agreement by Utility to that same customer at a different location.

Facility: An individual meter with the exception of meters combined for the Utility's operating convenience in accordance with Rule No. l7. Customers who have had more than one meter installed for their own convenience at their own request shall be treated as a separate facility with respect to each meter.

Family Dwelling Unit: A group of rooms; such as a house, a flat, or an apartment which provides complete family living facilities in which the occupant normally cooks meals, eats, sleeps, and carries on the household operations incident to domestic life.

Feedstock Usage: Natural gas used as raw material for its chemical properties in creating an end product .

Force Majeure: Unanticipated events or conditions beyond the reasonable control of the party claiming Force Majeure which could not have been prevented by the exercise of due diligence. Force Majeure as it applies to the Tariff Rate Schedules specifically does not include required maintenance of customer's facilities, plant closures, economic conditions or variations in agricultural crop production.

Full Requirements: Full requirements service is an option for core subscription customers and firm intrastate transmission customers. Full requirements customers choose to have all of their fossil fuel requirements satisfied by natural gas. Full requirements customers may choose to procure their supplies from the Utility; transport their own supplies; or any combination of the two. Such customers are not subject to use-or-pay charges except to the extent that unauthorized alternate fuel use or bypass occurs. Full requirements customers are prohibited from using alternate fuels or bypass pipeline service except: (1) in the event of curtailment, (2) to test alternate fuel systems, or (3) where Utility has provided prior written authorization for the use of alternate fuels or bypass. Any fuel produced on-site by the customer can be used by the producer without penalty.

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30008-G** & 30009-G*

32733-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

6

(continued)

14Rule No. 01

(continued)

Sheet of

Gas Engine Water Pumping: Any natural gas engine used for water pumping in agricultural or agricultural-related operations for the growing of crops or the raising of fowl or animals within SoCalGas' service territory. In addition, any natural gas engine used for municipal water pumping for countercyclical or agricultural use.

Heating Value: The number of Btus liberated by the complete combustion at constant pressure of one cubic foot of natural gas at a base temperature of sixty degrees Fahrenheit (60F) and a pressure base of fourteen and seventy-three hundredths (14.73) psia, with air at the same temperature and pressure as the natural gas, after the products of combustion are cooled to the initial temperature of the natural gas, and after the water vapor of the combustion is condensed to the liquid state. The Heating Value of the natural gas shall be corrected for the water vapor content of the natural gas being delivered except that, if such content is seven (7) pounds or less per one million (1,000,000) cubic feet, the natural gas shall be considered to be dry.

Housing Project: A building or group of buildings located on a single premises and containing residential dwelling units for which master metering of gas service at one location has been requested.

Hub: Also California Energy Hub, refers to SoCalGas' area natural gas hub. Encompasses the various delivery points in California or at the California border at which some portion of a Hub Transaction may be effectuated by utilizing SoCalGas' facilities or some interconnection therewith.

Hub Delivery Point: Shall mean any point on the Hub where SoCalGas shall deliver natural gas to any service user or for service user's account. A Hub Transaction may require more than one delivery point.

Hub displacement Delivery: Shall mean the delivery or redelivery to a service user on an interruptible basis of natural gas received by SoCalGas pursuant to a "Wheeling Transaction" or a "Parking Transaction", when such redelivery occurs at a delivery point where either party has access to an interstate pipeline, but not a delivery point located on or interconnected with the pipeline facilities of SoCalGas as the ultimate delivery point. A displacement delivery is made in the direction contrary to the physical flow of gas in a pipeline facility.

Hub Receipt Point: Shall mean any point on or off the Hub where SoCalGas shall receive natural gas from service user or for a service user's account in connection with a Hub Transaction. A Hub Transaction may require more than one receipt point.

Hub Transaction: Shall mean either an interruptible Parking or Loaning-storage type transaction or a Wheeling transmission type transaction or other transactions approved and implemented from time to time.

Hydrogen Production: A process in which natural gas as a raw material is reacted with steam in the presence of a catalyst to produce hydrogen gas.

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30009-G* & 30010-G**

32734-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

7

(continued)

14Rule No. 01

(continued)

Sheet of

Industrial Use: Service to customers engaged primarily in a process which creates or changes raw or unfinished materials into another form or product.

Intermittent Service: Service which, in the opinion of the Utility, is subject to discontinuance for a time or at intervals.

Interstate Transition Cost Surcharge (ITCS): A volumetric surcharge on the Utility's noncore intrastate transmission service to recover costs for certain interstate pipeline demand charges resulting from the transition to an unbundled interstate capacity market pursuant to the CPUC's Capacity Brokering Rules set forth in Decision Nos. 91-11-025 and 92-07-025. The ITCS is applicable to all noncore service except for enhanced oil recovery and that service provided by the Utility under fixed-rate contracts (including long-term contracts in effect on or before the implementation date of the CPUC's Capacity Brokering Rules).

Life-Support Device: A medical device using Utility-supplied natural gas for its operation that is regularly required to sustain, restore, or supplant a vital function of a person residing in a residential unit. The term does not include apparatus or appliances used in a hospital or medical clinic, nor does it include therapeutic devices such as pool or tank heaters, saunas, or hot tubs.

Loaning Transaction: Shall mean where SoCalGas advances or loans natural gas which is returned by service user delivering to SoCalGas an equivalent or greater natural gas quantity at the time(s) and locations(s) specified in the Hub Transaction.

Mailed Date: Any notice or other communication to the customer will be considered "mailed" when received into the customer's electronic mail box via electronic data interchange or when it is enclosed in a sealed envelope, properly addressed, and deposited in any authorized United States Postal Service receptacle.

Main Extension: The length of main and its related facilities required to transport natural gas from the existing facilities to the point of connection with the service piping.

Marketer/Shipper: A third party which accesses one or more interstate or intrastate pipeline systems for the purpose of transporting natural gas to Utility System on Marketer/Shipper's own behalf or on the behalf of designated end-use customers.

Maximum Daily Quantity: The maximum daily quantity of natural gas that can be nominated for delive ry to a customer's premises not served by an automated meter when the Utility institutes an excess nominations period. For noncore customers and core customers not served under core aggregation this is based on the equipment at the customer's facility. For core aggregators the maximum daily quantity is equal to their DCQ.

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L

30010-G** & 30011-G**

32735-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

8

(continued)

14Rule No. 01

(continued)

Sheet of

Minimum Daily Quantity: The minimum daily quantity (MinDQ) is an estimate of natural gas usage at a customers premises not served by an automated meter for purposes of compliance with winter delivery requirements as specified in Rule No. 30 .

Multifamily Accommodations: An apartment building, duplex, mobile home park, or any other group of permanent residential single-family dwellings located upon a single premises, provided that the residential dwellings therein meet the requirements for a single-family dwelling or accommodation. A multifamily accommodation does not include hotels, motels, residential hotels, guest or resort ranches, marinas, tourist camps, recreational vehicle parks, campgrounds, halfway houses, rooming houses, boarding houses, institutions, dormitories, rest or nursing homes, convalescent or care facilities, military barracks, or any enterprise that includes or rents to either transient tenants or transient accommodations.

Noncore Service: Noncore service includes: (1) all industrial and commercial usage where the customer has elected noncore service; and (2) all natural gas usage for qualifying electric generation equipment, including solar electric generation projects. Industrial and commercial customers whose usage is 20,800 therms or more per active month on an annualized basis for a period of any 12 contiguous months within the most recent 24-month period are eligible to elect noncore service in whole or in part. An active month is defined as any month during which the customer's usage exceeds 1,000 therms. All customers who receive noncore service are required to choose either core subscription, firm transportation, and/or interruptible transportation service as described in the applicable noncore service rate schedule. The end-use priorities of these services are set forth in Rule No. 23.

Non-Profit Group Living Facility: A non-profit homeless shelter that may be government-subsidized with six (6) or more beds that provides lodging day or night for a minimum of 180 days of the year; other non-profit residential-type facilities (excluding government-owned and privately-owned, "for profit" government-subsidized housing) that provide a service in addition to lodging and which may be licensed by the appropriate state agency to care for residents who temporarily or permanently cannot function normally outside of the group home environment; and non-licensed, separately metered affiliated facilities where the primary facility is eligible for CARE and is the customer of record for the affiliate, and at least 70% of the energy consumed by the affiliate is used for residential purposes. All residents must meet the CARE income eligibility standards, however a caregiver who lives in the group facility is not a resident for purposes of determining the facility's eligibility. Non-profit group living facilities that are not licensed or certified must provide any other documentation the Utility may reasonably require.

Off-System Customers: A marketer, broker, supplier or other entity bidding for storage service on their own behalf for ultimate consumption outside the Utility's service territory.

Parking Transaction: Shall mean when SoCalGas received natural gas for service user's account for short-term interruptible storage.

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L

30011-G** & 30012-G*

32736-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

9

(continued)

14Rule No. 01

(continued)

Sheet of

Peak Day Minimum: A volume of gas in storage inventory that provides deliverability for the core 1-in-35 year peak day event, firm withdrawal commitments and noncore balancing requirement. Peak day minimums are calculated annually as part of normal winter operations planning. Peak day minimums are specified in billion cubic feet (Bcf).

