-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, I8hiWdlLG6j0fBBy/Lwr5/tlYnnFtI/zzXaZJ9uz3msyGw6anspxFnJr7HrAgTMA eFBsPlMHwtXAj0MLfe0/Ew== 0000950149-95-000141.txt : 199507120000950149-95-000141.hdr.sgml : 19950711 ACCESSION NUMBER: 0000950149-95-000141 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950328 SROS: AMEX SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: PACIFIC GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000075488 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 940742640 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-02348 FILM NUMBER: 95523654 BUSINESS ADDRESS: STREET 1: 77 BEALE ST STREET 2: P O BOX 770000 MAIL CODE B7C CITY: SAN FRANCISCO STATE: CA ZIP: 94177 BUSINESS PHONE: 4159737000 10-K 1 FORM 10-K FOR PERIOD ENDING 12/31/94 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (MARK ONE) /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 1-2348 PACIFIC GAS AND ELECTRIC COMPANY (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) California (STATE OR OTHER JURISDICTION OF INCORPORATION OR ORGANIZATION) 77 Beale Street P.O. Box 770000 San Francisco, California (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) 94-0742640 (IRS EMPLOYER IDENTIFICATION NO.) 94177 (ZIP CODE) (415) 973-7000 (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE) SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON TITLE OF EACH CLASS WHICH REGISTERED Common Stock, par value $5 per share New York Stock Exchange and Pacific Stock Exchange First Preferred Stock, cumulative, American Stock Exchange and par value $25 per share: Pacific Stock Exchange
Redeemable: 8.20% 7.04 % 4.80% 8% 6.875% 4.50% 7.84% 5% 4.36% 7.44% 5% Series A Nonredeemable: 6% 5.5% 5%
First and Refunding Mortgage Bonds: New York Stock Exchange
INTEREST DATE OF SERIES RATE % MATURITY - ------- -------- -------------- II 4-1/4 Jun. 1, 1995 JJ 4-1/2 Jun. 1, 1996 KK 4-1/2 Dec. 1, 1996
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES 'X' No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ 'X' ] The total number of shares of the Company's Common Stock outstanding at March 6, 1995 was 430,151,818. On that date the aggregate market value of the voting stock held by nonaffiliates of the Company was approximately $11,511 million. The market values of the various classes of voting stock held by nonaffiliates were as follows: Common Stock, $10,787 million; and First Preferred Stock, $724 million. The market values of certain series of First Preferred Stock, for which market prices were not available, were derived by dividing the annual dividend rate of each such series of stock by the average yield of all of the Company's Preferred Stock outstanding for which market prices were available. DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. (1) Designated portions of the Annual Report to Shareholders for the year ended December 31, 1994...................................... Part II (Items 5, 6, 7 and 8) Part IV (Item 14) (2) Designated portions of the Proxy Statement relating to the 1995 annual meeting of shareholders........................... Part III (Items 10, 11, 12 and 13)
2 TABLE OF CONTENTS
PAGE ----- Glossary of Terms PART I Item 1. Business..................................................................... 1 General Corporate Structure and Business............................................. 1 Competition and Industry Restructuring....................................... 2 Gas Industry................................................................. 2 Electric Industry............................................................ 3 The Company's Response to the New Competitive Environment.................... 3 California Ratemaking Mechanisms............................................. 5 Base Revenue Mechanisms...................................................... 5 Electric Fuel Revenue Mechanisms............................................. 5 Gas Fuel Revenue Mechanisms.................................................. 6 Other Rate Adjustment Mechanisms............................................. 7 Proposed Regulatory Reforms.................................................. 7 Electric Industry Restructuring Proposal..................................... 7 Financial Impact of the Electric Industry Restructuring Proposal............. 9 Company's Proposals.......................................................... 10 Current Rate Proceedings..................................................... 12 1995 Revenue Changes......................................................... 12 Biennial Cost Allocation Proceeding.......................................... 13 1996 General Rate Case....................................................... 14 Workforce Reduction Rate Mechanism........................................... 14 Customer Energy Efficiency/Demand Side Management Programs................... 14 Capital Requirements and Financing Programs.................................. 15 Electric Utility Operations Electric Operating Statistics................................................ 17 Electric Generating and Transmission Capacity................................ 18 Electric Load Forecast and Resource Planning and Procurement................. 19 Electric Resources........................................................... 20 QF Generation................................................................ 20 Geothermal Generation........................................................ 21 Western Systems Power Pool................................................... 21 Electric Transmission Policies............................................... 21 Transmission Access and Pricing.............................................. 21 Regional Transmission Groups................................................. 22 Stranded Costs Rulemaking.................................................... 22 CPUC Transmission Policies................................................... 22 Electric Reasonableness Proceeding........................................... 23 Helms Pumped Storage Plant................................................... 23 Gas Utility Operations Gas Operations............................................................... 24 Gas Operating Statistics..................................................... 25 Natural Gas Supplies......................................................... 26 Gas Regulatory Framework..................................................... 26 Restructuring of Canadian Gas Supply Arrangements............................ 27 Decontracting Plan........................................................... 27 Financial Impact of Decontracting Plan and Litigation........................ 28 Restructuring of Interstate Gas Supply Arrangements.......................... 28 Current Gas Transportation and Procurement Arrangements...................... 28 Recovery of Interstate Transportation Demand Charges......................... 28 Gas Reasonableness Proceedings............................................... 29 1988-1990 Canadian Gas Procurement Activities................................ 30 Proposed Gas Settlements..................................................... 30 Financial Impact of Gas Reasonableness Proceedings........................... 30 PGT/PG&E Pipeline Expansion Project.......................................... 31 Other Competitive Pipeline Projects.......................................... 32 Storage Service.............................................................. 32
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PAGE ----- Diablo Canyon Diablo Canyon Operations..................................................... 33 Diablo Settlement............................................................ 33 Nuclear Fuel Supply and Disposal............................................. 35 Insurance.................................................................... 36 Decommissioning.............................................................. 36 PG&E Enterprises Non-Utility Electric Generation.............................................. 36 Gas and Oil Exploration and Production....................................... 37 Real Estate Development...................................................... 37 Environmental Matters and Other Regulation Environmental Matters........................................................ 37 Environmental Protection Measures............................................ 38 Hazardous Materials and Hazardous Waste Compliance and Remediation........... 39 Electric and Magnetic Fields................................................. 42 Low Emission Vehicle Programs................................................ 42 Other Regulation............................................................. 43 California Public Utilities Commission....................................... 43 California Energy Commission................................................. 43 Federal Energy Regulatory Commission......................................... 43 FERC-Hydroelectric Licensing................................................. 43 Nuclear Regulatory Commission................................................ 44 Item 2. Properties................................................................... 44 Item 3. Legal Proceedings............................................................ 44 Antitrust Litigation......................................................... 44 Hinkley Compressor Station Litigation........................................ 45 Counties Franchise Fees Litigation........................................... 46 Cities Franchise Fees Litigation............................................. 46 Time-of-Use Meter Litigation................................................. 47 Norcen Litigation............................................................ 47 Potter Valley Hydroelectric Project.......................................... 48 PGT Unit 4C Compressor Unit Permit........................................... 48 Item 4. Submission of Matters to a Vote of Security Holders.......................... 49 Executive Officers of the Registrant......................................... 49 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.... 50 Item 6. Selected Financial Data...................................................... 50 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................................................... 50 Item 8. Financial Statements and Supplementary Data.................................. 50 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................................................... 50 PART III Item 10. Directors and Executive Officers of the Registrant........................... 50 Item 11. Executive Compensation....................................................... 50 Item 12. Security Ownership of Certain Beneficial Owners and Management............... 50 Item 13. Certain Relationships and Related Transactions............................... 51 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............. 51 Indemnification Undertaking.................................................. 55 Signatures............................................................................... 56 Report of Independent Public Accountants................................................. 57 Financial Statement Schedule............................................................. 58
4 GLOSSARY OF TERMS AEAP.................. Annual Earnings Assessment Proceeding AER................... Annual Energy Rate AFUDC................. allowance for funds used during construction ANG................... Alberta Natural Gas Company Ltd ARA................... Attrition Rate Adjustment A&S................... Alberta and Southern Gas Co. Ltd. BCAP.................. Biennial Cost Allocation Proceeding BRPU.................. Biennial Resource Plan Update Proceeding BTA................... best technology available Btu................... British thermal unit California Superfund........... California Hazardous Substance Account Act CARE.................. California Alternate Rates for Energy program (formerly, LIRA) CCAA.................. California Clean Air Act CEC................... California Energy Commission CEE................... Customer Energy Efficiency CEMA.................. Catastrophic Events Memorandum Account CERCLA................ Comprehensive Environmental Response, Compensation, and Liability Act CIG................... customer identified gas program Company............... Pacific Gas and Electric Company core customers........ All residential gas customers and smaller commercial gas customers that do not exceed certain volume limitations core subscription customers........... Noncore customers who elect to receive combined gas procurement and transportation service from the Company CPIM.................. Core Procurement Incentive Mechanism CPUC.................. California Public Utilities Commission CTC................... Competition Transition Charge DALEN................. DALEN Resources Corp. Diablo Canyon......... Diablo Canyon Nuclear Power Plant Diablo Settlement..... Diablo Canyon rate case settlement DOE................... U.S. Department of Energy DPS................... Destec Power Services DRA................... Division of Ratepayer Advocates DSM................... Demand Side Management DTSC.................. California Department of Toxic Substances Control ECAC.................. Energy Cost Adjustment Clause El Paso............... El Paso Natural Gas Company EMF................... electric and magnetic fields Energy Act............ National Energy Policy Act of 1992 Enterprises........... PG&E Enterprises EPA................... Environmental Protection Agency ERAM.................. Electric Revenue Adjustment Mechanism ER94.................. 1994 Electricity Report EV.................... electric vehicle FERC.................. Federal Energy Regulatory Commission Geysers............... The Geysers Power Plant GFCA.................. Gas Fixed Cost Account GRC................... General Rate Case
5 GWh................... gigawatt-hours Helms................. Helms Pumped Storage Project Helms Settlement...... proposed settlement resolving the treatment of unrecovered Helms costs Humboldt.............. Humboldt Bay Power Plant IPP................... independent power producer ITCS.................. Interstate Transition Cost Surcharge kV.................... kilovolts kVa................... kilovolt-amperes kW.................... kilowatts kWh................... kilowatt-hour LEV................... low emission vehicle LIRA.................. Low Income Rate Assistance program (now referred to as CARE) Makowski.............. J. Makowski Co., Inc. Mcf................... thousand cubic feet MMBtu/d............... million British thermal units per day MMcf.................. million cubic feet MMcf/d................ million cubic feet per day Mojave................ Mojave Pipeline Company MW.................... megawatts NEIL.................. Nuclear Electric Insurance Limited NGV................... natural gas vehicle NML................... Nuclear Mutual Limited noncore customers..... industrial and commercial gas customers that exceed certain volume limitations NOx................... oxides of nitrogen NOVA.................. NOVA Corporation of Alberta Nuclear Act........... Nuclear Waste Policy Act of 1982 OIR/OII............... Order Instituting Rulemaking and Investigation OPA................... Oil Pollution Act of 1990 OSPRA................. Oil Spill Prevention and Response Act of 1990 PBR................... performance-based ratemaking PCBs.................. polychlorinated biphenyls PGA................... Purchased Gas Account PG&E.................. Pacific Gas and Electric Company PGT................... Pacific Gas Transmission Company Pipeline Expansion.... The expansion of the Company's and PGT's natural gas transmission systems which was placed in service in November 1993 Properties............ PG&E Properties, Inc. PRP................... potentially responsible party PURPA................. Public Utility Regulatory Policies Act of 1978 PXC................... Power Exchange Corp. QF.................... qualifying facility RD&D.................. research development & demonstration RDW................... Rate Design Window Regional Board........ Central Coast Regional Water Quality Control Board RRI................... Regulatory Reform Initiative RTG................... Regional Transmission Group
6 SFAS.................. Statement of Financial Accounting Standards SoCal Gas............. Southern California Gas Company SPCC.................. Spill Prevention Control and Countermeasure TID................... Turlock Irrigation District TCRM.................. Transition Cost Recovery Mechanism Transwestern.......... Transwestern Pipeline Company USGen................. U.S. Generating Company USOSC................. U.S. Operating Services Company WRTA.................. Western Regional Transmission Association WSPP.................. Western Systems Power Pool
7 PART I ITEM 1. BUSINESS. GENERAL CORPORATE STRUCTURE AND BUSINESS Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility engaged principally in the business of supplying electric and natural gas service throughout most of Northern and Central California. (Unless the context otherwise requires, the Company or PG&E shall refer to Pacific Gas and Electric Company and its wholly owned and majority-owned subsidiaries.) The Company's principal executive office is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. As of December 31, 1994, the Company had approximately $27.8 billion in assets. The Company generated approximately $10.4 billion in operating revenues for 1994. As of December 31, 1994, the Company had approximately 22,000 employees. The Company's gas and electric utility operations, which include Diablo Canyon Nuclear Power Plant (Diablo Canyon) operations, represent the principal component of its business, contributing $10.2 billion in revenues in 1994 (98% of the Company's total revenues). The Company's utility operations contributed $2.20 of the Company's total 1994 earnings per share of $2.21. The Company's utility assets were $26.3 billion at December 31, 1994, representing 95% of the Company's total assets. Diablo Canyon operations consist of two nuclear power reactor units, each capable of generating up to approximately 26 million kilowatt-hours (kWh) of electricity per day. In 1994, Diablo Canyon contributed $1.9 billion of revenues (18% of the Company's total revenues) and $1.04 in earnings per share (47% of the Company's total 1994 earnings per share). Diablo Canyon had assets of $6.0 billion at December 31, 1994 (22% of the Company's total assets). The Company's utility service territory covers 94,000 square miles with an estimated population of approximately 13 million, and includes all or portions of 48 of California's 58 counties. The area's diverse economy includes aerospace, electronics, financial services, food processing, petroleum refining, agriculture and tourism. At December 31, 1994, the Company served approximately 4.4 million electric customers and 3.5 million gas customers. The Company serves its electric customers with power generated by seven primarily natural gas-fueled steam power plants with 21 units, ten combustion turbines, the Diablo Canyon nuclear power plant with two units, 70 hydroelectric powerhouses with 111 units, the Helms hydroelectric pumped storage plant (Helms) with three units, and a geothermal energy complex of 14 units. The Company also purchases power produced by other generating entities that use a wide array of resources and technologies, including hydroelectric, wind, solar, biomass, geothermal and cogeneration. In addition, the Company is interconnected with electric power systems in 14 western states and British Columbia, Canada, for the purposes of buying, selling and transmitting power. To ensure a diverse and competitive mix of natural gas supplies, the Company purchases gas from both Canadian and United States suppliers. In 1994, about 53% of the Company's gas supply came from fields in Canada, about 42% came from fields in other states (substantially all from the U.S. Southwest) and about 5% came from fields in California. The Company's utility operations also include Pacific Gas Transmission Company (PGT), a wholly owned gas pipeline subsidiary of the Company. PGT owns and operates gas transmission pipelines and associated facilities capable of transporting approximately 2.4 billion cubic feet per day of natural gas over 612 miles from the Canadian-U.S. border to the Oregon-California border. PGT had assets of approximately $1.2 billion at December 31, 1994. PGT's revenues in 1994 were approximately $175 million, excluding revenues related to services provided to the Company. 1 8 Currently, the Company's utility operations, other than Diablo Canyon, are regulated primarily under the traditional cost-based approach to ratemaking. However, as discussed below (see "Competition and Industry Restructuring" and "Proposed Regulatory Reforms"), a number of proposals are being considered which would shift utility regulation from traditional cost-of-service based concepts to concepts based upon market competition and benchmarks. Diablo Canyon operations are conducted under an alternative performance-based approach to ratemaking, as a result of the Diablo Canyon rate case settlement (Diablo Settlement), effective in 1988. Under this approach, revenues for the plant are based primarily on the amount of electricity generated, rather than on the costs associated with the plant's operations. PG&E Enterprises (Enterprises), a wholly owned subsidiary of the Company, is the parent company for the nonregulated portion of the Company's business. Enterprises, through its subsidiaries and affiliates, engages in nonutility electric generation, power plant operations and services, gas and oil exploration and production and real estate development. Enterprises generated approximately $250 million in revenues in 1994 and contributed $.01 of the Company's total 1994 earnings per share of $2.21. Enterprises had assets of $1.5 billion at December 31, 1994. COMPETITION AND INDUSTRY RESTRUCTURING Under traditional utility regulatory schemes, utilities have been accorded the exclusive right to serve customers within designated areas in return for the commitment to provide service to all who request it. Regulation was designed in part to take the place of competition to ensure that utility services were provided at fair prices. Recent changes in both the gas and electric industries have allowed competition to develop in the gas supply and electric production segments of the Company's business. A number of reforms at both the federal and state level have been proposed. These reforms are designed to restructure regulation in the energy supply industry and promote competition by providing electric and gas customers with purchasing options. GAS INDUSTRY The current regulatory framework for natural gas service was established in California in 1988. This framework segmented customers into core (all residential customers and smaller commercial customers that do not exceed certain volume limitations) and noncore (industrial and commercial customers that exceed certain volume limitations) classes, and unbundled utilities' gas transportation and procurement services which allowed noncore customers to purchase gas directly from producers, aggregators and marketers and separately negotiate transportation services. Similarly, in 1992 the Federal Energy Regulatory Commission (FERC) instituted regulatory changes which required interstate pipelines, including PGT, to unbundle sales services from transportation services and established programs providing for the reallocation of pipeline capacity. As a result of these regulatory changes, the Company no longer provides combined procurement and transportation services to most of its noncore customers. Instead, many of these customers now procure their own gas supplies and then purchase transportation service from the Company. As a result, the Company has restructured its own gas operations to accommodate its decreased gas supply and transportation requirements. The Company has terminated its long-term Canadian gas purchase contracts and entered into new, more flexible arrangements for the purchase of the Company's reduced gas supply requirement and is continuing its efforts to permanently assign or broker its commitments for firm gas transportation capacity on interstate pipelines which it once held to serve its noncore customers. The changes in the supply and transportation segments of the gas industry will likely result in increased competition. The FERC has conditionally approved the expansion of an interstate pipeline's existing system into the Company's service territory. See "Gas Utility Operations -- Other Competitive Pipeline Projects" below. If built, this pipeline will compete directly for transportation service to the Company's noncore customers and may result in the loss of sales on the Company's gas transportation system. If the Company's 2 9 gas customers leave the Company's system by moving to an alternative intrastate delivery system, the Company will need to recover the fixed costs of its gas supply and delivery system over fewer units of sales. Unless costs are reduced or imposed as transition charges on exiting customers, the price per unit for remaining customers would go up, further exacerbating the competitive pressures. ELECTRIC INDUSTRY While the restructuring of the electric industry is still evolving, recently effected and currently proposed changes at both the federal and state levels are expected to bring increased competition into the electric generation business. The Company performs the functions of electricity production, transmission, distribution and customer service. However, the Company already obtains one-third of its electrical power supply from generation sources outside its service territory and from qualifying facilities (QFs), small power producers or cogenerators who meet certain federal guidelines which qualify them to supply generating capacity and electric energy to utilities, owned and operated by independent power producers (IPPs). It is expected that new power plant projects will be increasingly undertaken by IPPs rather than utilities. In addition, the recently enacted National Energy Policy Act of 1992 (Energy Act) reduces various restrictions on the operation and ownership of IPPs and provides them and other wholesale suppliers and purchasers with increased access to electric transmission lines throughout the United States. At the state level, in April 1994 the California Public Utilities Commission (CPUC) issued a proposal on electric industry restructuring which seeks to lower energy prices and provide customers with a choice of electric generation suppliers (known as direct access). In addition, where competition does not exist, the CPUC proposes to move electric utilities from traditional regulation, under which the utilities' revenues are set by regulators so as to cover the utilities' costs and provide a fair rate of return, to performance-based ratemaking (PBR). The shift to PBR is intended to provide stronger incentives for efficient utility operations, management and investment. Under its April 1994 proposal, the CPUC would unbundle electric services and, on a phased-in basis over time, provide to electric utility retail customers the option to choose from a range of electric generation providers, including utilities, beginning in 1996. This plan is termed "direct access." Utilities serving a given territory would still be obligated to provide transmission and distribution services on a nondiscriminatory basis to customers choosing direct access service from another generation provider, thereby engaging in the practice known as retail wheeling. Coinciding with these changes, the CPUC foresees development of a competitive spot market for electric generation and an increasing need for inter-regional coordination of the electric grid, and elimination of existing resource planning and procurement approaches. If as a result of restructuring a substantial number of the Company's customers were to elect electric generation alternatives under a retail wheeling system, the Company's recovery of its purchased power obligations to QFs and its investment in its electric generation assets would be dependent on prices charged to remaining customers, transition charges that may be imposed on existing customers, and the Company's ability to reduce its costs. While the CPUC proposal contemplates that some stranded costs of utility generating facilities be recovered through a "competition transition charge," the CPUC has not specified whether other costs, such as regulatory assets and QF obligations, might be recovered through such a charge or how such charge would be allocated to and collected from customers. See "Proposed Regulatory Reforms -- Electric Industry Restructuring Proposal" below. THE COMPANY'S RESPONSE TO THE NEW COMPETITIVE ENVIRONMENT The restructuring of the electric and gas industries has led to a greater emphasis on the Company's ability to offer its services at competitive prices. Currently, the Company's average gas prices for residential, commercial and industrial customers are among the lowest utility gas prices in California. The Company's residential electric bills are at the middle of the scale nationally. However, the Company's prices per kWh are high when compared with national averages. The Company's prices for industrial customers average approximately 7.0 cents per kWh, which is comparable to prices charged by the other major California 3 10 utilities, but above the industrial electric prices in many other states. The Company's electric prices include the costs for generation, transmission, distribution and customer service. The Company has taken several significant steps to address the issues raised by the new competitive environment in the energy industry. These steps include proposals to modify the existing regulatory process and to provide the Company additional pricing flexibility for those customers with the most competitive options. These proposals, together with various cost containment measures implemented by the Company, are intended to help position the Company to effectively compete in the restructured electric and gas industries. With this goal in mind: -- The Company has proposed to extend through 1996 its electric rate freeze, which began in 1993. -- The Company has announced a five-year goal of reducing its system average electric rate to 10 cents per kWh or less, which would constitute about a 25% reduction in the Company's system average electric rate after adjusting for inflation. -- In December 1994, the Company, the CPUC's Division of Ratepayer Advocates (DRA), the California Attorney General and other parties proposed to modify the Diablo Settlement to reduce the price paid for electricity generated at Diablo Canyon over the next five years. See "Diablo Canyon -- Diablo Settlement" below. -- The Company has requested CPUC approval to implement a statewide three-year experimental program under which California utilities would offer certain industrial customers and other large energy users the option to receive electricity from competitive suppliers, starting as early as January 1, 1996. -- The Company has proposed instituting PBR for determining base revenues, under which electric and natural gas base revenues would be determined annually by formula rather than through general rate cases (GRCs), attrition rate adjustments (ARAs) and Cost of Capital proceedings. The Company has also proposed a core gas procurement incentive mechanism (CPIM) that would substitute for reasonableness reviews of certain costs. The CPIM would measure the Company's gas procurement costs against market benchmarks and would provide for the sharing between ratepayers and shareholders of variances from a preset range around the market benchmark. -- The Company has reduced electric rates for certain of its largest industrial customers through an economic stimulus rate that the Company proposes to extend through the end of 1996. -- The Company has planned reductions in annual spending in 1995 of approximately $600 million from 1993 spending levels. -- The Company has refinanced debt and preferred stock over the last three years resulting in annual savings of approximately $97 million in financing costs. -- Through its wholly owned subsidiary, Enterprises, the Company has taken steps to position itself to compete in the nonregulated energy business. In 1994, Enterprises and Bechtel Enterprises, Inc. acquired J. Makowski Co., Inc. (Makowski), a company engaged in the development of natural gas-fueled power generation projects and natural gas distribution, supply and underground storage projects. In addition, Enterprises, in partnership with Bechtel Enterprises, Inc., is in the process of forming a company to develop, build, own and operate international nonutility generation projects. While it is difficult to predict the ultimate outcome of the ongoing changes that are taking place in the utility industry, the Company believes that the end result will involve a fundamental change in the way it conducts its business. The changes may impact financial operating trends and add volatility to the Company's earnings. The Company is actively seeking regulatory and operational changes that will allow the Company to provide energy services in a safe, reliable and competitive manner while achieving strong financial performance. 4 11 CALIFORNIA RATEMAKING MECHANISMS The ratemaking mechanisms currently applied by the CPUC in setting the Company's rates are discussed below. As more fully discussed below (see "Proposed Regulatory Reforms -- Company's Proposals"), the Company has filed proposals with the CPUC requesting alternatives to certain aspects of the current regulatory approach to setting rates. If adopted, those proposals would significantly alter the existing ratemaking mechanisms. In addition, the Company proposes to continue through 1996 its freeze on retail electric rates, first implemented in 1993, which impacts the application of certain of these ratemaking mechanisms in current rate proceedings (see "Current Rate Proceedings" below). BASE REVENUE MECHANISMS Under the CPUC's Rate Case Plan, the CPUC sets the Company's base revenue requirements for both electric and gas operations in the GRC proceeding. Base revenue is revenue intended to recover the Company's fixed costs and non-fuel variable costs and to provide a return on invested capital. (Fuel revenue requirements, intended to recover the Company's fuel and fuel-related costs, are set as part of the Energy Cost Adjustment Clause (ECAC) proceeding for electric operations and the Biennial Cost Allocation Proceeding (BCAP) for gas operations, as discussed below.) In the GRC, revenues and expenses are determined on a forecast or future test-year basis, rather than on a historic-year basis. The Company files a GRC application once every three years, with a decision issued approximately 13 months after the application is filed. The Company's current rates are based on its 1993 GRC. The Company filed its 1996 GRC application in December 1994, for rates effective January 1, 1996. The ARA adjusts base rates in the years between GRC decisions to partially offset attrition in earnings due to changes in non-fuel operating expenses and capital costs. Labor expenses and nonlabor maintenance and operation expenses are indexed, and a prescribed amount is allowed for recovery of expenses related to changes in depreciation, income taxes, financing costs, rate base growth and other items. The ARA improves the Company's ability to earn its authorized rate of return for utility operations in the years between GRCs. The cost of capital incorporated in an ARA, including authorized return on equity, is determined separately by the CPUC in the annual Cost of Capital consolidated proceeding which reviews financing costs and adopts capital structures for all California energy utilities. In May 1993, the DRA and various special interest groups filed a joint petition with the CPUC requesting suspension, for an indefinite period, of the ARA mechanism. The petition requests that any future attrition rate increases be considered only upon application for such relief and only if the then current rate of inflation exceeds 6% on an annual basis. The petition recommends that any attrition rate adjustment authorized in such cases be limited to inflation above the 6% threshold level. The CPUC has not acted on the DRA's petition, but its staff has recommended that the petitioners raise the matter in the Company's 1996 GRC. The Electric Revenue Adjustment Mechanism (ERAM) allows rate adjustments to offset the effect on base revenues of differences between actual electric sales volumes and the forecasted volumes used to set rates in the last GRC or ARA proceeding. The ERAM eliminates the impact on earnings of sales fluctuations, including those resulting from conservation and weather conditions. Base revenue differences resulting from the disparity between actual and forecasted electric sales accumulate in a balancing account, with interest, and are recovered from or returned to customers through higher or lower future rates. ERAM rate adjustments are made as part of the ECAC proceeding described below. ELECTRIC FUEL REVENUE MECHANISMS The ECAC provides for recovery of 91% of recorded (or actual) electric fuel and fuel-related energy costs, and for collection of revenues attributable to Diablo Canyon generation. Differences between the sum of actual costs and Diablo Canyon revenues recoverable through ECAC, and the revenues intended to cover such amounts, accumulate in a balancing account, usually with interest, and are recovered from or returned to ratepayers through ECAC adjustments to future rates. ECAC rate adjustments are set once a year, based on a January 1 effective date, to recover the adjustment amount over a forward-looking calendar test year. Revenue adjustments resulting from the California Alternate Rates for Energy (CARE) program (formerly known as 5 12 the Low Income Rate Assistance, or LIRA, program) and the ERAM are consolidated with the ECAC adjustment in the annual ECAC proceeding. The CARE program provides for discount residential rates for customers who qualify under low-income criteria, with the direct costs of CARE electric rate discounts funded through revenue adjustments made in the ECAC proceeding. Rates are subject to a further ECAC adjustment effective May 1 if the required adjustment would be more than 5% of total annual electric revenues. Fuel and fuel-related costs included in an ECAC adjustment are subject to a subsequent reasonableness review, in which the CPUC determines whether those costs were reasonably incurred. Costs found to be unreasonable may be disallowed, or deducted, from the amount to be recovered in rates. The amount of Diablo Canyon revenues recovered through the ECAC is determined under the Diablo Settlement and is not subject to reasonableness review. See "Diablo Canyon -- Diablo Settlement" below. The Annual Energy Rate (AER) mechanism provides for recovery of 9% of forecasted electric fuel and fuel-related costs, without balancing account protection for actual costs that are higher or lower than forecasted. Thus, the AER mechanism places the Company at partial risk for variations between actual and forecasted electric energy costs. To minimize the revenue risk resulting from the potential for substantial swings in energy-related expenses, the increase or reduction in earnings due to operation of the AER is limited to a change in return on equity of 1.4 percent. GAS FUEL REVENUE MECHANISMS The BCAP is the major rate proceeding for the Company's natural gas service. As part of this proceeding, the gas fuel revenue requirement and gas transportation revenue requirement are adopted, based on forecasts and assumptions for the upcoming two-year period. The gas fuel revenue requirement provides for the recovery of the cost of the gas procured for core customers; the gas transportation revenue requirement provides for the recovery of the cost of providing gas transportation service for all gas customers and other costs incurred in providing gas service, and also includes the gas base revenue requirement set in the GRC and adjusted by the ARA mechanism. Both the gas fuel revenue requirement and the gas transportation revenue requirement set in the BCAP include amounts accumulated in several associated balancing accounts. The main balancing account associated with the gas fuel revenue requirement is the Purchased Gas Account (PGA), which accumulates differences between the actual cost of gas procured for core customers and the revenues intended to recover those costs. The main balancing accounts associated with the gas transportation revenue requirement are the core and noncore Gas Fixed Cost Accounts (GFCAs), which generally accumulate differences between the actual transportation revenues and the authorized transportation revenue amounts for the core and noncore customer classes, respectively. In the case of the noncore GFCA, only 75% of any overcollection or undercollection of revenues is included in rates. BCAP rate adjustments may also include amounts accumulated in the Interstate Transition Cost Surcharge (ITCS) balancing account. Demand charges for interstate gas transportation capacity held by a utility which are not fully recovered under the operation of the CPUC's capacity brokering rules accumulate in the ITCS account and are recovered as authorized by the CPUC. Unrecovered demand charges will be allocated to customers on an equal cents-per-therm-usage basis, subject to a limit on the amount that can be allocated to core customers. In addition to adopting the gas revenue requirements in the BCAP, the CPUC also allocates both the gas fuel and transportation revenue requirements among core and noncore classes and among the customer groups within those classes. Revenue allocation (also referred to as cost allocation) is based primarily on forecasts of demand and use by each customer class. The BCAP also includes the rate design process, in which it is determined how specific costs are recovered from customers, with rates set accordingly. Generally, a BCAP filing is made on August 15 of every other year for rates to be effective on April 1 of the following year. An interim filing, referred to as a trigger filing, is permitted to set new rates for the second year of the BCAP period if amortization of accumulated overcollections or undercollections in balancing accounts would change either bundled core rates or noncore transportation rates by more than 5%. 6 13 In December 1992, the CPUC announced proposed rules which would (i) extend the gas ratemaking cycle from two to three years and (ii) reduce the amount of balancing account protection provided for noncore transportation revenues. Other than accepting comments from interested parties, the CPUC has taken no further action on the proposed rules. OTHER RATE ADJUSTMENT MECHANISMS Under the Customer Energy Efficiency (CEE) ratemaking mechanism adopted in 1990, the Company is authorized to recover in rates some of the energy savings resulting from and costs of certain of its CEE, or Demand Side Management (DSM), programs. CEE rate adjustments resulting from shareholder incentives earned on CEE programs are determined as part of the Annual Earnings Assessment Proceeding (AEAP), a consolidated proceeding established by the CPUC to authorize shareholder earnings for the Company and the other California energy utilities arising out of the previous year's DSM program accomplishments. AEAP rate adjustments will be consolidated with any other rate changes effective on January 1 of each year. See "Customer Energy Efficiency/Demand Side Management Programs" below. The Catastrophic Events Memorandum Account (CEMA) permits utilities to record for eventual recovery through rates the reasonable costs they incur in restoring service, repairing or replacing facilities and complying with government orders following a catastrophic event which is declared a disaster by the appropriate federal or state authorities. The utility must seek recovery of costs accumulated in the CEMA through a GRC or other formal rate-setting application, with recovery subject to a reasonableness review by the CPUC. PROPOSED REGULATORY REFORMS A number of proposals have been made by both the CPUC and the Company to effect reforms to the current regulatory approach to setting rates for California utilities. The most significant of these proposed reforms are detailed below. ELECTRIC INDUSTRY RESTRUCTURING PROPOSAL In April 1994, the CPUC issued an order instituting a rulemaking and investigation (OIR/OII) on electric industry restructuring. The proposal, which is subject to comment and modification, involves two major changes in electric industry regulation. The first would move electric utilities from traditional ratemaking to PBR. The second would unbundle electric services and provide electric utility retail customers the option to choose from a range of electric generation providers, including utilities. The CPUC characterized this approach as customer direct access. Under the CPUC's proposal, customer direct access to power supplies would be phased in over a six-year period from 1996 to 2002. Utilities would still be obligated to provide transmission and distribution services to all customers. To ensure an orderly transition that maintains the financial integrity of the utilities, the CPUC proposed that uneconomic costs of utility generating assets (i.e., costs which are above market and could not be recovered under market-based pricing) be recovered through a competition transition charge (CTC). However, the OIR/OII did not specify which costs might be recovered through such a transition charge or how such a charge would be allocated to and collected from customers. In June 1994, the Company filed its initial comments on the CPUC's proposal. The Company's response generally supported the CPUC's direct access approach to restructuring the energy services industry, but proposed an implementation schedule for direct access beginning in 1996, with direct access service available to all customers by 2008. The Company indicated that if its proposed implementation schedule is adopted, it will request recovery of certain incurred and committed costs through the CTC, but will not request recovery of transition costs associated with its electric generation facilities. The Company also indicated that it did not intend to shift costs between customer classes. For direct access customers, the Company proposed that it be given the pricing flexibility to compete and sell unbundled electric power while assuming the market risk of competitive pricing. The Company indicated that its proposed schedule, coupled with pricing flexibility, will 7 14 permit the Company sufficient time to reduce its generation costs and recover its investment in facilities built to meet its long-standing utility service obligations. Under the Company's proposed implementation schedule for direct access, industrial and large commercial customers (which represented approximately 30% of the Company's electric generation revenues in 1994) would be eligible for direct access in the period 1996 through 2002. The remaining non-residential customers (which represent approximately 31% of 1994 electric generation revenues) would be eligible in the period 2003 through 2006. Residential customers (which represent approximately 39% of 1994 electric generation revenues) would be eligible in 2007 and 2008. In its response, the Company proposed that unless and until a policy decision is made to discontinue existing environmental or social benefit programs, the costs of those programs should be allocated to all electric customers, including those who elect direct access, and included as a separately identified component on customers' bills. The Company also proposed to retain an ongoing obligation to provide electric power for residential customers, but suggested that the utility should be obligated to provide electric supply only on a best efforts basis to non-residential direct access customers that decide to return to the Company for their power supply and on terms of service to be negotiated. In November 1994, the Company filed testimony with the CPUC on uneconomic assets and obligations which would result from the CPUC's proposed electric industry restructuring. The Company indicated that the CTC should be permitted to provide for three types of costs: (1) utility-owned generation assets and obligations resulting from power purchase agreements other than contracts with QFs, (2) QF power purchase obligations, and (3) generation-related regulatory assets. The Company also indicated that it would not seek CTC recovery for the first of these categories -- costs associated with utility-owned generation assets and non-QF obligations -- if direct access is phased in over a 12-year period consistent with the proposal made by the Company in June 1994 and if pricing flexibility was provided to allow the Company to successfully compete to provide energy services to direct access eligible customers. The Company has since filed revised testimony which reflects the proposed agreement to modify the pricing provisions of the Diablo Settlement. See "Diablo Canyon -- Diablo Settlement" below. If the agreement is approved, it would reduce the amount of potential transition costs associated with the Company's generation assets. The table below sets forth the Company's revised estimates of the CTC which reflects the proposed settlement amounts for Diablo Canyon. ILLUSTRATION OF PG&E'S POTENTIAL CTC* USING PG&E'S COMPETITIVE PROXY PRICE AND REVISED DIABLO PRICING
1996 PRESENT VALUE @ 9.2% ($ BILLIONS) ------------------------------------------------------------------------------------------------------- COMPETITIVE PROXY PRICE (C/KWH) ------------------------------------------------- DESCRIPTIONS 3.2C IN 1994 4.0C IN 1994 4.8C IN 1994 -------------------------------------------------- ------------- ------------- ------------- PG&E Generation w/Revised Diablo Pricing.......... $5.9 $0.9 $0.0 QF Contracts...................................... $4.0 $2.9 $2.0 Generation-Related Regulatory Assets.............. $0.9-$1.3 $0.9-$1.3 $0.9-$1.3 Total CTC............................... $10.8-$11.2 $4.7-$5.1 $2.9-$3.3
- --------------- * The calculations reflected in the table are based on numerous assumptions, variables and estimates of future prices, energy supplies and economic trends. The CTC shown should be viewed only as preliminary estimates. The adopted CTC could be higher or lower depending on the method and assumptions selected by the CPUC for deriving the CTC. These CTC estimates were determined by comparing the future revenue requirements of generation assets (including Diablo Canyon at the proposed modified prices) and power purchase obligations over a twenty-year and thirty-year period, respectively, with the revenues computed at the assumed market price. 8 15 The revenue requirement for Diablo Canyon and all Company-owned generation assets included a return on investment. The actual amount of uneconomic assets and obligations will depend upon the final form of regulatory changes adopted by the CPUC and the actual market price of electricity. CTC recovery less than the amount estimated by the Company will not equate to the loss, if any, the Company may record as a result of the electric industry restructuring. See "Financial Impact of the Electric Industry Restructuring Proposal" below. In December 1994, the CPUC issued an interim decision in the OIR/OII. The decision set a schedule under which the CPUC would propose a policy decision in March 1995, with a final policy decision effective no earlier than September 1995. However, on March 21, 1995, the CPUC announced that it was postponing issuance of its proposed policy statement to allow additional time for analysis of the extensive record developed in the OIR/OII. It is expected that, when it is issued, the CPUC's proposed policy statement will be subject to hearings and state legislative review before it can be implemented. The CPUC's December 1994 interim decision also established a public working group to comment on unbundling and cost recovery, social programs and resource procurement under several different models for restructuring which involve direct access or a supply pool for use by wholesale and/or retail purchasers of electricity. The working group, which consisted of the energy utilities and any other parties who joined voluntarily, submitted its report to the CPUC in February 1995. In an effort to allow large energy users to begin exercising choice among electricity suppliers while public policy issues are resolved in the OIR/OII, the Company has requested CPUC approval to implement an experimental program under which California utilities would offer certain customers the option to receive electricity from competitive suppliers beginning as early as January 1996. See "Company's Proposals -- Experimental Procurement Service for Customer-Identified Electric Supply" below. FINANCIAL IMPACT OF THE ELECTRIC INDUSTRY RESTRUCTURING PROPOSAL The transition to a competitive market environment may affect the Company's future revenues and cash flows. In the event that recovery of the Company's costs and investments becomes unlikely or uncertain due to competitive pressures or regulatory changes, it could cause the Company to write off applicable portions of its regulatory assets. The final CPUC determination of uneconomic costs and the method and amount of recovery could adversely affect the Company's returns on its investments in electric generation assets. If future electric generation revenues are insufficient to recover the Company's investments and QF obligations, the Company would recognize a loss upon the determination of the competitive price for electricity resulting from the electric industry restructuring. The book value of the Company's generation assets, excluding Diablo Canyon, is approximately $2.7 billion at December 31, 1994. The net book value of the Company's investment in Diablo Canyon is approximately $5.2 billion at December 31, 1994. The Company currently accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result of applying the provisions of SFAS No. 71, the Company has accumulated approximately $3.7 billion of regulatory assets, including balancing accounts, as of December 31, 1994. If the OIR/OII is adopted as proposed by the CPUC or the Company determines that future electric generation rates will no longer be based on cost-of-service, the Company will discontinue application of SFAS No. 71 for the electric generation portion of its operations. If such discontinuance should occur, the Company would write off all applicable generation-related regulatory assets to the extent that transition cost recovery is not assured. The regulatory assets attributable to electric generation, excluding balancing accounts of approximately $700 million which are expected to be recovered in the near term, are estimated to be $1.6 billion at December 31, 1994. This amount could vary depending on the allocation methods used. The final determination of the financial impact will depend on the form of regulation, including transition mechanisms, if any, adopted by the CPUC and the groups of customers affected. Currently, the Company is unable to predict the ultimate outcome of the electric industry restructuring or predict whether such outcome will have a significant impact on its financial position or results of operations. 9 16 COMPANY'S PROPOSALS Experimental Procurement Service for Customer-Identified Electric Supply In February 1995, the Company requested CPUC approval to implement a statewide three-year experimental program under which California utilities would offer industrial customers and other large energy users the option to receive electricity from competitive suppliers, starting as early as January 1, 1996. The Company's proposed program would include the following key features: -- A group of large electricity users would be permitted to enter into individually negotiated "buy/sell" agreements with alternative suppliers of electricity. This "buy/sell" proposal would be modeled to a large extent after the "customer identified gas" (CIG) program implemented by the CPUC in 1991 as part of its restructuring of the natural gas industry. The utility would purchase electricity on behalf of each participating customer. The electricity would be purchased from any supplier chosen by the customer, at a price previously negotiated by the customer. The utility then would resell the electricity to the customer at the customer's negotiated price, as part of a bundled retail sale to that customer. For customers who elect to purchase energy from alternative sources located outside the Company's service territory, the Company will agree to use a portion of its transmission capacity (up to 50 megawatts (MW) at the Oregon-California border to accommodate purchases on behalf of customers whose suppliers deliver at that point. The Company will accept and buy power delivered to its other points of interconnection, and amounts in excess of 50 MW at the Oregon-California border interconnection, only if transmission capacity is available. -- The number of the Company's customers eligible to participate in the experiment would increase each year. The experimental program initially would apply in 1996 to customers with annual average demand above 7,500 kilowatts (kW) (approximately 30 customers). In 1997 customers with annual average demand above 4,000 kW (approximately 50 additional customers) would be eligible for the program, joined in 1998 by customers with annual average demand above 2,000 kW (approximately 110 additional customers). -- Utilities would be permitted to negotiate agreements with customers to compete with alternative suppliers of electricity. Lower revenues to the utility resulting from such individually negotiated contracts would not be offset through rate increases to other customers, putting shareholders at risk for any loss of revenue resulting from the experimental program. The Company estimates that if, upon full implementation of the experiment, all eligible customers who might find it economic participated in the buy/sell program and were able to use alternative suppliers to meet their entire load requirements, the maximum annual revenues that could be lost to the Company, net of generation costs saved as a result of customers' participation in the buy/sell program, is approximately $21 million. -- Customers participating in the "buy/sell" experiment would receive a predetermined credit on their utility bills which is based on prices paid to QFs for energy and capacity. This credit is used as a proxy for the market price of electricity. Added to participating customers' bills would be the cost of power they negotiated with an alternative supplier. -- The participating customers' prices would remain fully "bundled," a full package of services at one price. This would mean that issues such as unbundling, recover of transition costs, funding of social and environmental programs and resolution of state and federal jurisdictional matters would not have to be resolved prior to commencement of the experimental program. -- At the conclusion of the three-year experimental program, the information gained could be used by public policy makers to evaluate the benefits of customer choice. PBR In March 1994, the Company filed an application with the CPUC requesting that it adopt the Company's proposed Regulatory Reform Initiative (RRI). The Company's RRI included, among other things, a PBR proposal. While the guiding principles behind the Company's RRI proposal are not affected by the OIR/OII, many of the specifics would change. Once the details of the CPUC's electric industry restructuring plan are 10 17 sufficiently definitive, the Company proposes to revise its RRI filing to reflect the CPUC's plan. The Company expects to seek a revised RRI that includes PBR for determining base revenues annually by formula rather than through GRCs, ARAs and Cost of Capital proceedings. CPIM Specific proposals regarding a gas procurement mechanism were not included in the Company's March 1994 RRI filing. However, in December 1994, the Company filed an application for approval of the CPIM, a three-year experimental gas procurement incentive mechanism for core procurement purchases. The CPIM reflects an agreement with the DRA and would, among other things, replace traditional reasonableness review of gas costs with a comparison to a market-based benchmark. The CPIM covers all of the Company's purchases of commodity gas and pipeline capacity for its core and core subscription customers. (Core subscription customers are noncore customers who elect to receive combined procurement and transportation service from the Company.) The CPIM does not cover any gas base costs, including amounts associated with storage operations, gas and pipeline capacity purchased for the Company's power plants or out-of-state pipeline capacity beyond that reserved for the core and core subscription customers. Under the CPIM, the reasonableness of the Company's core gas purchases is determined by a comparison of actual costs against a market benchmark. The Company is either rewarded or penalized depending on whether its actual incurred costs fall below or above the benchmark and a tolerance band, or reasonableness zone. The Company would recover all costs that fall within the reasonableness zone; ratepayers and shareholders would share the costs or savings if actual costs fall above or below the reasonableness zone. The Company proposed an expedited schedule under which the CPUC would approve the CPIM by May 1995. However, protests have been filed requesting hearings or workshops on the Company's CPIM application, and it is not clear when a CPUC decision will be issued. Pricing Flexibility Proposals The Company has filed testimony in its 1995 electric rate design window (RDW) proceeding proposing beneficial rate options for certain industrial, commercial and agricultural customers who might otherwise not take service from the Company. The CPUC's GRC plan establishes the RDW as a forum for considering certain rate design changes in years between GRCs. The Company's proposals are narrowly focused to provide beneficial options to some customers. Specifically, the Company proposes several standard contracts for commercial and industrial customers which offer prices based upon the cost of the customer's alternatives or, in some cases, specified discounts from the Company's rates. (These contracts are similar to those contemplated in the Large Electric Manufacturing Class proposal that was included in the Company's March 1994 RRI filing.) In addition, the Company proposes rate options which would establish discounts from the current rates charged to certain agricultural customers. Although the Company's RDW filing seeks to have any revenue shortfall associated with these rate options allocated to all customers in future revenue allocation proceedings, in other instances in which the CPUC has approved similar rate options, revenue shortfalls have been allocated, in whole or in part, to shareholders. With respect to gas service, the Company filed a petition with the CPUC in June 1994 requesting authorization to implement an optional long-term competitive noncore gas transportation tariff which would be offered to the Company's largest gas transport customers under a ten-year firm service agreement. The Company's petition indicated that its shareholders would bear the risk of any revenue shortfalls attributable to differences between the long-term rate option and the customer's otherwise applicable standard rate. In September 1994, the CPUC issued a decision approving the Company's proposed long-term noncore gas transportation tariff, but subject to certain conditions that were not contemplated by the Company's original proposal. The Company has filed a petition for rehearing of that decision, and indicated that if the CPUC continues to insist upon its proposed conditions as the basis for its approval of the proposed tariff, the Company intends to decline to implement the proposed tariff and would not voluntarily accept the tariff as modified by the CPUC. 11 18 As an alternative service option, in October 1994 the Company began offering a standard 59-month interruptible transportation service, at a rate comparable to that requested under the noncore gas transportation tariff proposal, to noncore customers with potential transportation alternatives. A potential competitor of the Company has filed a complaint at the CPUC challenging the Company's use of this service option on several grounds. The CPUC has not yet acted on the complaint. CURRENT RATE PROCEEDINGS In August 1994, the Company announced that it would extend through 1995 its freeze on retail electric rates which began in 1993. The Company also announced that it would continue its annual $70 million economic stimulus rate reduction through 1995 for its largest business customers. (The Company has since proposed to extend its electric rate freeze and the economic stimulus rate reduction through 1996.) In December 1994, the CPUC approved the continuation of the electric rate freeze through 1995 and issued its decisions in the Company's ARA and ECAC proceedings. In order to accomplish the electric rate freeze, the effects of the CPUC decisions on the Company's various electric rate proceedings were consolidated, resulting in a net change in electric rates of zero, effective January 1, 1995 (see "1995 Revenue Changes" below). 1995 REVENUE CHANGES The following table summarizes the various rate case decisions that became effective on January 1, 1995. SUMMARY OF RATE CASE DECISIONS EFFECTIVE JANUARY 1, 1995 (IN MILLIONS)
ELECTRIC GAS TOTAL ----- ---- ----- 1995 Attrition (excluding Cost of Capital)...................... $ 0 $ 69 $ 69 1995 Cost of Capital............................................ 105 33 138 Helms Proceeding................................................ 12 -- 12 Petition to Modify 1993 GRC (reduced CEE and RD&D funding)...... (117) (33) (150) ARA Proceeding.................................................. (158) -- (158) ITCS............................................................ -- 31 31 ECAC/AER/ERAM/LIRA/CEE.......................................... 158 -- 158 ----- ---- ----- Total Change in Revenue Requirement................... $ 0 $100 $ 100 ===== ==== =====
ARA Proceeding. In December 1994, the CPUC issued a resolution authorizing the Company to implement an ARA to keep the Company's retail electric rates unchanged through 1995, consistent with the Company's 1995 electric rate freeze. The CPUC authorized the Company to forgo the electric rate increase of approximately $170 million that otherwise would have occurred on January 1, 1995 as authorized in the Company's 1993 GRC. In addition, the CPUC adopted the Company's proposal to decrease electric base revenues in an amount equal to the increase in revenues approved by the CPUC in the Company's 1995 Cost of Capital proceeding and ECAC proceeding (as described below), and the increase in revenues contemplated by the proposed settlement in the Helms proceeding (see "Electric Utility Operations -- Helms Pumped Storage Plant" below), such that electric rates will not increase through the end of 1995. The Company is implementing base cost reductions which are reflected in the decreased base revenues. The CPUC also authorized the implementation of an ARA which results in an increase of $69 million for gas base rates. Combined with the previously authorized increases of $33 million relating to the 1995 Cost of Capital proceeding and $31 million for partial recovery of amounts accrued in the ITCS balancing account (see "Gas Utility Operations -- Restructuring of Interstate Gas Supply Arrangements -- Recovery of Interstate Transportation Demand Charges" below), and approval of the Company's request to reduce authorized funding for gas CEE programs in 1995 by $33 million, gas revenues increased, effective January 1, 1995, by approximately $100 million, or 4.7% over rates previously in effect. 12 19 Also in December 1994, the CPUC granted the Company's request for reductions of approximately $100 million in authorized funding levels for 1995 electric CEE programs and $17 million for electric research development and demonstration (RD&D) programs. The request for such reductions was made as part of the Company's efforts to control costs under its electric rate freeze plan. 1995 Cost of Capital Proceeding. As part of its ruling in the annual generic Cost of Capital proceeding for California's major energy utilities, the CPUC authorized the Company to set rates in 1995 to provide a utility return on common equity of 12.10%. This represents an increase from the 11.00% return on common equity allowed in 1994. The higher return on common equity is intended to recognize increased interest rates as well as increased risks associated with the CPUC's OIR/OII on electric industry restructuring in California. The decision authorizes a utility capital structure of 48.00% common equity, 5.50% preferred stock and 46.50% long-term debt, which represents an increase from 47.50% in the current equity component of the Company's capital structure. The combined authorized costs of debt, preferred stock and the 12.10% return on common equity results in an overall return on rate base of 9.79% for 1995, compared with the 9.21% authorized for 1994. The decision increased revenue requirements by approximately $105 million for electric rates and $33 million for gas rates, effective January 1, 1995. However, consistent with the Company's current electric rate freeze, the electric revenue increase authorized in this proceeding was offset by a decrease in base revenues, such that electric rates will not increase through the end of 1995. ECAC. In December 1994, the CPUC issued a decision in the Company's 1995 ECAC proceeding which adopted all of the Company's proposals to continue the electric rate freeze currently in effect, including a $158 million ECAC increase, a base rate decrease approved in the ARA proceeding described above, an early refund of $84 million in CEE program dollars collected from ratepayers but not spent in 1993 and 1994, and deferral of collection of approximately $444 million of ECAC costs forecasted to be undercollected as of December 31, 1995. In granting the deferral, the decision continued imposition of the three conditions placed on the first deferral in the 1994 ECAC proceeding: (i) reinstatement of the AER mechanism, which places shareholders at risk for 9% of any deviations from forecasted operations, (ii) no interest on the estimated revenue requirement deferral, and (iii) written notification to all parties if the Company forecasts that rates would need to rise an additional 5% or more to amortize the undercollection. In its decision the CPUC agreed with the Company that the forgoing of interest on the deferral was limited to the adopted deferral amount and not to undercollections resulting from forecast error. The decision also makes it clear that the deferral would not be considered a transition cost in any restructuring of the electric industry, but should be separately collected from the customers receiving electric service during the period in which the deferred amounts were incurred. The ECAC decision also approved continuation of the Company's economic stimulus rate reduction, an annual $70 million rate reduction offered to the Company's largest business customers. The rate reduction, originally offered in July 1993, was developed to help attract and retain major employers in Northern and Central California. Although the ability of the Company to recover the ECAC balancing account undercollection has been impacted by the Company's freeze on retail electric rates, the proposed modification of the price for Diablo Canyon power will assist in reducing the ECAC balance. The Company currently believes that the ECAC balance will be collected in rates over the near term. BIENNIAL COST ALLOCATION PROCEEDING In July 1994, the CPUC approved the Company's request for an increase of $162 million (9.3%) in core gas rates effective July 15, 1994. The Company had requested the increase in an interim, or trigger, filing as permitted under the BCAP mechanism to set new rates for the second year of the BCAP period. During the first half of the applicable BCAP period (November 1992 -- October 1993), actual gas costs were higher than the forecasted costs used to adopt rates and actual gas sales were less than expected, leading to unrecovered gas and related fixed costs. In November 1994, the Company filed an application with the CPUC in its 1995 BCAP requesting a gas rate increase of approximately $173 million annually for the two-year test period beginning October 1, 1995, and ending September 30, 1997. The Company's request reflects a $53 million annual increase in procurement 13 20 revenues and a $120 million annual increase in transportation revenues. If the Company's request is adopted, rates would be effective September 15, 1995. A final CPUC decision is expected in the third quarter of 1995. 1996 GENERAL RATE CASE The Company filed its 1996 GRC application in December 1994 for base rates effective January 1, 1996. The application, as updated by the Company since the original filing, requests no change in electric revenues and a $163 million decrease in gas revenues, compared to rates in effect in 1995. The electric and gas requests will be consolidated with other proceedings, including the BCAP, the ECAC and the Cost of Capital proceedings, to determine the revenues to be collected from customers in 1996. (The request included in the original application to increase revenues by $13 million for the California, or in-state, portion of the Pipeline Expansion (see "Gas Utility Operations -- PGT/PG&E Pipeline Expansion Project" below) will be considered in a separate proceeding.) Since the Company anticipates that the CPUC will have implemented the Company's proposed PBR mechanism for determining base revenues before January 1, 1997, the Company's GRC application does not request the adoption of an ARA for the years 1997 and 1998. In March 1995, the DRA submitted its report on the Company's GRC application. The DRA recommendation, which is subject to further revision, proposes an overall revenue requirement which is significantly lower than that requested by the Company. The DRA recommends that the Company reduce its electric revenue requirement by $434 million (compared with the Company's request for no change), and its gas revenue requirement by $292 million (compared with the Company's request for a $163 million reduction). A significant portion of the difference between the revenue requirement requested by the Company and that recommended by the DRA relates to administrative and general expenses and the level of wages and benefits paid to Company employees. Hearings on the 1996 GRC are expected to begin in April 1995, with a final decision on the application expected in December 1995. WORKFORCE REDUCTION RATE MECHANISM In March 1993, the CPUC authorized the establishment of a memorandum account to record all costs and savings incurred in connection with the Company's 1993 workforce reduction program, subject to a reasonableness review. In October 1993, the Company filed a report with the CPUC to update the forecasted costs and savings associated with the workforce reduction program. As proposed in its filing with the CPUC, the Company's net revenue requirement savings expected to be achieved during the 1993 GRC cycle through the workforce reduction program are being passed on to ratepayers over a two-year period beginning January 1, 1994. These estimated savings total approximately $156 million. The total cost of the 1993 workforce reduction program was $264 million, net of a curtailment gain relating to pension benefits. As a result of the Company's freeze on electric rates in 1994, the Company expensed $190 million of such costs relating to electric operations. The amount relating to gas operations was deferred for future rate recovery and is being amortized as savings are realized. At December 31, 1994, $31 million remained to be amortized. CUSTOMER ENERGY EFFICIENCY/DEMAND SIDE MANAGEMENT PROGRAMS The Company has long been active in the implementation of CEE and other DSM programs which encourage customers to implement energy-efficient measures. These measures allow the Company to defer capital expenditures in connection with generation, transmission and distribution facilities, reduce operating costs, reduce the environmental impact of operations and provide service options to customers. In addition, these measures help to minimize the use of existing fossil fueled generation. Since the mid-1970s, the Company has expended over $1.5 billion on DSM programs, allowing the Company to avoid the need for approximately 1,600 MW of new generating capacity. Since 1990, the CPUC has permitted the Company to earn shareholder incentives on its CEE programs. For resource programs which are designed to produce positive net benefits (i.e., the net present value of the avoided energy, capacity, transmission and distribution costs of the programs exceeds the cost of the CEE 14 21 program), the shareholder incentive is a percentage of the positive net benefits. For certain service programs, including the Company's direct weatherization and energy efficiency education programs, the shareholder incentive is 5% of the cost of the programs. In a 1993 decision, the CPUC determined that shareholder incentives on resource programs will be based on actual measured energy savings rather than forecasted savings, beginning with the 1994 DSM programs. The decision also concluded that, starting with the 1994 programs, shareholder incentives will be recovered in rates in four equal installments over a ten-year period, and the amount recoverable will be subject to the outcome of periodic measurement and evaluation studies. Beginning in 1994, the amount of shareholder incentives authorized for the Company and other California utilities will be determined annually in the AEAP. In early 1994, the Company filed the first annual AEAP application, requesting shareholder incentives for its 1993 CEE programs. The CPUC granted the Company's request of $14.9 million in shareholder incentives to be recovered over a three-year period. The Company estimates that it will earn approximately $15 million (after-tax) in shareholder incentives from the 1994 CEE programs. In accordance with the 1993 decision, the 1994 shareholder incentive will be collected in four installments over a ten-year period, and will be adjusted based on the results of measurement and evaluation studies. In October 1994, the CPUC issued a decision establishing the incentive mechanism and incentive level for DSM programs in 1995 and beyond. The shareholder incentive level is established at 30% of the net benefits of the resource programs. However, the utilities must guarantee the overall cost effectiveness of their residential and non-residential portfolio of programs. If a portfolio is not cost-effective, the utility must refund to ratepayers the amount by which the costs of the programs exceed the resource benefits of the portfolio. If the actual accomplishments of a portfolio fall below a minimum performance standard established for the portfolio, the entire portfolio will be ineligible for shareholder incentives. The Company plans to spend approximately $150 million on CEE programs in 1995, compared to the $235 million spent on 1994 programs. The new shareholder incentive mechanism and the requirement of ex post measurement of energy savings over the 10 years makes an estimate of earnings over that period difficult at this time. The Company currently estimates it will earn approximately $57 million in shareholder incentives over the 10-year period as a result of the 1995 programs. The Company is permitted to recover, through a balancing account, up to a maximum of 130% of the program expenses authorized for resource programs. CAPITAL REQUIREMENTS AND FINANCING PROGRAMS The Company continues to require capital for improving its existing generation, transmission and distribution facilities to maintain their efficiency and reliability, to extend their useful lives and to comply with environmental laws and regulations. Expenditures for these purposes, including the allowance for funds used during construction (AFUDC) were approximately $1.1 billion for 1994. New investments in nonregulated businesses totaled $328 million in 1994. The following table sets forth the estimated total capital requirements, consisting of capital expenditures for the utility functions, Diablo Canyon and the nonregulated investments of Enterprises and amounts for maturing debt and sinking funds for the years 1995 through 1999. CAPITAL REQUIREMENTS (IN MILLIONS)
1995 1996 1997 1998 1999 TOTAL ------ ------ ------ ------ ------ ------- Utility(1)(2)........................... $1,212 $1,276 $1,237 $1,255 $1,304 $ 6,284 Diablo Canyon(2)........................ 47 50 52 54 56 259 Enterprises(3) DALEN Resources Company(4)............ 120 -- -- -- -- 120 U.S. Generating Company(5)............ 142 125 84 173 166 690 Other(6).............................. 23 17 200 203 198 641 ------ ------ ------ ------ ------ ------- Total Capital Expenditures......... 1,544 1,468 1,573 1,685 1,724 7,994 Maturing Debt and Sinking Funds......... 477 373 369 715 317 2,251 ------ ------ ------ ------ ------ ------- Total Capital Requirements......... $2,021 $1,841 $1,942 $2,400 $2,041 $10,245 ====== ====== ====== ====== ====== =======
(See footnotes on following page) 15 22 - --------------- (1) Utility expenditures are shown net of reimbursed capital and include California electric and gas operations and existing operations of the gas pipeline from Canada to California. Utility expenditures also include amounts relating to the expansion of PGT's pipeline system in 1995 through 1996 to provide additional deliveries in the Pacific Northwest. Capital expenditures relating to such further expansion total approximately $34 million. PGT is also considering a further expansion of its system which, if warranted by market demand at the time, could require capital expenditures of approximately $180 million during 1996 and 1997, which amount is not included in the table above. (2) Utility expenditures include AFUDC. Expenditures for Diablo Canyon and the in-state portion of the PGT/PG&E Pipeline Expansion (see "Gas Utility Operations -- PGT/PG&E Pipeline Expansion Project" below) include capitalized interest. (3) Enterprises' actual capital expenditures may vary significantly depending on the availability of attractive investment opportunities. (4) In July 1994, the Company approved a plan for the disposition of DALEN Resources Corp. (DALEN), formerly PG&E Resources Company. (5) U.S. Generating Company's expenditures include commitments by the Company and/or Enterprises to make capital contributions for Enterprises' equity share of currently identified generating facility projects. These contributions, payable upon commercial operation of the projects, are estimated to be $100 million and $114 million in 1995 and 1996, respectively. There are no current commitments to make contributions in 1997 or thereafter. (6) "Other" includes development and investment activity for international power generation, real estate and corporate development activities. Most of the utility capital expenditures for 1995 through 1999 are associated with short lead time, modest capital expenditure projects aimed at providing the facilities required by new customers and at the replacement and enhancement of existing generation, transmission, distribution and common utility facilities to maintain their efficiency and reliability and to comply with environmental laws and regulations. One exception is the seismic retrofit of part of the Company's general office complex in downtown San Francisco. The Company estimates that, in addition to the capital expenditure objectives referred to above, its total capital requirements for the years 1995 through 1999 will include approximately $2,251 million for payment at maturity of outstanding long-term debt and for meeting sinking fund requirements for debt. In January 1995, the Board of Directors authorized the Company to redeem or repurchase up to $153 million of mortgage bonds. In addition, $85 million remains from a previous authorization to repurchase medium-term notes. In 1994, the Company redeemed or repurchased $135 million of mortgage bonds, medium-term notes and Eurobonds. Redemptions and repurchases were financed in part by the issuance in 1994 of $30 million of medium-term notes and $63 million of redeemable preferred stock. The funds necessary for the Company's 1995-1999 capital requirements will be obtained from (i) internal sources, principally net income before noncash charges for depreciation and deferred income taxes, and (ii) external sources, including short-term financing, such as bank loans and the sale of short-term notes, and long-term financing, such as sales of equity and long-term debt securities, when and as required. The Company conducts a continuing review of its capital expenditures and financing programs. The programs and estimates above are subject to revision based upon changes in assumptions as to system load growth, rates of inflation, receipt of adequate and timely rate relief, availability and timing of regulatory approvals, total cost of major projects, availability and cost of suitable nonregulated investments, and availability and cost of external sources of capital. 16 23 ELECTRIC UTILITY OPERATIONS ELECTRIC OPERATING STATISTICS The following table shows the Company's operating statistics (excluding subsidiaries except where indicated) for electric energy, including the classification of sales and revenues by type of service.
YEARS ENDED DECEMBER 31 ---------------------------------------------------------------------- 1994 1993 1992 1991 1990 ---------- ---------- ---------- ---------- ---------- CUSTOMERS (AVERAGE FOR THE YEAR): Residential....................................... 3,788,044 3,748,831 3,708,374 3,665,055 3,604,327 Commercial........................................ 452,049 449,619 455,480 450,789 440,670 Industrial........................................ 1,260 1,243 1,207 1,186 1,102 Agricultural...................................... 90,520 91,376 94,562 96,270 98,131 Public street and highway lighting................ 16,709 16,096 15,681 15,314 14,979 Other electric utilities.......................... 29 28 24 21 20 ---------- ---------- ---------- ---------- ---------- Total....................................... 4,348,611 4,307,193 4,275,328 4,228,635 4,159,229 ========= ========= ========= ========= ========= GENERATED, RECEIVED AND SOLD -- KWH (IN MILLIONS): Generated: Hydroelectric plants............................ 7,791 14,403 7,537 7,996 8,008 Thermal-electric plants: Fossil fueled................................. 29,543 19,070 26,623 21,984 24,496 Geothermal.................................... 6,024 6,491 7,007 6,947 7,324 Nuclear....................................... 15,265 16,816 16,698 15,073 16,274 ---------- ---------- ---------- ---------- ---------- Total thermal-electric plants............... 50,832 42,377 50,328 44,004 48,094 Wind and solar plants........................... 1 -- -- -- -- Received from other sources(1).................... 47,199 48,859 46,243 48,966 46,682 ---------- ---------- ---------- ---------- ---------- Total gross system output(2)................ 105,823 105,639 104,108 100,966 102,784 Delivered for interchange or exchange............. 3,275 8,848 3,912 5,391 5,281 Delivered for the account of others(1)............ 18,622 13,726 17,235 13,602 16,093 Helms pumpback energy (3)......................... 467 452 398 593 396 Company use, losses, etc.(4)...................... 7,838 6,960 7,278 7,184 6,957 ---------- ---------- ---------- ---------- ---------- Total energy sold........................... 75,621 75,653 75,285 74,196 74,057 ========= ========= ========= ========= ========= POWER PLANT FUEL SUPPLY (IN THOUSANDS): Natural gas (equivalent barrels).................. 44,119 28,791 43,446 36,262 37,777 Fuel oil.......................................... 2,395 2,080 171 631 2,066 Nuclear (equivalent barrels)...................... 26,135 28,724 28,540 25,808 27,847 ---------- ---------- ---------- ---------- ---------- Total....................................... 72,649 59,595 72,157 62,701 67,690 ========= ========= ========= ========= ========= POWER PLANT FUEL COSTS (AVERAGE COST PER MILLION BTU'S): Natural gas....................................... $2.19 $2.86 $2.61 $2.75 $3.09 Fuel oil.......................................... $2.83 $3.49 $3.13 $3.00 $4.11 Weighted average.................................. $2.23 $2.90 $2.62 $2.75 $3.14 SALES -- KWH (IN MILLIONS): Residential....................................... 24,326 24,111 23,664 23,535 23,222 Commercial........................................ 26,195 26,258 26,246 25,758 25,867 Industrial........................................ 16,010 16,492 16,600 16,472 16,271 Agricultural...................................... 4,426 3,672 4,741 4,734 4,702 Public street and highway lighting................ 418 419 400 389 376 Other electric utilities.......................... 4,246 4,701 3,634 3,308 3,619 ---------- ---------- ---------- ---------- ---------- Total energy sold........................... 75,621 75,653 75,285 74,196 74,057 ========= ========= ========= ========= ========= REVENUES (IN THOUSANDS): Residential....................................... $2,980,966 $2,952,893 $2,790,605 $2,729,763 $2,418,250 Commercial........................................ 2,892,302 2,914,855 2,864,817 2,745,040 2,532,655 Industrial........................................ 1,128,561 1,183,728 1,210,754 1,186,452 1,071,714 Agricultural...................................... 477,330 419,628 478,941 477,397 429,445 Public street and highway lighting................ 55,545 55,976 53,133 50,631 47,121 Other electric utilities.......................... 201,133 242,433 185,555 204,089 217,276 ---------- ---------- ---------- ---------- ---------- Revenues from energy sales.................. 7,735,837 7,769,513 7,583,805 7,393,372 6,716,461 Miscellaneous..................................... 142,771 87,991 51,716 103,180 217,038 Regulatory balancing accounts..................... 127,549 8,539 111,971 (127,912) 102,572 ---------- ---------- ---------- ---------- ---------- Operating revenues.......................... $8,006,157 $7,866,043 $7,747,492 $7,368,640 $7,036,071 ========= ========= ========= ========= =========
- ---------- (1) Includes energy supplied through the Company's system by the City and County of San Francisco for San Francisco's own use and for sale by San Francisco to its customers, by the Department of Energy for government use and sale to its customers, and by the State of California for California Water Project pumping, as well as energy supplied by QFs and purchases from other utilities. (2) Includes energy output from Modesto and Turlock Irrigation Districts' own resources. (3) Represents energy required for pumping operations. (4) Includes use by business units other than the Electric Supply business unit. 17 24
YEARS ENDED DECEMBER 31 ----------------------------------------------------------------- 1994 1993 1992 1991 1990 --------- --------- --------- --------- --------- SELECTED STATISTICS: Total customers (at year-end)..................... 4,400,000 4,400,000 4,300,000 4,300,000 4,200,000 Average annual residential usage (kWh)............ 6,422 6,431 6,381 6,421 6,443 Average billed revenues per kWh (c): Residential..................................... 12.25 12.25 11.79 11.60 10.41 Commercial...................................... 11.04 11.10 10.92 10.66 9.79 Industrial...................................... 7.05 7.18 7.29 7.20 6.59 Agricultural.................................... 10.78 11.43 10.10 10.08 9.13 Net plant investment per customer ($)............. 3,362 3,436 3,428 3,445 3,443 Electric control area capability(1)(MW)........... 21,851 23,009 22,475 21,670 22,931 Electric net control area peak demand(2)(MW)...... 19,118 19,607 18,594 18,620 19,400
- ------------ (1) Area net capability at time of annual peak, based on actual water conditions. (2) Net control area peak demand includes demand served by Modesto and Turlock Irrigation Districts' own resources. ELECTRIC GENERATING AND TRANSMISSION CAPACITY As of December 31, 1994, the Company owned and operated the following generating plants, all located in California, listed by energy source:
NET OPERATING NUMBER CAPACITY GENERATION TYPE COUNTY LOCATION OF UNITS KW - ------------------------------------------ ------------------------------------ --------- Hydroelectric: Conventional Plants..................... 16 counties in Northern and 111 2,703,100 Central California Helms Pumped Storage Plant.............. Fresno 3 1,212,000 ------ --------- Hydroelectric Subtotal............. 114 3,915,100 ------ --------- Steam Plants: Contra Costa(1)......................... Contra Costa 2 680,000 Humboldt Bay............................ Humboldt 2 105,000 Hunters Point........................... San Francisco 3 377,000 Morro Bay............................... San Luis Obispo 4 1,002,000 Moss Landing(1)......................... Monterey 2 1,478,000 Pittsburg............................... Contra Costa 7 2,022,000 Potrero................................. San Francisco 1 207,000 ------ --------- Steam Subtotal.......................... 21 5,871,000 ------ --------- Combustion Turbines: Hunters Point........................... San Francisco 1 52,000 Oakland................................. Alameda 3 165,000 Potrero................................. San Francisco 3 156,000 Mobile Turbines(2)...................... Contra Costa and Humboldt 3 45,000 ------ --------- Combustion Turbines Subtotal............ 10 418,000 ------ --------- Geothermal: The Geysers(3).......................... Sonoma and Lake 14 1,224,000 Nuclear: Diablo Canyon........................... San Luis Obispo 2 2,160,000 ------ --------- Thermal Subtotal................... 47 9,673,000 ------ --------- Total........................................................... 161 13,588,100 ======= =========
- ---------- (1) Several fossil fuel steam units (527 MW) were on long-term standby reserve during 1994. The units require a 12-18 month reactivation time, and are included as unavailable capacity in the Control Area Net Capacity table below. Effective December 31, 1994, 12 units, totaling 1342 MW (including the 527 MW on long-term standby reserve), were retired in place. (2) Listed to show capability; subject to relocation within the system as required. (3) The Geysers net operating capacity is based on adequate geothermal steam supply conditions. Any decrease in capacity, at peak, is included as unavailable capacity in the Control Area Net Capacity table below. See "Geothermal Generation" below. 18 25 To transport energy to load centers, the Company as of December 31, 1994, owned and operated approximately 18,450 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 34,209,000 kilovolt-amperes (kVa). Energy is distributed to customers through approximately 105,527 circuit miles of distribution system and distribution substations having a capacity of approximately 22,091,000 kVa. The following table sets forth the available capacity for the control area (the area served by the Company and various publicly owned systems in Northern California) at the date of peak (including reduction for scheduled and forced outages and based on actual water conditions) by various sources of generation available to the control area and the total amount of generation provided by these sources during the year ended December 31, 1994.
CONTROL AREA NET CAPACITY (AT DATE OF 1994 PEAK) -------------------- KW % --------- Sources of Electric Generation: Company-Owned Plants: Fossil Fueled.................. 7,631,000 52 Geothermal..................... 1,224,000 8 Nuclear........................ 2,160,000 15 --------- ----- Total Thermal................ 11,015,000 75 Hydroelectric (available)...... 3,556,400 25 Solar.......................... 0 0 --------- ----- Total Company-Owned Capacity..... 14,571,400 100 ==== Less Unavailable Capacity...... (913,000) --------- Total Company Available Capacity....................... 13,658,400 62 Capacity Received from Others: QF Producers (available)....... 2,981,000 14 Area Producers & Imports...................... 5,211,600 24 --------- ----- Capacity from Others........... 8,192,600 38 --------- ----- Total Available Capacity......... 21,851,000 100 ========= ==== Total Area Demand(1)(2)............ 19,118,000 =========
GENERATION YEAR ENDED DECEMBER 31, 1994(3) ---------------------- KWH THOUSANDS % ------------- Electric Generation: Company-Owned Plants: Fossil Fueled.................. 29,542,611 28 Geothermal..................... 6,024,133 6 Nuclear........................ 15,264,977 15 ------------- ---- Total Thermal................ 50,831,721 49 Hydroelectric.................. 7,791,473 8 Solar.......................... 973 -- ------------- ---- Total Company Generation......... 58,624,167 57 Helms Pumpback Energy............ (466,524) -- ------------- ---- Net Company Generation......... 58,157,643 57 Generation Received from Others: QF Producers................... 21,692,229 21 Area Producers & Imports...................... 22,913,620 22 ------------- ---- Generation from Others......... 44,605,849 43 Total Area Generation............ 102,763,492 100 =========== ====
- ---------- (1) The maximum control area peak demand to date was 19,607,000 kW which occurred in August 1993. (2) The reserve capacity margin at the time of the 1994 control area peak, taking into account short-term firm capacity purchases from utilities located outside the Company's service area: spinning reserve (capability already connected to the system and ready to meet instantaneous changes in demand) to the control area peak was 6.7% of the peak demand and total reserve (spinning reserve and capability available within a short period of time) was 14.3%. (3) Represents actual year net generation from sources shown. ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT At present, California's long-range electric resource planning is coordinated between the California Energy Commission (CEC) and the CPUC. Every two years, the CEC prepares an Electricity Report that includes load forecasts and resource assumptions for a 20-year period. The CPUC conducts a Biennial Resource Plan Update (BRPU) proceeding which is linked to a specific CEC Electricity Report. The purpose of the BRPU is to determine whether any cost-effective electric resources (either new generating resources or power purchases) should be added to the regulated utilities' electric systems based on a 12-year planning horizon (as described below). In making this determination, the CPUC gives great weight to the load forecasts and resource assumptions included in the CEC's Electricity Report. The CEC has not yet adopted the complete 1994 Electricity Report (ER94). However, the CEC has adopted ER94 forecasts for energy loads and peak demands. The forecast for area electric peak demand (on a CEC area basis) indicates an increase from approximately 16,300 MW in 1994 to approximately 21,400 MW in 2013, reflecting a compound annual growth rate of 1.4%. The forecast for area electric energy load indicates an increase from approximately 88,600 gigawatt-hours (GWh) in 1994 to 116,100 GWh in 2013, reflecting a compound annual growth rate of 1.4%. The Company's current energy and peak demand forecasts after 2000 are higher than the CEC's ER94 forecast, primarily due to the Company's more optimistic economic and demographic assumptions. 19 26 For the remainder of this decade, the Company anticipates adding between 600 and 750 MW of electric resources. These resources will be comprised of (i) up to 265 MW of new purchases or company-owned resources resulting from the 1993 BRPU solicitation, assuming a recent FERC order finding the 1993 BRPU solicitation unlawful is not upheld, (ii) approximately 308 MW of new QF purchases to come on line by the end of 1996, (iii) between 49 and 200 MW of generation and DSM resources resulting from the integrated bid solicitation, (iv) improvements in its existing generating system, including 20 MW of upgrades of the hydroelectric system, and (v) further developments in regional operations efficiency from the Company's existing transmission lines from the Pacific Northwest. The Company currently plans no new major construction projects for electric supply before the year 2000, other than projects already under development. The future of electric resource acquisition is being addressed in the electric industry restructuring OIR/OII. However, future additions to satisfy electric supply needs in the Company's service territory likely will be determined largely through a competitive resource procurement process open to all potential suppliers. The Company has indicated its willingness to forgo competing in this process to build new generation resources if the CPUC grants the Company significant flexibility in conducting the planning and procurement process. The CEC committee conducting proceedings relating to the CEC's ER94 expanded the proceeding to include an extensive analysis of how changes in the structure of the electric industry may affect the achievement of California's energy policies. It is presently unclear to what extent considerations relating to electric industry restructuring will impact the content and timing of the final ER94. In 1993, the CPUC issued a decision in a DSM proceeding (see "General -- Customer Energy Efficiency/Demand Side Management Programs" above) which selected the Company to conduct an integrated bidding pilot program in which both resource generation and DSM bidders compete in the procurement process. The CPUC ordered the Company to conduct a pilot bid program for between 49 and 200 MW. The Company issued a request for bids in December 1994 and expects to file contracts in early 1996 for approval by the CPUC. ELECTRIC RESOURCES QF GENERATION Under the Public Utility Regulatory Policies Act of 1978 (PURPA), the Company is required to purchase electric energy and capacity produced by QFs. The CPUC established a series of power purchase agreements which set the applicable terms, conditions and price options. A QF must meet certain performance obligations, depending on the contract, prior to receiving capacity payments. The total cost of both energy and capacity payments to QFs is recoverable in rates. The Company's contracts with QFs expire on various dates from 1995 to 2026. Under these contracts the Company is required to make payments only when energy is supplied or when capacity commitments are met. In 1994, the Company negotiated the early termination or temporary suspension of seven QF contracts at a cost of $155 million, to be paid over a six-year period beginning in 1994. The amount has been deferred with the expectation that it will be recovered in future rates. Payments to QFs are expected to vary in future years. QF deliveries in the aggregate accounted for approximately 21% of the Company's 1994 total electric energy requirements and no single contract accounted for more than 5% of the Company's electric energy needs. The amount of energy received from QFs and the total energy and capacity payments made under these agreements were:
1994 1993 1992 ------ ------ ------ (IN MILLIONS) kWh received............................................. 21,699 21,242 21,173 Energy payments.......................................... $1,196 $1,099 $1,084 Capacity payments........................................ $518 $503 $489
20 27 As of December 31, 1994, the Company had approximately 5,900 MW of QF capacity under CPUC-mandated power purchase agreements. Of the 5,900 MW, approximately 4,600 MW were operational. Development of the balance is uncertain but it is estimated that only 300 MW of the remaining contracts will become operational. The 5,900 MW of QF capacity consists of 3,300 MW from cogeneration projects, 1,500 MW from wind projects and 1,100 MW from other projects, including biomass, geothermal, solar and hydroelectric. GEOTHERMAL GENERATION Because of declining geothermal steam supplies, the Company's geothermal units at The Geysers Power Plant (Geysers) are forecast to operate at reduced capacities. The consolidated Geysers capacity factor is forecast to be approximately 33% in 1995, which includes forced outages, scheduled overhauls and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 56% in 1994. The Company expects steam supplies at the Geysers to continue to decline. The Company has entered into new steam sale agreements with several of its steam suppliers which allow the Company to alter the operation of its units to more economically utilize the existing installed capacity and partially offset the impact of the declining steam supplies at the Geysers. The new agreements permit the steam suppliers to furnish lower pressure steam and require that they make payments to the Company to compensate for the declining steam supply to the Company's units. WESTERN SYSTEMS POWER POOL In 1991, the FERC approved an agreement among 40 utilities (including the Company) operating in 22 states and British Columbia for a permanent Western Systems Power Pool (WSPP). The entities participating in the WSPP may, on a voluntary basis, buy and sell surplus power and transmission capacity by posting quotes daily on a computer "bulletin board." The prices are negotiable but cannot exceed ceilings approved by the FERC. The permanent WSPP agreement approved by the FERC, among other things, imposes cost-based ceilings calculated from pool-wide average costs and allows QFs to participate in the pool if they waive their rights under PURPA to be paid avoided cost prices for transactions performed within the pool. The FERC order approving the permanent WSPP agreement was challenged in the U.S. Court of Appeals for the District of Columbia Circuit on the basis that the cost-based ceilings were improperly calculated and that the FERC exceeded its authority in conditioning QF participation in the pool. The Court of Appeals affirmed the FERC's authority to set cost-based ceilings and, at the request of the FERC, remanded the QF participation issues to the FERC for further consideration. In February 1994, the FERC ordered WSPP to permit QFs to participate on the same basis as other members without being required to waive their rights under PURPA. ELECTRIC TRANSMISSION POLICIES Beginning in 1993, the FERC implemented the Energy Act by establishing a number of policies with respect to transmission service, transmission pricing and Regional Transmission Groups (RTGs). TRANSMISSION ACCESS AND PRICING In 1993, the FERC held that eligible entities were entitled to receive network transmission service unless the transmitting utility was unable to provide it. Eligible entities under the Energy Act include electric utilities, federal power marketing agencies or any entity generating power for resale. Network transmission service generally involves delivery from multiple generators to multiple loads for a single charge. The FERC later held that network service could be priced based on the ratio of the load served by the network service to the entire load served by the transmitting utility's transmission system. In 1994, the FERC held that any utility providing service under an open-access transmission tariff (i.e., a filed tariff offering transmission service at specified rates and terms to all eligible entities) must provide transmission service to transmission customers on the same basis on which the utility provides transmission service to its own customers. This means the service must be comparable in terms of price, in terms of quality, 21 28 and with respect to all the uses the transmitting utility makes of its own transmission system. The Company currently intends to file an open-access tariff by May 1, 1995. In October 1994, the FERC issued a policy statement on transmission pricing. The new policy permits increased flexibility in transmission pricing methodology and rate design in instances where the transmitting utility is basing rates on a traditional embedded cost revenue requirement. In return utilities must meet the comparability of service standard described above. The FERC will also consider deviations from embedded cost revenues, but only from entities which have already filed open-access comparable service transmission tariffs. The FERC regards market-based pricing for transmission as disfavored, believing transmission to be a monopoly. Consistent with the intent of the Energy Act to promote competition in the wholesale power markets through increasing transmission access, in December 1994, the Company filed with the FERC for its approval an agreement to provide network transmission service to a power marketer, Destec Power Services (DPS). Under this agreement, the Company will provide flexible wholesale network transmission from generators who market their power through DPS. Many of these generators will be QFs which already have power purchase agreements to sell to the Company, but which have surplus power not covered by such agreements which can be marketed by DPS. The FERC is expected to act on the DPS agreement shortly. In March 1995, the Company entered into a similar agreement with another marketer, Power Exchange Corp. (PXC), which agreement has been filed with the FERC for approval. The services and rates under the PXC agreement are identical to those in the DPS agreement. However, the Company will provide transmission service under the PXC Agreement only for power bought or sold by PXC under contracts entered into before such time as the Company's open-access tariff has been filed and effective for two years. For all power contracts PXC enters into after that date, it must rely on transmission service under the Company's open-access tariff. REGIONAL TRANSMISSION GROUPS In 1993, the FERC issued a policy statement on RTGs, voluntary associations of transmission owners and wholesale transmission users, that would facilitate transmission access, coordinate transmission planning, and resolve disputes. In May 1994, the Western Regional Transmission Association (WRTA) became the first RTG to file its governing agreement at the FERC. The Company was one of the founding members of WRTA and supported FERC's approval of the bylaws. The FERC conditionally accepted the WRTA bylaws, but added two requirements. First, the FERC required either WRTA itself or all WRTA members to file comparable service open access tariffs providing transmission service to all other members. Second, the FERC required WRTA to file a single coordinated regional transmission plan and to update that plan as necessary. WRTA has filed a revised set of bylaws essentially accepting those conditions, which FERC will rule on within the next few months. STRANDED COSTS RULEMAKING In June 1994, the FERC issued a Notice of Proposed Rulemaking relating to stranded costs. These are fixed costs (typically for generation) which a utility may be unable to recover because of customers leaving the system. The proposed rules cover stranded costs for wholesale transactions and propose in the alternative either no role for FERC regarding retail stranded costs or only a limited role. A decision is expected sometime in 1995. CPUC TRANSMISSION POLICIES In September 1990, the CPUC issued an order instituting investigation into the development of transmission policies for (i) transmission access and allocation of transmission costs for a utility buying non-utility power; and (ii) transmission access, cost allocation and pricing issues for non-utility power producers who require transmission-only service from a utility. In September 1992, the CPUC issued a decision in the first phase of the investigation. The decision adopted certain policies and procedures on an interim basis which permit the Company to consider the expected transmission impacts of non-utility power purchases as it selects new QF resources through a competitive bidding process. Among other things, the decision provided that ratepayers, as opposed to utility shareholders, will bear prudently incurred costs of the most cost-effective transmission upgrades necessary to accommodate purchases from winning bidders. The recent BRPU 22 29 solicitation proceeded under these rules and enabled bidders in one utility's service territory to bid into another utility's auction. A second phase of the investigation to consider certain broader long-term transmission access and cost issues is currently on hold pending the outcome of the CPUC's electric industry restructuring OIR/OII. ELECTRIC REASONABLENESS PROCEEDING Recovery of costs through the ECAC are subject to a CPUC determination that such costs were incurred reasonably. Under the current regulatory framework, annual reasonableness proceedings are conducted on a historic calendar year basis. In August 1993, the DRA filed a report on the Company's ECAC expenses for the 1991 record period, which questioned the Company's execution of amendments to three power purchase agreements with Texaco, Inc. for three QFs. In its report and in testimony filed in February 1994, the DRA asserted that the Company improperly agreed to extend the construction time under these agreements and recommended that the CPUC find these extensions unreasonable. Although no payments are at issue in the 1991 record period, the DRA argues that certain capacity payments under the contracts should be disallowed in subsequent year proceedings over the 15-year term of the contracts. In its August 1993 report, the DRA indicated that this disallowance over the 15-year term of the contracts would approximate $80 million. In its report on ECAC expenses for the 1992 and 1993 record periods, the DRA recommended disallowances of approximately $3.5 million and $3.0 million, respectively, for two of these agreements. HELMS PUMPED STORAGE PLANT Helms, a three-unit hydroelectric combined generating and pumped storage facility, completion of which was delayed due to a water conduit rupture in September 1982 and various start-up problems related to the plant's generators, became commercially operable in June 1984. As a result of the damage caused by the rupture and the delay in the operational date, the Company incurred additional costs which are not yet included in rate base and lost revenues during the period the plant was under repair. Excluding the costs of the conduit rupture already reserved by the Company and the amount received in settlement of litigation with the supplier of the plant's generators, the remaining unrecovered costs of Helms (after adjustment for depreciation) and revenues discussed above totaled approximately $104 million at December 31, 1994. In October 1994, the Company and the DRA filed a joint motion seeking CPUC approval of a proposed all-parties settlement (Helms Settlement) resolving the treatment of remaining unrecovered Helms costs. The Helms Settlement would permit recovery of $48.9 million of Helms plant costs and $14.6 million of prior revenue requirements to be included in the Company's rate base on January 1, 1995. However, in connection with the Company's rate freeze for 1995, the revenue requirement for 1995 would not increase, as a result of other unrelated base revenue reductions. An additional amount of $35.3 million, representing revenues lost during the time the generators were being repaired, would be transferred to the ERAM account and amortized over the life of Helms, to 2034. Under the Helms Settlement, the Company would also agree not to seek recovery of the costs associated with the 1982 water conduit rupture, estimated to be $72.4 million. The Company took a charge against earnings for such costs in 1990. As noted above (see "General -- 1995 Revenue Changes"), in December 1994, the CPUC issued a resolution authorizing the Company to implement an ARA to keep the Company's retail electric rates unchanged through 1995. In its resolution, the CPUC adopted the revenue requirement increase of approximately $12 million that is contemplated by the Helms Settlement, and authorized a decrease in base revenues. The CPUC also authorized the collection in 1995 of $2 million as part of the amortization through ERAM of revenues lost during the time the generators were being repaired. The CPUC noted that because the Helms Settlement is still pending before the CPUC, the amount adopted in the resolution may be subject to further adjustment depending upon the final decision in the Helms proceeding. 23 30 GAS UTILITY OPERATIONS GAS OPERATIONS The Company owns and operates an integrated gas transmission, storage and distribution system in California. At December 31, 1994, the Company's "vintage" system consisted of approximately 5,300 miles of transmission pipelines, three gas storage facilities and approximately 35,400 miles of gas distribution lines. In addition, in November 1993, the Company placed in service a third transmission pipeline of approximately 400 miles (Line 401) as the in-state portion of the PGT/PG&E Pipeline Expansion. See "PGT/PG&E Pipeline Expansion Project" below. The Company's peak day send-out of gas on its integrated system in California during the year ended December 31, 1994 was 3,801 million cubic feet (MMcf). The total volume of gas throughput during 1994 was approximately 948,000 MMcf, of which 307,000 MMcf was sold to direct end-use or resale customers, 298,000 MMcf was transported by PG&E for its fossil-fueled electric generating plants, and 343,000 MMcf was transported customer-owned gas. The California Gas Report, which presents the outlook for natural gas requirements and supplies for the State of California through the year 2010, is prepared annually by the California electric and gas utilities as a result of a CPUC order. The 1994 report forecasts the Company's gas demand from 1994 through 2010. (Beginning in 1996, the report will be issued biennially.) The 1994 report forecasts growth in gas throughput served by the Company of 1.4% per year from 1994 through 2010. While this is a lower growth rate than the 1.8% shown for the same period in last year's forecast, most of the difference is due to higher power plant gas demand in 1994 than previously forecasted, as a result of lower than expected rainfall. Much of the forecasted growth in gas demand, outside of utility electric generation, is related to a more optimistic forecast of industrial output in the service territory and expected growth in the use of natural gas vehicles as a result of the Company's natural gas vehicle programs and state and federal clean air regulations. The gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of utility electric generation, fuel switching and new technology. In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, have the ability to purchase gas directly from gas producers, using unregulated private pipelines or interstate pipelines, bypassing the Company's system entirely. The report forecasts a total bypass volume of 126 billion cubic feet for 1994. The forecast assumes that bypass which began in 1991 will change little from the 1994 level and does not include any potential bypass from the proposed Mojave Pipeline Company expansion project. See "Other Competitive Pipeline Projects" below. 24 31 GAS OPERATING STATISTICS The following table shows the Company's operating statistics (excluding subsidiaries except where indicated) for gas, including the classification of sales and revenues by type of service.
YEARS ENDED DECEMBER 31 ------------------------------------------------------------- 1994 1993 1992 1991 1990 --------- --------- --------- --------- --------- CUSTOMERS (AVERAGE FOR THE YEAR): Residential........................................... 3,372,768 3,339,859 3,311,881 3,275,247 3,214,424 Commercial............................................ 196,509 195,815 195,689 197,029 194,596 Industrial............................................ 1,400 1,265 1,185 1,150 1,150 Other gas utilities................................... 2 4 4 4 4 --------- --------- --------- --------- --------- Total........................................... 3,570,679 3,536,943 3,508,759 3,473,430 3,410,174 ========= ========= ========= ========= ========= GAS SUPPLY -- THOUSAND CUBIC FEET (MCF) (IN THOUSANDS): Purchased: From Canada......................................... 319,453 329,693 321,770 345,020 372,421 From California..................................... 31,757 32,096 50,953 73,257 77,935 From other states................................... 249,733 243,058 327,272 240,141 273,981 --------- --------- --------- --------- --------- Total purchased................................. 600,943 604,847 699,995 658,418 724,337 Net from storage (to storage)......................... 3,591 (12,234) 10,135 (6,849) 6,152 --------- --------- --------- --------- --------- Total........................................... 604,534 592,613 710,130 651,569 730,489 Company use, losses, etc.(1).......................... 297,604 161,895 281,021 223,176 257,943 --------- --------- --------- --------- --------- Net gas for sales............................... 306,930 430,718 429,109 428,393 472,546 ========= ========= ========= ========= ========= BUNDLED GAS SALES AND TRANSPORTATION SERVICE -- MCF (IN THOUSANDS): Residential........................................... 214,358 206,053 190,176 210,657 204,433 Commercial............................................ 72,183 82,048 79,983 85,203 102,579 Industrial............................................ 19,495 133,178 145,356 119,916 133,930 Other gas utilities................................... 894 9,439 13,594 12,617 31,604 --------- --------- --------- --------- --------- Total(2)........................................ 306,930 430,718 429,109 428,393 472,546 ========= ========= ========= ========= ========= TRANSPORTATION SERVICE ONLY -- MCF (IN THOUSANDS): Vintage system (Substantially all Industrial)(3)...... 142,393 101,888 103,186 207,544 168,969 In-state portion of Pipeline Expansion (Line 401)..... 200,755 20,513 -- -- -- --------- --------- --------- --------- --------- Total........................................... 343,148 122,401 103,186 207,544 168,969 ========= ========= ========= ========= ========= REVENUES (IN THOUSANDS): Bundled gas sales and transportation service: Residential......................................... $1,268,966 $1,152,494 $1,092,324 $1,226,094 $1,139,998 Commercial.......................................... 444,805 467,962 479,599 551,669 565,608 Industrial.......................................... 57,297 367,221 425,467 366,346 453,871 Other gas utilities................................. 2,371 25,654 38,504 43,224 84,771 --------- --------- --------- --------- --------- Bundled gas revenues............................ 1,773,439 2,013,331 2,035,894 2,187,333 2,244,248 Transportation only revenue: Vintage system (Substantially all Industrial)....... 132,509 56,733 75,606 133,348 106,759 In-state portion of Pipeline Expansion (Line 401)... 58,442 8,097 -- -- -- --------- --------- --------- --------- --------- Transportation service only revenue............. 190,951 64,830 75,606 133,348 106,759 Miscellaneous......................................... 41,840 (14,925) 21,022 (59,056) 52,308 Regulatory balancing accounts......................... 11,068 138,627 36,093 (44,213) (124,606) Subsidiaries(4)....................................... 402,077 514,502 379,981 192,067 155,312 --------- --------- --------- --------- --------- Operating revenues.............................. $2,419,375 $2,716,365 $2,548,596 $2,409,479 $2,434,021 ========= ========= ========= ========= =========
- --------------- (1) Includes use by business units other than the Gas Supply business unit, principally as fuel for fossil-fueled generating plants. (2) In August 1991, the Company implemented its CIG program. Sales included approximately 105,000 MMcf, 130,000 MMcf and 50,000 MMcf in 1993, 1992 and 1991, respectively, of gas procured by the Company for CIG customers at prices negotiated directly between those customers and suppliers. The CIG Program was terminated on October 31, 1993 upon full implementation of the CPUC's capacity brokering program. (3) Does not include on-system transportation volumes transported on the in-state portion of the Pipeline Expansion of 79,749 MMcf and 7,205 MMcf for 1994 and 1993, respectively. (4) Includes gas transportation revenues from PGT and oil and gas revenues from Enterprises. 25 32
YEARS ENDED DECEMBER 31 ------------------------------------------------------------- 1994 1993 1992 1991 1990 --------- --------- --------- --------- --------- SELECTED STATISTICS: Total customers (at year-end)......................... 3,500,000 3,600,000 3,500,000 3,500,000 3,500,000 Average annual residential usage (Mcf)................ 64 62 57 64 64 Heating temperature -- % of normal(1)................. 104.4 89.9 76.0 101.5 94.9 Average billed bundled gas sales revenues Mcf: Residential......................................... $5.92 $5.59 $5.74 $5.82 $5.58 Commercial.......................................... 6.16 5.70 6.00 6.47 5.51 Industrial.......................................... 2.94 2.76 2.93 3.06 3.39 Average billed transportation only revenue per Mcf: Vintage system...................................... 0.60 0.52 0.73 0.64 0.63 In-state portion of Pipeline Expansion (Line 401)... 0.29 0.39 -- -- -- Net plant investment per customer..................... $1,340 $1,339 $1,170 $893 $748
- ------------ (1) Over 100% indicates colder than normal. NATURAL GAS SUPPLIES The objective of the Company's gas supply planning is to maintain a balanced supply portfolio which provides supply reliability and contract flexibility, minimizes costs and fosters competition among suppliers. Under current CPUC regulations, the Company purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual and operational constraints. During the year ended December 31, 1994, approximately 53% of the Company's total purchases of natural gas consisted of Canadian gas purchased from various Canadian producers and transported by PGT, a wholly owned subsidiary of the Company, approximately 5% was purchased from various California producers, and approximately 42% was purchased from other states (substantially all U.S. Southwest sources and transported by El Paso Natural Gas Company (El Paso) or Transwestern Pipeline Company (Transwestern)). The following table shows the volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by the Company from these sources during each of the last five years.