Peak Day Minimum + 5 Bcf Trigger: A volume of gas in storage inventory at which customers are required to deliver on a daily basis 90% of burn as specified in Rule No. 30.

Peak Day Minimum + 20 Bcf Trigger: A volume of gas in storage inventory at which customers are required to deliver on a daily basis 70% of burn as specified in Rule No. 30.

Peak-Day Volume: Used in the calculation of the GT-RLS tariff, a customer's highest one-day usage over the specified time period.

Percentage of Default: This value determines the noncore customer's order for curtailment of interruptible intrastate transmission service as set forth in Rule No. 23. Interruptible service to customers at full tariff rates shall be 100% of default. For interruptible service to customers at rates other than full-tariff rates, the percentage of default shall be determined on a monthly basis and shall be equal to:A. The customer's total (1) volumetric transmission charges, (2) demand charges or other non-

volumetric transmission charges, (3) customer or facilities charges, (4) the CPUC Reimbursement Fee (Schedule No. G-SRF) and (5) the Interstate Transition Cost Surcharge, under the applicable noncore service schedule for the immediate prior twelve-month period, divided by:

B. The total of the above charges that would have applied if the customer were paying full-tariff rates for the same 12-month period.

For customer's with individual demand forecasts adopted through the Utility's cost allocation proceeding, percentage of default shall be determined using the most recently adopted usage forecast. For all other customers, actual consumption shall be used. Charges not specifically applied to firm or interruptible service shall be prorated among the two services on the basis of actual or forecasted usage, whichever applies. The percentage of default calculation shall specifically exclude curtailment violation penalties, imbalance charges, and Utility User's Tax.

Permanent Service: Service which, in the opinion of the Utility, is of a permanent and established character. This may be continuous, intermittent, or seasonal in nature.

Petroleum Oil Stills and Heaters: Direct-fired vessels used to heat petroleum products for a distillation, refining or manufacturing process.

Point(s) of Delivery: The place(s) where Utility delivers customer-owned natural gas to customer at its facility.

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30012-G* & 30013-G

32737-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

10

(continued)

14Rule No. 01

(continued)

Sheet of

Point(s) of Receipt: The place(s) where customer delivers, or has delivered on its behalf, natural gas into the Utility System.

Post-Bypass Load Factor: Used to calculate the ceiling rate for Residual Load Service customers subject to one of the following applicable customer classes:

A. Non-UEG Customers and Non-Jurisdictional UEG Customers: The post-bypass load factor shall be calculated by dividing the average daily volume by the Peak-Day Volume on the SoCalGas system on a cumulative basis from the first day after bypass begins, or over the previous twelve months, whichever is less, to the 20th day of the calendar month prior to the month service is provided.

B. UEG customers subject to CPUC jurisdiction: The post-bypass load factor shall be calculated using the customer's average daily volume divided by the Peak-Day Volume on the SoCalGas system on a cumulative basis over the relevant time period as follows:

1) For the first three billing months following the date of bypass, the relevant time period will be the three months prior to the month service is provided, up to the 20th day of the month prior to the month service is provided.

2) After the first three billing months following the date of bypass, the relevant time period will be all days since the first day after bypass begins, or over the previous twelve months, whichever is less, to the 20th day of the month prior to the month service is provided.

Pre-Bypass Load Factor: Used to calculate the ceiling rate for Residual Load Service customers subject to one of the following applicable customer classes:

A. Non-UEG customers: The customer's average daily volume divided by the customer's Peak-Day Volume recorded on the SoCalGas system over the 12 month period prior to the installation and operation of bypass facilities.

B. UEG customers subject to CPUC jurisdiction: The customer's average daily combined volume divided by the combined Peak-Day Volume on the SoCalGas system and the bypass pipeline(s) on a cumulative basis over the relevant time period as follows:

1) For the first three billing months following the date of bypass, the relevant time period will be the three months prior to the month service is provided, up to the 20th day of the month prior to the month service is provided.

2) After the first three billing months following the date of bypass, the relevant time period will be all days since the first day after bypass begins, or over the previous twelve months, whichever is less, to the 20th day of the month prior to the month service is provided.

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30013-G & 30014-G*

32738-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

11

(continued)

14Rule No. 01

(continued)

Sheet of

C. UEG customers not subject to CPUC jurisdiction: The customer's aggregate forecasted average daily volume divided by the customer's Peak-Day Volume based on the most recently adopted forecast in SoCalGas' BCAP proceeding.

If daily measurement load data is not available for the specified time periods, then monthly load data will be pro-rated on a daily basis to calculate the appropriate Pre-Bypass Load Factor.

Premises: All of the real property and apparatus employed in a single enterprise on an integral parcel of land undivided, excepting in the case of industrial, agricultural, oil field, resort enterprises and public or quasi-public institutions, by a dedicated street, highway or other public thoroughfare or a railway. Automobile parking lots constituting a part of and adjacent to a single enterprise may be separated by an alley from the remainder of the premises served.

Prime Mover: A machine which converts heat energy supplied by fuel into mechanical energy.

Procurement Customer: A core customer who receives both procurement and transportation services from SoCalGas.

Procurement Management Charge: Charges billed to Aggregators participating in the Core Aggregation Transportation program that may arise from Aggregators' management of procurement portfolios on behalf of customers served by the Aggregators. Procurement Management Charges may include but are not limited to Imbalance/Adjustment charges, Curtailment/Operational Flow Order charges and any storage transactional charges.

California Public Utilities Commission (CPUC): The Public Utilities Commission of the State of California.

Qualified Agricultural Employee Housing Facility: A migrant farmworker housing center provided pursuant to Section 50710 of the Health and Safety Code currently under contract to the Office of Migrant Services; privately-owned employee housing as defined by Section 17008 of the Health and Safety Code, that is licensed and inspected by state and/or local agencies pursuant to Part I (commencing with Section 17000) of Division 13 of the Health and Safety Code; or agricultural employee housing operated by nonprofit entities as defined by Subdivision (b) of Section 1140.4 of the Labor Code exempted from local property taxes pursuant to subdivision (g) of Section 214 of the Revenue and Taxation Code. All usage (100%) must be residential except for master-metered migrant farmworker housing centers and agricultural employee housing operated by a nonprofit entity where at least 70% of the energy consumed must be used for residential purposes. Each resident household in the facility must meet the CARE income-eligibility standards, however an employee operating and/or managing the facility who lives in it is not considered a resident household for purposes of determining eligibility.

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30014-G* & 30015-G*

32739-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

12

(continued)

14Rule No. 01

(continued)

Sheet of

Qualified Contractor/Subcontractor (QC/S): QC/S shall: (1) Be licensed in California for the appropriate type of work (electrical, general, etc.); (2) Employ workmen properly certified for specific skills, required (plastic fusion, welding, etc.); Electric workmen shall be properly qualified (Qualified Electrical Worker, Qualified Person, etc.) as defined in State of California High Voltage Safety Orders (Title 8, Subchapter 5, Group 2). (3) Comply with applicable laws (Equal Opportunity Regulations, OSHA, EPA, etc.)

Red Team. A term referring to a California State sponsored economic development effort whose principal goal is the creation and/or retention of business within the State of California. A Red Team typically consists of State and local governments, utilities and businesses who mobilize individuals and resources to negotiate, streamline and expedite the business retention, expansion or development process; identify and propose incentives; and recommend resolution of regulatory issues and requirements. A separate Red Team is usually created for each project under the leadership or coordination efforts of the California Trade and Commerce Agency.

Residential Hotel: A hotel establishment which provides lodging as a primary or permanent residence and has at least 50% of the units or rooms leased for a minimum period of one month and said units are occupied for nine months of the year. Residential hotels do not include establishments such as guest or resort hotels, resort motels or resort ranches, tourist camps, recreational vehicle parks, half-way houses, rooming houses, boarding houses, dormitories, rest homes, convalescent or care facilities, military barracks, or a house, apartment, flat or any residential unit which is used as a residence by a single family or group of persons.

Residential Use: Gas service for use at family dwelling premises, which includes service to residential units and mobile home units but does not include enterprises such a rooming houses, boarding houses, dormitories, rest homes, convalescent or care facilities, military barracks, stores, restaurants, service stations and other similar establishments. Also excluded are central heating plants serving a combination of residential and commercial uses where the commercial portion of the use is in excess of 100 Mcf per day or is more than 15% of the total natural gas requirements.

Rules: Tariff sheets which set forth the application of all rates, charges and service when such applicability is not set forth in and as a part of the rate schedules.

Seasonal Service: Natural gas service to establishments which are occupied seasonally or intermittently, such as seasonal resorts, cottages or other part-time establishments.

Seasonal Use: Service to customers with 20% or less of their annual requirement occurring in the months of November through March.

Service: All pipe, valves, and fittings from and including the connection at the main up to and including the stop-cock on the riser.

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30015-G* & 30016-G

32740-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

13

(continued)

14Rule No. 01

(continued)

Sheet of

Service Extension: Consists of the service as above defined when provided for a new customer at a premises not heretofore served in accordance with the service extension rule.

Shipper: See Marketer/Shipper.

Short-Run Marginal Cost : The variable per-unit cost of providing additional throughput to the average customer in a customer class. Short-Run Marginal Cost (SRMC) is determined for a given customer class by dividing the sum of Company Use and UAF costs allocated to that customer class in the most recent BCAP by the cost allocation throughput for that customer class.