YEARS ENDED DECEMBER 31 ---------------------------------------------------------------------------------------------------------------- 1994 1993 1992 1991 1990 -------------------- -------------------- -------------------- -------------------- -------------------- THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) --------- -------- --------- -------- --------- -------- --------- -------- --------- -------- Canada.......... 319,453 $ 1.94 329,693 $ 2.26 321,770 $ 2.14 345,020 $ 2.34 372,421 $ 2.41 California...... 31,757 1.55 32,096 1.65 50,953 1.73 73,257 2.00 77,935 2.04 Other states (substantially all U.S. Southwest).... 249,733 2.41 243,058 2.84 327,272 2.51 240,141 2.61 273,981 2.81 --------- --------- --------- --------- --------- Total/Weighted Average....... 600,943 $ 2.12 604,847 $ 2.46 699,995 $ 2.28 658,418 $ 2.40 724,337 $ 2.52 ======== ======= ======== ======= ======== ======= ======== ======= ======== =======
- ---------- (1) The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges and other pipeline assessments, including direct bills allocated over the quantities received at the California border. The average prices for California gas include only commodity gas prices delivered to the Company's gas system. GAS REGULATORY FRAMEWORK The current regulatory framework for natural gas service in California (i) segments customers into core and noncore classes; (ii) unbundles utilities' gas transportation and procurement services; (iii) allows noncore customers and some core customers to purchase gas directly from producers, aggregators or marketers, and separately negotiate gas transportation with their utilities; and (iv) places the utilities at risk for collecting a portion of the transportation revenues associated with their noncore markets. Under the CPUC's capacity brokering program implemented in 1993, the Company is required to make available for brokering all interstate pipeline capacity not reserved for its core customers and core subscription customers. Noncore customers, marketers and shippers, and the Company's electric department can bid for such capacity. In addition, in April 1992, the FERC issued its Order 636, which required interstate pipelines to unbundle sales services from transportation services, established various programs providing for reallocation of 26 33 pipeline capacity and adopted various mechanisms by which pipelines may recover transition costs arising from the restructuring of their services. Under the Order 636 capacity allocation rules, firm capacity holders were permitted to exercise a one-time opportunity to "relinquish," i.e., permanently abandon, some or all of their transportation capacity, either by paying a negotiated exit fee or through a third party assuming the obligations of the existing transportation agreement. Thereafter, firm capacity holders may also "release" some or all of their capacity, i.e., give up capacity rights to third parties for a limited period of time. Releasing capacity holders remain liable on their existing contracts, but will receive a credit for the acquiring third parties' demand charge payments, the amounts of which will depend on the percentage of full rate paid by the acquiring third party. The Company's compliance with these regulatory changes allowed many of the Company's noncore customers to arrange for the purchase and transportation of their own gas supplies. These changes resulted in a decrease in the amount of gas required to be purchased by the Company and a related decrease in the Company's need for firm transportation capacity, and contributed to the need to restructure the Company's gas supply arrangements. RESTRUCTURING OF CANADIAN GAS SUPPLY ARRANGEMENTS DECONTRACTING PLAN Until November 1993, PG&E purchased Canadian natural gas from PGT, which in turn purchased such gas from Alberta and Southern Gas Co. Ltd. (A&S), a wholly owned subsidiary of PG&E. A&S had commitments to purchase minimum quantities of gas from Canadian producers under various contracts, most of which extended through 2005. As a result of the regulatory restructuring discussed above, negotiations were conducted to terminate A&S's contracts with Canadian gas producers, restructure A&S's contracts with Canadian pipelines and gas processors and settle all litigation and claims arising from such contracts. Those negotiations resulted in the implementation of a Decontracting Plan, effective November 1, 1993. Approximately 190 Canadian gas producers representing nearly 100% of the total volume of the gas supply of A&S participated in the Decontracting Plan. Under the Decontracting Plan, the Canadian producers' contracts with A&S, the sales agreement between A&S and PGT, and PG&E's service agreement with PGT each were terminated, effective on November 1, 1993. Participating producers released A&S, PGT and PG&E from any claims they may have had that resulted from the termination of the former arrangements as well as any prior claims related to these contracts. The total amount of settlement payments paid to the producers was approximately $210 million. As part of the overall A&S decontracting process, A&S' operations have been significantly reduced. A&S permanently assigned substantial portions of its commitments for transportation capacity with NOVA Corporation of Alberta (NOVA) through October 2001 and Alberta Natural Gas Company Ltd (ANG) through October 2005 to third parties and approximately 600 MMcf per day (MMcf/d) of capacity on each of these pipelines to PG&E for use in the servicing of PG&E's core and core subscription customers. A&S currently holds remaining capacity of approximately 300 MMcf/d on each of these pipelines with total annual demand charges of approximately $15 million for which it is continuing its efforts to assign or broker. It is currently anticipated that A&S will complete the permanent assignment to others of substantially all of its NOVA and ANG capacity by November 1995. The FERC has approved a transition cost recovery mechanism (TCRM) for PGT under which most costs which were incurred to restructure, reform or terminate the sales arrangements between A&S and PGT and underlying A&S gas supply contracts, or to resolve claims by gas suppliers related to past or future liabilities or obligations of PGT or A&S, are eligible for recovery in PGT's rates. Under the TCRM (1) 25% of such costs are absorbed by PGT; (2) 25% are recovered by PGT through direct bills (substantially all to PG&E as PGT's principal customer); and (3) 50% are recovered by PGT through volumetric surcharges over a three-year period. Costs associated with A&S's commitments for Canadian pipeline capacity do not qualify as transition costs recoverable under this mechanism. 27 34 In May 1994, the FERC approved PGT's application seeking recovery of $154 million under the TCRM, which is 75% of the $206 million in estimated settlement payments expected to be paid to Canadian gas producers as of the time PGT filed its application. PGT has also sought recovery of an additional $14 million under the TCRM. This amount represents 75% of additional settlement payments to producers and certain costs related to A&S' wind-down of its gas aggregation and supply business as a result of the decontracting process. In February 1995, the FERC held that this amount was eligible for recovery under the TCRM. The CPUC and other parties have until April 3, 1995 to challenge the prudency of this amount. If no such challenge is made, the amount will be recovered under the TCRM. In November 1993, PG&E paid PGT approximately $51 million in payment of a direct bill charged by PGT for transition costs under the TCRM. PG&E sought recovery in its most recent BCAP application of this amount and the volumetric surcharges to be billed to PG&E. As part of proposed gas settlement agreements discussed below (see "Gas Reasonableness Proceedings -- Proposed Gas Settlements"), the DRA has agreed that it will not seek any disallowance relating to costs incurred by PG&E in connection with its Canadian restructuring/decontracting activities once those costs are approved by the FERC. FINANCIAL IMPACT OF DECONTRACTING PLAN AND LITIGATION The Company incurred transition costs of $228 million in 1993, consisting of settlement payments made to producers in connection with the implementation of the Decontracting Plan and amounts incurred by A&S in reducing certain administrative and general functions resulting from the restructuring. Of these costs, the Company deferred $143 million for future rate recovery. In addition, the Company recorded a reserve of $31 million in 1993 related to A&S's remaining commitments for Canadian transportation capacity. Accordingly, the Company expensed $93 million in 1993 and a total of $23 million in prior years. RESTRUCTURING OF INTERSTATE GAS SUPPLY ARRANGEMENTS CURRENT GAS TRANSPORTATION AND PROCUREMENT ARRANGEMENTS The Company's firm transportation agreement with PGT for up to 1,066 MMcf/d runs through October 31, 2005. The Company's firm transportation agreement with El Paso for up to 1,140 MMcf/d runs through December 31, 1997. The agreements include provisions for fixed demand charges for reserving firm capacity on the pipelines. The firm transportation reservation charges associated with the Company's firm capacity on PGT and El Paso are approximately $50 million and $130 million per year, respectively. In April 1992, the Company executed firm transportation agreements with Transwestern to transport 200 MMcf/d of San Juan basin gas supplies into the Company's southern gas system, of which approximately 150 MMcf/d is to be used to meet the Company's gas sales demands and approximately 50 MMcf/d is for use by the Company's electric department. The demand charges associated with the entire Transwestern capacity are currently approximately $30 million per year. RECOVERY OF INTERSTATE TRANSPORTATION DEMAND CHARGES Pursuant to FERC rules on capacity relinquishment and release and the CPUC's capacity brokering program, the Company retained approximately 600 MMcf/d on each of the PGT and El Paso systems to support its core and core subscription customers and made amounts not needed to support such customers available for capacity release and brokering to other potential shippers beginning in 1993. Under the CPUC's capacity brokering program, noncore customers, or their gas suppliers, are able to make firm interstate transportation arrangements to deliver gas at the Company's interconnections with the interstate pipelines. The Company has permanently assigned portions of the capacity it no longer uses and is continuing its efforts to assign or broker the remaining unused capacity. During 1994, the Company has been able to broker a portion of its unused capacity, including limited amounts of that held for its core and core subscription customers when such capacity was not being used. Amounts brokered have generally been on a short-term basis, most of which were at a discounted price. Based on the current demand for Canadian gas, the Company believes it will be able to broker or assign substantially all of its unused capacity on PGT by the end of 1995; however, due to lower demand for Southwest pipeline capacity, the Company cannot predict the volume or price of the capacity on El Paso and Transwestern that will be brokered or assigned. 28 35 Interstate transportation capacity which cannot be marketed at the full rate results in unrecovered demand charges. Under the CPUC brokering rules, the CPUC has authorized the use of the ITCS to account for unrecovered demand charges associated with interstate pipeline obligations in existence at the time the decision creating the ITCS was issued in November 1991. To the extent the Company is unable to broker its firm interstate capacity above core and core subscription reservations at the full as-billed rate, or to broker such capacity at all, the Company has been authorized to accumulate unrecovered demand charges for El Paso and PGT in the ITCS account for later review and allocation among customer classes. Ultimate recovery of unrecovered interstate pipeline demand charges accumulated in the ITCS will be subject to CPUC reasonableness review. There may be instances where the CPUC may not allow full recovery with respect to discounted rates, such as rates given to a customer in a negotiated discount gas transportation contract entered into pursuant to the Company's EAD procedure. The CPUC has indicated that if an EAD rate discount results in a shortfall in recovery of ITCS costs contained in the otherwise applicable tariff rate, the Company will not recover those ITCS costs from other customers. In November 1994, the CPUC issued a decision on the Company's application seeking recovery of amounts accumulated in the ITCS. The Company's application sought to have $60.7 million, which represents the revenue requirement for the estimated amount accrued in the ITCS account for the period August 1, 1993 through August 31, 1994, recovered in noncore rates over a 12-month period beginning September 1, 1994. In its decision, the CPUC indicated that it did not have a sufficient record to resolve contested issues regarding the total amount of the Company's unrecovered costs of interstate pipeline capacity to allocate to noncore customers. However, citing the fact that legitimate unrecovered costs continue to accrue at a substantial rate, the decision authorized the Company to increase rates to all noncore customers on December 1, 1994 through a rate designed to collect approximately one-half of the accumulated demand charges for unbrokered or discounted capacity on an interim basis, subject to refund should ITCS costs prove to have been caused by improper acts of the Company. (This amount was included in the rate adjustments effected January 1, 1995. See "General -- Current Rate Proceedings -- 1995 Revenue Changes" above.) The CPUC also set the matter for hearing at the earliest practicable date to consider protests filed by El Paso. El Paso contends that the Company is inducing customers to move from the El Paso pipeline system to the Company's Pipeline Expansion by discounting rates on the Pipeline Expansion and recouping those discounts through the ITCS. The Company expects to seek recovery of the balance of the ITCS amounts originally sought in the hearing on this matter, which is scheduled for September 1995. Currently, the Company is not permitted to include any Transwestern firm capacity demand charges in rates or in the ITCS account. The Company is authorized to record costs associated with its Transwestern capacity in a balancing account, with recovery of such costs subject to reasonableness review proceedings, which are currently under way. In January 1994, the DRA issued its report on the reasonableness of the Company's gas procurement and operating activities for the 1992 record period. In its report, the DRA argued that the Company imprudently entered into firm transportation agreements with Transwestern in 1992 and recommended a disallowance of the associated demand charges of approximately $18 million paid by the Company during the record period, of which $4.5 million related to capacity for the Company's electric department. The DRA asserted that the Transwestern capacity was unnecessary to meet the expected needs of the Company's core customers and that the Company should not have contracted for such capacity. Hearings on this issue were concluded in January 1995, with a decision expected in late 1995. GAS REASONABLENESS PROCEEDINGS Recovery of gas costs through the Company's regulatory balancing account mechanisms is subject to a CPUC determination that such costs were incurred reasonably. Under the current regulatory framework, annual reasonableness proceedings are conducted by the CPUC on a historic calendar year basis. 29 36 1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES In March 1994, the CPUC issued a final decision on the Company's Canadian gas procurement activities during 1988 through 1990. The CPUC found that the Company could have saved its customers money if it had bargained more aggressively with its existing Canadian suppliers or bought cheaper gas from other Canadian sources. The CPUC concluded that it was appropriate for the Company to take a substantial portion (up to 700 MMcf/d) of its Canadian gas at its then-existing price, but that the Company could have met the remainder of its demand for Canadian gas at lower prices, either from the same suppliers or with purchases from other available Canadian natural gas sources. The decision orders a disallowance of $90 million of gas costs, plus accrued interest estimated at approximately $25 million through December 31, 1993. The CPUC also issued a final decision on the Company's non-Canadian gas operations during 1988 through 1990, ordering a disallowance of $8 million. The Company filed a request for rehearing of the CPUC's decision ordering a disallowance in connection with the Company's Canadian gas procurement activities in 1988-1990, which was denied in November 1994. In December 1994, the Company filed a complaint against the CPUC in the U.S. District Court for the Northern District of California challenging this decision by the CPUC. The complaint alleges that the CPUC disallowance order purports to regulate the foreign and interstate purchase and transportation of natural gas, matters within the exclusive jurisdiction of United States and Canadian regulatory authorities. Accordingly, the complaint alleges, such order is preempted by federal law and violates the Company's rights under the United States Constitution. The complaint seeks injunctive and declaratory relief. PROPOSED GAS SETTLEMENTS A number of other reasonableness issues related to the Company's gas procurement practices and supply operations for periods dating from 1988 through 1994 are still under review by the CPUC. The DRA recommended disallowances of $142 million and a penalty of $50 million and indicated that it was considering additional recommendations for pending issues. The Company and the DRA have signed settlement agreements to resolve most of these issues for a $68 million disallowance. Significant issues covered by the gas settlement agreements include (i) the Company's purchases of Canadian, Southwest and California gas for its electric department in 1991 and 1992 and its core customers from 1991 through May 1994; (ii) issues not related to gas procurement which arise from the DRA's investigation of A&S, and the proposed investigation of ANG, a former affiliate of the Company, for the period 1988 through May 1994; (iii) the effects the Company's Canadian gas procurement costs may have had on amounts paid by the Company for Northwest power purchases for 1988 through 1992 and for power purchased from geothermal and QF producers during 1991 and 1992; (iv) the Company's gas storage operations for 1991 and 1992; (v) the Company's Southwest gas procurement activities for 1988 through 1990; and (vi) Canadian gas restructuring transition costs billed to PG&E by PGT through FERC-approved rates. Agreements with the DRA do not constitute a CPUC decision and are subject to modification by the CPUC in its final decisions. The gas settlement agreements are expressly conditioned upon CPUC approval. Upon such approval, the Company would return approximately $68 million to its ratepayers. The proposed gas settlement agreements do not resolve issues related to the effect the Company's Canadian gas procurement costs during the 1988 through 1990 period may have had on the price the Company paid to geothermal and QF producers during those years. Hearings on those issues have not yet been scheduled by the CPUC. The proposed gas settlement agreements also do not resolve the reasonableness of the Company's subscription to Transwestern pipeline capacity or the costs accrued in the Company's ITCS account. FINANCIAL IMPACT OF GAS REASONABLENESS PROCEEDINGS The Company accrued approximately $135 million and $61 million in 1994 and 1993, respectively, for gas reasonableness matters including the CPUC decisions for the years 1988 through 1990 and issues covered by 30 37 the gas settlement agreements. The Company believes that the ultimate outcome of these matters will not have a significant impact on its financial position or results of operations. PGT/PG&E PIPELINE EXPANSION PROJECT In November 1993, PGT and the Company placed in service an expansion of their natural gas transmission systems from the Canadian border into California (Pipeline Expansion). The 840-mile combined pipeline provides an additional 148 MMcf/d of firm capacity to the Pacific Northwest and an additional 851 MMcf/d of capacity to Northern and Southern California. At December 31, 1994, the Company's total investment in the Pipeline Expansion project was approximately $1,627 million. The $1,627 million consisted of $786 million for the facilities within California (i.e., in-state portion) and $841 million for the facilities outside California (i.e., interstate, or PGT, portion). The conditions of the CPUC's approval of the construction of the in-state portion of the Pipeline Expansion place the Company at risk for its decision to construct based on its assessment of market demand and for undersubscription and underutilization of the facility. The CPUC required the application of a "cross- over" ban under which volumes delivered from the incremental PGT portion of the Pipeline Expansion must be transported at an incremental in-state expansion rate. Incremental rate design is based on the concept that expansion shippers, not existing ratepayers, bear the incremental costs of the expansion facilities. Capacity on the PGT portion of the Pipeline Expansion is fully subscribed under long-term firm transportation contracts. However, to date, shippers have only executed long-term firm transportation contracts for approximately 40% of the in-state capacity, and the Company continues negotiations for the remainder of that capacity. The CPUC has authorized the Company to provide as-available service on the in-state portion of the Pipeline Expansion, which provides additional revenues to recover the incremental costs of the expansion. In February 1994, the CPUC issued a decision on the Company's request for an increase in the cost cap for the in-state portion of the Pipeline Expansion and its interim rate filing. The cost cap represented the maximum amount determined by the CPUC to be reasonable and prudent based on an estimate of the anticipated construction costs at that time. The CPUC granted the Company's request to increase the cost cap to $849 million, but set interim rates based on the original cost cap of $736 million, subject to adjustment within the newly approved cost cap after the outcome of a reasonableness review of capital costs. The CPUC's decision finds that given market conditions at the time, the Company was reasonable in constructing the Pipeline Expansion. The CPUC has denied rehearing of this decision. In September 1994, the Company filed an application with the CPUC requesting that the CPUC find reasonable the full capital costs of the in-state portion of the Pipeline Expansion (estimated to be $813 million) and its initial operating expenses. The Company's request for a $13 million increase in revenues from the in-state portion of the Pipeline Expansion, compared to rates in effect in 1994, will also be considered in this proceeding. A decision in this proceeding is not expected until 1996. In its 1991 order approving the PGT portion of the Pipeline Expansion, the FERC concluded that PGT had not sufficiently demonstrated that shippers would not be subject to discriminatory restraints on access into California or on the PGT portion of the Pipeline Expansion as a result of the "cross-over" ban imposed by the CPUC. As a result, the FERC reduced PGT's approved rate of return on equity until such time as PGT demonstrates that neither its rates or transportation policies nor those of the Company result in unduly discriminatory restraints. In March 1994, the FERC allowed PGT to implement, subject to refund, an increase in the nominal return on equity to 12.75%, but reaffirmed the lower 10.13% return on equity it implemented as an incentive for PGT to seek removal of unduly discriminating restraints. In February 1994, PGT filed a general rate case with the FERC which proposed, among other things, that the lower return on equity imposed by the FERC be removed and PGT be allowed to determine rates for all of its facilities on an equity rate of return of 13%. In March 1994, the FERC approved PGT's proposal to determine rates based on the higher rate of return, subject to refund, pending the outcome of hearings in PGT's rate case, and authorized the rate change to begin in September 1994. Hearings in PGT's rate case are scheduled to begin in April 1995. 31 38 The Company believes that resolution of the rate proceedings pending at the CPUC and FERC will not have a significant impact on its financial position or results of operations. OTHER COMPETITIVE PIPELINE PROJECTS In March 1993, Mojave Pipeline Company (Mojave), which is a subsidiary of El Paso, filed a request seeking FERC authorization for construction of a 475 MMcf/d transportation-only pipeline expansion of its interstate natural gas pipeline. Mojave indicated that it intends to place the proposed expansion into service by January 1, 1996. The expansion would extend Mojave's system from its current terminus in Bakersfield, California, through California's Central Valley to Sacramento and the San Francisco Bay Area. Mojave's filing indicated that 433 MMcf/d of the firm service capacity provided by the proposed expansion would be provided to customers located in the Company's service territory, with approximately 257 MMcf/d of that amount to be used to provide gas service that currently is not provided by the Company. The remaining 176 MMcf/d represents service to customers currently served by the Company. In November 1994, the FERC issued an order, approving, with conditions, Mojave's expansion application and granting Mojave a permit to construct, subject to further environmental review. In response to Mojave's original application, the Company had requested that the FERC establish a mechanism to reimburse the Company for costs arising from bypass associated with Mojave's proposed expansion. In its order approving Mojave's expansion, the FERC rejected the Company's claim that the Mojave expansion will result in lost revenues of between $204 million and $223 million. Instead, the FERC estimated the amount would not likely exceed $5 million per year for 15 years. The FERC also rejected the Company's request to be relieved of up to $86 million in charges for El Paso capacity to account for reduced load resulting from Mojave's proposed expansion, concluding instead that such amount could not exceed $19.5 million. The FERC concluded that these costs did not justify rejection of Mojave's application, but it was unable to determine whether and what amount of compensation is owed to the Company by Mojave. The FERC also directed the Company, Mojave and El Paso to provide information explaining whether a connection exists between the Company's obligation to purchase service from El Paso and Mojave's service to the customers Mojave intends to serve within the Company's service territory, and specifying what type and volume of load the Company will lose as a direct result of the bypass by Mojave. In December 1994, the Company filed its response to the FERC's order. In its response, the Company affirmed that a direct connection exists between the Company's obligation to purchase service from El Paso and Mojave's service to bypassing end users. The Company included a list of current and future natural gas customers that the Company believes might be targeted by Mojave for bypass transportation service. The Company also updated its request for compensation as a result of the Mojave bypass, asking the FERC to relieve the Company of up to $66 million in El Paso capacity charges and require Mojave to pay the Company $135 million in lost revenues associated with the proposed bypass. In March 1994, the FERC denied several requests for rehearing of its order approving Mojave's expansion. The FERC deferred to a subsequent order consideration of the Company's request for relief from El Paso capacity charges and compensation from Mojave. The Company also faces competition from various other pipeline projects completed in recent years to serve the enhanced oil recovery market in Southern California and other customers. In 1992, projects sponsored by Mojave and the Kern River Gas Transmission Company commenced commercial operations, and both Transwestern and El Paso put into service expanded pipeline facilities from the San Juan Basin in New Mexico to the California border. These projects provide additional capacity to some of the same markets served by the Pipeline Expansion. Some of the gas available from the U.S. Southwest over these projects is priced equal to or lower than the price of Canadian gas available over the Pipeline Expansion, due in part to federal tax credits available for certain San Juan gas production. STORAGE SERVICE The Company has generally provided natural gas storage service only in conjunction with its procurement and transportation services. In February 1993, the CPUC adopted policies and rules for permanent unbundled 32 39 gas storage programs for noncore customers, and an unbundled storage program for the Company was approved by the CPUC in May 1994. Storage service for core customers remains bundled with procurement and transportation services. In September 1994, the Company began offering unbundled storage to noncore customers for varying terms of one year or less. Customers bid to purchase this storage capacity, with available capacity awarded to the highest bids first. To the extent the Company does not recover the full costs allocated to this noncore storage program, the CPUC authorized a Noncore Storage Balancing Account in which these unrecovered costs are accumulated for later review and allocation among customer classes. The CPUC also approved negotiated discounted rates for storage services for noncore customers under certain circumstances, but provided that a portion of any revenue shortfalls attributable to such discounted rates may not be recovered from other customers. To date, the Company has not offered storage service at discounted rates. DIABLO CANYON DIABLO CANYON OPERATIONS Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and March 1986, respectively. As of December 31, 1994, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 78% and 80%, respectively. The table below outlines Diablo Canyon's refueling schedule for the next five years. This schedule assumes that a refueling outage for a unit will last approximately six weeks, depending on the scope of the work required for a particular outage. The schedule is subject to change in the event of unscheduled plant outages or changes in the length of the fuel cycle.
1995 1996 1997 1998 1999 ---------- ---------- ---------- ---------- ---------- Unit 1 Refueling........... September March September Startup............. November April November Unit 2 Refueling........... March September March Startup............. May November May
In November 1994, the Nuclear Regulatory Commission's (NRC) Atomic Safety and Licensing Board issued its decision approving the Company's request to change the operating license expiration dates for both units at Diablo Canyon. Diablo Canyon Units 1 and 2 were originally licensed to operate for 40 years commencing on the date the construction permit for the respective unit was issued, which occurred in April 1968 and December 1970, respectively. In 1982, the NRC determined that the 40-year term of operation for nuclear power plants may instead begin upon issuance of the first operating license. License amendments were issued in March 1994 to extend the operating license expiration date for Units 1 and 2 to September 2021 and April 2025, respectively. DIABLO SETTLEMENT In December 1994, the Company, the DRA, the California Attorney General and several other parties representing energy consumers agreed to a memorandum of understanding and draft settlement agreement to modify the pricing provisions of the Diablo Settlement. All other terms and conditions of the Settlement Agreement would remain unchanged. The parties have filed the proposed modification with the CPUC and will seek expedited CPUC approval of the proposed change. Under the proposed modification, the price for power produced by Diablo Canyon would be reduced from the current level and would be as shown in the following table. Based on Diablo Canyon's current operating 33 40 performance, the proposed modification would result in approximately $2.1 billion less revenue over the next five years, compared to the original pricing provisions of the Diablo Settlement. DIABLO CANYON PRICE (CENTS) PER KWH
1995 1996 1997 1998 1999 ------ ------ ------ ------ ------ Original Settlement Agreement Price*............... 12.15 12.42 12.70 12.98 13.28 Proposed Price..................................... 11.00 10.50 10.00 9.50 9.00
- --------------- * Assumes 3.5% inflation After December 31, 1999, the escalating portion of the Diablo Canyon price will increase using the same formula specified in the Diablo Settlement. The proposed modification provides the Company with the right to reduce the price below the amount specified if it so chooses. The parties to the proposed modification agree that the difference between the Company's revenue requirement under the original terms of the Diablo Settlement and the proposed new prices will be applied to the ECAC balancing account until the ECAC undercollection as of December 31, 1995 (see "General -- Current Rate Proceedings -- 1995 Revenue Changes -- ECAC" above) is fully amortized. As a result, the Diablo Canyon price reductions would help achieve amortization of the ECAC undercollection. In addition, the parties agree that the prices for the period through December 31, 1999 are reasonable and shall be the basis for the recovery of the Company's ECAC revenue requirement pursuant to the pricing of Diablo Canyon power. The Diablo Settlement adopted alternative ratemaking for Diablo Canyon by basing revenues primarily on the amount of electricity generated by the plant, rather than on traditional cost-based ratemaking. Under this "performance based" approach, the Company assumes a significant portion of the operating risk of the plant because the extent and timing of the recovery of actual operating costs, depreciation and a return on the investment in the plant primarily depend on the amount of power produced and the level of costs incurred. The Company's earnings are affected directly by plant performance and costs incurred. Earnings relating to Diablo Canyon will fluctuate significantly as a result of refueling or other extended plant outages, plant expenses and the effects of a peak-period pricing mechanism. See "Diablo Canyon Operations" above for the plant refueling schedule. The settlement decision explicitly affirmed that Diablo Canyon costs and operations no longer should be subject to CPUC reasonableness reviews. The decision states that, to the extent permitted by law, the CPUC intends that this decision be binding upon future Commissions, based upon a determination that taken as a whole the settlement produces a just and reasonable result, and that the settlement has been approved based on the reasonable reliance of the parties and the CPUC that all of the terms and conditions will remain in effect for the full term of the settlement, ending 2016. However, the decision states that the CPUC cannot bind future Commissions in fixing just and reasonable rates for Diablo Canyon. Under the Diablo Settlement, revenues are based on a pre-established price per kWh consisting of a fixed component (3.15 cents per kWh) and an escalating component for each kWh of electricity generated by the plant. As noted above, the Company has proposed modifying the price for the years 1995 through 1999. After 1999, the escalating component will be adjusted by the change in the consumer price index plus 2.5%, divided by two. During the first 700 hours of full-power operation for each unit during the peak period (10 a.m. to 10 p.m. on weekdays in June through September), the price is 130% of the stated amount to encourage the Company to utilize the plant during the peak period. During the first 700 hours of full-power operation for each unit during the non-peak period of the year, the price is 70% of the stated amount. At all other times, the price is 100% of the stated amount. If power generation drops below specified capacity levels, the Company may trigger an annual revenue floor provision, or under certain conditions, seek abandonment of the plant (discussed below). Floor payments ensure that the Company will receive some revenue, even if the plant stops producing power. Floor payments 34 41 are based on the prices set in the agreement at a 36% capacity factor from 1988 through 1997 (reduced by 3% each time the floor provision is exercised and not repaid) with the capacity factor decreasing in the future. Floor payments must be refunded to customers under specified circumstances. If actual operation falls below the floor capacity factor in three consecutive years, whether or not the floor payment provision has been triggered, the Company must file for abandonment or explain why continued application of the settlement is appropriate. In the event there is a prolonged plant outage and the Company files for abandonment, the Company may ask for recovery of the lesser of (a) floor payments allowed for ten years, less any years of floor payments already received and not repaid, or (b) $3 billion, reduced by $100 million per year of operation on January 1 of each year starting in 1989. The Diablo Settlement provides that certain Diablo Canyon costs, including decommissioning costs, be recovered over the term of the Diablo Settlement, including a full return on such costs through base rates. NUCLEAR FUEL SUPPLY AND DISPOSAL The Company has purchase contracts for, and an inventory of, uranium concentrates and contracts for conversion of uranium to uranium hexafluoride, uranium enrichment and fuel fabrication. Based on current operations forecasts, Diablo Canyon's requirements for uranium supply, enrichment services and conversion services will be satisfied through existing long-term contracts through 1998, 1999 and 2001, respectively. The Company is also negotiating contracts for alternative uranium supply and enrichment services through 2002. Fuel fabrication contracts for the two units will supply their requirements for the next five operating cycles for each unit. These contracts are intended to ensure long-term fuel supply, but permit the Company the flexibility to take advantage of short-term supply opportunities. In most cases, the Company's nuclear fuel contracts are requirements-based, with the Company's obligations linked to the continued operation of Diablo Canyon. Under the Nuclear Waste Policy Act of 1982 (Nuclear Act), the U.S. Department of Energy (DOE) is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level waste. The Nuclear Act sets a national policy for the disposal of nuclear waste from commercial reactors, and establishes a timetable for the DOE to choose one or more sites for the deep underground burial of wastes from nuclear power plants. Under the Nuclear Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Act mandates that one or more such permanent disposal sites be in operation by 1998, although DOE has indicated that such sites may not be in operation until 2010. DOE is also considering providing interim storage in a monitored retrievable storage facility earlier than 2010. However, under DOE's current estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel is not likely to be accepted by DOE for interim or permanent storage before 2011, at the earliest. At the projected level of operation for Diablo Canyon, the Company's facilities are sufficient to store on-site all spent fuel produced through approximately 2006 while maintaining the capability for a full-core off-load. In the event an interim or permanent DOE storage facility is not available for Diablo Canyon's spent fuel by 2006, the Company will examine options for providing additional temporary spent fuel storage at Diablo Canyon or other facilities, pending disposal or storage at a DOE facility. Such additional temporary spent fuel storage may be necessary in order for the Company to continue operating Diablo Canyon beyond approximately 2006, and may require approval by the NRC and other regulatory agencies. In June 1994, a number of utilities (including the Company), state utility commissions and state attorneys general filed lawsuits seeking declaratory and injunctive relief against the DOE's alleged failure to meet its obligations under the Nuclear Act. Action on the lawsuits has been deferred pending issuance of a DOE policy statement on the same subject. In July 1988, the NRC gave final approval to the Company's plan to store radioactive waste from the Humboldt Bay Power Plant (Humboldt) at Humboldt for 20 to 30 years and, ultimately, to decommission the unit. The license amendment issued by the NRC allows storage of spent fuel rods at Humboldt until a federal repository is established. The Company has agreed to remove all nuclear waste as soon as possible after the federal disposal site is available. 35 42 INSURANCE The Company is a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). These companies, which are owned by utilities with nuclear generating facilities, provide insurance coverage against property damage, decontamination, decommissioning and business interruption and/or extra expenses during prolonged accidental outages for reactor units in commercial operation. If the nuclear plant of a member utility is damaged or increased costs for business interruption are incurred due to a prolonged accidental outage, the Company may be subject to maximum retrospective premium assessments of $28 million (property damage) and $7 million (business interruption), in each case per policy period, if losses exceed premiums, reserves and other resources of NML or NEIL. The federal government has enacted laws that require all utilities with nuclear generating facilities with a capacity of 100 MW or more to share in payment of claims resulting from a nuclear incident. The Price-Anderson Act limits industry liability for third-party claims resulting from any nuclear incident to $8.9 billion per incident. Coverage of the first $200 million is provided by a pool of commercial insurers. If a nuclear incident results in public liability claims in excess of $200 million, the Company may be assessed up to $159 million per incident with payments in each year limited to a maximum of $20 million per incident; payments in excess are deferred to the next calendar year. DECOMMISSIONING The estimated cost of decommissioning the Company's nuclear power facilities is recovered in base rates through an annual allowance. For the year ended December 31, 1994, the amount recovered in rates for decommissioning costs was $54 million. The estimated total obligation for decommissioning costs is approximately $1.1 billion in 1994 dollars (or $4.5 billion in future dollars); this obligation is being recognized ratably over the facilities' lives. This estimate considers the total costs of decommissioning and dismantling plant systems and structures and includes a contingency factor for possible changes in regulatory requirements and waste disposal cost increases. As of December 31, 1994, the Company had accumulated external trust funds with an estimated fair value of $617 million, based on quoted market prices, to be used for the decommissioning of the Company's nuclear facilities. Corresponding amounts are included in accumulated depreciation and decommissioning. The trust funds maintain substantially all of their investments in debt and equity securities. All fund earnings are reinvested. Funds may not be released from the external trust funds until authorized by the CPUC. The CPUC reviews the funding levels for the Company's decommissioning trust in each GRC. Based upon the trust's then-current asset level, and revised earnings and decommissioning cost assumptions, the CPUC may revise the amount of decommissioning costs it has authorized in rates for contribution to the trust. To date the CPUC has not revised the funding levels initially established in 1987. However, to comply with tax law requirements, the Company anticipates that the CPUC will revise the funding levels no later than the 1997 tax year to reflect then-current earnings assumptions and decommissioning cost estimates. PG&E ENTERPRISES Enterprises is the parent company established to oversee the Company's unregulated non-utility business activities. Enterprises was established in 1988 and is a wholly owned subsidiary of the Company. Enterprises' activities are conducted through the entities described below. NON-UTILITY ELECTRIC GENERATION A wholly owned Enterprises subsidiary is a general partner in U.S. Generating Company (USGen), a California general partnership. A subsidiary of Bechtel Enterprises, Inc., Bechtel Generating Company, Inc., is the other general partner of USGen. USGen develops and manages non-utility electric generation facilities that compete in the U.S. power generation market and sell power to utilities other than the Company. Enterprises' ownership interest in projects developed by USGen varies by project. Profits and losses realized by USGen are distributed in proportion to the partners' relative interests in the project from which those 36 43 profits or losses are derived. USGen is currently involved in eight operational plants and five projects under construction. The total generating capacity of these 13 plants is 2,238 MW. Enterprises' share of capacity from those projects is approximately 971 MW. The projects are typically financed with a combination of equity commitments from the project sponsors and non-recourse debt. In August 1994, USGen negotiated and completed the acquisition of Makowski on behalf of Enterprises and Bechtel Enterprises, Inc. Makowski is a Boston-based company engaged in the development of natural gas-fueled power generation projects and natural gas distribution, supply and underground storage projects. Makowski is currently involved in five operational plants. (USGen is also involved in one of these plants.) With the acquisition of Makowski, Enterprises' affiliates are involved in a total of 12 plants in operation and 5 plants under construction, with total generating capacity of 3,298 MW. Enterprises' share of capacity from all 17 plants is approximately 1,389 MW. In addition, Enterprises is in the process of forming, in conjunction with Bechtel Enterprises, Inc., a company to develop, build, own and operate international nonutility generation projects. U.S. Operating Services Company (USOSC), a California general partnership, provides operations and maintenance services for power facilities managed by USGen and to third parties in the independent power production business. An Enterprises subsidiary and a subsidiary of Bechtel Group, Inc. are the general partners of USOSC. Enterprises' economic interest in USOSC projects varies by project. GAS AND OIL EXPLORATION AND PRODUCTION DALEN, a wholly owned indirect subsidiary of Enterprises, is engaged in natural gas and oil exploration and production primarily in the Gulf Coast, east Texas, Anadarko and Rocky Mountain regions of the U.S. In July 1994, the Company approved a plan for the disposition of DALEN through an initial public offering of DALEN's common stock, subject to favorable market conditions. In February 1995, the Company confirmed its intent to sell DALEN in 1995, either through an initial public offering or a private sale. The Company's decision is based upon the Company's determination that oil and gas exploration and production activities do not fit within its revised long-term corporate strategy. In anticipation of the disposition, DALEN entered into multiple contracts in June 1994 to sell $130 million of its oil and gas properties, resulting in a net pretax gain of $2 million. As of December 31, 1994, DALEN had assets of approximately $490 million. REAL ESTATE DEVELOPMENT PG&E Properties, Inc. (Properties), a wholly owned subsidiary of Enterprises, develops real estate in the Company's service territory, focusing on residential lot creation. It also develops offices, industrial buildings, retail outlets and apartments. ENVIRONMENTAL MATTERS AND OTHER REGULATION ENVIRONMENTAL MATTERS The Company is subject to a number of federal, state and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, and air and water pollution, and, in recent years, by governing the use, treatment, storage and disposal of hazardous or toxic materials. These laws and regulations affect future planning and existing operations, including environmental protection and remediation activities. The Company has undertaken major compliance efforts with specific emphasis on its purchase, use and disposal of hazardous materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of the Company's bulk waste handling and storage facilities. 37 44 ENVIRONMENTAL PROTECTION MEASURES The Company's estimated expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. Capital expenditures for environmental protection are currently estimated to be approximately $39 million, $93 million, $85 million, $69 million and $66 million for 1995, 1996, 1997, 1998 and 1999, respectively, and are included in the Company's five-year estimate of capital requirements shown above in "General -- Capital Requirements and Financing Programs." Expenditures during these years will be primarily for oxides of nitrogen (NOx) emission reduction projects. In addition, PGT estimates its capital expenditures for environmental protection will be approximately $10 million in 1995, primarily for NOx emission reduction and dry low emission equipment, and approximately $1.8 million in 1996. Air Quality The Company's existing thermal electric generating plants are subject to numerous air pollution control laws, including the California Clean Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal Clean Air Act, the three local air districts in which the Company operates fossil fuel fired generating plants adopted final rules that require a reduction in NOx emissions from the power plants of approximately 90% by 2004 (with numerous interim compliance deadlines). The first major retrofits are scheduled to begin in 1996. Certain retrofits will not be required if the smaller generating units are operated for emergency purposes only after 2000. One rule may also require additional expenditures of up to $1.5 million in the San Luis Obispo County Air Pollution Control District, depending on air quality progress in that district. The Company currently estimates that compliance with these NOx rules could require capital expenditures of approximately $300 million over 10 years. This estimate assumes that most of the 170 MW and smaller boilers will be retired before the retrofits are required. Ongoing business and engineering studies could change this estimate. Other air districts have adopted NOx rules for the Company's natural gas compressor stations in California, and these rules continue to be modified. Eventually the rules are likely to require NOx reductions of up to 80% for many of the Company's natural gas compressor stations. The Company currently estimates that the total cost of complying with these rules will be approximately $25 to $55 million over five years. In the Company's 1993 GRC, the CPUC established an Air Quality Adjustment mechanism under which the Company may seek cost recovery in rates for NOx reduction projects during 1994 and 1995. However, by the time the retrofits are operational, the Company may either be subject to PBR or one of several restructuring proposals currently under consideration by the CPUC. Therefore, the mechanism for ratemaking treatment of these costs is uncertain at this time. In 1990 Congress passed extensive amendments to the Federal Clean Air Act. The Environmental Protection Agency (EPA) has issued numerous regulations for the implementation of these amendments. The Company is currently assessing the impact of the regulations. Generally, existing or proposed state and local air quality requirements are more stringent than the new federal requirements, which should therefore have little impact on the Company. However, stringent federal air monitoring requirements mandated the installation of monitoring equipment to measure emissions from the fossil fuel fired generating plants. The cost of complying with the monitoring requirements totalled approximately $22 million in 1994. Water Quality The Company's existing power plants, including Diablo Canyon, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Company's fossil fueled power plants comply in all material respects with the discharge constituents standards and either comply in all material respects with or are exempt from the thermal standards. A thermal effects study at Diablo Canyon was completed in May 1988, and has been reviewed by the Central Coast Regional Water Quality Control Board (Regional Board). The Regional Board has not yet made a final decision on the report and has requested that the Company continue the marine monitoring program. In the event that Diablo Canyon does 38 45 not comply with the thermal limitations and in the unlikely event that major modifications are required (e.g., cooling towers), significant additional construction expenditures could be required. A thermal effects study of the Company's Pittsburg and Contra Costa Power Plants was submitted to the San Francisco and Central Valley Regional Water Quality Control Boards in December 1992. In general, the study found no significant adverse effects associated with the thermal discharge at either plant. Additionally, several fish species listed or proposed for listing as endangered species may be found in the waters near these plants. There are severe restrictions on the "taking" (e.g. harassing, wounding or killing) of such species. Therefore, significant modifications could be required to plant operations (e.g., cooling towers) if a plant intake structure or thermal discharge is found to "take" an endangered species. Pursuant to the federal Clean Water Act, the Company is required to demonstrate that the location, design, construction and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at all existing water-cooled thermal plants. The Company has submitted detailed studies of each power plant's intake structure to various governmental agencies. Each plant's existing water intake structure was found to meet the BTA requirements. However, if in the future there are changes in available technology, these findings are subject to further review by various agencies. Thus, construction expenditures or operational changes may be necessary to meet a more stringent future standard. Oil Spill Prevention The Company operates three marine terminals, approximately 92 large aboveground fuel tanks with a capacity of approximately 18 million barrels and approximately 50 miles of fuel pipelines. These facilities are used for the transport, handling and storage of residual fuel oil and diesel fuels, both of which are used at the Company's power plants. The Company continues to assess its need to operate oil handling and storage facilities as part of its efforts to reduce exposure to oil handling risks and operational expenses without sacrificing electric system reliability. Under the federal Clean Water Act Spill Prevention Control and Countermeasure (SPCC) regulations, many of the Company's power plants, substations and service centers must install and maintain facilities to prevent the release of oil and other hazardous materials to surface waters. Capitalized SPCC project costs for 1995 and 1996 are estimated to be approximately $2 million. In addition, activities associated with the transport, storage and handling of petroleum products are regulated by the federal Oil Pollution Act of 1990 (OPA) and the California Oil Spill Prevention and Response Act of 1990 (OSPRA). Under these laws, the Company is required to demonstrate $500 million of financial responsibility, which it demonstrates through a combination of insurance and self insurance. Regulations under OPA and OSPRA require development of Oil Spill Emergency Response Plans utilizing worst case planning scenarios. Plans must include contracting for response resources to respond to the worst case scenarios. The Company is a member of the Clean Bay, Clean Seas and Humboldt Bay oil spill response organizations and the Marine Preservation Association through which it can obtain the services of the Marine Spill Response Corporation, a national oil spill response organization. Company expenditures to comply with OPA and OSPRA requirements in 1995 and 1996 are estimated to total less than $2 million. HAZARDOUS MATERIALS AND HAZARDOUS WASTE COMPLIANCE AND REMEDIATION The Company assesses, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. Generally, these compliance costs are recovered through the GRC process. However, as discussed below, the CPUC has established a separate mechanism for recovery of certain hazardous waste remediation costs. The EPA, the California Department of Toxic Substances Control (DTSC), and associated regional and local agencies have comprehensive rules which regulate the manufacture, distribution, use and disposal of 39 46 polychlorinated biphenyls (PCBs). The Company has established programs and has committed resources to achieve compliance with these rules. In 1982, the EPA adopted new regulations greatly restricting the use of PCBs in electrical equipment. The regulations have resulted in the early retirement and replacement of certain equipment. Since Company operations generate PCB-contaminated waste which requires special handling, the Company has contracted with EPA-approved firms for the disposal or recycling of PCB waste. The Company estimates that PCB disposal will cost approximately $8 million in 1995 and 1996. The Company has a comprehensive program to comply with the many hazardous waste storage, handling and disposal requirements promulgated by the EPA under the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), along with California's hazardous waste laws and other environmental requirements. As part of this general compliance effort, the Company has initiated programs to address three specific environmental issues: (i) wastewater holding ponds, (ii) underground storage tanks, and (iii) historic hazardous waste sites, including former manufactured gas plant sites. Wastewater evaporation ponds contain materials such as compressor cooling water blowdown from gas compressor stations. The Company has replaced the old ponds with new evaporation ponds that meet new standards for leak monitoring, detection and containment. Capital expenditures for this work in 1995 are estimated to be approximately $0.9 million. Closure and post-closure expenditures for these ponds, including groundwater remediation, health risk assessments and management plans, may approximate $30 million for a 30-year period. Underground storage tanks are the subject of federal and California regulatory programs directed at identifying and eliminating the possibility of leaks. The Company has approximately 270 underground tanks, some of which must be upgraded to meet new standards. The tanks contain hazardous materials such as gasoline, waste automotive crankcase oil, transformer fluid or oily wastewater. The Company has an ongoing program to improve leak monitoring, test each tank for leakage and, if necessary, sample soil and water from the surrounding area and remediate any contamination detected. Costs for testing, remediation and tank replacement in 1995 and 1996 are estimated to be approximately $4.6 million. A third program is aimed at assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation, manufactured gas plant facilities produced lampblack and tar residues, byproducts of a process that the Company and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Company's manufactured gas plants were removed from service. The residues which may remain at some sites contain chemical compounds which now are classified as hazardous. The Company has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites which the Company operated in its service territory. The Company owns all or a portion of 29 of these manufactured gas plant sites. The Company has begun a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites which the Company owns. The Company currently estimates that this program may result in expenditures of approximately $30 million over the period 1995 through 1996. The full long-term costs of the program cannot be determined accurately until a closer study of each site has been completed. It is expected that expenses will increase as remedial actions related to these sites are approved by regulatory agencies or if the Company is found to be responsible for clean up at sites it does not currently own. Manufactured gas plant sites at which the Company has been designated as a potentially responsible party (PRP) under the California Hazardous Substance Account Act (California Superfund) include the Martin Service Center site and Midway/Bayshore sites in Daly City, California, the San Rafael site, and the Sacramento site. The Company will perform a groundwater remedial action at its former Sacramento manufactured gas plant site during 1995 at a cost of up to $3 million. The DTSC must approve the groundwater remedial action design plan proposed for this site before it is implemented. The Company has accrued a $7.3 million liability at December 31, 1994 for the Sacramento gas plant site. In addition to the manufactured gas plant sites, the Company may be required to take remedial action at certain other disposal sites if they are determined to present a significant threat to human health and the 40 47 environment because of an actual or potential release of hazardous substances. The Company has been designated as a PRP under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales site in Malaga, California, the Jibboom Junkyard site in Sacramento, California, the Industrial Waste Processing site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales site is a former used oil recycling facility at which the Company is one of nine PRPs named in an EPA order requiring groundwater remediation at the site. The Company has also entered into an Administrative Order with the EPA to address soil contamination at the site. The Company has accrued a $6.4 million liability at December 31, 1994 for the Purity Oil Sales site. Although the Company has not been named as a PRP with respect to the Casmalia site near Santa Maria, California, the EPA has notified the Company and approximately 65 other generators who allegedly sent the largest volumes of waste to the site that action is needed to clean up and close the site. The Company is working with other alleged generators to evaluate measures which may need to be taken at the site. The Company has accrued a $1.9 million liability for the Casmalia site. Although the Company has not been formally designated a PRP with respect to the Geothermal Industries, Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General's office have directed the Company and other parties to initiate measures with respect to the study and remediation of that site. The Company has accrued a liability of $9.8 million for the Geothermal Industries, Incorporated site. In addition to the sites discussed above, the Company has also been identified as a PRP at certain disposal sites under the California Superfund. These sites include the Emeryville Service Center site in Emeryville, California and the GBF Landfill at Pittsburg, California. The Company has also received a demand from the California Attorney General seeking reimbursement of cleanup costs incurred by the State of California at the Company's former Jibboom Street power plant in Sacramento, California. In addition, the Company has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Company is responsible for performing or paying for remedial action at sites the Company no longer owns or never owned. The overall costs of the hazardous materials and hazardous waste compliance and remediation activities described above are difficult to estimate due to uncertainty concerning the extent of environmental risks and the Company's responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. However, based on the information currently available, the Company has an accrued liability as of December 31, 1994 of $95 million for hazardous waste remediation costs. The ultimate amount of such costs may be as much as $235 million if, among other things, the Company is held responsible for cleanup at additional sites, other PRPs are not financially able to contribute to these costs, or further investigation indicates that the extent of contamination and affected natural resources is greater than anticipated at sites for which the Company is responsible. Potential Recovery of Hazardous Waste Compliance and Remediation Costs In May 1994, the CPUC issued a decision in the Southern California Gas Company's (SoCal Gas) environmental reasonableness proceeding. The final decision adopts the settlement and proposed ratemaking mechanism for hazardous waste remediation costs which was previously submitted by the Company and other interested parties. That mechanism assigns 90% of the includable hazardous substance cleanup costs to utility ratepayers and 10% to utility shareholders, without a reasonableness review of such costs or of underlying activities. However, under the proposed mechanism, utilities will have the opportunity to recover the shareholder portion of the cleanup costs from insurance carriers. The mechanism provides that 70% of the ratepayer portion of the Company's cleanup costs is attributed to its gas department and 30% is attributed to its electric department. The Company can seek to recover hazardous substance cleanup costs under the new mechanism in any rate proceeding it deems most appropriate. The final decision in the SoCal Gas proceeding permits the Company to seek recovery under the new mechanism of environmental cleanup costs previously recorded in balancing accounts under the old recovery mechanism. Accordingly, in its 1995 BCAP, the Company is seeking recovery of $10.5 million in environmental cleanup costs under the new mechanism, which amount represents the gas department's allocation of such previously recorded cleanup costs. 41 48 To the extent that hazardous waste compliance and remediation costs are not recovered through insurance or by other means, the Company may apply for recovery through ratemaking procedures established by the CPUC and, assuming continuation of these procedures, expects that most prudently incurred hazardous waste compliance and remediation costs will be recovered through rates. As of December 31, 1994, the Company has a deferred charge of $83 million for hazardous waste remediation costs, which represents the minimum amount of such costs expected to be recovered under the current ratemaking mechanisms. The Company believes that the ultimate outcome of these matters will not have a significant adverse impact on its financial position or results of operations. In December 1992, the Company filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. The Company had previously notified its insurance carriers that it seeks coverage under its Comprehensive General Liability Policies to recover costs incurred at certain specified sites. In the main, the Company's carriers neither admitted nor denied coverage, but requested additional information from the Company. The amount of recovery from insurance coverage, if any, cannot be quantified at this time. ELECTRIC AND MAGNETIC FIELDS In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks which may be associated with electric and magnetic fields (EMF) from utility facilities. In its order instituting the investigation, the Commission acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMF, but went on to state that a body of evidence has been compiled which raises the question of whether adverse health impacts might exist. The CPUC proceeding was subsequently bifurcated into two phases -- one focusing on EMF related to electric power and the other on EMF generated by cellular telephone transmitters. In the electric power phase, in November 1993, the CPUC adopted an interim EMF policy for California energy utilities which, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMF from new and upgraded utility facilities. California energy utilities will be required to fund a $1.5 million EMF education program and a $5.6 million EMF research program managed by the California Department of Health Services over the next four years. As part of its effort to educate the public about EMF, the Company provides interested customers with information regarding the EMF exposure issue. The Company also provides a free field measurement service to its customers which informs customers about EMF levels at different locations in and around their residences or commercial buildings. The Company and other utilities are involved in litigation concerning EMFs. The Company is named as a defendant in three pending civil lawsuits. Plaintiffs allege personal injury resulting from exposure to EMFs and diminution in property value due to the presence of EMFs from nearby high voltage lines. In the event that the scientific community reaches a consensus that EMF presents a health hazard and further determines that the impact of utility-related EMF exposures can be isolated from other exposures, the Company may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot be estimated with any certainty at this time. However, such costs could be significant depending on the particular mitigation measures undertaken, especially if relocation of existing power lines is ultimately required. LOW EMISSION VEHICLE PROGRAMS In October 1991, the CPUC issued an Order Instituting Investigation/Order Instituting Rulemaking on Low Emission Vehicles (LEVs) to investigate policy issues surrounding electric and natural gas utility involvement in the market associated with LEVs, specifically natural gas vehicles (NGVs) and electric vehicles (EVs). Hearings in Phase I of the LEV proceeding were conducted in August 1992, and examined long-term utility involvement in LEV programs in relation to California's environmental, energy and 42 49 transportation goals. The Company generally proposed that its long-term role in the LEV market be that of a fuel supplier, transporter and distributor. In July 1993, the CPUC issued a decision in Phase I of the LEV proceeding. The decision recognized a significant role for the Company in the LEV market and directed the Company to file a request for funding for a six-year program (1995-2000). In August 1994, the Company requested approximately $41 million in funding for the Company's fleet and market development activities for NGVs and EVs over the six-year period. Joint hearings on all utilities' LEV funding requests were held in the fall of 1994, with a Phase II decision expected by mid-1995. As noted above (see "Proposed Regulatory Reforms -- Company's Proposals -- PBR"), the Company proposes to revise its RRI filing to reflect the CPUC's electric industry restructuring plan once the details of the CPUC's plan are sufficiently definitive. The Company anticipates that in its revised filing it will recommend that LEV program costs be funded as part of environmental and social benefit programs generally, with LEV funding included in the rate component related to such programs. The decision in the Company's 1993 GRC extended NGV funding of $8.5 million per year pending a final decision in the LEV proceeding described above, and authorized $1.8 million for EV programs. The Company is using the NGV funds to install additional natural gas refueling facilities, to purchase or convert additional NGVs for the Company's fleet, and to provide incentives and assistance in converting additional customer vehicles to NGVs. The Company and its customers currently operate nearly 2,700 NGVs. OTHER REGULATION CALIFORNIA PUBLIC UTILITIES COMMISSION In addition to its jurisdiction over rate matters, the CPUC has the authority, among other things, to establish rules and conditions of service, to authorize disposition of utility property, to establish rules and policies governing utility facilities, to regulate securities issues, to prescribe rates of depreciation and uniform systems of accounts and to regulate transactions between the Company and its subsidiaries and affiliates. CALIFORNIA ENERGY COMMISSION The Company also is subject to the jurisdiction of the CEC. The CEC has developed programs for forecasting peak demands and energy requirements, is encouraging and requiring certain types of energy conservation, has developed energy shortage and contingency plans, and is developing and coordinating a program of energy research and development. In addition, the CEC has statutory authority to certify future thermal-electric power plant sites and related facilities 50 MW and above within California. The Governor of California is currently in the process of submitting to the California State Legislature a plan to reorganize the CEC. Under that plan, the CEC would be consolidated into the existing Department of Conservation to create a new Department of Energy and Conservation, the head of which would be appointed by the Governor. FEDERAL ENERGY REGULATORY COMMISSION The Company is subject to regulation by the FERC under the Federal Power Act as a "public utility" as defined in the Act. The FERC has authority, among other things, to regulate the Company's rates and terms and conditions for sales of electricity for resale and transmission of electricity in interstate commerce, and to prescribe rates of depreciation and uniform systems of accounts. The FERC also regulates the terms and conditions of interstate pipeline transportation service utilized by the Company to transport gas it purchases outside California. In addition, the FERC regulates PGT's rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of PGT's facilities and PGT's accounting, among other things. FERC-HYDROELECTRIC LICENSING Most of the Company's hydroelectric facilities are subject to licenses issued under Part I of the Federal Power Act, with various expiration dates to the year 2033 and involving a total normal operating capability of 2,703 MW. Helms adds an additional capacity of 1,212 MW. As the initial licenses for these projects expire, 43 50 they become susceptible to competition for a new license. In the years prior to 1986, several governmentally run utilities, claiming a statutory "preference" in their favor superior to the Company, had filed competing applications for four of the Company's projects. Federal legislation enacted in 1986 eliminated any preference for governmentally run utilities in hydroelectric relicensing proceedings commenced after 1986. The 1986 law provided options for resolving relicensing competitions. The Company elected to pay the competing applicants for the four projects a "reasonable" settlement consisting of their costs incurred to pursue the licenses and a potential additional amount ranging from 0% to 100% of the Company's remaining net investment in the relevant project. In return, the competing applicants are required to withdraw their competing license applications. The FERC approved the settlement agreement for two projects. In October 1992, the FERC issued an order requiring the Company to pay compensation of $1.9 million to the competing applicants for the remaining two projects, representing the costs incurred preparing their applications. The FERC declined to award the competing applicants any additional compensation. In December 1993, the Company paid the amount called for in the FERC order, and in October 1994, the U.S. Court of Appeals affirmed that order. The Company expects to recover the costs of all FERC-awarded compensation through rates. NUCLEAR REGULATORY COMMISSION The Company also is subject to the jurisdiction of the NRC as to operation of its nuclear generating plants. ITEM 2. PROPERTIES. Information concerning the Company's electric generation units, gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All real properties and substantially all personal properties of the Company are subject to the lien of an indenture which provides security to the holders of the Company's First and Refunding Mortgage Bonds. ITEM 3. LEGAL PROCEEDINGS. See Item 1--Business, for other proceedings pending before governmental and administrative bodies. In addition to the following legal proceedings, the Company is subject to routine litigation incidental to its business. ANTITRUST LITIGATION On December 3, 1993, the County of Stanislaus and Mary Grogan, a residential customer of the Company, filed a complaint in the U.S. District Court, Eastern District of California, against the Company and PGT, on behalf of themselves and purportedly as a class action on behalf of all natural gas customers of the Company during the period of February 1988 through October 1993. The complaint alleges that the purchase of natural gas in Canada was accomplished in violation of various antitrust laws which resulted in increased prices of natural gas for the Company's customers. The complaint alleges that the Company could have purchased as much as 50% of the Canadian gas on the spot market instead of relying on long-term contracts and that the damage to the class members is at least as much as the price differential multiplied by the replacement volume of gas, an amount estimated in the complaint as potentially exceeding $800 million. In addition, the complaint indicates that the damages to the class could include over $150 million paid by the Company to terminate the contracts with the Canadian gas producers in November 1993. The complaint seeks recovery of three times the amount of the actual damages pursuant to the antitrust laws. In August 1994, the federal district court issued a decision granting the Company's motion to dismiss the federal and state antitrust claims and the state unfair practices claims against the Company and PGT. The only remaining claims did not seek monetary damages. In addition, the Court granted plaintiffs' motion seeking class certification. 44 51 In dismissing the antitrust claims, the Court determined that the prices the Company paid for Canadian gas had been filed with, reviewed and approved as reasonable by various federal and state regulatory authorities, and as a result, the plaintiffs were barred from claiming that those rates were too high. The Court also held that the CPUC's oversight of the Company's gas acquisition costs constitutes state action which immunizes the Company from a private antitrust lawsuit such as this one. In September 1994, plaintiffs filed an amended complaint with the Court. A&S, the Company's wholly owned Canadian gas purchasing subsidiary, is added as a defendant in the amended complaint. In essence, the amended complaint restates the claims in the original complaint, and in addition alleges that the defendants, through anticompetitive practices, foreclosed access over the PGT pipeline to alternative sources of gas in Canada by certain customers of the Company. A new motion to dismiss was filed by the Company in November 1994. The Company believes that the ultimate outcome of the antitrust litigation will not have a significant adverse impact on its financial position. HINKLEY COMPRESSOR STATION LITIGATION In May 1993, a complaint was filed in San Bernardino County Superior Court on behalf of a number of individuals seeking recovery of an unspecified amount of damages for personal injuries and property damage allegedly suffered as a result of exposure to chromium near the Company's Hinkley Compressor Station, located along the Company's gas transmission system in San Bernardino County, as well as punitive damages. The original complaint has been amended, and additional complaints have been filed, to include additional plaintiffs. The complaints plead several causes of action, including negligence, negligent and intentional misrepresentation, fraudulent concealment, strict liability and violation of California's Safe Drinking Water and Toxic Enforcement Act of 1986 (Proposition 65). The plaintiffs contend that between 1951 and 1966 the Company discharged Chromium VI-contaminated wastewater into unlined ponds, which led to chromium percolating into the groundwater of surrounding property. The plaintiffs further allege that the Company disposed of the chromium in those ponds to avoid costly alternatives. In 1987, the Company undertook an extensive project to remediate potential groundwater chromium contamination. The Company has incurred substantially all of the costs it currently deems necessary to clean up the affected groundwater contamination. In accordance with the remediation plan approved by the regional water quality board, the Company will continue to monitor the affected area and periodically perform environmental assessments. The Company has reached an agreement with plaintiffs pursuant to which plaintiffs' actions will be submitted to binding arbitration for resolution of issues concerning the cause and extent of any damages suffered by plaintiffs. Under the terms of the agreement, the Company will pay an aggregate amount of no more than $400 million in settlement of such plaintiffs' claims, including $50 million paid to escrow to date. In turn, those plaintiffs, and their attorneys, agree to indemnify the Company against any additional losses the Company may incur with respect to related claims pursued by the identified plaintiffs who do not agree to this settlement or by other third parties who may be sued by the identified plaintiffs in connection with the alleged chromium contamination. In January 1995, ten representative cases began arbitration before two judges. At the conclusion of the arbitration, the parties began a process of mediation in an attempt to settle the remaining 625 cases, based on the results of the arbitration. If the mediation is not successful, the parties will proceed to arbitrate another 25 to 30 more cases. Following that, the parties will attempt to mediate the remaining cases. This process will continue until all cases are arbitrated or settled. As of December 31, 1994, the Company had a remaining reserve of $50 million against any future potential liability in this case. The Company believes the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. 45 52 COUNTIES FRANCHISE FEES LITIGATION On March 31, 1994, the Counties of Alameda and Santa Clara filed a complaint in Santa Clara County Superior Court against the Company on behalf of themselves and purportedly as a class action on behalf of 47 counties with which the Company has gas or electric franchise contracts. Franchise contracts require the Company to pay fees on an annual basis to cities and counties for the right to use or occupy public streets and roads. The complaint alleges that, since at least 1987, the Company has intentionally underpaid its franchise fees to the counties in an unspecified amount. The complaint cites two reasons for the alleged underpayment of fees. Based on their interpretation of certain legislation, the plaintiffs allege that the Company has been using the wrong methodology to compute the franchise fees payable to the plaintiff counties. The plaintiffs also allege that fees have been underpaid due to incorrect calculations under the methodology used by the Company. The parties agreed to stipulate to this case proceeding as a class action lawsuit regarding the issue of the correct payment methodology to be applied in calculating the franchise fees due to the plaintiffs. On March 14, 1995, the Superior Court granted the Company's motion for summary judgment in the class action lawsuit. The plaintiffs may appeal that ruling. Consistent with the agreement between the parties noted above, the plaintiffs refiled a separate action covering just the issue of whether the Company properly computed its franchise payments, assuming that the Company has been using the correct methodology. Plaintiffs have not indicated damages to be sought in that separate action, but they are not anticipated to be material. Should the counties win the issue of franchise fee calculation methodology, the Company's annual system-wide county franchise fees could increase by approximately $15 million. Damages for alleged underpayments in prior years could be as much as $117 million (exclusive of interest, estimated to be $28 million as of December 31, 1994). The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. CITIES FRANCHISE FEES LITIGATION On May 13, 1994, the City of Santa Cruz filed a complaint in Santa Cruz County Superior Court against the Company on behalf of itself and purportedly as a class action on behalf of 107 cities with which the Company has certain electric franchise contracts. The complaint alleges that, since at least 1988, the Company has intentionally underpaid its franchise fees to the cities in an unspecified amount. The complaint alleges that the Company has asked for and accepted electric franchises from the cities included in the purported class, which provide for lower franchise payments than required by franchises granted by other cities in the Company's service territory. Plaintiff asserts that this was done in an unlawfully discriminatory manner based solely on location. The plaintiff also alleges that the transfer of these franchises to the Company by its predecessor companies was not approved by the CPUC as required, and, therefore, all such franchise contracts are void. The Court has certified the class of 107 cities in this action, and approved the City of Santa Cruz as the class representative. The case is in discovery and no trial date has been set. Should the cities prevail on the issue of franchise fee calculation methodology, the Company's annual system-wide city electric franchise fees could increase by approximately $17 million. Damages for alleged underpayments in prior years could be as much as $114 million (exclusive of interest, estimated to be $23 million as of December 31, 1994). The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. 46 53 TIME-OF-USE METER LITIGATION On July 21, 1994, Milton L. Grinstead, Michael Davis, Joan A. Williamson, Frank H. Lacy, and Matthew Doerksen filed a complaint in the Stanislaus County Superior Court against the Company on behalf of themselves and purportedly as a class action on behalf of all of the Company's customers, for "refund of unlawfully charged fees." The complaint has been amended to broaden the alleged class to include customers of the Turlock Irrigation District (TID), which purchases power from the Company, on the theory that TID customers' rates have been affected by the Company's alleged failure to notify its customers of the best available rate. The complaint alleges that the Company improperly failed to notify its customers of the most favorable rates available to each particular customer. The complaint focuses on the "time-of-use" billing option, which allows customers to save money by shifting their electricity use to off-peak hours when electricity is cheaper. Plaintiffs contend that all customers could have saved an average of $50-$75 per month per customer had they been placed on time-of-use rates. The complaint seeks damages estimated to be in excess of $16 billion. The amended complaint also includes a claim for $100 billion in "exemplary" damages, alleging that the Company's failure to properly advise customers of the "time-of-use" billing option and other rates was "wilful." The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. NORCEN LITIGATION On March 17, 1994, Norcen Energy Resources Limited (Norcen Energy) and Norcen Marketing Incorporated (Norcen Marketing) filed a complaint in the U.S. District Court, Northern District of California, against the Company and PGT. Norcen Marketing signed a 30-year Firm Service Agreement with PGT for transportation of 47,022 million Btus per day (MMBtu/d) on the PGT portion of the Pipeline Expansion. The annual demand charges under the contract currently are approximately $8.1 million. Norcen Energy is a guarantor of the 30-year transportation contract between PGT and Norcen Marketing. The complaint alleges that PGT and the Company wrongfully induced Norcen Energy and Norcen Marketing to enter into the 30-year contract by concealing legal action taken by the Company before the CPUC (requesting clarification that gas shipped on the PGT portion of the Pipeline Expansion should pay PG&E's incremental Expansion rates for in-state service) two days before Norcen Marketing's contract became binding. The complaint further alleges breach of representations to plaintiffs that the Company would not "unreasonably" build its Pipeline Expansion with less than "sufficient" firm subscription. The complaint also alleges breach of an agreement between PGT and a Norcen predecessor named Bonus Gas Processors Corp. (Bonus) relating to the installation of additional capacity. The complaint generally charges the Company with monopolizing the capacity on the original PGT facilities from Kingsgate to Malin and wrongfully preventing Norcen Energy and Norcen Marketing (apparently based on rights allegedly acquired from Bonus) from utilizing the existing PG&E transmission system to provide gas to customers in Northern California. The complaint alleges various antitrust, contractual, and other claims against the defendants and seeks rescission, restitution and recovery of unspecified damages. In a pleading filed in June 1994, the plaintiffs indicate a claim for $140 million (before trebling) based on defendants' allegedly exclusionary business behavior, as well as an unspecified amount of contract damages. Based on available information, plaintiffs' out-of-pocket contract damages appear to be less than $10 million. On September 19, 1994, the U.S. District Court, Northern District of California, granted PGT's and the Company's motion to dismiss all federal antitrust claims in the complaint in this case, and dismissed the remaining state antitrust and contract claims for lack of jurisdiction. On October 18, 1994, Norcen filed an amended complaint. The amended complaint reasserted part of the original complaint's antitrust claims, asserted new antitrust claims based on the same facts and specifically alleged diversity jurisdiction for the state 47 54 law contract claims. On November 18, 1994, PGT and the Company filed motions to dismiss the amended complaint. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. POTTER VALLEY HYDROELECTRIC PROJECT On January 19, 1995, the FERC issued a decision finding that the Company had not violated the FERC's April 1994 order relating to a fish screen and bypass facility for the Company's Potter Valley Hydroelectric Project, reversing the compliance order issued by the FERC in September 1994 indicating such a violation had occurred. Accordingly, no fines will be imposed in connection with the matters cited in the September compliance order. PGT UNIT 4C COMPRESSOR UNIT PERMIT PGT owns and operates the 4C Solar Mars compressor unit near Sandpoint, Idaho (Unit 4C). In connection with an upgrade of Unit 4C in 1986, PGT applied for and received a construction permit from the State of Idaho Department of Environmental Quality. At the time PGT received the construction permit, it was determined that no permit for the modification was needed under the federal Prevention of Significant Deterioration (PSD) program, then being administered in Idaho by the State. In the process of applying for a permit under the 1990 Clean Air Act, PGT conducted a review of its environmental permits and discovered information which now causes it to question whether a construction permit incorporating PSD requirements may have been required prior to the 1986 upgrade. PGT is in the process of discussing this information with the State of Idaho. If it is finally determined that such a permit was required, PGT may be required to apply for and obtain a PSD permit for Unit 4C and/or to retrofit Unit 4C. PGT may also be subject to fines and penalties which could exceed $100,000, but it cannot be determined with any certainty at present whether a fine will ultimately be imposed or what the amount of any such fine would be. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. 48 55 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Not applicable. EXECUTIVE OFFICERS OF THE REGISTRANT "Executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of the Company are as follows:
AGE AT DECEMBER 31, NAME 1994 POSITION EFFECTIVE DATE -------------------- -------------- ---------------------- ------------------ R. A. Clarke................. 64 Chairman of the Board July 1, 1994 S. T. Skinner................ 57 President and Chief Executive Officer July 1, 1994 R. D. Glynn, Jr.............. 52 Executive Vice President July 1, 1994 J. D. Shiffer................ 56 Executive Vice President November 1, 1991 R. J. Haywood................ 50 Senior Vice President and General Manager, December 21, 1994 Customer Energy Services J. F. Jenkins-Stark.......... 43 Senior Vice President and General Manager, Gas August 1, 1993 Supply Business Unit V. G. Rose................... 48 Senior Vice President and General Manager, January 1, 1994 Electric Supply Business Unit G. M. Rueger................. 44 Senior Vice President and General Manager, November 1, 1991 Nuclear Power Generation Business Unit T. W. High................... 47 Vice President and Assistant to the Chief July 1, 1994 Executive Officer G. N. Horne.................. 63 Vice President--Corporate Communications July 1, 1983 J. Pfannenstiel.............. 47 Vice President--Corporate Planning February 1, 1987 G. R. Smith.................. 46 Vice President and Chief Financial Officer November 1, 1991 B. Coull Williams............ 42 Vice President--Human Resources February 1, 1993 B. R. Worthington............ 45 Vice President and General Counsel December 21, 1994
All officers serve at the pleasure of the Board of Directors. All executive officers have been employees of the Company for the past five years. In addition to their current positions, the executive officers had the following business experience during that period:
NAME POSITION PERIOD HELD OFFICE ----------------------- -------------------------------------------- ---------------------------------- R. A. Clarke........... Chairman of the Board and Chief Executive May 1, 1986 to June 30, 1994 Officer S. T. Skinner.......... President and Chief Operating Officer November 1, 1991 to June 30, 1994 Vice Chairman of the Board May 1, 1986 to October 31, 1991 J. D. Shiffer.......... Senior Vice President and General Manager, February 1, 1990 to October 31, 1991 Nuclear Power Generation Business Unit Vice President--Nuclear Power Generation October 1, 1984 to January 31, 1990 R. D. Glynn, Jr........ Senior Vice President and General Manager, January 1, 1994 to June 30, 1994 Customer Energy Services Business Unit Senior Vice President and General Manager, November 1, 1991 to December 31, 1993 Electric Supply Business Unit Vice President--Power Generation January 1, 1988 to October 31, 1991 R. J. Haywood.......... Vice President of Power System February 22, 1993 to December 20, 1994 Vice President--Power Planning and Contracts April 20, 1988 to February 21, 1993 J. F. Jenkins-Stark.... Vice President and Treasurer January 15, 1992 to July 31, 1993 Treasurer November 1, 1987 to January 14, 1992 V. G. Rose............. Senior Vice President and General Manager, February 22, 1993 to December 31, 1993 Customer Energy Services Business Unit Senior Vice President and General Manager, September 1, 1988 to February 21, 1993 Distribution Business Unit G. M. Rueger........... Senior Vice President and General Manager January 1, 1988 to October 31, 1991 Electric Supply Business Unit T. W. High............. Vice President and Assistant to November 1, 1991-June 30, 1994 the Chairman of the Board Vice President and Corporate Secretary May 1, 1986 to October 31, 1991 G. R. Smith............ Vice President--Finance and Rates November 1, 1987 to October 31, 1991 B. Coull Williams...... Division Manager, San Francisco Division April 13, 1992 to January 31, 1993 Division Manager, North Bay Division July 1, 1989 to April 12, 1992 B. R. Worthington...... Chief Counsel--Corporate January 10, 1991-December 20, 1994 Attorney June 10, 1974-January 9, 1991
49 56 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. Information responding to Item 5 is set forth on page 43 under the heading "Quarterly Consolidated Financial Data" in the Company's 1994 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 6. SELECTED FINANCIAL DATA. A summary of selected financial information for the Company for each of the last five fiscal years is set forth on page 12 under the heading "Selected Financial Data" in the Company's 1994 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. A discussion of the Company's results of operations and liquidity and capital resources is set forth on pages 13 through 20 under the heading "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition" in the Company's 1994 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Information responding to Item 8 is contained in the Company's 1994 Annual Report to Shareholders on page 44 and pages 21 through 43 under the headings "Report of Independent Public Accountants," "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity and Preferred Stock," "Statement of Consolidated Capitalization," "Schedule of Consolidated Segment Information," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. Information regarding executive officers of the Company is included in a separate item captioned "Executive Officers of the Registrant" contained on page 47 in Part I of this report. Other information responding to Item 10 is included on pages 3 through 5 under the heading "Nominees for Director" in the 1995 Proxy Statement relating to the 1995 Annual Meeting of Shareholders, which information is hereby incorporated by reference. ITEM 11. EXECUTIVE COMPENSATION. Information responding to Item 11 is included on page 7 under the heading "Compensation of Directors" and on pages 11 through 18 under the heading "Executive Compensation" in the 1995 Proxy Statement relating to the 1995 Annual Meeting of Shareholders, which information is hereby incorporated by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Information responding to Item 12 is included on pages 8 and 19 under the headings "Security Ownership of Management" and "Principal Shareholders" in the 1995 Proxy Statement relating to the 1995 Annual Meeting of Shareholders, which information is hereby incorporated by reference. 50 57 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Information responding to Item 13 is included on page 7 under the heading "Certain Relationships and Related Transactions" in the 1995 Proxy Statement relating to the 1995 Annual Meeting of Shareholders, which information is hereby incorporated by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT: 1. The following consolidated financial statements, schedules of consolidated segment information, supplemental information and report of independent public accountants contained in the 1994 Annual Report to Shareholders, are incorporated by reference in this report: Statement of Consolidated Income for the Years Ended December 31, 1994, 1993 and 1992. Consolidated Balance Sheet at December 31, 1994 and 1993. Statement of Consolidated Cash Flows for the Years Ended December 31, 1994, 1993 and 1992. Statement of Consolidated Common Stock Equity and Preferred Stock for the Years Ended December 31, 1994, 1993 and 1992. Statement of Consolidated Capitalization at December 31, 1994 and 1993. Schedule of Consolidated Segment Information for the Years Ended December 31, 1994, 1993 and 1992. Notes to Consolidated Financial Statements. Quarterly Consolidated Financial Data. Report of Independent Public Accountants. 2. Report of Independent Public Accountants. 3. Consolidated financial statement schedules: II -- Consolidated Valuation and Qualifying Accounts for the Years Ended December 31, 1994, 1993 and 1992. Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto. 51 58 4. Exhibits required to be filed by Item 601 of Regulation S-K: 3.1 Restated Articles of Incorporation effective as of July 26, 1994 (Form 10-Q for quarter ended June 30, 1994 (File No. 1-2348), Exhibit 3.1). 3.2 By-Laws dated January 1, 1995. 4. First and Refunding Mortgage dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (Registration No. 2-1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2). 10.1 Firm Transportation Service Agreement between the Company and Pacific Gas Transmission Company dated October 26, 1993 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.4), rate schedule FTS-1, and general terms and conditions. 10.2 Transportation Service Agreement as Amended and Restated Between the Company and El Paso Natural Gas Company dated November 1, 1993 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.5), rate schedule T-3, and general terms and conditions. 10.3 Diablo Canyon Settlement Agreement dated June 24, 1988 (Form 8-K dated June 27, 1988) (File No. 1-2348), Exhibit 10.1), Implementing Agreement dated July 15, 1988 (Form 10-Q for the quarter ended June 30, 1988 (File No. 1-2348), Exhibit 10.1) and portions of the California Public Utilities Commission Decision No. 88-12-083, dated December 19, 1988, interpreting the Settlement Agreement (Form 10-K for fiscal year 1988 (File No. 1-2348), Exhibit 10.4). *10.4 Pacific Gas and Electric Company Deferred Compensation Plan for Directors (Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit 10.5). *10.5 Pacific Gas and Electric Company Deferred Compensation Plan for Officers (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.6). *10.6 Savings Fund Plan for Employees of Pacific Gas and Electric Company applicable to non-union employees, as amended September 21, 1994, effective April 1, 1995. *10.7 Performance Incentive Plan of Pacific Gas and Electric Company (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.10). *10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union employees, as amended September 21, 1994, effective January 1, 1995. *10.9 Pacific Gas and Electric Company Supplemental Executive Retirement Plan, as amended through October 16, 1991 (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11). *10.10 Pacific Gas and Electric Company Stock Option Plan, as amended effective as of September 16, 1992 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.13). *10.11 Pacific Gas and Electric Company Performance Unit Plan (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.13). *10.12 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16). *10.13 Pacific Gas and Electric Company Executive Flexible Perquisites Program (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16). *10.14 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16). - --------------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K. 52 59 *10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee Directors (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.18). *10.16 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non-Employee Directors (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.19). *10.17 Pacific Gas and Electric Company Long-Term Incentive Program (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.21). 11. Computation of Earnings Per Common Share (Form 8-K dated March 2, 1995 (File No. 1-2348), Exhibit 11). 12.1 Restated Computation of Ratios of Earnings to Fixed Charges. 12.2 Restated Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends. 13. 1994 Annual Report to Shareholders (portions of the 1994 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity and Preferred Stock," "Statement of Consolidated Capitalization," "Schedule of Consolidated Segment Information," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data," included only) (except for those portions which are expressly incorporated herein by reference, such 1994 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein). 21. Subsidiaries of the Company (not included because the Company's subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a "significant subsidiary" under Rule 1-02(v) of Regulation S-X as of the end of the year covered by this report). 23. Consent of Arthur Andersen LLP. 24.1 Resolution of the Board of Directors authorizing the execution of the Form 10-K. 24.2 Powers of Attorney. 27. Financial Data Schedule (Form 8-K dated March 2, 1995 (File No. 102348), Exhibit 27). 99. Information required by Form 11-K with respect to the Savings Fund Plan for Employees of Pacific Gas and Electric Company, as permitted by Rule 15d-21. - --------------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K. 53 60 The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission as indicated and are hereby incorporated by reference. Exhibits will be furnished to security holders of the Company upon written request and payment of a fee of $.30 per page, which fee covers only the Company's reasonable expenses in furnishing such exhibits. (B) REPORTS ON FORM 8-K Reports on Form 8-K during the quarter ended December 31, 1994 and through the date hereof: 1. October 13, 1994 Item 5. Other Events -- Helms Pumped Storage Plant -- Proposed Settlement 2. October 21, 1994 Item 5. Other Events -- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case Settlement -- Performance Incentive Plan -- Year-to-Date Financial Results 3. October 28, 1994 Item 5. Other Events -- California Public Utilities Commission Proceedings -- 1995 Cost of Capital Proceeding -- Long-Term Noncore Gas Transportation Tariff/Gas Transmission Jurisdiction 4. November 17, 1994 Item 5. Other Events -- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case Settlement 5. November 23, 1994 Item 5. Other Events -- California Public Utilities Commission Proceedings -- Electric Industry Restructuring -- Restructuring of Gas Supply Arrangements -- Recovery of Interstate Transportation Demand Charges -- Energy Cost Adjustment Clause -- 1995 Cost of Capital Proceeding -- PGT/PG&E Pipeline Expansion Project -- Other Competitive Interstate Pipeline Projects -- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case Settlement -- Diablo Canyon License Amendment 6. December 5, 1994 Item 5. Other Events -- Proposed Modification of Diablo Canyon Pricing Mechanism 7. December 19, 1994 -- California Public Utilities Proceedings -- Electric Industry Restructuring -- 1996 General Rate Case 54 61 8. January 4, 1995 Item 5. Other Events -- Performance Incentive Plan -- 1995 Target -- California Public Utilities Commission Proceedings -- 1995 Electric Rate Stabilization/Attrition Rate Adjustment -- ECAC -- 1988 - 1990 Gas Reasonableness Proceedings 9. January 19, 1995 Item 5. Other Events -- Performance Incentive Plan -- 1994 Financial Results -- 1994 Consolidated Earnings (unaudited) -- Common Stock Dividend -- California Public Utilities Commission Proceedings -- Core Procurement Incentive Mechanism 10. February 21, 1995 Item 5. Other Events -- California Public Utilities Commission Proceedings--Experimental Procurement Service for Customer-Identified Electric Supply 11. March 2, 1995 Item 7. Financial Statements, Pro Forma Information and Exhibits -- 1994 Financial Statements -- Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined Fixed Charges and Preferred Dividends -- Exhibits INDEMNIFICATION UNDERTAKING For purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into the registrant's Registration Statement on Form S-8 No. 33-23692 (filed August 12, 1988): Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in a successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. 55 62 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY AND COUNTY OF SAN FRANCISCO, ON THE 27TH DAY OF MARCH, 1995. PACIFIC GAS AND ELECTRIC COMPANY (Registrant) By GARY P. ENCINAS ----------------------------------- (Gary P. Encinas, Attorney-in-Fact) PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE - ------------------------------------------- --------------------------- --------------- A. PRINCIPAL EXECUTIVE OFFICER OR OFFICERS *STANLEY T. SKINNER President and Chief Executive March 27, 1995 Officer and Director B. PRINCIPAL FINANCIAL OFFICER *GORDON R. SMITH Vice President and March 27, 1995 Chief Financial Officer C. CONTROLLER OR PRINCIPAL ACCOUNTING OFFICER *THOMAS C. LONG Controller March 27, 1995 D. DIRECTORS * RICHARD A. CLARKE * H. M. CONGER * WILLIAM S. DAVILA * MELVIN B. LANE * DAVID M. LAWRENCE * LESLIE L. LUTTGENS * RICHARD B. MADDEN * GEORGE A. MANEATIS Directors March 27, 1995 * MARY S. METZ * WILLIAM F. MILLER * JOHN B. M. PLACE * SAMUEL T. REEVES * CARL E. REICHARDT * JOHN C. SAWHILL * ALAN SEELENFREUND * BARRY LAWSON WILLIAMS
* By GARY P. ENCINAS --------------------------------- (Gary P. Encinas, Attorney-in-Fact) 56 63 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and the Board of Directors of Pacific Gas and Electric Company: We have audited in accordance with generally accepted auditing standards, the consolidated financial statements and the schedule of consolidated segment information included in the Pacific Gas and Electric Company Annual Report to Shareholders incorporated by reference in this Annual Report on Form 10-K and have issued our report thereon dated February 6, 1995. Our report on the 1994 consolidated financial statements includes an explanatory paragraph that describes the uncertainties regarding the ultimate outcome of the electric industry restructuring, as discussed in note 2 to the consolidated financial statements. In addition, our report includes an explanatory paragraph indicating that, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits other than pensions and for income taxes as discussed in notes 1 and 9 to the consolidated financial statements. Our audits of the consolidated financial statements and the schedule of consolidated segment information were made for the purpose of forming an opinion on those statements taken as a whole. The supplemental schedule listed in Part IV, Item 14. (a)(3) of this Annual Report on Form 10-K is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the consolidated financial statements. The supplemental schedule has been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and the schedule of consolidated segment information and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements and schedule of consolidated segment information taken as a whole. ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP San Francisco, California February 6, 1995 57 64 SCHEDULE II PACIFIC GAS AND ELECTRIC COMPANY SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
COLUMN C COLUMN B ADDITIONS BALANCE ------------------- COLUMN E AT CHARGED BALANCE BEGINNING TO COSTS CHARGED COLUMN D AT COLUMN A OF AND TO OTHER DEDUC- END OF DESCRIPTION PERIOD EXPENSES ACCOUNTS TIONS PERIOD ------------------ (IN THOUSANDS)------------------- VALUATION AND QUALIFYING ACCOUNTS DEDUCTED FROM ASSETS: 1994: Reserve for impairment of oil and gas properties........................... $ 7,924 $ 4,565 $ -- $ 8,148 (3) $ 4,341 ========= ======== ======== ========= ========= Reserve for deferred project costs...... $18,689 $ 7,111 $ -- $ -- $25,800 ========= ======== ======== ========= ========= Allowance for uncollectible accounts.... $23,647 $14,010 $ -- $ 7,888 (5) $29,769 ========= ======== ======== ========= ========= Reserve for land costs.................. $ 6,154 $ -- $ -- $ 194 $ 5,960 ========= ======== ======== ========= ========= 1993: Reserve for investment in Alaska Natural Gas Transportation System............ $152,517 $ -- $ -- $152,517(1) $ 0 ========= ======== ======== ========= ========= Reserve for impairment of oil and gas properties........................... $10,417 $ 7,165 $ -- $ 9,658 (3) $ 7,924 ========= ======== ======== ========= ========= Reserve for deferred project costs...... $ 9,207 $11,086 $ -- $ 1,604 (4) $18,689 ========= ======== ======== ========= ========= Allowance for uncollectible accounts.... $23,806 $ 1,907 $ -- $ 2,066 (5) $23,647 ========= ======== ======== ========= ========= Reserve for land costs.................. $ 1,724 $ 4,749 $ -- $ 319 $ 6,154 ========= ======== ======== ========= ========= 1992: Reserve for investment in Alaska Natural Gas Transportation System............ $132,893 $19,624 $ -- $ -- $152,517(2) ========= ======== ======== ========= ========= Reserve for impairment of oil and gas properties........................... $10,835 $ 4,857 $ -- $ 5,275 (3) $10,417 ========= ======== ======== ========= ========= Reserve for deferred project costs...... $ 4,627 $ 4,580 $ -- $ -- $ 9,207 ========= ======== ======== ========= ========= Allowance for uncollectible accounts.... $16,677 $13,664 $ -- $ 6,535 (5) $23,806 ========= ======== ======== ========= ========= Reserve for land costs.................. $ 1,724 $ -- $ -- $ -- $ 1,724 ========= ======== ======== ========= =========
- --------------- (1) Company disposed of its investment in Alaska Natural Gas Transportation System in January 1993. (2) Construction on the gas transportation system was discontinued in 1983. The Company accrued and reserved AFUDC through January 1993, at which time the Company's subsidiary that was a partner in the partnership organized to build and operate the gas transportation system withdrew from that partnership. (3) Deductions consist principally of write-offs of expired leaseholds on reserved property. (4) Primarily due to development cost for power projects. (5) Deductions consist principally of write-offs, net of collections of receivables considered uncollectible. 58 65 ================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 EXHIBITS TO FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1994 ------------------ PACIFIC GAS AND ELECTRIC COMPANY ------------------ ================================================================================ 66 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION OF EXHIBITS - ------- ------------------------------------------------------------------------------------ 3.1 Restated Articles of Incorporation effective as of July 26, 1994 (Form 10-Q for quarter ended June 30, 1994 (File No. 1-2348), Exhibit 3.1). 3.2 By-Laws dated January 1, 1995. 4. First and Refunding Mortgage dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (Registration No. 2-1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2). 10.1 Firm Transportation Service Agreement between the Company and Pacific Gas Transmission Company dated October 26, 1993 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.4), rate schedule FTS-1, and general terms and conditions. 10.2 Transportation Service Agreement as Amended and Restated Between the Company and El Paso Natural Gas Company dated November 1, 1993 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.5), rate schedule T-3, and general terms and conditions. 10.3 Diablo Canyon Settlement Agreement dated June 24, 1988 (Form 8-K dated June 27, 1988) (File No. 1-2348), Exhibit 10.1), Implementing Agreement dated July 15, 1988 (Form 10-Q for the quarter ended June 30, 1988 (File No. 1-2348), Exhibit 10.1) and portions of the California Public Utilities Commission Decision No. 88-12-083, dated December 19, 1988, interpreting the Settlement Agreement (Form 10-K for fiscal year 1988 (File No. 1-2348), Exhibit 10.4). *10.4 Pacific Gas and Electric Company Deferred Compensation Plan for Directors (Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit 10.5). *10.5 Pacific Gas and Electric Company Deferred Compensation Plan for Officers (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.6). *10.6 Savings Fund Plan for Employees of Pacific Gas and Electric Company applicable to non-union employees, as amended September 21, 1994, effective April 1, 1995. *10.7 Performance Incentive Plan of Pacific Gas and Electric Company (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.10). *10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union employees, as amended September 21, 1994, effective January 1, 1995. *10.9 Pacific Gas and Electric Company Supplemental Executive Retirement Plan, as amended through October 16, 1991 (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.11). *10.10 Pacific Gas and Electric Company Stock Option Plan, as amended effective as of September 16, 1992 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.13). *10.11 Pacific Gas and Electric Company Performance Unit Plan (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.13). *10.12 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16). *10.13 Pacific Gas and Electric Company Executive Flexible Perquisites Program (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16). *10.14 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16). *10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee Directors (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.18). *10.16 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan for Directors, Deferred Compensation Plan for Officers, Supplemental Executive Retirement Plan and Retirement Plan for Non-Employee Directors (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.19). *10.17 Pacific Gas and Electric Company Long-Term Incentive Program (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.21).
67 INDEX TO EXHIBITS--(CONTINUED)
EXHIBIT NUMBER DESCRIPTION OF EXHIBITS - ------- ------------------------------------------------------------------------------------ 11. Computation of Earnings Per Common Share (Form 8-K dated March 2, 1995 (File No. 1-2348), Exhibit 11). 12.1 Restated Computation of Ratios of Earnings to Fixed Charges. 12.2 Restated Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends. 13. 1994 Annual Report to Shareholders (portions of the 1994 Annual Report to Shareholders under the headings "Selected Financial Data," "Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition," "Report of Independent Public Accountants," "Statement of Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of Consolidated Common Stock Equity and Preferred Stock," "Statement of Consolidated Capitalization," "Schedule of Consolidated Segment Information," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data," included only) (except for those portions which are expressly incorporated herein by reference, such 1994 Annual Report to Shareholders is furnished for the information of the Commission and is not deemed to be "filed" herein). 21. Subsidiaries of the Company (not included because the Company's subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a "significant subsidiary" under Rule 1-02(v) of Regulation S-X as of the end of the year covered by this report). 23. Consent of Arthur Andersen LLP. 24.1 Resolution of the Board of Directors authorizing the execution of the Form 10-K. 24.2 Powers of Attorney. 27. Financial Data Schedule (Form 8-K dated March 2, 1995 (File No. 102348), Exhibit 27). 99. Information required by Form 11-K with respect to the Savings Fund Plan for Employees of Pacific Gas and Electric Company, as permitted by Rule 15d-21.
- --------------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K. EX-3.2 2 BY-LAWS DATED JANUARY 1, 1995 1 EXHIBIT 3.2 BYLAWS OF PACIFIC GAS AND ELECTRIC COMPANY AS AMENDED JANUARY 1, 1995 ARTICLE I. SHAREHOLDERS. 1. PLACE OF MEETING. All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place within the State of California as may be designated by the Board of Directors. 2. ANNUAL MEETINGS. The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors. Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders. Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation. 3. SPECIAL MEETINGS. Special meetings of the shareholders shall be called by the Secretary or an Assistant Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, or the President. Special meetings of the shareholders shall also be called by the Secretary or an Assistant Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President or the Secretary. A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request. [1] 2 4. ATTENDANCE AT MEETINGS. At any meeting of the shareholders, each holder of record of stock entitled to vote thereat may attend in person or may designate an agent or a reasonable number of agents, not to exceed three to attend the meeting and cast votes for his shares. The authority of agents must be evidenced by a written proxy signed by the shareholder designating the agents authorized to attend the meeting and be delivered to the Secretary of the Corporation prior to the commencement of the meeting. 5. NO CUMULATIVE VOTING. No shareholder of the Corporation shall be entitled to cumulate his or her voting power. ARTICLE II. DIRECTORS. 1. NUMBER. The Board of Directors shall consist of seventeen (17) directors. 2. POWERS. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. EXECUTIVE COMMITTEE. There shall be an Executive Committee of the Board of Directors consisting of the Chairman of the Committee, the Chairman of the Board, if these offices be filled, the President, and four Directors who are not officers of the Corporation. The members of the Committee shall be elected, and may at any time be removed, by a two-thirds vote of the whole Board. The Executive Committee, subject to the provisions of law, may exercise any of the powers and perform any of the duties of the Board of Directors; but the Board may by an affirmative vote of a majority of its members withdraw or limit any of the powers of the Executive Committee. The Executive Committee, by a vote of a majority of its members, shall fix its own time and place of meeting, and shall prescribe its own rules of procedure. A quorum of the Committee for the transaction of business shall consist of three members. 4. TIME AND PLACE OF DIRECTORS' MEETINGS. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 5. SPECIAL MEETINGS. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Secretary. Such notice shall be delivered personally or by telephone to each Director at least four hours in advance of such meeting, or sent by first-class mail or telegram, postage prepaid, at least two days in advance of such meeting. 6. QUORUM. A quorum for the transaction of business at any meeting of the Board of Directors shall consist of six members. [2] 3 7. ACTION BY CONSENT. Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. 8. MEETINGS BY CONFERENCE TELEPHONE. Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another. ARTICLE III. OFFICERS. 1. OFFICERS. The officers of the Corporation shall be a Chairman of the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee (whenever the Board of Directors in its discretion fills these offices), a President, one or more Vice Presidents, a Secretary and one or more Assistant Secretaries, a Treasurer and one or more Assistant Treasurers, a General Counsel, a General Attorney (whenever the Board of Directors in its discretion fills this office), and a Controller, all of whom shall be elected by the Board of Directors. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, and the President shall be members of the Board of Directors. 2. CHAIRMAN OF THE BOARD. The Chairman of the Board, if that office be filled, shall preside at all meetings of the shareholders, of the Directors, and of the Executive Committee in the absence of the Chairman of that Committee. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. He shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and in the absence or disability of the President, shall exercise his duties and responsibilities. 3. VICE CHAIRMAN OF THE BOARD. The Vice Chairman of the Board, if that office be filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. In the absence of the Chairman of the Board, he shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, he shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 4. CHAIRMAN OF THE EXECUTIVE COMMITTEE. The Chairman of the Executive Committee, if that office be filled, shall preside at all meetings of the Executive Committee. He shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws. 5. PRESIDENT. The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. If there be no Chairman of the Board, the President shall also exercise the duties and responsibilities of that office. The President [3] 4 shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 6. VICE PRESIDENTS. Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each Vice President's authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President may confer a special title upon any Vice President. 7. SECRETARY. The Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and he shall record the minutes of all proceedings in books to be kept for that purpose. He shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. He shall give, or cause to be given, all notices required either by law or the Bylaws. He shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by his signature. The Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Secretary. In the absence or disability of the Secretary, his duties shall be performed by an Assistant Secretary. 8. TREASURER. The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. He shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board of Directors. He shall disburse such funds of the Corporation as have been duly approved for disbursement. The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Treasurer shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Treasurer. In the absence or disability of the Treasurer, his duties shall be performed by an Assistant Treasurer. 9. GENERAL COUNSEL. The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. He shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. He shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation. The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. [4] 5 10. CONTROLLER. The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and he shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. He shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them. The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. ARTICLE IV. MISCELLANEOUS. 1. RECORD DATE. The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be. 2. TRANSFERS OF STOCK. Upon surrender to the Secretary or Transfer Agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, and payment of transfer taxes, the Corporation shall issue a new certificate to the person entitled thereto, cancel the old certificate, and record the transaction upon its books. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers. 3. LOST CERTIFICATES. Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Secretary of the Corporation, before a new certificate may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed. 4. EMPLOYEE'S STOCK PURCHASE PLAN. Subject to any limitation contained in the Articles of Incorporation, the Board of Directors may in its discretion, from time to time, authorize the issue and sale of shares of capital stock of this Corporation to employees, pursuant to an employee's stock purchase plan, for such consideration as the Board shall determine to be reasonable. Such plan may provide for payment for such shares by installments over a period of time fixed by the Board. In any [5] 6 such plan, the Board may provide for interest on any installment payments, and that an employee may cancel his agreement to purchase all or part of the shares thereunder. The Board may fix such other terms and conditions for any such plan as it shall deem, in its discretion, to be in the best interests of this Corporation. Any such plan may include employees of: This Corporation's subsidiaries and affiliates; Pacific Service Employees Association; Pacific Service Employees Credit Union; and such other associated organizations as may be approved by the Board. ARTICLE V. AMENDMENTS. 1. AMENDMENT BY SHAREHOLDERS. Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders. 2. AMENDMENT BY DIRECTORS. To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors. [6] EX-10.1 3 PGT RATE SCHEDULE FTS-1 AND GENERAL TERMS 1 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 12 First Revised Volume No. 1-A Superseding Original Sheet No. 12 EXHIBIT 10.1 RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE 1. AVAILABILITY This rate schedule is available to any party (hereinafter called "Shipper") qualifying for service pursuant to the Commission's Regulations contained in 18 CFR Part 284, and who has executed a Firm Transportation Service Agreement with PGT in the form contained in this FERC Gas Tariff First Revised Volume No. 1-A. 2. APPLICABILITY AND CHARACTER OF SERVICE This rate schedule shall apply to firm gas transportation services performed by PGT for Shipper pursuant to the executed Firm Transportation Service Agreement between PGT and Shipper. PGT shall receive from Shipper such daily quantities of gas up to the Shipper's Maximum Daily Quantity as specified in the executed Firm Transportation Service Agreement between PGT and Shipper plus the required quantity of gas for fuel and line loss associated with service under this Rate Schedule FTS-1 and redeliver an amount equal to the quantity received less the required quantity of gas for fuel and line loss. This transportation service shall be firm and not subject to curtailment or interruption except as provided in the Transportation General Terms and Conditions. Firm transportation service shall be subject to all provisions of the executed Firm Transportation Service Agreement between PGT and Shipper and the applicable Transportation General Terms and Conditions. 3. RATES Shipper shall pay PGT each month the sum of the Reservation Charge, applicable Reservation Surcharge, the Firm Transportation Charge and other applicable surcharges for the quantities of natural gas delivered. The rate(s) and the Maximum Daily Quantity set forth in PGT's current Statement of Effective Rates and Charges for Transportation of Natural Gas in this FERC Gas Tariff First Revised Volume No. 1-A are applied to transportation service rendered under this rate schedule. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: JULY 29,1994 Effective: SEPTEMBER 01, 1994 2 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 13 First Revised Volume No. 1-A Superseding Original Sheet No. 13 RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3. RATES (Continued) 3.1 Reservation Charge The monthly Reservation Charge shall be the currently effective rate times the distance, in pipeline miles, from the point(s) of receipt to the point(s) of delivery times the Shipper's Maximum Daily Quantity delivered. 3.2 Reservation Surcharge Shippers converting to firm transportation under Rate Schedule FTS-1 from Rate Schedules T-2 or T-3 of PGT's Second Revised Volume No. 1 tariff shall pay a Reservation Surcharge. The Reservation Surcharge shall be calculated in the following manner: The currently effective T-2 or T-3 Reservation Surcharge Rate times the distance, in pipeline miles, from the point(s) of receipt to the point(s) of delivery times the Shipper's Maximum Daily Quantity delivered. The Reservation Surcharge Rates are stated on the Statement of Effective Rates and Charges of PGT's First Revised Volume No. 1-A tariff. Shipper's obligation to pay the Reservation Charge and applicable Reservation Surcharge is independent of Shipper's ability to obtain export authorization from the National Energy Board of Canada, Canadian provincial removal authority, and/or import authorization from the United States Department of Energy, and shall begin with the execution of the Firm Transportation Service Agreement by both parties. The Reservation Charge and Reservation Surcharge due and payable shall be computed beginning in the month in which service is first available (prorated if beginning in the month in which service is available on a date other than the first day of the month). Thereafter, the monthly Reservation Charge and Reservation Surcharge shall be due and payable each month during the Initial (and Subsequent) Term(s) of the Shipper's executed Firm Transportation Service Agreement and is unaffected by the quantity of gas transported by PGT to Shipper's delivery point(s) in any month except as provided for in Paragraphs 3.10 and 3.11 of this rate schedule. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: JULY 29,1994 EFfective: SEPTEMBER 01,1994 3 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 14 First Revised Volume No. 1-A Superseding Original Sheet No. 14 RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3. RATES (Continued) 3.3 Firm Transportation Charge The monthly Firm Transportation Charge shall be the product of the following: (a) The quantities of gas (excluding Authorized Overruns) delivered during the month (MMBtu); (b) An amount no less than the Minimum Delivery Rate, nor greater than the Maximum Delivery Rate set forth in the Statement of Effective Rates and Charges for Transportation of Natural Gas in this FERC Gas Tariff First Revised Volume No. 1-A; and (c) The distance, in pipeline miles, from the point(s) of receipt to the point(s) of delivery. 3.4 Delivery Rate Surcharge Shippers converting from Rate Schedules T-2 or T-3 of PGT's Second Revised Volume No. 1 tariff shall receive a credit calculated as the product of the applicable Delivery Rate Surcharge, the quantities of gas delivered during the month and the distance, in pipeline miles, from the point(s) of receipt to the point(s) of delivery. The Delivery Rate Surcharges are stated on the Statement of Effective Rates and Charges of PGT's First Revised Volume No. 1-A Tariff. 3.5 Shipper shall pay the Maximum Monthly Reservation Charge, applicable Reservation Surcharge, and the Maximum Delivery Rate for service under this rate schedule unless PGT offers to discount the Monthly Reservation Charge, Reservation Surcharge or the Delivery Rate or all to Shipper under this rate schedule. If PGT elects to discount the Monthly Reservation Charge, Reservation Surcharge or the Delivery Rate or all, PGT shall, up to forty-eight (48) hours prior to such discount, by written notice, advise Shipper of the effective date of such charges and the quantity of gas so affected; provided, however, such discount shall not be anticompetitive or unduly discriminatory between individual shippers. The rates for service under this rate schedule shall not be discounted below the Minimum Monthly Reservation Charge, the Minimum Delivery Rate, and applicable GSR and ACA Surcharges. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: JULY 29, 1994 Effective: SEPTEMBER 01, 1994 4 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 15 First Revised Volume No. 1-A Superseding Original Sheet No. 15 RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3. RATES (Continued) 3.6 Gas Supply Restructuring (GSR) Transition Cost Surcharge Shipper shall pay a GSR Transition Cost Surcharge for PGT's approved GSR costs as defined in Paragraph 30 of the Transportation General Terms and Conditions. This surcharge is stated on the Statement of Effective Rates and Charges and is defined in Paragraph 30 of the Transportation General Terms and Conditions. The surcharge shall be the product of the surcharge rate, the quantities of gas delivered during the month and the distance in pipeline miles from the point(s) of receipt to the point(s) of delivery. This surcharge shall not apply to those Shippers converting to firm transportation under this rate schedule from Rate Schedules T-2 or T-3 of PGT's Second Revised Volume No. 1 and which are Supporting Parties to the FERC-approved settlement in Docket No. RS92-46-000 for as long as these services are charged incremental rates. T-1 Shippers are also exempt from this surcharge, with the exception of Washington Natural Gas Company, per the provisions of Paragraph 30.5(d). 3.7 Backhauls or upstream deliveries shall be subject to the same charges as forward haul or downstream transportation arrangements except that no gas shall be retained by PGT for compressor station fuel, line loss and other unaccounted-for gas. 3.8 Direct Bills PG&E shall pay a Direct Bill for 100% of the costs allocated to the Direct Bill portion of Approved Gas Supply Restructuring (GSR) Costs excluding the amount to be collected from the Northwest Shippers as defined in Paragraph 30 of the Transportation General Terms and Conditions and credited against the Direct Bill portion of Approved GSR Costs as defined in Paragraph 30 of the Transportation General Terms and Conditions. PG&E may select one of three payment plans as shown on the Statement of Rates and Charges for Transportation of Natural Gas. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: DECEMBER 10, 1993 Effective: NOVEMBER 15, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-24-000OP , dated NOVEMBER 12, 1993 5 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 16 First Revised Volume No. 1-A RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3. RATES (Continued) 3.9 Capacity Release (a) Releasing Shippers: Shipper shall have the option to release capacity pursuant to the provisions of PGT's capacity release program as specified in the Transportation General Terms and Conditions. Shipper may release its capacity, up to Shipper's Maximum Daily Quantity under this rate schedule, in accordance with the provisions of Paragraph 28 of PGT's Transportation General Terms and Conditions of this FERC Gas Tariff, First Revised Volume No. 1-A. Shipper shall pay a fee associated with the marketing of capacity by PGT (if applicable) in accordance with Paragraph 28 of the Transportation General Terms and Conditions. This fee shall be negotiated between PGT and the Releasing Shipper. (b) Replacement Shippers: Shipper may receive released capacity service under this rate schedule pursuant to Paragraph 28 of the Transportation General Terms and Conditions and is required to execute a service agreement in the form contained for capacity release under Rate Schedule FTS-1 in this First Revised Volume No. 1-A. Shipper shall pay PGT each month the rates for transportation service under this rate schedule and as set forth in PGT's current Statement of Effective Rates and Charges in this First Revised Volume No. 1-A. The rates to be paid shall be the sum of the Reservation Charge, any applicable Reservation Surcharge and GSR Transition Cost Surcharge, Delivery Rate and other applicable surcharges or penalties. The rates paid by Shipper receiving capacity release transportation service shall be adjusted as provided on Exhibit R in the executed Transportation Service Agreement For Capacity Release between PGT and Shipper. Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 6 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 16A First Revised Volume No. 1-A RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 3.10 Reservation Charge Credit - Malin Primary Delivery Point If PGT fails to deliver to Malin, Oregon ninety-five percent (95%) or more of the aggregate Confirmed Daily Nominations (as hereinafter defined) of all Shippers with a Malin primary delivery point receiving service under this rate schedule (hereinafter referred to as the "Non-Deficiency Amount") for more than twenty-five (25) days in any given Contract Year, then for each day during that Contract Year in excess of twenty-five (25) days that PGT so fails to deliver the Non- Deficiency Amount (a "Credit Day") Shipper, as its sole remedy, shall be entitled to a Reservation Charge Credit calculated in the manner hereinafter set forth. For the purpose of this Paragraph 3.10, Confirmed Daily Nomination shall mean for any day, the lesser of (1) Shipper's Maximum Daily Quantity or (2) the actual quantity of gas that the connecting pipeline upstream of PGT is capable of delivering for Shipper's account to PGT at Shipper's primary point of receipt(s) on PGT less Shipper's requirement to provide compressor fuel and line losses under the Statement of Effective Rates and Charges of PGT's FERC Gas Tariff, First Revised Volume No. 1-A or (3) the quantity of gas that Pacific Gas And Electric Company (PG&E) is capable of accepting at Malin for Shipper's account or (4) Shipper's nomination to PGT. The Reservation Charge Credit for each Credit Day for a particular Shipper shall be equal to the product obtained by multiplying (i) that Shipper's Reservation Charge divided by 30.4 times (ii) that Shipper's Confirmed Daily Nomination for that Credit Day less the actual quantity of gas delivered by PGT to PG&E at Malin for Shipper's account for that Credit Day. Except as provided for in Paragraph 3.11 of this rate schedule, this Reservation Charge Credit is Shipper's sole remedy for nondelivery of gas by PGT. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 7 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 16B First Revised Volume No. 1-A RATE SCHEDULE FTS -1 FIRM TRANSPORTATION SERVICE (Continued) 3.11 Reservation Charge Credit - Other than Malin Primary Delivery Point If PGT fails to deliver to a primary delivery point on its system other than Malin, Oregon, ninety-five percent (95%) or more of the aggregate Confirmed Daily Nominations (as hereinafter defined) of all Shippers at such primary delivery point other than Malin receiving service under this rate schedule (hereinafter referred to as the "Non-Deficiency Amount") for more than twenty-five (25) days in any given Contract Year, then for each day during that Contract Year in excess of twenty-five (25) days that PGT so fails to deliver the Non-Deficiency Amount (a "Credit Day") Shipper, as its sole remedy, shall be entitled to a Reservation Charge Credit calculated in the manner hereinafter set forth. For the purpose of this Paragraph 3.11, Confirmed Daily Nomination shall mean for any day, the lesser of (1) Shipper's Maximum Daily Quantity or (2) the quantity of gas that the connecting downstream pipeline(s), local distribution company pipeline(s), or end-user(s) is/are capable of accepting for Shipper's account at Shipper's point(s) of primary delivery on PGT or (3) the quantity of gas that the connecting pipeline upstream of PGT is capable of delivering to PGT for Shipper's account to PGT at Shipper's primary point of receipt(s) on PGT less Shipper's requirement to provide compressor fuel and line losses under the Statement of Effective Rates and Charges of PGT's FERC Gas Tariff, First Revised Volume No. 1-A or (4) Shipper's nomination to PGT. The Reservation Charge Credit for each Credit Day for a particular Shipper shall be equal to the product obtained by multiplying (i) that Shipper's Reservation Charge divided by 30.4 times (ii) that Shipper's Confirmed Daily Nomination for that Credit Day less the actual quantity of gas delivered by PGT to a Shipper's primary delivery point(s) (other than Malin) for Shipper's account for that Credit Day. Except as provided for in Paragraph 3.10 of this rate schedule, this Reservation Charge Credit is Shipper's sole remedy for nondelivery of gas by PGT. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 8 Pacific Gas Transmission Company FERC Gas Tariff Substitute Second Revised Sheet No. 17 First Revised Volume No. 1-A Superseding First Revised Sheet No. 17 RATE SCHEDULE FTS-1 FIRM TRANSPORTATION SERVICE (Continued) 4. AUTHORIZED OVERRUNS Quantities in excess of Shipper's MDQ shall be transported when capacity is available on the PGT system and when the provision of such Authorized Overruns shall not affect any Shipper's rights on the PGT system. Authorized Overruns are interruptible in nature. The rate charged shall be the rates and charges as specified in the current Statement of Effective Rates and Charges for Transportation of Natural Gas of this First Revised Volume No. 1-A, and such Authorized Overruns shall be subject to the priority of service provisions of Paragraph 19 of the Transportation General Terms and Conditions. Revenues derived from Authorized Overruns shall be deemed to be interruptible revenues and credited in accordance with Paragraph 35 of the Transportation General Terms and Conditions. 5. FUEL AND LINE LOSS Shipper shall furnish to PGT quantities of gas for compressor station fuel, line loss and other utility purposes, plus other unaccounted for gas used in the operation of PGT's combined pipeline system between the International Boundary near Kingsgate, British Columbia and the Oregon-California boundary for the transportation quantities of gas delivered by PGT to Shipper, based upon the effective fuel and line loss percentages in accordance with Paragraph 37 of the General Terms and Conditions. 6. TRANSPORTATION GENERAL TERMS AND CONDITIONS All of the Transportation General Terms and Conditions are applicable to this rate schedule, unless otherwise stated in the executed Firm Transportation Service Agreement between PGT and Shipper. Any future modifications, additions or deletions to said Transportation General Terms and Conditions, unless otherwise provided, are applicable to firm transportation service rendered under this rate schedule, and by this reference, are made a part hereof. Issued by: P.G.Rosput, Senior Vice President Issued on: JULY 29, 1994 Effective: SEPTEMBER 01, 1994 9 Pacific Gas Transmission Company FERC Gas Tariff Fifth Revised Sheet No. 4 First Revised Volume No. 1-A Superseding Fourth Revised Sheet No. 4 STATEMENT OF EFFECTIVE RATES AND CHARGES FOR TRANSPORTATION OF NATURAL GAS (a) ($/MMBtu)
Rate Schedule Base Tariff Rates GSR (h) GRI (b) FERC (c) and Type of Charge (f) Minimum Maximum Surcharge Adjustment Annual Charge Load Factor High Low FTS-1 Firm Transportation Service (e) Reservation Charge 0.000000 0.006929 ---- 0.218 0.134 ---- Reservation Surcharge for (g): T-2 Converting Shippers 0.000000 0.005968 ---- ---- ---- ---- T-3 Converting Shippers 0.000000 0.016639 ---- ---- ---- ---- Delivery Rate 0.000031 0.000031 0.000194 0.0085 0.0085 0.0024 Delivery Rate Surcharge for: T-2 Converting Shippers 0.000000 (0.000004) ---- ---- ---- ---- T-3 Converting Shippers 0.000000 (0.000029) ---- ---- ---- ---- Authorized Overruns 0.000015 0.000473 0.000194 0.0085 0.0085 0.0024 ITS-1 Interruptible Transportation Service (d) 0.000015 0.000473 0.000194 0.0085 0.0085 0.0024 Backhaul Service 0.000015 0.000473 0.000194 0.0085 0.0085 0.0024
NOTES: (a) The Base Tariff Rates and Gas Supply Restructuring (GSR) Surcharge are applied per pipeline mile, to gas transported by PGT for delivery to Shipper. The pipeline mileage distance shall be measured from the point of receipt by PGT to Shipper-designated point of delivery. Consult PGT system map on Sheet 3 for delivery points and milepost designations. The rates posted on this Statement of Effective Rates and Charges for Transportation of Natural Gas consist entirely of transportation-related cost components. These rates do not include any storage or gathering charges. Issued by: P.G.Rosput, Senior Vice President Issued on: SEPTEMBER 01, 1994 Effective: OCTOBER 01, 1994 10 Pacific Gas Transmission Company FERC Gas Tariff Sixth Revised Sheet No. 5 First Revised Volume No. 1-A Superseding Fifth Revised Sheet No. 5 STATEMENT OF EFFECTIVE RATES AND CHARGES FOR TRANSPORTATION OF NATURAL GAS (a) ($/MMBtu) (Continued) Notes (Continued) (b) In accordance with Paragraph 2 of the Transportation General Terms and Conditions of this FERC Gas Tariff First Revised Volume No. 1-A, all Shippers that are not members of GRI shall pay a GRI funding unit adjustment as set forth on effective Sheet No. 4. This adjustment shall be in addition to the Base Tariff Rate(s) specified above. (c) In accordance with Paragraph 22 of the Transportation General Terms and Conditions of this FERC Gas Tariff First Revised Volume No. 1-A, all Shippers shall pay an ACA unit adjustment of $0.0024 per MMBtu. This adjustment shall be in addition to the Base Tariff Rate(s) specified above. (d) The maximum ITS-1 transportation charges calculated from the product of the rates above and the pipeline mileage distances for the following routes are: Kingsgate, B.C. to Spokane, WA 0.051221/MMBtu Kingsgate, B.C. to Stanfield, OR 0.131196/MMBtu Kingsgate, B.C. to Malin, OR 0.289694/MMBtu
(e) For Shippers who release capacity either through a primary release or a secondary release, a marketing of capacity fee may be added (if applicable) to the otherwise applicable rates and charges pursuant to Paragraph 28 of the Transportation General Terms and Conditions of this FERC Gas Tariff First Revised Volume No. 1-A. (f) Fuel Use: Shipper shall furnish gas used for compressor station fuel, line loss, and other utility purposes, plus other unaccounted-for gas used in the operation of PGT's combined pipeline system in an amount equal to the sum of the current fuel and line loss percentage and the fuel and line loss percentage surcharge in accordance with Paragraph 37 of this tariff, multiplied by the distance in pipeline miles transported from the receipt point to the delivery point multiplied by the transportation quantities of gas delivered to Shipper under these rate schedules. The current fuel and line loss percentage shall be adjusted each month between the maximum rate of 0.0041% per MMBtu per pipeline mile and the minimum rate of 0.0000% per MMBtu per mile. The fuel and line loss percentage surcharge is 0.0008% per MMBtu per pipeline mile. No fuel use charges will be assessed for backhaul service. (g) Shippers who convert from Section 7(c) service under Rate Schedules T-2 or T-3 to Part 284 service under Rate Schedule FTS-1 shall pay monthly Reservation Surcharges as provided in Paragraph 3.4 of Rate Schedule FTS-1. (h) Gas Supply Restructuring (GSR) Transition Cost Surcharge shall apply pursuant to the provisions of Paragraph 30 of the Transportation General Terms and Conditions and Paragraph 3.6 of Rate Schedule FTS-1 and Paragraph 3.3 of Rate Schedule ITS-1. Washington Natural Gas Company shall pay a GSR surcharge of $0.000089 per MMBtu-mile. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: DECEMBER 01, 1994 Effective: JANUARY 01, 1995 11 Pacific Gas Transmission Company FERC Gas Tariff Fourth Revised Sheet No. 51 First Revised Volume No. 1-A Superseding Third Revised Sheet No. 51 TRANSPORTATION GENERAL TERMS AND CONDITIONS TABLE OF CONTENTS
Paragraph No. Provision Sheet No. 1 Definitions 52 2 Gas Research Institute Charge Adjustment Provision 55 3 Quality of Gas 56 4 Measuring Equipment 58 5 Measurements 60 6 Inspection of Equipment and Records 61 7 Billing 61 8 Payment 62 9 Notice of Changes in Operating Conditions 63 10 Force Majeure 63 11 Warranty of Eligibility for Transportation 64 12 Possession of Gas and Responsibility 64 13 Indemnification 65 14 Arbitration 65 15 Governmental Regulations 66 16 Miscellaneous Provision 66 17 Transportation Service Agreement 66 18 Scheduling of Receipts and Deliveries 67 19 Operating Provisions for Interruptible Transportation Service 69 20 Operating Provisions for Firm Transportation Service 70 21 Operating Provisions for Interruptible and Firm Transportation Service 72 22 Annual Charge Adjustment (ACA) Provision 85 23 Shared Operating Personnel and Facilities 85 24 Complaint Procedures 86 25 Information Concerning Availability and Pricing of Transportation Service and Capacity for Transportation 87 26 Market Centers 88 27 Planned PGT Capacity Curtailments and Interruptions 88 28 Capacity Release 89 29 Flexible Receipt and Delivery Points 119 30 Gas Supply Restructuring Transition Costs 123 31 Former Buyer's Obligation for Unrecovered Account No. 191 Amounts 127 32 Equality of Transportation Service 129 33 Right of First Refusal Upon Termination of Firm Shipper's Service Agreement 130 34 Electronic Bulletin Board 132 35 Crediting of Interruptible Transportation Revenues 137 36 Capacity Relinquishment 139 37 Fuel, Line Loss and Other Unaccounted For Gas Adjustment 140 38 Crediting of Parking and Authorized Imbalance Revenues 142 39 Sales of Excess Gas 143 (Continued)
Issued by: P.G.Rosput, Senior Vice President Issued on: APRIL 08, 1994 Effective: APRIL 22, 1994 12 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 52 First Revised Volume No. 1-A Superseding Original Sheet No. 52 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 1. DEFINITIONS 1.1 The word "day" shall mean a period of twenty-four (24) consecutive hours, beginning and ending at 7:00 o'clock a.m. Pacific Standard Time or such other time as Shipper and PGT may agree upon. 1.2 The word "month" shall mean a period extending from the beginning of the first day in a calendar month to the beginning of the first day in the next succeeding calendar month. 1.3 The term "Maximum Daily Quantity" (MDQ) shall mean the maximum daily quantity in MMBtu of gas which PGT agrees to deliver exclusive of an allowance for compressor station fuel, line loss and other unaccounted for gas and transport for the account of Shipper to Shipper's point(s) of delivery on each day during each year during the term of Shipper's Transportation Service Agreement with PGT. 1.4 The term "marketing affiliate" shall mean Pacific Gas and Electric Company. 1.5 The word "gas" shall mean natural gas. 1.6 The term "cubic foot of gas" shall mean that quantity of gas which, at a temperature of sixty degrees (60o) Fahrenheit and at a pressure of 14.73 pounds per square inch absolute, occupies one (1) cubic foot. 1.7 The term "Mcf" shall mean one thousand (1,000) cubic feet of gas and shall be measured as set forth in Paragraph 5 hereof. The term "MMcf" shall mean one million (1,000,000) cubic feet of gas. 1.8 The term "Btu" shall mean British Thermal Unit. The term "MMBtu" shall mean one million (1,000,000) British Thermal Units. 1.9 The term "gross heating value" shall mean the number of Btu's in a cubic foot of gas at a temperature of sixty degrees (60o) Fahrenheit, saturated with water vapor, and at an absolute pressure equivalent to thirty (30) inches of mercury at thirty-two degrees (32o) Fahrenheit. 1.10 The term "psig" shall mean pounds per square inch gauge. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 13 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 53 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 1. DEFINITIONS (Continued) 1.11 Releasing Shipper: A firm transportation Shipper which intends to post its service to be released to a Replacement Shipper, has posted the service for release, or has released its service. 1.12 Replacement Shipper: A Shipper which has contracted to utilize a Releasing Shipper's service for a specified period of time. 1.13 Posting Period: The period of time during which a Releasing Shipper may post, or have posted by the pipeline, all or a part of its service for release to a Replacement Shipper. 1.14 Release Term: The period of time during which a Releasing Shipper intends to release, or has released all or a portion of its contracted quantity of service to a Replacement Shipper. 1.15 Bid Period: The period of time during which a Replacement Shipper may bid to contract for a parcel which has been posted for release by a Releasing Shipper. 1.16 The term "Agent" as defined in connection with PGT's Market Center Service is any party which contracts with PGT for Market Center Service and which itself is not a Shipper on PGT. 1.17 Parcel: The term utilized to describe an amount of capacity, expressed in MMBtu/d, from a specific receipt point to a specific delivery point for a specific period of time which is released and bid on pursuant to the capacity release provisions contained in Paragraph 28 of these Transportation General Terms and Conditions. 1.18 Primary Release: The term used to describe the release of capacity by a Releasing Shipper receiving service under a Part 284 firm transportation rate schedule. 1.19 Secondary Release: The term used to describe the release of capacity by a Replacement Shipper receiving service under a Part 284 firm transportation rate schedule. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 14 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 54 First Revised Volume No. 1-A Superseding Original Sheet No. 54 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 1. DEFINITIONS (Continued) 1.20 Bid Reconciliation Period: The period of time subsequent to the Bid Period during which bids are evaluated by PGT. 1.21 Match Period: The period of time subsequent to the Bid Reconciliation Period and before the notification deadline for awarding capacity for Prearranged Deal C during which the Prearranged Shipper may match any higher bids for the Parcel. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 15 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 55 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 2. GAS RESEARCH INSTITUTE CHARGE ADJUSTMENT PROVISION 2.1 Purpose: PGT has joined with other gas enterprises in the formation of, and participation in, the activities and financing of the Gas Research Institute (GRI), an Illinois Not For Profit corporation. GRI has been organized for the purpose of sponsoring Research, Development and Demonstration (RD&D) programs in the field of natural and manufactured gas for the purpose of assisting all segments of the gas industry in providing adequate, reliable, safe, economic and environmentally acceptable gas service for the benefit of gas consumers and the general public. For the purpose of funding GRI's approved expenditures, this Paragraph 2 establishes a GRI Adjustment Charge to be applicable to PGT's Rate Schedules ITS-1 and FTS-1, in this FERC Gas Tariff First Revised Volume No. 1-A; provided, however, such charge shall not be applicable to Shippers which are interstate pipelines and which include in their rates a charge for RD&D by GRI. 2.2 Basis for the GRI Adjustment Charges: The rate schedule specified in Paragraph 2.1 hereof shall include an increment for a GRI Adjustment Charge for RD&D. Such GRI Adjustment Charge shall be that increment, adjusted to PGT's pressure base and heating value if required, which has been approved by Federal Energy Regulatory Commission Orders approving GRI's RD&D expenditures. The GRI Adjustment Charge shall be reflected in the current Statement of Effective Rates and Charges for Transportation of Natural Gas in this FERC Gas Tariff First Revised Volume No. 1-A. 2.3 Filing Procedure: The notice period and proposed effective date of filings pursuant to this paragraph shall be as permitted under Section 4 of the Natural Gas Act; provided, however, that any such filing shall not become effective unless it becomes effective without suspension or refund obligation. 2.4 Remittance to GRI: PGT shall remit to GRI, not later than fifteen (15) days after the receipt thereof, all monies received by virtue of the GRI Adjustment Charge, less any amounts properly payable to a Federal, State or Local authority relating to the monies received hereunder. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 16 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 55A First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 2. GAS RESEARCH INSTITUTE CHARGE ADJUSTMENT PROVISION (Continued) 2.5 A high load factor Shipper is a Shipper with a load factor greater than fifty (50) percent. A low load factor Shipper is a Shipper with a load factor equal to or less than fifty (50) percent. A Shipper's load factor for each service agreement shall be determined annually using the most recent twelve (12) months of actual throughput available (including throughput using capacity released pursuant to Paragraph 28 of the Transportation General Terms and Conditions). The Shipper's load factor shall remain in effect during the calendar year. In the event twelve (12) months of actual data does not exist, the Shipper's load factor shall be determined monthly based on the latest recorded throughput data. The appropriate GRI demand surcharge is applied monthly until such time as twelve (12) months of actual data is accumulated. At such time the Shipper's load factor shall remain in effect during the calendar year. 2.6 For the purpose of funding GRI's approved expenditures, and subject to the further terms and conditions set forth in the Stipulation and Agreement Concerning the Post-1993 GRI Funding Mechanism and the orders approving such Stipulation and Agreement found at Gas Research Institute, 62 FERC 61,316 (1993) this Paragraph 2 establishes a GRI Funding Unit which shall be collected for quantities of gas transported under PGT's rate schedules provided, however, such charge shall not be applicable to discounted transactions except where the discounted rate is less than the GRI Funding Unit. In this instance PGT shall remit that portion of the GRI Funding Unit actually collected. For purposes of discounted transactions, any GRI Funding Unit shall be considered to be the first component of rates discounted. The GRI Funding Unit may be discounted to zero and shall not be applied to the same quantity of gas more than once. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: JANUARY 10, 1994 Effective: JANUARY 01, 1994 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. TM94-2-86-000, dated DECEMBER 30, 1993 17 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 56 First Revised Volume No. 1-A Superseding Original Sheet No. 56 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. QUALITY OF GAS 3.1 Quality Standards: The gas which Shipper delivers hereunder to PGT for transport (and the gas which PGT transports hereunder for Shipper) shall be merchantable gas at all times complying with the following quality requirements: (a) Heating Value: The gas shall have a gross heating value of not less than nine hundred ninety-five (995) Btus per standard cubic foot on a dry basis, but with the consent of Shipper, PGT may deliver gas at a lower gross heating value. (b) Freedom from Objectionable Matter: The gas: (1) Shall be commercially free from sand, dust, gums, crude oil, impurities and other objectionable substances which may be injurious to pipelines or which may interfere with its transmission through pipelines or its commercial utilization. (2) Shall not have a hydrocarbon dew-point in excess of fifteen degrees (15o) Fahrenheit at pressures up to eight hundred (800) psig. (3) Shall not contain more than one-quarter (1/4) grain of hydrogen sulfide per one hundred (100) standard cubic feet. (4) Shall not contain more than ten(10) grains of total sulphur per one hundred (100) standard cubic feet. (5) Shall not contain more than two percent (2%) by volume of carbon dioxide. (6) Shall not contain more than four (4) pounds of water vapor per one million (1,000,000) standard cubic feet. (7) Shall not exceed one hundred ten degrees (110o) Fahrenheit in temperature at the point of measurement. (8) Shall be as free of oxygen as it can be kept through the exercise of all reasonable precautions, and shall not in any event contain more than four-tenths of one percent (0.4%) by volume of oxygen. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 18 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 57 First Revised Volume No. 1-A Superseding Original Sheet No. 57 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. QUALITY OF GAS (Continued) 3.2 Quality Tests: (a) The quality specifications of the gas received by PGT hereunder shall be determined by tests which PGT shall cause to be made at the International Boundary or such other locations on PGT's system if required accordance with this Paragraph 3.2. (b) The gross heating value of gas delivered hereunder shall be determined from read-outs of continuously operating measuring instruments. The method shall consist of one or more of the following: (1) calorimeter (2) gas chromatograph (3) any other method mutually agreed upon by the parties. Measurement of gross heating value with the calorimeters shall comply with the standards set forth in the American Society for Testing and Materials' ASTM D 1826. Analysis of gas with gas chromatograph shall comply with the standards set forth in ASTM D 1945. Calculation of the gross heating value from compositional analysis by gas chromatography shall comply with the standards set forth in ASTM D 3588. PGT or its agent shall calibrate and maintain the gross heating value measurement device at intervals as agreed upon by PGT and Shipper. Shipper shall have access to PGT's devices and shall be allowed to inspect the devices and all charts or other records of measurement at any reasonable time. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1884 Effective: APRIL 01 1994 19 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 58 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. QUALITY OF GAS (Continued) 3.2 Quality Tests (Continued) (c) Tests shall be made to determine the total sulphur, hydrogen sulfide, carbon dioxide and oxygen content of the gas, by approved standard methods in general use in the gas industry, and to determine the hydrocarbon dew-point and water vapor content of such gas by methods satisfactory to the parties. Tests shall be made frequently enough to ensure that the gas is conforming continuously to the quality requirements. Shipper shall have the right to require PGT to have remedied any deficiency in quality of the gas and, in the event such deficiency is not remedied, the right, in addition to all other remedies available to it by law, to refuse to accept such deficient gas until such deficiency is remedied. 4. MEASURING EQUIPMENT 4.1 Installation: Unless PGT and Shippers agree otherwise, all gas volume measuring equipment, devices and materials at the point(s) of receipt and/or delivery shall be furnished and installed by PGT at Shipper's expense including the tax-on-tax effect. All such equipment, devices and materials shall be owned, maintained and operated by PGT. Shipper may install and operate check measuring equipment provided it does not interfere with the use of PGT's equipment. 4.2 Testing Meter Equipment: The accuracy of either PGT's or Shippers measuring equipment shall be verified by test, using means and methods acceptable to the other party, at intervals mutually agreed upon, and at other times upon request. Notice of the time and nature of each test shall be given by the entity conducting the test to the other entity sufficiently in advance to permit convenient arrangement for the presence of the representative of the other entity. If, after notice, the other entity fails to have a representative present, the results of the test shall nevertheless be considered accurate until the next test. If any of the measuring equipment is found to be registering inaccurately in any percentage, it shall be adjusted at once to read as accurately as possible. All tests of such measuring equipment shall be made at the expense of the entity conducting the same, except that the other entity shall bear the expense of tests made at its request if the inaccuracy is found to be two percent (2%) or less. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 20 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 59 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. MEASURING EQUIPMENT (Continued) 4.3 Correction and Adjustment: If at any time any of the measuring equipment is registering inaccurately by an amount exceeding two percent (2%) at a reading corresponding to the average hourly rate of flow, the previous readings of such equipment shall be corrected to zero error for any period definitely known or agreed upon, or if not so known or agreed upon, one-half (1/2) of the elapsed time since the last test. If the measuring equipment is out-of-service, the volume of gas delivered during such period shall be determined: (a) By using the data recorded by any check measuring equipment accurately registering; or (b) If such check measuring equipment is not registering accurately but the percentage of error is ascertainable by a calibration test, by using the data recorded, corrected to zero error; or (c) If neither of the methods provided in (a) and (b) above can be used, by estimating the quantity delivered, by reference to deliveries under similar conditions during a period when the equipment was registering accurately. No correction shall be made in the recorded volumes of gas delivered hereunder for measuring equipment inaccuracies of two percent (2%) or less, and in no event shall inaccuracies less than 25 Mcf be considered for adjustment. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 21 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 60 First Revised Volume No. 1-A Superseding Original Sheet No. 60 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. MEASUREMENTS 5.1 Metering: The gas shall be metered by one or more orifice, turbine, or displacement-type meters, at the discretion of PGT. When orifice meters are used, they shall be installed and maintained, and volumes shall be measured, in accordance with the methods prescribed in ANSI/API 2530, also published as A.G.A No. 3. When turbine meters are used, they shall be installed and maintained, and volumes shall be measured, in accordance with methods prescribed in AGA Report No. 4 or any subsequent revision. When displacement meters are used, they shall be installed and maintained and quantities shall be measured in accordance with methods prescribed in A.G.A. No. 2, and the number of Mcf delivered hereunder shall be computed by including factors for pressure, temperature and deviation from Boyle's Law. To accurately determine the deviation from Boyle's Law, a quantitative analysis of the gas components shall be made at reasonable intervals with such apparatus as shall be agreed upon by both parties. 5.2 Specific Gravity: The specific gravity of the gas delivered hereunder shall be determined from the read-outs of continuously operating measuring instruments. The method shall consist of one of the following: (a) gravitometer (b) gas chromatography (c) other instruments acceptable to both parties Analysis of chromatograph shall comply with the standards set forth in ASTM D 1945. Calculation of the specific gravity from compositional analysis by gas chromatography shall comply with the standards set forth in ASTM D 3588. Measurement of the specific gravity with a gravitometer shall comply with the standards set forth in ASTM D 1070. 5.3 Flowing Temperature: Flowing gas temperature shall be continuously measured and used in flow calculations. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 22 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 61 First Revised Volume No. 1-A Superseding Original Sheet No. 61 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 6. INSPECTION OF EQUIPMENT AND RECORDS 6.1 Inspection of Equipment and Data: PGT and Shipper shall have the right to inspect equipment installed or furnished by the other, and the charts and other measurement or test data of the other, at all times during business hours; but the reading, calibration and adjustment of such equipment and changing of charts shall be done only by the entity installing or furnishing same. Unless PGT and Shipper otherwise agree, each shall preserve all original test data, charts and other similar records in such party's possession, for a period of at least six (6) years. 6.2 Information for Billing: When information necessary for billing by PGT is in the control of Shipper, Shipper shall furnish such information, estimated if actual is not available, to PGT on or before the third (3rd) working day of the month following the month transportation service was rendered. If shipper furnishes estimated information, the actual information shall be furnished to PGT on or before the sixth (6th) working day of the month following the month transportation service was rendered. 6.3 Verification of Computations: PGT and Shipper shall have the right to examine at reasonable times the books, records and charts of the other to the extent necessary to verify the accuracy of any statement, charge or computation made pursuant to these Transportation General Terms and Conditions and to the rate schedules to which they apply, within twelve (12) months of any such statement, charge or computation. 7. BILLING 7.1 Billing under all Rate Schedules: On or before the twentieth (20th) day of each month, PGT shall render a bill to each Shipper under all applicable Rate Schedules for the service(s) rendered during the preceding month. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 24, 1994 Effective: MARCH 27, 1994 23 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 62 First Revised Volume No. 1-A Superseding Original Sheet No. 62 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 8. PAYMENT 8.1 Payment under all Rate Schedules: On or before the last day of each month, each Shipper under all applicable Rate Schedules shall pay to or upon the order of PGT in lawful money of the United States at PGT's office in San Francisco, California, the amount of the bill rendered by PGT during the month in accordance with Paragraph 7.1 of these Transportation General Terms and Conditions. 8.2 Interest on Unpaid Amounts: Should Shipper fail to pay the amount of any bill rendered by PGT when such amount is due, interest thereon shall accrue from the due date until paid at the rate of interest effective from time to time under 18 CFR Section 154.67. 8.3 Remedies for Failure to Pay: If such failure to pay continues for thirty (30) days after payment is due, PGT, in addition to any other remedy it may have, may suspend further delivery of gas until such amount is paid, unless Shipper in good faith disputes the amount owing and pays such amount as it concedes to be correct. Either party may submit to arbitration in accordance with Paragraph 14 of these Transportation General Terms and Conditions any dispute as to the amount due PGT hereunder. 8.4 Late Billing: If presentation of a bill by PGT is delayed after the date specified in Paragraph 7.1 hereof, then the time for payment shall be extended correspondingly unless Shipper is responsible for such delay. 8.5 Adjustment of Billing Error: In the event an error is discovered in any bill rendered by PGT, the amount of such error shall be adjusted, provided that claim therefor shall have been made within twelve (12) months from the date such bill was rendered. The adjustment shall be made within thirty (30) days of such timely claim. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 24, 1994 Effective: MARCH 27, 1994 24 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 63 First Revised Volume No. 1-A Superseding Original Sheet No. 63 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 9. NOTICE OF CHANGES IN OPERATING CONDITIONS PGT and Shipper shall each ensure that the other is notified from time to time as necessary of expected changes in the rates of delivery or receipt of gas, or in the pressures or other operating conditions, and the reason for such expected changes, so that they may be accommodated when they occur. 10. FORCE MAJEURE 10.1 If either party shall fail to perform any obligation imposed upon it by these Transportation General Terms and Conditions or by an executed Transportation Service Agreement, and such failure shall be caused, or materially contributed to, by force majeure which means any acts of God, strikes, lockouts, or other industrial disturbances, acts of public enemies, sabotage, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, floods, storms, fires, washouts, extreme cold or freezing weather, arrests and restraints of rulers and people, civil disturbances, explosions, breakage of or accident to machinery or lines of pipe, hydrate obstructions of lines of pipe, inability to obtain pipe, materials or equipment, legislative, administrative or judicial action which has been resisted in good faith by all reasonable legal means, any acts, omissions or causes whether of the kind herein enumerated or otherwise not reasonably within the control of the party invoking this paragraph and which by the exercise of due diligence such party could not have prevented, the necessity for making repairs to, replacing, or reconditioning machinery, equipment, or pipelines not resulting from the fault or negligence of the party invoking this paragraph, such failure shall be deemed not to be a breach of the obligation of such party, but such party shall use reasonable diligence to put itself in a position to carry out its obligations. Nothing contained herein shall be construed to require either party to settle a strike or lockout by acceding against its judgment to the demands of the opposing parties. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 25 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 64 First Revised Volume No. 1-A Superseding Original Sheet No. 64 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 10. FORCE MAJEURE (Continued) 10.2 No such cause as described in Paragraph 10.1 affecting the performance of either party shall continue to relieve such party from its obligation after the expiration of a reasonable period of time within which by the use of due diligence such party could have remedied the situation preventing its performance, nor shall any such cause relieve either party from any obligation unless such party shall give notice thereof in writing to the other party with reasonable promptness; and like notice shall be given upon termination of such cause. 10.3 No cause whatsoever, including without limitation the failure of PGT to perform including the causes specified in Paragraph 10.1, shall relieve Shipper from its obligations to make payments due, including the payments of reservation charges for the duration of such cause except as provided for in Paragraphs 3.10 and 3.11 of Rate Schedule FTS-1. 11. WARRANTY OF ELIGIBILITY FOR TRANSPORTATION Any Shipper transporting gas on the PGT system under this FERC Gas Tariff First Revised Volume No. 1-A warrants for itself, its successors and assigns, that it will have at the time of delivery of the gas to PGT hereunder good title to such gas and that all gas delivered to PGT for transportation hereunder is eligible for the requested transportation in interstate commerce under applicable rules, regulations or orders of the FERC, or other agency having jurisdiction. Shipper will indemnify PGT and save it harmless from all suits, actions, damages, costs, losses, expenses (including reasonable attorney fees) and costs connected with regulatory proceedings, arising from breach of this warranty. 12. POSSESSION OF GAS AND RESPONSIBILITY PGT shall be deemed to be in control and possession of, and responsible for, all gas delivered from the time that such gas is received by it at the point of receipt to the time that it is delivered at the point of delivery. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 26 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 65 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 13. INDEMNIFICATION Shipper agrees to indemnify and hold harmless PGT, its officers, agents, employees and contractors against any liability, loss or damage whatsoever occurring in connection with or relating in any way to the executed Transportation Service Agreement, including costs and attorneys' fees, whether or not such liability, loss or damage results from any demand, claim, action, cause of action, or suit brought by Shipper or by any person, association or entity, public or private, that is not a party to the executed Transportation Service Agreement, where such liability, loss or damage is suffered by PGT, its officers, agents, employees or contractors as a direct or indirect result of any breach of the executed Transportation Service Agreement or sole or concurrent negligence or gross negligence or other tortious act(s) or omission(s) by Shipper, its officers, agents, employees or contractors. 14. ARBITRATION Any arbitration provided for or agreed to by Shipper and PGT shall be conducted in accordance with the following procedures and principles: Upon the written demand of either PGT or Shipper and within ten (10) days from the date of such demand, each entity shall appoint an arbitrator and the two arbitrators so appointed shall promptly thereafter appoint a third. If either PGT or Shipper shall fail to appoint an arbitrator within ten (10) days from the date of such demand, then the arbitrator shall be appointed by a Superior Court of the State of California in accordance with the California Code of Civil Procedure. If the two arbitrators shall fail within ten (10) days from their appointment to agree upon and appoint the third arbitrator, then upon the application of either PGT or Shipper such third arbitrator shall be appointed by a Superior Court of the State of California in accordance with the California Code of Civil Procedure. The arbitrators shall proceed immediately to hear and determine the matter in controversy. The award of the arbitrators, or a majority of them, shall be made within forty-five (45) days after the appointment of the third arbitrator, subject to any reasonable delay due to unforeseen circumstances. The award of the arbitrators shall be drawn up in writing and signed by the arbitrators, or a majority of them, and shall be final and binding on both PGT and Shipper, and PGT and Shipper shall abide by the award and perform the terms and conditions thereof. Unless otherwise determined by the arbitrators, the fees and expenses of the arbitrator named for each party shall be paid by that party and the fees and expenses of the third arbitrator shall be paid in equal proportion by both PGT and Shipper. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 27 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 66 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 15. GOVERNMENTAL REGULATIONS These Transportation General Terms and Conditions, the rate schedules to which they apply, and any executed Transportation Service Agreement are subject to valid laws, orders, rules and regulations of duly constituted authorities having jurisdiction. 16. MISCELLANEOUS PROVISION 16.1 Waiver of Default: No waiver by either PGT or Shipper of any default by the other in the performance of any provisions of an executed Transportation Service Agreement shall operate as a waiver of any continuing or future default, whether of a like or different character. 16.2 Assignability: An executed Transportation Service Agreement shall bind and inure to the respective successors and assignees of PGT and Shipper thereto, but no assignment shall release either party thereto from such party's obligations without the written consent of the other party, which consent shall not be unreasonably withheld; provided, however, nothing contained herein shall give Shipper the right to reassign or broker its right to ship the quantities of gas specified in the Transportation Service Agreement on PGT's system to others. Further, nothing contained herein shall prevent either party from pledging, mortgaging or assigning its rights as security for its indebtedness and either party may assign to the pledgee or mortgagee (or to a trustee for the holder of such indebtedness) any money due or to become due under any service agreement. 16.3 Effect of Headings: The headings used throughout these Transportation General Terms and Conditions, the rate schedules to which they apply, and the executed Transportation Service Agreements are inserted for reference purposes only and are not to be considered or taken into account in construing the terms and provisions of any paragraph nor to be deemed in any way to qualify, modify or explain the effects of any such terms or provisions. 17. TRANSPORTATION SERVICE AGREEMENT 17.1 Form: Shipper shall enter into a contract with PGT utilizing PGT's appropriate standard form of Transportation Service Agreement. 17.2 Term: The term of the Transportation Service Agreement shall be agreed upon between Shipper and PGT at the time of the execution thereof. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 28 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 67 First Revised Volume No. 1-A Superseding Original Sheet No. 67 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS Initial Service: For purposes of scheduling commencement of initial transportation service five (5) business days prior to the day on which Shipper desires service to commence, or such lesser period of time as mutually agreed upon by PGT and Shipper, Shipper will provide PGT a completed Customer Nomination Form provided to: Pacific Gas Transmission Company Gas Control Department East 5105 3rd Avenue P.O. Box 4389 Spokane, Washington 99212 Phone - 509-534-0657 Fax - 509-671-2225 Shipper shall not be entitled to receive transportation service under this FERC Gas Tariff First Revised Volume No. 1-A if Shipper is not current in its payments to PGT for any charge, rate or fee authorized by the Commission for transportation service; provided, however, if the amount not current pertains to a bona fide dispute, including but not limited to force majeure claims relating to this FERC Gas Tariff, Shipper shall be entitled to receive or continue to receive transportation service if Shipper posts a bond satisfactory to PGT to cover the payment due PGT. 18.1 Firm Service The provisions of this Paragraph 18.1 shall be applicable to firm transportation service under Rate Schedule FTS-1 contained in this First Revised Volume No. 1-A. Firm transportation service under this First Revised Volume No. 1-A shall be provided when, and to the extent that, PGT determines that firm capacity is available on PGT's existing facilities. PGT shall not be required to provide firm transportation service in the event firm capacity is unavailable or to construct new facilities to provide firm service. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 29 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 68 First Revised Volume No. 1-A Superseding Original Sheet No. 68 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.1 Firm Service (Continued) For capacity that becomes available other than the circumstances identified in Paragraphs 28 and 33, requests for firm capacity shall be accommodated in the following manner and subject to the following conditions and limitations: (a) In order to be eligible for firm capacity, a party requesting service (requestor) must be deemed credit-worthy per Paragraph 18.3 and submit a valid request in accordance with the provisions herein. (b) PGT will post on Pacific Trail, PGT's Electronic Bulletin Board (EBB), available capacity. A requestor that submits a valid request may submit a bid via the EBB for the available capacity subsequent to PGT's posting of such capacity on the EBB. The Bid Period will be 5 business days, during which time other requestors with valid requests may submit a bid. All bids not withdrawn prior to the close of the Bidding Period shall be binding. At the end of the Bidding Period, PGT will evaluate the bids and determine the bid(s) having the greatest economic value as determined in Paragraph 18.1(c) below. (c) After the close of the Bidding Period, PGT may tender a Service Agreement for execution to the requestor(s) submitting the bid(s) having the greatest economic value for the capacity available, subject to the provisions of Paragraph 18.1(e). The criteria for determining which requestor(s) has submitted the bid(s) with the greatest economic value shall be the Net Present Value (NPV) of the reservation charge as calculated at Paragraph 28 that requestor(s) would pay at the rates requestor(s) has bid, which shall not be less than the Minimum Rate nor greater than the Maximum Rate, as stated on the currently effective Statement of Rates and Charges governing such service, over the term of service specified in the request. If the economic values of separate bids are equal, then service shall be offered to such requestors on a pro-rata basis. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 30 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 69 First Revised Volume No. 1-A Superseding Original Sheet No. 69 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.1 Firm Service (Continued) (d) If PGT accepts the winning bid(s) and tenders a Service Agreement, requestor(s) shall complete and return the Service Agreement within thirty (30) days. (e) Except as provided in Paragraph 28, PGT shall not be obligated to tender or execute a Service Agreement for service at any rate less than the Maximum Rate set forth in the Statement of Effective Rates and Charges applicable to the service requested. (f) A Shipper receiving service under FTS-1 shall not lose its priority for purposes of Paragraph 19 by the renewal or extension of term of that service; provided, however, any renewal or extension must be pursuant to a rollover or evergreen provision of the Service Agreement. Shipper's preexisting priority shall not apply, however, to any increase in transportation quantity or new primary point of delivery. 18.2 Interruptible Service The provisions of this Paragraph 18.2 shall be applicable to interruptible transportation service under Rate Schedule ITS-1 contained in this First Revised Volume No. 1-A. (a) Interruptible transportation service under this First Revised Volume No. 1-A shall be provided when, and to the extent that, capacity is available in PGT's existing facilities, which capacity is not subject to a prior claim under a pre-existing agreement pursuant to Rate Schedule FTS-1 or under another class of firm service. (b) In the event where natural gas tendered by Shipper to PGT at the receipt point(s) for transportation, or delivered by PGT to Shipper (or for Shipper's account) at the delivery point(s), is commingled with other natural gas at the time of measurement, the determination of deliveries applicable to Shipper shall be made in accordance with operating arrangements satisfactory to Shipper, PGT and any third party transporting to or from PGT's system. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 31 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 70 First Revised Volume No. 1-A Superseding Original Sheet No. 70 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.2 Interruptible Service (Continued) (c) PGT shall process the requests of potential Shippers requesting similar interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A on a first-come, first-served basis, to the extent practicable, taking into account the nature and character of the service requested. Available interruptible capacity shall be allocated by PGT on a first-come, first-served basis as provided in Paragraph 19 and determined by the date and time PGT receives a completed request for service under this FERC Gas Tariff which conforms to Paragraph 18 of these Transportation General Terms and Conditions. (d) A Shipper receiving service under ITS-1 shall not lose its priority for purposes of Paragraph 19 by the renewal or extension of term of that service; provided, however, any renewal or extension must be pursuant to a rollover or evergreen provision of the Service Agreement. Shipper's pre-existing priority shall not apply, however, to any increase in transportation quantity or new primary points of delivery. (e) If Shipper fails to nominate and tender gas within the later of: (a) fifteen (15) days after initial notification by PGT of the availability of service, (b) receipt of any necessary regulatory approvals, or (c) the installation of any necessary facilities, Shipper's priority date shall be deemed null and void, and the day Shipper first tenders gas to PGT at any receipt point shall be Shipper's new assigned priority date for service. Shipper's priority date designation pursuant to Section 2.3 of the Transportation Service Agreement shall not be deemed null and void if Shipper's failure to nominate and tender gas is caused by an event of force majeure as defined in PGT's Transportation General Terms and Conditions. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 32 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 70A First Revised Volume No. 1-A Superseding Original Sheet No. 70A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 Credit-worthiness (A) Credit-worthiness for Firm Transportation Service (1) PGT shall not be required to perform or to continue transportation service under this FERC Gas Tariff First Revised Volume 1-A on behalf of any Shipper who is or has become insolvent or who, after PGT's request, fails within a reasonable period to establish or confirm credit-worthiness. Shippers shall provide, initially and on a continuing basis, financial statements, evidence of debt and/or credit ratings, and other such information as is reasonably requested by PGT to establish or confirm Shipper's qualification for service. Credit limits will be established based on the level of requested service and Shipper credit-worthiness as established by the following: (a) Credit-worthiness must be evidenced by at least a long term bond (or other senior debt) rating of BBB or an equivalent rating. Such rating may be obtained in one of three ways: (i) The rating will be determined by Standard and Poors or another recognized U.S. or Canadian debt rating service; (ii) If Shipper's debt is not rated by a recognized debt rating service, an equivalent rating as determined by PGT, based on the financial rating methodology, criteria and ratios for the industry of the Shipper as published by the above rating agencies from time to time. In general, such equivalent rating will be based on the audited financial statements for the Shipper's two most recent fiscal years, all interim reports, and any other relevant information; (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: APRIL 20, 1994 Effective: MAY 21, 1994 33 Pacific Gas Transmission Company FERC Gas Tariff Substitute Second Revised Sheet No. 71 First Revised Volume No. 1-A Superseding First Revised Sheet No. 71 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (A) Credit-worthiness for Firm Transportation Service (Continued) (iii) Shipper may, at its own expense, obtain a private rating from a recognized debt rating service, or request that an independent accountant or financial advisor, mutually acceptable to PGT and the Shipper, prepare an equivalent evaluation based on the financial rating methodology, criteria, and ratios for the industry of the Shipper as published by the above rating agencies from time to time; or (b) Approval by PGT's lenders; or (c) If Shipper is requesting credit to bid on a parcel that is for one year (365 days) or less of service through PGT's Capacity Release Program contained in Paragraph 28, and this option is selected by the Releasing Shipper, Shipper may demonstrate credit-worthiness by providing two years of audited financial statements demonstrating adequate financial strength to justify the amount of credit to be extended. PGT shall apply consistent evaluation practices to determine credit-worthiness. (2) If Shipper does not establish or maintain credit-worthiness as described above, Shipper has the option of receiving transportation service under this FERC Gas Tariff by providing to PGT one of the following alternatives: (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: MAY 31, 1994 Effective: MAY 21, 1994 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-211-000 , dated MAY 20, 1994 34 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 72 First Revised Volume No. 1-A Superseding Original Sheet No. 72 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (A) Credit-worthiness for Firm Transportation Service (Continued) (a) A guarantee of Shipper's financial performance in a form satisfactory to PGT and for the term of the Gas Transportation Agreement from a corporate affiliate of the Shipper or a third party either of which meets the credit-worthiness standard discussed above. (b) Other security acceptable to PGT's lenders. 18.3 (B) Credit-worthiness for Interruptible Transportation Service (1) PGT shall not be required to perform or to continue interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A on behalf of any Shipper who is or has become insolvent or who, at PGT's request, fails within a reasonable period to demonstrate credit-worthiness. Shipper's credit-worthiness shall be determined by providing proof of least two of the items listed below: (a) A long-term bond or commercial paper rating from Standard and Poors or Moody's equivalent to a "Ba" or better, or a commercial paper rating from Standard and Poors or Moody's equivalent to Prime-3 or better. (b) Audited financial statements for the two preceding years showing good financial strength. (c) An estimated financial strength rating by Dun and Bradstreet sufficient to cover the credit to be extended and a corresponding Dun and Bradstreet composite credit appraisal of "fair" or better. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 35 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 73 First Revised Volume No. 1-A Superseding Original Sheet No. 73 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (B) Credit-worthiness for Interruptible Transportation Service (Continued) (d) A demonstration by the Shipper that the Company has sufficient financial capacity or backing to warrant an extension of credit. This demonstration could include proof of banking relationships sufficient to cover the service agreement, or a detailed listing of credit references within the industry, exhibiting a good credit history. (2) If Shipper does not demonstrate credit-worthiness, Shipper has the option of receiving interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A if Shipper provides PGT a letter of credit in an amount equal to the cost of performing the maximum level of service requested for a three (3) month period of time. The letter of credit must be from a credit worthy financial institution and be in place before the Transportation Service Agreement can be signed. The Shipper also has the option of receiving transportation service if Shipper prepays for transportation services on a month-to-month basis pursuant to the following terms: (a) For a calendar month in which transportation service is desired (delivery month), Shipper must notify PGT no later than eight (8) business days prior to the commencement of delivery month (estimation date) of its estimation of the maximum, cumulative gas deliveries (monthly estimation) desired for the delivery month. (For Shipper's initial monthly estimation, the delivery month, or remaining portion thereof, shall commence eight (8) days after the estimation date.) Notice of monthly estimation may be telephonic or written; telephonic notices must be confirmed in writing and received by PGT within five (5) business days. PGT will advise Shipper within forty-eight (48) hours of the estimation date of the exact dollar amount of the prepayment. Shipper shall not deliver or receive gas in excess of the monthly estimation during delivery month. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 36 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 74 First Revised Volume No. 1-A Superseding Original Sheet No. 74 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (B) Credit-Worthiness for Interruptible Transportation Service (Continued) (b) No later than three (3) business days (settlement date) prior to commencement of delivery month, Shipper shall pay to PGT and PGT shall have received from Shipper lawful money of the United States in an amount equal to the prepayment amount provided to Shipper by PGT described above. (c) On or before the twentieth (20th) day following delivery month, PGT shall provide a statement to Shipper detailing the transportation service provided during the delivery month. The statement will reconcile the amount prepaid in accordance with the monthly estimation, with the actual cost of transportation service provided, and provide a credit to Shipper, if applicable. Any such credit will be deducted from the prepayment for the following month. Should the Shipper elect not to receive transportation services for the following month, Shipper shall so notify PGT in writing; PGT will issue a check to the Shipper within seven (7) business days following receipt by PGT of such notice. 18.3 (C) Credit-worthiness for Firm and Interruptible Transportation Service For purposes of this FERC Gas Tariff First Revised Volume No. 1-A the insolvency of a Shipper shall be evidenced by the filing by such Shipper or any parent entity thereof (hereinafter collectively referred in this paragraph to as "the Shipper") of a voluntary petition in bankruptcy or the entry of a decree or order by a court having jurisdiction in the premises adjudging the Shipper as bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of the Shipper under the Federal Bankruptcy Act or any Act or any other applicable federal or state law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Shipper (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 37 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 75 First Revised Volume No. 1-A Superseding Original Sheet No. 75 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.3 (C) Credit-worthiness for Firm and Interruptible Transportation Service (Continued) or composition of or in respect of the Shipper under the Federal Bankruptcy Act or any Act or any other applicable federal or state law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Shipper or of any substantial part of its property, or the ordering of the winding-up liquidation of its affairs, with said order or decree continuing unstayed and in effect for a period of sixty (60) consecutive days. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 38 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 76 First Revised Volume No. 1-A Superseding Original Sheet No. 76 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.4 Upon request of PGT, Shipper shall from time to time submit estimates of daily, monthly and annual quantities of gas to be transported, including peak day requirements. 18.5 PGT shall not be obligated to install additional facilities, other than those specified in Paragraph 4.1 herein, that are required to provide service under this FERC Gas Tariff First Revised Volume No. 1-A; provided, however, PGT may install or Shipper may pay all of the expenses incurred for installing additional facilities on a nondiscriminatory basis and under terms that are mutually agreeable. In the event PGT incurs the cost of installing additional facilities on behalf of a Shipper, Shipper shall pay, in addition to the rate(s) stated in the applicable rate schedule, the prorated(based on Transportation Contract Demand) cost of service attributable to any such additional facilities until such time as a different allocation procedure is specified by Commission order. 18.6 No transportation service will be conducted for the account of Shipper by PGT until PGT has received the completed service request form, unedited and complete as to form, and Shipper has been advised by PGT that the transportation service may commence. 18.7 Requests for interruptible and firm transportation service hereunder shall be made by providing the information contained in PGT's Transportation Request Form to PGT. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 39 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 77 First Revised Volume No. 1-A Superseding Original Sheet No. 77 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.8 Transportation Request Form Gentlemen: ________________________________ (Shipper) hereby requests gas transportation service from Pacific Gas Transmission Company (PGT) in accordance with Paragraph 18.8 of the Transportation General Terms and Conditions of PGT's tariff and concurrently provides the following information relative to this request: 1. Shipper's Name ___________________________________________ Business Address __________________________________________ State or Province of Incorporation ________________________ 2. Requesting Party ____________________ Title _______________ Contact Name ________________________ Phone _______________ 3. Shipper's Status: LDC ____ Intrastate ____ End User ____ (Check one) Producer ____ Marketer/Broker __________ Gatherer ____ Interstate ____ Other __________________________________ 4. Type of Service Requested: (Check all applicable) a. Part 284 Interruptible ____ b. Part 284 Firm ____* c. New Service ____ d. Amendment to PGT Contract #_______ e. Add/Change Receipt/Delivery Point ____ f. Authority to Bid for Released Capacity ____ * PGT will accept requests for firm transportation service. At such time that firm capacity may become available, PGT will evaluate such requests. Currently, no excess firm capacity is available on the PGT system. 5. Type of Authority: Blanket Section 7 (Part 284, Subpart G)____ Section 311(a) (Part 284, Subpart B)____ (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 40 Pacific Gas Transmission Company FERC Gas Tariff Second Revised Sheet No. 78 First Revised Volume No. 1-A Superseding First Revised Sheet No. 78 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.8 Transportation Request Form (Continued) 6. If Shipper requests service under Section 311(a), provide the following information concerning the party on whose behalf the transportation will be provided (the "On Behalf of" party): (a) The exact legal name of the "On Behalf Of" party: ----------------------------------------------------------------- (b) The "On Behalf Of" party's address (if other than Shipper): ----------------------------------------------------------------- ----------------------------------------------------------------- ----------------------------------------------------------------- (c) Is the "On Behalf Of" party: A Local Distribution Company ______ An Intrastate Pipeline ______ 7. If Shipper requests service under Section 311(a), Shipper must provide a certification that the service qualifies under 18 C.F.R. Section 284.102. To enable PGT to verify that the requested transportation service will qualify under 18 C.F.R. Section 284.102, the certification must provide facts showing that: (a) the "On Behalf Of" party will have physical custody of and transport the natural gas at some point; or (b) the "On Behalf Of" party will hold title to the natural gas at some point, which may occur prior to , during, or after the time that the gas is transported by PGT, for a purpose related to the "On Behalf Of" party's status and function as an intrastate pipeline or its status and function as a local distribution company; or (c) the gas will be delivered to a customer that is either located in the "On Behalf Of" party's service area, if the "On Behalf Of" party is a local distribution company, or is physically able to receive direct deliveries of gas from the "On Behalf Of" party, if the "On Behalf Of" party is an interstate pipeline, and that "On Behalf Of" party has certified that it is on its behalf that PGT will be providing the requested transportation service. (The "On Behalf Of" party's certification must be submitted with the Transportation Request Form.) (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 41 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 79 First Revised Volume No. 1_A Superseding Original Sheet No. 79 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.8 Transportation Request Form (Continued) 8. The intended use of the gas is: _____ utility or pipeline system supply _____ end use by industry or commerce _____ other (specify) 9. Requested Commencement Date _______________ (not to exceed 3 months from request date) Termination Date __________________ Evergreen clause desired (Complete for Part 284 Interruptible or Firm Service only): Yes _____ No _____ 10. Transportation Quantities: a) Total Maximum Daily Quantity (MDQ): __________ MMBtu/day b) Total quantity for contract period: __________ MMBtu 11. Notices to: _______________________________________________________ Mailing Address ________________________________________________________ City State Zip ________________________________________________________ Street Address (if P.O. Box was used above) ________________________________________________________ City State Zip ________________________________________________________ Attention Title ________________________________________________________ Telephone Number Fax Number (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 42 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 80 First Revised Volume No. 1_A Superseding Substitute Original Sheet No. 80 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. OPERATING PROVISIONS (Continued) 18.8 Tranportation Request Form (Continued) Invoices to: _______________________________________________________ Mailing Address _______________________________________________________ City State Zip _______________________________________________________ Street Address (if P.O. Box was used above) _______________________________________________________ City State Zip _______________________________________________________ Attention Title _______________________________________________________ Telephone Number Fax Number (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 43 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 81 First Revised Volume No. 1-A Superseding Substitute Original Sheet No. 81 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS 19.1 Priority of Firm Service PGT shall provide service first for firm transportation Shippers for service at Shipper's primary receipt and delivery points in accordance with the applicable executed service agreements and rate schedules. Next, PGT will provide firm transportation service for service at Shipper's secondary receipt and delivery points or primary receipt and secondary delivery points in accordance with the applicable executed service agreements and rate schedules. If full service cannot be provided, PGT shall provide service on a pro rata basis according to the respective total Maximum Daily Demand or Maximum Daily Quantity, as appropriate, specified in each executed service agreement, first for service at Shipper's primary receipt and delivery points and second for service at Shipper's secondary receipt and delivery points. These provisions also apply for capacity released under PGT's capacity release program, and are subject to the terms and conditions as specified in an executed firm service agreement between PGT and Shipper. All service under the capacity release program shall be considered firm for purposes of priority of service. 19.2 Priority of Interruptible Service Interruptible transportation service under this FERC Gas Tariff First Revised Volume No. 1-A shall be provided when, and to the extent that, capacity is available in PTG's existing facilities, which capacity is not subject to a prior claim under a pre-existing contract, service agreement, certificate or under Priority 1 - Firm Service. PGT will provide interruptible transportation service, as set forth in Paragraph 19 of these Transportation General Terms and Conditions, on a first-come, first-served basis, as determined by the date and time PGT receives a completed request for service conforming to Paragraph 18.8, as approved by the Commission in Docket No. CP87-159-000. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 44 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 81A First Revised Volume No. 1-A Superseding Original Sheet No. 81A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS (Continued) 19.3 Priority of Authorized Overrun Service Authorized overrun service shall have a priority lower than firm or interruptible as defined above. Priority within the overrun class shall be determined using a first-come, first-serve procedure. 19.4 Nominations Quantities nominated for transportation shall be for previously approved and valid receipt and delivery points and shall be provided by Shipper via the Electronic Bulletin Board (EBB), to PGT's Gas Control no later than 10:00 a.m. Pacific Time for the following day. Nominations for an entire month may be made at any time up to 10:00 a.m. Pacific Time on the last day of the month. PGT shall have the discretion to accept nominations at such other later times as operating conditions may permit and without detrimental impact to other Shippers and upon confirmation that corresponding upstream and downstream arrangements in a manner satisfactory to PGT have been made. The receipt of the nomination by PGT is notice that all necessary regulatory approvals have been received and that valid upstream and downstream transportation and other contractual arrangements are in place. Shipper shall provide as a component of its nomination such other information as may be required by PGT to enable it to identify, confirm and schedule the nomination. Shipper shall also prioritize nominated receipts and deliveries when there is more than one supplier and more than one shipper customer respectively. Shipper designated priorities will be used to allocate gas when the upstream and downstream nominations vary from PGT's Shipper nominations. PGT shall be allowed to rely conclusively on the information submitted as part of the nomination in confirming the nomination for scheduling and allocation. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 45 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 81B First Revised Volume No. 1-A Superseding Original Sheet No. 81B TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS (Continued) 19.4 Nominations (Continued) Requests to amend previously scheduled nominations may be accepted during the gas day, subject to operational conditions and, further that corresponding upstream and downstream adjustments in a manner satisfactory to PGT can be confirmed. A request to increase a nomination for firm transportation up to the MDQ specified in the Service Agreement will be accommodated to the extent operating conditions permit; provided, however an increased nomination will not be scheduled to the extent it would affect another Shipper's flowing quantities during the Gas Day that the increased nomination is received. A request to increase a nomination for interruptible transportation shall be permitted only to the extent that capacity is available and that no displacement of other interruptible transportation occurs. Such changes will become effective only when system operating conditions, as determined by PGT, permit changes to occur. Quantities nominated are for a daily rate, and will be received and delivered at a uniform hourly rate of confirmed quantity divided by 24, unless as determined by PGT, variance from the hourly rate will not be detrimental to the operation of the pipeline or adversely affect other PGT Shippers. Nominations, as amended by Shipper and received by PGT, shall remain in effect during the month for which the nomination is applicable, whether or not transportation occurs, until a new or amended nomination is provided by Shipper and received by PGT. PGT reserves the right to reject any nominated quantity of less than 24 MMBTU/day. PGT's primary method of nomination transmission shall be the EBB. If and only if, the EBB is inoperable, shall PGT accept nominations via alternative means such as fax transmittal. PGT requires that a Shipper designate, in writing, those individuals who will be authorized to place nominations for transportation on the system. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 46 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 81C First Revised Volume No. 1-A Superseding Original Sheet No. 81C TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. CURTAILMENT PGT shall have the right to curtail, interrupt, or discontinue Transportation Service on any portion of its system at any time for reasons of Force Majeure or when capacity, supply, or operating conditions so require or it is necessary or desirable to make modifications, repairs, or operating changes to its system. PGT shall provide notice of such occurrences as is reasonable under the circumstances. Capacity may become constrained at individual receipt points, delivery points or on segments of the pipeline. PGT shall exercise this curtailment provision only at the point(s) or segment(s) of the pipeline affected by the constraint. When capacity is constrained or otherwise insufficient to serve all the transportation requirements which are scheduled to receive service, transportation service will be curtailed in reverse order of the scheduling provided in Paragraph 19. Curtailment of firm service if necessary, will be performed pro rata based on the MDQ across the contracts scheduled to use capacity at the applicable delivery point(s) or mainline segment(s) of pipeline, applied first to secondary delivery points. Curtailment of firm service, if necessary, at receipt points will be performed pro rata based on the quantities scheduled at the affected receipt point(s), applied first to secondary receipt points. If, on any day, PGT determines the capacity of its mainline system, or any portion thereof, including the points at which gas is tendered for transportation, is insufficient to serve transportation requirements which are otherwise scheduled to receive service on such day, or to accept the quantities of gas tendered, capacity which requires allocation shall be allocated in a manner which results in curtailment of capacity, to zero if necessary, first to the last quantities scheduled, and then sequentially in reverse order to the scheduling provided for in Paragraph 19, except that mid-gas day domination increases by interruptible Shippers shall not bump those interruptible Shippers' volumes already confirmed for that gas day. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 47 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 82 First Revised Volume No. 1-A Superseding Original Sheet No. 82 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. BALANCING Balancing of thermally equivalent quantities of gas received and delivered by PGT shall be achieved as nearly as feasible on a daily basis, with any cumulative imbalance accounted for on a monthly basis. Correction of imbalances shall be the responsibility of the Shipper whether or not notified by PGT at the time of incurrence of the imbalance. Correction of imbalances shall be scheduled with PGT using the nomination process as soon as an imbalance is known to exist based on the best available current data. Nominations to correct imbalances shall have the lowest priority for scheduling purposes and shall be subject to the availability of capacity and other operational constraints for imbalance correction. If on any day capacity is insufficient to schedule all imbalance nominations, all such nominations shall be prorated accordingly. To maintain the operational integrity of its system, PGT shall have the right to balance any Shipper's account as conditions may warrant. Imbalances shall exist as defined below and be subject to the applicable charges and penalties if not corrected. a) Actual delivered quantity exceeds MDQ An imbalance shall exist if the actual delivered quantity on any day exceeds the MDQ and the delivered quantity in excess of the MDQ has not been authorized by PGT (Unauthorized Overrun). Penalty: A Shipper shall be assessed $5/MMBTU for the quantity that is greater than 10% of the MDQ or 1000 MMBTU, whichever is greater. In addition, the quantity delivered in excess of the MDQ shall be charged the Authorized Overrun charge as provided in the applicable rate schedule of Shipper. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 48 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 83 First Revised Volume No. 1-A Superseding Original Sheet No. 83 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. BALANCING (Continued) (b) Actual delivered quantity exceeds receipt quantity A net positive imbalance shall exist if the difference between the delivered quantity and the quantity received, taking into account the reduction in quantity for compressor fuel use, yields a positive result. Commencing upon notification by PGT of the existence of the imbalance, Shipper shall have 3 days to correct the imbalance. Penalty: If, at the end of the 3 day period the difference between the actual delivered quantity and the receipt quantity is in excess of 10% of the delivered quantity or 1000 MMBTU, whichever is greater, the Shipper shall be assessed a charge of $5/MMBTU applied to the excess quantities. If the imbalance is not corrected within 45 days of PGT's notice of an imbalance, the Shipper shall be assessed an additional charge of $5/MMBTU, applied to the net imbalance remaining at the end of the 45 day balancing period. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 49 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 84 First Revised Volume No. 1-A Superseding Original Sheet No. 84 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. BALANCING (Continued) (c) Actual quantity received exceeds delivered quantity A net negative imbalance shall exist if the difference between the delivered quantity and the quantity received taking into account the reduction in quantity for compressor fuel use, yields a negative result. Commencing upon notification by PGT of the existence of the imbalance, Shipper shall have 3 days to correct the imbalance. Penalty: If, at the end of the 3 day period the difference between the actual quantity received and the delivered quantity is in excess of 10% of the delivered quantity or 1000 MMBTU, whichever is greater, the Shipper shall be assessed a penalty of $2/MMBTU applied to the excess quantity. If the imbalance is not corrected within 45 days of PGT's notice of an imbalance, PGT shall be able to retain the remaining imbalance quantity without compensation to the Shipper and free and clear of any adverse claim. (d) Scheduled delivery quantity exceeds actual delivered quantity An imbalance shall exist when the quantity scheduled (nominated and confirmed) for delivery exceeds the actual delivered quantity. Penalty: When the difference between the scheduled delivery quantity and actual delivered quantity is in excess of 10% of the actual deliveries, or 1000 MMBTU, whichever is greater, the Shipper shall be assessed the maximum applicable interruptible transportation rate applied to the excess quantities. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 50 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 84A First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. BALANCING (Continued) (e) Actual delivered quantity exceeds scheduled delivery quantity An imbalance shall exist when the quantity delivered exceeds the quantity scheduled (nominated and confirmed). Penalty: When the difference between the actual delivered quantity and the scheduled delivery quantity is in excess of 10% of the scheduled quantity or 1000 MMBTU whichever is greater, the Shipper shall be assessed a charge of $5/MMBTU applied to the excess quantity. Imbalance determinations as described above will be performed on a daily basis and each daily occurrence will constitute a separate incident. It is recognized and understood that more than one penalty provision may apply to each imbalance incident. In the event that any penalty would otherwise be applicable under these provisions as a direct consequence of any action or failure to take action by PGT or the failure of any facility under PGT's control, or an event of force majeure as defined in these Transportation General Terms and Conditions, said penalty shall not apply. The payment of a penalty in dollars pursuant to Paragraph 21 shall under no circumstances be considered as giving any Shipper the right to deliver or take overrun quantities. Upon termination of a Service Agreement, Shipper shall have 60 days to correct any remaining imbalances. After his period has elapsed, PGT shall have the right to retain any negative imbalance quantity without compensation to the Shipper and shall assess a charge of $5/MMBTU for any positive imbalance quantity as applicable. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 51 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 85 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 22. ANNUAL CHARGE ADJUSTMENT (ACA) PROVISION 22.1 Purpose: PGT shall recover from Shippers the annual charge assessed to PGT by the Federal Energy Regulatory Commission for budgetary expenses pursuant to Section 154.38(d)(6) of the Commission's regulations and Order No. 472 issued May 29, 1987. PGT shall recover this charge by means of an Annual Charge Adjustment (ACA); a per unit rate equivalent to the unit rate assessed against PGT by the Commission shall be included in PGT's transportation rates. (During the period that this ACA provision is in effect, PGT shall not recover in a Natural Gas Act Section 4 rate case annual charges recorded in FERC Account No. 928 assessed to PGT by the Commission pursuant to Order No. 472.) 22.2 Filing Procedure: The notice period and proposed effective date of filings pursuant to this paragraph shall be as permitted under Section 4 of the Natural Gas Act; provided, however, that any such filing shall not become effective unless they become effective without suspension or refund obligation. 22.3 ACA Unit Rate Adjustment: PGT's ACA unit rate shall be the unit rate used by the Commission to determine the annual charge assessment to PGT, and shall be reflected in the Statement of Effective Rates and Charges of this FERC Gas Tariff First Revised Volume No. 1-A. 22.4 Affected Rate Schedules: The ACA provision shall apply to all rate schedules contained in PGT's FERC Gas Tariff First Revised Volume No. 1-A. 23. SHARED OPERATING PERSONNEL AND FACILITIES PGT and its marketing affiliate do not share any operating personnel. PGT does not share any facilities with its marketing affiliate. To the extent PG&E elects service under Rate Schedule USS-1, PGT employees involved with the implementation of USS-1 service will operate independently from PGT's pipeline operating employees. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 52 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 86 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 24. COMPLAINT PROCEDURES 24.1 Any Shipper or potential Shipper may register a complaint regarding requested or provided transportation service. The complaint may be communicated to PGT primarily by use of PGT's Electronic Bulletin Board (EBB) and secondarily either orally, and/or in writing. Oral complaints should be made to PGT's Manager of Gas Control, telephone (509) 534-0657. Written complaints should be sent via registered or certified mail, facsimile (FAX No. (509) 536-2735), or hand delivered to: Pacific Gas Transmission Company East 5105 3rd Avenue P.O. Box 4389 Spokane, WA 99212 Attention: Gas Control Manager Oral, written and EBB-submitted complaints must contain the following minimum information: - Shipper or potential Shipper's name, address, and FAX and telephone numbers; - Shipper or potential Shipper's contact representative; - A clear, concise statement of the complaint. Each complaint will be recorded in PGT's Transportation Service Complaint Log maintained by PGT's Gas Control Department located in Spokane. Complaints will be logged by date and time received by PGT. 24.2 PGT will initially respond to each complaint within forty-eight (48) hours after PGT receives it. PGT will provide a written response to each complaint within thirty (30) days after PGT receives it. PGT's written response will be sent to Shipper or potential Shipper by certified or registered mail If the complaint was filed by the EBB, then PGT shall respond via the EBB. A copy of all complaints will be filed in the Transportation Service Complaint Log. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 53 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 87 First Revised Volume No. 1-A Superseding Original Sheet No. 87 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 25. INFORMATION CONCERNING AVAILABILITY AND PRICING OF TRANSPORTATION SERVICE AND CAPACITY AVAILABLE FOR TRANSPORTATION 25.1 Any affiliated or nonaffiliated Shipper or potential Shipper may obtain information concerning the availability and pricing of PGT's transportation services and the pipeline capacity available for transportation by: (a) Contacting PGT at: Pacific Gas Transmission Company Marketing and Transportation Department 160 Spear Street, Suite 1919 San Francisco, CA 94105-1570 Telephone: (415) 973-6169 Inquiries may be made orally or in writing. Upon request, PGT will provide to any Shipper or potential Shipper a copy of its FERC Gas Tariff, First Revised Volume No. 1-A, as well as any published notices concerning discounts then available to existing Shippers on the PGT system. (b) Subscribing to PGT's twenty-four (24) hour Electronic Bulletin Board by calling 1-800-238-2781. The Electronic Bulletin Board provides current information concerning the availability and pricing of transportation service on the PGT system, including all effective rates and discount notices, and capacity available for transportation. 25.2 The procedures to be followed by a potential Shipper requesting transportation service from PGT or by an existing Shipper requesting an amendment to its existing service or additional service from PGT are specified in Paragraph 21 of these Transportation General Terms and Conditions. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 54 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 88 First Revised Volume No. 1-A Superseding Original Sheet No. 88 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 25. INFORMATION CONCERNING AVAILABILITY AND PRICING OF TRANSPORTATION SERVICE AND CAPACITY AVAILABLE FOR TRANSPORTATION (Continued) 25.3 The procedures to be followed by Shippers for submitting nominations for transportation service are specified in Paragraph 19 of these Transportation General Terms and Conditions. 26. MARKET CENTERS The Market Center is defined as a point of interconnection between PGT and other pipelines and local distribution companies. PGT shall provide for Market Centers on PGT. Parties wishing to use Market Centers on the PGT system shall contact PGT for this service. At these Market Centers, Agents other than the pipeline Shippers, trade gas quantities without actively shipping the gas either upstream or downstream of the Market Center. Agents must nominate for the gas transactions in accordance with the nomination procedures of the Transportation General Terms and Conditions of First Revised Volume No. 1-A. An Agent's nomination for upstream supply and downstream delivery must match the corresponding upstream Shipper nomination and the downstream customer request. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 55 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 88A First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 27. PLANNED PGT CAPACITY CURTAILMENTS AND INTERRUPTIONS 27.1 When PGT needs to temporarily curtail or interrupt service to any Shipper hereunder for the purpose of making planned alterations or repairs, PGT shall give Shipper as much notice as possible of the process so that each Shipper's firm transportation requirements are taken into account in the planning process. 27.2 In the spring of each year PGT shall publish on its electronic bulletin board (EBB) to all Shippers a schedule of planned major maintenance and repairs which affect system capacity. The schedule shall show the estimated delivery point capacity for the next 12 months. 27.3 On a daily basis PGT shall post, on its EBB, capacity for each forthcoming gas day plus the estimated capacity for the next two gas days. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 56 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 89 First Revised Volume No. 1-A Superseding Original Sheet No. 89 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE 28.1 Eligibility to Release Any firm Shipper which contracts for firm transportation service under Part 284 of the Commission's regulations (Releasing Shipper) is eligible to release all or part of its capacity (Parcel) for use by another party (Replacement Shipper). Any Replacement Shipper which has previously contracted for a Parcel may also release its capacity to another party as a secondary release subject to the terms and conditions described herein. Upon releasing a Parcel, consistent with the terms and conditions described herein, all Releasing Shippers shall remain ultimately liable for all reservation charges billable for the originally contracted service. The Releasing Shipper, whether a primary or secondary capacity holder, must post the capacity it seeks to release on PGT's Electronic Bulletin Board (EBB) prior to the close of the Posting Period defined herein. A Releasing Shipper may release all of its capacity for the remainder of the term of its contract and extinguish its contractual obligations to PGT provided that: 1) the Replacement Shipper for this capacity is creditworthy pursuant to PGT's credit standards; 2) that the rate paid by the Replacement Shipper be no less than the rate contracted between the Releasing Shipper and PGT for the maximum volume, for the remaining term of the contract or the Releasing Shipper's maximum tariff rate; and 3) the release is for all of the Releasing Shipper's capacity. The release may be structured such that the right of first refusal may transfer to the Replacement Shipper even if the release has recall provisions and has been recalled by the Releasing Shipper at the end of the service agreement. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: OCTOBER 31, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993 57 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 90 First Revised Volume No. 1-A Superseding Original Sheet No. 90 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.2 Types of Release A Releasing Shipper may release a Parcel for a term (Release Term) up to or equivalent to the remaining term under its service agreement with PGT. Types of releases include: Rapid Release - one month or less, is not prearranged, requires bidding and is restricted to options 1 or 2 for the allocation of Parcels without special terms or conditions. A standard recall provision may be selected. (Capacity up to the full quantity of the release maybe recallable on 2 business days notice. This capacity may be returned to the Replacement Shipper on 2 business days notice. Replacement Shipper may refuse to accept such capacity returned in this fashion.) Standard Release - greater than or equal to one day, is not prearranged and requires bidding. Prearranged Deal-A - less than one calendar month . This type of release is prearranged and does not require bidding. This release cannot be rolled-over, renewed or otherwise extended beyond the term described above unless the Releasing Shipper follows the posting and bidding procedures that apply to the particular term sought contained in this Paragraph 28. The Releasing Shipper may not re-release this Parcel to the same Replacement Shipper until 30 days after the term of the initial release has ended. Rollovers are permitted without bidding or a waiting period provided the Prearranged Shipper agrees to pay the maximum rate and meet all the other terms and conditions of the release. Prearranged Deal-B - greater than or equal to one month at the maximum rate bid pursuant to the methodology selected by Releasing Shipper. This type of release is prearranged and does not require bidding. Prearranged Deal-C - greater than or equal to one day at a rate less than the maximum rate bid pursuant to the methodology selected by the Releasing Shipper. This type of release is prearranged, allows for bidding, and allows the right of first refusal. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 58 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 91 First Revised Volume No. 1-A Superseding Original Sheet No. 91 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.3 Notice Requirements Any Releasing Shipper electing to release capacity shall submit a notice via PGT's EBB that it elects to release firm capacity. The notice shall set forth the following information: (a) Releasing Shipper's legal name, contract number, and the name, title, address, telephone number, and fax number of the individual responsible for authorizing the release of capacity. (b) Rate schedule of the Releasing Shipper. (c) Whether bidders will bid on the reservation charge or a volumetric equivalent of the maximum reservation charge applicable to the Parcel on a 100% load-factor basis. If a volumetric rate is used, Releasing Shipper must indicate whether bids on a reservation charge basis will be accepted as well and if so must specify the method of evaluating the two types of bids. (d) Daily quantity of capacity to be released, expressed in MMBtu/d, at the designated delivery point(s). (This must not exceed Releasing Shipper's maximum contract demand available for capacity release and shall state the minimum quantity expressed in MMBtu/d acceptable for release.) (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 59 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 92 First Revised Volume No. 1-A Superseding Original Sheet No. 92 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.3 Notice Requirements (Continued) (e) The term of the release, identifying the date release is to begin and terminate. The minimum release term acceptable to PGT shall be one day. (f) Whether the Releasing Shipper is willing to consider release for a shorter period of time than that specified in (e) above and if so, the minimum acceptable period of release. (g) The receipt and delivery point. (h) Whether Option 1, 2, or 3 shall be used to determine the highest valued bid. If Option 3 is selected, Releasing Shipper must describe the criteria by which bids are to be evaluated. (i) Whether the Releasing Shipper wants PGT to market its released capacity. (j) Whether the Releasing Shipper requests to waive the creditworthiness requirements and agrees in such event to remain liable for all charges, or, if the release is for one year (365 days) or less, whether Releasing Shipper requests that the creditworthiness provisions of Paragraph 18.3(A)(1)(c) shall apply. (k) Whether Releasing Shipper is a marketing or other affiliate of PGT. (l) If release is a prearranged release, the Prearranged Shipper must be qualified pursuant to the criteria of Paragraph 28.6(a) unless waived above. Releasing Shipper shall include the Prearranged Shipper bid information pursuant to Paragraph 28.6(b) with its release information and shall indicate whether the Prearranged Shipper is affiliated with PGT or the Releasing Shipper. (m) Any special nondiscriminatory terms and conditions applicable to the release. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: MAY 31, 1994 Effective: MAY 21, 1994 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-211-000, , dated MAY 20, 1993 60 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 93 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.3 Notice Requirements (Continued) (n) Tie-breaker method preferred: (1) pro rata, (2) lottery, (3) order of submission (first- come/first-serve), (4) other. Other method must be objectively stated, administratively feasible as determined by PGT and nondiscriminatory. If none are selected, the system defaults to pro rata. (o) Recall provisions. These provisions must be objectively stated, nondiscriminatory, applicable to all bidders, operationally and administratively feasible as determined by PGT and in accordance with PGT's tariff. (p) The minimum rate (percentage of: reservation charge or a volumetric equivalent of the maximum reservation charge applicable to the Parcel on a 100% load-factor basis) acceptable to Releasor for this Parcel. (q) Whether the Releasing Shipper is willing to accept contingent bids that extend beyond the close of the Bid Period and, if so, any nondiscriminatory terms and conditions applicable to such contingencies including the date by which such contingency must be satisfied (which date shall not be later than the last day upon which PGT must award capacity) and whether, or for what time period, the next highest bidder(s) will be obligated to acquire the capacity should the winning contingent bidder be unable to satisfy the contingency specified in its bid. (r) Whether the Releasing Shipper wants to specify a longer bidding period for its Parcel than specified at Paragraph 28.8. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 61 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 94 First Revised Volume No. 1-A Superseding Original Sheet No. 94 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.4 Marketing of Capacity Fee PGT may act as a facilitator between a Releasing Shipper and a Replacement Shipper(s) that wishes to contract for that Releasing Shipper's capacity. All such Parcels must be posted on the EBB initially. A posting of a Parcel facilitated by PGT will include both the Parcel by the Releasing Shipper and the bid by the Prearranged Shipper. A marketing of capacity fee shall be negotiated between PGT and Releasing Shipper in a nondiscriminatory manner. Such a fee will apply when: a Releasing Shipper requests PGT to market released capacity, PGT actively markets such capacity beyond posting on the EBB, and such marketing results in capacity being released to a Replacement Shipper. 28.5 Posting of a Parcel The posting of a Parcel constitutes an offer to release the capacity provided a willing Replacement Shipper submits a valid bid consistent with PGT's Transportation General Terms and Conditions. The posting must contain the information contained in Paragraph 28.3. Any specific conditions posted by the Releasing Shipper must be operationally feasible, nondiscriminatory to other shippers, and in conformance with PGT's tariffs. If the Parcel is being released as a secondary release, then any recall provisions included in the primary release which may affect the re-release of this capacity must be included in the terms and conditions of the secondary release. Each Parcel will be reviewed by PGT prior to posting on the EBB for bidding. The receipt of a valid release will be acknowledged by the issuance of a release confirmation to the Releasing Shipper's EBB mailbox by PGT. It is the Releasing Shipper's sole responsibility to provide release and Prearranged Shipper bid information in advance of the close of the Posting Period. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993 62 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 95 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.5 Posting of a Parcel (Continued) Releasing Shippers who elect to release capacity and select Option 3 for the highest valued bid methodology and/or include, in their release, nondiscriminatory recall provisions and/or special terms and conditions are required to submit their request to release capacity by 12:00 p.m. Pacific Time at least two business days before the close of the Posting Period. This is to ensure adequate time for PGT to review and validate that the Option 3 criteria and/or any recall and special terms and conditions are not discriminatory. All Prearranged Shipper bids are subject to the Prearranged Shipper(s) meeting the preliminary qualifications as defined in Paragraph 28.6(a) for Replacement Shippers. A Parcel may be revised or withdrawn by the Releasing Shipper at any time prior to the close of the Posting Period. A Parcel cannot be revised after the close of the Posting Period. Parcels may be withdrawn subsequent to the close of the Posting Period and up until the close of the Bid Period only in situations where the Releasing Shipper has an unanticipated need for the capacity. In such instances, Releasing Shipper shall notify PGT via the EBB of its need to withdraw the Parcel due to an unanticipated need for the capacity. The withdrawal or revision of a Parcel will terminate all bids submitted for that Parcel to date. Replacement Shippers will need to resubmit their bids for the Parcel if the Parcel is resubmitted for release. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 63 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 96 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (a) Preliminary Qualification To bid for a Parcel, a Replacement Shipper must: pre-qualify by submitting a completed request for authority to bid for a Parcel, meet PGT's credit criteria, and execute an FTS-1 service agreement for capacity release as set forth in these Transportation General Terms and Conditions. Replacement Shippers may carry out these requirements through the use of PGT's EBB. Replacement Shippers are encouraged to pre-qualify in advance of any postings on PGT's EBB as credit requirements will take differing amounts of time to process depending on the particular financial profile of Replacement Shippers. The pre-qualification process will authorize a pre-set maximum monthly financial exposure level for the Replacement Shipper. Such exposure levels may be adjusted by PGT periodically re-evaluating a Replacement Shipper's credit-worthiness. Releasing Shippers may exercise their option to waive the credit requirements for any Replacement Shipper wishing to bid on a Parcel posted by that Releasing Shipper. Such waiver must be made on a nondiscriminatory basis. PGT must be informed of such waiver via the EBB before it will authorize such Replacement Shipper's participation with respect to that particular Parcel. In this instance, no pre-set maximum monthly financial exposure level is applicable. Should a Releasing Shipper waive the credit requirements for a Replacement Shipper, the Releasing Shipper shall be liable for all charges incurred by the Replacement Shipper in the event such Replacement Shipper defaults on payment to PGT for such capacity release service. (Continued) Issued by: P.G. Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 64 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 97 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (Continued) (a) Preliminary Qualification (Continued) The execution of the FTS-1 service agreement for capacity release is to be signed "electronically" by the Replacement Shipper. The Replacement Shipper shall execute the FTS-1 service agreement for capacity release (exhibits excluded) through the use of an authorization code procedure on the EBB. Upon notification by PGT of an award of a Parcel, PGT shall complete Exhibit R with the particulars of the awarded Parcel and Replacement Shipper shall execute, electronically, Exhibit R to the FTS-1 service agreement for capacity release. A hard copy of the FTS-1 service agreement for capacity release, including Exhibit R (signed by hand by PGT and Replacement Shipper), will follow subsequent to the awarding of a Parcel. A Replacement Shipper that subsequently obtains additional Parcels is not required to execute an additional FTS-1 service agreement for capacity release; rather, for each such additional Parcel obtained, an additional Exhibit R (designated sequentially "Exhibit R-2", "Exhibit R-3", etc.) will be executed and amended to such Replacement Shipper's FTS-1 service agreement for capacity release. Once the Replacement Shipper has met PGT's preliminary contractual and credit requirements, PGT will amend the Replacement Shipper's authorization to add access to the bidding and releasing portions of PGT's capacity release program on its EBB. This authorization, in combination with the Replacement Shipper's password, which will be unique and known only by the Replacement Shipper, will entitle the (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 65 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 98 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (Continued) (a) Preliminary Qualification (Continued) Replacement Shipper to submit a bid for a Parcel. Once a Replacement Shipper has acquired capacity, authority is granted to the Replacement Shipper to release that capacity. The execution of the FTS-1 service agreement for capacity release and use of this authorization to submit a bid or to release capacity will constitute an obligation on the part of the Replacement Shipper to be bound by the terms and conditions of PGT's capacity release program as set forth in these Transportation General Terms and Conditions. (b) Submitting a Bid All bids must be submitted through the use of PGT's EBB. Such bids shall be "open" for all participants to review. The particulars of all bids will be available for review but not the identity of bidders. PGT will post the identity of the winning bidder(s) only. A Replacement Shipper cannot request that its bid be "closed", nor can a Releasing Shipper specify that "closed" bids be submitted on its releases. A Replacement Shipper may submit only one bid per Parcel posted at any one point in time. Bids received after the close of the Bid Period shall be invalid. The Replacement Shipper may bid for no more than the quantity of the Parcel posted by the Releasing Shipper. Simultaneous bids for more than one Parcel are permitted. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 66 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 99 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (Continued) (b) Submitting a Bid (Continued) A valid bid to contract for a Parcel must contain the following information: (1) Replacement Shipper's legal name, address, telephone and fax numbers and the name and title of the individual responsible for authorizing the bid. (2) The identification of the Parcel bid on. (3) Term of service requested. The term of service must not exceed the term included in the Parcel. (4) Percentage of the applicable maximum rate, as identified in the Parcel, that Replacement Shipper is willing to pay. A Replacement Shipper may not bid below the minimum applicable charge or rate nor above the maximum authorized charge or rate for the Parcel. (5) The quantity desired not to exceed the quantity contained in the Parcel, expressed on a MMBtu/d delivered basis and greater than the minimum quantity acceptable to Replacement Shipper. (6) Under Options 1 or 2 acceptance or rejection of all recall provisions and special nondiscriminatory terms and conditions of service associated with the release. Rejection of any terms results in an invalid bid. (7) Whether or not Replacement Shipper is an affiliate of the Releasing Shipper. (8) A statement as to whether or not Replacement Shipper is affiliated with PGT. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 67 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 100 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.6 Bidding for a Parcel (Continued) (b) Submitting a Bid (Continued) (9) An affirmative statement that Replacement Shipper agrees to be bound by the terms and conditions of Rate Schedule FTS-1 and PGT's capacity release provisions in its tariff. (10) Whether the bid is a contingent bid and the contingencies which must be satisfied by the date specified by the Releasing Shipper in its posting of the Parcel. (c) Confirmation of Bids The receipt of a valid bid by PGT will be acknowledged by the issuance of a bid confirmation to the Replacement Shipper's EBB mailbox by PGT. It is the Replacement Shipper's sole responsibility to verify the correctness of the submitted bid and to take any corrective action necessary by resubmitting a bid when notified of an invalid or incomplete bid by PGT via the EBB. This must be done before the close of the Bid Period. (d) Withdrawn or Revision of Bids A previously submitted bid may be withdrawn or revised and resubmitted at any time prior to the close of the Bid Period with no obligation on the Replacement Shipper's part. Resubmitted bids must be equal to or greater in value than the initial bids. Lower valued bids will be invalid. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 68 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 101 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (a) Primary Allocation Winning bids for Parcels shall be awarded based on one of the following three options to be selected by the Releasing Shipper when posting a Parcel: Option 1 - Price Bids will be given priority based on the maximum rate bid as represented by a Replacement Shipper's bid of the percentage of: the maximum authorized reservation charge or a volumetric equivalent of the maximum reservation charge applicable to the Parcel on a 100% load factor basis. Releasing Shippers using a volumetric rate and wishing to accept reservation charge bids will be considered an Option 3 criteria. In this instance Releasing Shipper must define the method for evaluating such bids. A bid queue will be maintained for each individual Parcel. Option 2 - Net Present Value Bids will be given priority based on the net present value per MMBtu for the term of the bid according to the following formula: Present Value per unit = n (1 + i) -1 P * R * _________ n i (1 + i) where: P = percent of the rate or charge that the Replacement Shipper is willing to pay. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 69 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 102 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (Continued) (a) Primary Allocation (Continued) R = Rate or charge calculated as: The maximum authorized reservation charge (or a volumetric equivalent of the maximum reservation charge applicable to the Parcel on a 100% load factor basis) in effect at the time of the bid for service from the same receipt point to the same delivery point under the Releasing Shipper's rate schedule. i = FERC's annual interest rate divided by 12. n = number of periods for which the bidder wishes to contract, not to exceed the maximum periods to be released by the Releasing Shipper. For releases greater than or equal to one month, the period is the number of months. For releases less than one month the period is the number of days. A bid queue will be maintained for each individual Parcel. Option 3 - Releasing Shipper's Criteria for Highest Valued Bids Bids will be given priority based on the criteria established by the Releasing Shipper for determining the highest valued bids. The criteria must be objectively stated, applicable to all potential bidders, operationally and administratively feasible as determined by PGT, nondiscriminatory, and in conformance with PGT's tariff. A bid queue will be maintained for each individual Parcel. If Releasing Shipper does not specify an option for determining best bid, Option 2 will be the default option used. Under all options, PGT will evaluate and rank all bids for Parcels. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 70 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 103 First Revised Volume No. 1-A Superseding Original Sheet No. 103 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (Continued) (b) Right of First Refusal In the case of a Prearranged Shipper's bid for a Parcel with a term equal to one month or greater, at a rate other than at the highest valued bid, pursuant to the methodology specified by the Releasing Shipper, if the bid submitted by a subsequent Replacement Shipper exceeds the value of the Prearranged Shipper's bid, the Prearranged Shipper will be allowed to match the higher valued bid. The Prearranged Shipper will be allowed 1 business day from the close of the Bid Reconciliation Period to match the higher valued bid, otherwise, the allocation will be awarded to subsequent Replacement Shipper(s) in accordance with the primary and secondary allocation mechanisms. (c) Secondary Allocation To the extent there is more than one Replacement Shipper submitting a winning bid, the Parcel shall be allocated based on one of the following tie-breaker methodologies to be selected by the Releasing Shipper: pro rata, lottery, order of submission (first come/first serve), or by a method designated by the Releasing Shipper. Releasing Shipper's method must be objectively stated, applicable to all bidders, nondiscriminatory, administratively feasible as determined by PGT and in accordance with PGT's tariffs. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 71 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 104 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (Continued) (d) Confirmation of Allocation Upon each completion of an allocation, the successful Replacement Shipper(s) will be notified of the terms under which they have contracted for the awarded Parcel. The notification will be provided in the form of a notice in the Replacement Shipper's EBB mailbox. The notice will include an Exhibit R to the Replacement Shipper's Rate Schedule FTS-1 service agreement for capacity release which specifies the pertinent terms of the Replacement Shipper's bid as well as any additional terms specified by the Releasing Shipper. The Releasing Shipper will be notified of the terms under which its Parcel has been awarded. The notification will be provided in the form of a notice in the Releasing Shipper's EBB mailbox. The notification will include an Exhibit C to the Releasing Shipper's service agreement which specifies the pertinent terms of the credit to be applied to the Releasing Shipper as a result of the awarding of Parcel to the Replacement Shipper(s). In the case of multiple Replacement Shippers and Parcels, an Exhibit C to the Releasing Shippers' service agreement will be generated for each Parcel and Replacement Shipper. The Exhibit C's shall be numbered sequentially as Exhibit C-1, C-2, etc. (e) Purging of Expired Bids All unfulfilled bids, as well as any unfulfilled portions of bids which receive a partial award, will become ineffective as of the completion of bid reconciliation and the close of the Bid Period. Each unsuccessful Replacement Shipper which has bid shall receive a notice in its EBB mailbox indicating the ineffectiveness of the bid. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 72 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 105 First Revised Volume No. 1-A Superseding Original Sheet No. 105 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.7 Allocation of Parcels (Continued) (e) Purging of Expired Bids (Continued) Information regarding all bids for all Parcels shall be archived off-line before being purged from the system. 28.8 Scheduling of Parcels, Bids and Notifications (a) Rapid Release - one month or less, not prearranged. Posting Period - up to 12:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. Bid Period - a minimum period of 2 hours subsequent to the close of the Posting Period. The bid period may be extended by the Releasing Shipper. The Bid Period closes at 2:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. Notification of the results of the bidding for Parcels will be posted at 2:00 p.m. Pacific Time on the 2nd business day prior to the commencement of the Release Term. (b) Standard Release-greater than or equal to one day, not prearranged. Posting Period - up to 12:00 p.m. Pacific Time 5 business days prior to the commencement of the Release Term. Bid Period - a minimum period of 1 business day subsequent to the close of the Posting Period. The Bid Period closes at 2:00 p.m. Pacific Time 4 business days prior to the commencement of the Release Term. Bid Reconciliation Period - a period of 2 business days subsequent to the close of the Bid Period. The Bid Reconciliation Period closes at 2:00 p.m. Pacific Time 2 business days prior to the commencement of the Release Term at which time notification of the results of the bidding for Parcels will be posted. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 73 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 106 First Revised Volume No. 1-A Superseding Original Sheet No. 106 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.8 Scheduling of Parcels, Bids and Notifications (Continued) (c) Prearranged Deal-A - less than one calendar month. Releasing Shipper must inform PGT via the EBB of the particulars of the prearranged deal by 12:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. Posting Period - PGT will post the particulars of the prearranged deal no later than 12:00 p.m. Pacific Time 2 business days after the commencement of the Release Term. (d) Prearranged Deal-B - equal to or greater than one month at the highest valued bid pursuant to the methodology selected by the Releasing Shipper. Posting Period - Releasing Shipper must submit the particulars of the prearranged deal to PGT for posting on the EBB no later than 12:00 p.m. Pacific Time 2 business days before the commencement of the Release Term. (e) Prearranged Deal-C - greater than or equal to one day. Posting Period - up to 12:00 p.m. Pacific Time on the 6th business day before the commencement of the Release Term. Bid Period - a minimum period of 1 business day subsequent to the close of the Posting Period. The Bid Period closes at 2:00 p.m. Pacific Time on the 5th business day before the commencement of the Release Term. Bid Reconciliation Period - a period of 2 business days subsequent to the close of the Bid Period. The Bid Reconciliation Period closes at 2:00 p.m. Pacific Time on the 3rd business day before the commencement of the Release Term. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 74 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 107 First Revised Volume No. 1-A Superseding Original Sheet No. 107 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.8 Scheduling of Parcels, Bids and Notifications (Continued) (e) Prearranged Deal-C - greater than or equal to one day (Continued) Match Period - a period of 1 business day subsequent to the close of the Bid Reconciliation Period. The Match Period closes at 2:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. At that time results of the bidding shall be posted no later than 2:00 p.m. Pacific Time on the 2nd business day before the commencement of the Release Term. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 75 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 108 First Revised Volume No. 1-A Superseding Original Sheet No. 108 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) Reserved For Future Use. Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 76 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 109 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.9 Crediting, Billing Adjustments and Refunds (a) Eligibility PGT shall provide revenue credits to any Releasing Shipper which releases capacity to a Replacement Shipper pursuant to the provisions of Paragraph 28. (b) Monthly Crediting Procedure Revenue credits for released capacity shall be credited monthly as an offset a Releasing Shipper's reservation charge (or the volumetric equivalent of the reservation charge on a 100% load-factor basis applicable to the Releasing Shipper. This shall also be referred to in this Paragraph 28.9 as the equivalent volumetric rate) payable to PGT under the applicable rate schedule for the service that has been released. PGT shall credit each month to the Releasing Shipper's account 100% of the revenues from the charges invoiced to the Replacement Shipper(s) for the reservation charge (or equivalent volumetric rate). (c) Billing Adjustments PGT shall apply the revenues received from Replacement Shippers first to the reservation charge (or equivalent volumetric rate) next to the GRI reservation surcharge, applicable Gas Supply Restructuring Surcharge, delivery rate, GRI and ACA charges and any applicable interest and penalties billed to the Replacement Shipper. Should Replacement shipper default on payment to PGT of the reservation charge (or equivalent volumetric rate) PGT shall bill Releasing Shipper for such unpaid charges and apply interest to such adjustments in accordance with the provisions of Paragraph 8 of the Transportation General Terms and Conditions. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 77 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 110 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) 28.9 Crediting, Billing Adjustments and Refunds (Continued) (d) Excess Revenue Credits Releasing Shipper is entitled to excess revenue credits resulting when the reservation charge (or equivalent volumetric rate) revenues actually received by PGT from the Replacement Shipper(s) exceed the reservation charge (or equivalent volumetric rate) revenues which would have been received by PGT from the Releasing Shipper if capacity was not released. (e) Refunds PGT shall track all changes in its rates approved by the Commission. In the event the Commission orders refunds of any such rates charged by PGT and previously approved, PGT shall make corresponding refunds to all affected Shippers including Shippers receiving capacity release service. In such instances when rates to Replacement Shippers are reduced, PGT shall make corresponding adjustments to the crediting of revenues to Releasing Shippers for the period such refunds are payable. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 78 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 111 First Revised Volume No. 1-A Superseding Original Sheet No. 111 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) CAPACITY RELEASE TIMELINES STANDARD RELEASE (GREATER THAN OR EQUAL TO ONE DAY) [GRAPH] Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 79 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 112 First Revised Volume No. 1-A Superseding Original Sheet No. 112 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) CAPACITY RELEASE TIMELINES RAPID RELEASE (EQUAL TO OR LESS THAN ONE MONTH) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 80 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 113 First Revised Volume No. 1-A Superseding Original Sheet No. 113 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) CAPACITY RELEASE TIMELINES PRE-ARANGED DEAL A (LESS THAN ONE CALENDAR MONTH) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 81 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 114 First Revised Volume No. 1-A Superseding Original Sheet No. 114 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) CAPACITY RELEASE TIMELINES PRE-ARRANGED DEAL B (EQUAL TO OR GREATER THAN ONE MONTH AT HIGHEST VALUE BID) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 82 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 115 First Revised Volume No. 1-A Superseding Original Sheet No. 115 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE (Continued) CAPACITY RELEASE TIMELINES PRE-ARRANGED DEAL-C (GREATER THAN OR EQUAL TO ONE DAY) [GRAPH] Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 83 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 116 First Revised Volume No. 1-A Superseding Sheet Nos. 116-118 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) Reserved for Future Use Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 84 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 119 First Revised Volume No. 1-A Superseding Original Sheet No. 119 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. FLEXIBLE RECEIPT AND DELIVERY POINTS 29.1 Firm Service (a) Addition of a Receipt Point Any firm Shipper receiving service under Part 284 of the Commission's regulations is entitled to use the receipt point specified in its service agreement as a primary receipt point. A firm Shipper may add a secondary receipt point, provided the secondary receipt point is downstream of the primary receipt point at any time during the life of the contract. Firm Shippers who are billed under a reservation charge and a delivery rate will continue to be billed reservation charges based on the primary receipt point while delivery rates, including fuel, will be calculated on the receipt point actually used. To the extent additional meter station capacity or other facilities are required to effect the receipt point change, PGT will construct the additional capacity consistent with Paragraph 18.5. (b) Changing a Receipt Point A firm Shipper may change primary receipt points to a downstream receipt point but will continue to be billed reservation charges based on the original primary receipt point. Changes in receipt points will be permitted provided sufficient receipt point capacity exists at the receiving meter station and subject to any operating constraints. To the extent additional meter station capacity or other facilities are required to effect the receipt point change, PGT will construct the additional capacity at the firm Shipper's expense consistent with Paragraph 18.5. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 85 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 120 First Revised Volume No. 1-A Superseding Original Sheet No. 120 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued) 29.1 Firm Service (Continued) (c) Addition of a Delivery Point Each firm Shipper is entitled to an allocation of its MDQ to a delivery point(s) as its primary delivery point(s). A firm Shipper may add secondary delivery points provided the secondary delivery points are upstream of the primary delivery point, at any time during the life of the contract. In this case, the firm Shipper will continue to be billed any applicable reservation charges based on the primary delivery point; however, delivery rates, including fuel, will be calculated based on the delivery point actually used. A firm Shipper with primary deliveries allocated to a minor delivery point may add secondary delivery points to its contract provided that the addition of the secondary delivery point does not materially impact service to other firm Shippers. To the extent additional meter station capacity is required to effect the delivery point(s) change, and subject to any operating constraints PGT will construct the additional capacity consistent with Paragraph 18.5. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 86 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 121 First Revised Volume No. 1-A Superseding Original Sheet No. 121 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued) 29.1 Firm Service (Continued) (d) Changing a Delivery Point A firm Shipper may change primary delivery points, to an upstream delivery point but will continue to be billed reservation charges based on the original primary delivery point. Changes in delivery points will be permitted provided sufficient delivery point capacity exists at the delivery meter station. To the extent additional meter station and subject to any operating constraints capacity is required to effect the delivery point change, PGT will construct the additional capacity at the firm Shipper's expense consistent with Paragraph 18.5. A firm Shipper with primary deliveries allocated to a minor delivery point may change primary delivery points in its contract provided that the change of primary delivery point does not materially impact service to other firm Shippers. 29.2 Interruptible Service (a) Change of a Receipt/Delivery Point Interruptible Shippers will have the right to flexible receipt and delivery points, at a lower priority than firm or released services. (b) Addition of a Receipt Point Except as otherwise provided in this paragraph, Shippers receiving service under any Part 284 interruptible transportation rate schedule may add any receipt point downstream of the primary receipt point on the PGT system at any time during the life of the contract with no effect on the Interruptible Shipper's previously granted interruptible transportation priority. However, requests by an interruptible Shipper to increase its total MDQ and/or to add an upstream receipt point will be considered a new request for service. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 87 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 122 First Revised Volume No. 1-A Superseding Original Sheet No. 122 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued) 29.2 Interruptible Service (Continued) (c) Addition of a Delivery Point An Interruptible Shipper may request interruptible service at additional delivery points at any time. The request of an additional downstream delivery point, or a request to increase the delivery quantity at an existing delivery point, will be considered a new request for service with priority assigned in accordance with Paragraph 19.2. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 88 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 123 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS 30.1 Purpose This Paragraph 30 establishes the means by which PGT shall recover GSR Costs. PGT will make one or more separate rate filings to recover GSR Costs pursuant to this Paragraph 30. 30.2 Definitions The following defines certain terms as they are used in this Paragraph 30: (a) "Gas Supply Restructuring Costs" shall mean amounts in cash or other consideration eligible for recovery under Order Nos. 500, et seq., or 528, et seq., or 636, et seq., or which are incurred to restructure, reform or terminate the existing International Contract between PGT and A&S and underlying A&S gas supply contracts, or to resolve claims by Canadian gas suppliers related to past or future liabilities or obligations of PGT or A&S under the International Contract and underlying A&S gas supply contracts. (b) "The Initial GSR Cost Collection Period" will consist of the three (3) years commencing with the effective date of the rate filing to recover GSR Costs. An Initial GSR Cost Collection Period shall apply to each rate filing PGT makes to recover GSR Costs. (c) "Carryover GSR Cost Collection Period" will consist of the extension of the Initial GSR Collection Period in accordance with Paragraph 30.6 hereof to complete the full recovery (but no overrecovery) of PGT's GSR Costs. (d) "Approved GSR Costs" shall mean those GSR costs as defined in Paragraph 30.2(a) above, which are approved by FERC for recovery by PGT through the Transition Cost Recovery Mechanism as defined in this Paragraph 30. (e) "Northwest Shippers", for purposes of this paragraph, are defined as Washington Natural Gas Company, Cascade Natural Gas Company, Washington Water Power Company/WP Natural Gas and Northwest Natural Gas Company. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 89 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 124 First Revised Volume No. 1-A Superseding Original Sheet No. 124 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued) 30.3 Applicability of GSR Transition Costs GSR Transition Costs shall be applicable to all Shippers except those firm Shippers paying incremental rates on PGT which are also Supporting Parties to the FERC-approved settlement in Docket No. RS92-46-000. 30.4 Recovery of Surcharge Amounts PGT shall recover from each Shipper meeting the applicability criteria defined in Paragraph 30.3 the affected Shipper's GSR Surcharge amounts and Direct Bill, if applicable, during the Initial GSR Cost Collection Period and shall continue to recover such amounts during any applicable Carryover GSR Cost Collection Period as necessary to complete the full recovery (but no overrecovery) of PGT's GSR Costs. 30.5 Transition Cost Recovery Mechanism (a) Absorption -- PGT's shareholder shall absorb 25% of all Approved GSR Costs. (b) Direct Bill -- 25% of all Approved GSR Costs will be recovered by PGT through a Direct Bill. A Direct Bill will be assessed to PG&E for 100% of the Direct Bill amount, excluding the amount to be collected from the Northwest Shippers and credited against the Direct Bill portion as defined in Paragraph 30.5(d). PG&E may pay its Direct Bill in a lump sum, plus carrying charges on the principal amount accrued, in accordance with Paragraph 30.5(e) until the payment is made. In lieu of paying the Direct Bill in a lump sum, PG&E may elect one of three payment schedules. PG&E's Direct Bill amount and the monthly amount due under each extended payment option, which shall include carrying charges accrued on the unpaid balance in accordance with Paragraph 30.5(e), shall be specified in the Statement of Effective Rates and Charges of First Revised Volume No. 1-A. (c) GSR Transition Cost Surcharge -- 50% of all Approved GSR Costs will be recovered by PGT through a volumetric MMBtu-mile surcharge. The GSR Transition Cost Surcharge shall include any applicable carrying charges accruing on the unrecovered balance. The GSR Transition Cost Surcharge shall be stated in the Statement of Effective Rates and Charges of PGT's FERC Gas Tariff First Revised Volume No. 1-A as the same may change from time to time, depending on PGT's GSR Costs. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: DECEMBER 10, 1993 Effective: NOVEMBER 15, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RP94-24-000, et al., dated NOVEMBER 12, 1993 90 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 125 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued) 30.5 Transition Cost Recovery Mechanism (Continued) (d) Northwest Shippers' GSR Cost Responsibility -- All Northwest Shippers (excluding Washington Natural Gas Company) shall pay a Direct Bill and Washington Natural Gas shall pay a GSR transition cost surcharge (different from that provided in (c) above) for their share of GSR transition costs. The Northwest Shippers' responsibility shall be equal to 1.3 percent of the Approved GSR costs that are not absorbed by PGT and in any event shall not exceed a total of $1,454,000. Of this amount, one-third, up to $485,000, will be credited against the amount allocated to the Direct Bill as described in Paragraph 30.5(b), and two-thirds, up to $969,000, will be credited against the amount allocated to the GSR surcharge provided in Paragraph 30.5(c). The amounts allocated to the Northwest Shippers as a group will be allocated among the individual Northwest Shippers based on the percentages shown below and will not exceed the applicable total amount for each Shipper.