Smelter: Equipment used directly for (a) the recovery or reduction of a metal from an ore; or (b) the recovery of metals and alloys from new and used scrap, dross, slag and similar waste materials.

SoCalGas: Southern California Gas Company (also referred to as "Utility").

Solar Electric Generation Project: A project which utilizes solar energy as the primary fuel in the generation of electricity, uses natural gas as a secondary fuel constituting 25% or less of the total fuel utilized on an equivalent basis, has a natural gas efficiency utilization rate of more than 60%, and qualifies as a small power production facility under the Public Utility Regulatory Policies Act of l978.

Stationary Steam Boilers: Permanently installed, direct-fired, low pressure steam-boilers, high pressure steam-boilers, steam generators and hot water boilers manufactured in conformance with applicable boiler codes.

Stub Service: A lateral pipe, including valves and fittings, from and including the connection at the main to a dead end near the curb or property line of the street in which the main is located.

Tariff Schedules: The entire body of effective rates, rentals, charges, and rules collectively, of the Utility, as set forth herein, and including title page, preliminary statement, rate schedules, rules and sample forms.

Tariff Sheet: An individual sheet of the tariff schedules .

Temporary Service: Service for enterprises or activities which are temporary in character or where it is known in advance that service will be of limited duration. Service which, in the opinion of the Utility, is for operations of a speculative character or the permanence of which has not been established, also is considered temporary service.

Therm: A unit of measurement for billing purposes, nominally 100,000 Btu.

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30016-G & 30017-G*

32741-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

DEFINITIONS

14

(continued)

14Rule No. 01

Sheet of

Tract or Subdivision: An area for family dwellings which may be identified by filed subdivision plans or as an area in which a group of dwellings may be constructed about the same time, either by a large scale builder or by several builders working on a coordinated basis.

Transportation: The receipt of gas purchased and owned by a customer into the Utility System at one or more points of receipt and the subsequent delivery of an equivalent quantity of natural gas to the customer at a mutually acceptable location (points of delivery) on the system.

Transportation Services Customer: A core customer who elects to receive procurement service from an ESP and transportation services from SoCalGas, pursuant to Rule No. 32.

Utility: Southern California Gas Company (also referred to as "SoCalGas").

Utility System: That pipeline transmission and distribution system and related facilities located in California and operated by Utility during the term of an Agreement.

Wheeling Transaction: Shall mean the interruptible receipt of natural gas at a point of interconnection on SoCalGas' pipeline system and the interruptible redelivery of such natural gas to the initial or other service user either at a point of interconnection on or with SoCalGas' pipeline system, or at a point off such system. All Hub Transactions which require more than 1-day to complete are Parking or Loaning Transactions, even though Wheeling may be involved.

Year: A period of twelve consecutive months. "Contract Year" shall mean a twelve-month period beginning on the first day of the month immediately following the month in which service is scheduled to commence under an Agreement and each subsequent 12-month period; provided that the first Contract Year shall include the period from the date service commences until the first day of the following month.

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24642-G**

32742-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

CONTINUITY OF SERVICE AND INTERRUPTION OF DELIVERY

1 12Rule No. 23

(continued)

Sheet of

The provisions of this Rule shall not apply to service until the date of full implementation of the CPUC's Capacity Brokering Rules set forth in Decision Nos. 91-11-025 and 92-07-025 and Resolution Nos. G-3023, G-3033 and G-3043.

A. General

The Utility will exercise reasonable diligence and care to furnish and deliver service to its customers, and to avoid any interruption of same. The Utility shall not be liable for damages or otherwise for any failure to deliver gas or provide service to its customers, which failure in any way or manner results from breakage of its facilities, however caused, war, riots, acts of God, strikes, failure of or interruption in service, operating limitations or other conditions beyond its reasonable control.

B. Priority of Service

In the event of a curtailment, as defined in Rule No. 1, the Utility shall curtail gas service to customers as described in Section C, Curtailment of Service, herein. Customer usage will be assigned to appropriate end-use priority or service classifications as set forth below.

Core Service

Priority 1 All residential usage regardless of size. All commercial and industrial usage less than 20,800 therms per active month* (active month defined as one in which consumption exceeds 1,000 therms), excluding usage for electric generation and usage reclassified to noncore service pursuant to economic practicality prior to September 29, 1993.

Priority 2A All commercial and industrial usage of 20,800 therms or greater per active month* who elect to remain core customers.

Noncore Service

Firm Service All usage classified as noncore, as defined in Rule No. 1, Definitions, served through firm intrastate transmission service (including core subscription service).

Interruptible All usage classified as noncore, as defined in Rule No. 1, Service Definitions, served through interruptible intrastate transmission service. Interutility deliveries shall be considered interruptible intrastate service.

____________________________* A customer whose usage does not exceed 20,800 therms per active month on an annualized basis for a

period of any 12 contiguous months within the most recent 24 month period will be classified as Priority 1. A commercial or industrial customer whose usage is 20,800 therms per active month or greater on an annualized basis, for a period of any 12 contiguous months within the most recent 24 month period will be classified as Priority 2A and have the option of electing noncore service.

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30586-G

32743-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TRANSPORTATION OF CUSTOMER-OWNED GAS

4

(continued)

12Rule No. 30

(continued)

Sheet of

5. As between the customer and the Utility, the customer shall be deemed to be in control and possession of the gas to be delivered hereunder and responsible for any damage or injury caused thereby until the gas has been delivered at the point(s) of receipt. The Utility shall thereafter be deemed to be in control and possession of the gas after delivery to the Utility at the point(s) of receipt and shall be responsible for any damage or injury caused thereby until the same shall have been redelivered at the point(s) of delivery, unless the damage or injury has been caused by the quality of gas originally delivered to the Utility, for which the customer shall remain responsible.

6. Any penalties or charges incurred by the Utility under an interstate or intrastate supplier contract as a result of accommodating transportation service shall be paid by the responsible customer.

7. Customers receiving service from the Utility for the transportation of customer-owned gas shall pay any costs incurred by the Utility because of any failure by third parties to perform their obligations related to providing such service.

E. Interruption of Service

1. The customer's transportation service priority shall be established in accordance with the definitions of Core and Noncore service, as set forth in Rule No. 1, and the provisions of Rule No. 23, Continuity of Service and Interruption of Delivery. If the customer's gas use is classified in more than one service priority, it is the customer's responsibility to inform the Utility of such priorities applicable to the customer's service. Once established, such priorities cannot be changed during a curtailment period.

2. The Utility shall have the right, without liability (except for the express provisions of the Utility's Service Interruption Credit as set forth in Rule No. 23), to interrupt the acceptance or redelivery of gas whenever it becomes necessary to test, alter, modify, enlarge or repair any facility or property comprising the Utility's system or otherwise related to its operation. When doing so, the Utility will try to cause a minimum of inconvenience to the customer. Except in cases of unforeseen emergency, the Utility shall give a minimum of ten (10) days advance written notice of such activity.

F. Nominations in Excess of System Capacity

1. In the event the Utility determines that the transportation nominations received for a specific date of gas flow ("flow date") exceed its expected system capacity (including storage) on such flow date, the Utility shall apply Buy-Back service under Schedule No. G-IMB separately for each flow date that is overnominated. In such event, the Utility shall follow the procedure set forth below. This procedure and the resulting periods of excess nominations shall apply only to (1) all noncore transportation customers, and (2) all customers with usage exceeding 250,000 therms per year at each facility served under Schedule Nos. GT-10 and GT-NGV.

D

27296-G

32744-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

INTERSTATE CAPACITY BROKERING

5

(continued)

8Rule No. 36

(continued)

Sheet of

G. Less-Than-One-Month Capacity Assignment

1. From time-to-time, the Utility may offer to assign capacity for a term of less than one month. Such capacity shall be offered at a fixed rate, by pipeline and capacity allocation point, as designated by the Utility and shall be posted directly to the applicable interstate pipeline electronic bulletin board. The Utility shall provide notice, by way of its GasSelect system, of any posting of a less-than-one-month capacity offer. The notice shall indicate the capacity rate, allocation point, and any other conditions of the assignment.

2. For an assignment of capacity for less than one month, interested parties must arrange to receive the capacity assignment directly with the applicable interstate pipeline. The execution of a Pre-arranged Interstate Capacity Transfer (Form No. 6598) shall not be required as a condition of such assignment.

H. Direct Posting of Interstate Capacity

1. Between open seasons, the Utility may from time-to-time make its firm interstate capacity available by directly posting such capacity on the interstate pipelines' electronic bulletin boards. Such an offering of capacity shall not require an open season for biding and shall be conducted entirely pursuant to federal regulations. The Utility shall provide notice of such direct posting on its GasSelect system.

I. Core Aggregation Transportation

1. Capacity shall be reserved for core aggregators at the full as-billed rate pursuant to the provisions of Rule No. 32. Core aggregators may participate in the Utility's brokering program for any capacity which is additional to their reserved amount under the provisions set forth in this rule.

J. Large Core Transportation

1. From the total interstate capacity reserved by the Utility for its core market, the Utility shall reserve capacity for assignment to large core transportation customers served under Schedule No. GT-10 and GT-NGV. Such capacity shall be reserved for such customers in an amount equal to their DCQ, as defined in Rule No. 1. The amount of the capacity reserved for eventual assignment to the customer shall never at any time exceed the DCQ.

2. Of the total capacity to be made available to large core transportation customers and core aggregators (participating in the Utility's Core Aggregation Transportation Program, as described in Rule No. 32), 70% shall be reserved on the El Paso pipeline system and 30% shall be reserved on the Transwestern pipeline system.

T

27945-G

32745-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

COMMERCIAL/INDUSTRIAL EQUIPMENT INCENTIVE PROGRAM

1 5Rule No. 38

(continued)

Sheet of

A. Applicability

The terms and conditions of this Rule shall apply to the shareholder-funded incentives applicable to the purchase of new or replacement commercial or industrial gas equipment to be installed and used by nonresidential customers within the Utility's service territory for energy-efficiency purposes (including fuel substitution) and/or the cost of feasibility studies. In order to receive an incentive, the customer must sign a contract with the Utility: either Form No. 6700-1 for equipment incentives or Form No. 6700-2 for feasibility study incentives. As part of an equipment incentive agreement, the customer must accept responsibility for purchasing, installing, and operating the equipment in the manner described below. Additionally, the customer may be required to sign an affidavit attesting that the incentive was a material factor in the decision to utilize the energy equipment identified in the agreement.

B. Program Description

The Commercial/Industrial Equipment Incentive Program is designed to demonstrate and evaluate the performance of nonresidential gas equipment under actual operating conditions in the Utility's service territory.

1. Purpose of the Program

The Program is designed to help customers buy down the first-cost of qualifying high-efficiency equipment. The Program will also fund feasibility studies to evaluate the potential benefits of these kinds of gas equipment in commercially intensive locations throughout the Utility's service territory. The Program is open to existing and new nonresidential customers, on a first-come, first-served basis, based upon customer interest and qualifications.

2. Objectives of the Program

a. Persuade nonresidential customers to install state-of-the-art equipment to reduce their overall energy cost and increase their productivity and/or profitability.

b. Encourage and support manufacturers of gas equipment to develop and produce new, cost-effective and energy-efficient nonresidential equipment for southern California.

c. Demonstrate the Utility's commitment to develop and promote new, alternative technologies with environmental and/or energy-efficiency benefits.

d. Increase the amount of nonresidential gas equipment with high off-peak load usage by:

1. better utilizing the Utility's pipeline capacity during the summer months, and

2. reduce average operating costs by balancing system load.

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NT |TNN

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T

27945-G & 27946-G

32746-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


2

(continued)

5Rule No. 38

(continued)

Sheet of

B. Program Description (continued)

2. Objectives of the Program (continued)

e. Demonstrate that innovative nonresidential gas equipment is a viable and environmentally beneficial alternative to traditional gas and electric technologies.

C. Customer Selection

All of the Utility's existing and new nonresidential customers are eligible to participate in the Program. Qualifying customers, subject to the availability of funds, may apply for and receive one shareholder-funded equipment incentive per building per year. The minimum term of obligation for a customer receiving a shareholder-funded equipment incentive is to operate the equipment as specified in the contract. The Utility has the option of seeking Commission approval for contracts of five or more years before making such commitments.

1. Application to the Program

The customer shall be required to complete an application after the Utility's representative determines the project meets all of the pre-approval screening criteria (see C.2.a. below). The Utility's representative will submit the application and other information to the Utility for evaluation.

2. Application Evaluation Process

An application will be completed after the Utility's representative evaluates whether the customer's project satisfies the following pre-approval screening criteria:

a. Pre-Approval Screening Criteria

The Utility's representative will assess the following specific information for each project to ensure the project meets the requirements for funding under the program:

1. the type of equipment being considered and whether its purpose is energy efficiency, fuelsubstitution, etc.;

2. the size or capacity of the equipment;

3. the total cost of the feasibility study and/or total cost to purchase and install the equipment;

4. the customer's estimated payback period and acceptable payback period;

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T

27946-G & 27947-G

32747-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


3

(continued)

5Rule No. 38

(continued)

Sheet of

C. Customer Selection (continued)

2. Application Evaluation Process (continued)

a. Pre-Approval Screening Criteria (continued)

5. the customer's willingness to share relevant data and provide access to the facility;

6. the customer's industry and location in the Utility's service territory;

7. the customer's time requirements; and

8. whether the project will improve or maintain the energy efficiency of the customers facility (this may be demonstrated by a consultant's feasibility study or design engineer's evaluation).

b. Submitting the Application

The application will be submitted to the appropriate Approval Team at the Utility for approval.

c. Reviewing the Application

The level of shareholder-funded incentive to be provided by the Utility is a function of the cost of the feasibility study or first-cost of the gas equipment being considered, and on-going maintenance and operating costs, relative to those of the best alternative technology or electric equipment. The final evaluation for equipment incentives will be based on whether the shareholder-funded incentive will provide the customer with an acceptable payback period. The equipment incentive amount will be based on the customer's payback period.

1. Calculating the Payback Period

The payback period is calculated using the difference between the first-cost and operating costs of the gas equipment versus the existing or best available alternative equipment (including electric) along with any (gas or electric) utility incentives that may apply.

The formula the Utility will use to determine the payback period is:

Payback = Difference in Purchase & Installation Costs for Gas and Alternative Equipment Period Difference in Annual O&M Costs for Gas and Alternative Equipment

The equipment incentive will be computed using data reflecting the specific circumstances of each customer and consistent with what the customer considers an acceptable payback period.

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T

27947G & 27948-G

32748-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


4

(continued)

5Rule No. 38

(continued)

Sheet of

C. Customer Selection (continued)

2. Application Evaluation Process (continued)

c. Reviewing the Application (continued)

2. Determining the Level of Incentive

The level or amount of incentive must be consistent with the following:

a. Feasibility Studies: up to 50% of the study cost, up to a maximum of $20,000 per study.

b. Equipment Incentives: up to 50% of the installed equipment cost, up to a maximum of $100,000 per project or, in the case of air conditioning, up to $300 per ton for high-efficiency gas cooling equipment.

d. Approving or Denying the Application

The appropriate Approval Teams will meet as needed to approve funding requests received by the Utility in the prior month. Within 90 days of the meeting where an application is presented for consideration, the Utility's representative will receive confirmation of the Approval Team's decision, and the amount of funding, if any. The Utility's representative will inform the customer of the Approval Team's decision, and if appropriate, the Utility's representative will prepare a contract (Form No. 6700-1, Equipment Incentive Program Agreement--Shareholder-Funded, "Agreement-1" or Form No. 6700-2, Feasibility Study Program Agreement--Shareholder-Funded, "Agreement-2") and an affidavit when applicable (Rule 38 Affidavit, Form No. 6700-1B, "Affidavit") for the customer's signature. In the Affidavit, the customer must attest, under penalty of perjury, that the incentive was a material factor in the decision to utilize the energy equipment identified in Agreement-1.

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32749-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED


5

(continued)

5Rule No. 38

Sheet of

D. Verifying Contract Performance

Customer's equipment incentive is premised upon the customer installing and using the gas equipment as disclosed to the Utility. Customer could be subject to additional charges if the equipment is not installed and utilized as per Agreement-1 and Rule 38 Special Conditions Metering and Gas Usage, Form No. 6700-1A, when applicable. To verify contract performance, Utility may require some or all of the following:

1. proof of equipment purchase, delivery and installation;2. Utility's visual verification of the installation and operation of equipment;3. separate metering of affected gas equipment;4. establishment of a facility-wide baseload gas consumption, normally based on the previous 24-month

period; and5. additional information as necessary to complete Utility's annual program report to the Commission.

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T

19412-G

32750-G



CAL. P.U.C. SHEET NO.OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

ContractsAgreement for Non-Core Status, Rate Schedule GN-10 or GT-10 (Form 6486, 5/00)

1 1SAMPLE FORMS

T

Sheet of

(See Attached Form)

Form No. 6486 (Revised 5/00)

AGREEMENT FOR NONCORE STATUS

Applicable to customers who, absent thisAgreement, would receive gas service under

Rate Schedule Nos. GN-10 or GT-10.

This agreement ("Agreement") is made this dayof , 19 between the Southern California GasCompany ("Utility") and ("Customer").

Customer's gas usage for its facility at , Account # qualifies as a P- core customer under the currentCalifornia Public Utilities Commission ("CPUC") approved end-use priority system. Customer has warranted to Utility that itis technically and economically capable of burning an alternatefuel, and, therefore, Customer has requested that in return forusing gas at its facility for the term herein, its end-usepriority classification be changed to a P- non-corecustomer and service will be provided under Rate Schedule .Customer informed Utility of its intent to use natural gas asits primary fuel for a period of time equivalent to theamortization period used in Utility's analysis of a proposedalternate fuel for Customer's facility.

In conformance with CPUC Decision No. 87-12-039, asmodified by Decision No. 88-03-085, Utility and Customer agreeto such reclassification for the period from the effective dateof to subject tothe terms and conditions herein.