Total Percentage Amount Washington Natural Gas Company 55.02% up to $ 800,000 Cascade Natural Gas Corporation 24.07% up to 350,000 Washington Water Power Company/ WP Natural Gas 18.57% up to 270,000 Northwest Natural Gas Company 2.34% up to 34,000 Total Northwest Shippers 100.00% $1,454,000
Washington Water Power Company/WP Natural Gas (WWP), Cascade Natural Gas Corporation (CNG), and Northwest Natural Gas Company (NNG) will be billed and will pay immediately all amounts of the Approved GSR Costs allocated to them up to the total maximums noted above. The total amount allocated to Washington Natural Gas Company (WNG) will be recovered through a volumetric surcharge over a three-year amortization period based on the approved commodity throughput for WNG. Any amounts not recovered at the end of the 36-month amortization period will be due and payable in one lump sum. Once the maximum GSR Costs applicable to Northwest Shipper(s), as such amounts may be adjusted pursuant to the application of rolled-in rates on the PGT system, have been collected then the GSR Cost tariff provisions will no longer apply to such Northwest Shipper(s). (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 91 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 126 First Revised Volume No. 1-A Superseding Original Sheet No. 126 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued) 30.5 Transition Cost Recovery Mechanism (Continued) (e) Carrying Charges -- Carrying charges shall accrue beginning on the effective date of PGT's filing to recover GSR costs or the date PGT initiates payment for GSR costs, whichever is later. Carrying charges shall be calculated in accordance with Section 154.67 of the Commission's regulations. 30.6 Reconciliation (a) At the conclusion of the Initial GSR Cost Collection Period, PGT will determine its GSR Costs and the actual amounts of GSR Transition Cost Surcharge revenues. (b) If PGT's collections hereunder shall equal or exceed its GSR Costs, PGT shall file to terminate further collections hereunder. The amount of any excess collected shall be repaid to all Shippers affected hereby in proportion to the principal amount of GSR Transition Cost Surcharge payments they have provided pursuant to this Paragraph 30. Within ninety (90) days of the termination of collections pursuant to this Paragraph 30, PGT will submit a report to the Commission setting out a comparison of its GSR costs and the amounts collected hereunder and any repayments to be provided hereunder. Within thirty (30) days of the Commission's approval of such report, repayments, with applicable carrying charges, shall be paid. (c) If PGT's collections hereunder are less than its GSR Costs, PGT shall be permitted to recover such deficiency, including carrying charges, during the Carryover GSR Cost Collection Period by filing with the Commission GSR Transition Cost Surcharges within ninety (90) days of the conclusion of the Initial GSR Cost Collection Period. The GSR Transition Cost Surcharge will be determined by dividing the remaining GSR costs by the applicable quantities underlying PGT's then-effective rates. The GSR Transition Cost Surcharge shall be effective on the first day of the month following Commission approval of such filing. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993 92 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 127 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 31. FORMER BUYER'S OBLIGATION FOR UNRECOVERED ACCOUNT NO. 191 AMOUNTS 31.1 Purpose This Paragraph 31 establishes the disposition of PGT's FERC Account No. 191 as it exists on the day preceding the effectiveness of PGT's Compliance Filing in Docket No. RS92-46-000. 31.2 Disposition of Account No. 191 Amounts Upon the effectiveness of PGT's Compliance Filing in Docket No. RS92-46, PGT shall be permitted to direct bill to Pacific Gas and Electric Company (PG&E): (1) the total unrecovered amounts remaining in PGT's FERC Account No. 191; and (2) direct bill all prior period billing adjustments which PGT shall become obligated to pay, if such prior period adjustments arise from services provided or Gas purchased prior to the effectiveness of this Paragraph 31. Upon the effectiveness of this Paragraph 31, the unrecovered Account No. 191 Deferred Account Balance shall be adjusted to include a final reconciliation of amounts for exchange transactions and transportation imbalances recorded in Account No. 806. If the balance of PGT's FERC Account No. 191 shall be a credit balance, or PGT later receives refunds from its suppliers for services provided prior to the effectiveness of this Paragraph 31, PGT shall refund such balance or refunds to PG&E. 31.3 Amount of Direct Bills and Refund The amount of the Direct Bill and Refunds to PG&E shall consist of a prior Period Adjustment Component, as described in Paragraph 31.4 hereof. Each component shall reflect demand and commodity charges, as may be appropriate. 31.4 Calculation of Prior Period Adjustment Component (a) The Prior Period Adjustment Component of PG&E's Direct Bill shall be computed by adding the commodity and demand portions of each prior period adjustment which has been charged or refunded to PGT, as the case may be and which have not been reflected in PGT's deferred account prior to application of this Paragraph 31. The Prior Period Adjustment component shall be limited to a nine-month period which shall commence on the effective date of this tariff. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 93 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 128 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 31. FORMER BUYER'S OBLIGATION FOR UNRECOVERED ACCOUNT NO. 191 AMOUNTS (Continued) 31.4 Calculation of Prior Period Adjustment Component (Continued) (b) Carrying charges on all such amounts shall be calculated using the methods specified in Section 154.67 of the Commission's regulations. 31.5 Nature of Obligations (a) The entire amount of PG&E's obligation to PGT as described in this Paragraph 31, including its subsections, shall be deemed to be due on the day prior to the date this Paragraph becomes effective. (b) PGT shall invoice PG&E for the Direct Bill component hereunder on or after the tenth day of the month following the effectiveness of this Paragraph 31. The entire amount of PG&E's unrecovered Account No. 191 Direct Bill Amount shall be payable ten (10) days thereafter. Should PG&E fail to pay any amount which shall become due hereunder interest thereon shall accrue at the rate computed using the factors specified in Section 154.67 of the Commission's regulations, until such time as the full amount due has been paid or collected. (c) PG&E shall have the option, in lieu of a lump sum payment of the total Direct Bill for its obligation for unrecovered Account No. 191 amounts, of paying twelve (12) consecutive monthly payments equal to 1/12th of such amount. Carrying charges on the total unrecovered Account No. 191 Direct Bill amount shall commence on the effective date of this Paragraph 31 and shall be calculated and included on each monthly invoice to the extent PG&E elects the twelve (12) month payment option. Notwithstanding such election, PG&E may, at any time, pay the entire amount of its unpaid share of the unrecovered Account No. 191 Direct Bill amount to PGT, with no further obligation for carrying charges. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 94 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 129 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 31. FORMER BUYER'S OBLIGATION FOR UNRECOVERED ACCOUNT NO. 191 AMOUNTS (Continued) 31.5 Nature of Obligations (Continued) (d) The Prior Period Adjustment component shall be filed six (6) and twelve (12) months after the effective date of this Paragraph 31. Additional unrecovered Account No. 191 amounts will be direct billed in accordance with Paragraph 31.5(b), and refunds of Account No. 191 amounts will be paid by PGT to PG&E after approval of the Commission. The filing made twelve (12) months after the effective date of this Paragraph 31 shall constitute PGT's final flowthrough of the Prior Period Adjustment component. (e) Carrying charges on unpaid unrecovered Account No. 191 Direct Bill amounts in the event PG&E elects to extend its payments in accordance with Paragraph 31.5(c) for the Prior Period component shall be calculated using the methods specified in Section 154.67 of the Commission's regulations. (f) PGT will provide an accounting of the costs involved in the closeout of Account No. 191, and will provide any refund to PG&E within 60 days after the effective date of the tariff provisions submitted by PGT at Docket No. RS92-46-000 and, if necessary, subsequent adjustments will be refunded to or collected from PG&E within 60 days of these adjustments. 32. EQUALITY OF TRANSPORTATION SERVICE PGT hereby states that the terms and conditions of service for all unbundled sales and transportation services provided in PGT's FERC Gas Tariff Second Revised Volume No. 1 and First Revised Volume No. 1-A, are provided on a basis that is equal in quality for all Shippers. All Shippers can access all sellers of gas and receive the same quality of service on PGT whether their gas supplies are purchased from PGT or any other seller. Furthermore, no preference is accorded to any affiliate of PGT for sales and transportation services provided by PGT. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 95 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 130 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 33. RIGHT OF FIRST REFUSAL UPON TERMINATION OF FIRM SHIPPER'S SERVICE AGREEMENT Firm Shippers (original capacity holders) under PGT's firm transportation rate schedules of First Revised Volume No. 1-A shall have the right of first refusal at the termination of their service agreements. Original capacity holders must notify PGT one year prior to termination of their intent to terminate the service agreement. One year prior to the expiration of the service agreement, PGT will post a notice on its EBB that the original capacity holder's service agreement will terminate in one year and the original capacity holder has either elected or not elected to terminate. 33.1 In the event original capacity holder elects termination, PGT shall subject this capacity to a bidding process. PGT shall require bids be submitted no later than 6 months prior to the service agreement expiration. The bid period will be 2 months. PGT will announce the bid winner(s) 1 month after the close of the bid period. Tied bids will be awarded on a pro rata basis. Winning Shipper(s) and PGT must execute a new firm transportation service agreement prior to service commencement. 33.2 In the event original capacity holder does not elect termination, PGT will commence open bidding 6 months prior to the service agreement termination. The bid period will be 1 month. The original capacity holder will have 1 month from the close of the bid period to match the highest bid(s). PGT will announce the winning bid(s) within 1 month after the close of the match period. If the original capacity holder matches the highest bid(s), the capacity is awarded to the original capacity holder. If the original capacity holder does not match the highest bid(s), the original capacity holder's bid shall be rejected. If there is more than one winning bid, PGT shall award capacity on a pro rata basis. New Shippers must execute a firm transportation service agreement with PGT prior to service commencement. Original capacity holder is allowed to retain a portion of its capacity by matching price and term according to the procedure outlined in this provision. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 96 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 131 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 33. RIGHT OF FIRST REFUSAL UPON TERMINATION OF FIRM SHIPPER'S SERVICE AGREEMENT (Continued) 33.3 Bids shall be evaluated on the net present value incorporating price and term. The price shall be the rate Shippers are willing to pay up to the maximum authorized rate. The maximum term is 20 years. 33.4 If there are no competing bids other than that of the original capacity holder, the rate and terms of continuing service is to be negotiated between existing capacity holder and PGT. In addition, in this instance, if the existing capacity holder agrees to pay the maximum authorized rate, the existing capacity holder may determine the term it desires and PGT must extend its contract to the existing capacity holder accordingly. 33.5 Shippers who terminate their service agreements are not liable for any reservation charges or other charges applicable to the new Shipper contracting for this capacity. 33.6 Only bona fide bids will be accepted. A bona fide bid offer shall be: (a) submitted via PGT's EBB; (b) accepted in principle; and (c) pursuant to an arms-length transaction. If the Service Agreement is not executed within 30 days, the request for capacity shall expire without prejudice to the prospective Shipper's right to submit a new request for capacity. PGT shall then notify the Shipper via the EBB of the acceptable offer, if any, having the next greatest economic value in accordance with the provisions of this Paragraph. If there is no other acceptable offer, the Shipper may continue service in accordance with this Paragraph. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 97 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 132 First Revised Volume No. 1-A Superseding Substitute Original Sheet No. 132 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD 34.1 General PGT shall use its Electronic Bulletin Board (EBB), "Pacific Trail" for capacity release. PGT shall maintain an EBB which will provide a range of electronic pipeline services and information to all parties on a nondiscriminatory basis. The EBB is available to any party that has compatible equipment for electronic communication and transmission of data. Access to the EBB is obtained by contacting PGT's Gas Control Department at 1-800-238-2781 and requesting a user identification. The EBB will operate 24 hours a day; however, certain functions may be limited to specific operating times during the business day. There is no direct connection charge to use the EBB. However, PGT reserves the right to change the telephone access from an "800" number to a "900" number at its sole discretion. PGT shall exercise reasonable efforts to ensure the accuracy and security of information presented on the EBB. 34.2 Menu of Services and Information PGT's EBB will provide the following main menu of services and information: (a) Capacity Release (b) Bulletins and Capacity Available (c) Nominations (d) Submit Request for Firm or Interruptible Service (e) Interruptible Transportation Queue (f) Tariffs and Rates (g) Account Status of Shipper (h) Marketing Affiliate Information (i) Buy-Sell Transactions in California (j) Offers to Purchase Capacity (k) Procedures for Filing Complaints (l) E-mail to Other Shippers/PGT System Administrator (m) EBB Mailbox (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 98 Pacific Gas Transmission Company FERC Gas Tariff Substitute Original Sheet No. 133 First Revised Volume No. 1-A Superseding Original Sheet No. 133 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD (Continued) 34.2 Menu of Services and Information (Continued) (a) Capacity Release The capacity release menu would allow the following options: (1) Review Available Released Parcels (2) Submit/Check Status of Request for Authority to\ Bid/Release Capacity (3) Post/Withdraw Capacity for Release (4) Submit/Withdraw Bid for Released Capacity (5) Review the Status of Shipper's Active Bids (6) Review the Status of Shipper's Active Released Parcels (7) Review Shipper's Authority to Bid for Released Capacity (8) Review Transaction Log of Previous Releases (b) Bulletins and Capacity Available The bulletins and capacity available menu would allow the following options: Capacity Availability Information: (1) At Receipt Points (2) At Major Delivery Points (3) At Minor Delivery Points (4) Projected Capacity (5) PGT Maintenance Schedules (6) Whether the Capacity is Available From PGT or Through PGT's Capacity Release Program (7) Operational Bulletins (8) Regulatory Bulletins (including: (1) any assignment by PGT of any portion of its international contract if PG&E reduces its firm sales rights and (2) the posting of notices of conversion) (c) Nominations (1) Submit Nominations to PGT Gas Control (2) Review Confirmation (3) E-mail to Gas Control (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993 99 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 134 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD (Continued) 34.2 Menu of Services and Information (Continued) (d) Submit Request for Firm or Interruptible Service (e) Interruptible Transportation Queue (f) Tariffs and Rates The tariffs and rates menu would allow the following options: (1) Transportation Rates (2) Transportation Rate Discounts (including negotiated ITS-1 rates) (3) First Revised Volume No. 1-A - Tariff (4) Second Revised Volume No. 1 - Tariff (g) Account Status of Shippers (h) Marketing Affiliate Information The marketing affiliate information would allow the following options: (1) Transportation request data (2) Receipt/delivery point data (3) Delivery point discount data (i) Buy-Sell Transactions in California PGT will provide the following information: (1) Rate Schedule Under Which Buy/Sell Transaction Is Conducted (2) Name of End User (3) Maximum Daily Amount To Be Purchased and Transported (4) Receipt and Delivery Points (5) Term of Service (6) Other Terms and Conditions (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 100 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 135 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD (Continued) 34.2 Menu of Services and Information (Continued) (j) Offers to Purchase Capacity PGT shall post the following information on offers to purchase capacity: (1) Legal Name of Offerer (2) Name, telephone Number, Fax Number, Address of Contact Person and Alternate Contact Person (3) Firm or Interruptible Service Requested (4) Amount of Capacity Sought (5) Term Sought (6) Other Information (k) Procedures for Filing Complaints The Procedures for filing complaints menu offers the following options: (1) Review Complaint Procedure (2) Enter a Complaint (3) Send E-Mail to PGT System Administrator (l) E-Mail to other Shippers/PGT Systems Administrator (m) EBB Mailbox (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 101 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 136 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 34. ELECTRONIC BULLETIN BOARD (Continued) 34.3 Historical Information PGT will back up daily transaction information on the EBB. This historical information shall be kept for a three-year period and may be archived off-line. Information that may be accessed includes Parcel information and bid information associated with that Parcel, including the identity of the winning bid and bidder. PGT will provide access to historical data in one of the following manners: (a) Direct access by parties via the EBB. In such cases, data may be viewed, down loaded to a computer or printed by the party. (b) PGT may elect to archive historical data off-line. Parties may access this data by sending a written or an electronic mail request to the PGT Capacity Release System Administrator requesting such historical data. PGT will make such information available to Shippers. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 102 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 137 First Revised Volume No. 1-A Superseding Original Sheet No. 137 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 35. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES Interruptible Transportation Revenue Credits (a) Applicability. Revenue credits from interruptible transportation revenues received by PGT from Rate Schedule ITS-1 Shippers shall be provided to PGT's firm Shippers under Rate Schedules FTS-1, and T-3 (Eligible Shippers), excluding Shippers receiving service under a Capacity Release Service Agreement. (b) Crediting Percentage. PGT shall credit to Eligible Shippers 90 percent of interruptible transportation revenues received during each 12-month period, commencing November 1st of each year, but only to the extent that such transportation revenues exceed the amount of fixed costs which were allocated to interruptible transportation (Cost Allocation Amount) by PGT as part of designing PGT's effective transportation rates during such 12-month period. To the extent that PGT is required to provide interruptible transportation revenue credits during any period during which this Paragraph 35 shall be or shall have been in effect for less than 12 months, a "Short Period", PGT shall pro rate the Cost Allocation Amount by the number of days during such Short Period as compared to the total number of days in such 12 months. To calculate the interruptible transportation revenue credit due under the provisions of this paragraph, where applicable, such pro rated Cost Allocation Amount shall be compared to PGT's actual interruptible revenues for the Short Period. (c) Timing of Credits. Within 45 days after November 1st of each 12-month period or after the end of a Short Period, if applicable, PGT shall determine the total amount of the applicable Rate Schedule ITS-1 revenues received during the 12-month period or Short Period and the distribution of the interruptible revenue credits due to Eligible Shippers as described below. Such revenue credits shall be reflected as a credit billing adjustment in the next invoices rendered to the Eligible Shippers. In the event that such credit billing adjustment would result in a credit total invoice to any Shipper, PGT will refund the excess credit billing adjustment to the Shipper in cash within 15 days after determination of the amount of the credit due to the Shipper. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994 103 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 138 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 35. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES (Continued) Interruptible Transportation Revenue Credits (Continued) (d) Exclusion. Revenue credits shall not be awarded for that portion of interruptible revenues that are attributable to: (1) relate to the recovery by PGT of variable costs, which portion shall be equal to the minimum usage charge for Rate Schedule FTS-1, (2) the recovery of Gas Supply Restructuring (GSR) costs to be recovered by a GSR volumetric surcharge under Rate Schedule ITS-1, and (3) relate to other volumetric surcharges such as GRI and ACA. (e) Distribution Method. Interruptible transportation revenue credits shall be credited to each Eligible Shipper on a pro rata basis in proportion to the reservation revenues received during the 12-month period or Short Period from each Eligible Shipper divided by the total reservation revenue for each Eligible Shipper received during such period. The reservation revenues shall include the reservation charges which the Eligible Shippers actually pay prior to the distribution of all revenue credits, and including reservation charges applicable to capacity which was released into PGT's Capacity Release Programs during the 12-month period year or Short Period by the Eligible Shipper. (f) PGT shall pay interest to Eligible Shippers on any revenue credits from the date such credits accrue. Such interest shall be calculated based upon the rate of interest specified in Section 154.67(c) of the Commission's regulations. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 104 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 139 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 36. CAPACITY RELINQUISHMENT Firm capacity holders are permitted to permanently relinquish capacity up to 60 days after issuance of an order accepting this tariff sheet by the FERC approving PGT's compliance filing at Docket No. RS92-46-000 or the effective date of the filing, whichever is later. PGT shall permit such capacity relinquishment only if a qualified Replacement Shipper(s) is found willing to assume the capacity for at least the remaining contract term and agrees to pay the Reservation Charge, including surcharges, the Relinquishing Shipper is obligated to pay. PGT shall post a notice of relinquishment on the EBB for competitive bidding. Bids must be for at least the minimum term of the remaining contract term but may not be for a term of more than the remaining contract term plus 20 years. Bids will be evaluated on a net present value basis utilizing the formula defined in Paragraph 28. Tie bids will be awarded on a pro-rata basis. Issued by: P.G.Rosput, Senior Vice President Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993 105 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 140 First Revised Volume No. 1-A GENERAL TERMS AND CONDITIONS (Continued) 37. ADJUSTMENT MECHANISM FOR FUEL, LINE LOSS, AND OTHER UNACCOUNTED FOR GAS PERCENTAGES The effective fuel and line loss percentages under Rate Schedules FTS-1 and ITS-1 shall be adjusted downward to reflect reductions and may be adjusted upward to reflect increases in fuel usage and line loss in accordance with this Section 37. 37.1 Computation of Effective Fuel and Line Loss Percentage The effective fuel and line loss percentage shall be the sum of the current fuel and line loss percentage and the fuel and line loss surcharge percentage. 37.2 The Current Fuel and Line Loss Percentage (a) For each month, the current fuel and line loss percentage shall be determined in accordance with Section 37.2(c) hereof. The current fuel and line loss shall be effective from the first day of such month and shall remain in effect for the month. (b) The current fuel and line loss percentage to be applicable for the month shall be posted on PGT's Electronic Bulletin Board not less than seven (7) days prior to the beginning of the month. (c) The current fuel and line loss percentage for the month shall be determined on the basis of (1) the estimated quantities of gas to be delivered by PGT for the account of Shippers during such month and (ii) the projected quantities of gas that shall be required for fuel and line loss during such month, adjusted for overrecoveries or underrecoveries of fuel and line loss during such month preceding the month in which the current fuel and line loss percentage is posted; provided, that the percentage shall not exceed the maximum current fuel and line loss percentage and shall not be less than the minimum current fuel and line loss percentage set forth on the Statement of Effective Rates and Charges. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: DECEMBER 22, 1993 Effective: JANUARY 22, 1994 106 Pacific Gas Transmission Company FERC Gas Tariff Substittute Original Sheet No. 141 First Revised Volume No. 1-A Superseding Original Sheet No. 141 GENERAL TERMS AND CONDITIONS (Continued) 37. ADJUSTMENT MECHANISM FOR FUEL, LINE LOSS AND OTHER UNACCOUNTED FOR GAS PERCENTAGES (Continued) 37.2 The Current Fuel and Line Loss Percentage (Continued) (d) At least thirty (30) days prior to July 1 and January 1, PGT shall file with the Commission schedules supporting the current fuel and line loss percentages applicable during the six (6) months ending April 30 and October 31, respectively. 37.3 The Fuel and Line Loss Surcharge Percentage (a) For each six (6) month period beginning July 1 and January 1, the fuel and line loss surcharge percentage shall be determined in accordance with Section 37.3(c) hereof. The fuel and line loss surcharge percentage shall become effective on July 1 and January 1 and shall remain in effect for the six (6) month period ending December 31 and June 30, respectively. (b) At least thirty (30) days prior to each July 1 and January 1, PGT shall file with the Commission and post, as defined by Section 154.16 of the Commission's regulations, the fuel and line loss surcharge percentage, together with supporting documentation. (c) The fuel and line loss percentage shall be computed by (i) determining PGT's actual fuel and line loss for the six (6) month period ending April 30, if the effective date is July 1, or October 31, if the effective date is January 1, (ii) subtracting the actual quantities retained by PGT during such six (6) month period, and (iii) dividing the result by the estimated quantities of gas to be delivered by PGT for the account of Shippers during the six month period beginning with the effective date of the fuel and line loss surcharge percentage. If the percentage so determined is 0.0001% or less, the fuel and line loss surcharge percentage shall be deemed to be zero. Issued by: P.G.Rosput, Senior Vice President Issued on: JANUARY 10, 1994 Effective: JANUARY 22, 1994 Issued to comply with order of the Federal Energy Regulatory Commission, Docket No. TM94-2-86-000, dated DECEMBER 30, 1993 107 Pacific Gas Transmission Company FERC Gas Tariff Original Sheet No. 142 First Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 38. CREDITING OF PARKING AND AUTHORIZED IMBALANCE SERVICE REVENUES 38.1 Applicability Revenue credits from Parking and Authorized Imbalance Service revenues received by PGT from Rate Schedule PS-1 and AIS-1 Shippers shall be provided to all of PGT's Shippers who are receiving transportation service under a valid transportation service agreement (Eligible Shippers). 38.2 Crediting Percentage PGT shall credit to Eligible Shippers 90 percent of Parking and Imbalance Service revenues received during each 12- month period, commencing November 1st of each year. 38.3 Timing of Credits Within 45 days after November 1st of each 12-month period or after the end of a Short Period, if applicable, PGT shall determine the total amount of the applicable Rate Schedule PS-1 and Rate Schedule AIS-1 revenues received during the 12-month period or Short Period and the distribution of the revenue credits due to Eligible Shippers as described below. A "Short Period" shall be the period for which this Paragraph 38 shall have been in effect for less than 12 months. Such revenue credits shall be reflected as a credit billing adjustment in the next invoice rendered to Eligible Shippers. In the event that such credit billing adjustment would result in a credit total invoice to any Shipper, PGT will refund the excess credit billing adjustment to the Shipper in cash within 15 days after determination of the amount of the credit due to the Shipper. 38.4 Distribution Method Parking and Authorized Imbalance Service revenue credits shall be credited to each Eligible Shipper on a pro rata basis in proportion to the revenues received during the 12-month period or Short Period from each Eligible Shipper divided by the total revenues for all Eligible Shippers received during such period. (Continued) Issued by: P.G.Rosput, Senior Vice President Issued on: FEBRUARY 24, 1994 Effective: MARCH 27, 1994 108 Pacific Gas Transmission Company FERC Gas Tariff First Revised Sheet No. 143 First Revised Volume No. 1-A Superseding Original Sheet No. 143 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 38. CREDITING OF PARKING AND AUTHORIZED IMBALANCE SERVICE REVENUES (Continued) 38.5 Intent PGT shall pay interest to Eligible Shippers on any revenue credits from the date such credits accrue. Such interest shall be calculated based upon the rate of interest specified in Section 154.67(c) of the Commission's regulations. 39. SALES OF EXCESS GAS PGT may from time to time sell gas as required to dispose of excess linepack volumes to the extent necessary to manage system pressure and maintain system integrity. The purchaser shall be responsible for the transportation of gas from the point of sale. Issued by: P.G.Rosput, Senior Vice President Issued on: APRIL 08,1994 Effective: APRIL 22, 1994 109 Graphic Appendix List to Exhibit 10.1 of the Form 10-K DESCRIPTION The substantive information conveyed by the Capacity Release Timeline Standard Release (greater than or Equal to One Day) graph (appearing in Paragraph 28) is described in the body of the electronic document in Paragraph 28.2 and Paragraph 28.8 as permitted by Item 304 of Regulation S-T. The substantive information conveyed by the Capacity Release Timeline Rapid Release (equal to or less than one month) graph (appearing in Paragraph 28) is described in the body of the electronic document in Paragraph 28.2 and Paragraph 28.8 as permitted by Item 304 of Regulation S-T. The substantive information conveyed by the Capacity Release Timeline Pre-Arranged Deal A (less than one calendar month) graph (appearing in Paragraph 28) is described in the body of the electronic document in Paragraph 28.2 and Paragraph 28.8 as permitted by Item 304 of Regulation S-T. The substantive information conveyed by the Capacity Release Timeline Pre-Arranged Deal B (equal to or greater than one month at highest value bid) graph (appearing in Paragraph 28) is described in the body of the electronic document in Paragraph 28.2 and Paragraph 28.8. The substantive information conveyed the Capacity Release Timeline Pre-Arranged Deal C (greater than or equal to one day) graph (appearing in Paragraph 28) is described in the body of the electronic document in Paragraph 28.2 and Paragraph 28.8. EX-10.2 4 EL PASO RATE SCHEDULE T-3 AND GENERAL TERMS 1 EXHIBIT 10.2 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Second Revised Volume No. 1-A Original Sheet No. 110 RATE SCHEDULE T-3 Firm Transportation Service 1. AVAILABILITY This Rate Schedule is available to any party (hereinafter referred to as "Shipper") for the transportation of natural gas on a firm basis by El Paso Natural Gas Company (hereinafter referred to as "El Paso") under the following conditions: (a) El Paso determines it has available capacity to render the firm transportation service; and (b) Shipper and El Paso have executed a Transportation Service Agreement, in the form contained in this Volume No. 1-A Tariff, for such firm transportation service. 2. APPLICABILITY AND CHARACTER OF SERVICE: This Rate Schedule shall apply to all natural gas transported by El Paso for Shipper pursuant to the executed Transportation Service Agreement. Transportation service hereunder shall be firm, subject to the provisions of the executed Transportation Service Agreement and to the Transportation General Terms and Conditions incorporated herein by reference. Transportation service hereunder shall consist of the acceptance by El Paso of natural gas on behalf of Shipper for transportation at the Receipt Point(s) specified in the executed Transportation Service Agreement, the transportation of that natural gas through El Paso's pipeline system, and the delivery of that gas, after appropriate reductions as provided for in this Rate Schedule, to Shipper or for Shippers account at the Delivery Point(s) specified in the executed Transportation Service Agreement. 3. DEFINITIONS 3.1 Transportation Contract Demand: A Shipper's Transportation Contract Demand shall be the maximum quantity of gas El Paso is obligated to deliver to Shipper (or for Shippers account) at the Delivery Point(s) under this Rate Schedule. The Transportation Contract Demand shall be specified on Exhibit B of the executed Transportation Service Agreement, except that the Transportation Contract Demand shall not apply to full requirements agreements. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 2 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 111 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 3. DEFINITIONS (Continued) 3.2 Maximum Daily Quantity: The maximum quantity that El Paso is obligated to receive at each Receipt Point or deliver at each Delivery Point as specified in the executed Transportation Service Agreement; provided, however, that the Maximum Daily Quantity for a full requirements customer on any day shall be its full requirements on that day. 4. RATE Shipper shall pay to El Paso each month the charges set forth below as such charges are designated to be applicable to the transportation service rendered by El Paso for Shipper under the executed Transportation Service Agreement. The quantity of natural gas to which the charges shall apply is set forth below. 4.1 Transportation Charges: As compensation for the use of El Paso facilities in the transportation of natural gas under the executed Transportation Service Agreement, Shipper shall pay the following rate(s): (a) Mainline Transportation Reservation Charges: The maximum unit amount in dollars per dth, unless otherwise provided, applicable to the production area or state(s) in which deliveries are made as set forth from time to time on the currently effective Sheet No. 22 of this Volume No. 1-A Tariff, or superseding tariff, multiplied by Shipper's Transportation Contract Demand, except for those Shippers who have converted their existing sales entitlements to full requirements firm transportation service in which case the applicable Transportation Reservation Charge will be multiplied by each Shipper's respective Billing Determinant, as specified in Section 9(b) of this Rate Schedule. (b) Usage Charges: Except as otherwise provided below, in addition to the applicable Reservation Charge, Shipper shall pay an amount determined as the quantity of natural gas delivered in dth multiplied, as applicable, by the following: (i) Mainline Transportation Usage Charges: The maximum rate(s) per dth, unless otherwise provided, Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 3 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 112 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 4. RATE (Continued) 4.1 Transportation Charges (Continued) applicable from the production basin(s) in which natural gas is received to the production area(s) within such basin or state(s) in which deliveries are made set forth from time to time on currently effective Sheet No. 23 of this Volume No. 1-A Tariff, or superseding tariff; or (ii) Mainline Shorthaul Usage Charge: The maximum rate(s) per dth, unless otherwise provided, as set forth from time to time on currently effective Sheet No. 23 of this Volume No. 1-A Tariff, or superseding tariff, if the transportation service rendered by El Paso pursuant to the executed Transportation Service Agreement is a forward haul of one hundred miles or less; or (iii) Mainline Backhaul Usage Charge: The maximum rate(s) per dth, unless otherwise provided, as set forth from time to time on currently effective Sheet No. 23 of this Volume No. 1-A Tariff, or superseding tariff, if the transportation service rendered by El Paso pursuant to the executed Transportation Service Agreement is by backhaul. (iv) Comparable Discounts: If El Paso agrees to provide its marketing affiliate a discount for any pipeline service, El Paso shall make such discounted rate contemporaneously available to similarly situated unaffiliated Shippers. For those agreements in which transportation by El Paso is provided in two steps, with intermediate transportation service in between provided by a third party, the quantity of natural gas to which the charges set forth in Section 4.1(b) shall apply is determined by the quantity delivered by El Paso to the intermediate third-party. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 4 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 113 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 4. RATE (Continued) 4.2 Field Transportation Usage Charges: In addition to the maximum "Mainline Transportation Usage Charges," Mainline Shorthaul Usage Charge," or "Mainline Backhaul Usage Charge," the maximum "Field Transportation Usage Charges," unless otherwise provided, applicable to deliveries either onshore or offshore as set forth on Sheet No. 24 of this volume No. 1-A Tariff, or superseding tariff, will be charged if the natural gas received at the Receipt Point(s) requires field transportation services. The quantity of natural gas to which these charges shall apply is determined at the end of the field transportation system, or the products extraction plant inlet, when applicable. 4.3 Production Area Charges: In addition to the applicable charges set forth in Sections 4.1 and 4.2 above, if the natural gas received at the Receipt Point(s) receives any production area services, Shipper shall pay El Paso an amount determined as the maximum charge for "Dehydration," "Purification," and/or "Products Extraction," unless otherwise provided, as set forth on Sheet No. 24 of this Volume No. 1-A Tariff, or superseding tariff, multiplied by the quantity of natural gas receiving such service(s). The quantity of natural gas to which these charges shall apply is determined at the end of the field transportation system, or the products extraction plant inlet, when applicable. All volumes receiving production area services in the Jal Plant Complex (consisting of El Paso's Jal Plants, the Sid Richardson Plant, the Warren Eunice Plant, the Warren Monument Plant and the Texaco Eunice Plant) shall pay the applicable production area charge specified herein for any services received, irrespective of which plant provides such service, plus a pro rata share of any charge, whether in cash or in-kind, assessed by a third-party plant operator in the Jal Complex. Such production area charges shall not apply if a Shipper provides to El Paso, fifteen (15) days before initial deliveries of natural gas under an executed Transportation Service Agreement and thereafter fifteen (15) days before each annual anniversary date of such initial deliveries, the results from tests conducted within the previous thirty (30) days by an independent testing firm demonstrating that the gas is in conformance ("conformance gas") with El Paso's quality specifications set forth in Section 5.1 of the Transportation General Terms and-Conditions contained Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 5 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 114 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 4. RATE (Continued) 4.3 Production Area Charges (Continued) in this Volume No. 1-A Tariff. Shipper may have subsequent tests conducted anytime after its gas fails the annual conformance test. In the event the results of such test proves conformance with the applicable quality Specifications of El Paso's tariff and are provided to El Paso fifteen (15) days prior to the first day of any calendar month, then production area charges shall not apply effective the first day of the following calendar month after El Paso receives such notice. Additionally, if the purification and/or products extraction charge(s) are applicable but such test results demonstrate that the gas is being dehydrated to conform to said Section 5.1, then no dehydration charge shall apply. However, if El Paso, through independent field inspections, verifies that the dehydrator is not operating, then the Shipper either shall install and pay for real time measurement and communication equipment enabling El Paso to monitor continuously such source or, at Shipper's election, shall pay the dehydration charge for all gas received by El Paso from that source. In the event conformance gas is processed at an extraction plant or other facility operated by a third party, Shipper shall pay any charge assessed against Shipper's conformance gas by such third party in accordance with the provisions of this paragraph. If there is insufficient capacity available at any production area service facility for all gas scheduled for such facility, then conformance and non-conformance gas shall be curtailed pro rata on a non-discriminatory basis based on Shipper's scheduled conformance and non-conformance gas to the total scheduled gas. For the purpose of computing the Reservation Charges specified herein, if Shipper's Transportation Contract Demand or Maximum Daily Quantity is expressed in Mcf, it shall be converted to dth's by multiplying the number of Mcf by the heating value conversion factor of 1.030 which is the factor utilized in designing such charges. El Paso, at its sole discretion, may from time to time and at any time selectively adjust any or all of the rates stated above applicable to any individual Shipper; provided, however, that such adjusted rate(s) shall not exceed the applicable Maximum Rate(s) nor shall they be less than the Minimum Rate(s) set forth on Sheet Nos. 22, 23, and 24 of this Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 6 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 115 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 4. RATE (Continued) Volume No. 1-A Tariff, or superseding tariff. If El Paso so adjusts any rates to any Shipper, El Paso shall file with the Federal Energy Regulatory Commission any and all required reports respecting such adjusted rates. 5. MINIMUM MONTHLY BILL The Reservation Charge(s) for the month. 6. SCHEDULED OVERRUN TRANSPORTATION Upon request of Shipper, El Paso, at its reasonable discretion, may receive, transport and deliver natural gas in excess of Shipper's Transportation Contract Demand specified in the executed Transportation Service Agreement. Payments and fuel for any excess quantity shall be equivalent to the maximum "Mainline Transportation Charges" applicable from the production basin(s) in which the natural gas is received to the production area(s) within such basin or state(s) in which deliveries are made for service under El Paso's Rate Schedule T-1, as such rate is in effect and reflected from time to time on Sheet No. 20 of this Volume No. 1-A Tariff, or superseding tariff. 7. FUEL AND/OR SHRINKAGE In addition to the payments made pursuant to Section 4 of this Rate Schedule, Shipper shall provide fuel and be responsible for shrinkage that occurs in transporting natural gas and rendering Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 7 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 116 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 7. FUEL AND/OR SHRINKAGE (Continued) other services provided pursuant to Shippers executed Transportation Service Agreement as set forth below: (a) Mainline Transportation - 5% of quantity received Fuel for shorthaul and backhaul transportation may be discounted by El Paso between O% and 5%; however, the discounted percentage applied shall not be less than actual. (b) Field Transportation ) actual fuel/shrinkage as (c) Dehydration ) calculated at the end of (d) Purification ) the production month (e) Products Extraction ) Prior to the beginning of each month, El Paso shall post estimated fuel and shrinkage factors for individual wellheads, gathering systems and plant complexes based on historical values for use by Shippers in the scheduling process. The actual fuel and/or shrinkage allocable to each Shipper's Transportation Service Agreement shall be determined after the end of the production month and shall be reflected in Shipper's accounting statements. 8. GENERAL TERMS AND CONDITIONS Except as otherwise expressly indicated in this Rate Schedule or by the executed Transportation Service Agreement, all of the Transportation General Terms and Conditions contained in this Volume No. 1-A Tariff, including (from and after their effective date) any future modifications, additions or deletions to said General Terms and Conditions, are applicable to transportation service rendered under this Rate Schedule and, by this reference, are made a part hereof. 9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM TRANSPORTATION (a) Any Shipper that converted firm sales entitlements to firm transportation in accordance with the settlement of the proceeding at Docket No. RP88-44-000, at al., shall be entitled to receive firm transportation of the quantities specified by its Transportation Service Agreement with El Paso for a period, unless Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 8 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 117 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM TRANSPORTATION (Continued) otherwise agreed, which is at least as long as the period El Paso's Gas Inventory Charge certificate remains in effect. Following such period, El Paso shall not be authorized, in the absence of written concurrence by the affected Shipper, to avail itself of the "pre-granted" abandonment authority granted by the Commission's Regulations (currently codified at Section 284.221(d)). (b) The Billing Determinants to be utilized in determining the Transportation Reservation Charges set forth in Section 4.1(a) for those Shippers who are full requirements Shippers are as follows:
SHIPPER BILLING DETERMINANTS (dth) Production Area Gas Company of New Mexico 6,664 Navajo Tribal Utility Authority 9,275 Southern Union Gas Company 4,949 Texas ASARCO Inc. 6,589 El Paso Electric Company 30,751 Southdown, Inc. 3 Southern Union Gas Company 70,277 New Mexico El Paso Electric Company 0 Gas Company of New Mexico 71,618 Las Cruces, New Mexico, City of 14,578 Lordsburg, New Mexico, City of 747 Phelps Dodge Corporation 16,962
Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 9 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 118 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM TRANSPORTATION (Continued)
SHIPPER BILLING DETERMINANTS (dth) Arizona Arizona Electric Power Cooperative, Inc. 53,217 Arizona Public Service Company 62,364 ASARCO Inc. 3,526 Citizens Utilities Company 59,395 Cyprus Miami Mining Corporation 4,527 Magma Copper Company 14,219 Mesa, Arizona, City of 17,818 Navajo Tribal Utility Authority 2,970 PEMEX Gas y Petroquimica Basica 8,748 Phelps Dodge Corporation 4,455 Salt River Project Agricultural Improvement and Power District 57,910 Southwest Gas Corporation 399,698 Nevada Southwest Gas Corporation 180,000
(c) Shipper, at its option, may elect to pay El Paso the annual charges so determined from the Billing Determinants specified above allocated with two-thirds (2/3) of the total amount divided and payable in six (6) equal amounts for each of the winter months of November through April and one-third (1/3) of the total amount divided and payable in six (6) equal amounts for each of the summer months of May through October. Shipper, in concurrence with El Paso, may elect an allocation methodology different from that specified above if its seasonal profile so dictates. This provision applies only to Category B Customers as defined at Docket No. RP72-6, et al., except Southwest Gas Corporation, Southern Union Gas Company, Gas Company of New Mexico and Citizens Utilities Company. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 10 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 119 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 10. MAINLINE TRANSPORTATION RESERVATION CHARGE CREDIT If during any one-year period (the first such one-year period beginning with the effectiveness of the Stipulation and Agreement at Docket No. RS92-60-000, et al., is in effect and the last such period or partial period ending the day before El Paso's next general rate case is effective), El Paso collects more than the dollar amount set forth in Article 2.7(b) of said Stipulation and Agreement, attributable to costs allocated to interruptible transportation service, each Shipper paying the maximum Mainline Transportation Reservation Charge under this Rate Schedule shall be eligible to receive a credit to its Mainline Transportation Reservation Charge. The determination as to whether any credit is due shall be calculated as described below: (a) From the revenues received for interruptible mainline transportation service under Rate Schedule T-1, El Paso shall first deduct and retain revenues equal to the sum of the mainline transportation usage rate component of Rate Schedule T-3 and all rate surcharges. (b) El Paso shall retain all remaining interruptible transportation revenues received under Rate Schedule T-1 until such time as the total dollar amount set forth in Article 2.7(b) of the Stipulation and Agreement for the applicable one-year period or partial period has been received. (c) El Paso shall retain 10% of any revenues remaining after performing steps (a) and (b) of the allocation. The remaining 90% shall be credited to firm Shippers as follows: (i) During the amortization period applicable to Washington Ranch Facility costs described in Section 31 of this tariff, such remaining 90% shall be allocated among firm Shippers paying the maximum Mainline Transportation Reservation Charge under this Rate Schedule based on the proportion of each Shipper's Mainline Transportation Reservation Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 11 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 120 Second Revised Volume No. 1-A RATE SCHEDULE T-3 Firm Transportation Service (Continued) 10. MAINLINE TRANSPORTATION RESERVATION CHARGE CREDIT (Continued) revenue responsibility to the total Mainline Transportation Reservation revenue responsibility for all such Shippers paying the maximum Mainline Transportation Reservation Charge; and (ii) Commencing with the expiration of the amortization period of the Washington Ranch Facility costs described in Section 31 of this tariff, such remaining 90% shall be allocated among all firm Shippers, without regard to whether a Shipper is paying the maximum Mainline Transportation Reservation Charge, based on each such Shippers billed Transportation Reservation Charge under this Rate Schedule in proportion to the total Mainline Transportation Reservation Charges billed. The revenues to be credited as described above, if any, shall be credited to Shippers under this Rate Schedule within ninety (90) days following the date such revenues are received. In the event a credit amount cannot be applied to a Shipper under Section 10(c) above, then El Paso shall flow such amount through by means of a refund. In no event shall any Shipper receive a credit or refund under this provision that exceeds the Mainline Transportation Reservation Charges paid under this Rate Schedule by such Shipper during each one-year period or partial period. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 12 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet Nos. 121 through 124 Second Revised Volume No. 1-A Reserved Sheets Original Sheet Nos. 121 through 124 have been reserved. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 13 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 200 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS Table of Contents
Section Description Sheet No. 1 Definitions 201 2 Method of Measurement 203 3 Measurement Equipment 205 4 Scheduling and Capacity Allocation 210 5 Quality 220 6 Billing and Payment 237 7 Force Majeure 242 8 Control and Possession of Natural Gas 243 9 Adverse Claims to Natural Gas 244 10 Indemnification 245 11 Odorization 246 12 Non-Waiver of Future Default 247 13 Service Conditions 248 14 Statutory Regulation 250 15 Assignments 251 16 Descriptive Headings 252 17 Taxes 253 18 Gas Research Institute General Research Development and Demonstration Funding Unit Adjustment Provision 254 19 Operating Provisions for Interruptible Transportation Service 258 20 Operating Provisions for Firm Transportation Service 272 21 Annual Charge Adjustment Provision 291 22 Take-or-Pay Buyout and Buydown Cost Recovery 292 23 Compliance Plan for Transportation Services and Affiliate Transactions 293 24 Order No. 636 Electronic Bulletin Board 308 25 Reserved 310 26 Reserved 320 27 Unauthorized Gas 330 28 Capacity Release Program 334 29 Compliance Plan for Unbundled Sales Division 357 30 Assignment of Firm Capacity on Upstream Pipelines 358 31 Washington Ranch Facility Stranded Investment Cost Recovery 361
Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 14 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 201 Second Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 1. DEFINITIONS 1.1 Day - A period of twenty-four (24) consecutive hours commencing at seven (7:00) a.m., Mountain Standard Time, or such other period as the parties may agree upon. 1.2 Month - A period commencing on the first day of the corresponding calendar month and ending on the first day of the next following calendar month. 1.3 Year - A period of three hundred sixty-five (365) consecutive days commencing on the date to be specified in the executed Transportation Service Agreement; provided, however, that any such year which contains the date of February 29 shall consist of three hundred sixty-six (366) consecutive days. 1.4 British Thermal Unit ("Btu") - One (1) Btu shall mean one British thermal unit and is defined as the amount of heat required to raise the temperature of one (1) pound of water from fifty-nine degrees Fahrenheit (59 F) to sixty degrees Fahrenheit (60 F) at a constant pressure of fourteen and seventy-three hundredths pounds per square inch absolute (14.73 psia). Total Btu's shall be determined by multiplying the total volume of natural gas delivered times the gas heating value expressed in Btu's per cubic foot of gas adjusted on a dry basis. 1.5 Dekatherm ("dth") - One (1) dth shall mean a quantity of gas containing one million (l,000,000) Btu's. 1.6 Heating Value - The quantity of heat, measured in Btu, produced by combustion in air of one (1) cubic foot of anhydrous gas at a temperature of sixty degrees Fahrenheit (60 F) and a constant pressure of fourteen and seventy-three hundredths pounds per square inch absolute (14.73 psia), the air being at the same temperature and pressure as the gas, after the products of combustion are cooled to the initial temperature of the gas and air, and after condensation of the water formed by combustion. 1.7 Operator - The person or entity that controls the flow of gas into El Paso's system. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 15 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 202 Second Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 1. DEFINITIONS (Continued) 1.8 Natural Gas - Any mixture of hydrocarbons or of hydrocarbons and noncombustible gases, in a gaseous state, consisting essentially of methane. 1.9 One Thousand Cubic Feet ("Mcf") - The quantity of natural gas occupying a volume of one thousand (1,000) cubic feet at a temperature of sixty degrees Fahrenheit ( 60 F) and at a pressure of fourteen and seventy-three hundredths pounds per square inch absolute (14.73 psia). 1.10 El Paso System - The El Paso System is displayed on the map set forth on Sheet No. 11 of this FERC Gas Tariff. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 16 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 203 Second Revised Volume No. 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 2. METHOD OF MEASUREMENT 2.1 Unit of Measurement - The unit of measurement for the purpose of receipt and delivery of natural gas for transportation shall be one (1) dth. The number of dth's delivered shall be determined by multiplying the number of Mcf of gas delivered by the total heating value of such gas in Btu's per cubic foot, and multiplying the product by 0.001. The unit of volume for the purpose of measurement shall be one (1) Mcf at a pressure of fourteen and seventy-three hundredths pounds per square inch absolute (14.73 psia) and at a temperature of sixty degrees Fahrenheit (60 degrees F). All readings and registrations of the metering equipment shall be computed into such unit of volume. 2.2 Basis - All orifice meter volumes shall be computed in accordance with applicable American Gas Association reports. Where measurement is by other than orifice meters, all necessary factors for proper volume determination shall be applied. All orifice meter volumes shall be corrected for deviations from the ideal gas laws (supercompressibility) in accordance with the applicable American Gas Association reports. Where displacement meters are used, the square of the orifice meter supercompressibility factor shall be applied. For the purpose of measurement, the atmospheric pressure shall be the barometric pressure calculated for the elevation at the point of measurement. 2.3 Determination of Heating Value - The heating value of gas shall be determined from time to time by analysis of samples obtained from continuous sampling devices. The samples shall be run on a recording calorimeter, employing the Thomas principle of calorimetry, located at the measuring station or at any other point on the pipeline where there will be no commingling thereafter of gas, or by means of some other recognized method. The arithmetic average heating value of the gas during the chart period shall be used in computing any deficiency in Btu content of gas delivered during such period. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 17 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 204 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 2. METHOD OF MEASUREMENT (continued) 2.4 Determination of Flowing Temperature - The temperature of the gas flowing through a meter station shall be obtained by the use of a recording thermometer. The arithmetic average temperature of the gas during the chart period shall be used in computing the delivery of gas during such period. Where the quantities of gas metered will not be materially affected by so doing, the temperature at delivery shall be assumed to be sixty degrees Fahrenheit (60 degrees F) when not regularly measured. 2.5 Determination of Specific Gravity - The specific gravity of the gas flowing through orifice meter stations, when used, shall be determined by taking samples of such gas by means of a recording gravitometer located at the measuring station or at any other point on the pipeline where there will be no commingling thereafter of gas, or by any other recognized method which may be practical in the circumstances. The arithmetic average specific gravity of the gas at such points during the chart period shall be used in computing the delivery of gas during such period at such points. 2.6 Chromatographic Analysis - If the heating value and/or the specific gravity is determined by chromatographic analysis of the gas sample, the values of the physical constants for the gas compounds and the procedure for determining the gross heating value and/or the specific gravity of the gas from them shall be as set forth in the American Gas Association reports where available. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 18 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 205 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. MEASUREMENT EQUIPMENT 3.1 Installation and Operation of Measuring Facilities - All measuring facilities shall be installed, if necessary, owned, maintained and operated, at or near the Receipt Point(s) and Delivery Point(s), as mutually agreed to by El Paso and Shipper. The parties agree that new measurement Equipment and techniques which may be developed from time to time, including electronic flow measurement equipment and techniques, may be utilized by either party to measure the quantity of gas delivered to or by El Paso without additional authorization from the other party provided such new equipment or technique is recognized as generally acceptable for the intended purpose by recognized industry authorities, provides audit data acceptable by El Paso, and is installed and operated in accordance with generally accepted industry practices. Unless otherwise agreed to between the parties, orifice meters shall be utilized and shall employ flange taps and shall be installed and operated in accordance with the applicable American Gas Association reports. 3.2 Installation and Operation of Check Meters - Either party may install, maintain and operate at its own expense, at or near the Receipt Point(s) and the Delivery Point(s), check meters and other necessary equipment by which the quantity of gas delivered to or by El Paso may be measured, provided that such equipment is installed so as not to interfere with the operation of the primary measuring facilities provided for in Section 3.1 hereof. Unless otherwise agreed to between the parties, orifice meters shall be utilized and shall employ flange taps and shall be installed and operated in accordance with the applicable American Gas Association reports. 3.3 Non-interference - Measuring equipment applying to or affecting deliveries shall be installed in such manner as to permit an accurate determination of the quantity of gas delivered and ready verification of the accuracy of measurement. The parties shall exercise care in the installation, maintenance and operation of check measuring or pressure regulating equipment or gas compressors so as to prevent any inaccuracy in the determination of the quantity of gas being measured. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 19 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 206 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. MEASUREMENT EQUIPMENT (Continued) 3.4 Calibration and Test of Measurement Equipment - Each party shall have the right to have representatives present at the time of any installing, cleaning, changing, repairing, inspecting, testing, calibrating or adjusting done in connection with the other party's measuring equipment, including calorimeters, used in the measurement of deliveries of gas. The accuracy of the measuring equipment, including calorimeters, shall be verified at reasonable intervals but not more frequently than once in any thirty (30) day period. In the event either party shall notify the other that it desires a special test of said measuring equipment or of the check measuring equipment, as the case may be, the parties shall cooperate to secure prompt verification of the accuracy of such equipment. Each party shall give to the other party sufficient advance notice of the time of all such special tests so that the other party may conveniently have its representatives present. 3.5 Charts and Records - Upon request of either party, the other shall submit the records and charts from its measuring equipment used in the measurement and billing of gas, including records resulting from electronic flow measurement, chartless custody transfers or any other improved measurement technology, together with calculations therefrom, for inspection and verification, subject to return within thirty (30) days after receipt. The parties shall preserve all test data, charts and other required data pertaining to the measurement of gas by their respective measurement equipment for a period of three (3) years or such other period or periods as may be prescribed with respect to them by regulatory bodies having jurisdiction. 3.6 Correction of Metering Errors - If, upon test , the measuring equipment is found to be in error by not more than two percent (2%), previous recordings of such equipment shall be considered accurate in computing deliveries, but such equipment shall be adjusted at once to record accurately. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 20 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 207 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. MEASUREMENT EQUIPMENT (continued) 3.6 Correction of Metering Errors (Continued) If, upon test, the measuring equipment shall be found to be inaccurate by an amount exceeding two percent (2%), at a recording corresponding to the average hourly rate of flow for the period since the last preceding test, then any previous recordings of such equipment shall be corrected to zero error for any period that is known definitely or agreed upon. In case the period is not known or agreed upon, such correction shall be for a period equal to the lesser of one-half of the time elapsed since the date of the last test or sixteen (16) days. 3.7 Failure of Meters - In the event a meter is out of service or registering inaccurately, the quantity of gas delivered shall be determined: (i) By correcting the error if the percentage of error is ascertainable by calibration, test or mathematical calculations; or in the absence of (i), then (ii) By using the registration of any check meter or meters, if installed and accurately registering; or in the absence of both (i) and (ii), then (iii) By estimating the quantity of delivery during periods under similar conditions when the meter was registering accurately. 3.8 Right-of-Way and Rural Consumers - El Paso shall install, maintain and operate at its own expense, all main line taps and high-pressure regulators necessary for the delivery of natural gas by El Paso to Shipper for resale to right-of-way consumers as well as to rural consumers situated remotely from Shipper's general distribution system. For measurement of gas delivered by El Paso to Shipper for resale to such right-of-way consumers, Shipper shall install, maintain and operate at Shipper's own expense, adjacent to El Paso's pipeline, the meters, low-pressure regulators and other equipment required. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 21 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 208 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. MEASUREMENT EQUIPMENT (Continued) 3.8 Right-of-Way and Rural Consumers (Continued) For measurement of gas delivered by El Paso to Shipper for resale to such rural consumers, El Paso may, at its option, require Shipper to install, maintain and operate at Shipper's own expense, adjacent to El Paso's high-pressure regulators, the meters, low-pressure regulators and other equipment required. Notwithstanding the other provisions of these General Terms and Conditions and unless other operating arrangements mutually agreeable to Shipper and El Paso are employed, the following arrangements shall apply to deliveries of gas by El Paso to Shipper for resale to right-of-way consumers as well as to deliveries of gas by El Paso to Shipper for resale to rural consumers where, pursuant to the immediately preceding paragraph, Shipper installs meters, low-pressure regulators and other equipment. Shipper will service all equipment installed by it and the consumers served by use thereof, including handling of all complaints and/or service calls. The reading of said meters shall be performed by the party most conveniently able to do so as mutually agreed upon by El Paso and Shipper. If the meters are read by Shipper, then Shipper shall furnish a copy of the meter readings to the El Paso, all without expense to El Paso; provided, however, that El Paso shall have the right to read said meters at any reasonable time upon giving notice to Shipper. All pipe, meters and other equipment shall remain the property of the person or corporation paying for same. Shipper at its own expense will from time to time check the accuracy of the meters measuring said gas and shall give El Paso reasonable notice in writing of its intention to do so. The provisions of Sections 3.6 and 3.7 hereof shall apply to the accuracy of Shipper's measuring equipment. El Paso may at its option have a representative prevent at such test. The frequency of meter reading and the billing for gas delivered by El Paso to Shipper for resale to such right-of-way and rural consumers shall be in accordance with such operating arrangements as may be mutually satisfactory to El Paso and Shipper. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 22 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 209 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 3. MEASUREMENT EQUIPMENT (Continued) 3.9 Access to Measuring Equipment - Whenever any point of delivery provided for is on the premises of one party, the other party shall have the right of free use and ingress and egress at all reasonable times for the purpose of installation, operation, repair or removal of measuring equipment. In the event check measuring equipment is installed, the other party shall have access to the same at all reasonable times, but the reading, calibration and adjusting thereof and the changing of charts shall be done only by the party installing the check measuring equipment. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 23 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 210 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION This Section 4 applies to the operation of El Paso's system and sets forth the procedures for scheduling of receipts and deliveries and allocation of pipeline system capacity or any portion thereof among Shippers receiving transportation service from El Paso under executed Transportation Service Agreements pursuant to this Tariff and transportation arrangements included in El Paso's FERC Gas Tariff, Volume No. 2. 4.1 Scheduling of Receipts and Deliveries (a) For scheduling purposes, Day 1 shall be utilized only for scheduling firm requests using primary receipt points and primary delivery points and Day 2 shall be utilized, where additional capacity exists, first for scheduling any additional firm requests using primary receipt points and primary delivery points, secondly for scheduling firm requests using either alternate receipt points or alternate delivery points and third for scheduling any interruptible requests. The following procedure shall be utilized to schedule transportation on El Paso's system: Day 1 - On Day 1, Shippers shall verify their requests for firm transportation from primary receipt points to primary delivery points and cause the Operators to make confirmations of supply. El Paso shall utilize confirmed volumes, not to exceed requests, to determine capacity requirements; and, where necessary, the capacity allocation procedure set forth in Section 4.2 hereof shall be followed. However, when the confirmation from the last well causes the total confirmation to exceed the request, El Paso shall alter the confirmation on the last well as required for the total confirmation to equal requested volumes in accordance with the prioritized list of wells, if any, provided by each Shipper. El Paso shall then communicate electronically or via facsimile to the Shippers and Operators the scheduled quantities and any additional capacity availability. Such notification normally shall be completed prior to the beginning of business on Day 2. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 24 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 211 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.1 Scheduling of Receipts and Deliveries (Continued) Day 2 - Where additional capacity exists, Shippers shall have the opportunity, in accordance with the allocation procedures set forth in Section 4.2 of this Section, to request firm transportation for additional quantities of gas using primary receipt points and primary delivery points, then for firm requests using either alternate receipt points or alternate delivery points, or both, and then for requests for interruptible transportation. Shippers shall cause the Operator to make corresponding confirmations of supply. Such scheduling shall apply only to the additional capacity and shall not cause any change in the prior sequencing of deliveries. El Paso shall then normally communicate electronically or via facsimile the final scheduling of gas to Shippers and Operators prior to the beginning of business on Day 3. Day 3 - Shippers shall cause the Operators to tender the scheduled quantities of natural gas to El Paso at Receipt Points, plus volumes retained by El Paso for fuel and shrinkage as provided for in the applicable transportation rate schedule and El Paso shall deliver the scheduled quantities of natural gas, for Shippers' accounts, at Delivery Points. However, in the event an unexpected capacity constraint occurs, then El Paso shall allocate capacity in accordance with the applicable provisions of Section 4.2(d). (b) Operating conditions may, from time to time, cause a temporary and unintentional imbalance between the quantities (in dth's) of natural gas that El Paso receives and the quantities of natural gas that Shipper takes under the executed Transportation Service Agreement. Shipper shall schedule gas attributable to imbalances when El Paso, in its reasonable discretion and in a nondiscriminatory manner, determines that it can practicably receive or deliver such imbalance. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 25 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 212 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.1 Scheduling of Receipts and Deliveries (Continued) (c) El Paso shall not be obligated to accept, for the account of Shipper, from any receipt point, a quantity of gas that is less than fifteen (15) dth per day, so as to avoid measurement problems relative to small volumes and disproportionate administrative burdens. (d) With respect to its own natural gas supplies, El Paso shall be obligated to pool its supplies by basin, and schedule its own sales gas from such pools in the same manner as it schedules gas from pools for other Shippers. (e) In the event that, on any day, a Shipper's initial request for transportation on El Paso's system is unsuccessful due to lack of access to downstream transportation at any delivery point, which El Paso shall confirm by contacting the downstream operator, such condition shall have no adverse effect on the scheduling of other Shipper's rights at receipt or delivery points. (f) In the event of any occurrence which prevents El Paso from utilizing the process set forth above (e.g., computer failure), for the duration of such occurrence, all scheduling shall be done on the same day subject to the priority limitations applicable on Day 2. Notice of the commencement and termination of any such occurrence shall be posted on El Paso's EBB. The provisions of Section 4.2(d) below shall not apply to occurrences subject to this Section 4.1(f). (g) During Day 3, a Shipper moving gas pursuant to Rate Schedule T-3 of this Volume No. 1-A Tariff may divert scheduled volumes to a point that is within the same rate zone or in an upstream zone. A Releasing Shipper, as a term of release, may utilize such flow day diversion as a means of recalling capacity on an expeditious basis. Additionally, an Acquiring Shipper also may utilize flow day diversion for the same day return of such recalled capacity. Any diversion pursuant to this Section 4.1(g) is subject to the following conditions: Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 26 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 213 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.1 Scheduling of Receipts and Deliveries (Continued) (i) The Shipper who desires to divert gas to an alternate delivery point must: (1) Contact the Operator of the delivery point to which the gas was originally scheduled and arrange for that Operator to decrease the quantity to be received from El Paso, and (2) Arrange with the Operator of the alternate delivery point to receive the gas. (ii) The Operator of the delivery point from which the gas is to be diverted must notify El Paso, via El Paso's electronic scheduling system, which Shipper's gas is to be diverted and to whom and where it in to be diverted. (iii) The Operator of the alternate delivery point must notify El Paso, via El Paso's electronic scheduling system, that said Operator has agreed to receive the diverted gas and must specify the quantities to be diverted to each delivery point. (iv) El Paso shall compare the notifications to verify that the transactions correspond and shall determine if all or part of the requested transaction can be accommodated given the current and anticipated pipeline loading and operating conditions. A flow day diversion shall not have the effect of bumping a Shipper moving gas under Rate Schedule T-1 of this Volume No. 1-A Tariff. (v) If all or part of the transaction can be accommodated, El Paso shall notify the Shipper and Operators involved what portion of the transaction has been accepted. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 27 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 214 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.1 Scheduling of Receipts and Deliveries (Continued) (vi) The volumes scheduled to be diverted shall be assumed to have flowed such that no imbalance exists as a result of the diversion transactions at the end of the day of flow. Any imbalance resulting from the difference between the total scheduled quantities (including diversion volumes) and the actual measured volumes shall be accounted for at the delivery point or on a transportation service agreement, as appropriate. (vii) As a result of the diversion, Shipper shall not experience any change to the originally scheduled volumes and shall be invoiced as though the gas had been delivered to the originally scheduled point. 4.2 Capacity Allocation Procedure - If, on any day, El Paso determines that the capacity of its pipeline system, or any portion of such system, is insufficient to serve all transportation confirmed on Day 1 or Day 2, then El Paso will schedule transportation in accordance with the sequencing procedures set forth below until all available capacity at the constrained location is allocated. Priority to capacity on the mainline system controls priority to the capacity upstream of any mainline receipt point. Further, capacity shall be allocated among Shippers on a nondiscriminatory basis. Subject to the foregoing, capacity shall be allocated among Shippers in accordance with the following: Firm Allocation (a) First, Shippers receiving service under Rate Schedule FTS-S for delivery to primary delivery point(s), shall receive their full requirements before all other Shippers without any requirements or restrictions as to where the gas is received. Such service shall be based on confirmed quantities not to exceed the capacity of the facility to receive or deliver gas; then (b) Second, pro rata among firm transportation Shippers, including Acquiring Shippers receiving released capacity on Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 28 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 215 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.2 Capacity Allocation -Procedure (Continued) a firm or firm recallable basis under El Paso's Capacity Release Program, for delivery from primary receipt to primary delivery point(s) based on confirmed quantities not to exceed any applicable maximum contract quantities; then (c) Third, pro rata among all other firm transportation Shippers utilizing either an alternate receipt or an alternate delivery point, or both, based on confirmed volumes not to exceed the capacity of the facility to receive or deliver gas nor to exceed any Shipper's applicable maximum contract quantities. (d) If, on Day 3, an interruption of service occurs which requires an allocation of previously scheduled capacity, El Paso shall allocate pursuant to this Section 4.2, but shall treat categories (b) and (c) above equally for allocation purposes. After serving all firm requirements, then capacity shall be allocated to interruptible service as follows: Interruptible Allocation (a) First, pro rata among Shippers who contracted prior to October 9, 1985 for interruptible transportation service, according to the provisions of the applicable transportation contracts; then (b) Second, among Shippers utilizing El Paso's interruptible transportation service on a first-come/first-served basis as set forth in Section 19 of these General Terms and Conditions; then (c) Pro rata among Shippers receiving scheduled overrun transportation. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 29 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 216 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.3 Adjustments to Confirmed Volumes Received by El Paso in the Event of Supply Underperformance (a) If, on any day, El Paso determines in its reasonable discretion that underdelivery of natural gas into El Paso's system (supply underperformance), from a gathering system or other receipt point, if allowed to continue, could adversely affect system integrity, El Paso shall have the right, after providing as much advance notice as possible, to make adjustments at such point to Operators' Day 1 confirmations to reflect more accurately such Operators' previous actual deliveries of supply into El Paso's system. An adjustment pursuant to this Section 4.3 shall not eliminate Shippers' rights pursuant to the Day 2 scheduling procedures set forth in Section 4.1(a). The provisions of this Section 4.3 shall apply either until the underdelivery is eliminated or until this threat to System integrity no longer exists. (b) El Paso shall identify potential threats to system integrity by utilizing criteria such as: weather forecast for the market area and producing area; system conditions, including outages, maintenance, equipment availability and line pack; overall projected pressures at various locations; and storage conditions. (c) When supply underperformance occurs and the deficient source of supply is immediately identifiable, El Paso shall make adjustments to that Operator's confirmed volumes. Those supplies that are independently verifiable by El Paso and which match the Operator's confirmation shall not be subject to the provisions of this Section 4.3. When the deficient source of supply is not immediately identifiable, the smallest affected area by wellhead, gathering system, interconnect or residue plant, shall be identified and these procedures apply only to that portion of the system. The following procedures shall be used to adjust Operators' confirmed volumes of natural gas in the event of supply underperformance. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 30 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 217 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.3 Adjustments to Confirmation Volumes Received by El Paso in the Event of Supply Underperformance (Continued) (i) Wellhead Nonperformance - El Paso shall reduce to zero (0) a well's confirmed volume on Day 1 when El Paso determines that such well is not producing. The confirmation shall be restored after El Paso determines that the well is producing. (ii) Gathering System Underperformance - If supply underperformance exists, gathering system monitoring shall be performed by El Paso on a daily basis utilizing the most current data available. El Paso shall compare the most recent total actual production to Operators' confirmed volumes for each gathering system. When supply in expected to be less than Operator confirmations and the shortfall in receipts threatens the integrity of El Paso's system, El Paso shall notify Operators promptly and attempt to attain balancing in the affected gathering system. After being notified by El Paso, Operators may voluntarily reduce confirmed volumes to the actual supply level. If Operators volunteer collectively to reduce confirmations to the actual supply level, thereby eliminating the supply underperformance, no further action will be required by El Paso. However, if Operators collectively fail to eliminate the supply underperformance, then performance factors shall be used by El Paso to adjust the otherwise confirmed volumes as set forth below. (1) Calculation of Performance Factors - El Paso shall calculate performance factors applicable to each Operator in each gathering system based on a history of actual performance versus final scheduled volumes. When there is no history on which to calculate an Operator's performance factor in a particular gathering system, such Operator shall be included in the provisions contained Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 31 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 218 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.3 Adjustments to Confirmation Volumes Received by El Paso in the Event of Supply Underperformance (Continued) in this Section 4.3(c)(ii) with a factor that does not indicate underperformance, until such time as data become available. El Paso shall use the three most current available months of data. The absolute value of the difference between final scheduled volumes and actual received volumes for such three (3) month period shall be divided by each Operator's final scheduled volumes, as adjusted for any past system change data available, to arrive at that Operator's gross performance factor. El Paso shall reduce each Operator's performance factor by 2 percentage points. (2) Application of Performance Factors - The following procedure shall be used by El Paso to calculate an Operator's expected underperformance and allocate its share of supply shortfall for the targeted gathering system. El Paso shall apply the adjusted performance factor against an Operator's confirmed volumes to estimate the Operator's expected volume underperformance. The Operator's expected volume underperformance shall be compared with the sum of all Operators expected volume underperformance to determine each Operator's proportionate share (percentage) of the total expected volume underperformance. Each Operators proportionate share shall be applied against the total supply shortfall for the gathering system to determine the adjustment to each Operator's confirmed volumes. El Paso shall communicate all adjusted confirmed volumes Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 32 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 219 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 4. SCHEDULING AND CAPACITY ALLOCATION (Continued) 4.3 Adjustments to Confirmation Volumes Received by El Paso in the Event of Supply Underperformance (Continued) that have been scheduled to the appropriate parties in accordance with Section 4.1(a) of this FERC Gas Tariff. El Paso shall make available electronically to each Operator its applicable performance factor within each gathering system prior to each month. (iii) Interconnection or Residue Plant Underperformance Receipts from interconnecting pipelines and third party plants shall be monitored by El Paso on a daily basis where real time data is available. When actual receipts are less than confirmed volumes and the shortfall in receipts threatens the integrity of El Paso's system, El Paso shall notify the interconnect and plant Operators and request Operators to increase deliveries or reduce confirmed volumes prospectively. In the event interconnect or third party plant Operators fail to make adjustments, El Paso shall limit, on a pro rata basis, prospective confirmed volumes to actual receipts of supply on the day in question. Higher confirmations shall be allowed prospectively only when the Operator increases volumes of gas into El Paso's system. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 33 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 220 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY 5.1 All natural gas received by El Paso at any mainline Receipt Point(s) shall conform to the following specifications and must be, in El Paso's reasonable judgment, otherwise merchantable: (a) Liquids - The gas shall be free of water and hydrocarbons in liquid form at the temperature and pressure at which the gas is received. The gas shall in no event contain water vapor in excess of seven (7) pounds per million standard cubic feet. (b) Hydrocarbon Dew Point - The hydrocarbon dew point of the gas received shall not exceed twenty degrees Fahrenheit (20 degrees F) at normal pipeline operating pressures. (c) Total Sulfur - The gas shall not contain more than five (5) grains of total sulfur per one hundred (100) standard cubic feet, which includes hydrogen sulfide, carbonyl sulfide, carbon disulfide, mercaptans, and mono-, di- and poly-sulfides. The gas shall also meet the following individual specifications for hydrogen sulfide, mercaptan sulfur or organic sulfur: (i) Hydrogen Sulfide - The gas shall not contain more than one-quarter (0.25) grain of hydrogen sulfide per one hundred (100) standard cubic feet. (ii) Mercaptan Sulfur - The mercaptan sulfur content shall not exceed more than three-quarters (0.75) grain per one hundred (100) standard cubic feet. (iii) Organic Sulfur - The organic sulfur content shall not exceed one and one-quarter (1.25) grains per one hundred (100) standard cubic feet, which includes mercaptans, mono-, di- and poly-sulfides, but it does not include hydrogen sulfide, carbonyl sulfide or carbon disulfide. (d) Oxygen - The oxygen content shall not exceed two-tenths of one percent (0.2%) by volume and every reasonable effort shall be made to keep the gas delivered free of oxygen. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 34 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 221 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.1 (Continued) (e) Carbon Dioxide - The gas shall not have a carbon dioxide content in excess of two percent (2%) by volume, except for gas applicable to Sections 5.2 and 5.3. (f) Diluents - The gas shall not at any time contain in excess of three percent (3%) total diluents (the total combined carbon dioxide, nitrogen, helium, oxygen, and any other diluent compound) by volume, except for gas applicable to Sections 5.2 and 5.3. (g) Dust, Gums and Solid Matter - The gas shall be commercially free of dust, gums and other solid matter. (h) Heating Value - The gas shall have a heating value of not less than 967 Btu per cubic foot. (i) Temperature - The gas received by El Paso shall be at temperatures not in excess of one hundred twenty degrees Fahrenheit (120 degrees F) nor less than fifty degrees Fahrenheit (50 degrees F). Any party tendering gas at a temperature standard less than fifty degrees Fahrenheit (50 degrees F) shall receive a waiver of such standard only if a test has been conducted in accordance with procedures set forth in Section 5.12(b) hereof and the results from such test demonstrate that the particular segment of the pipeline tested can be safely operated below the fifty degrees Fahrenheit (50 degrees F) temperature standard. (j) Deleterious Substances - The gas shall not contain it deleterious substances in concentrations that are hazardous to health, injurious to pipeline facilities or adversely affect merchantability. 5.2 El Paso agrees that plant Receipt Points on El Paso's system, where gas does not conform to the carbon dioxide and/or the total diluent specification set forth in Sections 5.1(e) and (f) above, shall be grandfathered based on the highest non-conforming monthly average percentages of carbon dioxide and total diluents for a month during the twelve (12) month base period ended July 31, 1990. El Paso shall accept gas with carbon dioxide and/or total diluents at percentages up to the non-conforming specifications at Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 35 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 222 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.2 (Continued) volumes up to the residue volume at the plant design capacity as it exists on July 31, 1990; provided, however, to the extent El Paso must curtail non-conforming volumes to meet El Paso's delivery point specifications for carbon dioxide and/or total diluents, El Paso shall curtail volumes at these plants down to 125% of historical volumes in accordance with Section 5.5. Historical volumes for non-conforming plants shall be deemed to be the daily average for the highest monthly tailgate volume delivered to El Paso during the twelve (12) month base period ended July 31, 1990 and in the event a non-conforming plant or plants are closed, El Paso shall transfer the applicable historical volumes to another plant. To the extent a Shipper and/or a plant operator can demonstrate to El Paso that the specifications and/or historical volumes set forth below are in error or that any other plant located on El Paso's system has not historically met the carbon dioxide and the total diluents specifications set forth in Sections 5.1(e) and (f) above, El Paso shall either modify accordingly these specifications and/or historical volumes set forth below or grandfather such other plants on the same basis as the plants identified above, as appropriate. The identification of the non-conforming plants, the grandfathered specifications and the historical volumes are set forth on the table below.
NON-CONFORMING PLANTS GRANDFATHERED LOCATION METER SPECIFICATIONS HISTORICAL CODE CO2 MOL % TOTAL DILUENTS VOLUME MOL % (MCF/D) Amoco Slaughter Plant 77-039 - 11.89 6,915 (IAMSLAUG) Barnhart Plant (J.L. Davis) 77-002 - 3.55 6,149 (IBARNHRT) Big Lake Texon Plant 77-055 - 9.67 2,362 (Damson Oil Corp.) (ITEXON) Chevron Puckett Plant 14-261 3.55 4.09 37,390 (IPUCKETT) Conoco Ramsey Plant 77-095 - 6.38 4,579 (IRAMSEY)
Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 36 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 223 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued)
5.2 (Continued) NON-CONFORMING PLANTS (continued) GRANDFATHERED SPECIFICATIONS LOCATION METER TOTAL DILUENTS HISTORICAL CODE CO2 MOL % MOL % VOLUME (MCF/D) Exxon Snyder Plant 77-009 - 7.42 696 (Oryx Energy) (IEXSNYDR) Jal Complex 01-814 - 4.31 28,518 (IJALCPLX) Jameson Plant (Oryx Energy) 77-078 - 7.02 2,823 (ISUNJAME) Meridian Benedum Plant 02-304 - 3.18 75,585 (MOHI)(IHYBENDM) Midkiff Plant 01-079 - 4.95 39,371 (IMIDKIFF) Midway Lane Plant 03-933 - 4.45 4,617 (Apache Gas Corporation) (IMIDWAY) Permian Corp. CPD #2 14-082 - 6.03 6,620 (IPERTOD2) Phillips Goldsmith Plant 02-381 - 5.23 62,267 (IPHGOLDS) Phillips Lee Plant 77-025 - 7.34 27,484 (IPHLEE) Phillips Eunice Plant 77-287 - 5.15 57,672 (IPHEUNIC) Phillips Fullerton Plant 77-289 - 6.18 28,200 (IPHFULTN) Phillips Spraberry Plant 77-248 - 4.64 11,277 (IPHSPBRY) San Juan River Plant 01-125 - 4.35 32,827 (ISJRVPLT) Shell TXL Plant (ISHTXL) 77-029 - 6.17 12,054 Shell Wasson Plant 01-106 - 5.98 8,682 (ISHWASON) Terrell Plant 01-596 2.89 4.53 102,708 (ITERRELL)
Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 37 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 224 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.2 (Continued)
NON-CONFORMING PLANTS (continued) GRANDFATHERED SPECIFICATIONS LOCATION METER TOTAL DILUENTS HISTORICAL CODE CO2 MOL % MOL % VOLUME (MCF/D) Texaco Fuller 77-036 - 7.66 661 (ITEXFULR) Texaco Vealmoor Plant 77-028 - 6.32 10,204 (IVEALMOR) Tipperary Denton Plant 77-001 - 5.02 2,554 (J.L. Davis) (IDENTON) Union of California 77-027 - 6.42 2,056 Dollarhide Plant (IUTDOLHD) Union Texas Perkins Plant 77-068 - 10.19 9,178 (IUTPERKDI) Val Verde 14-136 2.13 - 195,985 (IMOITRKA) Warren Monument 77-045 - 4.04 31,576 (IWARMONU) Warren Saunders Plant 77-046 - 5.75 12,421 (IWARSAUD)
5.3 El Paso agrees that interconnect Receipt Points on El Paso's system, where gas does not conform to the carbon dioxide and/or the total diluent specification set forth in Sections 5.1(e) and (f) above, shall be grandfathered based on the twelve (12) month average non-conforming percentages of carbon dioxide and total diluents for the twelve (12) month base period ended July 31, 1990. El Paso shall accept gas with carbon dioxide and/or total diluents at percentages up to the grandfathered non-conforming specifications at volumes up to the historical volume. The historical volume is deemed to be the daily average volume received by El Paso at each of the non-conforming interconnect Receipt Points for the twelve (12) month base period ended July 31, 1990. The identification of the non-conforming interconnects, the grandfathered specifications and the historical volumes are set forth on the following table: Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 38 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 225 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.3 (Continued)
NON-CONFORMING INTERCONNECTS TOTAL LOCATION METER DILUENTS HISTORICAL CODE CO2 MOL % MOL % VOLUME (MCF/D) Big Blue Receipt Point 14-091 - 9.50 11,900 (Colorado Interstate) (IBIG8IFUE) Howe Ranch Discharge 02-721 4.12 5.20 3,480 (Meridian) Northern Natural Plains 40-019 - 4.22 111,072 (INN30PLA) Plains Compressor 40-043 - 4.50 8,464 (Westar-Felmac) (IW40-043)
5.4 In addition, El Paso agrees to grandfather the sulfur specifications set forth in Section 5.1(c) above for natural gas received at the tailgate of the Terrell and Puckett Plants, based on the actual monthly highest non-conforming concentrations during the twelve (12) month base period ending July 31, 1990. The sulfur specifications El Paso shall accept for natural gas at volumes up to the residue volume at plant design capacity received at the tailgate of the Terrell and Puckett Plants are identified below. To the extent a Shipper can demonstrate to El Paso that any other plant located on El Paso's system has not historically met the sulfur specifications set forth in Section 5.1 (c) above, El Paso shall grandfather such plant on the same basin as the Terrell and Puckett Plants; provided, however, a plant shall not qualify if such plant has changed the method of processing the gas in the last five (5) years.