Customer and Utility have executed a Contract for GasService which is attached hereto. CPUC approval of thisAgreement is required. However, if the effective date setforth above is prior to the receipt of any necessary CPUCapprovals, Customer will nevertheless be billed at the ratesset forth in the attached Contract for Gas Service. However,if this Agreement is not approved by the CPUC for sucheffective date, Customer agrees to pay Customer's original corerate for the period non core rates were charged without suchCPUC approval. In the event any necessary CPUC approval ofthis Agreement is not obtained, both this Agreement and theattached Contract for Gas Service shall be null and void.

Form No. 6486 (Revised 5/00)

- 2 -

Customer understands that this change in priorityclassification results in lower transmission and gasprocurement priorities, and increases the possibility ofcurtailment of Customer's gas service pursuant to Utility'sRule 23. Customer acknowledges that it has reviewed, isfamiliar with and agrees to abide by the rules and regulationsof Rule 23 including the requirement to cease usage of naturalgas for priorities curtailed. Utility is not responsible forfinancial losses or damages incurred because of any suchcurtailment.

Upon termination or expiration of this Agreement,Customer's priority for its gas usage will automatically returnto its original classification consistent with Rule 23.Further service will then be provided under the rates, termsand conditions of the appropriate rate schedule.

This Agreement shall not be assigned by either partywithout the prior written consent of the other. This Agreementshall not be modified or amended except by a written documentduly executed by the parties.

Customer agrees that all current and future Utilityrules and CPUC regulations apply to service under thisAgreement. This Agreement shall at all times be subject to anychanges or modifications by the CPUC as it may from time totime direct in the exercise of its jurisdiction.

Each party represents and warrants that it has fullpower and authority to enter into and perform this Agreement,and that the person signing this Agreement on behalf of suchparty has been properly authorized and empowered to enter intothis Agreement. Each party further acknowledges that it hasread this Agreement, understands it, and agrees to be bound byit.

Accepted and Agreed to:

CUSTOMER SOUTHERN CALIFORNIA GAS COMPANY

By: By:

Title: Title:

Date: Date:

27949-G

32751-G







291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

ContractsEquipment Incentive Program Agreement, Form No. 6700-1 (5/00)

1 1SAMPLE FORMS

T

Sheet of

(See Attached Form)

SoCalGas Form No. 6700-1, 5/00

Date ______________

Southern California Gas Company’s

Equipment Incentive Program Agreement

(Shareholder-Funded)

Customer Name and Address: Customer’s Capacity:

__ Corp./__ Gen.__Ltd. Ptship./__Lim. Liab. Co.

__ California/__ Foreign

__ State __ Federal Governmental Entity

Attn: Fed. Tax ID ____________ SIC Code

Telephone:

Equipment: Facility:

Account # Premises I.D.

The following provisions apply to Equipment Incentives:

Incentive $__________ • Maximum Percentage ____%. The Incentive will be paid by The GasCompany as follows: ___% upon placement of the Equipment purchase order, ___% upondelivery of the Equipment to the Facility and the balance after the Commencement Date. Inno event will the total Incentive or any individual payment exceed the Maximum Percentageof the amounts paid by Customer for the acquisition and installation of the Equipment.Verification of Customer’s execution of Equipment acquisition agreement and of Customer’spayment(s) will be required.

Purchase Order Date: The Purchase Order Date is the date a firm order for purchasing theEquipment has been placed with the Equipment vendor.

Commencement Date: The Commencement Date is the date the Equipment has been installed andhas produced one hour of continuous operation.

Cut-off: Purchase Order Date must occur by___________ and Commencement Date must occur by___________ (or such later dates as The Gas Company and Customer may agree to in writing).If not, The Gas Company has no obligation to pay the Incentive; or, if a part of theIncentive has been paid, Customer shall refund such amount to The Gas Company, plusinterest at 10% per annum, promptly upon demand. If, in The Gas Company’s reasonableopinion, the Commencement Date will not occur by the Cut-off date, no portion of theIncentive need be paid, or any paid portion shall be refunded as provided above.

Term of Use: ______ months from Commencement Date. If, for the Term of Use, Customer doesnot use the Equipment in the manner disclosed to The Gas Company prior to this Agreementand take gas service for the Facility from The Gas Company, Customer agrees that, unlessotherwise specified in Rule No. 38 Special Conditions: Metering and Gas Usage, Form No6700-1A (“Special Conditions”), it will refund, promptly upon demand, a pro-rata portionof the Incentive (based upon the number of months the Customer satisfied both conditions)plus interest at 10% per annum from the date of demand.

SoCalGas Form No. 6700-1, 5/00

1. Information and Demonstration. Customer will provide information and documentsreasonably requested by The Gas Company concerning the Equipment, including itsacquisition, installation and operation (energy use and operating costs). Thisinformation may be provided to third parties, except for Customer’s proprietary or tradesecret information. Customer will provide The Gas Company with reasonable access to theEquipment to observe and monitor its performance. The Gas Company may demonstrate theEquipment to third parties and may advertise savings/benefits realized; but anyadvertising which identifies Customer is subject to Customer’s prior written approval,which will not be unreasonably withheld. In its sole discretion, The Gas Company may waiveany of these rights.

2. Tariff Service. Customer understands and agrees that as consideration for theIncentive paid by The Gas Company, during the Term of Use, Customer will take natural gasservice (purchase and/or transportation) from The Gas Company for the Facility.

3. CPUC/Tariffs. This program is approved by the California Public UtilitiesCommission (“CPUC”) and may be amended, modified, or terminated at any time by the CPUC.This Agreement is subject to the provisions of Rule No. 38 as amended from time to timeand except as otherwise provided herein, to the terms and conditions of The Gas Company’sother applicable tariff rules as amended from time to time, including but not limited toRule 4, the terms of which are incorporated by reference.

4. No Ownership. The Gas Company will have no ownership interest in the Equipment, ifany, and is not a partner of or joint venturer with Customer.

5. NO WARRANTIES BY THE GAS COMPANY AND LIMITATION OF LIABILITY.

5.1 Although The Gas Company shall have the right to review information regardingthe Equipment and/or Consultant’s proposal and Report, as set forth above, Customerunderstands and agrees that The Gas Company’s review is for The Gas Company’s own purposesin determining Customer’s eligibility, calculating the amount of the Incentive and/orPayment for the Feasibility Study, and obtaining information on the Equipment’s operation.The Gas Company makes NO WARRANTIES, EXPRESS OR IMPLIED, AS TO THE EQUIPMENT OR THE SYSTEMOR ANY ASPECT OF THE INSTALLATION, OPERATION, PERFORMANCE, ENERGY USAGE, COST SAVINGS, ORANY OTHER MATTER CONCERNING THE EQUIPMENT OR THE SYSTEM OR CONSULTANT OR CONSULTANT’SRECOMMENDATIONS, INCLUDING BUT NOT LIMITED TO RECOMMENDATIONS AS TO SELECTION ANDINSTALLATION OF EQUIPMENT OR ADOPTION OF ENERGY MANAGEMENT MEASURES.

5.2 Customer understands and represents to The Gas Company that Customer willselect or has selected the Equipment and/or Consultant in reliance upon informationobtained by Customer or on its behalf by its agents and that The Gas Company is not andwill not be responsible for the selection, installation, operation, performance, energyusage, cost savings, or any other matter concerning the Equipment, Consultant orFeasibility Study or Report, or for any liability, losses, damages or injuries arisingfrom the Equipment’s use or from the Feasibility Study. If the Equipment isunsatisfactory for any reason, or if Consultant’s recommendations or implementation ofthem is unsatisfactory for any reason, Customer will make any claim on account thereofagainst Customer’s engineer, vendor, installer, Equipment manufacturer, and/or Consultantas appropriate.

5.3 The Gas Company will not be liable for any consequential, indirect, orpunitive damages.

6. No Third Party Beneficiaries. This program and Agreement are for the benefit of, andenforceable only by, The Gas Company and Customer.

7. If checked, the attached Rule No. 38 Special Conditions, Form No. 6700-1A, and RuleNo. 38 Affidavit, Form No. 6700-1B, are incorporated by reference.

Customer: Southern California Gas Company

By: By:

Title & Name: Title:

Date Signed: Date Signed:___________________________________

32752-G




OriginalCANCELING



291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

ContractsRule No. 38 Special Conditions: Metering and Gas Usage, Form No. 6700-1A (5/00)

1 1SAMPLE FORMS

Sheet of

(See Attached Form)

SoCalGas Form No. 6700-1A, 5/00

Rule No. 38 Special Conditions: Metering and Gas UsageCommercial & Industrial Equipment Incentive Program

Attachment to Form No. 6700-1

7.0 Special Conditions: Metering and Gas Usage

Check and Initial Applicable Paragraphs:

7.1 Baseload Gas Use[___] Customer Initials

Except as may be modified immediately below, historic actual gas consumption forthe 24 month period prior to signing the Agreement is used to establish theaverage baseload of _______________ therms per year (“Baseload”). Consumptiongreater than this Baseload will be considered towards fulfilling Customer’sobligation to use the Equipment in the manner disclosed in Paragraph 7.3 below.