Grandfathered Non-conforming Sulfur Specifications (grains per 100 standard cubic feet) LOCATION TOTAL HYDROGEN MERCAPTAN ORGANIC SULFUR SULFIDE SULFUR SULFUR Terrell Plant - 0.45 - - Puckett Plant - 0.45 - -
Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 39 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 226 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.5 El Paso agrees to accept natural gas (including volumes in excess of the volumes identified in Sections 5.2 and 5.3) which does not conform to the quality specifications set forth in Sections 5.1(e) and (f) at the Receipt Point(s), but only until such time as El Paso, in its reasonable discretion and judgement, determines that such natural gas must conform to the quality specifications set forth above to maintain prudent operation of part or all of El Paso's system. In exercising its discretion to discontinue accepting nonconforming natural gas under this Section, El Paso will consider only the volume, compositions and location of the gas, and the impact of its continued introduction into El Paso's system on El Paso's operations and an ability to meet its obligations to third parties, and will appropriately document the basis for its decision. Upon determining that it will no longer accept non-conforming volumes, El Paso will notify Shippers and/or plant operators that all prospective deliveries must comply with the quality specifications set forth above and that the provisions of Section 5.8 below shall be applicable to all natural gas tendered for transportation which does not so comply. In the event the aforementioned occurrences cause El Paso to curtail volumes at plant and/or interconnect Receipt Points such curtailment shall exclude those plant and/or interconnect volumes identified in Sections 5.2 and 5.3, provided, however, if El Paso determines that it must further curtail volumes of non-conforming gas to meet El Paso or delivery specifications for carbon dioxide and/or total diluents, El Paso shall curtail volumes down to 125% of the historical volumes for those plants identified in Section 5.2 on the following basis: (a) First, volumes of natural gas that did not meet the 967 Btu standard would be curtailed in order of lowest Btu to highest down to the level of 125% of historical volumes; (b) Second, plants with pipeline interconnects in addition to El Paso would be curtailed down to the level of 125% of historical volumes on a pro rata basis; and (c) Third, all other volumes would be curtailed on a pro rata basis, based on a percentage of such volumes that are out of compliance as to the particular substance that is causing the problem, down to 125% of historical volumes. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 40 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 227 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.5 (Continued) Based on the curtailment procedure as documented above, El Paso will determine the volume of gas, not to be less than 125% of historical volumes, that will be allowed to enter El Paso's system at the grandfathered carbon dioxide and/or total diluent specifications for each non-conforming plant and will notify the plant operator of such volumes. Following such initial notification to plant operators, El Paso shall provide a written notice accompanied by a verification of non-compliance and provide audit rights to all affected Shippers and operators, in order to ensure compliance with the above curtailment procedures. 5.6 Gas delivered to El Paso at Receipt Point(s) which receives any Production Area services shall conform to those specifications established herein. 5.7 The quality specifications for each gathering system connected to El Paso's mainline system shall be no more stringent than those specifications set forth in Section 5.1. All natural gas received at a gathering system Receipt Point shall conform to the specifications set forth in the table below: (Gathering System Specifications shall be waived by El Paso on a non-discriminatory basis) (THIS SPACE INTENTIONALLY LEFT BLANK) Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 41 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 228 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued)
Total Sulfur Water Hydro- H2S Mercaptan Sulfur Total Vapor carbons GR/100 Organic Sulfur 3/ CO2 Diluents Oxygen Location #/MMCF Dew Point Scf GR/100 Scf MOL # MOL # # San Juan Basin Sweet Gas (GSANJUAN) 25 1/ 0.25 5/.75/1.25 2 3 .2 La Jara (ILAJARA) 25 1/ 0.25 5/.75/1.25 2 3 .2 Tapacito Field (ITAPACIT) 25 1/ 0.25 5/.75/1.25 2 3 .2 Kutz (Exchange Point No. 13) 25 1/ 0.25 5/.75/1.25 2 3 .2 (IEXCPT13) Kutz (Exchange Point No. 18) 25 1/ 0.25 5/.75/1.25 2 3 .2 (IEXCPT18) Gas Company of New Mexico (Exchange Point No. 47) 25 1/ 0.25 5/.75/1.25 2 3 .2 (IEXCPT47) San Juan Ignacio Dry (GIGNACIO) 25 20 degrees F 0.25 5/.75/1.25 2 3 .2 Bondad (West Gas) (IBONDAD) 25 20 degrees F 0.25 5/.75/1.25 2 3 .2
Dust, Minimum Gums & Heating Solid Value Location Matter Btu Temperature San Juan Basin Sweet Gas Max 120 degrees F (GSANJUAN) Free of 967 Min 50 degrees F La Jara Max 120 degrees F (ILAJARA) Free of 967 Min 50 degrees F Tapacito Field Max 120 degrees F (ITAPACIT) Free of 967 Min 50 degrees F Kutz Max 120 degrees F (Exchange Point No. 13) Free of 967 Min 50 degrees F (IEXCPT13) Kutz Max 120 degrees F (Exchange Point No. 18) Free of 967 Min 50 degrees F (IEXCPT18) Gas Company of New Mexico Max 120 degrees F (Exchange Point No. 47) Free of 967 Min 50 degrees F (IEXCPT47) San Juan Ignacio Dry Max 120 degrees F (GIGNACIO) Free of 967 Min 50 degrees F Bondad (West Gas) Max 120 degrees F (IBONDAD) Free of 967 Min 50 degrees F
Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 42 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 229 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued)
Total Sulfur Water Hydro- H2S Mercaptan Sulfur Total Vapor carbons GR/100 Organic Sulfur 3/ CO2 Diluents Oxygen Location #/MMCF Dew Point Scf GR/100 Scf MOL # MOL # # WestGas (IWESTGAS) 25 20 degrees F 0.25 5/.75/1.25 2 3 .2 Lockridge (GLOCKRID) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2 Worsham (GWORSHAM) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2 Waha (GWAHA) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2 West Waha (GWSTWAHA) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2 Gomez (GGOMEZ) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2 Toro (GTORO) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2 Rojo Caballos (GROJOCAB) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2 Carlsbad (GCARLSBAD) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 Beckham County (GBECKHAM) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
Dust, Minimum Gums & Heating Solid Value Location Matter Btu Temperature WestGas Max 120 degrees F (IWESTGAS) Free of 967 Min 50 degrees F Lockridge Max 120 degrees F (GLOCKRID) Free of 967 Min 50 degrees F Worsham Max 120 degrees F (GWORSHAM) Free of 967 Min 50 degrees F Waha Max 120 degrees F (GWAHA) Free of 967 Min 50 degrees F West Waha Max 120 degrees F (GWSTWAHA) Free of 967 Min 50 degrees F Gomez Max 120 degrees F (GGOMEZ) Free of 967 Min 50 degrees F Toro Max 120 degrees F (GTORO) Free of 967 Min 50 degrees F Rojo Caballos Max 120 degrees F (GROJOCAB) Free of 967 Min 50 degrees F Carlsbad Max 120 degrees F (GCARLSBAD) Free of 967 Min 50 degrees F Beckham County Max 120 degrees F (GBECKHAM) Free of 967 Min 50 degrees F
Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 43 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 230 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued)
Total Sulfur Water Hydro- H2S Mercaptan Sulfur Total Vapor carbons GR/100 Organic Sulfur 3/ CO2 Diluents Oxygen Location #/MMCF Dew Point Scf GR/100 Scf MOL # MOL # # San Juan Mainline (GSJMNLIN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 26" Eunice to Pecos (GEU-PECS) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 Plains to San Juan (GSJXOVER) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 Terrell to Puckett (GTER-PUK) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 20" Goldsmith to Plains (G20GO-PL) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 16" C Line (G16C-LIN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 McKay Creek (GMCKAYCR) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 20" Sonora to Benedum (GSON-BEN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 Hobart (Phillips) (GHOBART) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 Hobart - Zybach (GHOB-ZYB) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
Dust, Minimum Gums & Heating Solid Value Location Matter Btu Temperature San Juan Mainline Max 120 degrees F (GSJMNLIN) Free of 967 Min 50 degrees F 26" Eunice to Pecos Max 120 degrees F (GEU-PECS) Free of 967 Min 50 degrees F Plains to San Juan Max 120 degrees F (GSJXOVER) Free of 967 Min 50 degrees F Terrell to Puckett Max 120 degrees F (GTER-PUK) Free of 967 Min 50 degrees F 20" Goldsmith to Plains Max 120 degrees F (G20GO-PL) Free of 967 Min 50 degrees F 16" C Line Max 120 degrees F (G16C-LIN) Free of 967 Min 50 degrees F McKay Creek Max 120 degrees F (GMCKAYCR) Free of 967 Min 50 degrees F 20" Sonora to Benedum Max 120 degrees F (GSON-BEN) Free of 967 Min 50 degrees F Hobart (Phillips) Max 120 degrees F (GHOBART) Free of 967 Min 50 degrees F Hobart - Zybach Max 120 degrees F (GHOB-ZYB) Free of 967 Min 50 degrees F
Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 44 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 231 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued)
Total Sulfur Water Hydro- H2S Mercaptan Sulfur Total Vapor carbons GR/100 Organic Sulfur 3/ CO2 Diluents Oxygen Location #/MMCF Dew Point Scf GR/100 Scf MOL # MOL # # ANR No. 1 (IANR#1AN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 ANR No. 2 (IANR#2AN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 BP Gas Transmission (Roger Mills County) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2 (ICHEY-CP) NGPL Beckham #3 (INGPLB#3) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
Dust, Minimum Gums & Heating Solid Value Location Matter Btu Temperature ANR No. 1 Max 120 degrees F (IANR#1AN) Free of 967 Min 50 degrees F ANR No. 2 Max 120 degrees F (IANR#2AN) Free of 967 Min 50 degrees F BP Gas Transmission Max 120 degrees F (Roger Mills County) Free of 967 Min 50 degrees F (ICHEY-CP) NGPL Beckham #3 Max 120 degrees F (INGPLB#3) Free of 967 Min 50 degrees F
___________________________ 1/ Free of hydrocarbons in liquid form. 2/ El Paso will accept natural gas with hydrogen sulfide at levels above 0.25 grains per 100 Scf in these gathering systems. The hydrogen sulfide level will be used as a basis to curtail gas in these gathering systems only if the treating plant facilities are limited as a result of, but not limited to, the following reasons; treating capacity limitation, sulfur emissions limitations, high residue gas hydrogen sulfide concentration. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 45 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 232 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) ___________________________ 3/ El Paso shall accept a total sulfur, mercaptan sulfur, and organic sulfur as specified in Sections 5.1(c), 5.1(c)(ii) and 5.1(c)(iii) above until such time that El Paso cannot blend the gas to conform to El Paso's delivery point specifications set forth in Section 5.10. In the event such situation occurs, El Paso will refuse acceptance of gas received by curtailing quantities commencing with the quantities of gas containing the highest total sulfur, mercaptan sulfur or organic sulfur down to a level that would permit El Paso to deliver gas at specifications required at the delivery points. 4/ El Paso will accept natural gas with total sulfur at levels above 5 grains per 100 Scf, mercaptans at levels above 0.75 grains per 100 Scf and organic sulfur at levels above 1.25 grains per 100 Scf only to the extent that the processing plant operations is not adversely impacted by these sulfur compounds and the residue gas from these processing plants meets the sulfur specifications listed under Section 5.1(c) above. 5/ El Paso will accept natural gas with carbon dioxide at levels above 2% in these gathering systems. The carbon dioxide level will be used as a basis to curtail gas in these gathering systems only if the treating plant facilities are limited as a result of, but not limited to, the following reasons; treating capacity limitation, carbon dioxide emissions limitations, high residue gas carbon dioxide concentration. 6/ El Paso will accept natural gas in these gathering systems that exceeds the total diluent percentage listed in the table only if the gas at the tailgate of the treating plant where the gas is processed does not exceed the total diluent percentage listed in the table. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 46 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 233 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.8 If, at any time, gas tendered by Shipper for transportation shall fail to substantially conform to any of the applicable quality specifications set forth in Section 5.1 above and El Paso notifies Shipper of such deficiency and Shipper fails to remedy any such deficiency within a reasonable period of time (immediately in those situations which threaten the integrity of El Paso's system), El Paso may, at its option, refuse to accept delivery pending correction of the deficiency by Shipper or continue to accept delivery and make such changes necessary to cause the gas to conform to such specifications, in which event Shipper shall reimburse El Paso for all reasonable expenses incurred by El Paso in effecting such changes, including operational and gas costs associated with purging and/or venting the pipeline. Failure by Shipper to tender quantities that conform to any of the applicable quality specifications shall not be construed to eliminate, or limit in any manner, the obligations of Shipper existing under any other provisions of the executed Transportation Service Agreement. In the event natural gas is delivered into El Paso system that would cause the natural gas in a portion of El Paso's pipeline to become unmerchantable, then El Paso is permitted to act expediently to make the gas merchantable again by any and all reasonable methods, including, without limitation, to venting the pipeline of whatever quantity of natural gas necessary to achieve a merchantable stream of gas. Shipper shall reimburse El Paso for all reasonable expenses incurred by El Paso to obtain merchantable natural gas again, including operational and gas costs associated with venting the pipeline. In such cases, El Paso shall promptly notify Shipper of the non-conforming supply and any steps taken to protect the merchantability of the gas. 5.9 After giving sufficient notice to a Shipper, El Paso shall have the right to collect from all Shippers delivering gas to El Paso at a common Receipt Point their volumetric pro rata share of the cost of any additional hydrogen sulfide analysis and/or water vapor analysis equipment which El Paso, at its reasonable discretion, determines is required to be installed at such Receipt Point to monitor the quality of gas delivered. 5.10 Except as otherwise provided below, all natural gas delivered by El Paso shall conform to the following specifications: Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 47 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 234 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.10 (Continued) (a) Liquids - The gas shall be free of water and hydrocarbons in liquid form at the temperature and pressure at which the gas is delivered. The gas shall in no event contain water vapor in excess of seven (7) pounds per million standard cubic feet. (b) Hydrocarbon Dew Point - The hydrocarbon dew point of the gas delivered shall not exceed twenty degrees Fahrenheit (20 degrees F) at a pressure of 600 psig. (c) Total Sulfur - The gas shall not contain more than three-quarters (0.75) grain of total sulfur per one hundred (100) standard cubic feet, which includes hydrogen sulfide, carbonyl sulfide, carbon disulfide, mercaptans, and mono-, di- and poly-sulfides. The gas shall also meet the following individual specifications for hydrogen sulfide, mercaptan sulfur or organic sulfur: (i) Hydrogen Sulfide - The gas shall not contain more than one-quarter (0.25) grain of hydrogen sulfide per one hundred (100) standard cubic feet. (ii) Mercaptan Sulfur - The mercaptan sulfur content shall not exceed more than three-tenths (0.3) grain per one hundred (100) standard cubic feet. (iii) Organic Sulfur - The organic sulfur content shall not exceed five-tenths (0.5) grain per one hundred (100) standard cubic feet, which includes mercaptans, mono-, di- and poly-sulfides, but it does not include hydrogen sulfide, carbonyl sulfide or carbon disulfide. (d) Oxygen - The oxygen content shall not exceed two-tenths of one percent (0.2%) by volume and every reasonable effort shall be made to keep the gas delivered free of oxygen. (e) Carbon Dioxide - The gas shall not have a carbon dioxide content in excess of three percent (3%) by volume. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 48 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 235 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.10 (continued) (f) Diluents - The gas shall not at any time contain in excess of four percent (4%) total diluents (the total combined carbon dioxide, nitrogen, helium, oxygen, and any other diluent compound) by volume. (g) Dust, Gums and Solid Matter - The gas shall be commercially free from solid matter, dust, gums, and gum forming constituents, or any other substance which interferes with the intended purpose or merchantability of the gas, or causes interference with the proper and safe operation of the lines, meters, regulators, or other appliances through which it may flow. (h) Heating Value - The gas shall have a heating value of not less than 967 Btu per cubic foot. For natural gas delivered at the border between the States of Arizona and California, the gas shall have a heating value of not less than 995 Btu per cubic foot. (i) Temperature - The gas shall be delivered at temperatures not in excess of one hundred five degrees Fahrenheit (105 degrees F) nor less than fifty degrees Fahrenheit (50 degrees F) except where, due to normal operating conditions and ambient temperatures on the pipeline system the temperature may periodically drop below such lower limit. (j) Deleterious Substances - The gas shall not contain any toxic or hazardous substance, in concentrations which, in the normal use of the gas, may be hazardous to health, injurious to pipeline facilities or be a limit to merchantability. If, at any time, gas tendered for delivery by El Paso shall fail to substantially conform to any of the specifications set forth in this Section 5.10, Shipper or its designee agrees to notify El Paso of such deficiency and if El Paso fails to promptly remedy any such deficiency within a reasonable time, then Shipper or its designee may, at its option, refuse to accept delivery pending correction of the deficiency by El Paso or continue to accept delivery and make such changes as necessary to cause the gas to conform to such specifications, in which event El Paso shall reimburse Shipper or its designee for all reasonable expenses incurred by Shipper or its designee in effecting such changes. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 49 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 236 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 5. QUALITY (Continued) 5.11 The quality specifications set forth in Section 5.10 above shall not apply to natural gas delivered by El Paso at delivery points in production areas designated as "Field Gas" on Exhibits A and/or B of an executed Transportation Service Agreement or any delivery point in production areas receiving gas delivered by El Paso on July 31, 1990 that did not meet the quality specifications set forth in Section 5.10 above. Gas so designated shall be of such quality an may exist in El Paso's pipeline from time to time at such points and El Paso makes no warranty of merchantability or fitness for any purpose with respect to such gas. 5.12 Testing Procedures - The following test procedures shall be utilized by El Paso. (a) To determine whether specified sulfur compound limitations are being met as stated under Section 5.1(c) and 5.10(c) hereof, El Paso shall use the appropriate American Society for Testing Materials Procedures (as revised) Volume 05.05 Gaseous Fuels; Coal and Coke and/or accepted industry practices such as sulfur titrators and chromatography. (b) To determine whether specific points on El Paso's system can operate below the fifty degree Fahrenheit (5O degrees F) tolerance as stated in Section 5.1(i), El Paso shall use the Charpy impact and drop-weight tear tests in accordance with API-5L Supplemental Requirements 5 and 6, respectively. Inasmuch as this test requires the shutdown of the specific segment of the system being tested, El Paso shall conduct such test only at a time when operations on such segments are not affected or the safety of the system is not put in jeopardy. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 50 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 237 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 6. BILLING AND PAYMENT 6.1 Billing - On or before the fifteenth (15th) day of each month El Paso shall mail to Shipper an invoice evidencing the bill for services rendered to Shipper under the executed Transportation Service Agreement during the preceding month. When Shipper is in control of information required by El Paso to prepare invoices, Shipper shall cause such information to be received by El Paso on or before the tenth (10th) day of the month immediately following the month to which the information applies. 6.2 Payment by Wire Transfer - Payment to El Paso for services rendered during the preceding month shall be due on the twenty-sixth (26th) day of the calendar month next succeeding that month for which such service was rendered and shall be paid by Shipper on or before such due date. Subject to the provisions of Section 6.3 below, Shipper shall make such payment to El Paso by wire transfer in immediately available funds to a depository designated by El Paso. When the due date falls on a day that the designated depository is not open in the normal course of business to receive Shipper's payment, Shipper shall cause such payment to be actually received by El Paso on or before the first business day on which the designated depository is open after such due date. 6.3 Payment Other Than by Wire Transfer - In the event in any month, that Shipper does not make payment by wire transfer, then payment to El Paso for services rendered during the preceding month shall be due on the twenty-fifth (25th) day of the calendar month next succeeding that month for which such service was rendered. Shipper shall cause payment for such bill to be actually received by El Paso at its offices in El Paso, Texas, directed to the attention of General Accounting, on or before such due date. When the due date falls on a day that El Paso's offices located in El Paso, Texas, are not open in the normal course of business to receive Shipper's payment, Shipper shall cause such payment to be actually received by El Paso on or before the last business day on which El Paso's offices located in El Paso, Texas, are open prior to such due date. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 51 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 238 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 6. BILLING AND PAYMENT (Continued) 6.4 Failure to Pay Bills - Should Shipper fail to pay all of the amount of any bill for gas delivered under the executed Transportation Service Agreement when such amount is due, as herein provided, Shipper shall pay El Paso interest on the unpaid balance that shall accrue on each calendar day from the twenty-fifth (25th) day of the month during which payment was due at a rate equal to two percent (2%) above the then effective prime commercial lending rate per annum announced from time to time by The Chase Manhattan Bank (N.A.) at its principal office in New York City, provided that for any period that such interest exceeds any applicable maximum rate permitted by law, the interest shall equal said applicable maximum rate. The interest provided for by this Section 6.4 shall be compounded monthly. Unless otherwise mutually agreed between the parties, if either principal or interest are due, any payments thereafter received shall first be applied to the interest due, then to the previously outstanding principal due and, lastly, to the most current principal due. Subject to requirements of regulatory bodies having jurisdiction and without prejudice to any other rights and remedies available to El Paso under the law and the executed Transportation Service Agreement, El Paso shall have the right to suspend transportation service without obtaining additional prior approval from the Commission if any amount billed to Shipper remains unpaid for more than thirty (30) days after the due date thereof; provided, however, prior to suspension El Paso shall follow these notification procedures. (a) First Notice: On or about ten (10) days after the due date of any payment, El Paso shall contact Shipper by telephone or other routine communication means to advise that unpaid bills may lead to suspension of transportation service when more than thirty (30) days past due; (b) Second Notice: On or about twenty (20) days after the due date of any payment, El Paso shall notify Shipper by written correspondence to advise that continued failure to pay bills can lead to suspension of transportation service when the bill becomes more than thirty (30) days past due; Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 52 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 239 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 6. BILLING AND PAYMENT (Continued) 6.4 Failure to Pay Bills (Continued) (c) Final Notice: Not less than five (5) days prior to the thirtieth (30th) day after the due date of any payment or five (5) days before El Paso intends to suspend service under this Section 6. 4, if such suspension will occur more than thirty (30) days after the due date, El Paso shall inform the Commission, interested State utility regulators, and Shipper in writing and delivered by any reliable and expeditious means available, that transportation service shall be suspended; provided further, however, that in the event of a bona fide dispute between the parties concerning the amount billed of the unpaid bill, El Paso shall not suspend transportation service under the notification procedure outlined above when Shipper acts in a timely manner to provide additional information and security for El Paso in accordance with the following Procedures. (d) Identify Dispute: Within fifteen (15) days after the due date of any payment, Shipper shall notify El Paso by written correspondence of the amount billed that is in bona fide dispute and of all reasons and documentation why Shipper believes full payment is not now appropriate; and (e) Payment Security: Within thirty (30) days after the due date of any payment, Shipper shall either pay in full the total amount billed without prejudice to Shipper's rights to dispute all or part of said amount and subject to return by El Paso of the disputed amount so identified, with interest calculated in accordance with this Section 6. 4, after resolution of that dispute in favor of Shipper, or pay the undisputed portion of the amount billed in full and furnish good and sufficient surety bond, guaranteeing payment to El Paso of all amounts ultimately found due after resolution of the dispute, including the amount now in dispute plus the estimated interest calculated in accordance with this Section 6.4 that accrues until resolution of the dispute, which may be reached either by agreement or judgment of a court of competent jurisdiction; provided, however, neither El Paso nor Shipper shall calculate or pay interest on Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 53 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 240 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 6. BILLING AND PAYMENT (Continued) 6.4 Failure to Pay Bills (Continued) any amounts of less than $10,000. If resolution of the dispute is in favor of Shipper and the Shipper furnished a surety bond instead of paying the disputed amount, then El Paso shall refund to Shipper the costs incurred in securing that surety bond for this dispute. This section does not apply to ordinary adjustments of overcharges and undercharges in accordance with Section 6.5. 6.5 Adjustment of Overcharge and Undercharge - If it shall be found that at any time or times, within the time limits of Section 6.1 below, Shipper has been overcharged or undercharged in any form whatsoever under the provisions hereof as a result of an error in billing for which El Paso is solely responsible and Shipper shall have actually paid the bill containing such overcharge or undercharge, then, unless mutually agreed otherwise, within thirty (30) days after the final determination thereof, and except where otherwise required by statute, rule, regulation or order, El Paso shall refund the amount of any such overcharge, with interest thereon at the then effective rate computed in the same manner as set forth in Section 6.4 above, and Shipper shall pay the amount of any such undercharge, with interest thereon at the then effective rate computed in the same manner as set forth in Section 6.4 above. Interest on overcharges or undercharges shall be calculated from the time such overcharge or undercharge was paid to the date of refund or payment, respectively; provided, however, neither El Paso nor Shipper shall calculate or pay interest on any amounts of less than $10,000. This section does not apply to payments subject to a billing dispute in accordance with Section 6.4. 6.6 Delayed Bill or Notice - If El Paso fails to render or otherwise fails to mail any bill by the fifteenth (15th) day of the month then the time of payment shall be extended by one (1) day for each day that the rendering of said bill is delayed unless Shipper is responsible for such delay. If El Paso fails to render or otherwise fails to mail any notice within the time specified in this Billing and Payment Section, then the time for Shipper's response to such notice shall be extended by one (1) day for each day that the rendering of said notice is delayed unless Shipper is responsible for such delay. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 54 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 241 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 6. BILLING AND PAYMENT (Continued) 6.7 Adjustment of Errors - In the event an error is discovered in any invoice that El Paso renders, such error shall be adjusted within thirty (30) days of the determination thereof; provided, however,that any claim for adjustment must be made within twelve (12) months from the date of such invoice. 6.8 Fees - Shipper shall reimburse El Paso for all filing and other fees actually paid by El Paso pursuant to the Commission's Regulations which are attributable to an executed Transportation Service Agreement. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 55 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 242 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 7. FORCE MAJEURE 7.1 Effect of Force Majeure - In the event of either El Paso or Shipper being rendered unable by force majeure to wholly or in part carry out its obligations under the provisions of the executed Transportation Service Agreement, it is agreed that the obligations of the party affected by such force majeure, other than to make payments due, shall be suspended without liability for breach of contract during the continuance of any inability so caused but for no longer period, and such cause shall, so far as possible, be remedied with all reasonable dispatch. A force majeure event affecting the performance by either party shall not relieve it of liability in the event of its concurring negligence, where such negligence was a cause of the force majeure event, or in the event of its failure to use reasonable diligence to remedy the situation and remove the cause in an adequate manner and with all reasonable dispatch, nor shall such causes or contingencies relieve either party of liability unless such party shall give notice and full particulars of the same in writing to the other party as soon as possible after the occurrence relied on. 7.2 Definition of Force Majeure - The term "force majeure" as employed herein shall mean acts of God, strikes, lockouts or other industrial disturbances, failure of any third parties necessary to the performance by either El Paso or Shipper under the executed Transportation Service Agreement, inability to obtain pipe or other material or equipment or labor, wars, riots, insurrections, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrests and restraint of rulers and people, interruptions by government or court orders, prevent or future orders of any regulatory body having proper jurisdiction, civil disturbances, explosions, breakage or accident to machinery or lines of pipe, freezing of wells or pipelines, and any other cause whether of the kind herein enumerated or otherwise, not within the control of the party claiming suspension and which, by the exercise of due diligence, such party is unable to overcome. Nothing contained herein, however, shall be construed to require either party to settle a strike against its will. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 56 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 243 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 8. CONTROL AND POSSESSION OF NATURAL GAS 8.1 As between El Paso and Shipper, El Paso shall be deemed to be in control and possession of the natural gas from the time it is delivered to El Paso at the Receipt Point(s) until it in redelivered to Shipper at the Delivery Point(s), and Shipper shall be deemed to be in control and possession of the natural gas at all other times. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 57 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 244 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 9. ADVERSE CLAIMS TO NATURAL GAS 9.1 Notwithstanding Section 10.1 herein, Shipper agrees to indemnify and hold harmless El Paso, its officers, agents, employees and contractors against any liability, loss or damage whatsoever, including litigation expenses, court costs and attorneys' fees, suffered by El Paso, its officers, agents, employees or contractors, where such liability, loss or damage arises directly or indirectly out of any demand, claim, action, cause of action or suit brought by any person, association or entity, public or private, asserting ownership of or an interest in the natural gas tendered for transportation or the proceeds resulting from any sale of that natural gas. The receipt and delivery of natural gas under the executed Transportation Service Agreement shall not be construed to affect or change title to the natural gas. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 58 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 245 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 10. INDEMNIFICATION 10.1 Each party to the executed Transportation Service Agreement shall bear responsibility for all of its own breaches, tortious acts, or tortious omissions connected in any way with the executed Transportation Service Agreement causing damages or injuries of any kind to the other party or to any third party, unless otherwise expressly agreed in writing between the parties. Therefore, the offending party as a result of such offense shall hold harmless and indemnify the non-offending party against any claim, liability, loss,.or damage whatsoever suffered by the non-offending party or by any third party. As used herein: the term "party" shall mean a corporation or partnership entity or individual and its officers, agents, employees and contractors; the phrase "damages or injuries of any kind" shall include without limitation litigation expenses, court costs, and attorneys' fees; and the phrase "tortious acts or tortious omissions" shall include without limitation sole or concurrent simple negligence, gross negligence, recklessness, and intentional acts or omissions. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 59 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 246 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 11. ODORIZATION 11.1 As between El Paso and Shipper, El Paso shall have no obligation whatsoever to odorize the natural gas delivered, nor to maintain any odorant levels in such natural gas. Notwithstanding Section 10.1 herein, Shipper agrees to indemnify and hold harmless El Paso, its officers, agents, employees and contractors against any liability, loss or damage, including litigation expenses, court costs and attorneys' fees, whether or not such liability, loss or damage arises out of any demand, claim, action, cause of action, and/or suit brought by Shipper or by any person, association or entity, public or private, that is not a party to the executed Transportation Service Agreement, where such liability, loss or damage is suffered by El Paso, its officers, agents, employees and/or contractors as a direct or indirect result of any actual or alleged sole or concurrent negligent failure by El Paso or any actual or alleged act or omission of any nature by Shipper to odorize the natural gas or product delivered under the executed Transportation Service Agreement or to maintain any odorant levels in such natural gas or product. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 60 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 247 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 12. NON-WAIVER OF FUTURE DEFAULT 12.1 No waiver by either El Paso or Shipper of any one or more defaults by the other in performance of any of the provisions of the executed Transportation Service Agreement shall operate or be construed as a waiver of any other existing or future default or defaults, whether of a like or of a different character. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 61 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 248 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 13. SERVICE CONDITIONS 13.1 Interruptible transportation service provided under this Volume No. 1-A Tariff is subject to and conditioned upon the availability of capacity sufficient to provide the transportation service without detriment or disadvantage to El Paso's firm transportation customers. 13.2 El Paso and Shipper acknowledge that the executed Transportation Service Agreement does not prohibit either party from selling or transferring its own facilities; therefore, neither El Paso nor Shipper shall have any obligation to provide services under the executed Transportation Service Agreement that requires the use of any facilities sold or transferred; provided, however, El Paso first shall seek abandonment authorization for any jurisdictional facilities or Jurisdictional services and Shipper shall have the right to protest such abandonment as inconsistent with the present or future public convenience and necessity. 13.3 Unless otherwise provided in the executed Transportation Service Agreement, in the event El Paso and Shipper agree in writing that additional facilities are necessary in order to implement the service provided under the executed Transportation Service Agreement, Shipper agrees to reimburse El Paso for all expenditures associated with the construction and installation of such facilities which shall be owned, operated and maintained by El Paso. 13.4 Unless otherwise agreed to in writing, El Paso shall only be responsible for the maintenance and operation of its own properties and facilities and shall not be responsible for the maintenance or operation of any other properties or facilities connected in any way with the transportation of natural gas. 13.5 El Paso shall have the right to interrupt the transportation of natural gas when necessary to test, alter, modify, enlarge or repair any facility or property comprising a part of, or appurtent to, the El Paso System, or otherwise related to the operation thereof. El Paso shall endeavor to cause a minimum of inconvenience to Shipper and, except in cases of emergency, shall give Shipper advance notice of its intention to so interrupt the transportation of gas and of the expected magnitude of such interruptions. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 62 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 249 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 13. SERVICE CONDITIONS (continued) 13.6 As a condition to providing service under Section 284.102(d) of the Commission's Regulations for any Shipper under this Volume No. 1-A Tariff, Shipper shall provide certification including sufficient information to verify that its services qualify under said section. Prior to commencing transportation service described in Section 284.102(d)(3) of the Commission's Regulations, El Paso must receive the certification required from a local distribution company or an intrastate pipeline pursuant to Section 284.102(d)(3). Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 63 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 250 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 14. STATUTORY REGULATION 14.1 The respective obligations of El Paso and Shipper under the executed Transportation Service Agreement are subject to the laws, orders, rules and regulations of duly constituted authorities having jurisdiction. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 64 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 251 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 15. ASSIGNMENTS 15.1 Shipper shall make no sale or assignment of the executed Transportation Service Agreement or any of the rights or obligations thereunder unless there first shall have been obtained the written consent thereto of El Paso; provided, however, that Shipper may, without the necessity of obtaining the consent of El Paso, assign any of its rights, but not its obligations thereunder to a trustee or trustees, individual or corporate, as security for bonds or other obligations or securities without such trustee or trustees becoming obligated to perform the obligations of the assignor thereunder and, if any such trustee be a corporation, without its being required to qualify to do business in any State in which performance of the executed Transportation Service Agreement may occur. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 65 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 252 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 16. DESCRIPTIVE HEADINGS 16.1 The descriptive headings of the provisions of the executed Transportation Service Agreement and of these Transportation General Terms and Conditions are formulated and used for convenience only and shall not be deemed to affect the meaning or construction of any such provision. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 66 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 253 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 17. TAXES 17.1 Shipper shall pay or cause to be paid all taxes and assessments imposed on Shipper with respect to natural gas transported prior to and including its delivery to El Paso, and El Paso shall pay or cause to be paid all taxes and assessments imposed on El Paso with respect to natural gas transported after its receipt by El Paso and prior to redelivery to Shipper, provided however, that Shipper shall pay to El Paso all taxes, levies or charges which El Paso may by law be required to collect from Shipper by reason of all services performed for Shipper. 17.2 Neither party shall be responsible or liable for any taxes or other statutory charges levied or assessed against any of the facilities of the other party used for the purpose of carrying out the provisions of the executed Transportation Service Agreement. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 67 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 254 Second Revised Volume No. 1-A Superseding Original Sheet No. 254 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND DEMONSTRATION FUNDING UNIT ADJUSTMENT PROVISION 18.1 Purpose - El Paso has joined with other enterprises in the formation of and participation in the activities and financing of the Gas Research Institute ("GRI"), an Illinois non-profit corporation. GRI has been organized to sponsor research, development and demonstration ("RD&D") programs in the field of natural and manufactured gas for the purpose of assisting all segments of the gas industry in providing adequate, reliable, safe, economic and environmentally acceptable gas service for the benefit of gas consumers and the general public. This Section 18 provides for-a volumetric surcharge and, as specified herein, a reservation surcharge applicable to the Program Funding Services comprising transportation services rendered by El Paso, under the rate schedules contained in this FERC Gas Tariff. Such surcharges are necessary to produce revenues required to fund El Paso's allocable pro rata share of the RD&D expenditures of GRI, as approved by the Commission. 18.2 Applicability - This Section 18 establishes El Paso's GRI General RD&D Funding Unit Adjustment to be included in El Paso's rates for transportation services rendered for Shippers, except other pipeline companies which include in their respective tariffs a charge for the GRI funding requirement, under rate schedules contained in this FERC Gas Tariff. This Section 18 also specifies the procedures to be utilized in changing El Paso's GRI General RD&D Funding Unit Adjustment under each such applicable rate schedule in order to reflect changes in El Paso's allocable share of GRI's approved RD&D expenditures. The GRI funding mechanism is designed to collect 50 percent of GRI's budget through reservation surcharges, and 50 percent through usage surcharges. Under such funding mechanism, the reservation and usage surcharges are applicable to volumes of natural gas transported by El Paso. In the event El Paso discounts its reservation and/or usage rates, the applicable surcharges shall be considered as the first rate increment to be discounted for purposes of this Section 18. If the discount is less than the reservation and/or usage surcharges, then the difference between the reservation and/or usage surcharges and the discount shall be remitted to GRI. The reservation surcharge is divided into two load factor categories at two distinct rates: (1) high load Issued by: Patricia A. Shelton, Vice President Issued on: NOVEMBER 30, 1994 Effective: January 01, 1995 68 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 255 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND DEMONSTRATION FUNDING UNIT ADJUSTMENT PROVISION (Continued) 18.2 Applicability (Continued) factor Shippers and (2) low load factor Shippers. The load factor is calculated yearly using the firm Shipper's most recent twelve (12) month throughput divided by its annual contract demand or billing determinant. The load factor for a new firm Shipper shall be calculated each month based on actual throughput for each prior month of service until a twelve (12) month history is established. Thereafter, the new firm Shipper's load factor shall be based on its twelve (12) month throughput consistent with other Shippers. For the purposes of this Section only and as set forth in Section 18.7 hereof, Shippers with a load factor exceeding 50 percent are classified as high load factor Shippers, and those Shippers with a load factor of 50 percent or less are classified as low load factor Shippers. 18.3 The GRI General RD&D Funding Unit Adjustment - The rates charged under each of the rate schedules applicable hereunder shall include, as appropriate, surcharge(s) for the GRI General RD&D Funding Unit Adjustment. Such surcharge(s) shall be that General RD&D Funding Unit amount proposed from time to time by GRI for its RD&D expenditures and approved by the Commission. The GRI General RD&D Funding Unit Adjustment surcharge(s) shall be effective on the applicable Adjustment Date provided in Section 18.4 hereof without suspension, or refund obligations. 18.4 Adjustment Date - The Adjustment Date under this Section 18 shall be the date as approved by the Commission. On and after the Adjustment Date El Paso shall, in accordance with the provisions of this Section 18, increase or decrease the rate applicable to each affected rate schedule so as to include the approved GRI General RD&D Funding Unit Adjustment to be collected during the period preceding the next Adjustment Date. 18.5 Time and Manner of Filing and Related Report - El Paso shall file changes in the GRI General RD&D Funding Unit Adjustment at least thirty (30) days prior to the proposed effective date by means of revised tariff sheets to those rate schedules contained in this FERC Gas Tariff. Such filing shall identify the amount of said adjustment (i.e., the GRI General RD&D Funding Unit as approved by the Commission) and the resulting currently effective tariff rates under each applicable rate schedule. Such filing shall be posted Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 69 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 256 Second Revised Volume No. 1-A Superseding Original Sheet No. 256 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND DEMONSTRATION FUNDING UNIT ADJUSTMENT PROVISION (Continued) 18.5 Time and Manner of Filing and Related Report (Continued) as defined by the Commission and shall be served upon each of El Paso's affected Shippers under rate schedules contained in this FERC Gas Tariff, and upon interested state regulatory agencies. 18.6 Disposition of GRI Funding Unit Adjustment Surcharge Revenues El Paso shall remit to GRI the total revenues resulting from the GRI General RD&D Funding Unit Adjustment provided by this Section 18 within fifteen (15) days following the receipt thereof from El Paso's affected Shippers. 18.7 Identification of High and Low Load Factor Shippers by Agreement HIGH LOAD FACTOR (in excess of 50%) SHIPPERS
Agreement Description Code Amoco Energy Trading Corporation 97JB Arizona Public Service Company 97ZC ASARCO Inc. 9834 ASARCO Inc. 982A Cyprus Miami Mining Corporation 982G El Paso Electric Company 9827 Los Angeles Department of Water and Power 9836 Magma Copper Company 97ZU Meridian Oil Marketing Inc. 97YW Meridian Oil Marketing Inc. 97YG Meridian Oil Trading Inc. 97J4 Meridian Oil Trading Inc. 97J5 Mission Energy Fuel Company 97YX Mobil Natural Gas Inc. 97YK Pacific Gas and Electric Company 97VU Phelps Dodge Corporation 97Z7 Saguaro Power Company 97YE San Diego Gas and Electric Company 9844 Southern California Edison Company 97YV Southern California Gas Company 97VT Southern Union Gas Company 97VX Sunrise Energy Company 97YL Texaco, Inc. 97YF U.S. Borax and Chemical Corporation 97YH West Texas Gas, Inc. 982V
Issued by: Patricia A. Shelton, Vice President Issued on: NOVEMBER 30, 1994 Effective: JANUARY 01, 1995 70 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 257 Second Revised Volume No. 1-A Superseding Original Sheet No. 257 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND DEMONSTRATION FUNDING UNIT ADJUSTMENT PROVISION (Continued) 18.7 Identification of High and Low Load Factor Shippers by Agreement (Continued) LOW LOAD FACTOR (50% or less) SHIPPERS
Agreement Description Code Arizona Electric Power Cooperative, Inc. 9838 Citizens Utilities Company 97ZH Gas Company of New Mexico 97VW Las Cruces, New Mexico, City of 982M Lordsburg, New Mexico, City of 982N Meridian Oil Trading Inc. 97YM Mesa, Arizona, City of 97ZV Natural Gas Processors Company 97YR Navajo Tribal Utility Authority 97ZY PEMEX Gas y Petroquimica Basica 97ZZ Salt River Project Agricultural Improvement 9826 and Power District Southdown, Inc. (SW Portland) 982Q Southwest Gas Corporation 97ZL Southwest Gas Corporation 97ZK
Issued by: Patricia A. Shelton, Vice President Issued on: NOVEMBER 30, 1994 Effective: JANUARY 01, 1995 71 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 258 Second Revised Volume No. 1-A Superseding Original Sheet No. 258 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE Interruptible transportation service under this FERC Gas Tariff shall be provided when, and to the extent that, El Paso determines that capacity is available in El Paso's existing facilities, which capacity is not subject to a prior claim by another customer or another class of service under a pre-existing contract, service agreement or certificate. Available interruptible capacity shall be allocated by El Paso on a first come/first served basis, as determined by El Paso, and interruptible transportation service hereunder shall be provided in accordance with such allocation. The provisions of this Section 19 shall also be applicable to interruptible service under special rate schedules contained in El Paso's Volume No. 2 Tariff. 19.1 A valid request for interruptible transportation service under this FERC Gas Tariff made after the effectiveness of Section 23 hereof shall be in accordance with, and contain the data required by the provisions contained in such Section 23. 19.2 With respect to all requests for interruptible service by a Shipper who had not contracted for service prior to October 9, 1985, the provisions of Sections 19.3 through 19.6 and Section 23.5 shall govern. 19.3 On any day that sufficient capacity is not available in El Paso system to provide transportation for all gas tendered under executed Transportation Service Agreements with Shippers referred to in Section 19.2 above, El Paso shall allocate its available capacity among such Shippers on a first come/first served basis. For purposes of allocating such capacity, any Shipper holding an effective Transportation Service Agreement or any Shipper who has furnished El Paso with a valid request complying with the requirements contained in Section 19.4 and in Section 23, when accepted by El Paso in an executed Transportation Service Agreement, will be entitled to priority over any Shipper furnishing El Paso with a valid request on a later date and shall be unaffected by and shall have priority over subsequent requests for service under Rate Schedule T-1. Issued by: A. W. Clark, Vice President Issued on: AUGUST 30, 1994 Effective: OCTOBER 01, 1994 72 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 259 Second Revised Volume No. 1-A Superseding Original Sheet No. 259 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.4 Requests for transportation under this FERC Gas Tariff will be invalid and will not be considered if service is requested to commence later than six (6) months after the information specified in Section 23.5 of this FERC Gas Tariff is provided to El Paso. 19.5 Upon receipt of all of the information required in Section 23 for a valid request for transportation service, El Paso shall prepare and tender to Shipper for execution a Transportation Service Agreement in the form contained in this Volume No. 1-A Tariff. If Shipper fails to execute the Transportation Service Agreement or any amendment thereto within thirty (30) days of the date tendered, Shipper's request shall be deemed null and void. 19.6 If a Shipper that has executed a Transportation Service Agreement fails, on the later of the date service is to commence or fifteen (15) days after the Shipper executes the Transportation Service Agreement, or the completion of construction of any necessary facilities or the issuance of any necessary certificate authorization, to nominate pursuant to Section 4.1 of these General Terms and Conditions any quantity of gas for transportation or fails, having nominated a quantity of gas and El Paso having scheduled the quantity for transportation, to tender any gas for transportation, the Shipper's Transportation Service Agreement shall be terminated and the Shipper's request for service shall be deemed null and void; provided, however, that the Shippers Transportation Service Agreement shall not be terminated nor shall the Shipper's request for service be deemed null and void if the Shipper's failure to nominate or tender is caused by an event of force majeure as defined in Section 7 of these General Terms and Conditions. 19.7 El Paso shall not be required to perform or continue service on behalf of any Shipper that fails to comply with the terms contained in Sections 19 and 23 and any and all terms of the applicable rate schedule and the terms of Shipper's Transportation Service Agreement with El Paso. El Paso shall have the right to waive any one or more specific defaults by any Shipper under Sections 19.8 through 19.13, inclusive, or any provision of the applicable rate schedule or Transportation Service Agreement; provided, however, that no such waiver shall operate or be Issued by: A. W. Clark, Vice President Issued on: AUGUST 30, 1994 Effective: OCTOBER 01, 1994 73 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 260 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.7 (Continued) construed as a waiver of any other existing or future default or defaults, whether of a like or different character. 19.8 Upon request of El Paso, Shipper shall from time to time submit estimates of daily, monthly and annual quantities of gas to be transported, including peak day requirements. 19.9 Shipper shall endeavor to deliver and receive natural gas in uniform hourly quantities during any day with operating variations to be kept to the minimum feasible. 19.10 El Paso shall not be required to perform or to continue interruptible service under this FERC Gas Tariff on behalf of any Shipper who is or has become insolvent, or fails to meet payment obligations in accordance with Sections 6.2 or 6.3 of this FERC Gas Tariff, or who, at El Paso's request, fails, within a reasonable period to demonstrate creditworthiness or fails to provide adequate assurances of performance as such are defined in the Texas version of the Uniform Commercial Code (See, Vernon's Texas Codes Annotated, Business and Commerce Code, Acts 1967, 60th Leg., Ch. 785, H.B. No. 293, UCC effective September 1, 1967). However, such Shipper may receive interruptible service under this FERC Gas Tariff if Shipper prepays for such service or furnishes good and sufficient security, as determined by El Paso in its reasonable discretion , an amount equal to the cost of performing the service requested by Shipper for a three (3) month period to include the cost of gas for permissible imbalance quantities. For purposes of this FERC Gas Tariff, the insolvency of a Shipper shall be evidenced by the filing by such Shipper or any parent entity thereof (hereinafter collectively referred to as "the Shipper") of a voluntary petition in bankruptcy or the entry of a decree or order by a court having jurisdiction in the premises adjudging the Shipper as bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of the Shipper under the Federal Bankruptcy Act or any other applicable federal or state law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Shipper or of any substantial part of its property, or the ordering of the winding-up or liquidation of its affairs, with said order or Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 74 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 261 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.10 (Continued) decree continuing unstayed and in effect for a period of sixty (60) consecutive days. Notwithstanding the above and Section 6.4 of this FERC Gas Tariff, El Paso shall not suspend service to any Shipper, who is or has become insolvent, in a manner that is inconsistent with the Federal Bankruptcy Code. 19.11 El Paso shall have no responsibility prior to its acceptance of natural gas at the receipt point(s) and after delivery at the delivery point(s), and Shipper shall have sole responsibility for all arrangements necessary for delivery of natural gas to El Paso at the receipt point(s) for transportation, and for all arrangements necessary for receipt of natural gas for the account of Shipper at the delivery point(s), which arrangements otherwise meet the provisions set forth in these General Terms and Conditions. 19.12 Resolution of Imbalances For purposes of this Section 19.12 "Shipper" shall include any party utilizing El Paso's system and services including, without limitation, any party tendering or receiving gas under Shipper's contract but excluding any operator of interconnecting facilities and any volume subject to a written assistance agreement with El Paso. El Paso and the operator of any interconnecting facilities may cash-out imbalances, pursuant to a written agreement between them. (a) Imbalances Prior to Effective Date of this Provision Imbalances existing prior to the effective date of this provision will be corrected in kind, as described below, unless El Paso and Shipper agree to correct such imbalances in cash. El Paso and Shipper shall attempt, in good faith, to agree upon the historical imbalance and the time period to correct such historical imbalance. If, despite such good faith efforts, El Paso and Shipper fail to reach written agreement upon the appropriate corrective action within six (6) months from the effectiveness of this section, then Shipper shall be required to correct any remaining imbalance within sixty (60) days, subject to operational constraints on El Paso's system. El Paso shall extend the sixty (60) Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 75 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 262 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.12 Resolution of Imbalances (Continued) day balancing period by one (1) day for each day that El Paso is unable to receive or deliver scheduled imbalance gas due to operational constraints on El Paso's system. If after the sixty (60) day balancing period or extension due to operational constraints Shipper has not corrected the imbalance, then El Paso shall (i) for any remaining imbalances where deliveries exceed receipts ("negative imbalance") charge Shipper per dth based upon the arithmetic average of the System Weighted Index Price for each quarter of the twelve (12) months ending December 31, 1992 (the System Weighted Index Price for each quarter shall be based on the method set forth in Section 19.12(e)(i) below); or (ii) for any remaining imbalances where receipts exceed deliveries ("positive imbalance") retain the imbalance at no cost and free and clear of any adverse claims by any party or any obligation to account for such gas; provided however, that in the event of a bona fide dispute by Shipper of the amount of the imbalance, El Paso shall not take the action outlined above when Shipper acts in a timely manner to provide additional information and security for El Paso in accordance with the following procedures. (i) Identify Dispute: Within fifteen (15) days after El Paso's notification of an imbalance, Shipper shall notify El Paso by written correspondence of the imbalance that is in bona fide dispute and of all reasons and documentation why Shipper believes El Paso's calculation of the imbalance is not correct; and (ii) Payment Security: Within thirty (30) days after El Paso's notification of an imbalance, Shipper shall either agree to the imbalance calculated by El Paso without prejudice to Shipper's rights to dispute all or part of said imbalance and subject to return of the disputed imbalance so identified after resolution of that dispute or Shipper shall take the necessary actions to correct the imbalances it concedes to be correct and furnish good and sufficient surety bond, guaranteeing the Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 76 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 263 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.12 Resolution of Imbalances (Continued) correction of any imbalance ultimately found owed to El Paso after resolution of the dispute, including late payment charges which accrue until resolution of the dispute with respect to any negative imbalances, which resolution may be reached either by agreement or judgment of a court of competent jurisdiction. If resolution of the dispute is in favor of Shipper and the furnished a surety bond then El Paso shall pay to Shipper the costs incurred in securing that surety bond for this dispute including any late payment charges actually paid to El Paso. (b) Calculation of an Imbalance Subsequent to the Effectiveness of this Provision - El Paso and Shippers shall resolve an over-delivery or under-delivery of gas to El Paso each month in accordance with this Section 19.12. Each month, El Paso will calculate a percentage imbalance for each individual contract for each Shipper by dividing the total cumulative imbalance quantities in excess of 1,000 dth, attributable to the imbalance amount for such contract (numerator) by the most recent calendar year monthly average of quantities actually delivered (denominator). Such average is derived by dividing the quantities delivered during the calendar year by the number of months the quantities were delivered; provided however, if no quantities have been delivered during the last calendar year to Shipper, the monthly average shall be Shipper's total Transportation Service Agreement Maximum Daily Quantity multiplied by 30 days. The result of such calculation will be included on El Paso's imbalance statement to Shipper, or its designee, and shall serve as notification to the Shipper of an imbalance. If an imbalance is equal to or greater than +/-5%, the Shipper is provided additional notice on said statement that if such imbalance continues and becomes equal to or greater than +/-10%, the Shipper is subject to cash-out of the imbalance pursuant to this Section 19.12; provided, however, that in no event shall cash-out be assessed when the amount of the imbalance does not exceed 1,000 dth, unless the parties mutually agree otherwise; provided, further, if a verifiable imbalance is caused by El Paso, that portion of the Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 77 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 264 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.12 Resolution of Imbalances (Continued) imbalance shall not be considered as part of Shipper's imbalance for purposes of initiating cash-out. In addition, cash-out of imbalances will not be mandatory if the parties have reached written agreement on the resolution of the imbalance provided such agreement is final prior to the triggering of cash-out as specified in Section 19.12(c) below. Written agreements may consist of, but are not limited to the following provisions (i) offsetting of imbalances; (ii) extension of a payback period within a set time period; and (iii) negotiated price other than the cash-out prices reflected herein. (c) Triggering of Cash-Out - Except for those contracts without activity for a period of six (6) months, as discussed in Section 19.12(d), any cumulative imbalance at the end of any month that is within a tolerance level less than +/-5% shall not be subject to this Section 19.12 during such month. Such imbalance shall be forwarded to the next month's imbalance calculation. If the cumulative imbalance for any month is equal to or greater than +/-5%, El Paso shall notify Shipper, as indicated in Section 19.12(b), that it is approaching a cash-out situation for an imbalance actual to or in excess of +/-10%. For any month that a cumulative imbalance is equal to or in excess of +/-10%, cash-out of the imbalance will take place provided Shipper has received a minimum of two (2) consecutive monthly notices (minimum of 45 days from date of first notice) alerting Shipper to an imbalance equal to or in excess of +/-5%. El Paso shall extend the 45-day grace period by one (1) day for each day that El Paso is unable to receive or deliver requested and confirmed imbalance gas for a given contract due to operational constraints on El Paso's system. If the parties have not reached written agreement otherwise, the imbalance will be reduced to +/-5% by "cash-out" the month following the last notice, at the dollar value calculated with the cumulative imbalance and an established monthly price, referred to herein as the Index Price, as determined in Section 19.12(e) below. The Index Price shall be calculated as of the month the imbalance first equals or exceeds the +/-10% level. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 78 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 265 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.12 Resolution of Imbalances (Continued) (d) Six-Month Resolution of Inactive Contracts - El Paso will notify Shipper after three (3) consecutive months of inactivity that at the end of any six (6) month period that a contract between Shipper and El Paso has been inactive and has maintained an imbalance of less than +/-10%, for which no cash-out was applicable and before the next invoice and balance statement date , such imbalance shall be reduced to zero (O) by cash-out utilizing the Index Price for the month after the end of six (6) month period reflected in Section 19.12(e). (e) Index Prices and Cash Out (i) Cash-out shall be based on one of four calculated price indices, depending on whether Shipper has one or more of the three supply basins (i.e., San Juan, Permian or Anadarko Basins) included in its agreement. A single price index calculated only for a specific supply basin will be used if Shipper has only that one supply basin in its agreement. A System Weighted Index Price calculated for all supply basins will be used if Shipper has more than one supply basin in its agreement. The calculation of each price index is set forth below: (1) The Anadarko Basin Index Price shall be computed using a sample average of reported prices as delivered to El Paso's Mainline System at Washita, Anadarko, Oklahoma, or the Texas Panhandle from the publications identified in Section 19.12(e)(ii); (2) The Permian Basin Index Price shall be computed using a simple average of reported prices as delivered to El Paso'" Mainline System at West Texas, Permian or Waha from the publications identified in Section 19.12(e)(ii); and Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 79 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 266 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.12 Resolution of Imbalances (Continued) (3) The San Juan Basin Index Price shall be computed using a simple average of reported prices as delivered to El Paso's Mainline System at Ignacio, San Juan or New Mexico from the publications identified in Section 19.12(e)(ii). (4) The System Weighted Index Price shall be computed monthly by using the weighted average of the Anadarko Basin Index Price, the Permian Basin Index Price, and the San Juan Basin Index Price. The weighting is based on the volumes entering El Paso's system in each basin during the previous quarter and will be updated quarterly. (ii) The four trade publications referenced above are Inside FERC Gas Market Report (Prices of Spot Gas Delivered to Pipelines), Natural Gas Week (Spot Prices on Natural Gas Pipeline Systems, Delivered to Pipelines), Gas Daily (Natural Gas Survey), and Natural Gas Intelligence Gas Price Index (Spot Gas Prices Delivered to Pipeline, 30 Day Supply Transactions). In the event any of the publications cease publication or to the extent a publication fails to report spot prices, then El Paso shall reserve the right to substitute prices reported in a similar independent publication or continue the pricing formula using the average of the remaining publications. Changes in the name, format or other method of reporting by the publications in (e) above that do not materially affect the content shall not affect their use hereunder, (iii) El Paso shall post the Index Price monthly on its electronic bulletin board on or before the 15th day of each month applicable to the prior business month. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 80 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 267 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.12 Resolution of Imbalances (Continued) (iv) For any contract where total deliveries by El Paso for a Shipper exceed the total receipts from Shipper, after appropriate reductions, such imbalance shall be "cashed out" based on the percentages provided below. Further, the Index Price shall be adjusted to reflect the point at which the imbalance is held. (1) For any contract subject to Section 19.12(d), or by mutual agreement any contract with an imbalance up to and including +5%, the quantity will be invoiced at 100% of the Index Price; (2) For any contract subject to Section 19.12(d) or any contract with an imbalance greater than +5% but less than or equal to +10%, the quantity in excess of +5% will be invoiced at 110% of the Index Price; (3) For any contract with an imbalance greater than +10% but less than or equal to +15%, the volume in excess of +10% will be invoiced at 120% of the Index Price; (4) For any contract with an imbalance greater than +15% but less than or equal to +20%, the volume in excess of +15% will be invoiced at 130% of the Index Price; and (5) For any contract with an imbalance greater than +20%, the volume in excess of +20% will be invoiced at 140% of the Index Price. (v) For any contract where total receipts by El Paso from a Shipper, after appropriate reductions, exceed total deliveries for that Shipper, such imbalance shall be "cashed out" based on the percentages provided below. Further, the Index Price shall be adjusted to reflect the point at which the imbalance is held. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 81 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 268 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.12 Resolution of Imbalances (Continued) (1) For any contract subject to Section 19.12(d) or subject to any other mutually agreeable terms, with an imbalance up to and including -5%, the quantity will be purchased by El Paso at 100% of the Index Price; (2) For any contract subject to Section 19.12(d) or any contract with an imbalance greater than -5% but less than or equal to -10%, the quantity in excess of -5% will be purchased by El Paso at 90% of the Index Price; (3) For any contract with an imbalance greater than -10% but less than or equal to -15%, the volume in excess of -10% will be purchased by El Paso at 80% of the Index Price; (4) For any contract with an imbalance greater than -15% but less than or equal to -20%, the volume in excess of -15% will be purchased by El Paso at 70% of the Index Price; and (5) For any contract with an imbalance greater than -20%, the volume in excess of -20% will be purchased by El Paso at 60% of the Index Price. (vi) At the time a Shipper is in a cash-out position requiring payment to El Paso at the appropriate rate set forth in Section 19.12(e)(iv) above and such Shipper also has an Unauthorized Gas balance, as such term is defined in Section 27.1 of these General Terms and Conditions, such Unauthorized Gas balance may be offset against the quantities due El Paso within the same production basin and adjusted to reflect the point at which the imbalance is held. At the time of invoicing for the net imbalance, El Paso shall appropriately invoice or account for any production area charges and liquid credits applicable to the unauthorized Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 82 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 269 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.12 Resolution of Imbalances (Continued) gas used as an offset. This provision is not applicable to the Unauthorized Gas retained as a penalty pursuant to Section 27 of these General Terms and Conditions. Prior to any offsets, El Paso at its option may first offset any under or over-deliveries between contracts with such Shipper. Shipper or its suppliers shall be responsible for reporting and payment of any royalty, tax, or other burdens on natural gas volumes received by El Paso and El Paso shall not be obligated to account for or pay such burdens. (f) Crediting of Revenues - When the aggregate value received from all sources resulting from cash-out exceeds the cost of gas plus administrative fees, El Paso shall credit such net amount within 90 days of the payment date to Shippers on a pro rata basis in accordance with the volumes transported for each Shipper. (g) Netting of Contracts - For purposes of resolving an imbalance with a Shipper, El Paso shall net gas imbalances, on a non-discriminatory basis, adjusted to reflect a common point at which the imbalance is held, between contracts with such Shipper pursuant to the conditions identified below. (i) Netting between gathering and pooling agreement imbalances is negotiable as long as the imbalances were generated in the same basin. (ii) Netting between upstream interconnects and pooling agreements is negotiable if the pooling agreement has that interconnect point as a receipt point. (iii) Netting between downstream interconnect and mainline agreement imbalances is negotiable if the agreement has the interconnect point as a delivery point. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 83 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 270 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE Continued) 19.12 Resolution of Imbalances (Continued) (iv) Netting between Unauthorized Gas and mainline or pooling/gathering agreement imbalances is negotiable if both the Unauthorized Gas and imbalance were generated in the same basin. (v) Netting between mainline agreement imbalances (for similar transportation service) is negotiable. (vi) Netting between gathering/pooling and mainline agreements is negotiable if the gathering/pooling basin is a receipt point on the mainline agreement. For any specific situation not discussed above, El Paso is willing to negotiate a transportation transaction which could have the effect of netting imbalances. 19.13 Unauthorized Overpull Penalty (a) A penalty shall be levied by El Paso and paid in dollars by any receiving party (any Shipper, Local Distribution Company, Direct Sales Customer or other party who operates the facilities that receive the gas transported by El Paso) who exceeds the limits specified below. Such penalty is applicable when, in times of capacity constraints, or when, due to unforeseen circumstances beyond El Paso's control, El Paso has determined that its ability to maintain scheduled deliveries to all receiving parties is materially threatened due to insufficient pressures in El Paso's system and El Paso so notifies said receiving parties. Nothing herein shall limit El Paso's right to take any further actions required to maintain the integrity of its system operations. (b) On any day El Paso determines that it is unable to deliver the total volumes of gas scheduled for delivery for the account of all Shippers, it shall have the right to notify all receiving parties that an Unauthorized Overpull Penalty situation exists. Contemporaneously with, or shortly Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 84 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 271 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued) 19.13 Unauthorized Overpull Penalty (Continued) following such notice, El Paso shall give notice to any receiving party who is taking volumes at a level that would subject such party to an Unauthorized Overpull Penalty as provided below. (c) The quantity of gas subject to such penalty is that quantity of gas taken by the receiving party which exceeds the quantity of gas scheduled by El Paso for delivery to such party on any day. (d) Upon receipt of a notification from El Paso, such party shall within twenty-four (24) hours reduce takes to a level no more than 3% above its scheduled volume for such day or 1,000 dth, whichever is larger. Such twenty-four (24) hour notice period shall commence at seven (7:00) a.m. Mountain Standard Time on the day after notice is actually provided. If after the twenty-four (24) hour notice period the receiving party continues to take volumes of gas that exceed the foregoing threshold, an Unauthorized Overpull Penalty shall be levied by El Paso and paid in dollars by any receiving party as follows: (i) A penalty of $5.00 per dth shall apply to all unauthorized overrun volumes which exceed the 3% or 1,000 dth tolerance level, whichever is larger, up to the first 5% of scheduled volumes; and (ii) A penalty of $10.00 per dth shall apply to daily unauthorized overrun volumes in excess of 5% of scheduled volumes. El Paso shall notify Shippers each day during an Unauthorized Overpull Penalty situation, via El Paso's Electronic Bulletin Board, that the situation continues to exist. Such notice does not constitute notification of a new penalty period pursuant to this Section 19.13(d) and does not begin a new twenty-four (24) hour correction period. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 85 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 272 Second Revised Volume No. 1-A Superseding Original Sheet No. 272 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE Firm transportation service under this FERC Gas Tariff shall be provided when , and to the extent that, El Paso determines that firm capacity is available in El Paso's existing facilities, which firm capacity is not subject to a prior claim by another customer or another class of service. Firm capacity which becomes available on and after the effective date of this Section 20 , other than capacity which becomes available through the installation of new mainline transmission facilities (other than minor tap), and which is not converted or subject to conversion to firm transportation capacity pursuant to Section 284.10 of the Commission's Regulations, shall be made available to potential Shippers to support new firm transportation agreements on a first come/first served basis. The provisions of this Section 20 shall also be applicable to firm service under special rate schedules contained in El Paso's Volume No. 2 Tariff. 20.1 A valid request for firm transportation service under this FERC Gas Tariff made after the effectiveness of Section 23 hereof shall be in accordance with, and contain the data required by the provisions contained in such Section 23. 20.2 With respect to all requests for firm transportation service by a Shipper made on and after the effective date of this Section 20, the provisions of Sections 20.3 through 20.5 and 23.5 shall govern. 20.3 (a) The availability of firm capacity for contract shall be determined by the time and date El Paso receives a valid request for service under this FERC Gas Tariff, which conforms to Section 20.4 below and the provisions contained in Section 23 upon effectiveness of such section. El Paso shall consider all valid requests in the order received, and when a request for service is accepted in writing by El Paso. Allocation of contracted firm capacity will be on a pro rata basis. Issued by: A. W. Clark, Vice President Issued on: AUGUST 30, 1994 Effective: OCTOBER 01, 1994 86 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 273 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.3 (Continued) (b) In the event that two or more Shippers seek to obtain the firm capacity that one or more Shippers offer to relinquish on the Outer Continental Shelf, such capacity shall be allocated as follows: (i) during the open season conducted in accordance with Order No. 509, et seq., firm capacity will be reallocated in accordance with Section 284.304(a) of the Commission's Regulations; and (ii) after the open season within ten (10) days of receiving a complete and valid request for firm transportation, El Paso will provide the requesting Shipper a list of all five Shippers under contract with El Paso. If the requesting Shipper finds an existing Shipper willing to relinquish voluntarily all or a portion of its firm capacity, El Paso will reallocate that capacity on a first come/first served basis. The relinquishing Shipper and the new Shipper shall advise El Paso in writing of their mutual agreement. In the event there is more than one valid request for service on a given day, and such requests exceed the available firm capacity, such capacity shall be allocated among the requesting Shippers on a pro rata basis. Any capacity which is relinquished by an existing Shipper and subsequently assumed by the requesting Shipper must have compatible receipt and delivery point obligations, unless El Paso has capacity available at other requested receipt and delivery points. In the event El Paso has uncommitted firm capacity available, it may assign part or all of that capacity before it reallocates the capacity of existing Shippers. Upon execution of the new Transportation Service Agreement with the new Shipper, El Paso shall be absolved of all service obligations to the relinquishing Shipper and shall be deemed to have received pregranted abandonment authorization for such relinquishing Shipper. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 87 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 274 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.4 Requests for firm transportation hereunder shall be accompanied by a prepayment, not to exceed $10,000.00, of the total Reservation Charge provided by Section 4.1 of Rate Schedule T-3 of this FERC Gas Tariff. 20.5 Upon receipt of all of the information required in Section 23 for a valid request for transportation service, El Paso shall prepare and tender to Shipper for execution a Transportation Service Agreement in the form contained in this Volume No. 1-A Tariff. If Shipper fails to execute the Transportation Service Agreement or any amendment thereto within thirty (30) days of the date tendered, Shipper's request shall be deemed null and void. 20.6 El Paso shall not be required to perform or continue service on behalf of any Shipper that fails to comply with the terms contained in Sections 20 and 23 and any and all terms of the applicable rate schedule and the terms of Shipper's Transportation Service Agreement with El Paso. El Paso shall have the right to waive any one or more specific defaults by any Shipper under Sections 20.7 through 20.12, inclusive, or any provision of the applicable rate schedule or Transportation Service Agreement; provided, however, that no such waiver shall operate or be construed as a waiver of any other existing or future default or defaults, whether of a like or different character. 20.7 Upon request of El Paso, Shipper shall from time to time submit estimates of daily, monthly and annual quantities of gas to be transported, including peak day requirements. 20.8 Shipper shall endeavor to deliver and receive natural gas in uniform hourly quantities during any day with operating variations to be kept to the minimum feasible. 20.9 El Paso shall not be required to perform or to continue firm service under this FERC Gas Tariff on behalf of any Shipper who is or has become insolvent, or fails to meet payment obligations in accordance with Sections 6.2 or 6.3 of this FERC Gas Tariff, or who, at El Paso's request, fails, within a reasonable period to demonstrate creditworthiness or fails to provide adequate assurances of performance as such are defined in the Texas version of the Uniform Commercial Code (See, Vernon's Texas Codes Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 88 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 275 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.9 (Continued) Annotated, Business and Commerce Code, Acts 1967, 60th Leg., Ch. 785, H.B. No. 293, UCC effective September 1, 1967). However, such Shipper may receive firm service under this FERC Gas Tariff if Shipper prepays for such service or furnishes good and sufficient security, as determined by El Paso in its reasonable discretion, an amount equal to the cost of performing the service requested by Shipper for a three (3) month period to include the cost of gas for permissible imbalance quantities. For purposes of this FERC Gas Tariff, the insolvency of a Shipper shall be evidenced by the filing by such Shipper or any parent entity thereof (hereinafter collectively referred to as "the Shipper") of a voluntary petition in bankruptcy or the entry of a decree or order by a court having jurisdiction in the premises adjudging the Shipper as bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of the Shipper under the Federal Bankruptcy Act or any other applicable federal or state law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the Shipper or of any substantial part of its property, or the ordering of the winding-up or liquidation of its affairs, with said order or decree continuing unstayed and in effect for a period of sixty (60) consecutive days. Notwithstanding the above and Section 6. 4 of this FERC Gas Tariff, El Paso shall not suspend service to any Shipper, who is or has become insolvent, in a manner that is inconsistent with the Federal Bankruptcy Code. 20.10 El Paso shall have no responsibility prior to its acceptance of natural gas at the receipt point(s) and after delivery at the delivery point(s), and Shipper shall have sole responsibility for all arrangements necessary for delivery of natural gas to El Paso at the receipt point(s) for transportation, and for all arrangements necessary for receipt of natural gas for the account of Shipper at the delivery point(s), which arrangements otherwise meet the provisions set forth in these General Terms and Conditions. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 89 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 276 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.11 Resolution of Imbalances For purposes of this Section 20.11 "Shipper" shall include any party utilizing El Paso's system and services including, without limitation, any party tendering or receiving gas under Shipper's contract but excluding any operator of interconnecting facilities and any volume subject to a written assistance agreement with El Paso. El Paso and the operator of any interconnecting facilities may cash-out imbalances, pursuant to a written agreement between them. (a) Imbalances Prior to Effective Date of this Provision -- Imbalances existing prior to the effective date of this provision will be corrected in kind, as described below, unless El Paso and Shipper agree to correct such imbalances in cash. El Paso and Shipper shall attempt, in good faith, to agree upon the historical imbalance and the time period to correct such historical imbalance. If, despite such good faith efforts, El Paso and Shipper fail to reach written agreement upon the appropriate corrective action within six (6) months from the effectiveness of this section, then Shipper shall be required to correct any remaining imbalance within sixty (60) days, subject to operational constraints on El Paso's system. El Paso shall extend the sixty (60) day balancing period by one (1) day for each day that El Paso is unable to receive or deliver scheduled imbalance gas due to operational constraints on El Paso's system. If after the sixty (60) day balancing period or extension due to operational constraints Shipper has not corrected the imbalance, then El Paso shall (i) for any remaining imbalances where deliveries exceed receipts ("negative imbalance") charge Shipper per dth based upon the arithmetic average of the System Weighted Index Price for each quarter of the twelve (12) months ending December 31, 1992 (the System Weighted Index Price for each quarter shall be based on the method set forth in Section 20.11(e)(i) below); or (ii) for any remaining imbalances where receipts exceed deliveries (positive imbalances) retain the imbalance at no cost and free and clear of any adverse claims by any party or any obligation to account for such gas; provided however, that in the event of a bona fide dispute by Shipper of Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 90 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 277 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.11 Resolution of Imbalances (Continued) the amount of the imbalance, El Paso shall not take the action outlined above when Shipper acts in a timely manner to provide additional information and security for El Paso in accordance with the following procedures. (i) Identify Dispute: Within fifteen (15) days after El Paso's notification of an imbalance, Shipper shall notify El Paso by written correspondence of the imbalance that is in bona fide dispute and of all reasons and documentation why Shipper believes El Paso's calculation of the imbalance is not correct: and (ii) Payment Security: Within thirty (30) days after El Paso's notification of an imbalance, Shipper shall either agree to the imbalance calculated by El Paso without prejudice to Shipper's rights to dispute all or part of said imbalance and subject to return of the disputed imbalance so identified after resolution of that dispute or Shipper shall take the necessary actions to correct the imbalances it concedes to be correct and furnish good and sufficient surety bond, guaranteeing the correction of any imbalance ultimately found owed to El Paso after resolution of the dispute, including late payment charges which accrue until resolution of the dispute with respect to any negative imbalances, which resolution may be reached either by agreement or judgment of a court of competent jurisdiction. If resolution of the dispute is in favor of Shipper and the Shipper furnished a surety bond then El Paso shall pay to Shipper the costs incurred in securing that surety bond for this dispute including any late payment charges actually paid to El Paso. (b) Calculation of an Imbalance Subsequent to the Effectiveness of this Provision - El Paso and Shippers shall resolve an over-delivery or under-delivery of gas to El Paso each month Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 91 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 278 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.11 Resolution of Imbalances (Continued) in accordance with this Section 20.11. Each month, El Paso will calculate a percentage imbalance for each individual contract for each Shipper by dividing the total cumulative imbalance quantities in excess of 1,000 dth, attributable to the imbalance amount for such contract (numerator) by Shipper's Transportation Contract Demand multiplied by 30 days (denominator) or, with respect to those Shippers with an executed Transportation Service Agreement which requires the delivery by El Paso of "Full Requirements," the average non-coincidental three (3) day peak over the most recent five (5) year period multiplied by 30 days (denominator). The result of such calculation will be included on El Paso's imbalance statement to Shipper, or its designee, and shall serve as notification to the Shipper of an imbalance. If an imbalance is equal to or greater than +/-5%, the Shipper is provided additional notice on said statement that if such imbalance continues and becomes equal to or greater than +/-10%, the Shipper is subject to cash-out of the imbalance pursuant to this Section 20.11; provided, however, that in no event shall cash-out be assessed when the amount of the imbalance does not exceed 1,000 dth, unless the parties mutually agree otherwise provided, further, if a verifiable imbalance is caused by El Paso, that portion of the imbalance shall not be considered as part of Shipper's imbalance for purposes of initiating cash-out. In addition, cash-out of imbalances will not be mandatory if the parties have reached written agreement on the resolution of the imbalance provided such agreement is final prior to the triggering of cash-out as specified in Section 20.11(c) below. Written agreements may consist of, but are not limited to the following provision (i) offsetting of imbalances; (ii) extension of a payback period within a set time period; and (iii) negotiated price other than the cash-out prices reflected herein. (c) Triggering of Cash-Out - Except for those contracts without activity for a period of six (6) months, as discussed in Section 20.11(d), any cumulative imbalance at the end of any month that is within a tolerance level less than +/-5% shall Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 92 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 279 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.11 Resolution of Imbalances (Continued) not be subject to this Section 20.11 during such month. Such imbalance shall be forwarded to the next month's imbalance calculation. If the cumulative imbalance for any month is equal to or greater than +/-5%, El Paso shall notify Shipper, as indicated in Section 20.11(b), that it is approaching a cash-out situation for an imbalance equal to or in excess of +/-10%. For any month that a cumulative imbalance is equal to or in excess of +/-10%, cash-out of the imbalance will take place provided Shipper has received a minimum of two (2) consecutive monthly notices (minimum of 45 days from date of first notice) alerting Shipper to an imbalance equal to or in excess of +/-5%. El Paso shall extend the 45-day grace period by one (1) day for each day that El Paso is unable to receive or deliver requested and confirmed imbalance gas for a given contract due to operational constraints on El Paso's system. If the parties have not reached written agreement otherwise, the imbalance will be reduced to +/-5% by "cash-out" the month following the last notice, at the dollar value calculated with the cumulative imbalance and an established monthly price, referred to herein as the Index Price, as determined in Section 20.11(e) below. The Index Price shall be calculated as of the month the imbalance first equals or exceeds the +/-10% level. (d) Six-Month Resolution of Inactive Contracts - El Paso will notify Shipper after three (3) consecutive months of inactivity that at the end of any six (6) month period that a contract between Shipper and El Paso has been inactive and has maintained an imbalance of less than +/-10%, for which no cash-out was applicable and before the next invoice and balance statement date, such imbalance shall be reduced to zero (O) by cash-out utilizing the Index Price for the month after the end of six (6) month period reflected in Section 20.11(e). (e) Index Prices and Cash Out (i) Cash-out shall be based on one of four calculated price indices, depending on whether Shipper has one Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 93 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 280 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.11 Resolution of Imbalances (continued) or more of the three supply basins (i.e., San Juan, Permian or Anadarko Basins) included in its agreement. A single price index calculated only for a specific supply basin will be used if Shipper has only that one supply basin in its agreement. A System Weighted Index Price calculated for all supply basins will be used if Shipper has more than one supply basin in its agreement. The calculation of each price index is set forth below: (1) The Anadarko Basin Index Price shall be computed using a simple average of reported prices as delivered to El Paso's Mainline System at Washita, Anadarko, Oklahoma, or the Texas Panhandle from the publications identified in Section 20.11(e)(ii); (2) The Permian Basin Index Price shall be computed using a simple average of reported prices as delivered to El Paso's Mainline System at West Texas, Permian or Waha from the pulications identified in Section 20.11(e)(ii); and (3) The San Juan Basin Index Price shall be computed using a simple average of reported prices as delivered to El Paso's Mainline System at Ignacio, San Juan or New Mexico from the publications identified in Section 20.11(e)(ii). (4) The System Weighted Index Price shall be computed monthly by using the weighted average of the Anadarko Basin Index Price, the Permian Basin Index Price, and the San Juan Basin Index Price. The weighting is based on the volumes entering El Paso's System in each basin during the previous quarter and will be updated quarterly. (ii) The four trade publications referenced above are Inside FERC Gas Market Report (Prices of Spot Gas Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 94 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 281 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (continued) 20.11 Resolution of Imbalances (Continued) Delivered to Pipelines), Natural Gas Week (Spot Prices on Natural Gas Pipeline Systems, Delivered to Pipelines), Gas Daily (Natural Gas Surrey), and Natural Gas Intelligence Gas Price Index (Spot Gas Prices Delivered to Pipeline, 30 Day Supply Transactions). In the event any of the publications cease publication or to the extent a publication fails to report spot prices, then El Paso shall reserve the right to substitute prices reported in a similar independent publication or continue the pricing formula using the average of the remaining publications. Changes in the name, format or other method of reporting by the publications in (e) above that do not materially affect the content shall not affect their use hereunder. (iii) El Paso shall post the Index Price monthly on its electronic bulletin board on or before the 15th day of each month applicable to the prior business month. (iv) For any contract where total deliveries by El Paso for a Shipper exceed the total receipts from Shipper, after appropriate reductions, such imbalance shall be "cashed out" based on the percentages provided below. Further, the Index Price shall be adjusted to reflect the point at which the imbalance is held. (1) For any contract subject to Section 20.11(d), or by mutual agreement any contract with an imbalance up to and including +5%, the quantity will be invoiced at 100% of the Index Price; (2) For any contract subject to Section 20.12(d) or any contract with an imbalance greater than +5% but less than or equal to +10%, the quantity in excess of +5% will be invoiced at 110% of the Index Price; Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 95 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 282 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.11 Resolution of Imbalances (Continued) (3) For any contract with an Unbalance greater than +10% but less than or equal to +15%, the volume in excess of +10% will be invoiced at 120% of the Index Price; (4) For any contract with an imbalance greater than +15% but less than or equal to +20%, the volume in excess of +15% will be invoiced at 130% of the Index Price; and (5) For any contract with an imbalance greater than +20%, the volume in excess of +20% will be invoiced at 140% of the Index Price. (v) For any contract where total receipts by El Paso from a Shipper, after appropriate reductions, exceed total deliveries for that Shipper, such imbalance shall be "cashed out" based on the percentages provided below. Further, the Index Price shall be adjusted to reflect the point at which the imbalance is held. (1) For any contract subject to Section 20.11(d) or subject to any other mutually agreeable terms, with an imbalance up to and including -5%, the quantity will be purchased by El Paso at 100% of the Index Prices; (2) For any contract subject to Section 20.11(d) or any contract with an imbalance greater than -5% but less than or equal to -10%, the quantity in excess of -5% will be purchased by El Paso at 90% of the Index Price; (3) For any contract with an imbalance greater than -10% but less than or equal to -15%, the volume in excess of -10% will be purchased by El Paso at 80% of the Index Price; Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 96 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 283 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.11 Resolution of Imbalances (Continued) (4) For any contract with an imbalance greater than -15% but less than or equal to -20%, the volume in excess of -15% will be purchased by El Paso at 70% of the Index Price; and (5) For any contract with an imbalance greater than -20%, the volume in excess of -20% will be purchased by El Paso at 60% of the Index Price. (vi) At the time a Shipper if in a cash-out position requiring payment to El Paso at the appropriate rate set forth in Section 20.11(e) (iv) above and such Shipper also has an Unauthorized Gas balance, as such term is defined in Section 27.1 of these General Terms and Conditions, such Unauthorized Gas balance may be offset against the quantities due El Paso within the same production basin and adjusted to reflect the point at which the imbalance is held. At the time of invoicing for the net imbalance, El Paso shall appropriately invoice or account for any production area charges and liquid credits applicable to the unauthorized gas used as an offset. This provision is not applicable to the Unauthorized Gas retained as a penalty pursuant to Section 27 of these General Terms and Conditions. Prior to any offsets, El Paso at its option may first offset any under or over-deliveries between contracts with such Shipper. Shipper or its suppliers shall be responsible for reporting and payment of any royalty, tax, or other burdens on natural gas volumes received by El Paso and El Paso shall not be obligated to account for or pay such burdens. (f) Crediting of Revenues - When the aggregate value received from all sources resulting from cash-out exceeds the cost of gas plus administrative fees, El Paso shall credit such net amount within 90 days of the payment date to Shippers on a Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 97 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 284 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRS TRANSPORTATION SERVICE (Continued) 20.11 Resolution of Imbalances (Continued) pro rata basis in accordance with the volumes transported for each Shipper. (g) Netting of Contracts - For purposes of resolving an imbalance with a Shipper, El Paso shall net gas imbalances, on a non-discriminatory basis, adjusted to reflect a common point at which the imbalance is held, between contracts with such Shipper pursuant to the conditions identified below. (i) Netting between downstream interconnect and mainline agreement imbalances is negotiable if the agreement has the interconnect point as a delivery point. (ii) Netting between mainline agreement imbalances (for similar transportation service) is negotiable. (iii) Netting between gathering/pooling and mainline agreements is negotiable if the gathering/pooling basin is a receipt point on the mainline agreement. (iv) Netting between Unauthorized Gas and mainline or pooling/gathering agreement imbalances is negotiable if both the Unauthorized Gas and imbalance were generated in the same basin. For any specific situation not discussed above, El Paso is willing to negotiate a transportation transaction which could have the effect of netting imbalances. 20.12 Unauthorized Overpull Penalty (a) A penalty shall be levied by El Paso and paid in dollars by any receiving party (any Shipper, Local Distribution Company, Direct Sales Customer or other party who operates the facilities that receive the gas transported by El Paso) who exceeds the limits specified below. Such penalty is applicable when, in times of capacity constraints, or when, due to unforeseen circumstances beyond El Paso's control, El Paso has determined that its ability to maintain scheduled deliveries to all receiving parties is materially Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 98 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 285 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.12 Unauthorized Overpull Penalty (Continued) threatened due to insufficient pressures in El Paso's system and El Paso so notifies said receiving parties. Nothing herein shall limit El Paso's right to take any further actions required to maintain the integrity of its system operations. (b) On any day El Paso determines that it is unable to deliver the total volumes of gas scheduled for delivery for the account of all Shippers, it shall have the right to notify all receiving parties that an Unauthorized Overpull Penalty situation exists. Contemporaneously with, or shortly following such notice, El Paso shall give notice to any receiving party who is taking volumes at a level that would subject such party to an Unauthorized Overpull Penalty as provided below. (c) The quantity of gas subject to such penalty is that quantity of gas taken by the receiving party which exceeds the quantity of gas scheduled by El Paso for delivery to such party on any day. (d) Upon receipt of a notification from El Paso, such party shall within twenty-four (24) hours reduce takes to a level no more than 3% above its scheduled volume for such day or 1,000 dth, whichever is larger. Such twenty-four (24) hour notice period shall commence at seven (7:00) a.m. Mountain Standard Time on the day after notice is actually provided. If after the twenty-four (24) hour notice period the receiving party continues to take volumes of gas that exceed the foregoing threshold, an Unauthorized Overpull Penalty shall be levied by El Paso and paid in dollars by any receiving party as follows: (i) A penalty of $5.00 per dth shall apply to all unauthorized overrun volumes which exceed the 3% or 1,000 dth tolerance level, whichever is larger, up to the first 5% of scheduled volumes and (ii) A penalty of $10.00 per dth shall apply to daily unauthorized overrun volumes in excess of 5% of scheduled volumes. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 99 EL PASO NATURAL GAS COMPANY ERC Gas Tariff Original Sheet No. 286 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.12 Unauthorized Overpull Penalty (Continued) El Paso shall notify Shippers each day during an Unauthorized Overpull Penalty situation, via El Paso's Electronic Bulletin Board, that the situation continues to exist. Such notice does not constitute notification of a new penalty period pursuant to this Section 20.12(d) and does not begin a new twenty-four (24) hour correction period. (e) El Paso shall establish an Unauthorized Overpull Penalty account for each month that El Paso receives such penalty payments for the benefit of all qualified Shippers as provided below: (i) A qualified Shipper is defined as a Shipper that did not receive its scheduled volumes due to El Paso's inability, for any reason, to make such deliveries on days when El Paso has provided notice that an Unauthorized Overpull Penalty situation exists, as defined in Section 20.12(a) above. (ii) Payments for Unauthorized Overpull Penalties shall be credited to the Unauthorized Overpull Penalty account. The disposition of the total dollars paid unconditionally to El Paso in any month, as determined in (iii) below, shall be made on a quarterly basis as determined in (iv) below. (iii) The Unauthorized Overpull Penalty amounts attributable to each day shall be allocated on a pro rata basis to all qualified Shippers that receive less than their scheduled quantities of gas on that day. (iv) Each qualified Shipper shall be entitled to receive their share of the Unauthorized Overpull Penalty account determined in accordance with (iii) above as a credit adjustment to the transportation service invoice rendered by El Paso in any month in the following calendar quarter after the penalty payment is received by El Paso. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 100 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 287 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.13 Flexible Receipt and Delivery Point(s) (a) Any Shipper that has a Rate Schedule T-3 firm Transportation Service Agreement applicable to mainline or field transportation shall have the right to tender gas to El Paso at any designated receipt point physically located on that part of El Paso's system to which such Shipper's Transportation Service Agreement applies. Shipper's Transportation Service Agreement shall designate the "primary receipt point(s)." Any other receipt point(s) utilized by such Shipper shall be referred to as an "alternate receipt point(s)." (b) In addition to a Rate Schedule T-3 Shipper's point(s) of delivery as established in its effective firm Transportation Service Agreement, hereinafter referred to as the "primary delivery point(s)," such Shipper may utilize alternate delivery point(s) under such agreement pursuant to the following conditions: (i) the alternate delivery point(s) on El Paso's system is located within the same delivery zone as Shipper's primary delivery point(s) or is located upstream of the delivery zone containing Shipper's primary delivery point(s), or for those contracts in which the direction of service is counter to the flow order specified below, the alternate delivery point(s) is located along the route over which service is provided and for which a reservation charge(s) is paid. The flow order in which the delivery zones are arranged from the furthest downstream to the furthest upstream zones are as follows: California; Nevada; Arizona; New Mexico; and Texas; and (ii) the total quantity of gas transported by El Paso to Shipper's primary delivery point(s) and alternate delivery point(s) shall not exceed Shipper's Transportation Contract Demand unless otherwise agreed to by El Paso. For any Shipper who is a full requirements Shipper, for purposes of this Section 20.13(b), such Shipper's Transportation Contract Demand shall be deemed to be Shipper's Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 101 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 288 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.13 Flexible Receipt and Delivery Point(s) (Continued) Billing Determinant as set forth in Rate Schedule T-3 of this FERC Gas Tariff; provided, however, such Billing Determinant limitation shall not apply when a full requirements Shipper utilizes only its primary delivery point(s). 20.14 Rate Application for Alternate Receipt and Delivery Point(s) - In the event Shipper uses an alternate receipt point(s) or delivery point(s) located in an upstream delivery zone, Shipper shall continue to be billed the reservation charge(s) and reservation surcharge(s) applicable to the delivery zone in which Shippers primary delivery point(s) is located. In addition, Shipper shall pay the maximum usage charge(s), unless otherwise provided, applicable to the production basin(s) and delivery point(s) actually used for the transportation service. Notwithstanding the applicability of any contractually agreed-upon lower rate for services using primary receipt and delivery points, all transportation services using either an alternate receipt point or alternate delivery point, or both, shall be subject to the maximum transportation rate for such service, as set forth in this FERC Gas Tariff, unless El Paso otherwise agrees in writing at the time the service using such alternate point(s) is requested. 20.15 Abandonment of Transportation Service - Unless otherwise provided in the applicable Transportation Service Agreement and Subject to Section 20.16 below, El Paso shall be entitled to avail itself of the pregranted abandonment authority under Section 7(b) of the Natural Gas Act of long-term (twelve (12) months or more) firm transportation services, as authorized by Section 284.221(d) of the Commission's Regulations, upon the expiration of the contractual term or upon termination of each individual transportation arrangement and shall seek offers from competing Shippers interested in receiving such firm transportation service, as provided below. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 102 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 289 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.16 Right-of-First-Refusal (a) Upon expiration of the term of the Transportation Service Agreement of a long term Shipper, such Shipper shall have a "right-of-first-refusal" as prescribed in this Section 20.16. In order to avail itself of its right-of-first-refusal, the Shipper must give El Paso its written notice of intent to exercise such right of first refusal not later than (i) the date of the notice period provided for in Shipper's contract; or (ii) twelve (12) months prior to the expiration of the terms of the contract, whichever shall first occur. (b) El Paso sboard the terms and conditions of the available capacity under the expiring contract as follows: (i) firm daily quantities stated in Mcf/d; (ii) the delivery point(s) at which capacity is available and the firm quantities at such point(s); (iii) effective date; (iv) term; (v) the rate (i.e., Reservation Charge(s) and Usage Charge(s) applicable to each delivery point); (vi) minimum conditions; and (vii) the criteria by which bids are to be evaluated. (c) Capacity will be made available on a nondiscriminatory basis and will be assigned on the basis of an open season for a period of not less than ninety (90) days duration. (i) Shipper(s) desiring to acquire such available capacity shall notify El Paso, via its electroniSuch notice shall be binding open season. once received by El Paso and shall not be revocable by such Shipper. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 103 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 290 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued) 20.16 Right-of-First-Refusal (Continued) (ii) Shipper's bid must include: (a) Shippers legal name and, if applicable, the contract number under which it desires to acquire capacity; (b) the quantity of capacity to be acquired at each delivery point(s); (c) the term of the acquisition (the maximum term used for bid evaluation will be twenty (20) years); and (d) the maximum rate Shipper is willing to pay for the capacity. (iii) The potential Shipper must satisfy the other provisions of this Tariff applicable to requests for firm transportation. (d) El Paso shall not be obligated to accept any offer for such capacity at less than the maximum applicable tariff rate. In the event El Paso accepts an offer, however, El Paso shall inform the existing Shipper of the terms of such offer. The existing Shipper shall have seven (7) days in which to inform El Paso that it agrees to match such offer. Such agreement shall be irrevocable. The existing Shipper or the offering Shipper, as appropriate, shall execute a Transportation Service Agreement containing the terms offered or matched. (e) In the event there are no competing offers, then the existing Shipper shall not be entitled to continue to receive transportation service upon the expiration of its contract except by agreeing to pay the maximum tariff rate unless El Paso and such Shipper shall enter into a new firm transportation service agreement providing otherwise. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 104 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 291 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 21. ANNUAL CHARGE ADJUSTMENT PROVISION 21.1 Purpose - This Section 21 establishes an Annual Charge Adjustment Provision ("ACA") which will permit El Paso to recover from its Shippers the annual charges assessed to El Paso by the Commission under Part 382 of the Commission's Regulations. 21.2 Applicable Customers - The ACA is applicable to each rate schedule contained in Volume Nos. 1-A and Volume No. 2 FERC Gas Tariff as identified on Sheet Nos. 20, 23, and 25, and Sheet Nos. 1-D.2 and 1-D.3. 21.3 Adjustment Date - The ACA unit charge shall be filed with the Commission by El Paso at least thirty (30) days prior to the proposed Adjustment Date unless a shorter period is specifically requested and permitted by the Commission. The Adjustment Date shall be October 1 of each year or as directed by an order of the Commission. On the Adjustment Date, El Paso shall increase or decrease the ACA unit charge to each of the applicable rate schedules as authorized by the Commission to be recovered by El Paso. For those rate schedules with a two-part rate, the ACA unit charge shall only apply to the usage component of such rate. 21.4 Effective Date - The ACA unit charge shall become effective October 1 of each year or as directed by an order of the Commission if: (a) El Paso has paid the applicable annual charge in compliance with Section 382.103 of the Commission's Regulations; and (b) the ACA unit charge is not subject to suspension or refund obligation. 21.5 Accounting for Annual Charges Paid Under Part 382 - El Paso shall account for annual charges paid by charging the amount to Account No. 928, Regulatory Commission Expenses, of the Commission's Uniform System of Accounts. Any annual charges recorded in Account No. 928 shall not be recovered by El Paso in a Natural Gas Act Section 4 rate case. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 105 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 292 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 22. TARE-OR-PAY BUYOUT AND BUYDOWN COST RECOVERY The provisions for this Section 22 are contained in Section 21 of the General Terms and Conditions of El Paso's Volume No. 1 Tariff and are incorporated herein by reference with respect to those provisions applicable to the Throughput Surcharge. Such Throughput Surcharge is applicable to all Shippers subject to El Paso's mainline transportation rates and/or Rate Schedules contained in this volume No. 1-A Tariff. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 106 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 293 Second Revised Volume No. 1-A Superseding Original Sheet No. 293 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS 23.1 Shared operating employees and shared operating facilities between El Paso and its marketing affiliate(s): None. There are no shared operating employees between the transportation function of (i) El Paso and the merchant function of El Paso or (ii) El Paso and its marketing affiliate(s). Only support facilities, including utility, telecommunication, and computer systems at the corporate headquarters complex, are shared by El Paso and its marketing affiliate(s). Separate books of account, records, and computer files are maintained for El Paso and for its marketing affiliate(s). 23.2 The information and format required from a Shipper for a valid request for transportation service or amended service are contained in Section 23.5 of this Section 23. 23.3 The procedures used to address and resolve complaints by Shippers and potential Shippers are as follows: (a) Any Shipper or potential Shipper may register a telephone complaint concerning requested and/or furnished transportation service by calling El Paso's customer assistance toll-free number 1-800-441-3764. Telephone complaints should provide the same information as provided in written complaints by a Shipper. Written complaints by any Shipper or potential Shipper, clearly stating the issue(s), facts relied on by Shipper, Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 107 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 294 Second Revised Volume No. 1-A Superseding Original Sheet No. 294 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) 23.3 (Continued) and the Shipper's position, should be mailed by registered or certified mail, or delivered by hand to: El Paso Natural Gas Company Post Office Box 1492 El Paso, Texas 79978 Attention: Director Mainline Transportation Department (Street Address: 100 N. Stanton, El Paso, Texas 79901) Upon receipt by El Paso, a complaint will be date stamped and recorded in the Transportation Service Complaint Log maintained by El Paso's Mainline Transportation and Customer Services Department. (b) El Paso will respond initially to all complaints by the most appropriate communication means available within 48 hours and will respond to all complaints filed with El Paso in writing within 30 days. El Paso's written response will be mailed by registered or certified mail to Complainant and filed in the Transportation Service Complaint Log. The final resolution of the complaint will be dependent upon the nature of the complaint and the time necessary to investigate the complaint, verify the underlying cause(s) and determine the relevant facts. 23.4 El Paso will maintain a log containing the following information on all requests for interruptible transportation service where allocation of capacity is based on a first come/first served priority. The log data relating to each contract shall be maintained as long as the contract is used to allocate capacity and for three (3) years thereafter. Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 108 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 295 Second Revised Volume No. 1-A Superseding Original Sheet No. 295 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) 23.4 (Continued) (a) The identity of the Shipper making the request for service including designating whether the Shipper is a local distribution company, an interstate pipeline, an intrastate pipeline, an end-user, a producer, or a marketer; (b) The specific affiliation of the requester with El Paso, and the extent of El Paso's affiliation, if any, with the person to be provided transportation service; (c) The contract number; and (d) The date that the request was accepted as valid. Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 109 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 296 Second Revised Volume No. 1-A Superseding Original Sheet No. 296 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) 23.5 Transportation Service Request Form EL PASO NATURAL GAS COMPANY TRANSPORTATION SERVICE REQUEST FORM Federal Energy Regulatory Commission record and reporting requirements and El Paso's FERC Gas Tariff require prospective Shippers and existing Shippers requesting amended service to furnish the information below prior to processing a request. Return this completed FORM to: Customer Services Department El Paso Natural Gas Company Post Office Box 1492 El Paso, Texas 79978 Telecopy: (915) 541-2544 (PLEASE TYPE OR PRINT) SHIPPER INFORMATION 1. Legal Name of Shipper:_______________________________________________________ 2. Shipper's Address: P.O. Box/Zip______________________________________________ Street/Zip__________________________________________________ City/State__________________________________________________ 3. Shipper's State of Incorporation:____________________________________________ 4. Duns Number:_________________________________________________________________ 5. Name of Requesting Party:____________________________________________________ Title:_______________________________________________________________________ Phone:_______________________________________________________________________ If employed by other than Shipper, please specify Requesting Party's: Company Name_________________________________________________________________ P.O. Box/Zip_________________________________________________________________ Street/Zip___________________________________________________________________ City/State___________________________________________________________________ Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 110 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 297 Second Revised Volume No. 1-A Superseding Original Sheet No. 297 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) 6. Shipper is (check one of the following): a. ____ Interstate Pipeline e. ____ End-User b. ____ Intrastate Pipeline* f. ____ Producer c. ____ Local Distribution Company* g. ____ Marketer d. ____ Hinshaw Pipeline* h. ____ Other (Specify)_______
*State(s) in which Shipper's natural gas system facilities are located: 7. This request is for (check one): ____ New Service ____ Amended Service Under Contract #____________________ If the request is for new service, please skip the Amended Service Request section. If the request is for amended service, please complete the Affiliate Information and Amended Service Request sections only. SERVICE/CONTRACT INFORMATION 1. Type of Transportation Service Requested (check one): ____Firm ____Interruptible ____Other 2. Date service is requested to commence:_________________________________ Date service is requested to terminate:________________________________ Evergreen term requested: ______ Yes ______ No 3. Maximum daily contract quantity requested (please specify both): __________ Mcf/d MMBtu/d __________ MMBtu/d. Total contract quantity requested over primary term of agreement (please specify both): __________ Mcf/d MMBtu/d __________ MMBtu/d. Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 111 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 298 Second Revised Volume No. 1-A Superseding Original Sheet No. 298 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) If service is requested for a term of more than 120 days, what quantities are requested to be transported on an: Average Day ____ Mcf ____ MMBtu Annual Basis ____ Mcf ____ MMBtu 4. Requested Receipt Point(s) and producing area(s) that are the source(s) of gas transported. Please list on attached Exhibit A. 5. Requested Delivery Point(s). Please list on attached Exhibit B. 6. Notices to:____________________________________________________________ Street or P.O. Box:____________________________________________________ City, State, Zip:______________________________________________________ Attention of:__________________________________________________________ Telephone:_____________________________________________________________ Telecopy:______________________________________________________________ Invoices to:___________________________________________________________ Street or P.O. Box:____________________________________________________ City, State, Zip:______________________________________________________ Attention of:__________________________________________________________ Telephone:_____________________________________________________________ Telecopy:______________________________________________________________ Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 112 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 299 Second Revised Volume No. 1-A Superseding Original Sheet No. 299 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) 7. Name of Shipper's dispatcher for 24-hour contact: _____________________ Phone: _______________________________________ Telecopy: ___________ RATE INFORMATION Contact your T&E Project Manager in the Mainline Transportation Department for discount requests. FINANCIAL INFORMATION El Paso requires each Shipper to provide financial statements (to include a balance sheet, income statement and statement of cash flow). The statements should be the most current available as of the date they are submitted. If audited financial statements are not available, then Shipper also should provide an attestation by its chief financial officer that the information shown in the unaudited statements submitted is true, correct and a fair representation of Shipper's financial condition. Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 113 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 300 Second Revised Volume No. 1-A Superseding Original Sheet No. 300 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) Based on its review of Shipper's financial statements, El Paso may agree to waive any further credit requirements as a condition of service. Alternatively, El Paso may request Shipper to provide additional evidence of its creditworthiness, in which event Shipper may elect to provide one of the following: - a clean irrevocable letter of credit in form and substance satisfactory to El Paso in a face amount equal to (i) the sum of the gas cost component of El Paso's sale-for-resale rates and the applicable unit transportation rate(s) specified in El Paso's Tariff for the service(s) which El Paso provides Shipper, (ii) multiplied by the maximum daily quantity specified in El Paso's Transportation Service Agreement with Shipper, (iii) multiplied by 90; or - a guarantee, in form and substance satisfactory to El Paso, executed by a person whom El Paso deems creditworthy, of Shipper's performance of its obligations to El Paso under the Transportation Service Agreement; or - such other form of security as Shipper may agree to provide and as may be acceptable to El Paso. The FERC Gas Tariff of El Paso does not require the pipeline transportation service on behalf of any Shipper who fails to demonstrate creditworthiness. El Paso will treat the financial statements provided by Shipper as confidential. AFFILIATE INFORMATION 1. Is Shipper affiliated with El Paso: ___ Yes ___ No Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 114 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 301 Second Revised Volume No. 1-A Superseding Original Sheet No. 301 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) 2. Is the Requesting Party (if other than Shipper) affiliated with El Paso: ____ Yes ____ No AMENDED SERVICE REQUEST 1. Addition of Receipt Point(s) -- Add the Receipt Point(s) identified on Exhibit A to Contract # _________________________ . 2. Addition of Delivery Point(s) -- Add the Delivery Point(s) identified on Exhibit B to Contract # _________________________ . (Note addition of new Delivery Point(s) and end users generally will result in a new position in the first come/first served queue.) Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 115 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 302 Second Revised Volume No. 1-A Superseding Original Sheet No. 302 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) 3. Increase the maximum daily contract quantity under Contract # _________________________ to (specify both): _______________ Mcf/d _________________________ MMBtu/d. (Note an increase in the maximum daily contract quantity generally will result in a new position in the first come/first served queue.) 4. Does Shipper request that service under Contract # ___________ be converted from Subpart B to Subpart G service (check one): ____ Yes ____ No 5. Other requested service change(s): ______________ _____________________________________________________ _____________________________________________________ _____________________________________________________ _____________________________________________________ _____________________________________________________ _____________________________________________________ _____________________________________________________ * * * Shipper hereby certifies that it has title or the right to ship the gas delivered to El Paso for transportation and has entered into or will enter into arrangements necessary to assure all upstream and downstream transportation will be in place prior to commencement of service. Shipper also certifies that the information herein is complete and accurate to the best of Shipper's knowledge, information and belief. Legal Name of Shipper: _______________________________ By: _______________________________________________ (Name and Title) Date: _______________________________________________ Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 116 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 303 Second Revised Volume No. 1-A Superseding Original Sheet No. 303 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) EL PASO NATURAL GAS COMPANY TRANSPORTATION SERVICE REQUEST FORM EXHIBIT A
Requested Maximum Total Volume Receipt Point(s)* Daily Volume (Over Term) _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu
Use 8-digit EPNG Code and include meter number(s). Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 117 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 304 Second Revised Volume No. 1-A Superseding Original Sheet No. 304 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) EL PASO NATURAL GAS COMPANY TRANSPORTATION SERVICE REQUEST FORM EXHIBIT B
Requested Maximum Total Volume Receipt Point(s)* Daily Volume (Over Term) _________________ ____________Mcf/d _____________Mcf/d __________MMBtu/d ____________MMBBtu _________________ ____________Mcf/d _____________Mcf/d __________MMBtu/d ____________MMBBtu _________________ ____________Mcf/d _____________Mcf/d __________MMBtu/d ____________MMBBtu _________________ ____________Mcf/d _____________Mcf/d __________MMBtu/d ____________MMBBtu _________________ ____________Mcf/d _____________Mcf/d __________MMBtu/d ____________MMBBtu _________________ ____________Mcf/d _____________Mcf/d __________MMBtu/d ____________MMBBtu
Use 8-digit EPNG Code and include meter number(s). Issued by: A. W. Clark, Vice President Issued on: August 30, 1994Effective: October 01, 1994 118 EL PASO NATURAL GAS COMPANY FERC Gas Tariff First Revised Sheet No. 305 Second Revised Volume No. 1-A Superseding Sheet Nos. 305 through 307 Reserved Sheets Sheet Nos. 305 through 307 have been reserved Issued by: A. W. Clark, Vice President Issued on: August 30, 1994 Effective: October 01, 1994 119 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 306 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) EL PASO NATURAL GAS COMPANY TRANSPORTATION SERVICE REQUEST FORM EXHIBIT A
Producing Area Requested Maximum Total Volume Area Source Receipt Point(s)* Daily Volume (Over Term) of Gas ______________ ____________Mcf/d _____________Mcf/d ______________ __________MMBtu/d ____________MMBBtu ______________ ____________Mcf/d _____________Mcf/d ______________ __________MMBtu/d ____________MMBBtu ______________ ____________Mcf/d _____________Mcf/d ______________ __________MMBtu/d ____________MMBBtu ______________ ____________Mcf/d _____________Mcf/d ______________ __________MMBtu/d ____________MMBBtu ______________ ____________Mcf/d _____________Mcf/d ______________ __________MMBtu/d _____________MMBBtu ______________ ____________Mcf/d _____________Mcf/d ______________ __________MMBtu/d _____________MMBBtu
* Use 8-digit EPNG Code and include meter number(s). Also, identify the name of the pipeline, gatherer or other entity delivering the gas into El Paso's system. ** Enter 2-digit code from attached list applicable to the producing area where the field or well producing the gas to be transported is located. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 120 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 307 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS (Continued) EL PASO NATURAL GAS COMPANY TRANSPORTATION SERVICE REQUEST FORM EXHIBIT B
Requested Maximum Total Volume Receipt Point(s)* Daily Volume (Over Term) _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu _________________ ____________Mcf/d ____________Mcf/d __________MMBtu/d ___________MMBBtu
* Use 8-digit EPNG Code and include meter number(s). Also, identify the name of the pipeline, local distribution company or other entity receiving the gas downstream of El Paso. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 121 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 308 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 24. ORDER NO. 636 ELECTRONIC BULLETIN BOARD 24.1 El Paso's Electronic Bulletin Board ("EBB") is accessed through its electronic communications service known as "Passport". Passport provides a portfolio of electronic business services to El Paso's customers. El Paso's EBB is available on a non-discriminatory basis to any party that has compatible equipment for electronic transmission of data, provided that such party has entered into a Passport Electronic Network Agreement and has been assigned a user identification, password and security code. Access to the EBB may be obtained by contacting Passport Services at (915) 541-2000. There is no charge to use the EBB. 24.2 El Paso's EBB shall provide such data as described in and shall be in compliance with FERC Order No. 636, et seq., by providing: (a) a means for all firm shippers to post their "grandfathered" buy/sell transactions, for informational purposes only, for a period of thirty (30) days identifying price, terms and conditions and name of the parties; and (b) a means for a releasing or acquiring Shipper electing to release all or a portion of its firm transportation rights in accordance with Section 28.4 and Section 28.5 contained in this Volume No. 1-A Tariff to advertise such release. 24.3 Parties wishing to bid on released capacity or to compete with prearranged offers shall post their bids through the EBB. Only those parties who are prequalified with respect to creditworthiness in accordance with Section 28.20 contained in El Paso's Volume No. 1-A Tariff may submit a bid during the open season in accordance with Section 28.9 contained in said Tariff. 24.4 The EBB shall contain information concerning the availability of capacities (a) at receipt points; (b) on the mainline; (c) at delivery points; and Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 122 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Second Revised Volume 1-A Original Sheet No. 309 TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 24. ORDER NO. 636 ELECTRONIC BULLETIN BOARD (Continued) 24.4 (Continued) (d) whether the capacity is available from El Paso directly or through El Paso's Capacity Release Program set forth in Section 28 contained in this volume No. 1-A Tariff. 24.5 El Paso shall post on the EBB notification of any of its uncommitted firm pipeline capacity. 24.6 El Paso shall post, daily, on the EBB notification of any unscheduled capacity available for interruptible transportation service, with bidding in accordance with the applicable provisions of Section 19 contained in this Volume No. 1-A Tariff. 24.7 EBB users shall have access to all the information specifically identified in FERC Order Nos. 497 and 636. EBB access, including historical data, shall be available to state regulatory commissions and state consumer advocates on the same basis as any other party. El Paso shall maintain backup copies of the data contained on its EBB for three years, which may be archived to off-line storage. Parties may access the on-line data directly through the EBB. In the event the data has been archived off-line, parties may request the data from Passport Services through Passport's electronic mail service, wherein such data shall be made available for downloading on user's computer. EBB users shall be allowed to download files so their contents can be reviewed in detail without tying up access to EBB. Information on the most recent transactions shall be listed before older information. EBB users shall be able to split large files into smaller parts for ease of use. On-line help shall be available to assist the EBB users along with a search function allowing users to locate all information concerning a specific transaction, and menus that permit users to separately access each record in the transportation log, offers to release capacity, capacity available directly from the pipeline, and standards of conduct information. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 123 EL PASO NATURAL GAS COMPANY Sheet Nos. 310 through 319 FERC Gas Tariff Second Revised Volume No. 1-A Reserved Sheets Original Sheet Nos. 310 through 319 have been reserved. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 124 EL PASO NATURAL GAS COMPANY Sheet Nos. 320 through 329 FERC Gas Tariff Second Revised Volume No. 1-A Reserved Sheets Original Sheet Nos. 320 through 329 have been reserved. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 125 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 330 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 27. UNAUTHORIZED GAS 27.1 Definition of Unauthorized Gas - Unauthorized Gas is natural gas that has not been scheduled as authorized to be received by El Paso, either for its own purchase under any gas purchase agreement, or for transportation to another market under any Transportation Service Agreement in accordance with the provisions of El Paso's FERC Gas Tariff. In addition, when a well, with two or more designated markets is scheduled but one or more markets fail to materialize, El Paso shall continue to schedule the volumes confirmed for that part of the well's production that has a market, but that portion for which the market has failed to materialize will be classified as unauthorized, unless this is the last well to be confirmed. Unauthorized Gas is distinguished from transportation imbalances which are excess volumes of natural gas delivered into El Paso's facilities from any source scheduled to a market in accordance with the provisions of this FERC Gas Tariff on any day, including excess volumes from the last well to be confirmed by contract that results in volumes in excess of the confirmed volumes, when some lesser amount is expressly authorized to flow on that day pursuant to Section 4.1 of the General Terms and Conditions contained in this FERC Gas Tariff. Such excess scheduled volumes from the last well to be confirmed shall be subject to Sections 19.12 or 20.11 of said General Terms and Conditions. 27.2 Unauthorized Gas Causing a Critical Situation - Upon notification from El Paso of a critical Unauthorized Gas situation, any party shall, within twenty-four (24) hours, terminate any unauthorized flow into El Paso's facilities. El Paso shall have the right to shut in, physically, the source of any Unauthorized Gas. If, after the twenty-four (24) hour notice period, any quantity of Unauthorized Gas continues to flow into El Paso's system, El Paso shall retain, except for partial market wells that have been classified as unauthorized, at no cost to itself and free of any obligation to account therefor in kind or otherwise to any person claiming an interest therein, the full quantity of Unauthorized Gas introduced into El Paso's facilities. A critical Unauthorized Gas situation shall apply only when El Paso, in good faith, has determined that the safety and/or integrity of its system is threatened. Nothing herein shall limit El Paso's right to take any other actions required to maintain the safety and integrity of its system operations. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 126 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 331 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 27.2 Unauthorized Gas Causing a Critical Situation (Continued) Until El Paso notifies the party(ies), either electronically or via facsimile, that the critical Unauthorized Gas situation has ended, the Unauthorized Gas penalty of retention of gas remains applicable on each subsequent day without further notification and the party(ies) shall not resume or continue flow of Unauthorized Gas from a well, plant or interconnected pipeline or gathering facility. 27.3 Notification of Unauthorized Gas Not Causing a Critical Situation - After the end of each month El Paso shall send each operator a notice of Unauthorized Gas flow entitled "Statement of Unauthorized Gas Account Balances," or succeeding Statement. Such notice shall include the volume, the receipt point(s) and the time frame in which the Unauthorized Gas was received into El Paso's system. 27.4 Unauthorized Gas Subsequent to the Effectiveness of this Section - For any Unauthorized Gas volumes delivered to El Paso subsequent to the effectiveness of this section, and not retained because of a critical Unauthorized Gas situation on El Paso's system, said party shall have until the first day of the third month following the month of El Paso's notification (Return Periods) to resolve the Unauthorized Gas volumes; provided however, that any such resolution must be approved by El Paso. El Paso and the party agree to negotiate in good faith for resolution of the Unauthorized Gas and to commit in writing during the Return Period any mutually agreed upon resolution. If El Paso incorrectly classifies gas as Unauthorized Gas, El Paso will transfer such gas to the appropriate agreement and will not assess any penalties under this Section 27 on such volumes. 27.5 Unauthorized Gas Prior to the Effectiveness of this Section - For any Unauthorized Gas volumes delivered to El Paso prior to the effectiveness of this section, said party shall have six (6) months after El Paso's notification (Extended Return Periods) to resolve the Unauthorized Gas volumes; provided however, that any such resolution must be approved by El Paso. El Paso and the party agree to negotiate in good faith for resolution of the Unauthorized Gas and to commit to writing during this Extended Return Period any mutually agreed upon resolution. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 127 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 332 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 27. UNAUTHORIZED GAS (Continued) 27.6 Disposition of Unauthorized Gas - El Paso will approve resolution of Unauthorized Gas volumes described in Sections 27.4 and 27.5 above as follows (a) With El Paso's consent, proven owners of Unauthorized Gas may sell such Unauthorized Gas volumes to any party as long as said party causes the gas to be transported under an effective Transportation Service Agreement on El Paso's system. Unless waived by El Paso on a not unduly discriminatory basis, the party agrees to pay El Paso the Unauthorized Gas penalty of thirty cents ($.30) per dth for the respective Unauthorized Gas volumes being purchased, plus any applicable transportation charge including fuel for redelivery. The penalty of thirty cents ($.30) per dth shall not be applicable for Unauthorized Gas volumes delivered into El Paso's system prior to the effectiveness of this section or for partial market wells that have been classified as unauthorized. (b) If said Unauthorized Gas volumes are not resolved by a mutually agreed upon plan within the Return Period or the Extended Return Period, as appropriate, El Paso may retain such Unauthorized Gas volumes at no cost to itself and free of any obligation to account therefor in kind or otherwise to any person claiming an interest therein. El Paso shall not assess more than one Unauthorized Gas penalty for the same Infraction. 27.7 Claiming Unauthorized Gas - To claim Unauthorized Gas volumes, the party shall submit a written plan for resolution thereof to El Paso within the Return Period or the Extended Return Period, as appropriate, along with proof of ownership. 27.8 Reporting and Payment of Royalty, Tax, or other Burdens - Shipper or its suppliers shall be responsible for reporting and payment of any royalty, tax, or other burdens on natural gas volumes received by El Paso and El Paso shall not be obligated to account for or pay such burdens. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 128 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 333 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 27. UNAUTHORIZED GAS (Continued) 27.9 Challenging El Paso's Classification of Unauthorized Gas - Any party claiming an interest in volumes of natural gas which El Paso has determined to be Unauthorized Gas may challenge that determination by the first day of the month following receipt from El Paso of the notice of Unauthorized Gas. Such challenge shall be in writing and include all documentation upon which such party relies to substantiate its challenge. El Paso shall hold such gas until a final determination has been reached as to the classification of the gas in question. If no such challenge is received by El Paso within the period specified, then El Paso's determination that the quantities in question were Unauthorized Gas shall be. Upon a determination that El Paso incorrectly classified natural gas as unauthorized, El Paso shall correct all records and make gas available, subject to operational conditions, within sixty (60) days of such determination. 27.10 Accounting for Retained Unauthorized Gas and Penalties - El Paso shall record the value of the Unauthorized Gas retained (pursuant to Sections 27.2 and 27.6(b) of this tariff) and the penalty payments received by El Paso (pursuant to Section 27.6(a) of this tariff) in the appropriate revenue account. The Unauthorized Gas volumes retained shall be valued at the value determined for the month the Unauthorized Gas enters the El Paso system. The value of such retained Unauthorized Gas shall be based on the appropriate index price for each production basin (Anadarko, Permian or San Juan). Such calculation shall be in accordance with Sections 20.11(e)(i)(l), (2) or (3), respectively, of this tariff. Any Shipper who has a valid Transportation service Agreement providing for mainline transportation services shall be eligible to receive a share of the value of the Unauthorized Gas volumes retained (less production area charges and taxes and royalties, if applicable and penalty payments received by El Paso. The Shipper's share shall be credited to the monthly transportation service invoice rendered by El Paso not later than 90 days after the month of retention or payment of the penalty. El Paso shall credit each Shipper, including any Acquiring Shipper, in proportion to the mainline charges billed to that Shipper less conditional credits pursuant to Section 28.18 of this tariff to the mainline charges billed to all Shippers in the month of crediting less such conditional credits. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 129 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 334 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM 28.1 Purpose - This Section 28 sets forth the specific terms and conditions applicable to the implementation by El Paso of a Capacity Release Program on its interstate pipeline system. 28.2 Applicability - This Section 28 is applicable to any Shipper who has a Part 284 Transportation Service Agreement under Rate Schedule T-3 contained in this Volume No. 1-A Tariff or an Acquired Capacity Agreement (except for those Acquired Capacity Agreements providing for volumetric reservation charges) and who elects to release, subject to the Capacity Release Program set forth herein, all or a portion of its firm transportation rights. Shipper shall have the right to release any portion of the firm capacity rights held under a Transportation Service Agreement or an Acquired Capacity Agreement but only to the extent that the capacity so released is acquired by another Shipper pursuant to the provisions of this Section 28. (a) With respect to any full requirements Rate Schedule T-3 Shipper who elects to participate in this Capacity Release Program, the total capacity rights of such Shipper shall be deemed to be limited to the quantity representing such Shipper's Billing Determinants underlying El Paso's rates in effect from time to time less the quantity actually released by such Shipper. This limitation on the capacity rights of such full requirements Shipper shall not apply during the time all capacity released hereunder is recalled by such Shipper. If a full requirements Shipper under Rate Schedule T-3 is not participating in the Capacity Release Program, such Shipper shall be entitled to full requirements service in accordance with its Transportation Service Agreement. (b) Any Rate Schedule FTS-S Shipper may release capacity under the same conditions set forth in (a) above provided that such Shipper is willing to convert on a temporary basis, for a minimum term of one (1) month, to service under Rate Schedule T-3. Notice of the intent to convert must be given to El Paso at least one (l) week prior to the beginning of the month(s) for which such conversion is to be effective. For purposes of determining capacity rights of such Shipper, El Paso will utilize either the Shipper's billing Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 130 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 335 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.2 Applicability (Continued) determinants established in the general rate proceeding applicable on the effective date of the conversion or a billing determinant negotiated by the parties. 28.3 Definitions - For purposes of this Section 28, the following definitions shall apply: (a) Releasing Shipper - any Shipper holding firm capacity rights under a Part 284 Transportation Service Agreement under Rate Schedule T-3 or an Acquired Capacity Agreement who desires to release such firm capacity rights to another Shipper pursuant to this Section 28. (b) Bidding Shipper - any Shipper who is qualified, pursuant to Section 28.20, to bid for capacity via El Paso's electronic bulletin board and who submits a bid for such capacity. (c) Pre-Arranged Shipper - any Shipper who is qualified, pursuant to Section 28.20, and seeks to acquire capacity under a prearranged release for which notice is given pursuant to Section 28.5. (d) Acquiring Shipper - any Shipper who acquires released capacity rights from a Releasing Shipper. (e) Firm Recallable Capacity - firm capacity released subject to the Releasing Shipper's right to recall such capacity during the term of the release. (f) Acquired Capacity Agreement - an agreement between El Paso and the Acquiring Shipper setting forth rate(s) and the terms and conditions of service for using capacity rights acquired pursuant to this Section 28, in the form contained in Section 28.25 of this Volume No. 1-A Tariff. 28.4 Notice by Shipper Electing to Release Capacity - A Releasing Shipper shall deliver a notice via El Paso's electronic bulletin board that it elects to release firm capacity. The notice shall set forth: Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 131 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 336 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.4 Notice by Shipper Electing to Release Capacity (Continued) (a) Releasing Shipper's legal name, contract number, and the name and title of the individual responsible for authorizing the release of capacity; (b) the maximum and minimum (if desired) quantity of firm daily capacity which the Releasing Shipper desires to release, stated in Mcf/d; (c) the delivery point(s) at which the Releasing Shipper will release capacity and the firm capacity to be released at each such point; (d) whether capacity will be released on a firm or firm recallable basis and, if on a firm recallable basis, the terms on which the capacity can be recalled, which terms must be objectively stated, non-discriminatory and applicable to all bidders; (e) the requested effective date and the term of the release; (f) whether the Releasing Shipper is willing to consider release for a shorter time period than that specified in (e) above, and, if so, the minimum (if desired) acceptable period of release (g) whether the Releasing Shipper desires bids in dollars or as a percentage of El Paso's maximum reservation charge(s) and reservation surcharge(s) applicable to the capacity to be released under this Volume No. 1-A Tariff as in effect from time to time; (h) the maximum reservation charge(s) and reservation surcharge(s) applicable to the capacity being released as shown on El Paso's Statement of Rates applicable to the Releasing Shipper's Transportation Service Agreement or Acquired Capacity Agreement and whether the Releasing Shipper is willing to consider releasing capacity at a lower rates; Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 132 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 337 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.4 Notice by Shipper Electing to Release Capacity (Continued) (i) whether the Releasing Shipper desires to release capacity on the basis of a volumetric reservation charge and, if so, whether bids shall be stated in dollars or as a percentage of El Paso's maximum reservation charge(s) and reservation surcharge(s) in accordance with Section 28. 16 below; (j) whether Option 1, Option 2, Option 3 or Option 4 of Section 28. 10 shall be used to determine the highest bidder and, if Option 3 is selected, the criteria by which bids are to be evaluated; whatever evaluation option the Releasing Shipper chooses, it may establish and post objective, non-discriminatory minimum conditions for an acceptable bid, subject to the provisions of Section 28.4(q) set forth below: (k) the weight for each factor if bids will be evaluated using the Option 1 weighted composite bid method; (1) the method by which ties will be broken; (m) whether the Releasing Shipper wants El Paso to market its released capacity in accordance with Section 28. 17; (n) the duration of the open season and of the matching period if longer than the minimums specified in section 28.8 below; (o) the date and time the notice is posted on the electronic bulletin board; (p) whether the Releasing Shipper is willing to accept contingent bids that extend beyond the open season and, if so, any non-discriminatory terms and conditions applicable to such contingencies including the date by which such contingency must be satisfied (which date shall be no later than two (2) business days prior to the first day the Acquired Capacity Agreement is to be effective) and whether, or for what the period, the next highest bidder will be obligated to acquire the capacity should the winning contingent bidder be unable to satisfy the contingency specified in its bid; and Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 133 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 338 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28. 4 Notice by Shipper Electing to Release Capacity (Continued) (q) whether the Releasing Shipper's notice will state minimum conditions or that such Shipper has revealed such minimums to El Paso which conditions shall not be revealed during the open seasons and (r) any other applicable conditions. A Releasing Shipper including any Shipper with a prearranged release that is subject to an open season, may withdraw such notice regardless of whether a valid bid has been received, at any time prior to the close of the open season set forth in Section 28.8 if such withdrawal is due to an unanticipated need for the capacity; provided, however, that once the notice is withdrawn, both the offer to release and any bids received during the open season shall remain posted on the electronic bulletin board for a period of thirty (30) days for monitoring and control purposes. 28.5 Notice of Pre-Arranged Release - The Releasing Shipper shall deliver a notice via El Paso's electronic bulletin board of a prearranged release. The notice shall set forth all of the information on the terms of the release called for in Section 28.4 above and all of the information called for in Section 28.9 below required to define the pre-arranged bid. In addition, it shall specify if the prearranged bid is for the maximum applicable reservation rate, whether the Releasing Shipper is seeking bids to compete with the non-rate provisions of the prearranged bid. The Releasing Shipper shall also designate if it is seeking bids when the release of capacity is for less than one (1) month. 28.6 Terms of Released Capacity - The term of any release of firm capacity shall not exceed the term of the Transportation Service Agreement or Acquired Capacity Agreement under which releasing occurs, nor shall it be less than one (1) full gas flow day. 28.7 Availability of Released Capacity - Released capacity shall be made available on a nondiscriminatory basis and shall be assigned on the basis of an open season or pre-arrangement in accordance with the procedures described in Sections 28.8 and 28.10 below. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 134 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 339 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM Continued) 28.8 Open Season and Matching Period - The minimum term of any open season to be held as a consequence of the posting by a Releasing Shipper of its election to release capacity in accordance with Sections 28.4 or 28.5 hereof shall be as specified below, except that: (1) no open season shall be required for a prearranged release that is for the maximum reservation charge(s) and reservation surcharge(s) applicable to the rate schedule pursuant to which capacity is released under this Volume No. 1-A Tariff as in effect from time to time; and (2) no open season shall be required for a pre-arranged release with a duration of less than one month regardless of the rate bid. (a) Capacity released under a prearrangement, for a period of less than one (1) month may not be rolled over or extended unless an offer to release is posted on El Paso's electronic bulletin board, prior to the effective date of the rollover or extension, treating the extension or rollover as a prearranged release and initiating the appropriate open season. A Releasing Shipper may not re-release capacity subject to this paragraph (a) to the same Acquiring Shipper until thirty (30) days after the first release period has ended unless such Acquiring Shipper offers to pay the maximum reservation charge(s) and reservation surcharge(s) and such bid meets all the terms and conditions of the subsequent release or such Acquiring Shipper is the highest bidder for the capacity during the open season. (b) For capacity to be released for a term of less than one (1) calendar month and which is being offered subject to the Option 4 bid evaluation procedure specified in Section 28.10 below, an open season of at least one (1) business day shall be held commencing at least two (2) business days prior to the effective day of the release. If the bids are to be evaluated in accord with Options 1 or 2, the open season must commence at least two (2) business days prior to the effective date of the release. If the capacity to be released is subject to a prearranged bid, the open season must commence at least three (3) business days prior to the effective date of the release to allow for a minimum of one (1) business day for the Pre-Arranged Shipper to match any bids received during the open season. If the bids are to be Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 135 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 340 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.8 Open Season and Matching Period (Continued) evaluated pursuant to Option 3, the open season shall commence at least three (3) business days prior to the effective date of the release to allow for a minimum of one (1) business day for bid evaluation. (c) For capacity to be released for a term of at least one (1) calendar month but not more than three (3) calendar months, an open season of at least five (5) business days shall be held commencing at least nine (9) business days prior to the effective date of the release. If the capacity to be released is subject to a pre-arranged bid, the open season must commence at least twelve (12) business days prior to the effective date of the release to allow for a minimum of three (3) business days for the Pre-Arranged Shipper to match any bids received during the open season. (d) For capacity to be released for a term of more than three (3) calendar months but not more than one (1) year, an open season of at least ten (10) business days shall be held commencing at least fourteen (14) business days prior to the effective date of the release. If the capacity to be released is subject to a pre-arranged bid, the open season must commence at least nineteen (19) business days prior to the effective date of the release to allow for a minimum of five (5) business days for the Pre-Arranged Shipper to match any bids received during the open season. (e) For capacity to be released for a term of more than one (1) year, an open season of at least twenty (20) business days shall be held commencing at least twenty four (24) business days prior to the effective date of the release. If the capacity to be released is subject to a pre-arranged bid, the open season must commence at least thirty four (34) business days prior to the effective date of the release to allow for a minimum of ten (10) business days for the Pre-Arranged Shipper to match any bids received during the open season. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 136 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 341 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.8 Open Season and Matching Period (Continued) (f) With respect to any prearranged release which is not subject to an open season, the Releasing Shipper shall post notice not later than forty-eight (48) hours after the transaction commences. (g) If any Releasing Shipper agrees to accept a contingent bid pursuant to Section 28.4(p) the beginning of the open season as set forth in Sections 28.8(a), (b), (c), (d) and (e) above shall start earlier by the number of business days so stated by the Releasing Shipper. 28.9 Bids for Released Capacity - A bid may be submitted to El Paso by a Bidding Shipper at any time during the open season via El Paso's electronic bulletin board. (a) Each bid for released capacity must include the following: (i) Bidding Shipper's legal name, address, and the name and title of the individual responsible for authorizing the bid; (ii) the term of the proposed acquisition; (iii) the maximum reservation charge(s) and reservation surcharge(s) Bidding Shipper is willing to pay for the capacity (iv) the volume desired and any minimum acceptable volumes (v) whether or not the Bidding Shipper is an affiliate of the Releasing Shipper; (vi) whether the bid is a contingent bid and the contingency which must be satisfied before the date specified by the Releasing Shipper pursuant to Section 28.4(p) above; and (vii) all other information requested by the Releasing Shipper. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 137 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 342 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM Continued) 28.9 Bids for Released Capacity (Continued) (b) Any bid received by El Paso during the open season shall be posted on El Paso's electronic bulletin board (excluding Bidding Shipper's name). The posting shall indicate if the bid is a contingent bid. Any bid may be withdrawn by such Shipper at any time prior to the close of the open season. However, once a bid is withdrawn, such Shipper may not resubmit a bid at a lower rate but may resubmit a bid at a higher rate. A Bidding Shipper may not simultaneously submit multiple bids for the same package of capacity and may not have more than one bid posted at a given time for such package of capacity. (c) A Bidding Shipper may not bid a reservation charge(s) less than the minimum reservation charge(s) nor more than the sum of the maximum reservation charge(s) and reservation surcharge(s) specified by this Volume No. 1-A Tariff, nor may the volume or the term of the release of such bid exceed the maximum volume or term specified by the Releasing Shipper. (d) Any capacity acquired on a volumetric reservation charge basis may not be re-released. 28.10 Awarding of Released Capacity - Released capacity shall be awarded in accordance with this Section 28.10. (a) If Bidding Shipper submits a bid to acquire the released capacity at the maximum reservation charge(s) and reservation surcharge(s) and upon all the terms and conditions specified in the Releasing Shipper's notice, then the capacity shall be awarded to such Bidding Shipper, and the Releasing Shipper shall not be entitled to reject such bid. Provided, however, if such bid was submitted as a bid in an open season relating to a pre-arranged release and the Pre-Arranged Shipper matches such offer, then the capacity shall be awarded pursuant to Section 28.10(g) hereof. If more than one such bid is received then the capacity shall be awarded in accordance with Section 28.10(f) hereof. The Releasing Shipper shall not be entitled to reject any bid so selected. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 138 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 343 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.10 Awarding of Released Capacity (Continued) (b) If a bid is received that exceeds the minimum but does not conform completely to the reservation charge(s) and reservation surcharge(s) and all the terms and conditions specified in the Releasing Shipper's notice, then the Acquiring Shipper(s) shall be the Bidding shipper(s) who offer(s) the highest bid determined under Option 1, Option 2, Option 3 or Option 4 below, as applicable. Provided, however, if such bid was submitted as a bid in an open season relating to a prearranged release and the Prearranged Shipper matches such offer, then the capacity shall be awarded pursuant to Section 28.10(g) hereof. If bids from two or more Bidding Shippers result in bids of equal rank then the capacity shall be awarded in accordance with Section 28.10(f) hereof El Paso shall evaluate and rank all bids submitted during the open season. If Bidding Shipper has not removed its contingency by the date specified by the Releasing Shipper pursuant to Section 28.4(p) hereof, such bid shall be deemed to have been withdrawn. (i) Default Bid Evaluation Criteria - If Releasing Shipper does not specify otherwise, all bids will be evaluated pursuant to Option 1 with equal weighting factors on all three criteria. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 139 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 344 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.10 Awarding of Released Capacity (continued) (ii) OPTION 1 - Weighted Composite Bid Calculation
Bidding Releasing Releasing Bidding Shipper's Shipper's Shipper's Shipper's Actual Bid Assigned Bid Maximum Bid Actual Bid Weighting Weighting (%) Values Values (%) (a) (b) (c) (d) (1) Volume in Mcf (2) Term Stated in Months (3) Reservation Charge(s) and Reservation Surcharge(s) Actual Weighted ____ Composite Bid ____% * d = c/b x a
(iii) OPTION 2 - Net Present Value Calculation R x 1 - (1 + i)-n x V - present value --------------- i where: i = interest rate per month using the current Commission interest rate as defined in 18 C. F. R. Section 154.67(c)(2)(iii)(A) n = term of the agreement, in months R = the Reservation Charge(s) and Reservation Surcharge(s) bid V = sold stated in Mcf Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 140 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 345 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.10 Awarding of Released Capacity (Continued) (iv) OPTION 3 - Releasing Shipper's Criteria Releasing Shipper shall specify how bids are to be evaluated to determine which is the best offer and must include all criteria necessary to enable El Paso to evaluate any contingent or non-contingent bids. The criteria must be objectively stated, applicable to all potential bidders and non-discriminatory. Such criteria shall also include provisions describing how capacity shall be allocated in the event two or more bids are ranked equally. (v) OPTION 4 - First-Come/ First-Served Capacity shall be awarded on a first-come/first-served basis as bids are received, up to maximum capacity specified in the notice of release, to the Acquiring Shipper(s) who submits a bid meeting the minimum terms and conditions of the release. Option 4 shall only apply to capacity to be released for a term of less than one (1) calendar month which is not subject to a pre-arranged release or a contingency. (c) If Option 1 is selected by the Releasing Shipper, then such Shipper shall specify, among the criteria listed above, those criteria which are to be applicable in determining the highest weighted composite bid and shall assign a relative weighting to each such factor. At the end of the open season, El Paso shall, for each bid received, calculate an actual weighted composite bid by dividing the actual bid component by Releasing Shipper's maximum bid component and multiplying the result by the Releasing Shipper's assigned bid weighting. The results of this calculation shall determine each bid components actual weight. Once all bid components are calculated, an actual composite weighting will be determined for each bid by summing the bid weightings for each component. The bids will then be ranked in order from the highest to the lowest actual weighted composite score. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 141 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 346 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.10 Awarding of Released Capacity (Continued) (d) If Option 2 is selected by the Releasing Shipper, then, at the end of the open season, El Paso shall calculate a Net Present Value for each bid received, with the bids being ranked in order from the highest to the lowest Net Present value. (e) If no bids are received which meet or exceed all of the minimum conditions specified by the Releasing Shipper, no capacity shall be awarded. If any bids are received which meet or exceed the Releasing Shipper's minimum criteria, El Paso shall rank all such bids in accordance with the criteria specified in the notice of release and shall award the capacity to the successful Bidding Shipper(s). Any Bidding Shipper who would receive less than the minimum acceptable bid volume shall not be obligated to accept released capacity. (f) If bids from two or more Bidding Shippers result in bids of equal score, the Acquiring Shipper(s) shall be determined based upon the tie breaking method designated by the Releasing Shipper, and if none is specified, by a lottery. The lottery shall be conducted by El Paso on a non-discriminatory basis. Capacity shall be awarded in accordance with the order of draw, with capacity awarded to the first-drawn Bidding Shipper up to the volume bid by such Shipper, and, if any released capacity remains after such award, it shall be offered to other Bidding Shippers in the lottery in accordance with the order of draw. Any Bidding Shipper who, by virtue of its place in the order of draw, receives less than the minimum acceptable bid volume shall not be obligated to accept released capacity. The results of the lottery shall be posted on El Paso's electronic bulletin board. (g) If a prearranged release is for the maximum reservation charge(s) and reservation surcharge(s) under this volume No. 1-A Tariff, as in effect from time to time, and meets all other terms and conditions imposed by the Releasing Shipper, then the Prearranged Shipper shall become the Acquiring Shipper. Service to such Acquiring Shipper may begin on the next scheduling day after award of the capacity and Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 142 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 347 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.10 Awarding of Released Capacity (Continued) execution of the Acquired Capacity Agreement described in Section 28.11 hereof if that is the effective date specified by the Releasing Shipper. If a pre-arranged release is for less than the maximum reservation charge(s) and reservation surcharge(s) or does not meet all other terms and conditions required by the Releasing Shipper, an open season is required pursuant to Section 28.8. If a better offer is received during the open season, as determined under Option 1, Option 2 or Option 3, the Pre-Arranged Shipper shall have the time specified in Section 28.8 hereof to match that offer and if the offer is matched, the Pre-Arranged Shipper shall become the Acquiring Shipper. If the Pre-Arranged Shipper fails to match the better offer, then the Bidding Shipper who presented the better offer shall become the Acquiring Shipper. (h) A Releasing Shipper shall retain all of the capacity under the executed Transportation Service Agreement or Acquired Capacity Agreement that is not acquired by an Acquiring Shipper as the result of an open season or a pre-arranged release. 28.11 Execution of Agreements or Amendments (a) Upon the award of capacity, the Acquiring Shipper obtaining released capacity shall execute electronically an Acquired Capacity Agreement with El Paso in the form set forth in Section 28.25 below; provided, however, such Shipper shall also return to El Paso an executed hard copy of the Acquired Capacity Agreement within five (5) business days of such award of capacity. Service to be performed under the Acquired Capacity Agreement is subject to discontinuance if the executed contract is not provided to El Paso within such time period. Once an Acquired Capacity Agreement has been executed, the terms of such Agreement are not subject to amendment, except as provided in Section 28.8(a). Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 143 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 348 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.11 Execution of Agreements or Amendments (Continued) (b) Where capacity has been released for the entire remaining term of the Releasing Shipper's Transportation Service Agreement, the Releasing Shipper may request El Paso to amend its Transportation Service Agreement to reflect the release of capacity. Absent agreement by El Paso to such amendment, which may be conditioned on exit fees or other terms and conditions, the Releasing Shipper shall remain bound by and liable for payment of the reservation charge(s) and reservation surcharge(s) under the Transportation Service Agreement. To the extent that capacity is released for the remaining term of the Releasing Shipper's Transportation Service Agreement and the Acquiring Shipper has agreed to pay the maximum reservation charge(s) and reservation surcharge(s) for such capacity, Releasing Shipper's contract shall be amended so as to relieve such shipper of any further liability for payment of the reservation charge(s) and reservation surcharge(s) applicable to the capacity released under the Transportation Service Agreement. In the event the Releasing Shipper's Transportation Service Agreement is amended to reflect the release of capacity, El Paso shall enter into a Transportation Service Agreement with the Acquiring Shipper in the form prescribed for service under Rate Schedule T-3 but containing the rates and terms and conditions established for the acquired capacity pursuant to this Section 28. 28.12 Notice of Completed Transactions - Within five (5) business days after capacity has been awarded pursuant to Section 28.10, El Paso shall post the information identified below regarding each transaction on its electronic bulletin board for a period of five (5) business days. (a) term; (b) reservation charge(s) and reservation surcharge(s) as bid; (c) delivery points; Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 144 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 349 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (continued) 28.12 Notice of Completed Transactions (Continued) (d) volume in Mcf; (e) whether the capacity is firm or firm recallable; (f) all conditions, including any minimums, concerning the release; (g) the names of the Releasing Shipper and the Acquiring Shippers; and (h) whether or not the Acquiring Shipper is an affiliate of the Releasing Shipper or El Paso. 28.13 Effective Date of Release and Acquisition - The effective date of the release by a Releasing Shipper and acquisition by an Acquiring Shipper shall be on the date so designated in the Acquired Capacity Agreement or Transportation Service Agreement referenced in Section 28.11 above. 28.14 Notice by El Paso of Uncommitted Firm Capacity - In the event El Paso determines that it has any uncommitted firm capacity on its system, El Paso shall post on its electronic bulletin board a notice of the availability of such capacity, setting forth the same information as prescribed in Section 28.4 or Section 28.5, as applicable. The capacity shall be awarded using the procedures specified by Sections 28.8 and 28.10. Any pre-arranged transaction for uncommitted or expansion firm capacity shall be subject to the posting and bidding procedures of this Section 28 regardless of the term or rate. Tied bids will be resolved by the tie-breaking method specified in Section 28.10(f) with no preference given to any Shipper involved in a pre-arranged transaction. El Paso shall not be obligated to accept any bid for uncommitted capacity that is for less than the maximum reservation charge(s) and reservation surcharge(s) specified in this Volume No. 1-A Tariff as in effect from time to time. 28.15 Notice of Offer to Purchase Capacity - In the event a party desires to purchase capacity on El Paso's system, it may post a notice of offer to purchase capacity on El Paso's electronic bulletin board or, if such party is not currently authorized to access the electronic bulletin board and elects to provide El Paso Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 145 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 350 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (continued) 28.15 Notice of Offer to Purchase Capacity (Continued) with the information in some other form El Paso shall post such offer on its electronic bulletin board within twenty-four (24) hours of receipt of such offer. The offering party may furnish all data for posting which it deems appropriate but at a minimum such data shall include the following: (i) offering party's legal name, address, and person to contact for additional information; (ii) the term of the proposed purchase; (iii) the maximum reservation charge(s) and reservation surcharge(s) the party is willing to pay for the capacity; (iv) the volume desired; and (v) the delivery points. 28.16 Rates - The reservation charge(s) and reservation surcharge(s) for any released firm capacity shall be the reservation charge(s) and reservation surcharge(s) bid by the Acquiring Shipper, but in no event shall such reservation charge(s) and reservation surcharge(s) be less than El Paso's minimum or more than El Paso's maximum reservation charge(s) and reservation surcharge(s) under the applicable-rate schedule as in effect from time to time. In addition, Acquiring Shipper shall pay the maximum usage charge as well as all other applicable charges and surcharge(s) for the service rendered unless discounted by El Paso. For a volumetric reservation charge, the sum of the reservation charge(s) and reservation surcharge(s) shall be converted to a daily rate by dividing by the number of days in the month. 28.17 Marketing Fee - When a Releasing Shipper requests that El Paso actively market the capacity to be released, the Releasing Shipper and El Paso shall negotiate the terms of the marketing service to be provided by El Paso and the marketing fee to be charged therefor. 28.18 Billing - El Paso shall bill the Acquiring Shipper the rate(s) specified in the Acquired Capacity Agreement or the Transportation Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 146 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 351 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (continued) 28.18 Billing (Continued) Service Agreement and any other applicable charges and such Acquiring Shipper shall pay the billed amounts directly to El Paso. Further, the Acquiring Shipper who has acquired capacity on a volumetric reservation rate basis shall be billed the daily reservation rate(s) plus the usage rate(s) and all applicable surcharges times the volumes actually transported. Releasing Shipper shall be billed the reservation charge(s) and reservation surcharge(s) associated with the released capacity pursuant to its contract, with a concurrent conditional credit for payment of the reservation charge(s) and reservation surcharge(s) due from the Acquiring Shipper. This bill shall include an itemization of credits and adjustments associated with each Acquired Capacity Agreement. Releasing Shipper shall also be billed a marketing fee, if applicable, pursuant to the provisions of Section 28.17. An Acquiring Shipper who re-releases acquired capacity shall pay to El Paso a marketing fee, if applicable. If an Acquiring Shipper does not make payment to El Paso of the reservation charge(s) and-reservation surcharge(s) due as set forth in Section 6 of this Volume No. 1-A Tariff, El Paso shall notify the Releasing Shipper of the amount due, including all applicable late charges authorized by Section 6.4 of this Tariff, and such amount shall be paid by the Releasing Shipper. In addition, Releasing Shipper may terminate the release of capacity to an Acquiring Shipper if such Shipper fails to pay all of the amount of any bill for gas delivered under the executed Acquired Capacity Agreement when such amount is due, in accordance with said Section 6.4. Once terminated, capacity and all applicable charges shall revert to the Releasing Shipper. Notwithstanding the provisions of Section 6.4, all payments received from an Acquiring Shipper shall first be applied to the reservation charge(s) due for transportation service and then to any reservation surcharges(s), including late charges related solely to such reservation charge(s), then to any penalty due, then to usage charges, and last to late charges not related to any reservation charge(s) due. 28.19 Nominations and Scheduling - An Acquiring Shipper shall nominate and schedule natural gas for transportation service hereunder directly with El Paso in accordance with the applicable procedures set forth in this Volume No. 1-A Tariff. Releasing Shipper shall give El Paso and the Acquiring Shipper(s) notice of any recall no Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 147 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 352 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.19 Nominations and Scheduling (Continued) later than the close of Day 1 scheduling for the day on which the recall is to take effect. Releasing Shipper, when returning recalled capacity to the Acquiring Shipper(s), shall give El Paso and such Acquiring Shipper(s) notice prior to the close of Day 1 scheduling for the day on which the capacity is to revert to the Acquiring Shipper(s). 28.20 Qualification for Participation in the Capacity Release Program - Any Shipper wishing to become a Bidding Shipper, or a potential Pre-Arranged Shipper, must satisfy the credit worthiness requirements of El Paso's transportation tariff by pre-qualifying prior to submitting a bid for capacity or prior to becoming a party to a pre-arranged release. Once a Shipper becomes an Acquiring Shipper, such Shipper can be subject to an annual credit review with respect to its eligibility to make additional bids on other offers of released capacity. A Shipper cannot bid for services which exceed its qualified level of creditworthiness. Notwithstanding such qualification to participate in the open season, El Paso does not guarantee the payment of any outstanding amounts by an Acquiring Shipper. 28.21 Compliance by Acquiring Shipper - By acquiring released capacity, an Acquiring Shipper agrees that it will comply with the terms and conditions of El Paso's certificate of public convenience and necessity authorizing this Capacity Release Program and all applicable Commission orders and regulations, including Part 284 thereof. Such Acquiring Shipper also agrees to be responsible to El Paso for compliance with all terms and conditions of El Paso's Volume No. 1-A Tariff, as well as the terms and conditions of the Acquired Capacity Agreement. End user lists shall not be required. 28.22 Obligations of Releasing Shipper - The Releasing Shipper shall continue to be liable and responsible for all reservation charge(s) and reservation surcharge(s) associated with the released capacity up to the maximum reservation charge(s) and reservation surcharge(s) specified in such Releasing Shipper's Transportation Service Agreement or Acquired Capacity Agreement. Re-releases by an Acquiring Shipper shall not relieve the original or any subsequent Releasing Shipper of its obligations under this section. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 148 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 353 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.23 Flexible Receipt and Delivery Point(s) - Shipper(s) using Acquired Capacity Agreements may utilize alternate receipt and delivery point(s) pursuant to the conditions contained in Section 20.13 of this Volume No. 1-A Tariff which is incorporated herein. 28.24 Refunds - In the event that the Commission orders refunds of any rates charged by El Paso, El Paso shall flow-through refunds to any Acquiring Shipper to the extent that such Shipper has paid a rate in excess of El Paso's just and reasonable, applicable maximum rates. 28.25 Acquired Capacity Agreement Acquired Capacity Agreement - Between El Paso Natural Gas Company and ____________________________ THIS AGREEMENT is made and entered into as of this _______ day _____________________________, by and between El Paso NATURAL GAS COMPANY, a Delaware corporation, hereinafter referred to as "El Paso," and _____________________________, a corporation, hereinafter referred to as Acquiring Shipper." WHEREAS, El Paso and _____________________________, hereinafter referred to as "Releasing Shipper," are parties to a _________________________ Agreement under Rate Schedule _________________________ contained in El Paso's FERC Gas Tariff, First Revised volume No. 1-A, dated _________________________ (contract code __________); WHEREAS, Acquiring Shipper desires to acquire all or a portion of the firm capacity rights to be released from said Agreement. NOW THEREFORE, in consideration of the promises and premises hereinafter set forth, El Paso and Acquiring Shipper agree as follows: Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 149 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 354 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (continued) 28.25 Acquired Capacity Agreement (Continued) 1. Acquiring Shipper agrees to comply with the terms and conditions of El Paso's certificate of public convenience and necessity issued by the Commission authorizing El Paso's Capacity Release Program and with Section 28 of the General Terms and Conditions contained in El Paso's Volume No. 1-A Tariff. In addition, Acquiring Shipper agrees to comply with all other terms and conditions of said Volume No. l-A Tariff as well as the terms and conditions set forth herein. 2. The following capacity rights, which are released through the Capacity Release Program, are acquired at the Receipt Point(s) and Delivery Point(s) designated below: Receipt Point(s): Those Receipt Point(s) set forth in the __________ Agreement. Delivery Point(s): The Delivery Point(s) as specified in the Notice posted pursuant to Sections 28.4 or 28.5 of El Paso's Volume No. 1-A Tariff. If the Releasing Shipper does not limit the Acquiring Shipper's rights to the primary Delivery Paint(s) specified in the Notice, then the Acquiring Shipper may designate any primary Delivery Point(s) within the same zone as the Releasing Shipper's primary Delivery Point(s), or within any upstream zone through which the released capacity passes, to the extent that capacity is available at such point(s). Contract Volume _______________ Mcf (for billing the reservation charge(s) and reservation surcharge(s), this volume shall be converted to dekatherms) 3. Capacity acquired hereunder is released through the Capacity Release Program on a (firm or firm recallable) basis. The Acquiring Shipper acknowledges notice of and agrees to be bound by the terms of the Notice posted pursuant to Sections 28.4 or 28.5 of El Paso's volume No. 1-A Tariff, as regards to the terms on which this capacity can be recalled by the Releasing Shipper. Releasing Shipper is responsible for exercising such recall, in accordance with the Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 150 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 355 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.25 Acquired Capacity Agreement (Continued) provisions of Section 28.19 of El Paso's Volume No. 1-A Tariff. (The foregoing paragraph shall be applicable to Acquiring Shipper(s) who acquire firm recallable capacity.) 4. For capacity acquired hereunder, Acquiring Shipper shall pay El Paso each month the charges set forth below:________________________________________________ _____________________________________________________. 5. This Agreement shall become effective on _________________________ and continue in full force and effect through _________________________ unless terminated pursuant to Section 28.18 of El Paso's Volume No. 1-A Tariffs 6. Other terms As specified in the Notice posted pursuant to Sections 28.4 or 28.5 of El Paso's Volume No. l-A Tariff. 7. Any formal notice, request or demand that either party gives to the other respecting this Agreement, shall be in writing and shall be mailed by registered or certified mail or delivered by hand to the following address of the other party: El Paso: El Paso Natural Gas Company Post Office Box 1492 El Paso, Texas 79978 Attention: Director, Mainline Transportation and Customer Services Department Acquiring Shipper: Notices regarding recall rights shall also be delivered by telephone, facsimile, or El Paso's electronic system. 8. Acquiring Shipper hereby certifies that it has title or the right to ship the gas delivered to El Paso for transportation and has entered into or will enter into arrangements necessary to assure all upstream and downstream transportation will be in place prior to commencement of service. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 151 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 356 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 28. CAPACITY RELEASE PROGRAM (Continued) 28.25 Acquired Capacity Agreement (Continued) IN WITNESS HEREOF, the parties have caused this Agreement to be executed in two (2) original counterparts, by their duly authorized officers, the day and year first set forth herein. ATTEST: EL PASO NATURAL GAS COMPANY By _________________________ By __________________________ (Title) (Title) ATTEST: ____________________________ (Acquiring Shipper) By _________________________ By _________________________ (Title) (Title) Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 152 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 357 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 29. COMPLIANCE PLAN FOR UNBUNDLED SALES DIVISION 29.1 El Paso will organize its unbundled sales and transportation operating employees so that they function independently of each other to the maximum extent practicable. 29.2 El Paso Gas Marketing Company, a separate and independently operated corporate affiliate, is designated as El Paso's agent for purposes of conducting El Paso's gas merchant function. El Paso and El Paso Gas Marketing Company as agent for El Paso will conduct their business in conformance with the standards of conduct set forth in Section 161.3 and Section 284.286 of the Commission's Regulations and other applicable requirements of Order Nos. 497 and 497-A. 29.3 El Paso will not provide a preference in any pipeline services to a Shipper because that Shipper also purchases natural gas from El Paso or from its marketing affiliate, or to a marketing affiliate of El Paso, over Shippers who purchase natural gas from another merchant. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 153 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 358 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. ASSIGNMENT OF FIRM CAPACITY ON UPSTREAM PIPELINES 30.1 Purpose - This Section 30 sets forth the terms and conditions under which El Paso shall assign, in whole or in part, the rights and obligations under contracts held by El Paso for firm capacity on upstream jurisdictional pipelines. 30.2 Applicability - This Section 30 shall apply to any firm Shipper who accepts assignment of any or all of El Paso's firm transportation capacity rights described in Section 30.1 above. 30.3 Availability of Capacity - El Paso's firm upstream capacity shall be made available on a nondiscriminatory basis and shall be assigned on the basis of an open season in accordance with the procedures described in Section 30.6 below. 30.4 Permanent Assignment - All assignments pursuant to this Section 30 shall be for the entire remaining term of El Paso's contract with such upstream pipeline 30.5 Rate - The rate for such assigned capacity shall be as established by the tariff of such upstream pipeline or as otherwise negotiated between the Shipper and upstream pipeline. El Paso shall not charge any fee in connection with the assignment of its capacity on the upstream pipeline. 30.6 Open Season - Upon the effectiveness of this Section 30, El Paso shall conduct an open season for a period of fifteen (15) days by posting a notice of such availability on its electronic bulletin board. In order for a Shipper to participate in this open season, Shipper shall submit to El Paso a completed bid in the form set forth in Section 30.9 below. If Shippers' requests for capacity exceed the available firm capacity during the open season, such capacity shall be allocated among the requesting Shippers based on a lottery. After the open season, El Paso will allocate all requests for available capacity on a first-come/first-served basis. 30.7 Qualifications for Assignment - Shipper must satisfy any applicable requirements of the upstream pipeline's tariff, including credit worthiness. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 154 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 359 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. ASSIGNMENT OF FIRM CAPACITY ON UPSTREAM PIPELINES (Continued) 30.8 Reporting Requirements - El Paso and any Shipper accepting assignment of capacity obtained from El Paso pursuant to this Section 30 shall file with the Commission the following information: (1) the name, address, and telephone number of the assignee; (2) the corporate affiliation between the assignor and the assignee, if any; and (3) a description of the specific rights assigned, including term, receipt and delivery points, and volume. 30.9 Bid Form 1. Company Name ______________________________________ 2. Mailing Address ______________________________________ 3. Name of Company Contact/Title ______________________________________ 4. Phone & FAX No. Phone _____________ FAX ____________ 5. Upstream Contract ______________________________ 6. Contract Quantity ______________________________ 7. Receipt Point(s) ______________________________ ______________________________ ______________________________ Delivery Point(s) ______________________________ ______________________________ ______________________________ 8. Requested Begin Data ______________________________ Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 155 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 360 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 30. ASSIGNMENT OF FIRM CAPACITY ON UPSTREAM PIPELINES (Continued) 30.9 Bid Form (Continued) Shipper represents that all information submitted with this bid is correct and is submitted by its authorized representative. Bids are binding only when a fully executed Assignment Agreement has been returned to El Paso. 9. Signature __________________________________________ 10. Print Name __________________________________________ 11. Title __________________________________________ 12. Date __________________________________________ Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 156 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 361 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY This Section 31 applies to those Shippers having an executed Transportation Service Agreement with El Paso for firm forward haul service subject to either Rate Schedule T-3 or Rate Schedule FTS-S. In addition to other charges otherwise due under such Rate Schedules, Shipper shall pay the Reservation Surcharge pursuant to this Section 31. 31.1 Purpose - This Section 31 establishes the procedures which will permit El Paso to recover from its Shippers one hundred percent (100%) of stranded investment costs associated with the Washington Ranch Facility. Such costs shall be allocated to El Paso's Rate Schedule T-3 and FTS-S firm forward haul Shippers based on each Shipper's reservation revenue responsibility, as established in the Settlement at Docket No. RP92-214-000, et al., for the period termed "Prospective Period." 31.2 Effectiveness - Commencing with the effective date of El Paso's Stipulation and Agreement at Docket No. RP92-214-000, et al., El Paso shall be entitled to bill and collect the Washington Ranch Facility stranded investment costs. Such costs will accrue interest effective February 1, 1993 and shall be fully amortized by December 31, 1996. 31.3 Definitions - The definition of terms applicable to this Section 31 are as follows: (a) Recovery Period - The period beginning on the effective date any new rates become effective under this Section 31 and ending on the day prior to the effective date of any Succeeding rate change under this Section. The initial recovery period shall begin upon the effectiveness of the Settlement at Docket No. RP92-214-000, et al., and end on the day prior to the effective date of the second recovery period. The subsequent recovery periods shall be the six (6) month periods commencing each January 1 and July 1 until all amounts have been amortized and interest thereon has been recovered. (b) Monthly Amortized Amounts - The Monthly Amortized Amounts shall be allocated to El Paso's firm forward haul Shippers based on each Shipper's forward haul reservation dollar allocation as established at Docket No. RP92-214-000, at al., "Prospective Period." The Monthly Amortized Amounts Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 157 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 362 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued) 31.3 Definitions (Continued) are the total estimated stranded investment costs, less previously amortized amounts divided by the number of months remaining in the Amortization Period, plus interest for the applicable Recovery Period. The Monthly Amortized Amounts shall be in effect until adjusted in accordance with Section 31.4(b) (c) Reservation Surcharge - A reservation surcharge rate shall be determined as set forth in Section 31.4(a) below. The Reservation Surcharge shall be selectively adjusted by El Paso; provided, however, that such adjusted Reservation Surcharge shall not exceed the applicable Maximum Rate nor shall it be less than the Minimum Rate in effect from time to time. (d) Billing Determinants - The Billing Determinants underlying the rates at Docket No. RS92-60-000 et al., "Prospective Period," and identified on Statement of Rates Sheet Nos. 27, 28, and 29 of this FERC Gas Tariff shall apply to those firm forward haul Shippers of El Paso for the purpose of this Section. (e) Monthly Billed Amount - The monthly amount billed each Shipper as reflected on Statement of Rates Sheet Nos. 27, 28, and 29 of the FERC Gas Tariff as described in Section 31.4(b) below shall be the Reservation Surcharge multiplied by the Billing Determinant. (f) Interest Rate - The quarterly interest rate published by the Commission and computed in accordance with Section 154.67(c)(2)(iii) of the Commission's Regulations. 31.4 Determination of the Reservation Surcharge and Monthly Amortized Amount - El Paso shall determine the Reservation Surcharge and Monthly Amortization by the following procedures: (a) The Reservation Surcharge rate(s) shall be determined utilizing the total Monthly Amortized Amount within each rate zone divided by the total of the Billing Determinants for that zone, and is reflected on the Statement of Rates Sheet contained in this Volume No. 1-A Tariff. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 158 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 363 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued) 31.4 Determination of the Reservation Surcharge and Monthly Amortized Amount (Continued) (b) El Paso shall adjust the Monthly Amortized Amount for interest calculated on the unrecovered balance of El Paso's stranded investment costs as set forth below. Interest shall commence to accrue with respect to El Paso was stranded investment costs effective February 1, 1993. (i) Effective with the Settlement at Docket No. RP92-214-000, at al., El Paso shall include the actual accrued interest from February 1, 1993 through the effective date and estimated interest through December 31, 1993 utilizing the actual Interest Rate (if the actual Interest Rate is unknown the interest rate shall be estimated), divided by the number of months remaining in 1993 to derive the interest adjustment to the Monthly Amortized Amount. (ii) Effective for the six (6) months commencing January 1, 1994, El Paso shall reflect any differences resulting from the use of estimated versus actual accrued interest for the period February 1, 1993 through December 31, 1993. Any resulting difference shall be added to or deducted from the estimated interest for the six(6) month period commencing January 1, 1994. The total interest shall be divided by six (6) to determine the monthly interest for such Recovery Period. (iii) At the end of each six (6) month period following June 30, 1994 through the termination of the Amortization Period, El Paso shall calculate an estimate for the projected interest expense for the next six (6) month Recovery Period. At the same time, El Paso shall calculate the actual interest expense that would have accrued during the previous Recovery Period. This actual interest amount will be compared to the previously estimated interest amount for such period and any resulting difference shall be added to or deducted from the next six (6) Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 159 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Original Sheet No. 364 Second Revised Volume 1-A TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued) 31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued) 31.4 Determination of the Reservation Surcharge and Monthly Amortized Amount (Continued) month interest protection, divided by six (6) months to derive the interest for the applicable Recovery Period. (iv) Effective the third month following the end of the Amortization Period, El Paso shall calculate the actual interest for any past period of estimated interest utilizing the appropriate Interest Rate, and shall make a one time adjustment to reflect the appropriate amount to each Shipper's invoice. (c) In the event the Transportation Service Agreement of any existing Shipper terminates during any Recovery Period, the unamortized portion of the costs inclusive of interest allocated to such Shipper under this Section 31.4 will be due within thirty (30) days or such other period as mutually agreed to by El Paso and Shipper, not to extend beyond the termination of the Amortization Period. (d) Each Shipper subject to this Section 31 shall have the option of paying the amount allocated to it in a lump sum or over a shorter Amortization Period if desired, with an appropriate interest adjustment. 31.5 True-up of Actual Versus Estimated Loss or Gain Realized from the Sale of Washington Ranch Gas Inventory - El Paso shall adjust the remaining unamortized balance to reflect the difference between the actual gain or loss and the previously estimated gain or loss from the sale of gas inventory from the Washington Ranch Facility. Such adjustment shall be reflected in El Parody earliest semi-annual filing following one year's effectiveness of this Section 31. Such adjustment shall be reflected in the balance as of February 1, 1993 for interest accrual purposes. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 160 EL PASO NATURAL GAS COMPANY FERC Gas Tariff Sheet Nos. 365 through 399 Second Revised Volume 1-A Reserved Sheets Original Sheet Nos. 365 through 399 have been reserved. Issued by: A. W. Clark, Vice President Issued on: May 23, 1994 Effective: July 01, 1994 EX-10.6 5 SAVINGS FUND PLAN FOR EMPLOYEES 1 Exhibit 10.6 THE PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN FOR NON-UNION EMPLOYEES This is the controlling and definitive statement of the Pacific Gas and Electric Company Savings Fund Plan for Non-Union EMPLOYEES1/ in effect on and after April 1, 1995. The PLAN, which covers ELIGIBLE EMPLOYEES of the COMPANY and other EMPLOYERS, is a further revision of the one originally placed in effect by the COMPANY as of April 1, 1959. It has since been amended from time to time. The PLAN as amended may be further amended retroactively in order to meet applicable rules and regulations of the Internal Revenue Service, the United States Department of Labor and all other applicable rules and regulations. The PLAN is maintained for the exclusive benefit of participants or their BENEFICIARIES, and contributions or benefits under the PLAN do not discriminate in favor of HIGHLY COMPENSATED EMPLOYEES. ELIGIBILITY AND PARTICIPATION 1. Eligibility A non-union EMPLOYEE becomes an ELIGIBLE EMPLOYEE upon completion of one year of SERVICE. Once eligibility occurs it continues as long as the EMPLOYEE remains a non-union EMPLOYEE and SERVICE continues. 2. Participation To become a participant, an ELIGIBLE EMPLOYEE must provide NOTICE to the PLAN ADMINISTRATOR of the ELIGIBLE EMPLOYEE'S election to participate and to be bound by the terms of the PLAN. Through such NOTICE, the ELIGIBLE EMPLOYEE shall: (a) authorize the EMPLOYER to reduce his COVERED COMPENSATION by a stated percentage and to contribute such amount to the PLAN as a Section 401(k) CONTRIBUTION; and/or (b) elect to make NON-Section 401(k) CONTRIBUTIONS, if any, to the PLAN; and (c) instruct the PLAN ADMINISTRATOR as to the manner in which EMPLOYEE contributions and matching EMPLOYER CONTRIBUTIONS are to be invested. CONTRIBUTIONS 3. EMPLOYEE Contributions To become a contributing participant, an ELIGIBLE EMPLOYEE must make Section 401(k) CONTRIBUTIONS, NON-Section 401(k) CONTRIBUTIONS, or a combination of both to the PLAN through payroll deduction. __________________________________ 1/ Words in all capitals are defined in Section 30. -1- 2 All contributions withheld by the EMPLOYER from COVERED COMPENSATION are paid over to the TRUSTEE, unconditionally credited to the participant's account and invested in accordance with the participant's instructions. (a) Section 401(k) CONTRIBUTIONS. A Section 401(k) CONTRIBUTION is an election to defer the receipt of a specified whole percentage of COVERED COMPENSATION which would otherwise be currently payable to a participant. The EMPLOYER shall reduce the participant's COVERED COMPENSATION by an amount equal to the percentage of the Section 401(k) CONTRIBUTION elected by the participant. Under current law, Section 401(k) CONTRIBUTIONS deferred by a participant under the PLAN are not subject to federal or state income tax until actually withdrawn or distributed from the PLAN. (b) FLEXDOLLARS. By giving NOTICE, a participant in the COMPANY'S Flex Plan may elect to have any unused FLEXDOLLARS contributed to this PLAN. Any FLEXDOLLARS contributed to this PLAN shall be deemed Section 401(k) CONTRIBUTIONS and shall be subject to all restrictions and limitations applicable to Section 401(k) CONTRIBUTIONS. FLEXDOLLAR contributions shall not be eligible for matching EMPLOYER CONTRIBUTIONS as described in Section 4. (c) NON-Section 401(k) CONTRIBUTIONS. NON-Section 401(k) CONTRIBUTIONS differ from Section 401(k) CONTRIBUTIONS in that a participant has already paid taxes on the amounts contributed to the PLAN. All EMPLOYEE Contributions made to the PLAN as it existed prior to October 1, 1984, are considered to be NON-Section 401(k) CONTRIBUTIONS and are so recorded in the accounts maintained by the PLAN ADMINISTRATOR. NON-Section 401(k) CONTRIBUTIONS must be made in whole percentages of COVERED COMPENSATION, and the sum of all Section 401(k) CONTRIBUTIONS and NON-Section 401(k) CONTRIBUTIONS made by a participant may not exceed 15 percent of the participant's COVERED COMPENSATION. (d) CHANGING CONTRIBUTIONS. By giving NOTICE to the PLAN ADMINISTRATOR, a participant may direct the PLAN ADMINISTRATOR to cease or resume making contributions, or to change the rate of contributions. Any such change shall become effective within 30 days of receipt by the PLAN ADMINISTRATOR of such NOTICE. 4. Employer Contributions (a) Each and every time that participants make Section 401(k) or non-Section 401(K) CONTRIBUTIONS to the PLAN eligible for matching EMPLOYER CONTRIBUTIONS, the COMPANY shall make a matching EMPLOYER CONTRIBUTION to the PLAN in cash or in whole shares of COMPANY STOCK, or partly in both. Matching EMPLOYER CONTRIBUTIONS shall be limited to an amount equal to three- quarters of the aggregate participant contributions eligible for matching EMPLOYER CONTRIBUTIONS under the provisions of Subsection 4(a)(1). The COMPANY shall charge to each EMPLOYER its appropriate share of matching EMPLOYER CONTRIBUTIONS. (1) Section 401(k) and NON-Section 401(k) CONTRIBUTIONS Eligible for Matching EMPLOYER CONTRIBUTIONS. Although a participant may elect to defer up to 15 percent of COVERED COMPENSATION to the PLAN, the maximum amount of a -2- 3 participant's contributions eligible for matching EMPLOYER CONTRIBUTIONS shall be one of the following percentages of COVERED COMPENSATION: (i) up to 3 percent, with at least one but less than three years of SERVICE; or (ii) up to 6 percent, with at least three years of SERVICE. (iii) for a participant who is absent from work and receiving temporary compensation under any state Worker's Compensation Law or under the COMPANY'S LONG TERM DISABILITY PLAN, the larger of: a) the maximum percentage calculated under (i) or (ii), whichever is applicable; or b) the dollar amount which was eligible for matching EMPLOYER CONTRIBUTIONS immediately before the participant's absence began. (b) Investment of EMPLOYER CONTRIBUTIONS. All EMPLOYER CONTRIBUTIONS made to the PLAN shall be invested by the TRUSTEE in accordance with a participant's INVESTMENT FUND directions. 5. Limitations (a) Average Deferral Percentage Limitation. In any PLAN YEAR, the average rate of Section 401(k) CONTRIBUTIONS as a percentage of compensation for all participating HIGHLY COMPENSATED ELIGIBLE EMPLOYEES shall not exceed the larger of: (1) the average rate of Section 401(k) CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES multiplied by 1.25 percent; or (2) the lesser of: (i) the average rate of Section 401(k) CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES multiplied by 2; or (ii) the average rate of Section 401(k) CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES plus 2 percentage points, or such lesser amount as the Secretary of the Treasury may prescribe in order to prevent the multiple use of this alternative limitation with respect to any HIGHLY COMPENSATED participant. The average rate of Section 401(k) CONTRIBUTIONS for a PLAN YEAR for a designated group of ELIGIBLE EMPLOYEES shall be the average of the ratios, calculated separately for each participating ELIGIBLE EMPLOYEE in the group, of the amount of Section 401(k) CONTRIBUTIONS made by each EMPLOYEE for the PLAN YEAR, to the EMPLOYEE'S compensation for such PLAN YEAR. As used in this subsection, compensation shall mean compensation paid by an EMPLOYER to the participant during the PLAN YEAR which is required to be reported as wages on the participant's form W-2 and shall also include compensation -3- 4 which is not currently includable in the participant's gross income by reason of the application of CODE Sections 125 and 402(e)(3). For purposes of this subsection, the ratio of the amount of Section 401(k) CONTRIBUTIONS to a participant's compensation for any participant who is HIGHLY COMPENSATED for the PLAN YEAR and who is eligible to have elective deferrals or qualified employer deferral contributions allocated to his account under two or more plans or arrangements described in Section 401(k) of the CODE that are maintained by an employer or affiliated employer shall be determined as if all such Section 401(k) CONTRIBUTIONS, elective deferrals and qualified employer deferral contributions were made under a single arrangement. For purposes of determining the ratio of the amount of Section 401(k) CONTRIBUTIONS to a participant's compensation for a participant who is HIGHLY COMPENSATED by reason of being one of the ten highest-paid EMPLOYEES or a 5 percent owner of the controlled group of corporations, as defined in Section 414 of the CODE, the Section 401(k) CONTRIBUTIONS and compensation of such participant shall include the Section 401(k) CONTRIBUTIONS and compensation of the participant's family members, as defined in Section 414 of the CODE, and such family members shall be disregarded in determining the average rate of Section 401(k) CONTRIBUTIONS for non-HIGHLY COMPENSATED participants. The determination and treatment of Section 401(k) CONTRIBUTIONS of any participant shall satisfy such other requirements as may be prescribed by the Secretary of the Treasury. (b) Average Contribution Percentage Limitation. In any PLAN YEAR, the average rate of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as a percentage of compensation for all participating HIGHLY COMPENSATED ELIGIBLE EMPLOYEES shall not exceed the larger of: (1) the average rate of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES multiplied by 1.25; or (2) the lesser of: (i) the average rate of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as a percentage of compensation for all other participating ELIGIBLE EMPLOYEES multiplied by 2; or (ii) the average rate of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for all other participating ELIGIBLE EMPLOYEES plus 2 percentage points, or such lesser amount as the Secretary of the Treasury may prescribe in order to prevent the multiple use of this alternative limitation with respect to any HIGHLY COMPENSATED participant. The average rate of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for a PLAN YEAR for a designated group of ELIGIBLE EMPLOYEES shall be the average of the ratios, calculated separately for each participating ELIGIBLE EM- -4- 5 PLOYEE in the group, of the amount of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS made by and on behalf of each EMPLOYEE for the PLAN YEAR, to the EMPLOYEE'S compensation for such PLAN YEAR. As used in this subsection, compensation shall mean compensation paid by an EMPLOYER to the participant during the PLAN YEAR which is required to be reported as wages on the participant's form W-2 and shall also include compensation which is not currently includable in the participant's gross income by reason of the application of CODE Sections 125 and 402(e)(3). For purposes of this subsection, the ratio of the amount of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to a participant's compensation for any participant who is HIGHLY COMPENSATED for the PLAN YEAR and who is eligible to have elective deferrals or qualified employer deferral contributions allocated to his account under two or more plans or arrangements described in Section 401(k) of the CODE that are maintained by an employer or affiliated employer shall be determined as if all such NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS, elective deferrals and qualified employer deferral contributions were made under a single arrangement. For purposes of determining the ratio of the amount of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to a participant's compensation for a participant who is HIGHLY COMPENSATED by reason of being one of the ten highest-paid EMPLOYEES or a 5 percent owner of the controlled group of corporations, as defined in Section 414 of the CODE, the NON- Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and compensation of such participant shall include the NON- Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and compensation of the participant's family members, as defined in Section 414 of the CODE, and such family members shall be disregarded in determining the average rate of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for non-HIGHLY COMPENSATED participants. The determination and treatment of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS of any participant shall satisfy such other requirements as may be prescribed by the Secretary of the Treasury. (c) In the event that the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, in its sole and absolute discretion, determines that the rate of Section 401(k) CONTRIBUTIONS, and/or the rate of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS will exceed either or both of the maximum limitations contained in subsections 5(a) and 5(b), the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall instruct the PLAN ADMINISTRATOR to reduce the rate of contributions made by HIGHLY COMPENSATED participants so that the limitations will be met. The PLAN ADMINISTRATOR shall first determine the maximum average rate of contributions which can be made by the HIGHLY COMPENSATED participants. The contributions made by HIGHLY COMPENSATED participants shall then be reduced, on a prospective basis, until the limitations are met. Any necessary reduction shall be made by first reducing the highest rate of Section 401(k) CONTRIBUTIONS or NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as may be appropriate, currently authorized by participants, with such rate to -5- 6 be reduced in one percent increments until the maximum permissible average rate of contributions is met. Notwithstanding any other provision of the PLAN, if, as of the end of a PLAN YEAR, the PLAN fails to meet either or both of the tests described in subsections 5(a) or 5(b), the PLAN ADMINISTRATOR shall, on or before December 31 of the following PLAN YEAR distribute to each HIGHLY COMPENSATED participant, beginning with the participant having the higher ratio, such excess portion of the participant's Section 401(k) CONTRIBUTIONS, and/or NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS (and any income allocable to such portion), until the PLAN satisfies both of the tests. If there is a loss allocable to such excess amount, the amount of the distribution shall in no event be less than the lesser of the (i) participant's account or (ii) the participant's Section 401(k) CONTRIBUTIONS, or NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS, as appropriate, for the PLAN YEAR. For the PLAN YEARS 1987, 1988, 1989, 1990 and 1991 only, the PLAN ADMINISTRATOR may elect to make qualified non-elective employer contributions within the meaning of Section 401(m)(4)(c) of the CODE, on behalf of such non-HIGHLY COMPENSATED participants who are EMPLOYEES of Pacific Service Employees Association as will cause the PLAN to meet the appropriate limits set forth in subsections 5(a) and 5(b). For purposes of PLAN withdrawals qualified non-elective employer contributions shall be treated as Section 401(k) CONTRIBUTIONS. For purposes of determining whether the PLAN meets either or both of the limits set forth in subsections 5(a) and 5(b), the PLAN ADMINISTRATOR may elect to make the look-back year calculation as provided in Regulation 1.414(q)-ITA-14(b)(1) for any determination year on the basis of the calendar year ending with the applicable determination year. (d) Annual Section 401(k) Limitation. Effective as of January 1, 1987, no participant shall be permitted to make Section 401(k) CONTRIBUTIONS to the PLAN during any PLAN YEAR in excess of $7,000, multiplied by the adjustment factor prescribed by the Secretary of the Treasury under Section 415(d) of the CODE for years beginning after December 31, 1987, as applied to elective deferrals. A participant who is unable to make Section 401(k) CONTRIBUTIONS which would have been eligible for matching EMPLOYER CONTRIBUTIONS because of the limitation contained in this subsection 5(d), shall be entitled to make NON-Section 401(k) CONTRIBUTIONS in an amount equal to the amount of Section 401(k) CONTRIBUTIONS that could have been made but for the subsection 5(d) limitation. Such NON-Section 401(k) CONTRIBUTIONS shall be eligible for matching EMPLOYER CONTRIBUTIONS as though they were Section 401(k) CONTRIBUTIONS, subject to the limitations contained in Section 5. (e) Section 415 Limitation. Anything herein to the contrary notwithstanding, in no event shall the annual additions to a participant's accounts in a YEAR exceed the lesser of (1) 25 percent of the participant's compensation (as defined in subparagraph 5(e)(1), below) for the YEAR or (2) $30,000, or, if greater, one-fourth of the defined benefit dollar limitation set forth Section 415(b)(1) of the CODE as in effect for the PLAN YEAR. For purposes of applying the limitations of Section 415 of the CODE, the annual additions -6- 7 which must be kept within the limits set forth above, shall mean the sum credited to a participant's account for any PLAN YEAR of (i) EMPLOYER CONTRIBUTIONS and Section 401(k) CONTRIBUTIONS, (ii) NON-Section 401(k) CONTRIBUTIONS, and (iii) any amounts allocated to an individual medical account, as defined in Sections 415(l)(2) and 419A(d)(2) of the CODE. The compensation limitation percentage referred to above shall not apply to (i) any contribution for medical benefits, as defined in Section 419A(f)(2) of the CODE, after a participant's separation from SERVICE which is otherwise treated as an annual addition, or (ii) any amount which is otherwise treated as an annual addition under Section 415(l)(1) of the CODE. (1) Solely for purposes of applying the Section 415 limitations, compensation shall include all of a participant's wages, salaries, fees for professional service, and other amounts received for personal services actually rendered in the course of employment with an EMPLOYER (including, but not limited to, commissions paid to salesmen, compensation for services on the basis of a percentage of profits, commissions on insurance premiums, tips, and bonuses). For purposes of applying the Section 415 limitations, compensation shall not include any of the following: a) Contributions made by an EMPLOYER to a plan of deferred compensation to the extent that, before the application of the Section 415 limitations to that plan, the contributions are not includable in the gross income of the participant for the taxable year in which contributed. Any distributions from a plan of deferred compensation are not considered as compensation for Section 415 purposes, regardless of whether such amounts are includable in the gross income of the EMPLOYEE when distributed. However, any amounts received by a participant pursuant to an unfunded, nonqualified plan may be considered as compensation for Section 415 purposes in the year such income is includable in the gross income of the EMPLOYEE. b) Amounts realized from the exercise of a nonqualified stock option, or when restricted stock (or property) held by a participant either becomes freely transferable or is no longer subject to a substantial risk of forfeiture. c) Amounts realized from the sale, exchange, or other disposition of stock acquired under a qualified stock option. d) Other amounts which receive special tax benefits such as premiums for group term life insurance (but only to the extent that the premiums are not includable in the gross income of the participant). In the event that the annual additions to a participant's accounts would exceed the Section 415 Limitations, the PLAN ADMINISTRATOR shall first reduce the participant's NON-Section 401(k) -7- 8 CONTRIBUTIONS until the Section 415 limitations are met. (f) If a participant of this PLAN is also a participant in the COMPANY'S RETIREMENT PLAN, Section 415 of the CODE imposes a combined benefit limitation. Contributions to this PLAN will nevertheless be permitted to the maximum extent permitted by Section 415 of the CODE and the terms of the PLAN. If the combined maximum benefit permitted would be exceeded, the benefit from the COMPANY'S RETIREMENT PLAN shall be reduced so that the limitation will be met. The combined maximum benefit for a participant shall be determined pursuant to the provisions of Section 415(e) of the CODE. At the election of the PLAN ADMINISTRATOR, special transitional rules may apply for both the defined benefit fraction and the defined contribution fraction for EMPLOYEES who were participants as of December 31, 1982. (g) Top Heavy Provisions. In the event that the PLAN is or becomes "Top Heavy", as that term is defined in Section 416(g) of the CODE, the provision contained in Special Provision A shall supersede any conflicting provision of the PLAN. (h) For purposes of determining all benefits under the PLAN, for PLAN YEARS beginning after 1988 and before 1994, the maximum compensation of each EMPLOYEE that may be taken into account each PLAN YEAR shall not exceed $200,000 (as adjusted by the Secretary of the Treasury under Section 401(a)(17) of the CODE. For purposes of determining all benefits under the PLAN, for PLAN YEARS beginning after 1993, the maximum compensation of each EMPLOYEE that may be taken into account each PLAN YEAR shall not exceed $150,000 (as adjusted by the Secretary of the Treasury under Section 401(a)(17) of the CODE). In determining the compensation of a HIGHLY COMPENSATED EMPLOYEE for purposes of this limitation, the rules of Section 414(q)(6) of the CODE shall apply, except that the term "family" shall include only the spouse of the EMPLOYEE and any lineal descendants of the EMPLOYEE who have not attained age 19 before the close of the YEAR. If the aggregate compensation of family members exceeds the applicable compensation limit of compensation as limited by Section 401(a)(17) of the CODE, then the amount of compen- sation considered under the PLAN for each family member is proportionately reduced so that the total equals the applicable compensation limitation under Section 401(a)(17) of the CODE. SELECTION OF INVESTMENT FUNDS 6. (a) Section 401(k) CONTRIBUTIONS, NON-Section 401(k) CONTRIBUTIONS, and EMPLOYER CONTRIBUTIONS. By giving NOTICE, a participant shall instruct the PLAN ADMINISTRATOR to invest his Section 401(k) CONTRIBUTIONS, NON-Section 401(k) CONTRIBUTIONS, and EMPLOYER CONTRIBUTIONS in one or more INVESTMENT FUNDS. The minimum amount which can be invested in any single INVESTMENT FUND shall be one percent of a participant's current contributions to the PLAN. A participant may elect to invest more than the minimum amount in any INVESTMENT FUND, provided that any such increase must be in increments of one percent. -8- 9 (b) CHANGE OF INVESTMENT FUND ALLOCATIONS. By giving NOTICE to the PLAN ADMINISTRATOR, a participant may (1) change the percentage levels of future contributions which are to be allocated to any INVESTMENT FUND or FUNDS or, (2) change the INVESTMENT FUNDS in which his future contributions are to be invested. Each election regarding investment of future contributions shall be effective with the next deposit of contributions. THE INVESTMENT FUNDS 7. Company Stock Fund This FUND is invested primarily in Common Stock of the COMPANY, with a small portion invested in cash or cash equivalents. The FUND also holds COMPANY STOCK and the earnings thereon attributable to EMPLOYER CONTRIBUTIONS and participant contributions made to the Basic Fund of the PLAN as it existed prior to April 1, 1983, as well as all COMPANY STOCK which has been transferred to this PLAN from the TRASOP and PAYSOP Plan. All cash dividends received by the TRUSTEE on COMPANY STOCK are reinvested in the FUND. (a) Investment Generally. Whenever the TRUSTEE invests cash in COMPANY STOCK, the EMPLOYEE BENEFIT FINANCE COMMITTEE shall direct the TRUSTEE to purchase the COMPANY STOCK either (i) at a public sale on a recognized stock exchange, (ii) directly from the COMPANY at a price equal to that day's closing price for COMPANY STOCK on the New York Stock Exchange, or (iii) from a private source at a price no higher than the price that would have been payable under (i). (b) Voting of COMPANY STOCK. Each and every time shareholders who are not participants in the PLAN are entitled to vote COMPANY STOCK, participants shall have an absolute right to vote COMPANY STOCK. Whenever participants are given the opportunity to vote COMPANY STOCK, the TRUSTEE shall inform each participant of all relevant material received by the TRUSTEE with a written request for confidential voting instructions. The TRUSTEE is required to vote the COMPANY STOCK credited to a participant's account as the participant directs. If the participant does not give such instructions within the required time, the TRUSTEE may not vote any COMPANY STOCK credited to a participant's account. (c) Cost of UNITS. The cost of a UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the COMPANY STOCK FUND. (d) Value of UNITS. The value of a UNIT is the value of the COMPANY STOCK held in the FUND at the closing price on the New York Stock Exchange plus the cash held in the FUND, as determined by the TRUSTEE each BUSINESS DAY, less any fees or other expenses which are charged to the FUND which shall reduce the earnings of that fund, divided by the number of UNITS. Each payment into the COMPANY STOCK FUND of contributions shall increase, and each payment out of the COMPANY STOCK FUND shall decrease, the number of UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. -9- 10 8. United States Bond Fund This FUND was maintained for the purpose of investing EMPLOYEE contributions in United States BONDS. This FUND also holds all BONDS attributable to participant contributions made to the Basic Fund of the PLAN as it existed prior to April 1, 1983. Income from BONDS is reflected in the greater redemption values of the BONDS. BONDS held in this FUND cannot be transferred to another INVESTMENT FUND under the transfer provisions of Section 14. Effective July 1, 1991, the U.S. BOND FUND no longer accepts EMPLOYEE contributions. BONDS purchased to date with EMPLOYEE contributions will continue to be held in the PLAN until a distribution is requested by the EMPLOYEE in accordance with current PLAN provisions. 