Modifications to Paragraph No. 7.1[___] Customer Initials

7.2 Metering[___] Customer Initials

Except as may be modified immediately below, Utility will install a Utility-ownedgas meter in accordance with Rule 13, Meters and Appliances, and when applicablewith Rule 21, Gas Service Extensions, on the Equipment to verify Customer’senergy use during the Term of Use. Customer shall install the energy Equipmentin a manner such that this gas meter can readily and safely be installed andaccessed on the natural gas line servicing that Equipment. Customer shall allowUtility routine access to the measurement-related facilities for servicing andmeter reading, in accordance with Rule 25, Company’s Right of Ingress to andEgress from Customer’s Premises. Following the Term of Use, all such facilitieswill be removed by Utility, unless other arrangements are made.


7.3 Rate Schedule[___] Customer Initials

Except as may be modified immediately below, Customer must take gas underUtility’s noncore GT-F, GT-I or G-CS tariff rate schedule for the entire Termof Use as long as Customer qualifies for at least one of these rates or untilboth Customer and Utility mutually agree on a different rate.


SoCalGas Form No. 6700-1A, 5/00

7.4 Gas Requirements / Customer Equipment Disclosure[___] Customer Initials

Customer discloses that Equipment will have a collective rated capacity of________ MMBtu/h, and during the Term of Use will consume a Minimum AnnualQuantity (“MAQ”) of not less than ________ therms of gas per year (includingBaseload use when the box by Paragraph 7.1 is checked), to be assessed each 12months following the Commencement Date. If a period of fewer than 12 monthsremains at the end of the Term of Use, a pro-rata portion of the MAQ applies.Except as may be modified immediately below, if actual usage falls below thisMAQ, Customer will be subject each contract year to an additional charge equalto the difference in Transmission Charges between Customer’s actual usage andMAQ in that time period. MAQ adjustments will be made to the extentconsumption is reduced specifically due to intrastate curtailment or an eventof force majeure, as defined in Rule 1, on either the interstate or intrastatesystems.


7.5 Other[___] Customer Initials

32753-G




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DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

ContractsRule No. 38 Affidavit, Form No. 6700-1B (5/00)

1 1SAMPLE FORMS

Sheet of

(See Attached Form)

SoCalGas Form No. 6700-1B, 5/00

Rule No. 38 AffidavitCommercial & Industrial Equipment Incentive Program

Attachment to Form No. 6700-1

Customer certifies as follows:

Southern California Gas Company’s shareholder-funded incentive offered to Customer under TariffRule 38 was a material factor in Customer’sdecision to utilize the energy Equipment identifiedin the Equipment Incentive Program Agreement towhich this Affidavit is attached.

The identified equipment is not an existing gasload that Customer has received past SoCalGasdiscounts to avoid fuel switching to fuels such asoil and propane, nor is it an existing gas loadwith a demonstrated history of fuel switching.Additionally, Customer, in making its decision toutilize the identified equipment, was notcontemplating bypassing SoCalGas' system foranother system within the State of California,and/or is not a new customer planning on locatingin close proximity to a bypass pipeline.

I declare under penalty of perjury under the laws of the State ofCalifornia that the foregoing statement is true and correct.

Executed at ________________, California, this _____ day of _________,20___. (City) (Date) (Month)

CUSTOMER

(enter full Company name)

Name: (print)

Signature:

Title:

32754-G




OriginalCANCELING



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DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

ContractsRed Team Affidavit, Form No. 6683 (5/00)

1 1SAMPLE FORMS

Sheet of

(See Attached Form)

SoCalGas Form No. 6683, 5/00

RED TEAM AFFIDAVIT

Customer Affidavit for Rates Negotiated as part of, or in conjunction with, aState of California sponsored Red Team

As representative of I will be expanding and/or (customer name)

locating a new business within the State of California. I was considering other

locations outside of the State of California to expand and/or start new business.

I verify that a material factor in the decision to locate within the State of

California was an incentive package offered by a Red Team which was formed

by the California Trade & Commerce Agency (“CA-TCA”), including the incentive

offered by The Southern California Gas Company, either as a participating

member of, or in conjunction with, the package offered by the Red Team. The

decision to locate, or expand, within the State of California was not based on

any ability to bypass The Southern California Gas Company system for another

system within the State of California.

I declare under penalty of perjury under the laws of the State of California that

the foregoing statement is true and correct.

Executed at ____________________, ______. ______/__/____,(city) (state) (month/day/year)

Company Name: _______________________________(print)

Signature: _______________________________

Print: _______________________________

Title: _______________________________

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DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

(continued)

Schedule Number Title of Sheet Cal. P.U.C. Sheet No.

GR Residential Service ..................................... 30818-G,32563-G,32564-G,31016-GGT-R Core Aggregation Transportation for

Residential Service ................................. 31173-G,32565-G,32566-G,31175-GGS Multi-Family Service Submetered ................ 32567-G,32568-G,32569-G,30829-G

31017-GGT-S Core Aggregation Transportation for Multi-Family

Submetered Service .................. 32570-G,32571-G,32572-G,31178-G,31179-GGM Multi-Family Service ................................ 30832-G,32573-G,32574-G,32575-G

30836-G,31018-GGT-M Core Aggregation Transportation for

Multi-Family Service ............................ 31180-G,32576-G,32577-G,31182-G31183-G,31184-G

GMB Large Multi-Family Service ....................... 32578-G,32579-G,32580-G,32581-G32582-G,31019-G

GT-MB Core Aggregation Transportation forLarge Multi-Family Service ................... 32583-G,32584-G,32585-G,31187-G

31188-G,31189-GGRL Residential Service,

Income Qualified ................... 30856-G,32586-G,32587-G,31502-G,31503-GGT-RL Core Aggregation Transportation Residential Service,

Income Qualified .................... 31190-G,32588-G,32589-G,31504-G,31505-GGSL Submetered Multi-Family Service,

Income Qualified .................................. 32590-G,32591-G,32592-G,31506-G31507-G,31021-G

GT-SL Core Aggregation Transportation Submetered Multi-FamilyService, Income Qualified ...................... 32593-G,32594-G,32595-G,31508-G

31509-G,31198-GGO-SSA Summer Saver Optional Rate for Owners of

Existing Gas Equipment ............. 32044-G,32596-G,32597-G,32598-G,31253-GGTO-SSA Transportation-Only Summer Saver Optional Rate for Owners o f

Existing Gas Equipment ............ 31579-G,32599-G,32600-G,31580-G,31258-GGO-SSB SummerSaver Optional Rate for Customers Purchasing New o r

Repairing Inoperable Equip. ....... 32046-G,32601-G,32602-G,32603-G,31263-GGTO-SSB Transportation-Only SummerSaver Optional Rate for Customers Purchasing New o r

Repairing Inoperable Equip. ....... 31581-G,32604-G,32605-G,31583-G,31268-GGO-AC Optional Rate for Customers Purchasing New Gas

Air Conditioning Equipment ........ 32048-G,32606-G,32607-G,32608-G,31277-GGTO-AC Transportation-Only Optional Rate for Customers Purchasing New Gas

Air Conditioning Equipment ........ 31584-G,32609-G,32610-G,32611-G,31282-G

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DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

(continued)

GL Street and Outdoor Lighting Natural Gas Service ..................... 32612-G,31022-GGN-10 Core Service for Small Commercial and

Industrial Service ........................ 32613-G,32614-G,32615-G,32616-G32617-GGT-10 Core Aggregation Transportation for Core Commercial and

Industrial Service ...................... 32618-G,32619-G,32620-G,32621-G,32622-G32623-G

GN-10L Core Commercial and Industrial Service,Income Qualified ....................... 32624-G,32625-G,32626-G,32627-G,32628-G

32629-G,32630-G,32631-G,32632-GGT-10L Core Aggregation Transportation Commercial and

Industrial Service, Income Qualified ....... 32633-G,32634-G,32635-G,32636-G32637-G,32638-G,32639-G,32640-G,32641-G

G-AC Core Air Conditioning Service for Commercial andIndustrial ................... 32642-G,32643-G,32644-G,31026-G,31524-G,31525-G

GT-AC Core Transportation-only Air Conditioning Service forCommercial and Industrial .................................... 32645-G,32646-G,29992-G

29993-G,31526-G,31527-G,29996-GG-EN Core Gas Engine Service for Agricultural

Water Pumping .................................................... 32057-G,32647-G,31027-GGT-EN Core Transportation-only Gas Engine Service for

Agricultural Water Pumping ................................ 32648-G,29998-G,29999-GG-NGV Natural Gas Service for Motor Vehicles ................... 32059-G,32649-G,31028-GGT-NGV Transportation of Customer-Owned Gas for

Motor Vehicle Service ........................... 32650-G,32651-G,30002-G,30003-GGO-ET Emerging Technologies Optional Rate for

Core Commercial and Industrial ................... 30200-G,32061-G,30202-GGTO-ET Transportation-Only Emerging Technologies Optional Rate for

Core Commercial and Industrial ........................... 30203-G,30204-G,30205-GGO-IR Incremental Rate for Existing Equipment for

Core Commercial and Industrial ................... 30206-G,32062-G,30208-GGTO-IR Transportation-Only Incremental Rate for Existing Equipment for

Core Commercial and Industrial ........................... 30209-G,30210-G,30211-GG-CP Core Procurement Service .......................................... 32477-G,32478-G,31031-GG-CS Core Subscription Natural Gas Service ....... 32652-G,32653-G,32654-G,32655-G