9. Diversified Equity Fund (DEF) This FUND is maintained for the purpose of investing in a diversified portfolio consisting principally of common stock and securities convertible into common stock. However, at no time shall the DEF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the DEF INVESTMENT MANAGER. The DEF INVESTMENT MANAGER directs the day-to-day investment of the FUND. Contributions to this FUND are paid over to the TRUSTEE and invested in accordance with instructions received from the DEF INVESTMENT MANAGER. A participant's account is credited with the number of DEF UNITS purchased with contributions allocated to his account. All Diversified Investment Fund Units attributable to participant contributions made to the PLAN as it existed prior to April 1, 1983 are held in this FUND under the new designation of DEF UNITS. (a) Cost of DEF UNITS. The cost of a DEF UNIT shall be the current value of a UNIT as determined by the DEF INVESTMENT MANAGER as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the DEF. (b) Value of DEF UNITS. The value of a DEF UNIT is the value of the FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the FUND), divided by the number of DEF UNITS. Each payment into the FUND of contributions shall increase, and each payment out of the FUND shall decrease, the number of FUND UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of the payment. 10. Utility Stock Fund (USF) This FUND is maintained for the purpose of investing in an index fund consisting of common stocks of publicly traded electric utility companies that are members of the Edison Electric Institute. However, at no time shall the FUND be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the USF INVESTMENT MANAGER. The FUND seeks to provide investment results that correspond to the price and yield performance of common stocks of selected utilities engaged in the generation, transmission, or distribution of electric energy, as represented by an index comprising the common stocks of companies that are members of the Edison Electric Institute. Stocks in the FUND's portfolio are generally held in the -10- 11 same proportions that each stock has within the index. Seeking to duplicate the index as closely as possible, the portfolio is monitored and adjusted by computer; no attempt is made to manage the portfolio in the traditional sense using economic, financial, and market analyses. Contributions to the USF are paid to the TRUSTEE and invested in accordance with the instructions from the USF INVESTMENT MANAGER. A participant's account is credited with the number of USF UNITS purchased with contributions allocated to his account. (a) Cost of USF UNITS. The cost of a USF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the USF. (b) Value of USF UNITS. The value of a USF UNIT is the value of the assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than interests of participants in the USF), divided by the number of USF UNITS. Each payment into the USF of contributions shall increase, and each payment out of the USF shall decrease the number of USF UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 11. Guaranteed Income Fund (GIF) This FUND is designed to provide participants with a stable and consistent rate of return. The FUND is made up of investment contracts with a diversified group of insurance companies, banks, and other financial institutions which provide for credited interest rates and terms that are negotiated at the time of purchase. Contributions made to the GIF are invested in a portfolio of investment contracts. The GIF INVESTMENT MANAGER directs the day-to-day investment of the FUND. The blended interest earned on all contracts held in the portfolio is posted daily to the participant's account. (a) COST OF GIF UNITS. The cost of a GIF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the GIF. (b) VALUE OF GIF UNITS. The value of a GIF UNIT is the value of the GIF assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the GIF), divided by the number of GIF UNITS. Each payment into the GIF of contributions shall increase, and payments out of the GIF shall decrease, the number of GIF UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 12. Bond Index Fund (BIF) The BIF is maintained for the purpose of investing in a diversified portfolio consisting principally of marketable fixed-income securities. At no time shall the BIF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the BIF INVESTMENT MANAGER. The -11- 12 BIF INVESTMENT MANAGER directs the day-to-day investment of the BIF. Contributions to the BIF are paid over to the TRUSTEE and invested in accordance with instructions received from the BIF INVESTMENT MANAGER. A participant's account is credited with the number of BIF UNITS purchased with contributions allocated to his account. (a) Cost of BIF UNITS. The cost of a BIF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the FUND. (b) Value of BIF UNITS. The value of a BIF UNIT is the value of the BIF assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the BIF), divided by the number of BIF UNITS. Each payment into the BIF of contributions shall increase, and each payment out of the BIF shall decrease, the number of BIF UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 13. Stock and Bond Fund (SBF) The SBF is maintained for the purpose of investing in a diversified portfolio consisting principally of U.S. equities and U.S. fixed income investments. At no time shall the SBF be invested in securities issued or guaranteed by the COMPANY or any of its subsidiaries, except to the extent that any such securities are held in a commingled account invested in by the SBF INVESTMENT MANAGER. The SBF INVESTMENT MANAGER directs the day-to-day investment of the SBF. Contributions to the SBF are paid over to the TRUSTEE and invested in accordance with instructions from the SBF INVESTMENT MANAGER. A participant's account is credited with the number of SBF UNITS purchased with contributions allocated to his account. (a) Cost of SBF UNITS. The cost of an SBF UNIT shall be the current value of a UNIT as determined by the TRUSTEE as of the valuation date immediately preceding the date that the TRUSTEE invests contributions in the SBF. (b) Value of SBF UNITS. The value of an SBF UNIT is the value of the assets, as determined each BUSINESS DAY by the TRUSTEE, less any liabilities (other than the interests of participants in the SBF), divided by the number of SBF UNITS. Each payment into the SBF of contributions shall increase, and each payment out of the SBF shall decrease, the number of SBF UNITS by a number equal to the amount of the payment divided by the last UNIT value determination immediately preceding the date of payment. 14. Transfer of Investment Fund Balances (a) By giving NOTICE to the PLAN ADMINISTRATOR, a participant may elect to transfer any portion of the contributions held in his account, plus the earnings thereon, from any INVESTMENT FUND to another INVESTMENT FUND or FUNDS. A transfer shall be effective and shall be valued on the day it is made, if such day is a BUSINESS DAY, and the participant provides NOTICE of such transfer prior to the closing time -12- 13 of the New York Stock Exchange. All other transfers shall be effective and valued as of the next BUSINESS DAY. Upon receipt of a transfer NOTICE, the TRUSTEE shall value the UNITS to be transferred from the FUND and convert the UNITS to cash. The FUND account of the participant shall be debited with the number of UNITS transferred from that FUND and the TRUSTEE shall purchase with the cash proceeds realized from the converted UNITS, UNITS in the appropriate FUND or FUNDS, as designated by the participant. The cost of the UNITS purchased shall be the value of the FUND UNITS as determined on the date of transfer, and the number of UNITS purchased shall be credited to the appropriate INVESTMENT FUND account of the participant. (b) COMPANY STOCK FUND -- Overall Limitation. Anything herein to the contrary notwithstanding, if, as of any single month, the TRUSTEE is required, as a result of the transfer provisions of this Section 14, to sell on the open market more than one percent of the number of outstanding shares of COMPANY STOCK, then the TRUSTEE shall immediately so advise the EMPLOYEE BENEFIT FINANCE COMMITTEE. The EMPLOYEE BENEFIT FINANCE COMMITTEE may, in its sole discretion, limit, prorate, or temporarily suspend further sales of COMPANY STOCK by the PLAN or take whatever steps necessary to ensure an orderly market in COMPANY STOCK. The percentage limitation set forth in this subsection shall be applied to the excess of shares sold on the open market less shares purchased to meet Section 14 requirements for the applicable period. PARTICIPANT'S INTEREST IN THE PLAN 15. Participant Accounts The PLAN ADMINISTRATOR maintains a separate account for each PLAN participant which records the participant's interest in each of the INVESTMENT FUNDS, together with EMPLOYER CONTRIBUTIONS made on his behalf. Each account is charged with participant transfers and withdrawals and credited with its appropriate share of FUND income. The account maintained by the PLAN ADMINISTRATOR for each participant also records separately the participant's Section 401(k) CONTRIBUTIONS and NON-Section 401(k) CONTRIBUTIONS, the UNITS purchased therewith, and the earnings thereon. All Basic Contributions and Supplemental Contributions made to the PLAN as it existed prior to October 1, 1984, are recorded as NON-Section 401(k) CONTRIBUTIONS on the records maintained by the PLAN ADMINISTRATOR. Whenever UNITS attributable to a participant's Section 401(k) CONTRIBUTIONS are transferred to another FUND OR FUNDS, the resulting UNITS are also recorded as attributable to Section 401(k) CONTRIBUTIONS. Similarly, UNITS attributable to NON-Section 401(k) CONTRIBUTIONS which are transferred to another FUND or FUNDS are also recorded as NON-Section 401(k) CONTRIBUTIONS. A participant is at all times fully vested in his own contributions and all EMPLOYER CONTRIBUTIONS credited to his account, together with income attributable thereto. 16. Account Statements As soon as practicable after the end of each CALENDAR QUARTER, all participants will receive from the ADMINISTRATOR a statement of their interest in the PLAN. -13- 14 PLAN WITHDRAWALS 17. Withdrawal During Service Except as provided in this Section, withdrawals of any part of a participant's interest in the PLAN are not permitted as long as SERVICE continues. A participant may never replace in the TRUST FUND any UNITS or cash which have been withdrawn. By submitting a withdrawal Form, a participant may make withdrawals as provided below. (a) Section 401(k) CONTRIBUTIONS. (1) A participant may withdraw all or part of the UNITS, including income thereon and including additional UNITS attributable thereto, bought with the participant's Section 401(k) CONTRIBUTIONS upon the occurrence of any of the following events: (a) the participant is disabled and is receiving benefits under the LONG TERM DISABILITY PLAN; or (b) the participant has attained age 59 1/2. (2) A participant may withdraw an amount equal to his Section 401(k) CONTRIBUTIONS, as well as any income and UNITS attributable to income accrued thereon prior to January 1, 1989, upon receipt of satisfactory proof by the PLAN ADMINISTRATOR that the withdrawal is required to meet immediate and heavy financial needs of the participant which constitute a valid hardship as defined under the CODE and regulations issued by the Secretary of the Treasury. A request for a withdrawal for one of the following reasons will be deemed to be on account of a valid hardship: (a) To cover medical expenses (as defined in Section 213(d) of the CODE) of the participant, the participant's spouse or dependents (as defined in Section 152 of the CODE); (b) The purchase of a participant's principal place of residence, but not including mortgage payments; (c) To meet tuition payments for the next semester or quarter of post-secondary education for the participant, his spouse, children or dependents; or (d) To prevent the eviction of the participant from his principal place of residence, or to prevent a foreclosure of the mortgage on the participant's principal place of residence. A request for a withdrawal under this subsection 17(a)(2) will not be deemed to be for immediate and heavy financial needs unless the participant represents that the need cannot be met from the following resources: (a) through reimbursement or compensation by insurance or otherwise, -14- 15 (b) by reasonable liquidation of the participant's resources, (c) by cessation of contributions to the PLAN, or (d) by other distributions, withdrawals or nontaxable loans from any plans maintained by an EMPLOYER, or by borrowing from commercial sources on reasonable commercial terms. For purposes of this Subsection 17(a)(2), a participant's resources shall be deemed to include any assets of his spouse and minor children that are reasonably available to the participant. In addition, withdrawals under Subsection 17(a)(2) may not exceed the amount actually required to meet the participant's immediate financial needs. (3) A participant who withdraws UNITS under Subsection 17(a) will automatically be suspended from the PLAN and will not be permitted to resume making contributions to the PLAN for six months following the date upon which the withdrawal Form is processed by the PLAN ADMINISTRATOR. After suspension ends, contributions may be resumed by giving NOTICE to the PLAN ADMINISTRATOR. (b) NON-Section 401(k) CONTRIBUTIONS. A participant may at any time elect to withdraw all or any part of the UNITS including income thereon and including additional UNITS attributable thereto, bought with the participant's NON-Section 401(k) CONTRIBUTIONS to the PLAN. Such an election will not cause suspension from the PLAN. (c) EMPLOYER CONTRIBUTIONS. (1) A participant may withdraw all or any part of the UNITS, including the income attributable thereto, bought with EMPLOYER CONTRIBUTIONS which were made to the PLAN at anytime prior to the second YEAR preceding the current YEAR. For example, UNITS, including the income attributable thereto, purchased with EMPLOYER CONTRIBUTIONS made in 1981 and prior years may be withdrawn in 1984 or anytime thereafter. Such an election will not cause suspension from the PLAN. (2) UNITS, including the income attributable thereto, bought with EMPLOYER CONTRIBUTIONS which would not be withdrawable under Subsection 17(c)(1), shall nonetheless be withdrawable upon the occurrence of any of the following events: (a) the participant is disabled and is receiving benefits under the LONG TERM DISABILITY PLAN; (b) the participant attains 59-1/2; or (c) the participant has requested and is entitled to receive a hardship distribution which meets the requirements of Subsection 17(a)(2) but only if all amounts distributable under Subsection 17(a) have been exhausted. -15- 16 Anything herein to the contrary notwithstanding, if as of any single month, the TRUSTEE is required as a result of the withdrawal provisions of this Subsection 17(c), to sell on the open market more than one percent of the outstanding shares of COMPANY STOCK, then the TRUSTEE shall immediately so advise the EMPLOYEE BENEFIT FINANCE COMMITTEE. The EMPLOYEE BENEFIT FINANCE COMMITTEE may, in its sole discretion, limit, prorate, or temporarily suspend further sales of COMPANY STOCK by the PLAN or take whatever steps necessary to ensure an orderly market in COMPANY STOCK. A participant shall submit the appropriate Form to the SAVINGS FUND PLAN directing the PLAN ADMINISTRATOR as to the amount of the withdrawal. Distribution will be made as soon as practicable after receipt of the withdrawal Form. Upon each withdrawal, the UNITS credited to the appropriate FUND or FUNDS will be reduced by the number of UNITS withdrawn. Withdrawals from the BOND FUND can only be made in United States BONDS. Withdrawals from the COMPANY STOCK FUND may be made in cash or whole shares of stock at the election of the participant. Withdrawals of DEF, USF, BIF, SBF, or GIF UNITS will be made in cash at the then current value of the UNITS; or, at the election of the participant, the UNITS will be transferred to the COMPANY STOCK FUND pursuant to Section 14 and distribution will be made in whole shares of COMPANY STOCK. (d) Ordering of Withdrawals. Whenever the PLAN ADMINISTRATOR is required to make a distribution under this Section 17 or Section 18, the PLAN ADMINISTRATOR shall first withdraw UNITS and earnings thereon attributable to a participant's NON-Section 401(k) CONTRIBUTIONS made prior to 1987, followed by UNITS and earnings thereon attributable to NON- Section 401(k) CONTRIBUTIONS made after 1986, followed by UNITS withdrawable under Subsection 17(c)(1) followed by UNITS withdrawable under Subsection 17(c)(2), but only if available for withdrawal under that subsection, followed by UNITS and earnings thereon attributable to a participant's Section 401(k) CONTRIBUTIONS, but only to the extent that such UNITS can be withdrawn by the participant under Subsection 17(a). 18. Termination of Participation Participation in the PLAN ends as of the date that a participant ceases to be an ELIGIBLE EMPLOYEE. Although a former participant may elect to have an account balance held in the PLAN under Section 19 after participation ends, a former participant may not contribute to the PLAN, except that contributions to the PLAN will be accepted with respect to retroactive wage payments. A former participant who has an account balance in the PLAN may make withdrawals from the account balance, and transfer from one or more FUNDS to another FUND or FUNDS pursuant to the terms of the PLAN. Upon the death of a participant, the PLAN ADMINISTRATOR shall distribute the participant's account balance to the participant's BENEFICIARY within a reasonable time but not later than 60 days after receipt of a completed withdrawal form or 180 days after the PLAN ADMINISTRATOR receives NOTICE of the participant's death. If the BENEFICIARY does not complete a withdrawal form within the time periods set forth above, the distribution shall be in cash and paid directly to the BENEFICIARY. -16- 17 19. Distribution of Plan Benefits (a) Upon termination of participation, a distribution shall be made of the balances allocated to a participant's accounts if the value of the participant's account is $3,500 or less. Such distribution shall be made no later than the 60th day following the close of the PLAN YEAR in which participation terminates, unless the participant elects to receive distribution at an earlier date. If the value of a participant's account exceeds $3,500, distribution will be made upon receipt by the PLAN ADMINISTRATOR of the written distribution request of the participant. Distribution will therefore be made within 60 days of the receipt of such distribution request. Any provision of the PLAN notwithstanding, if participation continues beyond the end of the YEAR in which the participant attains age 70-1/2, distribution of the participant's entire interest in the PLAN shall be made no later than April 1 of the YEAR following the YEAR in which the participant attains age 70-1/2. All distributions due under the PLAN shall be payable only out of the PLAN's assets as directed by the ADMINISTRATOR. Unless a cash distribution is requested the TRUSTEE will distribute a certificate for the whole shares of COMPANY STOCK, the United States BONDS, and the TRUSTEE'S check for the then current value of all other UNITS credited to the participant's account, plus any uninvested cash. Alternatively, at the direction of the participant, FUND UNITS other than U.S. SAVINGS BONDS UNITS may be transferred to the COMPANY STOCK FUND pursuant to Section 14 and distribution will be made in whole shares of COMPANY STOCK. If a participant elects a cash distribution, upon receipt of the appropriate Form requesting such distribution, the TRUSTEE will distribute the then current value of the INVESTMENT FUND UNITS and uninvested cash. Until the TRUSTEE converts INVESTMENT FUND UNITS to cash, all UNITS shall continue to share in investment gains and losses. Distributions from the BOND FUND can only be made in United States BONDS. (b) Any provision of the PLAN notwithstanding: Unless the participant otherwise elects, distribution to such participant shall be made (or shall commence) not later than the 60th day after the close of the PLAN YEAR in which occurs the latest of the following events: (1) The participant attains age 65; (2) The participant attains the 10th anniversary of the date on which he or she became a participant under the PLAN; or (3) The participant's termination of employment with the EMPLOYER. (c) Distributions hereunder will be made in accordance with Section 401(a)(9) of the CODE and the regulations thereunder, including Treasury regulation Section 1.401(a)(9)-2, which are incorporated by reference herein. -17- 18 20. Direct Rollovers Notwithstanding any provision of the PLAN to the contrary that would otherwise limit a participant's election under this section, effective January 1, 1993, a participant or BENEFICIARY who is a surviving spouse may elect, at the time and in the manner prescribed by the PLAN ADMINISTRATOR, to have any portion of an eligible rollover distribution, as defined below, paid directly to an eligible retirement plan, as defined below, specified by the participant or BENEFICIARY who is a surviving spouse in a direct rollover. Any taxable portion of an eligible rollover distribution that is not transferred directly to an eligible retirement plan will be subject to mandatory federal income tax withholding. (a) An eligible rollover distribution shall mean any distribution of all or any portion of the balance to the credit of the participant, except that an eligible rollover distribution does not include any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the participant or the joint lives (joint life expectancies) of the participant and his or her designated BENEFICIARY, or for a specified period of 10 years or more; any distribution to the extent such distribution is required under Section 401(a)(9) of the CODE; and the portion of any distribution that is not includable in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to employer securities). (b) An eligible retirement plan shall mean an individual retirement account described in Section 408(a) of the CODE, an individual retirement annuity described in Section 408(b) of the CODE, an annuity plan described in Section 403(a) of the CODE, or a qualified trust described in Section 401(a) of the CODE, that accepts the participant's eligible rollover distribution. However, in the case of an eligible rollover distribution to the surviving spouse, an eligible retirement plan is an individual retirement account or individual retirement annuity. ADMINISTRATIVE PROVISIONS 21. Company's Powers and Duties The COMPANY, acting through its BOARD OF DIRECTORS or Executive Committee, reserves to itself the exclusive power to amend, suspend or terminate the PLAN as provided below and to appoint and remove from time to time: (a) The individuals comprising the EMPLOYEE BENEFIT FINANCE COMMITTEE; (b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE; and (c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN. All powers and duties not reserved to the COMPANY are delegated to the EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of a majority of the members of the committee at a meeting, or in writing without a meeting and evidenced by the signature of any member who is so authorized by the committee. The COMPANY -18- 19 indemnifies each member of each committee against any personal liability or expense arising out of any action or inaction of the committee or of any member of the committee or of such individual, except that due to his own willful misconduct. 22. Funding and Investment Provisions The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY'S BOARD OF DIRECTORS to serve at its pleasure has the express powers and duties described in this section. (a) Appointments. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole power and duty from time to time to appoint and remove the TRUSTEE, the INVESTMENT MANAGER, actuaries, accountants and such other advisors and consultants as may be needed for the proper financial administration and investment of the assets of the PLAN. Supplementing such appointments, the EMPLOYEE BENEFIT FINANCE COMMITTEE may enter into appropriate agreements with each TRUSTEE, INVESTMENT MANAGER or other advisors appointed under this paragraph and delegate to them appropriate powers and duties. The EMPLOYEE BENEFIT FINANCE COMMITTEE may appoint and delegate to one or more individuals the power and duty to handle the day-to-day financial administration of the PLAN. Such individuals need not be members of the committee and shall serve at the pleasure of the committee. (b) Investment Policy. The funding policy is set forth in Sections 3 and 4. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole power and duty to establish the investment policy and to review and revise it from time to time as the committee shall determine in its sole discretion. A copy of the current investment policy will be available for participants' review in the ADMINISTRATOR'S office. Any revision of the investment policy shall not be an amendment of the PLAN. 23. Administration The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appointed by the COMPANY'S BOARD OF DIRECTORS to serve at its pleasure, is the ADMINISTRATOR of the PLAN and is responsible for the overall administration of the PLAN. The ADMINISTRATOR has the sole power and duty to establish, and from time to time revise, such rules and regulations as may be necessary to administer the PLAN in a nondiscriminatory manner for the exclusive benefit of participants and all other persons entitled to benefits under the PLAN. The ADMINISTRATOR shall also maintain such records and make such computations, interpretations and decisions as may be necessary or desirable for the proper administration of the PLAN. The ADMINISTRATOR shall maintain for participants' inspection copies of the PLAN, TRUST AGREEMENT, investment policy, each agreement with an INVESTMENT MANAGER, the latest annual report, PLAN description and summary description and any amendments or changes in any of these documents. On written request, participants may obtain from the ADMINISTRATOR a copy of any of these documents at a cost established by the ADMINISTRATOR from time to time. The ADMINISTRATOR may appoint and delegate to one or more individuals the power and duty to handle the day-to-day administration of the PLAN. Such individuals need not be members of the committee and shall serve at the pleasure of the committee. -19- 20 The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall serve as the final review committee under the PLAN, to determine conclusively for all parties any and all questions arising from the administration of the PLAN and shall have sole and complete discretionary authority and control to manage the operation and administration of the PLAN, including, but not limited to, the determination of all questions relating to eligibility for participation and benefits, interpretation of all PLAN provisions, determination of the amount and kind of benefits payable to any participant or BENEFICIARY, and construction of disputed or doubtful terms. Such decisions shall be conclusive and binding on all parties and not subject to further review. 24. Claims and Appeals Procedure If a claim is denied in whole or in part, the ADMINISTRATOR shall furnish to the claimant a written notice setting forth: (a) Specific reason(s) for the denial, (b) The PLAN provision(s) on which the denial is based, (c) A description of any material or information, if any, necessary for the claimant to perfect the claim, and an explanation of why such material or information is necessary, and (d) Information concerning the steps to be taken if claimant wishes to submit a claim for review. The above information shall be furnished to the claimant within 90 days after the claim is received by the ADMINISTRATOR. If a claimant is not satisfied with the written NOTICE described in the preceding paragraph, such claimant may request a full and fair review by so notifying the ADMINISTRATOR in writing within 90 days after receiving such notice. If a review is requested the claimant shall also be entitled, upon written request, to review pertinent documents and to submit issues and comments in writing. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall furnish the claimant with a written final decision within 60 days after receipt of the request for review. 25. Qualified Domestic Relations Orders The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall apply the provisions of this section with regard to a Domestic Relations Order (as defined below) to the extent not inconsistent with Section 414(p) of the CODE. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall establish procedures, consistent with Section 414(p) of the CODE, to determine the qualified status of any Domestic Relations Order, to administer distributions under any Qualified Domestic Relations Order (as defined below), and to provide to the Participant and the Alternate Payee(s) (as defined below) all notices required under Section 414(p) of the CODE with respect to any Domestic Relations Order. Within a reasonable period of time after the receipt of a Domestic Relations Order (or any modification thereof), the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall determine whether such order is a Qualified Domestic Relations Order. For purposes of this section: -20- 21 (a) Alternate Payee shall mean any spouse, former spouse, child, or other dependent of a participant who is recognized by a Domestic Relations Order as having a right to receive all, or a portion of, the benefits payable under the PLAN with respect to such Participant. (b) Domestic Relations Order shall mean any judgment, decree, or order (including approval of a property settlement agreement) which: (1) relates to the provision of child support, alimony payments, or marital property rights to a spouse, former spouse, child, or other dependent of a participant; and (2) is made pursuant to a state domestic relations law (including a community property law). (c) Qualified Domestic Relations Order shall mean a Domestic Relations Order which meets the requirements of Section 414(p)(1) of the CODE. 26. Lost Participant or Beneficiary If, after three years, the ADMINISTRATOR cannot locate a participant or BENEFICIARY who is entitled to a distribution from an account, the UNITS, cash or COMPANY stock in the account shall be applied to reduce the amount of future EMPLOYER CONTRIBUTIONS payable to the PLAN. A participant or BENEFICIARY who is entitled to a distribution from an account which has previously been applied to reduce EMPLOYER CONTRIBUTIONS under this Section 24 shall, upon filing a written claim, have the account reinstated in full and upon such reinstatement shall receive a distribution of the balance in the reinstated account, with interest at the prevailing legal rate accrued from the date his account was applied to reduce EMPLOYER CONTRIBUTIONS. 27. Benefits Are Not Assignable Except as may be required by law, a participant's interest in the PLAN and that of a participant's BENEFICIARY or spouse shall not be subject in any manner to assignment, anticipation, alienation, sale, transfer, pledge, encumbrance or charge, whether voluntary or involuntary, and any attempt to so assign, anticipate, sell, transfer, pledge, encumber or charge the same shall be void. 28. Facility of Payment If the ADMINISTRATOR determines that any individual entitled to any payment under the PLAN is physically or mentally incompetent and no guardian or conservator has been appointed to receive such payment, the ADMINISTRATOR may cause all payments thereafter becoming due to such individual to be applied for and on behalf of and for the benefit of such individual. Payments made pursuant to this provision shall completely discharge the EMPLOYER, the ADMINISTRATOR, the TRUSTEE and all fiduciaries of all further responsibility with respect to such individual. 29. Future of the Plan If participation in the PLAN is ended because a substantial portion of an EMPLOYER'S property is sold or otherwise disposed of or because an EMPLOYER withdraws from the PLAN, a participant's -21- 22 interest is determined in accordance with the provisions of the next paragraphs as if the PLAN itself has been terminated. The COMPANY hopes and expects to continue this PLAN indefinitely, but because future conditions cannot be foreseen, its BOARD OF DIRECTORS necessarily reserves the right to amend or terminate the PLAN at any time. However, no amendment, merger or consolidation of the PLAN may be made which would reduce the right that any individual may then have with respect to the PLAN'S assets then being held under the PLAN or permit any funds to revert to an EMPLOYER or to be used for any purpose except for the exclusive benefit of participants, spouses and BENEFICIARIES. If the PLAN is terminated, all contributions to the PLAN shall cease but the PLAN shall continue to operate in all other respects until all of the TRUST assets have been distributed in accordance with the provisions of the PLAN in effect on the date of its termination. In the event of a merger or consolidation with, or transfer of assets or liabilities to any other plan, if such other plan is then terminated, participant shall receive a benefit immediately after such merger, consolidation, or transfer which is equal to or greater than the benefit which participant would have received had the PLAN terminated immediately prior to such merger, consolidation, or transfer. 30. Definitions ----------- Administrator: Employee Benefit Administrative Committee, ------------- 201 Mission Street, l9th Floor, Mail Code P19A, P.O. Box 770000, San Francisco, California 94177 BIF: The Bond Index Fund. --- Beneficiary: The person or persons entitled to receive any distribution due under ----------- the Plan in the event of a participant's death. For a married participant, the participant's spouse shall automatically be the Beneficiary unless the participant, with the written consent of his spouse, elects to designate another person or persons to be Beneficiary. The consent of the spouse shall be in writing, shall acknowledge the effect of the consent, and shall be witnessed by a notary public or Plan representative. A participant designates a Beneficiary on a Designation of Beneficiary Form available from the Plan Administrator. In the event an unmarried participant does not designate a Beneficiary, the participant's estate shall be deemed to be the Beneficiary. Board of Director: The Board of Directors of Pacific Gas and Electric Company. ----------------- Bond Fund: A fund invested in United States Savings Bonds. (See Section 8) ---------
-22- 23 Bond Index Fund: A fund invested in marketable fixed-income securities. (See Section 12) --------------- Bonds: Series "EE" Savings Bonds issued by the United States Treasury. If ----- the issuance of Series "EE" Bonds is discontinued, Bonds will refer to any other Bond issued by the United States Treasury which the Employee Benefit Finance Committee selects for purchase under the Plan. Business Day: Any day that the New York Stock Exchange is open for business. ------------ Calendar Quarter: The three month period commencing on January 1, April 1, July 1 or ---------------- October 1. Code: The Internal Revenue Code of 1986, as amended from time to time. ---- Company: Pacific Gas and Electric Company. ------- Company Stock: The common stock issued by Company. ------------- Company Stock Fund: A fund invested in the common stock issued by the Company. (See ------------------ Section 7) Covered Compensation: Earnings from an Employer, including straight-time pay for hours -------------------- worked, shift and nuclear premiums at the straight-time rate, straight-time pay for temporary upgrades, vacation pay (including vacation pay upon retirement), inclement weather pay, sick leave pay, holiday pay, differential pay for military training, pay for other time off with permission carrying full pay, temporary compensation under any state Worker's Compensation Law, payments under the Long Term Disability Plan, or supplemental benefits for industrial injury. Covered Compensation shall not include pay or shift and nuclear premiums for more than 40 hours per week, overtime bonuses, vacation or holiday pay requests other special fees or allowances, per diem allowances, payments, other than temporary compensation, made under any Workers' Compensation Law, voluntary wage benefit or state disability plans, or any other benefit plan. For Plan Years beginning after 1988 and before 1994, the maximum Covered Compensation of each Employee that may be taken into account each Plan Year shall not exceed $200,000 (as adjusted by the Secretary of the Treasury under Sec-
-23- 24 tion 401(a)(17) of the Code. For Plan Years beginning after 1993, the maximum Covered Compensation of each Employee that may be taken into account each Plan Year shall not exceed $150,000 (as adjusted by the Secretary of the Treasury under Section 401(a)(17) of the Code). In determining the Covered Compensation of a Highly Compensated Employee for purposes of this limitation, the rules of Section 414(q)(6) of the Code shall apply, except that the term "family" shall include only the spouse of the Employee and any lineal descendants of the Employee who have not attained age 19 before the close of the Year. If the aggregate Covered Compensation of family members exceeds the applicable compensation limit as limited by Section 401(a)(17) of the Code, then the amount of Covered Compensation considered under the Plan for each family member is proportionately reduced so that the total equals the applicable compensation limitation under Section 401(a)(17) of the Code. DEF: The Diversified Equity Fund. --- Diversified Equity Fund: A fund invested in a diversified portfolio of securities. (See ----------------------- Section 9) Eligible Employee: One entitled to become a contributing participant, provided, however, ----------------- however, a "leased employee," as defined in Section 414(n)(2) of the Code shall not be entitled to become an Eligible Employee. Employee: An Employee of an Employer who is not represented by a union. -------- Employee Benefit The Employee Benefit Administrative Committee referred to in Administrative Committee: Section 23. ------------------------ Employee Benefit Finance The Employee Benefit Finance Committee referred to in Section 22. Committee: --------- Employer: Pacific Gas and Electric Company, Pacific Service Employees -------- Association, and any other company, association, or credit union designated by the Board of Directors as eligible to participate in this Plan as an Employer. Employer Contributions: Any contributions to the Plan by Company. ----------------------
-24- 25 FlexDollars: Amounts which a participant elects pursuant to the Company's Flex ----------- Plan to contribute as Section 401(k) Contributions. Rules governing FlexDollars are contained in the Company's Flex Plan; rules governing the treatment of FlexDollars under this Plan are contained in Subsection 3(b). Fund: The Company Stock Fund, the U.S. Bond Fund, the Diversified Equity ---- Fund, the Guaranteed Income Fund, the Bond Index Fund, the Stock and Bond Fund, and the Utility Stock Fund, or any of them. GIF: The Guaranteed Income Fund. --- Guaranteed Income Fund: A fund invested in fixed rate, fixed term contracts. (See Section ---------------------- 11) Highly Compensated: Whether an Eligible Employee is Highly Compensated shall be ------------------ determined using the simplified method under Code Section 414(q)(12) as described in applicable Treasury regulations or other guidance issued by the Internal Revenue Service. Investment Fund: The Company Stock Fund, the U.S. Bond Fund, the Diversified Equity --------------- Fund, the Guaranteed Income Fund, the Bond Index Fund, the Stock and Bond Fund, and the Utility Stock Fund, or any of them. Investment Manager: 1. Diversified Equity Fund. ------------------ J. P. Morgan, 522 Fifth Avenue, New York, NY 10036, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. 2. Guaranteed Income Fund. PRIMCO Capital Management, Inc., 101 South Fifth Street, Louisville, Kentucky 40202, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. 3. Bond Index Fund. The Vanguard Group, Vanguard Financial Center, Valley Forge, Pennsylvania 19482, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. 4. Stock and Bond Fund. Columbia Trust Company, 1301 S.W. Fifth Avenue, P.O. Box 1350, Portland, Oregon 97207, or such other firm or
-25- 26 individual as may be selected from time to time by the Employee Benefit Finance Committee. 5. Utility Stock Fund. Wells Fargo Nikko Investment Advisors, 45 Fremont Street, San Francisco, California 94105, or such other firm or individual as may be selected from time to time by the Employee Benefit Finance Committee. Long Term Disability Plan: Part B of the Group Life Insurance and Long Term Disability Plan of ------------------------- Pacific Gas and Electric Company as amended January 1, 1991. Non-Section 401(k) Contributions: Employee contributions to the Plan as described in Subsection 3(c) -------------------------------- and all Employee Contributions made prior to October 1, 1984. Non-Section 401(k) Contributions are made with after-tax dollars. Notice: Any method of communication, whether electronic, telephonic, written ------ or other, provided that the Plan Administrator has communicated in writing to participants any such method and its format as appropriate and acceptable. Plan: This Company's Savings Fund Plan for Non-Union Employees, as ---- amended, revised and set forth herein. Retirement Plan: The Company's Retirement Plan as revised from time to time. --------------- SBF: The Stock and Bond Fund. --- Savings Fund Plan Office: 201 Mission Street, l9th Floor ------------------------ Mail Code P19A P.O. Box 770000 San Francisco, CA 94177 Section 401(k) Contribution: Amounts deferred from a Participant's Covered Compensation as --------------------------- described in Subsection 3(a). Section 401(k) Contributions are made with pre-tax dollars. Service: The period of time commencing with the first day of employment or ------- reemployment for an Employer and ending on participant's Severance from Service Date. If an Employee with less than one year of Service is rehired after a period of severance which extends for 12 months or more, the Employee shall be treated as a new Employee for all purposes, and
-26- 27 the Service and compensation before the Severance from Service Date shall not be recognized for any purpose of the Plan. Participants who have a period of severance after they have completed at least one year of Service and who are later rehired, immediately become Eligible Employees entitled to contribute in accordance with their total years of Service. Service shall also include all years of Service with: (a) Any corporation which is a member of the same controlled group of corporations as the Company or of any other Employer (within the meaning of Section 414(b) of the Code); (b) Any trade or business under the common control of the Company or of any other Employer (within the meaning of Section 414(c) of the Code); (c) Any service organization which is a member of the same affiliated service group as the Company or of any other Employer (within the meaning of Section 414(m) of the Code). Severance From Service A. The date on which an Employee quits, retires, is discharged Date: or dies; or ---- B. The first anniversary of the first date of a period in which a participant remains absent from work for an Employer for any reason other than resignation, retirement, discharge, or death. C. For the purpose of determining the Severance from Service Date, the following periods shall not be considered as absences from work for an Employer: (1) Absence on a leave of absence authorized by an Employer. (2) Absence because of illness or injury as long as the participant is entitled to receive sick leave pay or is entitled to receive benefits
-27- 28 under the provisions of the Voluntary Wage Benefit Plan, a state disability plan, the Long Term Disability Plan, or a Workers' Compensation Law. (3) Absence for military service or service in the Merchant Marines so long as reemployment rights are protected by law. (4) Absence caused by layoff for lack of work of less than 12 continuous months for a Participant who has less than five years of service, or 24 continuous months for a Participant who has five or more years of service. Stock and Bond Fund: A fund invested in U.S. equities and U.S. fixed-income investments. ------------------- (See Section 13) Trust: The Trust into which all contributions are deposited and from which ----- all distributions are made. Trustee: State Street Bank and Trust Company, 225 Franklin Street, Boston, ------- Massachusetts 02101, or such other bank or trust company selected by the Employee Benefit Finance Committee which agrees to act as Trustee or successor Trustee of the Trust pursuant to the Trust Agreement. Trust Agreement: The agreement between the Company and the Trustee. --------------- Unit: A measurement of participant's interest in the Investment Funds. ---- For purposes of the Bond Fund, a unit shall be a United States Bond. USF: The Utility Stock Fund. --- Utility Stock Fund: An index fund invested in common stocks of companies engaged in the ------------------ generation, transmission or distribution of electric energy (See Section 10). Year: The calendar year beginning January 1 and ending December 31. ---
-28- 29 SPECIAL PROVISION A TOP HEAVY PROVISIONS (a) General Rule For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined in subsection (g) below, any other provisions of this PLAN to the contrary notwithstanding, this PLAN shall be subject to the following provisions: (1) The minimum contribution provisions of subsection (b). (2) The limitation on contribution set by subsection (d). (b) Minimum Contribution Provisions Each participant who (i) is a non-key EMPLOYEE (as defined in subsection (i) below) and (ii) is employed on the last day of the PLAN YEAR, even if such individual is excluded from the PLAN for failing to make mandatory contributions to the PLAN, shall be entitled to have contributions allocated to his account of not less than three percent (the "minimum contribution percentage") of the participant's compensation (within the meaning of Section 415 of the CODE). In determining the minimum contribution percentage to be allocated to an EMPLOYEE'S account, a participant's Section 401(k) CONTRIBUTIONS shall be considered as EMPLOYER CONTRIBUTIONS. The minimum contribution percentage set forth above shall be reduced for any PLAN YEAR in which the percentage at which contributions are made (or required to be made) under the PLAN for the PLAN YEAR for the key EMPLOYEE for whom such percentage is the highest for such PLAN YEAR is less than three percent. For this purpose, the percentage with respect to a key EMPLOYEE (as defined in subsection (g) below) shall be determined by dividing the contributions (including forfeitures) made for such key EMPLOYEES by so much of his total compensation for the PLAN YEAR. Contributions taken into account under the immediately preceding sentence shall include contributions under this PLAN and under all other defined contribution plans required to be included in an aggregation group (as defined in subsection (f)(2) below) but shall not include any plan required to be included in such aggregation group if such plan enables a defined contribution plan required to be included in such group to meet the requirements of the CODE prohibiting discrimination as to contributions or benefits in favor of EMPLOYEES who are officers, shareholders or the highly-compensated or prescribing the minimum participation standards. Contributions taken into account under this subsection (b) shall not include any contributions under the Social Security Act or any other Federal or State law. (c) Limitations on Contributions In the event that the EMPLOYER also maintains a defined benefit PLAN providing benefits on behalf of participants in this PLAN, one of the two following provisions shall apply: (1) If for the PLAN YEAR this PLAN would not be a "top-heavy PLAN" as defined in subsection (a)(2) above if "90 percent" were substituted for "60 percent," then subsection (b) shall -29- 30 apply for such PLAN YEAR as if amended so that "four percent" were substituted for "three percent". (2) If for the PLAN YEAR this PLAN would continue to be a "top-heavy PLAN" as defined in subsection (f) below if "90 percent" were substituted for "60 percent," then the denominator of both the defined contribution PLAN fraction and the defined benefit PLAN fraction shall be calculated as set forth in Section 415 (e) of the CODE for the limitation year ending in such PLAN YEAR by substituting "1.0" for "1.25" in each place such figure appears, except with respect to any individual for whom there are no EMPLOYER CONTRIBUTIONS allocated or any accruals for such individual under the defined benefit PLAN. Furthermore, the transitional rule set forth in Section 415 (e) of the CODE shall be applied by substituting "$41,500" for "$51,875". (d) Coordination with Other Plans In the event that another defined contribution or defined benefit plan maintained by the EMPLOYER provides contributions or benefits on behalf of participants in this PLAN, such other plan shall be treated as a part of this PLAN pursuant to applicable principles (such as Rev. Rul. 81-202 or any successor ruling or regulations) in determining whether this PLAN satisfies the requirements of subsection (b), (c) and (d). Such determination shall be made upon the advice of counsel by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE. (e) Top-Heavy Plan Definition This PLAN shall be a "top-heavy plan" for any PLAN YEAR if, as of the determination date (as defined in subsection (f)(1) below), the aggregate of the accounts under the PLAN and any required aggregation group or permissive aggregation group of plans for participants (including former participants) who are key EMPLOYEES (as defined in subsection (g) below but not including accounts of individuals excluded under section 416(g)(4)(E) of the CODE) exceeds 60 percent of the present value of the aggregate of the accounts for all participants, excluding former key EMPLOYEES, or if this PLAN is required to be in an aggregate group (as defined in subsection (f)(3) below) which for such PLAN YEAR is a top-heavy group (as defined in subsection (f)(4) below). (1) "Determination date" means for any PLAN YEAR the last day of the immediately preceding PLAN YEAR. (2) "Valuation date" means the last day of each PLAN YEAR. (3) "Aggregation group" means the group of plans, if any, that includes both the group of plans that are required to be aggregated and the group of plans that are permitted to be aggregated. (A) The group of plans that are required to be aggregated (the "required aggregation group") includes (i) Each plan of the EMPLOYER (as defined in subsection (i) below) in which a key EMPLOYEE is a participant, including collectively- bargained plans, and (ii) Each other plan, including collectively- bargained plans of the EMPLOYER (as defined in subsection (i) below) which enables a plan in which a key EMPLOYEE is a participant to meet -30- 31 the requirements of the CODE prohibiting discrimination as to contributions or benefits in favor of EMPLOYEES who are officers, shareholders or the highly- compensated or prescribing the minimum participation standards. (B) The group of plans that are permitted to be aggregated (the "permissive aggregation group") includes the required aggregation group plus one or more plans of the EMPLOYER (as defined in subsection (i) below) that is not part of the required aggregation group and that the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE certifies as constituting a plan within the permissive aggregation group. Such plan or plans may be added to the permissive aggregation group only if, after the addition, the aggregation group as a whole continues not to discriminate as to contributions or benefits in favor of officers, shareholders or the highly-compensated and to meet the minimum participation standards under the CODE. (4) "Top-heavy group" means the aggregation group, if as of the applicable determination date, the sum of the present value of the cumulative accrued benefits for key EMPLOYEES under all defined benefit plans included in the aggregation group plus the aggregate of the accounts of key EMPLOYEES under all defined contribution plans included in the aggregation group exceeds 60% of the sum of the present value of the cumulative accrued benefits for all EMPLOYEES, excluding former key EMPLOYEES, under all such defined benefit plans plus the aggregate accounts for all EMPLOYEES, excluding former key EMPLOYEES, under such defined contribution plans. If the aggregation group that is a top-heavy group is a required aggregation group, each plan in the group will be top heavy. If the aggregation group that is a top-heavy group is a permissive aggregation group, only those plans that are part of the required aggregation group will be treated as top-heavy. If the aggregation group is not a top-heavy group, no plan within such group will be top-heavy. (5) In determining whether this PLAN constitutes a "top-heavy plan," the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (or its agent) shall make the following adjustments in connection therewith: (A) When more than one plan is aggregated, the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall determine separately for each plan as of each plan's determination date the present value of the accrued benefits or account balance. The results shall then be aggregated separately by adding the results of each plan as of the determination dates for such plans that fall with the same calendar year. (B) In determining the present value of the cumulative accrued benefit or the amount of the account of any EMPLOYEE, such present value or account shall include the amount in dollar value of the aggregate distributions made to such EMPLOYEE under the applicable plan during the five-year period ending on the determination date, unless reflected in the value of the accrued benefit or account balance as of the most recent valuation date. Such amounts shall include distribu- -31- 32 tions to EMPLOYEES which represented the entire amount credited to their accounts under the applicable plan. (C) Further, in making such determination, in any case where an individual is a "non-key EMPLOYEE" as defined in subsection (h) below, with respect to an applicable plan, but was a key EMPLOYEE with respect to such plan for any prior PLAN YEAR, any accrued benefit and any account of such EMPLOYEE shall be altogether disregarded. For this purpose, to the extent that a key EMPLOYEE is deemed to be a key EMPLOYEE if he or she met the definition of key EMPLOYEE within any of the four preceding PLAN YEARS, this provision shall apply following the end of such period of time. (f) Key EMPLOYEE The term "key EMPLOYEE" means any EMPLOYEE or former EMPLOYEE under this PLAN who, at any time during the PLAN YEAR containing the determination date or during any of the four preceding PLAN YEARS, is or was one of the following: (1) An officer of the EMPLOYER having an annual compensation greater than 50 percent of the amount in effect under Section 415(b)(1)(A) of the CODE for such PLAN YEAR. Whether an individual is an officer shall be determined by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE on the basis of all the facts and circumstances, such as an individual's authority, duties and term of office, not on the mere fact that the individual has the title of officer. For any such PLAN YEAR, these shall be treated as officers no more than the lesser of: (A) 50 EMPLOYEES, or (B) the greater of three EMPLOYEES or 10 percent of the EMPLOYEES. For this purpose, if there are more than 50 officers, the 50 highest-paid officers shall be the key EMPLOYEES. (2) One of the ten EMPLOYEES owning (or considered as owning, within the meaning of the constructive ownership rules of the CODE) the largest interests in the EMPLOYER (as defined in subsection (i)). An EMPLOYEE who has some ownership interest is considered to be one of the top ten owners unless at least ten other EMPLOYEES own a greater interest than that EMPLOYEE. However, an EMPLOYEE will not be considered a top ten owner for a PLAN YEAR if the EMPLOYEE earns an amount equal to or less than the maximum dollar limitation on contributions and other annual additions to a participant's account in a defined contribution PLAN under the CODE as in effect for the calendar year in which the determination date falls. (3) Any person who owns (or is considered as owning within the meaning of the constructive ownership rules of the CODE) more than five percent of the outstanding stock of the EMPLOYER or stock possessing more than five percent of the combined total voting power of all stock of the EMPLOYER. (4) A one percent owner of the EMPLOYER having an annual compensation from the EMPLOYER of more than $150,000, and who owns more than one percent of the outstanding stock of the EM- -32- 33 PLOYER or stock possessing more than one percent of the combined total voting power of all stock of the EMPLOYER. For purposes of this subsection, compensation means all items includable as compensation for purposes of applying the limitations on contributions and other annual additions to a participant's account in a defined contribution plan and the maximum benefit payable under a defined benefit plan under the CODE. For purposes of parts (1), (2), (3) and (4) of this definition, a BENEFICIARY of a key EMPLOYEE shall be treated as a key EMPLOYEE. For purposes of parts (3) and (4), each EMPLOYER is treated separately (without regard to the definition in subsection (i)) in determining ownership percentages; but, in determining the amount of compensation, the definition of EMPLOYER in subsection (i) is taken into account. (g) Non-key EMPLOYEE The term "non-key EMPLOYEE" means any EMPLOYEE (and any beneficiary or an EMPLOYEE) who is not a key EMPLOYEE. (h) Employer The term "employer" as defined in Section 30 of this PLAN. -33- 34 ------------------------- I, Leslie H. Everett, do hereby certify that I am the Corporate Secretary of the PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of California, and that the above and foregoing is a full, true and correct copy of the Pacific Gas and Electric Company SAVINGS FUND PLAN FOR NON-UNION EMPLOYEES as the same exists at the date of this certification. WITNESS my hand and the seal of the said corporation hereunto affixed this day of . Leslie H. Everett Corporate Secretary of PACIFIC GAS AND ELECTRIC COMPANY -34- EX-10.8 6 PG&E RETIREMENT PLAN FOR EMPLOYEES 1 EXHIBIT 10.8 THE PACIFIC GAS AND ELECTRIC COMPANY RETIREMENT PLAN 2 PART I TABLE OF CONTENTS RETIREMENT PLAN
Page ---- 1. Introduction. . . . . . . . . . . . . . . . . . . 1 2. Eligibility and Participation . . . . . . . . . . 2 3. Service . . . . . . . . . . . . . . . . . . . . . 2 4. Break in Service and Reemployment . . . . . . . . 2 5. Normal Retirement Date. . . . . . . . . . . . . . 3 6. Basic Pension Benefit Formula . . . . . . . . . . 3 7. Early Retirement Pension Benefit Formula. . . . . 4 8. Pensions Where Employment Ends Before Age 55. . . 5 9. Deferred Retirement . . . . . . . . . . . . . . . 6 10. Forms of Pension. . . . . . . . . . . . . . . . . 6 11. Spouse's Pension. . . . . . . . . . . . . . . . . 8 12. Withdrawal of Participant Contributions on Termination of Employment . . . . . . . . . . . . 9 13. Death Benefits. . . . . . . . . . . . . . . . . . 9 14. Facility of Payment . . . . . . . . . . . . . . . 9 15. Benefits Are Not Assignable . . . . . . . . . . . 10 16. Employer Contributions. . . . . . . . . . . . . . 10 17. Company's Powers and Duties . . . . . . . . . . . 11 18. Funding and Investment Provisions . . . . . . . . 11 19. Administration. . . . . . . . . . . . . . . . . . 12 20. Claims Procedure. . . . . . . . . . . . . . . . . 12 21. Qualified Domestic Relations Orders . . . . . . . 13 22. Amendment, Termination, and Merger. . . . . . . . 13 23. Definitions and Cross-References. . . . . . . . . 14 SPECIAL PROVISIONS A, B, C, D, E, F, G, H, I, J, K, M and N . . . . . . . . . . . . . . . . . . . . . . 21-78
3 RETIREMENT PLAN 1. Introduction This is the controlling and definitive statement of the Pacific Gas and Electric Company Retirement PLAN1/ which, with certain exceptions, is effective on and after Janu- ary 1, 1994, for EMPLOYEES who are employed by Pacific Gas and Electric Company and other EMPLOYERS. This PLAN is a further revision of the PLAN, originally placed in effect by the COMPANY January 1, 1937, which has been amended from time to time in the intervening years. Rights of PARTICIPANTS in this PLAN will not be less than rights of PARTICIPANTS under COMPANY'S PLAN as it existed before 1994. The purpose of this PLAN is to distribute the corpus and income of accumulated PENSION trust funds in accordance with the PLAN. Under no circumstances shall contributions or benefits under this PLAN discriminate in favor of a "highly compensated EMPLOYEE," as that term is defined using the simplified method under CODE Section 414(q)(12) as described in applicable Treasury regulations or other guid- ance issued by the Internal Revenue Service. Forfeitures of nonvested accrued benefits under the PLAN shall not be applied to increase benefits any EMPLOYEE could otherwise receive under the terms of the PLAN. Except for pension adjustments provided for in Special Provision G, PARTICIPANTS who retire or terminate employment before the effective date of any amendment are not affected or benefited by such amendments. Since final regulations governing many statutory re- quirements of the Employee Retirement Income Security Act of 1974 (ERISA) have not yet been issued, the COMPANY reserves the right to retroactively modify the final language of the revised PLAN to conform to these requirements. As provided for in Section 414(f) of the CODE, the PLAN has elected to be treated as a single employer plan. This PLAN consists of Part I and Part II. Part I applies solely to EMPLOYEES not covered by a collective bargaining agreement, and Part II applies solely to EMPLOY- EES whose benefits are the subject of collective bargaining with a union representing EMPLOYEES of the COMPANY.2/ ________________________ 1/ Words in all capitals are defined in Section 23. 2/ For PLAN YEARS prior to January 1, 1995, only management EMPLOYEES were PARTICIPANTS in Part I of the PLAN; prior to January 1, 1995, weekly- paid, non-union EMPLOYEES participated in Part II. -1- 4 PART I 2. Eligibility and Participation An EMPLOYEE automatically becomes a PARTICIPANT in the PLAN on the first day of work for an EMPLOYER, and partici- pation continues until the PARTICIPANT's SERVICE is termi- nated. 3. Service (a) The SERVICE of a PARTICIPANT on any date shall consist of the sum of the following: (1) Any CREDITED SERVICE as of December 31, 1975, as defined under the PLAN prior to the January 1, 1976, amendment and reproduced in Special Provision F, and (2) The elapsed time from the first day of em- ployment with an EMPLOYER (but not earlier than January 1, 1976) to the PARTICIPANT's SEVERANCE FROM SERVICE DATE, excluding any periods of BREAK IN SERVICE and any SERVICE cancelled by the operation of Sections 4 and 13. (b) For EMPLOYEES who attain PART-TIME status at any time on or after January 1, 1991, service benefit accruals will be based on the following SERVICE: (i) Paragraph (a) of this Section will apply to all SERVICE prior to January 1, 1991; (ii) All SERVICE after December 31, 1990 in which the EMPLOYEE is designated as a PART-TIME EMPLOYEE shall be prorated for purposes of benefit accruals based on the ratio of actual straight-time hours worked in the calendar year to the full-time hourly equivalent (2,080 per calendar year) rounded to the nearest month. 4. Break in Service and Reemployment Upon reemployment with an EMPLOYER after a BREAK IN SERVICE, prior SERVICE earned under the PLAN will be treated for eligibility, vesting and/or benefit accrual as follows: (a) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January 1, 1989, the SERVICE of such PARTICIPANT prior to the BREAK IN SERVICE will be cancelled unless such prior SERVICE was at least five years or, in the event that such prior SERVICE was less than five years, if the period of the BREAK IN SERVICE was less than the prior SERVICE. (b) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January 1, 1985, but before January 1, 1989, the SERVICE of such PARTICIPANT prior to the BREAK IN SERVICE will be cancelled unless such prior SERVICE was at least 10 years or, in the event that such prior SERVICE was less than 10 years, such prior SERVICE will be cancelled if the period of the BREAK IN SERVICE is equal to or exceeds the greater of (i) five years or (ii) the period of SERVICE prior to the BREAK IN SERVICE. (c) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January 1, 1976, but before January 1, 1985, the SERVICE of such PARTICIPANT prior to the BREAK IN SERVICE will be cancelled unless such prior SERVICE was at least 10 years or, in the event that such prior SERVICE was less than 10 years, if the period of the BREAK IN SERVICE -2- 5 was less than the prior SERVICE. If the PARTICIPANT's contributions to the PLAN have been withdrawn, restoration of the PARTICIPANT's prior SERVICE will be in accordance with the provisions of Section 12. (d) EMPLOYEES who were PARTICIPANTS in the PLAN prior to January 1, 1976, and whose prior SERVICE would not be restored under the provisions of (a) of this Section, but would have been restored under the provisions of the PLAN prior to the January 1, 1976, amendment, shall continue to be eligible to have their prior SERVICE restored under the rules of the PLAN prior to the January 1, 1976, amendment. Such rules are set forth in Special Provision E. 5. Normal Retirement Date NORMAL RETIREMENT DATE is the first day of the month following a PARTICIPANT's 65th birthday. 6. Basic Pension Benefit Formula A PARTICIPANT whose SERVICE continues to NORMAL RETIRE- MENT DATE or beyond3/ is entitled to a BASIC PENSION pay- able on ACTUAL RETIREMENT DATE and on the first day of each month thereafter as long as the PARTICIPANT lives.4/ (a) The monthly amount of the BASIC PENSION for a PARTICIPANT whose entire SERVICE is accrued as a PARTICIPANT in Part I of this PLAN shall be a monthly amount equal to 1.6 percent of the PARTICIPANT's average BASIC MONTHLY SALARY for the final 36 consecutive months of SERVICE,5/ multiplied by the number of whole and fractional years of SERVICE. The amount so determined shall take the place of all other retirement income to which a PARTICIPANT might otherwise have been entitled under any suspended plan of an EMPLOYER or predecessor company. (b) The monthly amount of the BASIC PENSION for a PARTICIPANT whose classification is changed and who has accrued SERVICE under both Part I and Part II of this PLAN shall be the larger of (1) or (2) below: (1) The amount produced by computing all years of SERVICE pursuant to the applicable formula for the new classification. (2) The amount equal to the sum of (i) a pension benefit for SERVICE prior to the change in classification, computed pursuant to the applicable formula for the PARTICIPANT's old classification in effect at the time of the change in classification; and (ii) a pension benefit for SERVICE after the change in clas- sification, computed pursuant to the formula applicable for ______________________ 3/ See Section 9 for the conditions under which this may occur. 4/ See Section 10 for the conditions under which other forms of pension may be substituted for the BASIC PENSION. 5/ A married PARTICIPANT'S EARLY RETIREMENT PENSION shall be in the form of a MARITAL PENSION, computed as provided in Section 10b. In lieu of a MARITAL PENSION, a PARTICIPANT may elect any of the alternative forms of the EARLY RETIREMENT PENSION described in Section 10b. and subject to the rules contained therein. -3- 6 the PARTICIPANT's new job classification. Each portion of the BASIC PENSION calculated under (i) and (ii) above shall be subject to all the applicable reductions imposed in PART I and PART II with respect to age and early retirement, joint pensions, marital pensions, and the election of an alternative spouse's pension. (c) The monthly amount of the BASIC PENSION for a PARTICIPANT receiving LONG TERM DISABILITY PLAN benefits on ACTUAL RETIREMENT DATE shall be computed under (1) or (2) below, as applicable: (1) For EMPLOYEES receiving LONG TERM DISABILITY PLAN benefits on January 1, 1988, a monthly benefit equal to 1.6 percent of the larger of (i) the PARTICIPANT'S BASIC MONTHLY SALARY for the last month of active SERVICE or (ii) the PARTICIPANT'S LONG TERM DISABILITY PLAN benefit for the month immediately preceding ACTUAL RETIREMENT DATE. The result obtained in (i) or (ii) shall be multiplied by the number of whole or fractional years of SERVICE. (2) For EMPLOYEES who start receiving LONG TERM DISABILITY PLAN benefits after January 1, 1988, a monthly benefit equal to 1.6 percent of the larger of (i) the average BASIC MONTHLY SALARY for the final consecutive 36 months of active SERVICE or (ii) the PARTICIPANT'S LONG TERM DISABILITY PLAN benefit for the month immediately preceding ACTUAL RETIREMENT DATE. The result obtained in (a) or (b) shall be multiplied by the number of whole and fractional years of SERVICE. 7. Early Retirement Pension Benefit Formula If a PARTICIPANT's SERVICE ends after the first day of the month following said PARTICIPANT's 55th birthday, and before NORMAL RETIREMENT DATE or death, the PARTICIPANT shall elect to receive either: a. A BASIC PENSION computed as provided in Section 6, or a MARITAL PENSION computed as provided in Section 10b., whichever is applicable, payable beginning with NORMAL RETIREMENT DATE; or b. An EARLY RETIREMENT PENSION with payments to begin on the PARTICIPANT's EARLY RETIREMENT DATE and to continue on the first day of each month thereafter so long as PARTICIPANT lives. EARLY RETIREMENT DATE is the date selected by the PARTICIPANT for commencement of payment of retirement benefits. This date must be the first day of any month after the termination of SERVICE and before the PARTICIPANT's 65th birthday. To elect an EARLY RETIREMENT PENSION, PARTICIPANT must notify the EMPLOYER in writing at least 30 days before the EARLY RETIREMENT DATE the PARTICIPANT selects. The monthly amount of the PARTICIPANT's EARLY RETIREMENT PENSION6/ will be as follows: - ---------- 6/ A married PARTICIPANT'S EARLY RETIREMENT PENSION shall be in the form of a MARITAL PENSION, computed as provided in Section 10b and Section 7. In lieu of a MARITAL PENSION, a PARTICIPANT may elect any of the alternative forms of the EARLY RETIREMENT PENSION described in Section 10b, and subject to the rules contained therein. -4- 7 (1) If PARTICIPANT has less than 15 years of SERVICE on the EARLY RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced by one-fourth of one percent for each month (three percent per year) between PARTICIPANT's NORMAL RETIREMENT DATE and PARTICIPANT's EARLY RETIREMENT DATE; or (2) If PARTICIPANT has at least 15 but less than 30 years of SERVICE and is 62 years of age or older on the EARLY RETIREMENT DATE, the amount shall be the PARTICIPANT's BASIC PENSION computed to the PARTICIPANT's EARLY RETIREMENT DATE; or (3) If PARTICIPANT has at least 15 but less than 25 years of SERVICE and is less than 62 years of age on the EARLY RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced by one-fourth of one percent for each month (three percent per year) by which PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 62nd birthday, and further reduced by 1/12th of one percent for each month (one percent per year) by which PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 60th birthday; or (4) If PARTICIPANT has at least 25 but less than 30 years of SERVICE and is less than 62 years of age on the EARLY RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced by one-fourth of one percent for each month (three percent per year) by which PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 62nd birthday; or (5) If a PARTICIPANT has at least 30 years of SERVICE and is less than 60 years of age on the EARLY RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced by one-half of one percent for each month (up to a maximum of 12 months or six percent) by which PARTICIPANT'S EARLY RETIREMENT DATE precedes PARTICIPANT's 60th birthday, and further reduced by one-fourth of one percent for each month (three percent per year) by which PARTICIPANT'S EARLY RETIREMENT DATE precedes PARTICIPANT's 59th birthday; or (6) If PARTICIPANT has at least 30 years of SERVICE and is 60 years of age or older on the EARLY RE- TIREMENT DATE, the amount shall be the PARTICIPANT's BASIC PENSION computed to the PARTICIPANT's EARLY RETIREMENT DATE. (7) If a PARTICIPANT has at least 35 years of SERVICE and is 55 years of age or older on EARLY RETIRE- MENT DATE, and such PARTICIPANT was formerly a PARTICIPANT on December 31, 1994, in Part II of the PLAN, the amount shall be the PARTICIPANT'S BASIC PENSION computed to the PARTICIPANT'S EARLY RETIREMENT DATE. See Special Provision B for a table of EARLY RETIREMENT reductions. 8. Pensions Where Employment Ends Before Age 55 Until January 1, 1989, a PARTICIPANT with at least 10 years of SERVICE will be designated as a former EMPLOYEE rather than a retired EMPLOYEE if such PARTICIPANT's SERVICE ends before the first day of the month which follows the PARTICIPANT's 55th birthday. Effective January 1, 1989, any PARTICIPANT with at least five years of SERVICE will be designated as a former EMPLOYEE if such PARTICIPANT's SER- VICE ends before the first day of the month which follows the PARTICIPANT's 55th birthday. Such former EMPLOYEE has a vested right to receive a PENSION -5- 8 with the same rights of election and in the same amounts as provided in Section 7, provided that the earliest election date for commencement of PENSION payments is the first day of the month after the PARTICIPANT's 55th birthday and the latest shall be April 1 of the year following the year in which the PARTICIPANT attains age 70 1/2. Such a PARTICI- PANT is also entitled to the elections provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Partici- pant Contributions on Termination of Employment), 13 (Death Benefits in Certain Cases), and 15 (Facility of Payment). 9. Deferred Retirement An EMPLOYEE may continue in employment beyond the NORMAL RETIREMENT DATE only at the request of an EMPLOYER or as may be required by law. A PARTICIPANT whose employment continues beyond NORMAL RETIREMENT DATE shall not be enti- tled to a pension until PARTICIPANT's ACTUAL RETIREMENT DATE. Any provision of the PLAN notwithstanding, distribu- tions from the PLAN shall comply with the requirements of CODE Section 401(a)(9) and the regulations thereunder. The amount of the PENSION payable shall be the PENSION benefit accrued as of the April 1 following the end of the year in which the EMPLOYEE attains age 70 1/2, adjusted for any elections made by the PARTICIPANT and any forms of PENSION required under Section 10. Pursuant to CODE Section 401(a)(9)(A)(ii), if an EM- PLOYEE continues employment beyond the end of the year in which the EMPLOYEE attains age 70 1/2, a PENSION shall be distributed, commencing not later than April 1 of the calen- dar year following the calendar year in which the EMPLOYEE attains age 70 1/2, over the life of the EMPLOYEE or over the joint lives of the EMPLOYEE and the EMPLOYEE'S SPOUSE or other JOINT PENSIONER. If an EMPLOYEE dies after the distribution of the EMPLOYEE'S interest in the PLAN has begun, then, in accor- dance with CODE Section 401(a)(9)(B)(i), the remaining portion of the EMPLOYEE'S accrued PENSION benefit, if any, will be distributed at least as rapidly as under the method of distributions being used as of the date of his or her death. If an EMPLOYEE dies before the ACTUAL RETIREMENT DATE, then the EMPLOYEE'S SPOUSE may elect to postpone receiving distributions under the SPOUSE'S PENSION, but postponement of receipt of benefits shall not extend beyond the date that the EMPLOYEE would have attained age 70 1/2. Death benefits provided under the PLAN shall be no more than incidental, within the meaning of the CODE, to the PLAN'S primary purpose of providing retirement benefits to EMPLOY- EES. 10. Forms of Pension (a) Joint Pension With Non-Spouse For a PARTICIPANT who is unmarried on the ACTUAL RE- TIREMENT DATE, the normal form of a PENSION shall be a BASIC PENSION or an EARLY RETIREMENT PENSION which terminates on the PARTICIPANT'S death. A MARITAL PENSION, as described in 10(b) below, is the normal form of PENSION for PARTICIPANTS who are married on the ACTUAL RETIREMENT DATE. However, any PARTICIPANT, whether married or unmarried, who wishes to have the PENSION continued in whole or in part after the PARTICIPANT'S death for the life of a non-spouse JOINT PENSIONER, may elect to have the applicable normal form of PENSION paid as a JOINT PENSION by giving the EM- PLOYER at least 30 days' advance written notice prior to the PARTICIPANT'S ACTUAL RETIREMENT DATE. -6- 9 If such an election is made, the PARTICIPANT will receive a reduced BASIC or EARLY RETIREMENT PENSION for life and, upon the PARTICIPANT'S death, the non-spouse JOINT PENSIONER designated by the PARTICIPANT will receive that proportion of such reduced PENSION, up to 100 percent, which the PARTICIPANT has elected, for the remainder of the JOINT PENSIONER'S life. Non-spouse JOINT PENSIONS shall be determined in accor- dance with an actuarial formula which is set forth in Special Provision C. (b) Joint Pension With Spouse For a PARTICIPANT who is married on the ACTUAL RETIRE- MENT DATE, the normal form of PENSION shall be a MARI- TAL PENSION, reducing the amount of the PARTICIPANT'S BASIC PENSION and providing that on the PARTICIPANT'S death one-half of such MARITAL PENSION will be contin- ued to the SPOUSE for the remainder of the SPOUSE'S life. In lieu of the MARITAL PENSION, a married PARTICIPANT, by making a QUALIFIED ELECTION prior to ACTUAL RETIRE- MENT DATE, may elect one of the following options: (1) a JOINT PENSION with SPOUSE which provides that an amount equal to either 25, 75 or 100 percent of a reduced BASIC or EARLY RETIREMENT PENSION will, upon the PARTICIPANT'S death, be continued for the remainder of the SPOUSE'S life, or (2) a SPECIAL JOINT PENSION with SPOUSE which provides an amount of one-half or 100 percent of a reduced BASIC or EARLY RETIREMENT PENSION that, upon the PARTICIPANT'S death, will be continued for the remainder of the SPOUSE'S life. However, if the SPOUSE predeceases the PARTICIPANT, future PENSION payments will be restored to the amount of the full BASIC or EARLY RETIREMENT PENSION that the PARTICIPANT would be entitled to receive if no SPECIAL JOINT PENSION with SPOUSE had been elect- ed. MARITAL PENSIONS and JOINT PENSIONS with SPOUSE shall be determined in accordance with an actuarial formula which is set forth in Special Provision D. Special Provision D also includes tables of factors which apply to typical options which may be elected. SPECIAL JOINT PENSIONS with SPOUSE shall also be deter- mined in accordance with the actuarial formula which is set forth in Special Provision D, but actuarially adjusted further to reflect the value of the restora- tion feature. Provision D also includes tables of the factors which apply to SPECIAL JOINT PENSION options that may be elected. (c) Basic or Early Retirement Pension Terminating Upon The Death Of The Participant Under this option, no additional PENSION payments are made to anyone after the PARTICIPANT'S death. (d) Conditions Applicable To All Forms Of Pensions The CONSENT of the SPOUSE is required whenever a QUALI- FIED ELECTION is made which would provide benefits to a surviving SPOUSE less than those provided by a MARITAL PENSION. -7- 10 The SPOUSE of a PARTICIPANT may not receive a benefit under any provisions of this Section if a larger SPOUSE'S PENSION is payable under Section 11. 11. Spouse's Pension (a) If a married PARTICIPANT dies while employed by an EMPLOYER and prior to the ACTUAL RETIREMENT DATE, or within 30 days thereafter, the PARTICIPANT's surviving SPOUSE will be eligible to receive a SPOUSE's PENSION if, at the time of the PARTICIPANT'S death, (i) the PARTICIPANT was at least 55 years of age, or (ii) the sum of the PARTICIPANT's age and years of SERVICE equaled 70 or more. (69.5 or more is rounded to 70.) The amount of the SPOUSE's PENSION is one-half of the PENSION that the PARTICIPANT would have been entitled to receive, and will be calculated as if: (1) the PARTICIPANT had elected a BASIC PENSION under Section 10(b)(3), (2) the first day of the month following the PARTICIPANT's death had been the PARTICIPANT's ACTUAL RETIREMENT DATE, and (3) The PARTICIPANT had in fact retired on that date without reduction for early retirement. However, if the SPOUSE is more than 10 years younger than the PARTICIPANT, the amount of the SPOUSE's PEN- SION shall be reduced 1/20th of one percent for each full month in excess of 120 months' differ- ence in their ages, except that such reduction shall not result in a SPOUSE's PENSION lower than would have been payable if the PARTICIPANT had retired as of the date of death and elected an optional form providing for continuation of 50 percent to a named JOINT PENSIONER with SPOUSE the same sex and age of the SPOUSE, under the provisions of Section 10(b)(1). The SPOUSE's PENSION is payable to the PARTICIPANT's surviving SPOUSE on the first day of the month following the PARTICIPANT's death and the first day of each month thereafter so long as the SPOUSE lives. (b) The surviving SPOUSE of a PARTICIPANT or of a former EMPLOYEE who dies prior to actual retirement date shall be entitled to receive a SPOUSE's PENSION under this Section 11(b) if, at the time of the death of the PARTICIPANT or former EMPLOYEE, (i) the PARTICIPANT or former EMPLOYEE had at least five years of SERVICE, and (ii) the surviving SPOUSE does not qualify for a SPOUSE's PENSION under Section 11(a), above. A SPOUSE's PENSION under this Section 11(b) shall be payable on the first day of the month following the later of (i) the date of death or (ii) the month in which the deceased PARTICIPANT or former EMPLOYEE would have attained his 55th birthday. By submitting an election form to the PLAN ADMINISTRATOR, a SPOUSE may elect to begin receiving a SPOUSE's PENSION at a speci- fied later date. Unless a vested PARTICIPANT or vested former EMPLOYEE and his or her SPOUSE have elected otherwise pursuant to a QUALIFIED ELECTION, if a PARTICIPANT dies on or before age 55, the PARTICIPANT'S or FORMER EMPLOYEE'S surviving SPOUSE (if any) will receive the same benefit that would have been payable if the PARTICIPANT or former EMPLOYEE had: -8- 11 (1) separated from SERVICE on the date of death (or date of separation from SERVICE, if earlier), (2) survived to age 55, (3) retired with a MARITAL PENSION at age 55, (4) died on the day of retirement, and begun to re- ceive benefit payments at the date as of which the PARTICIPANT or former EMPLOYEE would have attained age 55. Unless a surviving SPOUSE elects otherwise, the surviv- ing SPOUSE will begin to receive payments at the date as of which the PARTICIPANT or former EMPLOYEE would have attained age 55. Benefits commencing after this date will be the ACTUARIAL EQUIVALENT of the benefit to which the surviving SPOUSE would have been entitled if benefits had commenced at this date. A PARTICIPANT's SPOUSE may not receive both a SPOUSE's PENSION under this Section and a MARITAL or JOINT PENSION under Section 10. If the PARTICIPANT dies within 30 days after the PARTICIPANT's ACTUAL RETIREMENT DATE, the SPOUSE will receive the larger of the monthly Pensions under this Section and Section 3.10, but not both. 12. Withdrawal of Participant Contributions on Termination of Employment A PARTICIPANT's contributions to the PLAN may not be withdrawn prior to ACTUAL RETIREMENT DATE or other termina- tion of SERVICE. After a PARTICIPANT's SERVICE is terminat- ed, the PARTICIPANT, by written notice to the PARTICIPANT's EMPLOYER at least 30 days before the date the PENSION be- gins, may elect to have such CONTRIBUTIONS PLUS INTEREST returned. If a PARTICIPANT elects to withdraw such CONTRIBUTIONS PLUS INTEREST, the PENSION the PARTICIPANT would otherwise be entitled to at the NORMAL or EARLY RETIREMENT DATE shall be reduced by an amount that reflects the actuarial value of the contributions withdrawn. The factors used to reduce the PENSION of a PARTICIPANT who has withdrawn his contributions shall comply with CODE Sections 411(a)(7)(D) and 411(c)(2)(B) and are contained in the table set forth in Special Provision I. 13. Death Benefits If a PARTICIPANT with contributions on deposit in the PLAN dies before receiving payments from the PLAN equal to the amount of the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST, the difference between the payments made and the CONTRIBU- TIONS PLUS INTEREST will be paid to the named BENEFICIARY, unless a PENSION is payable to the PARTICIPANT's surviving SPOUSE or JOINT PENSIONER. If a PENSION is payable after such PARTICIPANT's death, and if upon the death of the SPOUSE or JOINT PENSIONER the total combined amount paid to the PARTICIPANT and the SPOUSE or JOINT PENSIONER does not equal the amount of the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST, the difference between the total amount paid and the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST will be paid to the BENEFICIARY of the SPOUSE or JOINT PENSIONER. 14. Facility of Payment (a) If the present value of all PENSION benefits payable under the PLAN to any individual is less than $3,500.00 as of the date of SEVERANCE FROM SERVICE or ACTUAL RETIREMENT DATE, the equivalent value shall be paid in a lump sum, as directed by the ADMINISTRATOR. For -9- 12 PARTICIPANTS terminating before age 55, present value means the ACTUARIAL EQUIVALENT of the normal retirement benefit commencing at NORMAL RETIREMENT DATE. For PARTICIPANTS retiring at or after age 55, present value means the ACTUAR- IAL EQUIVALENT of the early, normal or deferred retirement benefit commencing at ACTUAL RETIREMENT DATE. In determin- ing the present value, the PLAN ADMINISTRATOR shall use the Unisex Mortality Table for 1984 (UP-84) and the interest rates set, as of the first day of the PLAN YEAR in which the lump sum payment is made, by the Pension Benefit Guaranty Corporation for the purpose of determining the present value of a lump sum distribution on PLAN termination. (b) If the ADMINISTRATOR determines that any individu- al entitled to any payment under the PLAN is physically or mentally incompetent to handle the payment and no guardian or conservator has been appointed to receive such payment, the ADMINISTRATOR may cause all payments thereafter becoming due to such individual to be applied for and on behalf of and for the benefit of such individual. Payments made pursuant to this provision shall completely discharge the EMPLOYER, the ADMINISTRATOR, the Trustee, and all fiducia- ries of all further responsibility with respect to such individual. (c) If the distributee of any eligible rollover dis- tribution (as defined below) elects to have the distribution paid directly to an eligible retirement plan (as defined below), and if the distributee specified, according to the manner specified by the PLAN, the eligible retirement plan to which such distribution is to be paid, then the distribu- tion shall be made in the form of a direct trustee-to-trust- ee transfer to the eligible retirement plan specified by the distributee. The trustee-to-trustee transfer shall be made available only if the distribution from the PLAN would be subject to federal income taxation. The term "eligible rollover distribution" shall mean any distribution to a PARTICIPANT or former EMPLOYEE of all or part of the balance to the credit of the PARTICIPANT or former EMPLOYEE in the PLAN. The term shall not, however, include any distribution which is one of a series of "sub- stantially equal periodic payments" (as defined at CODE Section 402(c)(4)(A), or any distribution that is required under CODE Section 401(a)(9). The term "eligible retirement plan" means an individual retirement account described in CODE Section 408(a), an individual retirement annuity described in CODE Section 408(b) (other than an endowment contract), an annuity plan described in CODE Section 403(a), or a qualified defined contribution plan, the terms of which permit the acceptance of rollover distributions. 15. Benefits Are Not Assignable Except as may be required by law, a PARTICIPANT's interest in the PLAN, either before or after retirement, and that of a PARTICIPANT's SPOUSE, JOINT PENSIONER, or BENEFI- CIARY shall not be subject to assignment, anticipation, sale, transfer, pledge, encumbrance, or charge, whether voluntary or involuntary, and any attempt to so assign, anticipate, sell, transfer, pledge, encumber, or charge shall be void. 16. Employer Contributions The COMPANY shall contribute to the PLAN such amount of EMPLOYER CONTRIBUTIONS as the EMPLOYEE BENEFIT FINANCE COMMITTEE, with the advice of the actuary, shall determine is necessary to keep the PLAN funded in accordance with the Funding Policy and to satisfy any minimum funding standard required by the Internal Revenue SERVICE or the Department of Labor. The EMPLOYEE BENEFIT FINANCE COMMITTEE shall determine and -10- 13 charge to each EMPLOYER its share of the EMPLOYER contribu- tions made by the COMPANY. 17. Company's Powers and Duties The COMPANY, acting through its Board of Directors or Executive Committee, reserves to itself the exclusive power to amend, suspend, or terminate the PLAN as provided below and to appoint and remove from time to time: (a) The individuals comprising the EMPLOYEE BENEFIT FINANCE COMMITTEE; (b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE; (c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN. (d) Except as provided in Section 20, the appropriate committees established by the COMPANY shall serve as the final review committees, under the PLAN, to determine con- clusively for all parties any and all questions arising from the administration of the PLAN and shall have sole and complete discretionary authority and control to manage the operation and administration of the PLAN, including, but not limited to, the determination of all questions relating to eligibility for participation and benefits, interpretation of all PLAN provisions, determination of the amount and kind of benefits payable to any PARTICIPANT, SPOUSE or beneficia- ry, and construction of disputed or doubtful terms. Such decisions shall be conclusive and binding on all parties and not subject to further review. All powers and duties not reserved to the COMPANY are delegated to the EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of a majority of the members of the committee at a meeting, or in writing without a meeting, and evidenced by the signature of any member who is so authorized by the committee. The COMPANY indemnifies each member of each committee against any personal liability or expense arising out of any action or inaction of the committee or of any member of the committee or of such individual, except that due to his own willful misconduct. 18. Funding and Investment Provisions The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY's Board of Directors to serve at its pleasure has the express powers and duties described in this Section. (a) Appointments. The EMPLOYEE BENEFIT FINANCE COM- MITTEE has the sole power and duty from time to time to appoint and remove the Funding Agents, the Investment Manag- er, actuaries, accountants, and such other advisors and consultants as may be needed for the proper financial admin- istration and investment of the assets of the PLAN. Supple- menting such appointments, the EMPLOYEE BENEFIT FINANCE COMMITTEE may enter into appropriate agreements with each Trustee, Investment Manager or other advisors appointed under this paragraph and delegate to them appropriate powers and duties. The EMPLOYEE BENEFIT FINANCE COMMITTEE may appoint and delegate to one or more individuals the power and duty to handle the day-to-day financial administration of the PLAN. Such individuals need not be members of the committee and shall serve at the pleasure of the committee. -11- 14 (b) Funding Policy. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole power and duty to establish a funding policy and an investment policy and to review and revise it from time to time as the committee shall determine in its sole discretion. All EMPLOYER contributions to the PLAN shall be paid to Funding Agents which may be one or more insurance companies or corporate trustees, or to any combi- nation thereof, as the EMPLOYEE BENEFIT FINANCE COMMITTEE may determine from time to time. These contributions, and all previous contributions of PARTICIPANTS and EMPLOYERS, together with the proceeds of their investment, shall be held and administered by these Funding Agents pursuant to the agreements between the COMPANY and the Funding Agents. All of the PLAN'S assets held by Funding Agents are avail- able to pay benefits on behalf of all PARTICIPANTS covered by this PLAN. 19. Administration The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appoint- ed by the COMPANY's Board of Directors to serve at its pleasure, is the ADMINISTRATOR of the PLAN and is responsi- ble for the overall administration of the PLAN. The ADMIN- ISTRATOR has the sole power and duty to establish, and from time to time revise, such rules and regulations as may be necessary to administer the PLAN in a nondiscriminatory manner for the exclusive benefit of PARTICIPANTS and all other persons entitled to benefits under the PLAN. The ADMINISTRATOR shall also maintain such records and make such computations, interpretations, and decisions as may be necessary or desirable for the proper administration of the PLAN. The ADMINISTRATOR may demand such proof of age of any PARTICIPANT, JOINT PENSIONER, or SPOUSE as it consid- ers necessary, and it may adjust any PENSION or other pay- ment or payments thereafter due under the PLAN as it deems appropriate and equitable to correct any factual error or misrepresentation. The ADMINISTRATOR shall maintain for PARTICIPANTS' inspection copies of the PLAN, trust agree- ment, investment policy, each agreement with an Investment Manager, the latest annual report, PLAN description, and summary description, and any amendments or changes in any of these documents. On written request, PARTICIPANTS may obtain from the ADMINISTRATOR a copy of any of these docu- ments at a cost established by the ADMINISTRATOR from time to time. All expenses of administration may be paid out of the PLAN's assets upon authorization by the appropriate commit- tee, unless paid by the COMPANY. Such expenses shall in- clude any expenses incident to the functioning of the ADMIN- ISTRATOR, including, but not limited to, fees for accoun- tants, actuaries, counsel, investment managers and other specialists and their agents, and other costs of administer- ing the PLAN. 20. Claims Procedure If a claim is denied in whole or in part, the ADMINIS- TRATOR shall furnish to the claimant a written notice set- ting forth: (a) Specific reason(s) for the denial, (b) The PLAN provision(s) on which the denial is based, (c) A description of any material or information, if any, necessary for the claimant to perfect the claim, and an explanation of why such material or information is neces- sary, and (d) Information concerning the steps to be taken if claimant wishes to submit a claim for review. -12- 15 The above information shall be furnished to the claimant within 90 days after the claim is received by the ADMINIS- TRATOR. If a claimant is not satisfied with the written notice described in the preceding paragraph, such claimant may request a full and fair review by so notifying the ADMINIS- TRATOR in writing within 90 days after receiving such no- tice. If a review is requested the claimant shall also be entitled, upon written request, to review pertinent docu- ments and to submit issues and comments in writing. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall furnish the claimant with a written final decision within 60 days after receipt of the request for review. 21. Qualified Domestic Relations Orders The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall apply the provisions of this section with regard to a Domestic Relations Order (as defined below) to the extent not incon- sistent with Section 414(p) of the CODE. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall estab- lish procedures, consistent with Section 414(p) of the CODE, to determine the qualified status of any Domestic Relations Order, to administer distributions under any Qualified Domestic Relations Order (as defined below), and to provide to the PARTICIPANT and the Alternate Payee(s) (as defined below) all notices required under Section 414(p) of the CODE with respect to any Domestic Relations Order. Within a reasonable period of time after the receipt of a Domestic Relations Order (or any modification thereof), the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall determine whether such order is a Qualified Domestic Relations Order. For purposes of this section: (a) Alternate Payee shall mean any SPOUSE, former SPOUSE, child, or other dependent of a PARTICIPANT who is recognized by a Domestic Relations Order as having a right to receive all, or a portion of, the benefits payable under the PLAN with respect to such PARTICI- PANT. (b) Domestic Relations Order shall mean any judgment, decree, or order (including approval of a property settlement) which: (1) relates to the provision of child support, alimony payments, or marital property rights to a SPOUSE, former SPOUSE, child, or other dependent of a PARTICIPANT; and (2) is made pursuant to a state domestic relations law (including a community property law). (c) Qualified Domestic Relations Order shall mean a Domes- tic Relations Order which meets the requirements of Section 414(p)(1) of the CODE. 22. Amendment, Termination, and Merger The COMPANY hopes and expects to continue this PLAN indefinitely but, because future conditions cannot be fore- seen, its Board of Directors necessarily reserves the right to change, suspend, or terminate the PLAN at any time. However, no change can be made which would adversely affect the rights which any PARTICIPANT, retired EMPLOYEE, former EMPLOYEE, SPOUSE, JOINT PENSIONER, or BENEFICIARY may then have with respect to funds then being held under the PLAN by any Funding Agent or permit any such funds to revert to an EMPLOYER or be used for any -13- 16 purpose except for the exclusive benefit of PARTICIPANTS, Pensioners, and their SPOUSES, JOINT PENSIONERS, and BENEFI- CIARIES. In the event the PLAN is partially terminated, termi- nated or suspended, all EMPLOYER contributions with respect to the affected PARTICIPANTS shall cease and the accrued benefits of the affected PARTICIPANTS shall become nonfor- feitable. Subject to applicable requirements of notice to the Pension Benefit Guaranty Corporation governing termina- tion of PENSION benefit plans, the funds held under the PLAN by the Funding Agents shall be applied to provide the PEN- SIONS, benefits and refunds accrued to the date of termina- tion or suspension and to the extent funded. Such provision shall be made in such manner as the ADMINISTRATOR shall direct, including the purchase of paid-up annuities, distri- bution in installments, or lump-sum distributions and shall be in conformance with the requirements and priorities established by various governmental agencies to oversee PLAN suspensions and terminations. Notwithstanding any contrary provisions of the PLAN, after its termination and after all liabilities for the payment of PENSIONS, benefits and re- funds to the date of termination have been satisfied or provided for in accordance with the foregoing, any funds remaining with the Funding Agents shall be returned to the COMPANY. This PLAN shall not be merged into or consolidated with any other PLAN, nor shall any of its assets or liabilities be transferred to any other PLAN, unless each PARTICIPANT in this PLAN would (if such other PLAN then terminated) receive a benefit immediately after the merger, consolidation, or transfer which is equal to or greater than the benefit such PARTICIPANT would have been entitled to receive immediately before the merger, consolidation, or transfer (if this PLAN had then terminated). 23. Definitions and Cross-References Actual Retirement Date: The date of one of the following, whichever is applicable: (a) The date on which an EARLY RETIREMENT PENSION begins, or (b) The PARTICIPANT's Normal Retirement Date, or (c) If the PARTICIPANT continues in the employ of an EMPLOYER beyond Normal Retirement Date, the first day of the month following termination of SERVICE. Actuarial Equivalent or For purposes of determining actuarially Actuarial Equivalence: equivalent benefits under this PLAN, the provisions of Special Provision D shall apply. Administrator: The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE referred to in Section 20, 201 Mission Street, 19th Floor, Mail Code P19A, P.O. Box 770000, San Francisco, California 94177. Basic Monthly Salary: The rate of pay used to calculate the monthly earnings from an EMPLOYER, adjusted to reflect nuclear premium payments, if
-14- 17 any, but excluding payments from the LONG TERM DISABILITY PLAN and all other bonuses, premiums, special allowances, overtime pay, or any other payments. For a PARTICIPANT who is paid weekly or bi-weekly, BASIC MONTHLY SALARY shall be equal to the PARTICIPANT'S weekly pay rate multiplied by 4.33, rounded up to the nearest Five Dollars. For purposes of calculating a PARTICIPANT'S accrued benefit under this PLAN, the compensation limitations of CODE Section 401(a)(17) shall be applicable. For purposes of calculating accruals after December 31, 1993, the amount of a PARTICIPANT'S compensation taken into account shall not exceed $150,000, or such greater amount permitted by the Secretary of the Treasury. For purposes of calculating accruals after December 31, 1988, and before January 1, 1994, the amount of compensation taken into account shall not exceed $200,000, or such greater amount permitted by the Secretary of the Treasury. Unless otherwise provided under this PLAN, each CODE Section 401(a)(17) employee's accrued benefit under this PLAN will be the greater of the accrued benefit determined for the employee under 1 or 2 below: 1. The employee's accrued benefit determined with respect to the benefit formula applicable for the PLAN YEAR beginning on or after January 1, 1994, as applied to the employee's total years of SERVICE taken into account under the PLAN for the purposes of benefit accruals, or 2. The sum of: (a) the employee's accrued benefit as of the last day of the last PLAN YEAR beginning before January 1, 1994, frozen in accordance with CODE Section 1.401(a)(4)-13, and (b) the employee's accrued benefit determined under the benefit formula applicable for the PLAN YEAR beginning on or after January 1, 1994, as applied to the employee's years of service credited to the employee for PLAN YEARS beginning on or after January 1, 1994, for purposes of benefit accruals.
-15- 18 A CODE Section 401(a)(17) employee means an employee whose current accrued benefit as of a date on or after the first day of the first PLAN YEAR beginning on or after January 1, 1994, is based on compensation for a year beginning prior to the first day of the first PLAN YEAR beginning on or after January 1, 1994, that exceeded $150,000. Basic Pension: The PENSION due at the later of NORMAL RETIREMENT DATE or ACTUAL RETIREMENT DATE and unreduced because of marital status. See Sections 6 and 10b. Beneficiary: The individual or individuals or inter-vivos trust or trusts that a PARTICIPANT, SPOUSE, or JOINT PENSIONER designates to receive any death benefits due pursuant to Section 13. Such designation must be made on forms pro- vided by the EMPLOYER and filed with the ADMINISTRATOR. A PARTICIPANT, or the PARTICIPANT's SPOUSE (if receiving a SPOUSE's PENSION), or the PARTICIPANT's JOINT PENSIONER (if receiving a Joint PENSION), may change the designated Beneficiary from time to time by filing an appropriate written notice with the ADMINISTRATOR. In the absence of a designation, the Beneficiary shall be the estate of the person entitled to make the designation. There were no employee contributions after December 31, 1972. Therefore, EMPLOYEES who first became Participants in the PLAN after said date were not required or permitted to name a Beneficiary. Break in Service: A BREAK IN SERVICE occurs 12 months after the SEVERANCE FROM SERVICE DATE if during such 12-month period an EMPLOYEE does not work for an EMPLOYER. Once a Break in Service occurs, it continues until an EMPLOYEE is reemployed by an EMPLOYER. Code: CODE shall mean the Internal Revenue CODE of 1986, as amended from time to time. Company: Pacific Gas and Electric Company. Consent: The CONSENT by a SPOUSE that is required for a QUALIFIED ELECTION. Any such CONSENT shall be effective only with respect to such SPOUSE. A CONSENT permitting desig- nation by the PARTICIPANT without further CONSENT from the SPOUSE must acknowledge that the SPOUSE has the right to limit CONSENT to a specific BENEFICIARY and also to a specific benefit form, and that the SPOUSE voluntarily elects to relinquish either or both of such rights. A revocation of a prior QUALIFIED ELECTION be made by a PARTICIPANT without the CONSENT of the SPOUSE at any time prior to
-16- 19 the commencement of benefits. An unlimited number of revocations shall be permitted. No CONSENT obtained under this provision shall be valid unless the PARTICIPANT has received proper NOTICE. Contributions Plus Interest: The cumulative total of contributions made by a PARTICIPANT to the PLAN under Section 13; paragraph (b) of Special Provision F; and to the COMPANY's Retirement PLAN as it existed before 1969, plus interest at two percent per year on a PARTICIPANT's contributions made after 1953, compounded annually to 1976, together with interest at five percent compounded annually after 1975 on all contributions and previous interest. Credited Service: See Special Provision F. Early Retirement Date: See Section 7. Early Retirement Pension: See Section 7. Employee: An EMPLOYEE of an EMPLOYER who is not covered by a collective bargaining agree- ment. A "leased employee," as defined in Section 414(n) of the CODE, shall not be considered an EMPLOYEE eligible to become a PARTICIPANT in the PLAN. Notwithstanding any other provisions in the PLAN, solely for purposes of CODE Section 414(n)(3), the term EMPLOYEE shall, to the extent required by CODE Section 414, include leased EMPLOYEES. Employee Benefit Administrative Committee: The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE referred to in Section 19. The Employee Benefit Finance Committee: The EMPLOYEE BENEFIT FINANCE COMMITTEE referred to in Section 18. Employer: Pacific Gas and Electric Company, Pacific Gas Transmission Company, Pacific Service Employees Association, and any other company, association, or credit union designated by the Board of Directors as eligible to participate in this PLAN is an EMPLOYER. Joint Pension: See Section 10. Joint Pensioner: The individual designated by a PARTICIPANT upon the election of a JOINT PENSION who will be entitled upon the PARTICIPANT's death to receive a PENSION, as explained in Section 10. Long Term Disability Plan: Part B of the Pacific Gas and Electric Company's Group Life Insurance and Long Term Disability Plan.
-17- 20 Marital Pension: See Section 10(b). Maximum Pension: See Special Provision H. Normal Retirement Date: The first of the month following the PARTI- CIPANT's 65th birthday. Notice: The NOTICE that is required by this PLAN pursuant to CODE Section 417 in order to waive the MARITAL PENSION. In the case of MARITAL PENSION, the PLAN shall provide to each PARTICIPANT, and to each vested former EMPLOYEE, no less than 30 days and no more than 90 days prior to the annuity starting date a written expla- nation of: (i) the terms and conditions of the MARITAL PENSION, (ii) the right to make and the effect of an election to waive the MARITAL PENSION, (iii) the rights of the PARTICIPANT'S or the former EMPLOYEE'S SPOUSE, (iv) the right to make an election to waive the MARITAL PENSION and the effect of revoking a previous election to waive the MARITAL PENSION, and (v) the relative values of the various optional forms of benefit under the PLAN. Participant: See Section 2. Part-Time Employee: An EMPLOYEE whose regularly scheduled work week is less than 40 hours. Pension: Retirement income payable under the PLAN. Plan: The Company's Retirement Plan as amended, revised and set forth herein. Plan Year: The PLAN YEAR shall be the calendar year which shall also be the limitation year for purposes of applying the annual benefit limitations of CODE Section 415. Qualified Election: An election qualifying under CODE Section 417(a) to waive either, or both, of the 50 percent spousal survivor annuities that are based on the MARITAL PENSION and that are described in Sections 10(b) or 11(b) of the PLAN. Any such waiver shall not be consi- dered a QUALIFIED ELECTION unless: (a) the PARTICIPANT'S SPOUSE furnishes written CONSENT to the election, (b) the election designates a specific alternate BENEFICIARY, including any class of BENEFICIARIES or any contingent BENEFICIARIES, which may not be changed without spousal CONSENT (or the SPOUSE expressly permits designations by the PARTICIPANT without any further spousal CONSENT, (c) the SPOUSE'S CONSENT acknow- ledges the effect of the election, and (d) the SPOUSE'S CONSENT is witnessed by a PLAN representative or a notary public. A PARTICIPANT'S
-18- 21 waiver of the survivor annuity will not constitute a QUALIFIED ELECTION unless the form of benefit payment may not be changed without spousal CONSENT, or the SPOUSE expressly permits designations by the PARTICIPANT without any further spousal CONSENT. If it is established to the satis- faction of the PLAN representative that such written CONSENT may not be obtained because there is no SPOUSE or the SPOUSE cannot be located, then a waiver will be deemed a QUALIFIED ELECTION. Service: For full-time EMPLOYEES, the period of time commencing with the first day of work for an EMPLOYER and ending on PARTICIPANT's SEVERANCE FROM SERVICE Date. For periods of PART-TIME and intermittent employment, SERVICE for purposes of benefit accrual is prorated based on the ratio of actual hours worked in the calendar year to the full-time equivalent (2,080 per calendar year) rounded to the nearest month. Such proration is applicable for any employment period beginning with initiation of PART-TIME or intermittent status on or after January 1, 1991, and ending on the earlier of Partici- pant's return to full time status or the PARTICIPANT'S SEVERANCE FROM SERVICE DATE. The method of computing SERVICE is described in Section 3. Severance from Service Date: (i) The date prior to NORMAL RETIREMENT DATE on which an EMPLOYEE quits, retires, is discharged or dies, or the ACTUAL RETIREMENT DATE; or (ii) The first anniversary of the first date of a period in which a PARTICIPANT remains absent from work for an EMPLOYER for any reason other than a quit, retirement, discharge, or death. For the purpose of determining the Severance from SERVICE Date, the following periods shall not be considered as absences from work for an EMPLOYER: (a) Absence on a leave of absence authorized by an EMPLOYER. (b) Absence because of illness or injury as long as the PARTICIPANT is enti- tled to receive sick leave pay or is entitled to receive benefits under the provisions of the Voluntary Wage Benefit Plan, a state disability plan, Part B of the Group Life Insurance and Long Term Disability Plan, or a Workers' Compensation Law.
-19- 22 (c) Absence for military service or service in the Merchant Marines so long as reemployment rights are pro- tected by law. (d) Absence caused by layoff for lack of work of less than 12 continuous months for a PARTICIPANT who has less than five years of SERVICE, or 24 continuous months for a PARTICIPANT who has five years or more of SERVICE. Special Joint Pension: See Section 10. Spouse: (a) If a PARTICIPANT dies in SERVICE, SPOUSE shall mean the PARTICIPANT's wife or husband at the time of the PARTICIPANT's death. (b) If a PARTICIPANT dies after ACTUAL RETIREMENT DATE, SPOUSE shall mean the PARTICIPANT's wife or husband at the time of the PARTICIPANT's Actual Retirement. Spouse's Pension: See Section 11.
-20- 23 SPECIAL PROVISION A Payment of all PENSIONS to PARTICIPANTS which commenced before January 1, 1969, under the Retirement Plan of the COMPANY, its Past Service Plan, its Supplemental Benefits and under any applicable retirement plan of a predecessor company shall continue to be made under the PLAN, without regard to the separate sources from which such pensions were previously paid. SPECIAL PROVISION B EARLY RETIREMENT REDUCTIONS IN PERCENTAGE POINTS Years Of Service At Early Retirement Date
Age at Less Than 15 But Less 25 But Less 30 Years Retirement 15 Years Than 25 Years Than 30 Years And Above ---------- --------- ------------- ------------- --------- 64 3 0 0 0 63 6 0 0 0 62 9 0 0 0 61 12 3 3 0 60 15 6 6 0 59 18 10 9 6 58 21 14 12 9 57 24 18 15 12 56 27 22 18 15 55 30 26 21 18
-21- 24 SPECIAL PROVISION C JOINT PENSION WITH NON-SPOUSE (Entire Provision Amended 1/1/88) The amount of non-spouse JOINT PENSION shall be determined by the use of Actuarial Tables which provide 12%, 16%, 25%, 33-1/3%, 50%, 66-2/3%, 75% and 100% of the JOINT PENSION to a non-spouse JOINT PENSIONER who survives the death of the PARTICIPANT. Partial Actuarial Tables of 50% and 100% have been attached. The following tables illustrate the factors to be applied for typical options which may be elected for 50% and 100%. EXAMPLE: Assume the PARTICIPANT is age 62 and elects a 50% or 100% option with a non-spouse age 50. Also assume that the PARTICIPANT's BASIC PENSION is $1,000 per month.