32656-G,32657-G,332658-G,32659-GGT-F Firm Intrastate Transmission Service .......... 32660-G,32661-G,32662-G,32663-G

32664-G,32665-G,32666-G,32667-GGT-I Interruptible Intrastate Transmission Service .............. 32668-G,32669-G,32670-G

32671-G,32672-G,32673-G

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DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

(continued)

GT-SD Intrastate Transmission Service ................. 32674-G,30593-G,30594-G,30595-GGT-RLS Residual Load Service .............................................. 27508-G,31497-G,27510-GGW-LB Wholesale Natural Gas Service ..... 32675-G,32676-G,32677-G,32678-G,32679-G

32680-G,32681-GGW-SD Wholesale Natural Gas Service ................................ 32682-G,32683-G,32684-G

32685-G,32686-GGW-SWG Wholesale Natural Gas Service ................................. 32687-G,32688-G,32689-G

32690-G,32691-GGW-VRN Wholesale Natural Gas Service ................................. 32692-G,32693-G,32694-G

32695-G,32696-G,32697-GG-IMB Transportation Imbalance Service ............... 29614-G,32441-G,32442-G,32423-G

32424-G,29517-G,29518-GG-ITC Interconnect Access Service ..................................................... 32698-G,32699-GG-ICMA Interconnect Charge Memorandum Account .......................................... 31889-GG-BSS Basic Storage Service .................................. 32700-G,32701-G,32702-G,32703-G

32704-G,32705-G,32706-G,32707-GG-AUC Auction Storage Service .............................. 32708-G,32709-G,32710-G,32711-G

32712-G,32713-G,32714-G,32715-GG-LTS Long-Term Storage Service ........................ 32716-G,32717-G,32718-G,32719-G

32720-G,32721-G,32722-G,32723-GG-TBS Transaction Based Storage Service ............ 32724-G,32725-G,27374-G,27375-G

31929-G,27377-G,27378-GG-CFS Surcharge to Fund California Alternate Rates

for Energy Discount ........................................................................... 32726-GG-SRF Surcharge to Fund Public Utilities Commission

Utilities Reimbursement Account ........................................................ 24565-GG-MHPS Surcharge to Fund Public Utilities Commission

Master Metered Mobile Home Park Gas SafetyInspection and Enforcement Program .................................................. 30473-G

G-MSUR Transported Gas Municipal Surcharge ...................................... 25005-G,25006-GGIT Interruptible Interutility Transportation ..................................... 24567-G,24568-GGLT Long-Term Transportation of Customer-Owned

Natural Gas .......................................................... 24569-G,24570-G,24571-GGLT-1 Transportation of Customer-Owned Natural Gas ....... 24572-G,24573-G,24574-G

24575-G,24576-G,24577-GGLT-2 Transportation of Customer-Owned Natural Gas ....... 24578-G,24579-G,24580-G

24581-G,24582-G,24583-GG-LOAN Hub Loaning ........................................................................................ 32727-GG-PRK Hub Parking ......................................................................................... 32728-GG-WHL Hub Service .......................................................................................... 32729-G

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DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

(continued)

RULES

Rule Number Title of Sheet Cal. P.U.C. Sheet No.

1 Definitions ....................... 30004-G,30005-G,32730-G,32731-G,32732-G,32733-G32734-G,32735-G,32736-G,32737-G,32738-G,32739-G,32740-G,32741-G

2 Description of Service ................................................. 28356-G,28357-G,28358-G28359-G,28360-G,28361-G,28362-G

3 Application for Service .............................................................................. 24598-G4 Contracts .................................................................................................. 24599-G4.1 Exemption from Public Inspection Requirements for

Certain Gas Corporation Contracts .............. 28977-G,28978-G,28979-G,28980-G5 Special Information Required on Forms ....................................... 29864-G,24601-G6 Establishment and Re-Establishment of Credit ............................. 28448-G,28449-G7 Deposits .................................................................................................... 24604-G8 Return of Deposit--Interest on Deposit ....................................................... 26214-G9 Discontinuance of Service .............................. 24606-G,26950-G,26422-G,26423-G

26424-G,24611-G10 Service Charges .............. 30599-G,30600-G,30601-G,30602-G,30603-G,30604-G

30605-G,30606-G,30607-G,30608-G,30609-G,30610-G11 Disputed Bills ........................................................................................... 24616-G12 Payment of Bills ....................................................................................... 28817-G13 Meters and Appliances ............................................................... 24618-G,24619-G14 Meter Reading .......................................................................................... 24620-G15 Meter Tests ................................................................................ 24621-G,24622-G16 Adjustment of Bills ...................................................... 24623-G,24624-G,24625-G17 Reading of Separate Meters Not Combined ............................................... 24626-G18 Notices ..................................................................................................... 24627-G19 Rates and Optional Rates .......................................................................... 24628-G20 Gas Main Extensions ........ 31800-G,31801-G,31802-G,31803-G,31804-G,31805-G

31806-G,31807-G,31808-G,31809-G,31810-G,31811-G,31812-G21 Gas Service Extensions ..... 31813-G,31814-G,31815-G,31816-G,31817-G,31818-G

31819-G,31820-G,31821-G,31822-G,31823-G,31824-G,31825-G22 Temporary Service ...................................................................... 24640-G,30294-G23 Continuity of Service and Interruption of

Delivery.......................... 32742-G,24643-G,24644-G,24645-G,24646-G,24647-G24648-G,24649-G,24650-G,24651-G,24652-G,27273-G

24 Supply to Individual Premises and Resale of Gas .................................................................................................... 24654-G

25 Company's Right of Ingress to and Egress f rom the Consumer's Premises .......................................................................... 24655-G

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DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

(continued)

RULES (continued)

26 Consumer Responsible for Equipment for Receiving Gas ......................................................................................... 24656-G

27 Service Connections Made by Company's Employees .............................................................................................. 24657-G

28 Compensation to Company's Employees .................................................... 24658-G29 Change of Consumer's Apparatus or Equipment ........................................ 24659-G30 Transportation of Customer-Owned Gas ....... 29531-G,29532-G,30585-G,32743-G

30587-G,30588-G,30589-G,29598-G29599-G,29600-G,29601-G,29602-G

31 Automated Meter Reading .......................................................... 24669-G,24670-G32 Core Aggregation Transportation .................. 30018-G,31199-G,30020-G,30021-G

30022-G,30023-G,30024-G,30025-G,30026-G,30027-G30028-G,30029-G,30030-G,30031-G,30032-G,30033-G30034-G,30035-G,30036-G,30037-G,30038-G,30039-G

33 GasSelect ..................................................... 30116-G,26501-G,26430-G,26502-G35 Contracted Marketer Transportation .............. 27068-G,27069-G,27070-G,27071-G

27072-G,27073-G,27074-G,27075-G36 Interstate Capacity Brokering ........................ 24687-G,27293-G,27294-G,27295-G

32744-G,27297-G,27298-G,27299-G37 Hub Service ..................... 26589-G,26590-G,26591-G,26592-G,26593-G,26594-G38 Commercial/Industrial Equipment

Incentive Program ......................... 32745-G,32746-G,32747-G,32748-G,32749-G

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291700-04-060


DECISION NO.

ISSUED BY


MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

(continued)

SAMPLE FORMS (continued)

Contracts (continued)

Transportation, Terms and Conditions (Form No. 6351, 12-87) ..................................... 18586-GGas Service Agreement (Form 6533, Rev. 5-91) ......................................................... 20882.1-GTargeted Sales Service Agreement (Form 6534) ........................................................ 21435.4-GEnergy Services Provider Agreement (Form 6536-A, 1/99) ........................................ 31200-GCustomer Termination of CAT Program Contract (Form 6567-T) .............................. 26418-GMarketer/Aggregator Contract (Form No. 6536) ....................................................... 21435.3-GGasSelect Agreement (Form 6537, Rev. 4/98) ............................................................ 30119-GCustomer Information Release (Form 6538) .............................................................. 21435.1-GCogeneration Standby Equipment Affidavit (Form 6419, 3/88) .................................. 18773.1-GStorage Service Agreement (Form 6473) ..................................................................... 21473-GNotice of Intrastate Curtailment Transfers (Form 6600) ............................................... 24232-GAgreement for Non-Core Status, Rate Schedule GN-10

(Form 6485, 8/89) .................................................................................................. 19411-GAgreement for Non-Core Status, Rate Schedule GN-10 or GT-10

(Form 6486, 5-00) .................................................................................................. 32750-G"As-Available" Storage Service Agreement (Form 6573) .............................................. 22073-GBid Procedure (Form 6474, 4/89) ................................................................................. 19214-GApplicant Design Terms and Conditions (Form 6665, 5/98) .......................................... 30295-GTemporary Service Extension (Form 3454-C, 2/73) ...................................................... 13814-GAssignment of Contract (Form 3907-A, 7/73) ............................................................... 13815-GTransfer of Service Pipe to Yard Piping (Form 1951-F) ................................................ 13816-GForm of Indemnification (Form 6403, 10/87) ................................................................ 18570-GGas Service Agreement with the City of

Long Beach ................................................... 15510-G,15511-G,15512-G,15513-G,15514-GGas Service Agreement -- San Diego Gas & Electric

Company ..................................................................... 15989-G,15990-G,15591-G,15992-G15993-G,15994-G,15995-G,15996-G

Master Services Contract (Form 6597) ........................................................................ 23730-GMaster Services Contract, Schedule A,

Intrastate Transmission Service (Form 6597-a) ....................................................... 23604-GMaster Services Contract, Schedule B,

Marketer/Core Aggregator/Use-or-Pay Aggregator (Form 6597-2) .......................... 23605-GMaster Services Contract, Schedule D,

Basic Storage Service (Form 6597-4, 7/96) ........................................................... 27911.1-GMaster Services Contract, Schedule E,

Auction Storage Service (Form 6597-5) .................................................................. 23732-G

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DECISION NO.

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MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

(continued)

SAMPLE FORMS (continued)

Contracts (continued)

Master Services Contract, Schedule F,Long-Term Storage Service (Form 6597-6) .............................................................. 23733-G

Master Services Contract, Schedule H,Extended Balancing Service (Form 6597-8) .............................................................. 23735-G

Amendment to Master Services Contract, Schedule A,Intrastate Transmission Service (Form 6597-9) ........................................................ 26370-G

Supplement to Master Services Contract Schedule A, IntrastateTransmission Service, (Form 6597-10, Rev. 5/97) ................................................... 28713-G

Master Services Contract, Schedule I,Transaction Based Storage Service (Form 6597-11) ................................................. 27379-G

Master Services Contract, Schedule J,Gas Air Conditioning Service (Form 6597-12, Rev. 11/99) ...................................... 32027-G

Pre-Arranged Interstate Capacity Transfer (Form 6598) ............................................... 23606-GAccess Agreement (Form 6600) .................................................................................... 25062-GSeismic Services Subscription Contract (Form 6625 - 6/95) .......................................... 26972-GSeismic Services Sales Contract (Form 6627 - 6/95) ..................................................... 26973-GImbalance Trading Agreement (Form 6544) .................................................................. 27111-GProducer's Application Fee Notification Letter (Form 6640 - 7/96) ................................ 27898-GAppendix A - Producer's Payment for Utility's Investment for Facilities (Existing Facilities) (Form 6641 - 7/96) ..................................................................... 27899-GAppendix A - Producer's Payment for Utility's Investment for Facilities (New Facilities) (Form 6642 - 7/96) .......................................................................... 27900-GAppendix B - Producer's Payment for Utility's Operation & Maintenance Fee (Form 6643 - 7/96) .................................................................................................... 27901-GEquipment Incentive Program Agreement (Form 6700-1, Rev. 5/00) ............................. 32751-GRule 38 Special Conditions: Metering and Gas Usage (Form 6700-1A - 5/00) ............... 32752-GRule 38 Affidavit (Form 6700-1B - 5/00) ..................................................................... 32753-GRed Team Affidavit (Form 6683 - 5/00) ....................................................................... 32754-GFeasibility Study Program Agreement (Form 6700-2, Rev. 8/96) .................................. 27950-GExcess Core Gas Sales Prequalification Contract (Form 6628 - 8/96) ........................... 27957-GExcess Core Gas Sales Contract (Form 6629 - 8/96) .................................................... 27958-GSpecial Facilities Contract (Form 6633 - 1/96) ............................................................. 28386-GNondisclosure Agreement (Form 6658 - 7/97) ............................................................. 28981-GProposal and Agreement for Transfer of Ownership of Distribution Systems (Form 6660 - 3/98) .................................................................................................... 29947-GOptional Rate Agreement and Affidavit (Form 6662 - 4/98) ......................................... 30212-G

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DECISION NO.

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MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

The following listed sheets contain all effective Schedules of Rates and Rules affecting service and information relating thereto in effect on the date indicated thereon.

GENERAL Cal. P.U.C. Sheet No.

Title Page .......................................................................................................................... 21888-GTable of Contents--General and Preliminary Statement ........................................ 32762-G,32763-GTable of Contents--Service Area Maps and Descriptions ..................................................... 28516-GTable of Contents--Rate Schedules ........................................................ 32755-G,32756-G,32757-GTable of Contents--List of Cities and Communities Served .................................................. 31694-GTable of Contents--List of Contracts and Deviations ........................................................... 31694-GTable of Contents--Rules ..................................................................................... 32758-G,32759-GTable of Contents--Sample Forms ........................ 31532-G,32760-G,32761-G,31979-G,31980-G

PRELIMINARY STATEMENT

Part I General Service Information ........................... 24331-G,24332-G,24333-G,24334-G,24749-G

Part II Summary of Rates and Charges ...... 32485-G,32486-G,32487-G,32488-G,32489-G,32490-G32491-G,32492-G,32493-G,32494-G,32495-G,32496-G,32497-G

Part III Cost Allocation and Revenue Requirement ... 27024-G,27025-G,27026-G,27027-G,32498-G

Part IV Income Tax Component of Contributions and Advances ........................... 24353-G,24354-G

Part V Description of Regulatory Accounts-Balancing ............ 32499-G,32500-G,32501-G,32502-G32503-G,32504-G,32505-G,32506-G,32507-G,32508-G,32509-G

Part VI Description of Regulatory Accounts-Memorandum ..... 32510-G,32511-G,32512-G,32513-G32514-G,32515-G,32516-G,32517-G,32518-G,32519-G,32520-G,32521-G,32522-G,32523-G

Part VII Description of Regulatory Accounts-Tracking ......................... 32524-G,32525-G,32526-G32527-G,32528-G,32529-G

Part VIII Gas Cost Incentive Mechanism (GCIM) ..... 31776-G,31777-G,31778-G,30523-G,30524-G

Part IX Hazardous Substances Mechanism (HSM) ................................ 26199-G,26200-G,26201-G

Part X Global Settlement ....................................................... 32530-G,32531-G,32532-G,32533-G

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DECISION NO.

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MAY 19,2000

RESOLUTION NO.

EFFECTIVE

DATE FILED

TABLE OF CONTENTS

(continued)

(continued)

PRELIMINARY STATEMENT (continued)

Part XI Performance Based Regulation (PBR) ...................... 32534-G,32535-G,32536-G,32537-G32538-G,32539-G,32540-G,32541-G,32542-G,32543-G,32544-G32545-G,32546-G,32547-G,32548-G,32549-G,32550-G,32551-G32552-G,32553-G,32554-G,32555-G,32556-G,32557-G,32558-G

32559-G,32560-G,32561-G,32562-G

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ATTACHMENT CAdvice No. 2917

SOUTHERN CALIFORNIA GAS COMPANYSUMMARY OF PRESENT AND PROPOSED RATES

1999 Biennial Cost Allocation Proceeding

Current ProposedRates Rates

Effective Reflecting Increase/Decrease

Class of Service 1/01/20001999 Biennial Cost

Allocation Proceeding Rate %(a) (b) (c)=(b)-(a) (d)=(c)/(a)

CORE - TRANSPORTATION COMPONENTResidential

Average ResidentialCustomer Charge $/month $5.00 $5.00 - 0.00%Baseline ¢/th 29.290 24.405 (4.885) -16.68%Non-Baseline ¢/th 45.779 42.389 (3.390) -7.41%Average Residential Rate ¢/th 45.647 41.052 (4.595) -10.07%

Non-ResidentialCore Commercial & Industrial Small C/I Only Combined C/I

Customer Charge $/month $15.00 $10.00/15.00 N/A N/ATier I (0-100 S, 250 W) ¢/th 50.960 38.280 (12.680) -24.88%Tier II (Tier I-4167) ¢/th 26.313 22.955 (3.358) -12.76%Tier III (>4167) ¢/th 10.908 10.006 (0.901) -8.26%

Gas Air ConditioningCustomer Charge $/month $150.00 $150.00 - 0.00%Volumetric Rate ¢/th 11.924 8.551 (3.373) -28.29%

Gas EngineCustomer Charge $/month $50.00 $50.00 - 0.00%Volumetric Rate ¢/th 13.761 18.057 4.296 31.22%

NONCORE - Average Transmission RateRetail

Industrial ¢/th 6.178 5.448 (0.731) -11.83%

Electric Generation ¢/th 4.111 3.389 (0.722) -17.56%

Wholesale

Long Beach ¢/th 4.556 2.949 (1.606) -35.26%

SDG&E ¢/th 3.538 2.237 (1.300) -36.76%

Vernon ¢/th N/A 2.495 N/A N/A

UNBUNDLED STORAGEAnnual Reservation

Injection $/Dthd 22.423 20.169 (2.254) -10.05%Withdrawal $/Dthd 13.735 11.584 (2.151) -15.66%Inventory $/Dth 0.193 0.214 0.021 10.97%

Variable ChargesInjection $/Dth 0.0314 0.0127 (0.01862) -59.39%Withdrawal $/Dth 0.0243 0.0177 (0.00660) -27.13%

BROKERAGE FEESCore ¢/th 0.20100 0.20100 - 0.00%Noncore ¢/th 0.26600 0.26600 - 0.00%

Documents

Lee Schavrien - SoCalGas · new short-term contract filed with the CPUC by informational letter on February 23, 2000, and also included in the Joint Recommendation, approved pursuant