Non- Non- Non-Spouse's Pension Spouse's Option Basic Reduced Spouse's In Event of Option Factor Pension Pension Portion Participant's Death - -------- ------ ------- ------- -------- -------------------- 50% .861 X $1,000. = $861. X .50 = $430.50 100% .756 X $1,000. = $756. X 1.00 = $756.00
Tables for 12%, 16%, 33-1/3%, 66-2/3%, or 75% are available upon request. Tables for Beneficiary's Age at Pensioner's Retirement of less than 25 years or greater than 84 years are also available upon request. -22- 25 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 25 .844 .836 .827 .817 .807 .797 .786 .775 .763 .751 .738 .725 .711 .697 .682 .667 25 26 .847 .838 .829 .819 .809 .799 .788 .777 .765 .753 .740 .727 .713 .699 .684 .669 26 27 .849 .840 .831 .821 .811 .801 .790 .779 .767 .755 .742 .729 .715 .701 .686 .671 27 28 .851 .842 .833 .824 .814 .803 .793 .781 .769 .757 .745 .731 .718 .703 .689 .674 28 29 .853 .844 .835 .826 .816 .806 .795 .784 .772 .760 .747 .734 .720 .706 .691 .676 29 30 .855 .847 .838 .828 .818 .808 .797 .786 .774 .762 .750 .736 .723 .708 .694 .679 30 31 .858 .849 .840 .831 .821 .811 .800 .789 .777 .765 .752 .739 .725 .711 .696 .681 31 32 .860 .852 .843 .833 .824 .813 .803 .792 .780 .768 .755 .742 .728 .714 .699 .684 32 33 .863 .854 .846 .836 .826 .816 .806 .794 .783 .771 .758 .745 .731 .717 .702 .687 33 34 .866 .857 .848 .839 .829 .819 .809 .797 .786 .774 .761 .748 .734 .720 .705 .690 34 35 .868 .860 .851 .842 .832 .822 .812 .801 .789 .777 .764 .751 .737 .723 .708 .693 35 36 .871 .863 .854 .845 .835 .825 .815 .804 .792 .780 .768 .754 .741 .727 .712 .697 36 37 .874 .866 .857 .848 .839 .829 .818 .807 .796 .784 .771 .758 .744 .730 .715 .700 37 38 .877 .869 .860 .851 .842 .832 .821 .811 .799 .787 .775 .761 .748 .734 .719 .704 38 39 .880 .872 .864 .855 .845 .835 .825 .814 .803 .791 .778 .765 .752 .737 .723 .708 39 40 .884 .875 .867 .858 .849 .839 .829 .818 .806 .795 .782 .769 .756 .741 .727 .712 40 41 .887 .879 .870 .862 .852 .843 .832 .822 .810 .798 .786 .773 .760 .746 .731 .716 41 42 .890 .882 .874 .865 .856 .846 .836 .826 .814 .803 .790 .777 .764 .750 .735 .720 42 43 .893 .886 .877 .869 .860 .850 .840 .830 .818 .807 .794 .782 .768 .754 .740 .725 43 44 .897 .889 .881 .873 .864 .854 .844 .834 .823 .811 .799 .786 .773 .759 .744 .729 44 45 .900 .893 .885 .876 .868 .858 .848 .838 .827 .816 .803 .791 .777 .764 .749 .734 45 46 .904 .896 .889 .880 .872 .862 .853 .842 .832 .820 .808 .795 .782 .768 .754 .739 46 47 .907 .900 .892 .884 .876 .867 .857 .847 .836 .825 .813 .800 .787 .774 .759 .744 47 48 .911 .904 .896 .888 .880 .871 .861 .851 .841 .830 .818 .805 .792 .779 .764 .750 48 49 .914 .907 .900 .892 .884 .875 .866 .856 .846 .835 .823 .811 .798 .784 .770 .755 49
-23- 26 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 50 .918 .911 .904 .896 .888 .880 .870 .861 .850 .840 .828 .816 .803 .790 .775 .761 50 51 .921 .915 .908 .900 .892 .884 .875 .866 .855 .845 .833 .821 .808 .795 .781 .767 51 52 .925 .918 .912 .904 .897 .888 .880 .870 .860 .850 .839 .827 .814 .801 .787 .773 52 53 .928 .922 .916 .908 .901 .893 .884 .875 .865 .855 .844 .832 .820 .807 .793 .779 53 54 .932 .926 .919 .913 .905 .897 .889 .880 .870 .860 .849 .838 .826 .813 .799 .785 54 55 .935 .929 .923 .917 .909 .902 .894 .885 .876 .866 .855 .844 .832 .819 .806 .792 55 56 .938 .933 .927 .921 .914 .906 .898 .890 .881 .871 .861 .849 .838 .825 .812 .798 56 57 .942 .936 .931 .925 .918 .911 .903 .895 .886 .876 .866 .855 .844 .831 .819 .805 57 58 .945 .940 .934 .928 .922 .915 .908 .900 .891 .882 .872 .861 .850 .838 .825 .812 58 59 .948 .943 .938 .932 .926 .920 .912 .905 .896 .887 .878 .867 .856 .844 .832 .819 59 60 .951 .947 .942 .936 .930 .924 .917 .910 .902 .893 .883 .873 .863 .851 .839 .826 60 61 .954 .950 .945 .940 .934 .928 .922 .914 .907 .898 .889 .879 .869 .858 .846 .833 61 62 .957 .953 .948 .944 .938 .932 .926 .919 .912 .904 .895 .885 .875 .864 .853 .840 62 63 .960 .956 .952 .947 .942 .937 .931 .924 .917 .909 .901 .891 .882 .871 .860 .848 63 64 .963 .959 .955 .951 .946 .941 .935 .929 .922 .914 .906 .897 .888 .878 .867 .855 64 65 .965 .962 .958 .954 .949 .944 .939 .933 .927 .920 .912 .903 .894 .884 .874 .862 65 66 .968 .965 .961 .957 .953 .948 .943 .938 .931 .925 .917 .909 .900 .891 .881 .870 66 67 .970 .967 .964 .960 .956 .952 .947 .942 .936 .930 .923 .915 .907 .897 .888 .877 67 68 .972 .970 .967 .963 .960 .955 .951 .946 .940 .934 .928 .920 .913 .904 .894 .884 68 69 .975 .972 .969 .966 .963 .959 .955 .950 .945 .939 .933 .926 .918 .910 .901 .891 69 70 .977 .974 .972 .969 .966 .962 .958 .954 .949 .944 .938 .931 .924 .916 .908 .898 70 71 .979 .976 .974 .971 .968 .965 .961 .957 .953 .948 .942 .936 .930 .922 .914 .905 71 72 .980 .978 .976 .974 .971 .968 .965 .961 .957 .952 .947 .941 .935 .928 .920 .912 72 73 .982 .980 .978 .976 .973 .971 .968 .964 .960 .956 .951 .946 .940 .933 .926 .918 73 74 .984 .982 .980 .978 .976 .973 .970 .967 .964 .960 .955 .950 .945 .939 .932 .925 74
-24- 27 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 75 .985 .984 .982 .980 .978 .976 .973 .970 .967 .963 .959 .954 .949 .944 .937 .931 75 76 .987 .985 .984 .982 .980 .978 .976 .973 .970 .966 .963 .958 .954 .948 .943 .936 76 77 .988 .987 .985 .984 .982 .980 .978 .975 .973 .970 .966 .962 .958 .953 .948 .942 77 78 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .966 .962 .957 .952 .947 78 79 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .957 .952 79 80 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .956 80 81 .992 .991 .990 .989 .988 .987 .986 .984 .982 .980 .978 .975 .972 .969 .965 .961 81 82 .993 .992 .991 .991 .990 .988 .987 .986 .984 .982 .980 .978 .975 .972 .968 .964 82 83 .994 .993 .992 .992 .991 .990 .989 .987 .986 .984 .982 .980 .978 .975 .972 .968 83 84 .995 .994 .993 .993 .992 .991 .990 .989 .987 .986 .984 .982 .980 .978 .975 .972 84
28 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 25 .667 .652 .636 .620 .603 .586 .569 .551 .533 .515 .497 .479 .461 .442 .424 .406 25 26 .669 .654 .638 .622 .605 .588 .571 .553 .535 .517 .499 .481 .462 .444 .426 .407 26 27 .671 .656 .640 .624 .607 .590 .573 .555 .537 .519 .501 .483 .464 .446 .427 .409 27 28 .674 .658 .642 .626 .609 .592 .575 .557 .539 .521 .503 .485 .466 .448 .429 .411 28 29 .676 .661 .645 .628 .612 .595 .577 .560 .542 .524 .505 .487 .468 .450 .431 .413 29 30 .679 .663 .647 .631 .614 .597 .580 .562 .544 .526 .507 .489 .470 .452 .433 .414 30 31 .681 .666 .650 .633 .617 .600 .582 .564 .546 .528 .510 .491 .473 .454 .435 .417 31 32 .684 .669 .653 .636 .619 .602 .585 .567 .549 .531 .512 .494 .475 .456 .437 .419 32 33 .687 .671 .655 .639 .622 .605 .588 .570 .552 .533 .515 .496 .477 .459 .440 .421 33 34 .690 .675 .659 .642 .625 .608 .591 .573 .555 .536 .518 .499 .480 .461 .442 .423 34 35 .693 .678 .662 .645 .628 .611 .594 .576 .558 .539 .520 .502 .483 .464 .445 .426 35 36 .697 .681 .665 .649 .632 .614 .597 .579 .561 .542 .524 .505 .486 .467 .448 .429 36 37 .700 .685 .669 .652 .635 .618 .600 .582 .564 .545 .527 .508 .489 .470 .451 .431 37 38 .704 .688 .672 .656 .639 .621 .604 .586 .567 .549 .530 .511 .492 .473 .454 .434 38 39 .708 .692 .676 .659 .643 .625 .607 .589 .571 .552 .534 .515 .495 .476 .457 .438 39 40 .712 .696 .680 .663 .647 .629 .611 .593 .575 .556 .537 .518 .499 .480 .460 .441 40 41 .716 .700 .684 .668 .651 .633 .616 .597 .579 .560 .541 .522 .503 .483 .464 .444 41 42 .720 .705 .689 .672 .655 .638 .620 .602 .583 .564 .545 .526 .507 .487 .468 .448 42 43 .725 .709 .693 .677 .660 .642 .624 .606 .588 .569 .550 .530 .511 .491 .472 .452 43 44 .729 .714 .698 .681 .664 .647 .629 .611 .592 .573 .554 .535 .515 .495 .476 .456 44 45 .734 .719 .703 .686 .669 .652 .634 .616 .597 .578 .559 .539 .520 .500 .480 .460 45 46 .739 .724 .708 .691 .674 .657 .639 .621 .602 .583 .564 .544 .524 .505 .485 .465 46 47 .744 .729 .713 .697 .680 .662 .644 .626 .607 .588 .569 .549 .529 .509 .489 .469 47 48 .750 .734 .718 .702 .685 .668 .650 .631 .613 .594 .574 .554 .535 .515 .494 .474 48 49 .755 .740 .724 .708 .691 .673 .655 .637 .618 .599 .580 .560 .540 .520 .500 .479 49
-26- 29 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 50 .761 .746 .730 .713 .697 .679 .661 .643 .624 .605 .585 .566 .546 .525 .505 .485 50 51 .767 .752 .736 .720 .703 .685 .667 .649 .630 .611 .591 .572 .551 .531 .511 .490 51 52 .773 .758 .742 .726 .709 .692 .674 .655 .637 .617 .598 .578 .558 .537 .517 .496 52 53 .779 .764 .748 .732 .715 .698 .680 .662 .643 .624 .604 .584 .564 .543 .523 .502 53 54 .785 .770 .755 .739 .722 .705 .687 .669 .650 .631 .611 .591 .571 .550 .529 .508 54 55 .792 .777 .762 .746 .729 .712 .694 .676 .657 .638 .618 .598 .578 .557 .536 .515 55 56 .798 .784 .768 .753 .736 .719 .701 .683 .664 .645 .625 .605 .585 .564 .543 .522 56 57 .805 .790 .775 .760 .743 .726 .709 .691 .672 .653 .633 .613 .592 .571 .550 .529 57 58 .812 .798 .783 .767 .751 .734 .717 .699 .680 .661 .641 .621 .600 .579 .558 .537 58 59 .819 .805 .790 .775 .759 .742 .725 .707 .688 .669 .649 .629 .608 .587 .566 .545 59 60 .826 .812 .798 .783 .767 .750 .733 .715 .696 .677 .658 .638 .617 .596 .575 .553 60 61 .833 .820 .805 .790 .775 .758 .741 .724 .705 .686 .667 .646 .626 .605 .584 .562 61 62 .840 .827 .813 .799 .783 .767 .750 .733 .714 .695 .676 .656 .635 .614 .593 .571 62 63 .848 .835 .821 .807 .792 .776 .759 .742 .724 .705 .685 .665 .645 .624 .602 .581 63 64 .855 .843 .829 .815 .800 .785 .768 .751 .733 .715 .695 .675 .655 .634 .612 .591 64 65 .862 .850 .837 .824 .809 .794 .778 .761 .743 .725 .705 .686 .665 .644 .623 .601 65 66 .870 .858 .845 .832 .818 .803 .787 .770 .753 .735 .716 .696 .676 .655 .634 .612 66 67 .877 .866 .854 .841 .827 .812 .797 .780 .763 .745 .727 .707 .687 .666 .645 .623 67 68 .884 .873 .862 .849 .836 .821 .806 .790 .774 .756 .738 .718 .698 .678 .657 .635 68 69 .891 .881 .870 .858 .845 .831 .816 .801 .784 .767 .749 .730 .710 .690 .668 .647 69 70 .898 .888 .878 .866 .853 .840 .826 .811 .795 .778 .760 .741 .722 .702 .681 .659 70 71 .905 .896 .885 .874 .862 .849 .836 .821 .805 .789 .771 .753 .734 .714 .693 .672 71 72 .912 .903 .893 .882 .871 .859 .845 .831 .816 .800 .783 .765 .746 .727 .706 .685 72 73 .918 .910 .900 .890 .879 .868 .855 .841 .826 .811 .794 .777 .759 .739 .719 .698 73 74 .925 .917 .908 .898 .888 .876 .864 .851 .837 .822 .806 .789 .771 .752 .732 .712 74
-27- 30 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 75 .931 .923 .915 .906 .896 .885 .873 .861 .847 .833 .817 .801 .784 .765 .746 .726 75 76 .936 .929 .921 .913 .904 .893 .882 .870 .858 .844 .829 .813 .796 .778 .759 .740 76 77 .942 .935 .928 .920 .911 .902 .891 .880 .868 .854 .840 .825 .808 .791 .773 .754 77 78 .947 .941 .934 .927 .918 .909 .900 .889 .877 .865 .851 .836 .821 .804 .786 .768 78 79 .952 .946 .940 .933 .925 .917 .908 .898 .887 .875 .862 .848 .833 .817 .800 .782 79 80 .956 .951 .945 .939 .932 .924 .916 .906 .896 .885 .872 .859 .845 .829 .813 .795 80 81 .961 .956 .951 .945 .938 .931 .923 .914 .905 .894 .883 .870 .856 .842 .826 .809 81 82 .964 .960 .955 .950 .944 .937 .930 .922 .913 .903 .892 .881 .868 .854 .839 .823 82 83 .968 .964 .960 .955 .950 .943 .937 .929 .921 .912 .902 .891 .879 .866 .851 .836 83 84 .972 .968 .964 .960 .955 .949 .943 .936 .928 .920 .911 .900 .889 .877 .863 .849 84
-28- 31 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 25 .731 .718 .704 .691 .676 .662 .647 .632 .617 .601 .585 .568 .551 .535 .518 .500 25 26 .734 .721 .707 .694 .679 .665 .650 .635 .619 .603 .587 .571 .554 .537 .520 .503 26 27 .737 .724 .710 .697 .683 .668 .653 .638 .622 .606 .590 .574 .557 .540 .523 .505 27 28 .740 .727 .714 .700 .686 .671 .656 .641 .625 .609 .593 .576 .560 .543 .525 .508 28 29 .744 .731 .717 .703 .689 .675 .660 .644 .629 .613 .596 .580 .563 .545 .528 .511 29 30 .747 .734 .721 .707 .693 .678 .663 .648 .632 .616 .599 .583 .566 .549 .531 .514 30 31 .751 .738 .725 .711 .696 .682 .667 .651 .636 .619 .603 .586 .569 .552 .534 .517 31 32 .755 .742 .728 .715 .700 .686 .671 .655 .639 .623 .607 .590 .573 .555 .538 .520 32 33 .759 .746 .732 .719 .704 .690 .675 .659 .643 .627 .610 .593 .576 .559 .541 .523 33 34 .763 .750 .737 .723 .708 .694 .679 .663 .647 .631 .614 .597 .580 .562 .545 .527 34 35 .768 .754 .741 .727 .713 .698 .683 .667 .651 .635 .618 .601 .584 .566 .549 .531 35 36 .772 .759 .746 .732 .717 .703 .687 .672 .656 .639 .623 .606 .588 .570 .553 .535 36 37 .777 .764 .750 .736 .722 .707 .692 .677 .661 .644 .627 .610 .593 .575 .557 .539 37 38 .781 .768 .755 .741 .727 .712 .697 .681 .665 .649 .632 .615 .597 .579 .561 .543 38 39 .786 .773 .760 .746 .732 .717 .702 .687 .670 .654 .637 .620 .602 .584 .566 .548 39 40 .791 .779 .765 .751 .737 .723 .707 .692 .676 .659 .642 .625 .607 .589 .571 .552 40 41 .797 .784 .771 .757 .743 .728 .713 .697 .681 .665 .648 .630 .612 .594 .576 .557 41 42 .802 .789 .776 .762 .748 .734 .719 .703 .687 .670 .653 .636 .618 .600 .581 .563 42 43 .807 .795 .782 .768 .754 .740 .724 .709 .693 .676 .659 .642 .624 .605 .587 .568 43 44 .813 .800 .788 .774 .760 .746 .731 .715 .699 .682 .665 .648 .630 .611 .593 .574 44 45 .819 .806 .793 .780 .766 .752 .737 .721 .705 .689 .671 .654 .636 .618 .599 .580 45 46 .824 .812 .799 .786 .773 .758 .743 .728 .712 .695 .678 .660 .642 .624 .605 .586 46 47 .830 .818 .806 .793 .779 .765 .750 .734 .718 .702 .685 .667 .649 .631 .612 .593 47 48 .836 .824 .812 .799 .785 .771 .757 .741 .725 .709 .692 .674 .656 .638 .619 .600 48 49 .842 .830 .818 .805 .792 .778 .764 .748 .732 .716 .699 .681 .663 .645 .626 .607 49
-29- 32 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 50 .848 .837 .825 .812 .799 .785 .771 .756 .740 .723 .706 .689 .671 .652 .633 .614 50 51 .854 .843 .831 .819 .806 .792 .778 .763 .747 .731 .714 .697 .679 .660 .641 .622 51 52 .860 .849 .838 .826 .813 .799 .785 .770 .755 .739 .722 .705 .687 .668 .649 .630 52 53 .866 .855 .844 .832 .820 .807 .793 .778 .763 .747 .730 .713 .695 .676 .657 .638 53 54 .872 .862 .851 .839 .827 .814 .800 .786 .771 .755 .738 .721 .703 .685 .666 .646 54 55 .878 .868 .857 .846 .834 .821 .808 .794 .779 .763 .747 .730 .712 .693 .674 .655 55 56 .884 .874 .864 .853 .841 .829 .816 .802 .787 .771 .755 .738 .721 .702 .683 .664 56 57 .890 .880 .870 .860 .848 .836 .823 .810 .795 .780 .764 .747 .730 .712 .693 .673 57 58 .895 .886 .877 .866 .855 .844 .831 .818 .804 .789 .773 .756 .739 .721 .702 .683 58 59 .901 .893 .883 .873 .863 .851 .839 .826 .812 .798 .782 .766 .749 .731 .712 .693 59 60 .907 .898 .890 .880 .870 .859 .847 .834 .821 .806 .791 .775 .758 .741 .722 .703 60 61 .912 .904 .896 .887 .877 .866 .855 .842 .829 .815 .800 .785 .768 .751 .733 .714 61 62 .918 .910 .902 .893 .884 .873 .862 .851 .838 .824 .810 .794 .778 .761 .743 .725 62 63 .923 .916 .908 .900 .890 .881 .870 .859 .846 .833 .819 .804 .788 .772 .754 .736 63 64 .928 .921 .914 .906 .897 .888 .878 .867 .855 .842 .829 .814 .799 .782 .765 .747 64 65 .933 .926 .919 .912 .904 .895 .885 .875 .863 .851 .838 .824 .809 .793 .776 .758 65 66 .937 .931 .925 .918 .910 .902 .892 .882 .872 .860 .847 .833 .819 .803 .787 .770 66 67 .942 .936 .930 .924 .916 .908 .900 .890 .880 .868 .856 .843 .829 .814 .798 .781 67 68 .946 .941 .935 .929 .922 .915 .906 .897 .888 .877 .865 .853 .839 .825 .809 .793 68 69 .950 .946 .940 .934 .928 .921 .913 .905 .895 .885 .874 .862 .849 .835 .820 .804 69 70 .954 .950 .945 .939 .933 .927 .920 .912 .903 .893 .883 .871 .859 .845 .831 .816 70 71 .958 .954 .949 .944 .939 .932 .926 .918 .910 .901 .891 .880 .868 .855 .842 .827 71 72 .962 .958 .953 .949 .944 .938 .932 .925 .917 .908 .899 .889 .878 .865 .852 .838 72 73 .965 .961 .957 .953 .948 .943 .937 .931 .923 .916 .907 .897 .887 .875 .863 .849 73 74 .968 .965 .961 .957 .953 .948 .942 .936 .930 .922 .914 .905 .895 .884 .873 .860 74
-30- 33 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 75 .971 .968 .965 .961 .957 .952 .948 .942 .936 .929 .921 .913 .904 .893 .882 .870 75 76 .974 .971 .968 .965 .961 .957 .952 .947 .941 .935 .928 .920 .912 .902 .892 .880 76 77 .976 .974 .971 .968 .965 .961 .957 .952 .947 .941 .934 .927 .919 .910 .900 .890 77 78 .979 .976 .974 .971 .968 .965 .961 .957 .952 .946 .940 .934 .926 .918 .909 .899 78 79 .981 .979 .976 .974 .971 .968 .965 .961 .956 .952 .946 .940 .933 .926 .917 .908 79 80 .983 .981 .979 .977 .974 .971 .968 .965 .961 .956 .951 .946 .939 .932 .925 .916 80 81 .985 .983 .981 .979 .977 .974 .971 .968 .965 .961 .956 .951 .945 .939 .932 .924 81 82 .986 .985 .983 .981 .979 .977 .975 .972 .968 .965 .961 .956 .951 .945 .939 .931 82 83 .988 .986 .985 .983 .982 .980 .977 .975 .972 .969 .965 .961 .956 .951 .945 .938 83 84 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .958 .951 .945 84
-31- 34 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 25 .500 .483 .466 .449 .432 .414 .397 .380 .364 .347 .331 .315 .299 .284 .269 .254 25 26 .503 .486 .468 .451 .434 .416 .399 .382 .365 .349 .333 .316 .301 .285 .270 .256 26 27 .505 .488 .471 .453 .436 .419 .401 .384 .367 .351 .334 .318 .302 .287 .272 .257 27 28 .508 .491 .473 .456 .438 .421 .403 .386 .369 .353 .336 .320 .304 .288 .273 .258 28 29 .511 .493 .476 .458 .441 .423 .406 .388 .371 .355 .338 .322 .306 .290 .275 .260 29 30 .514 .496 .478 .461 .443 .426 .408 .391 .374 .357 .340 .324 .307 .292 .276 .261 30 31 .517 .499 .481 .464 .446 .428 .411 .393 .376 .359 .342 .326 .309 .294 .278 .263 31 32 .520 .502 .484 .466 .449 .431 .413 .396 .378 .361 .344 .328 .311 .295 .280 .265 32 33 .523 .505 .488 .470 .452 .434 .416 .398 .381 .364 .347 .330 .314 .298 .282 .267 33 34 .527 .509 .491 .473 .455 .437 .419 .401 .384 .366 .349 .332 .316 .300 .284 .269 34 35 .531 .513 .494 .476 .458 .440 .422 .404 .387 .369 .352 .335 .318 .302 .286 .271 35 36 .535 .516 .498 .480 .462 .443 .425 .407 .390 .372 .355 .337 .321 .304 .288 .273 36 37 .539 .520 .502 .484 .465 .447 .429 .411 .393 .375 .357 .340 .323 .307 .291 .275 37 38 .543 .525 .506 .488 .469 .451 .432 .414 .396 .378 .361 .343 .326 .310 .293 .277 38 39 .548 .529 .511 .492 .473 .455 .436 .418 .400 .382 .364 .346 .329 .312 .296 .280 39 40 .552 .534 .515 .496 .478 .459 .440 .422 .403 .385 .367 .350 .332 .315 .299 .283 40 41 .557 .539 .520 .501 .482 .463 .445 .426 .407 .389 .371 .353 .336 .319 .302 .286 41 42 .563 .544 .525 .506 .487 .468 .449 .430 .412 .393 .375 .357 .339 .322 .305 .289 42 43 .568 .549 .530 .511 .492 .473 .454 .435 .416 .397 .379 .361 .343 .326 .309 .292 43 44 .574 .555 .536 .517 .497 .478 .459 .440 .421 .402 .383 .365 .347 .329 .312 .295 44 45 .580 .561 .542 .522 .503 .483 .464 .445 .425 .406 .388 .369 .351 .333 .316 .299 45 46 .586 .567 .548 .528 .509 .489 .469 .450 .431 .411 .392 .374 .355 .337 .320 .303 46 47 .593 .573 .554 .534 .515 .495 .475 .455 .436 .417 .397 .379 .360 .342 .324 .307 47 48 .600 .580 .561 .541 .521 .501 .481 .461 .442 .422 .403 .384 .365 .346 .328 .311 48 49 .607 .587 .567 .548 .528 .507 .487 .467 .447 .428 .408 .389 .370 .351 .333 .315 49
-32- 35 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 50 .614 .594 .575 .555 .534 .514 .494 .474 .454 .434 .414 .394 .375 .356 .338 .320 50 51 .622 .602 .582 .562 .542 .521 .501 .480 .460 .440 .420 .400 .381 .362 .343 .325 51 52 .630 .610 .590 .570 .549 .529 .508 .487 .467 .446 .426 .406 .387 .367 .348 .330 52 53 .638 .618 .598 .577 .557 .536 .515 .495 .474 .453 .433 .413 .393 .373 .354 .335 53 54 .646 .626 .606 .586 .565 .544 .523 .502 .481 .461 .440 .419 .399 .379 .360 .341 54 55 .655 .635 .615 .594 .574 .553 .532 .510 .489 .468 .447 .426 .406 .386 .366 .347 55 56 .664 .644 .624 .603 .582 .561 .540 .519 .497 .476 .455 .434 .413 .393 .373 .353 56 57 .673 .654 .633 .613 .592 .570 .549 .528 .506 .484 .463 .442 .421 .400 .380 .360 57 58 .683 .663 .643 .622 .601 .580 .558 .537 .515 .493 .472 .450 .429 .408 .387 .367 58 59 .693 .673 .653 .632 .611 .590 .568 .546 .524 .502 .481 .459 .437 .416 .395 .374 59 60 .703 .684 .663 .643 .622 .600 .578 .556 .534 .512 .490 .468 .446 .424 .403 .382 60 61 .714 .694 .674 .654 .632 .611 .589 .567 .545 .522 .500 .478 .455 .434 .412 .391 61 62 .725 .705 .685 .665 .644 .622 .600 .578 .556 .533 .510 .488 .465 .443 .421 .400 62 63 .736 .716 .697 .676 .655 .634 .612 .589 .567 .644 .521 .499 .476 .453 .431 .409 63 64 .747 .728 .708 .688 .667 .646 .624 .601 .579 .556 .533 .510 .487 .464 .441 .419 64 65 .758 .740 .720 .700 .679 .658 .636 .614 .591 .568 .545 .522 .498 .475 .452 .430 65 66 .770 .751 .732 .712 .692 .671 .649 .627 .604 .581 .557 .534 .511 .487 .464 .441 66 67 .781 .763 .745 .725 .705 .684 .662 .640 .617 .594 .571 .547 .523 .500 .476 .453 67 68 .793 .775 .757 .738 .718 .697 .676 .653 .631 .608 .584 .560 .537 .513 .489 .465 68 69 .804 .787 .769 .751 .731 .711 .689 .667 .645 .622 .598 .574 .550 .526 .502 .478 69 70 .816 .799 .782 .764 .744 .724 .703 .682 .659 .636 .613 .589 .565 .540 .516 .492 70 71 .827 .811 .794 .777 .758 .738 .718 .696 .674 .651 .628 .604 .580 .555 .531 .506 71 72 .838 .823 .807 .790 .771 .752 .732 .711 .689 .666 .643 .619 .595 .571 .546 .521 72 73 .849 .835 .819 .802 .785 .766 .746 .726 .704 .682 .659 .635 .611 .586 .562 .536 73 74 .860 .846 .831 .815 .798 .780 .761 .741 .720 .698 .675 .651 .627 .603 .578 .553 74
-33- 36 SPECIAL PROVISION C FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------- 75 .870 .857 .843 .828 .811 .794 .775 .756 .735 .714 .691 .668 .644 .620 .595 .569 75 76 .880 .868 .854 .840 .824 .807 .790 .771 .751 .730 .708 .685 .661 .637 .612 .587 76 77 .890 .878 .865 .852 .837 .821 .804 .785 .766 .746 .724 .702 .679 .654 .630 .605 77 78 .899 .888 .876 .863 .849 .834 .818 .800 .781 .762 .741 .719 .696 .672 .648 .623 78 79 .908 .898 .886 .874 .861 .847 .831 .814 .797 .778 .757 .736 .714 .690 .666 .641 79 80 .916 .907 .896 .885 .873 .859 .844 .828 .811 .793 .774 .753 .731 .709 .685 .660 80 81 .924 .915 .906 .895 .884 .871 .857 .842 .826 .808 .790 .770 .749 .727 .704 .680 81 82 .931 .923 .915 .905 .894 .882 .869 .855 .840 .823 .806 .787 .766 .745 .723 .699 82 83 .938 .931 .923 .914 .904 .893 .881 .868 .853 .838 .821 .803 .784 .763 .741 .718 83 84 .945 .938 .931 .922 .913 .903 .892 .880 .866 .852 .836 .819 .800 .781 .760 .738 84
-34- 37 SPECIAL PROVISION D MARITAL PENSIONS, JOINT PENSIONS WITH SPOUSES AND SPECIAL JOINT PENSIONS WITH SPOUSES MARITAL PENSIONS and JOINT PENSIONS with SPOUSES shall be determined by multiplying factors calculated in accordance with the 1951 Male Group Annuity Table at 5% interest, with the following modifications: (i) PARTICIPANT's mortality rates shall be determined by adding 41% of the rates at PARTICIPANT's ages to 59% of the rates at ages five years lower. (ii) SPOUSE's mortality rates shall be determined by adding 59% of the rates at SPOUSE's ages to 41% of the rates at ages five years lower. (iii) For MARITAL PENSIONS, the factors shall be calculated taking into account only one-half of the costs of the benefits to surviving SPOUSES. (iv) When the proportions of the JOINT PENSIONS to be continued to SPOUSES exceed 50%, the factors shall be calculated in such a way that the values of such JOINT PENSIONS are equal to the values of corresponding MARITAL PENSION. (v) When the proportions of the JOINT PENSIONS to be continued to SPOUSES are less than 50%, the factors shall be calculated taking into account only one-half of the costs to surviving SPOUSES. (vi) Whenever a factor calculated for a MARITAL or JOINT PENSION with SPOUSE is smaller than the corresponding factor for a non- spouse JOINT PENSION, the non-spouse JOINT PENSION factor shall be substituted for the calculated factor. The following tables illustrate the factors to be applied for typical options which may be elected between 25% and 100%. EXAMPLE: Assume the PARTICIPANT is age 62 and Spouse age 60. Also assume that the PARTICIPANT's BASIC PENSION is $1,000 per month.
Spouse's Pension Spouse's Option Basic Reduced Spouse's In Event of Option Factor Pension Pension Portion Participant's Death - -------- ------ ------- ------- -------- -------------------- 25% .976 X $1,000. = $976. X .25 = $244.00 50% .955 X $1,000. = $955. X .50 = $477.50 75% .914 X $1,000. = $914. X .75 = $685.50 100% .876 X $1,000. = $876. X 1.00 = $876.00
SPECIAL JOINT PENSIONS with SPOUSES shall be determined using the same actuarial assumptions described above and are illustrated in the tables following the JOINT PENSION tables. -35- 38 SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 25% OPTION ELECTION
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .969 .967 .964 .962 .959 .956 .953 .950 .946 .943 .939 .935 .930 .926 .921 .916 40 41 .970 .968 .965 .963 .960 .957 .954 .951 .948 .944 .940 .936 .932 .927 .922 .917 41 42 .971 .969 .966 .964 .961 .958 .955 .952 .949 .945 .941 .937 .933 .929 .924 .919 42 43 .972 .970 .967 .965 .962 .960 .957 .953 .950 .947 .943 .939 .934 .930 .925 .920 43 44 .973 .971 .968 .966 .963 .961 .958 .955 .951 .948 .944 .940 .936 .931 .927 .922 44 45 .974 .972 .969 .967 .965 .962 .959 .956 .953 .949 .946 .942 .937 .933 .928 .923 45 46 .975 .973 .970 .968 .966 .963 .960 .957 .954 .951 .947 .943 .939 .935 .930 .925 46 47 .976 .974 .972 .969 .967 .964 .962 .959 .955 .952 .948 .945 .940 .936 .932 .927 47 48 .977 .975 .973 .970 .968 .966 .963 .960 .957 .953 .950 .946 .942 .938 .933 .928 48 49 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 .948 .944 .939 .935 .930 49 50 .979 .977 .975 .973 .970 .968 .965 .963 .960 .956 .953 .949 .945 .941 .937 .932 50 51 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 .947 .943 .939 .934 51 52 .980 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 .953 .949 .945 .940 .936 52 53 .981 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .954 .951 .947 .942 .938 53 54 .982 .981 .979 .977 .975 .973 .971 .968 .965 .962 .959 .956 .952 .948 .944 .940 54 55 .983 .982 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .954 .950 .946 .942 55 56 .984 .983 .981 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .952 .948 .944 56 57 .985 .984 .982 .980 .979 .977 .975 .972 .970 .967 .964 .961 .958 .954 .950 .946 57 58 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .959 .956 .952 .948 58 59 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .967 .964 .961 .958 .954 .950 59
NOTE: Factors for additional age combinations are available from the Administrator. -36- 39 SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 25% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .987 .986 .985 .984 .982 .980 .978 .976 .974 .972 .969 .966 .963 .960 .956 .952 60 61 .988 .987 .986 .985 .983 .981 .980 .978 .976 .973 .971 .968 .965 .962 .958 .954 61 62 .989 .988 .987 .985 .984 .983 .981 .979 .977 .975 .972 .970 .967 .964 .960 .957 62 63 .990 .989 .988 .986 .985 .984 .982 .980 .978 .976 .974 .971 .969 .966 .962 .959 63 64 .990 .990 .988 .987 .986 .985 .983 .981 .980 .978 .975 .973 .970 .967 .964 .961 64 65 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .977 .975 .972 .969 .966 .963 65 66 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .974 .971 .968 .965 66 67 .992 .992 .991 .990 .989 .988 .986 .985 .983 .982 .980 .978 .975 .973 .970 .967 67 68 .993 .992 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 .977 .975 .972 .969 68 69 .994 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 69 70 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 70 71 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 71 72 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 72 73 .995 .995 .995 .994 .993 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 73 74 .996 .995 .995 .994 .994 .993 .992 .992 .991 .990 .989 .987 .986 .984 .982 .980 74
NOTE: Factors for additional age combinations are available from the Administrator. -37- 40 SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 50% OPTION ELECTION
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .942 .938 .934 .929 .924 .919 .914 .909 .903 .897 .891 .885 .878 .871 .863 .856 40 41 .943 .939 .935 .931 .926 .921 .916 .911 .905 .899 .893 .887 .880 .873 .865 .858 41 42 .945 .941 .937 .933 .928 .923 .918 .913 .907 .901 .895 .889 .882 .875 .868 .860 42 43 .947 .943 .939 .934 .930 .925 .920 .915 .909 .903 .897 .891 .884 .877 .870 .862 43 44 .948 .945 .941 .936 .932 .927 .922 .917 .911 .906 .899 .893 .886 .879 .872 .865 44 45 .950 .946 .942 .938 .934 .929 .924 .919 .914 .908 .902 .895 .889 .882 .875 .867 45 46 .952 .948 .944 .940 .936 .931 .926 .921 .916 .910 .904 .898 .891 .884 .877 .870 46 47 .954 .950 .946 .942 .938 .933 .929 .923 .918 .912 .906 .900 .894 .887 .880 .872 47 48 .955 .952 .948 .944 .940 .935 .931 .926 .920 .915 .909 .903 .896 .889 .882 .875 48 49 .957 .954 .950 .946 .942 .938 .933 .928 .923 .917 .911 .905 .899 .892 .885 .878 49 50 .959 .956 .952 .948 .944 .940 .935 .930 .925 .920 .914 .908 .901 .895 .888 .880 50 51 .961 .957 .954 .950 .946 .942 .938 .933 .928 .922 .917 .911 .904 .898 .891 .883 51 52 .962 .959 .956 .952 .948 .944 .940 .935 .930 .925 .919 .913 .907 .900 .894 .886 52 53 .964 .961 .958 .954 .950 .946 .942 .938 .933 .927 .922 .916 .910 .903 .897 .889 53 54 .966 .963 .960 .956 .953 .949 .945 .940 .935 .930 .925 .919 .913 .906 .900 .893 54 55 .968 .965 .962 .958 .955 .951 .947 .942 .938 .933 .927 .922 .916 .909 .903 .896 55 56 .969 .966 .963 .960 .957 .953 .949 .945 .940 .936 .930 .925 .919 .913 .906 .899 56 57 .971 .968 .965 .962 .959 .955 .952 .947 .943 .938 .933 .928 .922 .916 .909 .902 57 58 .972 .970 .967 .964 .961 .958 .954 .950 .946 .941 .936 .931 .925 .919 .913 .906 58 59 .974 .972 .969 .966 .963 .960 .956 .952 .948 .944 .939 .934 .928 .922 .916 .909 59
NOTE: Factors for additional age combinations are available from the Administrator. -38- 41 SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 50% OPTION ELECTION (Continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .976 .973 .971 .968 .965 .962 .959 .955 .951 .946 .942 .937 .931 .926 .919 .913 60 61 .977 .975 .973 .970 .967 .964 .961 .957 .953 .949 .945 .940 .934 .929 .923 .916 61 62 .979 .976 .974 .972 .969 .966 .963 .960 .956 .952 .947 .943 .938 .932 .926 .920 62 63 .980 .978 .976 .974 .971 .968 .965 .962 .958 .955 .950 .946 .941 .936 .930 .924 63 64 .981 .979 .977 .975 .973 .970 .967 .964 .961 .957 .953 .949 .944 .939 .933 .928 64 65 .983 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .952 .947 .942 .937 .931 65 66 .984 .982 .980 .979 .976 .974 .972 .969 .966 .962 .959 .955 .950 .945 .940 .935 66 67 .985 .984 .982 .980 .978 .976 .974 .971 .968 .965 .961 .957 .953 .949 .944 .939 67 68 .986 .985 .983 .982 .980 .978 .975 .973 .970 .967 .964 .960 .956 .952 .947 .942 68 69 .987 .986 .985 .983 .981 .979 .977 .975 .972 .970 .966 .963 .959 .955 .951 .946 69 70 .988 .987 .986 .984 .983 .981 .979 .977 .974 .972 .969 .966 .962 .958 .954 .949 70 71 .989 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 .968 .965 .961 .957 .953 71 72 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .971 .967 .964 .960 .956 72 73 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .970 .967 .963 .959 73 74 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .966 .962 74
NOTE: Factors for additional age combinations are available from the Administrator. -39- 42 SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 75% OPTION ELECTION
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .890 .883 .875 .868 .859 .851 .842 .833 .824 .814 .803 .793 .782 .771 .760 .748 40 41 .893 .886 .878 .871 .863 .854 .845 .836 .827 .817 .807 .796 .785 .774 .763 .751 41 42 .896 .889 .881 .874 .866 .857 .849 .840 .830 .820 .810 .800 .789 .778 .766 .754 42 43 .899 .892 .885 .877 .869 .861 .852 .843 .834 .824 .814 .803 .792 .781 .770 .758 43 44 .902 .895 .888 .880 .872 .864 .856 .847 .837 .827 .817 .807 .796 .785 .773 .762 44 45 .905 .898 .891 .884 .876 .868 .859 .850 .841 .831 .821 .811 .800 .789 .777 .765 45 46 .908 .901 .894 .887 .879 .871 .863 .854 .845 .835 .825 .814 .804 .792 .781 .769 46 47 .911 .905 .898 .891 .883 .875 .867 .858 .849 .839 .829 .819 .808 .797 .785 .773 47 48 .915 .908 .901 .894 .887 .879 .870 .862 .853 .843 .833 .823 .812 .801 .789 .778 48 49 .918 .911 .905 .898 .890 .883 .874 .866 .857 .847 .837 .827 .816 .805 .794 .782 49 50 .921 .915 .908 .901 .894 .886 .878 .870 .861 .851 .842 .831 .821 .810 .798 .786 50 51 .924 .918 .912 .905 .898 .890 .882 .874 .865 .856 .846 .836 .825 .814 .803 .791 51 52 .927 .922 .915 .909 .902 .894 .887 .878 .869 .860 .851 .840 .830 .819 .808 .796 52 53 .931 .925 .919 .912 .906 .898 .891 .883 .874 .865 .855 .845 .835 .824 .813 .801 53 54 .934 .928 .922 .916 .910 .902 .895 .887 .878 .869 .860 .850 .840 .829 .818 .806 54 55 .937 .932 .926 .920 .913 .906 .899 .891 .883 .874 .865 .855 .845 .834 .823 .811 55 56 .940 .935 .930 .924 .917 .911 .903 .896 .887 .879 .870 .860 .850 .839 .828 .817 56 57 .943 .938 .933 .927 .921 .915 .908 .900 .892 .884 .875 .865 .855 .845 .834 .822 57 58 .946 .942 .936 .931 .925 .919 .912 .905 .897 .888 .880 .870 .860 .850 .839 .828 58 59 .949 .945 .940 .935 .929 .923 .916 .909 .901 .893 .885 .876 .866 .856 .845 .834 59
NOTE: Factors for additional age combinations are available from the Administrator. -40- 43 SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 75% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .952 .948 .943 .938 .933 .927 .920 .914 .906 .898 .890 .881 .871 .861 .851 .840 60 61 .955 .951 .946 .942 .936 .931 .925 .918 .911 .903 .895 .886 .877 .867 .857 .846 61 62 .958 .954 .950 .945 .940 .935 .929 .922 .915 .908 .900 .892 .883 .873 .863 .852 62 63 .961 .957 .953 .948 .944 .939 .933 .927 .920 .913 .905 .897 .888 .879 .869 .858 63 64 .963 .960 .956 .952 .947 .942 .937 .931 .925 .918 .910 .902 .894 .885 .875 .865 64 65 .966 .962 .959 .955 .951 .946 .941 .935 .929 .923 .916 .908 .900 .891 .881 .871 65 66 .968 .965 .962 .958 .954 .950 .945 .939 .934 .927 .921 .913 .905 .897 .887 .878 66 67 .971 .968 .964 .961 .957 .953 .948 .943 .938 .932 .925 .918 .911 .902 .894 .884 67 68 .973 .970 .967 .964 .960 .956 .952 .947 .942 .936 .930 .924 .916 .908 .900 .891 68 69 .975 .972 .970 .967 .963 .960 .956 .951 .946 .941 .935 .929 .922 .914 .906 .897 69 70 .977 .975 .972 .969 .966 .963 .959 .955 .950 .945 .940 .933 .927 .920 .912 .903 70 71 .979 .977 .974 .972 .969 .966 .962 .958 .954 .949 .944 .938 .932 .925 .918 .910 71 72 .981 .979 .976 .974 .971 .968 .965 .962 .958 .953 .948 .943 .937 .930 .923 .916 72 73 .982 .980 .978 .976 .974 .971 .968 .965 .961 .957 .952 .947 .942 .936 .929 .922 73 74 .984 .982 .980 .978 .976 .974 .971 .968 .964 .960 .956 .951 .946 .940 .934 .927 74
NOTE: Factors for additional age combinations are available from the Administrator. -41- 44 SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 100% OPTION ELECTION
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .844 .834 .824 .814 .803 .792 .781 .769 .757 .744 .732 .719 .705 .692 .678 .664 40 41 .847 .838 .828 .818 .807 .796 .785 .773 .761 .748 .736 .723 .709 .696 .682 .668 41 42 .851 .842 .832 .822 .811 .800 .789 .777 .765 .753 .740 .727 .713 .700 .686 .672 42 43 .855 .846 .836 .826 .816 .805 .793 .782 .770 .757 .744 .731 .718 .704 .690 .676 43 44 .860 .850 .841 .831 .820 .809 .798 .786 .774 .762 .749 .736 .722 .709 .695 .680 44 45 .864 .855 .845 .835 .825 .814 .803 .791 .779 .766 .754 .740 .727 .713 .699 .685 45 46 .868 .859 .850 .840 .829 .819 .807 .796 .784 .771 .759 .745 .732 .718 .704 .690 46 47 .873 .864 .854 .844 .834 .824 .812 .801 .789 .776 .764 .750 .737 .723 .709 .695 47 48 .877 .868 .859 .849 .839 .829 .817 .806 .794 .782 .769 .756 .742 .728 .714 .700 48 49 .881 .873 .864 .854 .844 .834 .823 .811 .799 .787 .774 .761 .748 .734 .719 .705 49 50 .886 .877 .868 .859 .849 .839 .828 .817 .805 .793 .780 .767 .753 .739 .725 .711 50 51 .890 .882 .873 .864 .854 .844 .833 .822 .810 .798 .786 .772 .759 .745 .731 .716 51 52 .895 .887 .878 .869 .860 .850 .839 .828 .816 .804 .791 .778 .765 .751 .737 .722 52 53 .899 .892 .883 .874 .865 .855 .845 .834 .822 .810 .797 .784 .771 .757 .743 .728 53 54 .904 .896 .888 .879 .870 .860 .850 .839 .828 .816 .804 .791 .777 .763 .749 .735 54 55 .908 .901 .893 .884 .876 .866 .856 .845 .834 .822 .810 .797 .784 .770 .756 .741 55 56 .913 .906 .898 .890 .881 .872 .862 .851 .840 .829 .816 .804 .791 .777 .763 .748 56 57 .917 .910 .903 .895 .886 .877 .868 .857 .846 .835 .823 .810 .797 .784 .770 .755 57 58 .922 .915 .908 .900 .892 .883 .873 .863 .853 .842 .830 .817 .804 .791 .777 .762 58 59 .926 .919 .912 .905 .897 .888 .879 .870 .859 .848 .837 .824 .811 .798 .784 .770 59
NOTE: Factors for additional age combinations are available from the Administrator. -42- 45 SPECIAL PROVISION D FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE 100% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .930 .924 .917 .910 .902 .894 .885 .876 .866 .855 .843 .831 .819 .805 .792 .777 60 61 .934 .928 .922 .915 .908 .900 .891 .882 .872 .861 .850 .839 .826 .813 .799 .785 61 62 .938 .933 .926 .920 .913 .905 .897 .888 .878 .868 .857 .846 .834 .821 .807 .793 62 63 .942 .937 .931 .925 .918 .911 .903 .894 .885 .875 .864 .853 .841 .829 .815 .802 63 64 .946 .941 .935 .929 .923 .916 .908 .900 .891 .882 .871 .860 .849 .837 .824 .810 64 65 .950 .945 .940 .934 .928 .921 .914 .906 .897 .888 .878 .868 .857 .845 .832 .819 65 66 .953 .949 .944 .938 .933 .926 .919 .912 .904 .895 .885 .875 .864 .853 .840 .827 66 67 .957 .952 .948 .943 .937 .931 .925 .918 .910 .901 .892 .882 .872 .860 .848 .836 67 68 .960 .956 .951 .947 .942 .936 .930 .923 .916 .908 .899 .890 .879 .868 .857 .844 68 69 .963 .959 .955 .951 .946 .941 .935 .928 .921 .914 .906 .897 .887 .876 .865 .853 69 70 .966 .962 .959 .955 .950 .945 .940 .934 .927 .920 .912 .903 .894 .884 .873 .862 70 71 .969 .965 .962 .958 .954 .949 .944 .939 .932 .926 .918 .910 .901 .892 .881 .870 71 72 .971 .968 .965 .962 .958 .953 .949 .943 .938 .931 .924 .917 .908 .899 .889 .879 72 73 .974 .971 .968 .965 .961 .957 .953 .948 .943 .937 .930 .923 .915 .906 .897 .887 73 74 .976 .974 .971 .968 .965 .961 .957 .952 .947 .952 .936 .929 .921 .913 .904 .895 74
NOTE: Factors for additional age combinations are available from the Administrator. -43- 46 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 20 .966 .964 .961 .959 .956 .953 .950 .947 .944 .940 .937 .933 .929 .926 .921 .917 20 21 .967 .964 .962 .959 .957 .954 .951 .948 .945 .941 .938 .934 .930 .926 .922 .918 21 22 .967 .965 .963 .960 .957 .955 .952 .949 .945 .942 .938 .935 .931 .927 .923 .919 22 23 .968 .966 .963 .961 .958 .955 .952 .949 .946 .943 .939 .936 .932 .928 .924 .920 23 24 .969 .966 .964 .961 .959 .956 .953 .950 .947 .944 .940 .937 .933 .929 .925 .921 24 25 .969 .967 .965 .962 .960 .957 .954 .951 .948 .944 .941 .937 .934 .930 .926 .921 25 26 .970 .968 .965 .963 .960 .958 .955 .952 .949 .945 .942 .938 .935 .931 .927 .922 26 27 .971 .969 .966 .964 .961 .959 .956 .953 .950 .946 .943 .939 .936 .932 .928 .923 27 28 .971 .969 .967 .965 .962 .959 .957 .954 .950 .947 .944 .940 .936 .933 .929 .924 28 29 .972 .970 .968 .965 .963 .960 .957 .954 .951 .948 .945 .941 .937 .934 .930 .925 29 30 .973 .971 .969 .966 .964 .961 .958 .955 .952 .949 .946 .942 .939 .935 .931 .927 30 31 .974 .972 .969 .967 .965 .962 .959 .956 .953 .950 .947 .943 .940 .936 .932 .928 31 32 .974 .972 .970 .968 .965 .963 .960 .957 .954 .951 .948 .944 .941 .937 .933 .929 32 33 .975 .973 .971 .969 .966 .964 .961 .958 .955 .952 .949 .945 .942 .938 .934 .930 33 34 .976 .974 .972 .970 .967 .965 .962 .959 .956 .953 .950 .947 .943 .939 .935 .931 34 35 .977 .975 .973 .970 .968 .966 .963 .960 .957 .954 .951 .948 .944 .940 .937 .933 35 36 .977 .975 .973 .971 .969 .967 .964 .961 .958 .955 .952 .949 .945 .942 .938 .934 36 37 .978 .976 .974 .972 .970 .968 .965 .962 .960 .957 .953 .950 .947 .943 .939 .935 37 38 .979 .977 .975 .973 .971 .969 .966 .963 .961 .958 .955 .951 .948 .944 .940 .937 38 39 .980 .978 .976 .974 .972 .970 .967 .964 .962 .959 .956 .952 .949 .946 .942 .938 39
NOTE: Factors for additional age combinations are available from the Administrator. -44- 47 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .980 .979 .977 .975 .973 .970 .968 .966 .963 .960 .957 .954 .950 .947 .943 .939 40 41 .981 .979 .978 .976 .974 .971 .969 .967 .964 .961 .958 .955 .952 .948 .945 .941 41 42 .982 .980 .978 .977 .975 .972 .970 .968 .965 .962 .959 .956 .953 .950 .946 .942 42 43 .983 .981 .979 .977 .975 .973 .971 .969 .966 .963 .961 .958 .954 .951 .947 .944 43 44 .983 .982 .980 .978 .976 .974 .972 .970 .967 .965 .962 .959 .956 .952 .949 .945 44 45 .984 .982 .981 .979 .977 .975 .973 .971 .968 .966 .963 .960 .957 .954 .950 .947 45 46 .985 .983 .982 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .952 .948 46 47 .985 .984 .982 .981 .979 .977 .975 .973 .971 .968 .965 .963 .960 .957 .953 .950 47 48 .986 .984 .983 .981 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 48 49 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 .953 49 50 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .964 .961 .958 .954 50 51 .988 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 51 52 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .961 .957 52 53 .989 .988 .986 .985 .984 .982 .980 .979 .977 .975 .972 .970 .968 .965 .962 .959 53 54 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .960 54 55 .990 .989 .988 .986 .985 .984 .982 .980 .979 .977 .975 .972 .970 .968 .965 .962 55 56 .990 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 56 57 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 57 58 .991 .990 .989 .988 .987 .986 .985 .983 .981 .980 .978 .976 .974 .971 .969 .966 58 59 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 59
NOTE: Factors for additional age combinations are available from the Administrator. -45- 48 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION (Continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .992 .991 .990 .989 .988 .987 .986 .985 .983 .981 .980 .978 .976 .974 .972 .969 60 61 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .971 61 62 .993 .992 .991 .991 .990 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .972 62 63 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .983 .981 .979 .977 .975 .973 63 64 .994 .993 .992 .991 .991 .990 .989 .987 .986 .985 .983 .982 .980 .978 .976 .974 64 65 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .978 .976 65 66 .994 .994 .993 .992 .992 .991 .990 .989 .988 .986 .985 .984 .982 .980 .979 .977 66 67 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .980 .978 67 68 .995 .994 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 68 69 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 69 70 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 70 71 .996 .995 .995 .994 .994 .993 .992 .991 .991 .990 .989 .987 .986 .985 .984 .982 71 72 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .985 .983 72 73 .996 .996 .996 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 .987 .985 .984 73 74 .997 .996 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .985 74 75 .997 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 75 76 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 .987 76 77 .997 .997 .997 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 77 78 .997 .997 .997 .996 .996 .996 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 78 79 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .991 .991 .990 .989 79
NOTE: Factors for additional age combinations are available from the Administrator. -46- 49 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 80 .998 .997 .997 .997 .997 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .990 80 81 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .993 .992 .991 .990 81 82 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .992 .991 82 83 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 83 84 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .993 .992 84 85 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 85 86 .999 .998 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 .994 .993 86 87 .999 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .995 .994 .993 87 88 .999 .999 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 88 89 .999 .999 .999 .998 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 89
NOTE: Factors for additional age combinations are available from the Administrator. -47- 50 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- < C> 20 .917 .913 .908 .903 .898 .893 .888 .882 .876 .870 .864 .857 .850 .843 .836 .828 20 21 .918 .913 .909 .904 .899 .894 .888 .883 .877 .871 .865 .858 .851 .844 .837 .829 21 22 .919 .914 .910 .905 .900 .895 .889 .884 .878 .872 .865 .859 .852 .845 .838 .830 22 23 .920 .915 .911 .906 .901 .896 .890 .885 .879 .873 .866 .860 .853 .846 .838 .831 23 24 .921 .916 .912 .907 .902 .897 .891 .886 .880 .874 .867 .861 .854 .847 .839 .832 24 25 .921 .917 .912 .908 .903 .898 .892 .887 .881 .875 .868 .862 .855 .848 .840 .833 25 26 .922 .918 .913 .909 .904 .899 .893 .888 .882 .876 .869 .863 .856 .849 .841 .834 26 27 .923 .919 .914 .910 .905 .900 .894 .889 .883 .877 .870 .864 .857 .850 .842 .835 27 28 .924 .920 .916 .911 .906 .901 .895 .890 .884 .878 .871 .865 .858 .851 .844 .836 28 29 .925 .921 .917 .912 .907 .902 .896 .891 .885 .879 .873 .866 .859 .852 .845 .837 29 30 .927 .922 .918 .913 .908 .903 .898 .892 .886 .880 .874 .867 .860 .853 .846 .838 30 31 .928 .923 .919 .914 .909 .904 .899 .893 .887 .881 .875 .868 .862 .855 .847 .840 31 32 .929 .925 .920 .915 .911 .905 .900 .895 .889 .883 .876 .870 .863 .856 .849 .841 32 33 .930 .926 .921 .917 .912 .907 .901 .896 .890 .884 .878 .871 .864 .857 .850 .842 33 34 .931 .927 .923 .918 .913 .908 .903 .897 .891 .885 .879 .873 .866 .859 .851 .844 34 35 .933 .928 .924 .919 .915 .909 .904 .899 .893 .887 .881 .874 .867 .860 .853 .845 35 36 .934 .930 .925 .921 .916 .911 .906 .900 .894 .888 .882 .876 .869 .862 .854 .847 36 37 .935 .931 .927 .922 .917 .912 .907 .902 .896 .890 .884 .877 .870 .863 .856 .849 37 38 .937 .932 .928 .924 .919 .914 .909 .903 .897 .892 .885 .879 .872 .865 .858 .850 38 39 .938 .934 .930 .925 .920 .915 .910 .905 .899 .893 .887 .880 .874 .867 .859 .852 39
NOTE: Factors for additional age combinations are availavble from the Administrator. -48- 51 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .939 .935 .931 .927 .922 .917 .912 .906 .901 .895 .889 .882 .875 .868 .861 .854 40 41 .941 .937 .933 .928 .924 .919 .914 .908 .903 .897 .890 .884 .877 .870 .863 .856 41 42 .942 .938 .934 .930 .925 .920 .915 .910 .904 .898 .892 .886 .879 .872 .865 .858 42 43 .944 .940 .936 .931 .927 .922 .917 .912 .906 .900 .894 .888 .881 .874 .867 .860 43 44 .945 .941 .937 .933 .929 .924 .919 .914 .908 .902 .896 .890 .883 .876 .869 .862 44 45 .947 .943 .939 .935 .930 .926 .921 .915 .910 .904 .898 .892 .885 .878 .871 .864 45 46 .948 .944 .941 .936 .932 .927 .922 .917 .912 .906 .900 .894 .887 .880 .873 .866 46 47 .950 .946 .942 .938 .934 .929 .924 .919 .914 .908 .902 .896 .889 .883 .876 .868 47 48 .951 .948 .944 .940 .936 .931 .926 .921 .916 .910 .904 .898 .892 .885 .878 .871 48 49 .953 .949 .946 .942 .937 .933 .928 .923 .918 .912 .907 .900 .894 .887 .880 .873 49 50 .954 .951 .947 .943 .939 .935 .930 .925 .920 .915 .909 .903 .896 .890 .883 .875 50 51 .956 .953 .949 .945 .941 .937 .932 .927 .922 .917 .911 .905 .899 .892 .885 .878 51 52 .957 .954 .951 .947 .943 .939 .934 .929 .924 .919 .913 .907 .901 .895 .888 .880 52 53 .959 .956 .952 .949 .945 .941 .936 .932 .927 .921 .916 .910 .904 .897 .890 .883 53 54 .960 .957 .954 .950 .947 .943 .938 .934 .929 .924 .918 .912 .906 .900 .893 .886 54 55 .962 .959 .956 .952 .948 .945 .940 .936 .931 .926 .920 .915 .909 .902 .896 .889 55 56 .963 .960 .957 .954 .950 .946 .942 .938 .933 .928 .923 .917 .911 .905 .898 .891 56 57 .965 .962 .959 .956 .952 .948 .944 .940 .935 .931 .925 .920 .914 .908 .901 .894 57 58 .966 .964 .961 .957 .954 .950 .946 .942 .938 .933 .928 .922 .917 .910 .904 .897 58 59 .968 .965 .962 .959 .956 .952 .948 .944 .940 .935 .930 .925 .919 .913 .907 .900 59
NOTE: Factors for additional age combinations are available from the Administrator. -49- 52 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .969 .967 .964 .961 .958 .954 .950 .946 .942 .938 .933 .927 .922 .916 .910 .903 60 61 .971 .968 .965 .962 .959 .956 .952 .949 .944 .940 .935 .930 .925 .919 .913 .906 61 62 .972 .969 .967 .964 .961 .958 .954 .951 .947 .942 .938 .933 .927 .922 .916 .909 62 63 .973 .971 .968 .966 .963 .960 .956 .953 .949 .945 .940 .935 .930 .924 .919 .912 63 64 .974 .972 .970 .967 .965 .962 .958 .955 .951 .947 .942 .938 .933 .927 .922 .916 64 65 .976 .974 .971 .969 .966 .963 .960 .957 .953 .949 .945 .940 .935 .930 .925 .919 65 66 .977 .975 .973 .970 .968 .965 .962 .959 .955 .951 .947 .943 .938 .933 .928 .922 66 67 .978 .976 .974 .972 .969 .967 .964 .961 .957 .954 .950 .945 .941 .936 .930 .925 67 68 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .952 .948 .943 .939 .933 .928 68 69 .980 .978 .977 .975 .972 .970 .967 .964 .961 .958 .954 .950 .946 .941 .936 .931 69 70 .981 .980 .978 .976 .974 .971 .969 .966 .963 .960 .956 .953 .948 .944 .939 .934 70 71 .982 .981 .979 .977 .975 .973 .971 .968 .965 .962 .959 .955 .951 .947 .942 .937 71 72 .983 .982 .980 .978 .976 .974 .972 .970 .967 .964 .961 .957 .953 .949 .945 .940 72 73 .984 .983 .981 .979 .978 .976 .974 .971 .969 .966 .963 .959 .956 .952 .947 .943 73 74 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .961 .958 .954 .950 .946 74 75 .986 .985 .983 .982 .980 .978 .976 .974 .972 .969 .967 .963 .960 .956 .953 .948 75 76 .987 .985 .984 .983 .981 .980 .978 .976 .973 .971 .968 .965 .962 .959 .955 .951 76 77 .987 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .967 .964 .961 .957 .954 77 78 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .972 .969 .966 .963 .960 .956 78 79 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .968 .965 .962 .959 79
NOTE: Factors for additional age combinations are available from the Administrator. -50- 53 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 50% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 80 .990 .989 .988 .986 .985 .984 .983 .981 .979 .977 .975 .973 .970 .967 .964 .961 80 81 .990 .989 .988 .987 .986 .985 .984 .982 .980 .979 .977 .974 .972 .969 .966 .963 81 82 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .971 .968 .965 82 83 .991 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .978 .975 .973 .970 .968 83 84 .992 .991 .990 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .972 .970 84 85 .992 .992 .991 .990 .989 .988 .987 .986 .985 .984 .982 .980 .978 .976 .974 .972 85 86 .993 .992 .992 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 .978 .976 .973 86 87 .993 .993 .992 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .977 .975 87 88 .994 .993 .993 .992 .991 .991 .990 .989 .988 .987 .985 .984 .983 .981 .979 .977 88 89 .994 .994 .993 .993 .992 .991 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 89
NOTE: Factors for additional age combinations are available from the Administrator. -51- 54 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 20 .904 .898 .892 .885 .879 .872 .864 .856 .849 .840 .832 .823 .815 .805 .796 .787 20 21 .906 .900 .894 .887 .880 .873 .866 .858 .850 .842 .834 .825 .816 .807 .798 .788 21 22 .908 .902 .896 .889 .882 .875 .868 .860 .852 .844 .836 .827 .818 .809 .800 .790 22 23 .909 .904 .897 .891 .884 .877 .870 .862 .854 .846 .838 .829 .820 .811 .802 .792 23 24 .911 .905 .899 .893 .886 .879 .872 .864 .856 .848 .840 .831 .822 .813 .804 .794 24 25 .913 .907 .901 .895 .888 .881 .874 .866 .858 .850 .842 .833 .824 .815 .806 .796 25 26 .915 .909 .903 .897 .890 .883 .876 .868 .860 .852 .844 .835 .826 .817 .808 .798 26 27 .917 .911 .905 .899 .892 .885 .878 .870 .862 .854 .846 .837 .829 .820 .810 .801 27 28 .919 .913 .907 .901 .894 .887 .880 .872 .865 .857 .848 .840 .831 .822 .813 .803 28 29 .921 .915 .909 .903 .896 .889 .882 .875 .867 .859 .851 .842 .833 .824 .815 .805 29 30 .923 .917 .911 .905 .899 .892 .885 .877 .869 .861 .853 .845 .836 .827 .817 .808 30 31 .925 .919 .913 .907 .901 .894 .887 .880 .872 .864 .856 .847 .838 .829 .820 .811 31 32 .927 .921 .916 .909 .903 .896 .889 .882 .874 .866 .858 .850 .841 .832 .823 .813 32 33 .929 .923 .918 .912 .905 .899 .892 .884 .877 .869 .861 .852 .844 .835 .825 .816 33 34 .931 .926 .920 .914 .908 .901 .894 .887 .879 .872 .864 .855 .846 .838 .828 .819 34 35 .933 .928 .922 .916 .910 .904 .897 .890 .882 .874 .866 .858 .849 .840 .831 .822 35 36 .935 .930 .924 .919 .913 .906 .899 .892 .885 .877 .869 .861 .852 .843 .834 .825 36 37 .937 .932 .927 .921 .915 .909 .902 .895 .888 .880 .872 .864 .855 .846 .837 .828 37 38 .939 .934 .929 .923 .917 .911 .905 .898 .890 .883 .875 .867 .858 .850 .840 .831 38 39 .941 .936 .931 .926 .920 .914 .907 .900 .893 .886 .878 .870 .861 .853 .844 .834 39
NOTE: Factors for additional age combinations are available from the Administrator. -52- 55 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .943 .939 .934 .928 .922 .916 .910 .903 .896 .889 .881 .873 .865 .856 .847 .838 40 41 .945 .941 .936 .930 .925 .919 .913 .906 .899 .892 .884 .876 .868 .859 .850 .841 41 42 .947 .943 .938 .933 .927 .921 .915 .909 .902 .895 .887 .879 .871 .863 .854 .845 42 43 .949 .945 .940 .935 .930 .924 .918 .912 .905 .898 .890 .883 .874 .866 .857 .848 43 44 .951 .947 .942 .937 .932 .927 .921 .914 .908 .901 .893 .886 .878 .869 .861 .852 44 45 .953 .949 .945 .940 .935 .929 .923 .917 .911 .904 .897 .889 .881 .873 .864 .856 45 46 .955 .951 .947 .942 .937 .932 .926 .920 .914 .907 .900 .892 .885 .876 .868 .859 46 47 .957 .953 .949 .944 .939 .934 .929 .923 .916 .910 .903 .896 .888 .880 .872 .863 47 48 .959 .955 .951 .946 .942 .937 .931 .925 .919 .913 .906 .899 .891 .884 .875 .867 48 49 .960 .957 .953 .949 .944 .939 .934 .928 .922 .916 .909 .902 .895 .887 .879 .871 49 50 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .906 .898 .891 .883 .875 50 51 .964 .960 .957 .953 .948 .944 .939 .934 .928 .922 .916 .909 .902 .894 .887 .878 51 52 .965 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 .898 .890 .882 52 53 .967 .964 .960 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .902 .894 .886 53 54 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .918 .912 .905 .898 .890 54 55 .970 .967 .964 .960 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .901 .894 55 56 .971 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 .898 56 57 .973 .970 .967 .964 .961 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .902 57 58 .974 .972 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 58 59 .975 .973 .970 .967 .964 .961 .957 .953 .949 .944 .939 .934 .928 .922 .916 .909 59
NOTE: Factors for additional age combinations are available from the Administrator. -53- 56 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .977 .974 .972 .969 .966 .963 .959 .955 .951 .946 .942 .937 .931 .925 .919 .913 60 61 .978 .976 .973 .971 .968 .964 .961 .957 .953 .949 .944 .939 .934 .929 .923 .917 61 62 .979 .977 .975 .972 .969 .966 .963 .959 .955 .951 .947 .942 .937 .932 .926 .920 62 63 .980 .978 .976 .974 .971 .968 .965 .961 .958 .954 .949 .945 .940 .935 .929 .924 63 64 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .952 .947 .943 .938 .933 .927 64 65 .982 .981 .978 .976 .974 .971 .968 .965 .962 .958 .954 .950 .945 .941 .936 .930 65 66 .983 .982 .980 .978 .975 .973 .970 .967 .964 .960 .956 .952 .948 .944 .939 .934 66 67 .984 .983 .981 .979 .977 .974 .971 .969 .965 .962 .959 .955 .951 .946 .942 .937 67 68 .985 .984 .982 .980 .978 .976 .973 .970 .967 .964 .961 .957 .953 .949 .945 .940 68 69 .986 .985 .983 .981 .979 .977 .974 .972 .969 .966 .963 .959 .955 .952 .947 .943 69 70 .987 .985 .984 .982 .980 .978 .976 .973 .971 .968 .965 .961 .958 .954 .950 .946 70 71 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .953 .948 71 72 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 .968 .965 .962 .959 .955 .951 72 73 .989 .988 .987 .985 .984 .982 .980 .978 .975 .973 .970 .967 .964 .961 .957 .954 73 74 .990 .989 .987 .986 .985 .983 .981 .979 .977 .974 .972 .969 .966 .963 .960 .956 74 75 .990 .989 .988 .987 .986 .984 .982 .980 .978 .976 .973 .971 .968 .965 .962 .959 75 76 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 .964 .961 76 77 .992 .991 .990 .989 .987 .986 .984 .983 .981 .979 .976 .974 .972 .969 .966 .963 77 78 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .971 .968 .965 78 79 .993 .992 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 79
NOTE: Factors for additional age combinations are available from the Administrator. -54- 57 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 80 .993 .992 .992 .991 .990 .988 .987 .986 .984 .982 .980 .978 .976 .974 .972 .969 80 81 .994 .993 .992 .991 .990 .989 .988 .987 .985 .983 .982 .980 .978 .976 .973 .971 81 82 .994 .993 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 .977 .975 .973 82 83 .995 .994 .993 .992 .992 .991 .990 .988 .987 .986 .984 .982 .981 .979 .977 .975 83 84 .995 .994 .994 .993 .992 .991 .990 .989 .988 .986 .985 .983 .982 .980 .978 .976 84 85 .995 .995 .994 .994 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .980 .978 85 86 .996 .995 .995 .994 .993 .992 .992 .991 .989 .988 .987 .986 .984 .983 .981 .979 86 87 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 87 88 .996 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .986 .985 .983 .982 88 89 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .988 .987 .986 .985 .983 89
NOTE: Factors for additional age combinations are available from the Administrator. -55- 58 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 20 .787 .777 .767 .757 .746 .736 .725 .714 .702 .691 .679 .667 .654 .642 .629 .617 20 21 .788 .779 .769 .759 .748 .737 .726 .715 .704 .692 .680 .668 .656 .643 .631 .618 21 22 .790 .781 .771 .760 .750 .739 .728 .717 .705 .694 .682 .670 .657 .645 .632 .620 22 23 .792 .782 .772 .762 .752 .741 .730 .719 .707 .695 .683 .671 .659 .646 .634 .621 23 24 .794 .784 .774 .764 .754 .743 .732 .721 .709 .697 .685 .673 .661 .648 .635 .623 24 25 .796 .787 .776 .766 .756 .745 .734 .723 .711 .699 .687 .675 .662 .650 .637 .624 25 26 .798 .789 .779 .768 .758 .747 .736 .725 .713 .701 .689 .677 .664 .652 .639 .626 26 27 .801 .791 .781 .771 .760 .749 .738 .727 .715 .703 .691 .679 .666 .653 .641 .628 27 28 .803 .793 .783 .773 .762 .751 .740 .729 .717 .705 .693 .681 .668 .655 .643 .630 28 29 .805 .796 .786 .775 .765 .754 .743 .731 .719 .708 .695 .683 .670 .658 .645 .632 29 30 .808 .798 .788 .778 .767 .756 .745 .734 .722 .710 .698 .685 .673 .660 .647 .634 30 31 .811 .801 .791 .780 .770 .759 .748 .736 .724 .712 .700 .688 .675 .662 .649 .636 31 32 .813 .803 .793 .783 .772 .761 .750 .739 .727 .715 .703 .690 .677 .664 .651 .638 32 33 .816 .806 .796 .786 .775 .764 .753 .741 .730 .718 .705 .693 .680 .667 .654 .641 33 34 .819 .809 .799 .789 .778 .767 .756 .744 .732 .720 .708 .695 .682 .669 .656 .643 34 35 .822 .812 .802 .792 .781 .770 .759 .747 .735 .723 .711 .698 .685 .672 .659 .646 35 36 .825 .815 .805 .795 .784 .773 .762 .750 .738 .726 .714 .701 .688 .675 .662 .648 36 37 .828 .818 .808 .798 .787 .776 .765 .753 .742 .729 .717 .704 .691 .678 .665 .651 37 38 .831 .821 .811 .801 .791 .780 .768 .757 .745 .733 .720 .707 .694 .681 .668 .654 38 39 .834 .825 .815 .805 .794 .783 .772 .760 .748 .736 .723 .711 .698 .684 .671 .657 39
NOTE: Factors for additional age combinations are available from the Administrator. -56- 59 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 40 .838 .828 .818 .808 .797 .787 .775 .764 .752 .739 .727 .714 .701 .688 .674 .661 40 41 .841 .832 .822 .812 .801 .790 .779 .767 .755 .743 .730 .718 .704 .691 .678 .664 41 42 .845 .835 .825 .815 .805 .794 .783 .771 .759 .747 .734 .721 .708 .695 .681 .667 42 43 .848 .839 .829 .819 .808 .798 .786 .775 .763 .751 .738 .725 .712 .698 .685 .671 43 44 .852 .843 .833 .823 .812 .802 .790 .779 .767 .755 .742 .729 .716 .702 .689 .675 44 45 .856 .846 .837 .827 .816 .806 .794 .783 .771 .759 .746 .733 .720 .706 .693 .679 45 46 .859 .850 .841 .831 .820 .810 .799 .787 .775 .763 .750 .737 .724 .711 .697 .683 46 47 .863 .854 .845 .835 .825 .814 .803 .791 .780 .767 .755 .742 .728 .715 .701 .687 47 48 .867 .858 .849 .839 .829 .818 .807 .796 .784 .772 .759 .746 .733 .719 .705 .691 48 49 .871 .862 .853 .843 .833 .823 .812 .800 .789 .776 .764 .751 .738 .724 .710 .696 49 50 .875 .866 .857 .847 .837 .827 .816 .805 .793 .781 .769 .756 .742 .729 .715 .701 50 51 .878 .870 .861 .852 .842 .832 .821 .810 .798 .786 .773 .761 .747 .734 .720 .706 51 52 .882 .874 .865 .856 .846 .836 .825 .814 .803 .791 .778 .766 .752 .739 .725 .711 52 53 .886 .878 .869 .860 .851 .841 .830 .819 .808 .796 .784 .771 .757 .744 .730 .716 53 54 .890 .882 .874 .865 .855 .845 .835 .824 .813 .801 .789 .776 .763 .749 .735 .721 54 55 .894 .886 .878 .869 .860 .850 .840 .829 .818 .806 .794 .781 .768 .755 .741 .727 55 56 .898 .890 .882 .873 .864 .855 .845 .834 .823 .812 .799 .787 .774 .760 .747 .732 56 57 .902 .894 .886 .878 .869 .860 .850 .839 .828 .817 .805 .793 .780 .766 .752 .738 57 58 .905 .898 .890 .882 .874 .864 .855 .845 .834 .822 .811 .798 .785 .772 .758 .744 58 59 .909 .902 .895 .887 .878 .869 .860 .850 .839 .828 .816 .804 .791 .778 .764 .750 59
NOTE: Factors for additional age combinations are available from the Administrator. -57- 60 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION (continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 60 .913 .906 .899 .891 .883 .874 .865 .855 .844 .834 .822 .810 .797 .784 .771 .757 60 61 .917 .910 .903 .895 .887 .879 .870 .860 .850 .839 .828 .816 .803 .790 .777 .763 61 62 .920 .914 .907 .900 .892 .884 .875 .865 .855 .845 .834 .822 .810 .797 .784 .770 62 63 .924 .917 .911 .904 .896 .888 .880 .870 .861 .850 .839 .828 .816 .803 .790 .776 63 64 .927 .921 .915 .908 .901 .893 .884 .876 .866 .856 .845 .834 .822 .810 .797 .783 64 65 .930 .925 .918 .912 .905 .897 .889 .881 .871 .862 .851 .840 .828 .816 .803 .790 65 66 .934 .928 .922 .916 .909 .902 .894 .886 .877 .867 .857 .846 .835 .823 .810 .797 66 67 .937 .931 .926 .920 .913 .906 .899 .891 .882 .873 .863 .852 .841 .829 .817 .804 67 68 .940 .935 .929 .924 .917 .911 .903 .895 .887 .878 .868 .858 .847 .836 .824 .811 68 69 .943 .938 .933 .927 .921 .915 .908 .900 .892 .883 .874 .864 .854 .842 .830 .818 69 70 .946 .941 .936 .931 .925 .919 .912 .905 .897 .889 .880 .870 .860 .849 .837 .825 70 71 .948 .944 .939 .934 .929 .923 .916 .909 .902 .894 .885 .876 .866 .855 .844 .832 71 72 .951 .947 .942 .938 .932 .927 .921 .914 .907 .899 .890 .881 .872 .861 .851 .839 72 73 .954 .950 .945 .941 .936 .931 .925 .918 .911 .904 .896 .887 .878 .868 .857 .846 73 74 .956 .952 .948 .944 .939 .934 .929 .922 .916 .909 .901 .893 .884 .874 .864 .853 74 75 .959 .955 .951 .947 .943 .938 .932 .927 .920 .913 .906 .898 .889 .880 .870 .859 75 76 .961 .958 .954 .950 .946 .941 .936 .931 .924 .918 .911 .903 .895 .886 .876 .866 76 77 .963 .960 .957 .953 .949 .944 .940 .934 .929 .922 .916 .908 .900 .892 .882 .873 77 78 .965 .962 .959 .955 .952 .948 .943 .938 .933 .927 .920 .913 .906 .897 .888 .879 78 79 .967 .964 .961 .958 .954 .951 .946 .942 .936 .931 .925 .918 .911 .903 .894 .885 79
NOTE: Factors for additional age combinations are available from the Administrator. -58- 61 SPECIAL PROVISION D SPECIAL JOINT PENSION WITH SPOUSE FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE 100% OPTION ELECTION (Continued)
SPOUSE'S SPOUSE'S AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT PENSIONER'S PENSIONER'S RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT - ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------- 80 .969 .967 .964 .961 .957 .953 .949 .945 .940 .935 .929 .923 .916 .908 .900 .891 80 81 .971 .969 .966 .963 .960 .956 .952 .948 .944 .939 .933 .927 .920 .913 .906 .897 81 82 .973 .970 .968 .965 .962 .959 .955 .951 .947 .942 .937 .931 .925 .918 .911 .903 82 83 .975 .972 .970 .967 .965 .961 .958 .954 .950 .946 .941 .936 .930 .923 .916 .909 83 84 .976 .974 .972 .969 .967 .964 .961 .957 .953 .949 .945 .939 .934 .928 .921 .914 84 85 .978 .976 .974 .971 .969 .966 .963 .960 .956 .952 .948 .943 .938 .932 .926 .919 85 86 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .951 .947 .942 .937 .931 .924 86 87 .981 .979 .977 .975 .973 .971 .968 .965 .962 .958 .955 .950 .946 .941 .935 .929 87 88 .982 .980 .979 .977 .975 .973 .970 .967 .965 .961 .958 .954 .949 .945 .939 .934 88 89 .983 .982 .980 .978 .976 .974 .972 .970 .967 .964 .961 .957 .953 .948 .943 .938 89
NOTE: Factors for additional age combinations are available from the Administrator. -59- 62 SPECIAL PROVISION E As in Effect Prior to January 1, 1976 A PARTICIPANT who is rehired after a BREAK IN SERVICE shall be treated as a new PARTICIPANT for all purposes, and the PARTICIPANT's SERVICE and compensation before the BREAK IN SERVICE shall not be recognized for any purpose of the PLAN, except as follows: (a) Upon either the death or retirement of a PARTICIPANT with broken SERVICE, the last period of CREDITED SERVICE immediately preceding the PARTICIPANT's latest employment date by EMPLOYER shall be counted as SERVICE provided: (1) The PARTICIPANT has accrued at least five years of SERVICE since last re-employed by EMPLOYER, and (2) The PARTICIPANT was last re-employed by EMPLOYER within five years of the date the PARTICIPANT's latest previous employment was terminated; and (3) The PARTICIPANT had accrued at least five years of CREDITED SERVICE prior to the date the PARTICIPANT's last previous employment with EMPLOYER terminated. (b) All other periods of prior employment with EMPLOYER, if any, shall not be counted as SERVICE. SPECIAL PROVISION F CREDITED SERVICE (a) As in effect prior to January 1, 1976: All SERVICE prior to ACTUAL RETIREMENT DATE, provided the PARTICIPANT joined the PLAN on the date when the PARTICIPANT first became eligible and participated therein continuously thereafter. An EMPLOYEE who first became eligible to join the COMPANY's Retirement PLAN prior to January 1, 1969, was permitted a grace period of six months beyond the EMPLOYEE'S eligibility date. An EMPLOYEE who first became eligible to join the PLAN on or after January 1, 1969, was permitted a grace period of 60 days beyond the EMPLOYEE'S eligibility date. Subject to these grace periods, if an EMPLOYEE did not become a PARTICIPANT when first eligible the EMPLOYEE'S CREDITED SERVICE did not begin until the EMPLOYEE became a PARTICIPANT. If a PARTICIPANT suspended contributions at any time between January 1, 1969, and December 31, 1972, inclusive. CREDITED SERVICE did not accrue to the PARTICIPANT after the date of such suspension of contributions. CREDITED SERVICE did not include any time for which a vacation allowance may be paid subsequent to an EMPLOYEE'S NORMAL RETIREMENT DATE. (b) Effective April 1, 1981: An EMPLOYEE who first became eligible to join the PLAN prior to January 1, 1973, but who for any reason did not do so, shall, except those EMPLOYEES who have had their CREDITED SERVICE previously adjusted by action of the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (EBAC), be allowed the opportunity to have such lost CREDITED SERVICE restored. An EMPLOYEE'S CREDITED SERVICE shall not be adjusted or restored except as follows: -60- 63 (1) Prior to April 1, 1982, any EMPLOYEE described above shall, upon application to EBAC, be permitted to buy back any portion of the five years of lost CREDITED SERVICE immediately preceding the latest date on which an EMPLOYEE became a member of the PLAN. Such restored CREDITED SERVICE shall not, in combination with current SERVICE, exceed PARTICIPANT's actual COMPANY SERVICE. The cost for restoring such CREDITED SERVICE shall be computed at the rate of five percent of an EMPLOYEE'S current monthly wage rate for each month of restored CREDITED SERVICE. (2) In addition to the above, and prior to April 1, 1982, any EMPLOYEE described above shall, upon application to EBAC, be permitted to buy back any portion of the lost CREDITED SERVICE which is in excess of the five years permitted in (1) above. The cost for restoring such excess CREDITED SERVICE shall be computed at the rate of ten percent of an EMPLOYEE'S current monthly wage rate for each month of restored excess CREDITED SERVICE. For the purpose of applying Section 13 (Withdrawal of PARTICIPANT Contributions on Termination of Employment) only that portion of the payment made above, for restoration of lost CREDITED SERVICE, which the EMPLOYEE would have contributed had the EMPLOYEE participated in the PLAN at that time will be considered as CONTRIBUTIONS. SPECIAL PROVISION G PENSION AND LTD ADJUSTMENTS (a) Effective December 31, 1993, the PENSION of any PARTICIPANT who retired or the PENSION of a person receiving a SPOUSE's PENSION or a JOINT PENSION, will be increased as follows:
Increase -------- Retired on or before 12/31/73 9.0% Retired between 1/1/74 and 12/31/83 5.0% Retired between 1/1/84 and 12/31/89 2.5% Retired between 1/1/88 and 12/31/88 2.5%
A minimum monthly increase of $50 will be provided to retirees with at least 30 years of SERVICE, and a retirement date at or after normal retirement age. A minimum monthly increase of $25 will be provided to surviving SPOUSES of such retirees. (b) The above adjustments shall apply to those Participants who are receiving Long Term Disability Benefit payments. (c) By Company resolutions dated June 17, 1964, February 25, 1969, April 9, 1974, September 20, 1977, March 4, 1980, July 15, 1981, and December 21, 1983, the amounts of pensions received by certain pensioners were increased in accordance with the provisions of said resolutions. The money required to fund these additional payments is based on actuarial factors and the required contributions are paid into the Plan. The Company intends to continue making these additional payments out of Plan assets and on the same basis as it has done in the past. -61- 64 SPECIAL PROVISION H MAXIMUM PENSION This PLAN incorporates by reference the benefit limitations imposed by CODE Section 415. The annual benefit amount otherwise payable to a former EMPLOYEE at any time will not exceed the maximum permissible amount under CODE Section 415. For purposes of determining compliance with the Section 415 benefit limitations, the limitation year shall be the PLAN YEAR. If the benefit the PARTICIPANT would otherwise accrue in a limitation year would produce an annual benefit in excess of the maximum permissible amount under CODE Section 415, then the rate of accrual will be reduced so that the annual benefit will equal the maximum permissible amount. If a PARTICIPANT in this PLAN also participates in any defined contribution plan maintained by an EMPLOYER, the sum of the PARTICIPANT'S "Defined Benefit Fraction" and the PARTICIPANT'S "Defined Contribution Fraction" shall not exceed 1.0. In the event that in any PLAN YEAR the sum of the PARTICIPANT'S Defined Benefit Fraction and the PARTICIPANT'S Defined Contribution Fraction exceed 1.0, then the PENSION payable under this PLAN shall be reduced so that the sum of such fractions in respect of that PARTICIPANT will not exceed 1.0." For purposes of determining the PLAN'S compliance with CODE Section 415, the annual benefit is a retirement benefit payable under the PLAN in the form of a straight life annuity. Except as provided below, a benefit payable in a form other than a straight life annuity must be adjusted to an actuarially equivalent straight life annuity before applying the limitations of Section 415. The interest rate assumption used to determine actuarial equivalence will be the greater of rate used in Special Provision D or 5 percent. No actuarial adjustment to the benefit is required for the value of a qualified joint and survivor annuity, the value of benefits that are not directly related to retirement benefits (such as the qualified disability benefit, pre-retirement death benefits, and post-retirement medical benefits), and the value of post-retirement cost-of-living increases made in accordance with 415(d) of the CODE. The annual benefit does not include any benefits attributable to EMPLOYEE contributions or rollover contributions or the assets transferred from a qualified plan not maintained by the COMPANY. Compensation, for purposes of determining the PLAN'S compliance with Section 415 of the CODE, shall mean all of each PARTICIPANT'S wages, tips, and other Box 10 compensation on the PARTICIPANT'S Form W-2. SPECIAL PROVISION I If prior to 1989 SERVICE terminates with at least ten years of SERVICE, or with at least five years of SERVICE after 1988, the PENSION the PARTICIPANT would otherwise be entitled to receive shall be reduced because of the withdrawal. If the withdrawal occurs prior to age 55, the yearly PENSION payable at the NORMAL RETIREMENT DATE, prior to reduction for EARLY RETIREMENT (if any), shall be reduced by the product of the amount withdrawn and the applicable factor selected from the following table: -62- 65
Age Last Age Last Birthday At Birthday At Refund Date Factor Refund Date Factor ----------- ------ ----------- ------ 25 .6705 40 .3225 26 .6385 41 .3072 27 .6081 42 .2925 28 .5792 43 .2786 29 .5516 44 .2653 30 .5253 45 .2527 31 .5003 46 .2407 32 .4765 47 .2292 33 .4538 48 .2183 34 .4321 49 .2079 35 .4116 50 .1980 36 .3920 51 .1886 37 .3733 52 .1796 38 .3556 53 .1710 39 .3386 54 .1629
If the withdrawal occurs after age 55, the yearly PENSION payable at the ACTUAL RETIREMENT DATE, after reduction for EARLY RETIREMENT (if any), shall be reduced by the product of the amount withdrawn and the applicable factor selected from the following table:
Age Last Birthday At Refund Date Factor ----------- ------ 55 .0775 56 .0792 57 .0810 58 .0829 59 .0849 60 .0871 61 .0894 62 .0919 63 .0946 64 .0975 65 .1000 66 .1039 67 .1074 68 .1111 69 .1151 70 .1192
Notwithstanding the foregoing, in no event will the PENSION be reduced by more than one-third. The monthly reduction is computed by multiplying the appropriate factor times the PARTICIPANT'S contributions including interest and dividing that amount by twelve months. -63- 66 EXAMPLE: Assumptions: Age 60 Basic Pensions = $1,500.00/month Contributions = $6,000.00 Interest = 3,000.00 --------- Total = $9,000.00 - 65.33* --------- Pension with contributions = $1,434.67/month plus interest withdrawn _______________________ *Calculation: (Contributions + Interest x Age 60 Refund Factor) : 12 Months ($9,000 x .0871 : 12 Months = $65.33) -64- 67 SPECIAL PROVISION J TOP HEAVY PROVISIONS (a) General Rule For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined in subsection (g) below, any other provisions of this PLAN to the contrary notwithstanding, this PLAN shall be subject to the following provisions: (1) The vesting provisions of subsection (b). (2) The minimum benefit provisions of subsection (c). (3) The limitation on compensation set by subsection (d). (4) The limitation on benefits set by subsection (e). If any individual has not performed SERVICE for an EMPLOYER at any time during the five-year period ending on the last day of the preceding PLAN YEAR, any accrued benefit for such individual shall not be taken into account for purposes of determining whether the PLAN is a "top-heavy plan." For purposes of determining whether the PLAN is top-heavy, a non-key EMPLOYEE'S accrued benefit must be determined as if it is accrued not more rapidly than the slowest accrual rate permitted under CODE Section 411(b)(1)(C) (i.e., the "fractional rule"). (b) Vesting Provisions Each PARTICIPANT who (i) has completed an hour of SERVICE during any PLAN YEAR in which the PLAN is top heavy and (ii) has completed the number of years of credited SERVICE specified in the following table shall have a nonforfeitable right to the percentage of the benefit accrued under this PLAN derived from EMPLOYER contributions correspondingly specified in the following table:
Years of Percentage of credited service: nonforfeitable benefit: 2 20 3 40 4 60 5 80 6 or more 100
"Credited service" as used in this subsection (b) shall constitute SERVICE as defined in Section 22 of this PLAN. Each PARTICIPANT's nonforfeitable accrued benefit shall not be less than his nonforfeitable accrued benefit determined as of the last day of the last PLAN YEAR in which the PLAN was a top-heavy PLAN. If the PLAN ceases to be top-heavy, each PARTICIPANT with five or more years of SERVICE, whether or not consecutive, shall have his nonforfeitable accrued benefit determined in accordance with this Section and Section 3. Each such PARTICIPANT shall have the right to elect the applicable schedule within 60 days after the day the PARTICIPANT is issued written notice by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, or as otherwise provided in accordance with regulations issued under the provision of the Internal Revenue CODE of 1954, as amended, relating to changes in the vesting schedule. -65- 68 This provision shall apply without regard to contributions or benefits under Social Security or any other Federal or State law. (c) Minimum Benefit Provisions Each PARTICIPANT who (i) is a non-key employee (as defined in subsection (i) below) and (ii) has completed 1,000 hours of SERVICE during any PLAN YEAR shall be entitled to an accrued benefit in the form of an annual retirement benefit (as defined in paragraph (1) below) that shall be not less than the applicable percentage (as defined in paragraph (2) below) of the PARTICIPANT's average annual compensation for years in the testing period (as defined in paragraph (3) below). (1) "Annual retirement benefit" means a benefit payable annually in the form of a single life annuity (with no ancillary benefits) beginning at NORMAL RETIREMENT DATE as defined in Section 22 of this PLAN or its actuarial equivalent. (2) "Applicable percentage" means the lesser of two percent multiplied by the number of top-heavy PLAN YEARs of service (as defined in paragraph (4) below) of 20 percent. (3) "Testing period" means, with respect to a PARTICIPANT, the period of consecutive years (not exceeding five) of SERVICE during which the PARTICIPANT had the greatest aggregate compensation from the EMPLOYER. The testing period shall not include any year of SERVICE not included as a year of SERVICE as defined in paragraph (4) below. The testing period shall also not include any year of SERVICE that ends in a PLAN YEAR beginning before January 1, 1984 or during which the PLAN was not a top-heavy plan. (4) "Years of service" means SERVICE as defined in Section 3 of this PLAN. Benefits taken into account under this Subsection shall not include any benefits payable under the Social Security Act or any other Federal or State law. (d) Limitation on Benefits In the event that the EMPLOYER also maintains a defined contribution PLAN providing contributions on behalf of PARTICIPANTS in this PLAN, one of the two following provisions shall apply: (1) If for the PLAN YEAR this PLAN would not be a "top-heavy plan" as defined in subsection (g) below if "90 percent" were substituted for "60 percent," then subsection (c) shall apply for such PLAN YEAR as if amended so that the "applicable percentage" means the lesser of three percent multiplied by the number of years of SERVICE (as defined in paragraph (4) of subsection (c)) during which the PLAN would be top-heavy (as defined in subsection (g)) and the overall applicable percentage does not exceed the lesser of 30% or 20% plus 1% for each year the PLAN is taken into account under this subsection ((e)(1)). (2) If for the PLAN YEAR this PLAN would continue to be a "top-heavy plan" as defined in subsection (g) below if "90 percent" were substituted for "60 percent," then the denominator of both the defined contribution PLAN fraction and the defined benefit plan fraction shall be calculated as set forth in Special Provision H for the limitation year ending in such PLAN YEAR by substituting "1.0" for "1.25," except with respect to any individual for whom there are no EMPLOYER contributions, forfeitures or voluntary -66- 69 nondeductible contributions allocated or any accruals for such individual under the defined benefit PLAN. Furthermore, the transitional rule set forth in CODE Section 415 shall be applied by substituting "$41,500" for $51,875". (e) Coordination with Other Plans In the event that another defined contribution or defined benefit PLAN maintained by the EMPLOYER provides contributions or benefits on behalf of PARTICIPANTS in this PLAN, such other PLAN shall be treated as a part of this PLAN pursuant to applicable principles (such as Rev. Rul. 81-202 or any successor ruling) in determining whether this PLAN satisfies the requirements of subsection (b), (c) and (d). Such determination shall be made upon the advice of counsel by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE. (f) Top-heavy Plan Definition This PLAN shall be a "top-heavy plan" for any PLAN YEAR if, as of the determination date (as defined in subsection (g)(1) below), the present value (as determined in subsection (g)(2) below) of the cumulative accrued benefits under the PLAN for participants (including former participants) who are key employees (as defined in subsection (h) below) exceeds 60 percent of the present value of the cumulative accrued benefits under the PLAN for all participants, excluding former key employees, or if this PLAN is required to be in a aggregation group (as defined in subsection (g)(3) below) which for such PLAN YEAR is a top-heavy group (as defined in subsection (g)(4) below). (1) "Determination date" means for any PLAN YEAR the last day of the immediately preceding PLAN YEAR. (2) The present value shall be determined as of the most recent valuation date that is within the twelve-month period ending on the determination date and as described in the regulations under the Internal Revenue CODE as of 1954, as amended. (3) "Aggregation group" means the group of plans, if any, that includes both the group of plans that are required to be aggregated and the group of plans that are permitted to be aggregated. (A) The group of plans that are required to be aggregated (the "required aggregation group") includes (i) Each plan of the EMPLOYER (as defined in subsection (j) below) in which a key employee is a PARTICIPANT, including collectively-bargained plans, and (ii) Each other plan, including collectively-bargained plans of the EMPLOYER (as defined in subsection (j) below) which enables a plan in which a key employee is a PARTICIPANT to meet the requirements of the Internal Revenue CODE of 1954, as amended, prohibiting discrimination as to contributions or benefits in favor of employees who are officers, shareholders or the highly-compensated or prescribing the minimum participation standards. (B) The group of plans that are permitted to be aggregated (the "permissive aggregation group") includes the required aggregation group plus one or more plans of the EMPLOYER (as defined in subsection (j) below) that is not part of the required aggregation group and that the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE certifies as constituting a plan within the permissive aggregation group. Such plan or plans may be added to the permissive aggrega- -67- 70 tion group only if, after the addition, the aggregation group as a whole continue not to discriminate as to contributions or benefits in favor of officers, shareholders or the highly-compensated and to meet the minimum participation standards under the Internal Revenue CODE of 1954, as amended. (4) "Top-heavy group" means the aggregation group, if as of the applicable determination date, the sum of the present value of the cumulative accrued benefits for key employees under all defined benefit plans included in the aggregation group plus the aggregate of the accounts of key employees under all defined contribution plans included in the aggregation group exceeds 60% of the sum of the present value of the cumulative accrued benefits for all employees, excluding former key employees, under all such defined benefit plans plus the aggregate accounts for all employees, excluding former key employees, under such defined contribution plans. If the aggregation group that is a top-heavy group is a required aggregation group, each Plan in the group will be top heavy. If the aggregation group that is a top-heavy group is a permissive aggregation group, only those plans that are part of the required aggregation group will be treated as top-heavy. If the aggregation group is not a top-heavy group, no plan within such group will be top-heavy. (5) In determining whether this PLAN constitutes a "top-heavy plan", the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (or its agent) shall make the following adjustments in connection therewith: (A) When more than one plan is aggregated, the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall determine separately for each plan as of each plan's determination date the present value of the accrued benefits or account balance. The results shall then be aggregated by adding the results of each plan as of the determination dates for such plans that fall within the same calendar year. (B) In determining the present value of the cumulative accrued benefit or the amount of the account of any employee, such present value or account shall include the amount in dollar value of the aggregate distributions made to such employee under the applicable plan during the five-year period ending on the determination date, unless reflected in the value of the accrued benefit or account balance as of the most recent valuation date. Such amounts shall include distributions to employees which represented the entire amount credited to their accounts under the applicable plan. (B) Further, in making such determination, in any case where an individual is a "non-key employee" as defined in subsection (h) below, with respect to an applicable plan, but was a key employee with respect to such plan for any prior PLAN YEAR, any accrued benefit and any account of such employee shall be altogether disregarded. For this purpose, to the extent that a key employee is deemed to be a key employee if he met the definition of key employee within any of the four preceding PLAN YEARS, this provision shall apply following the end of such period of time. (g) Key Employee The term "key employee" means any employee or former employee under this PLAN who, at any time during the PLAN YEAR containing the determination date or during any of the four preceding PLAN YEARS, is or was one of the following: (1) An officer of the EMPLOYER (as defined in subsection (j)). Whether an individual is an officer shall be determined by the -68- 71 EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE on the basis of all the facts and circumstances, such as an individual's authority, duties and term of office, not on the mere fact that the individual has the title of an officer. For any such PLAN YEAR, there shall be treated as officers no more than the lesser of: (A) 50 employees, or (B) the greater of three employees or 10 percent of the employees. For this purpose, the highest-paid officers shall be selected. Business organizations other than corporations shall be deemed to have no officers. (2) One of the ten employees owning (or considered as owning, within the meaning of the constructive ownership rules of the Internal Revenue CODE of 1954, as amended) the largest interests in the EMPLOYER (as defined in subsection (j)). An employee who has some ownership interest is considered to be one of the top ten owners unless at least ten other employees own a greater interest than that employee. However, an employee will not be considered a top ten owner for a PLAN YEAR if the employee earns less than the maximum dollar limitation on contributions and other annual additions to a PARTICIPANT's account in a defined contribution plan under the Internal Revenue CODE of 1954, as amended, as in effect for the calendar year in which the determination date falls. (3) Any person who owns (or is considered as owning within the meaning of the constructive ownership rules of the CODE more than five percent of the outstanding stock of the EMPLOYER or stock possessing more than five percent of the combined total voting power of all stock of the EMPLOYER. (4) A one percent owner of the EMPLOYER having an annual compensation from the EMPLOYER of more than $150,000, and possessing more than five percent of the combined total voting power of all stock of the EMPLOYER. For purposes of this subsection, compensation means all items includable as compensation for purposes of applying the limitations on contributions and other annual additions to a PARTICIPANT's account in a defined contribution plan and the maximum benefit payable under a defined plan under the Internal Revenue CODE of 1954, as amended. For purposes of parts (1), (2), (3) and (4) of this definition, a beneficiary of a key employee shall be treated as a key employee. For purposes of parts (3) and (4), each EMPLOYER is treated separately (without regard to the definition in subsection (j)) in determining ownership percentages; but, in determining the amount of compensation, the definition of EMPLOYER in subsection (j) is taken into account. (h) Non-Key Employee The term "non-key employee" means any employee (and any beneficiary of an employee) who is not a key employee. (i) Employer The term "employer" means EMPLOYER as defined in Section 22 of this PLAN. -69- 72 (j) Collective Bargaining Rules The provisions of subsection (b), (c) and (d) above do not apply with respect to any employee included in a unit of employees covered by a collective bargaining agreement unless the application of such subsections has been agreed upon with the collective bargaining agent. (k) Distributions to Key Employees Any other provisions of this PLAN to the contrary notwithstanding, distribution of the entire interest in this PLAN of each PARTICIPANT who is or any time has been a key employee shall commence no later than the end of the taxable year of the PARTICIPANT in which the PARTICIPANT attains age 70 1/2. SPECIAL PROVISION K I. Introduction This Special Provision K, an amendment to the COMPANY'S RETIREMENT PLAN, adopted by the COMPANY'S Board of Directors on December 17, 1986, is the controlling and definitive statement of the Voluntary Retirement Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus of COMPANY employees in certain designated operations. The VRI is a part of the RETIREMENT PLAN, and except as otherwise provided in this Special Provision K, shall be administered in accordance with and subject to the terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section 22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of Special Provision K. The decision of an Eligible Employee to elect to participate in the VRI is wholly voluntary, and an election not to participate in the VRI shall in no way affect benefits under the RETIREMENT PLAN to which an Eligible Employee might otherwise be entitled. II. Eligibility to Participate in the VRI Eligible Employees shall be any full-time active employee of the COMPANY or of a Participating Employer, born on or before January 1, 1937, who has at least 15 years of SERVICE on January 1, 1987. For purposes of this VRI only, the term active employee shall not include an employee of the COMPANY or a Participating Employer, (i) who, on January 1, 1987, is presently receiving benefits under Part B of the Group Life Insurance and Long Term Disability Plan; (ii) who, as of January 1, 1987, is on personal or medical leave, with or without pay; or (iii) who is a former employee whose ACTUAL RETIREMENT DATE was November 1, 1986, or earlier. Anything herein to the contrary notwithstanding, an Eligible Employee who (i) elects not to participate in the VRI and (ii) prior to January 1, 1988, is severed under the Company's Corporate Severance Program, shall be entitled to receive a Basic VRI Benefit under this Special Provision K. Such Basic VRI Benefit shall be in lieu of any benefits to which the Eligible EMPLOYEE would otherwise be entitled to receive under the Corporate Severance Program. For purposes of calculating the Basic VRI Benefit under this provision, the VRI Retirement Date shall be the first of the month following the month in which the employee is severed. -70- 73 III. Election to Participate An Eligible EMPLOYEE must elect to participate in the VRI by submitting a completed and signed VRI enrollment form which is received by a designated COMPANY representative no later than January 30, 1987, except that Eligible Employees who are employed by Pacific Gas Transmission Company will have until the close of business, September 30, 1987, to submit their completed and signed VRI enrollment form to a designated employer representative. An Eligible EMPLOYEE who fails to submit a timely enrollment form shall be deemed to have elected not to participate in the VRI. The election of an Eligible Employee not to participate in the VRI, whether through failure to timely submit a VRI election form or otherwise, shall be conclusive and binding on the employee, employee's spouse, heirs, and assigns. IV. VRI Benefit A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner to participate in the VRI shall be entitled to receive a Basic VRI Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit formula calculated under Subsection 6(a)(1), with the following adjustments: 1. BASIC MONTHLY SALARY shall mean the PARTICIPANT'S BASIC MONTHLY SALARY on January 1, 1986, increased by 5 percent; 2. SERVICE shall mean the PARTICIPANT'S SERVICE as of the VRI Retirement Date selected by the PARTICIPANT, increased by five years; and 3. The EARLY RETIREMENT PENSION reduction provisions of Subsection 7(b) shall not apply to any Basic VRI Benefit payable under this Special Provision K. B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date selected by the Eligible Employee and shall be paid as soon as practicable after the applicable VRI Retirement Date. Eligible Employees who elect to participate in the VRI shall not be subject to the age 55 requirement contained in Section 8. C. Section 10 of the RETIREMENT PLAN shall control the conditions under which other forms of pension may be substituted for the Basic VRI Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic VRI Benefit, if the PARTICIPANT is married, Section 10(b) of the RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a MARITAL PENSION, unless the PARTICIPANT'S spouse CONSENTS to an alternative form of pension. D. The Basic VRI Benefit payable under this Special Provision K shall be in lieu of any benefit which might otherwise be payable under the RETIREMENT PLAN. E. A participant who elects to participate in VRI shall also be entitled to make the elections provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Participant Contributions on Termination of Employment), 13 (Death Benefits), and 14 (Facility of Payment). -71- 74 V. VRI Retirement Dates At such time as an employee elects to participate in the VRI, he shall select a VRI Retirement Date. For purposes of this Special Provision K, a VRI Retirement Date shall mean one of the following: A. For Eligible Employees other than Eligible Employees employed by Pacific Gas Transmission Company: 1. February 1, 1987, provided, however, that eligible participants have completed all necessary VRI enrollment procedures prior to January 15, 1987; 2. March 1, 1987; 3. April 1, 1987; or 4. The first of any month during the period commencing with March 1, 1987, and ending with and including October 1, 1987. This Subsection V.A.4. shall only apply in the event that the COMPANY or the Participating Employer, as the case may be, has a demonstrated business need which requires the retention of the Eligible Employee. Should the business needs of the COMPANY or of a Participating Employer require the retention of an Eligible Employee beyond October 1, 1987, the VRI Retirement Date shall be the first of any month during the period subsequent to October 1, 1987, and ending with and including July 1, 1988. The selection of any such VRI Retirement Date subsequent to October 1, 1987, shall be made by the COMPANY, or Participating Employer, through an appropriate member of the COMPANY's Management Committee. B. For Eligible Employees employed by Pacific Gas Transmission Company: 1. October 1, 1987, provided, however, that eligible participants have completed all necessary VRI enrollment procedures prior to September 15, 1987; 2. November 1, 1987; or 3. The first of any month during the period commencing with December 1, 1987, and ending with and including June 1, 1988. This Subsection V.B.3. shall only apply in the event that Pacific Gas Transmission Company has a demonstrated need which requires the retention of the Eligible Employee. The VRI Retirement Date selected shall also be the date as of which an Eligible Employee ceases to be an employee of the COMPANY or a Participating Employer, as the case may be. VI. Revocation of Election An Eligible Employee who has elected to participate in the VRI may revoke his election, provided, however, that any such revocation shall only be effective if received by the COMPANY on or before January 30, 1987, for those Eligible Employees who elected a VRI Retirement Date of February 1, 1987; February 15, 1987, for those Eligible Employees who elected a VRI Retirement Date of March 1, 1987, or later; September 30, 1987, for those Eligible Employees of Pacific Gas Transmission Company who elected a VRI Retirement Date of October 1, 1987; or October 15, -72- 75 1987, for those Eligible Employees of Pacific Gas Transmission Company who elected a VRI Retirement Date of November 1, 1987, or later. VII. Definitions A. Basic VRI Benefit: The benefit calculated under Section IV of this Special Provision K. B. Eligible Employee: An employee of the COMPANY or of a Participating Employer who has met the eligibility criteria as set forth in Section II on January 1, 1987. For purposes of this Special Provision K only, Eligible Employee shall not include any COMPANY Officer at the vice presidential level, or above. C. Participating Employer: Natural Gas Corporation, Pacific Gas Transmission Company, and Pacific Service Employees Association. D. VRI: The COMPANY's Voluntary Retirement Incentive program as set forth in this Special Provision K. E. VRI Retirement Date: The date selected by an Eligible Employee under Section V of this Special Provision K. SPECIAL PROVISION M I. Introduction This Special Provision M, an amendment to the COMPANY'S RETIREMENT PLAN, adopted by the COMPANY'S Board of Directors on February 17, 1993, is the controlling and definitive statement of the Voluntary Retirement Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus of COMPANY employees in certain designated operations. The VRI is a part of the RETIREMENT PLAN, and except as otherwise provided in this Special Provision M, shall be administered in accordance with and subject to the terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section 22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of Special Provision M. The decision of an Eligible Employee to elect to participate in the VRI is wholly voluntary, and an election not to participate in the VRI shall in no way affect benefits under the RETIREMENT PLAN to which an Eligible Employee might otherwise be entitled. II. Eligibility to Participate in the VRI An Eligible Employee shall be any active employee of the COMPANY whose base job classification on February 17, 1993, is in a Targeted Organization and who was born on or before December 31, 1942, and has at least 15 years of SERVICE on December 31, 1992. For purposes of this VRI only, the term active employee shall not include an employee of the COMPANY (i) who, on February 17, 1993, is presently receiving benefits under Part B of the Group Life Insurance and Long Term Disability Plan; (ii) who is on a leave of absence, with or without pay, which began on or prior to August 17, 1992; or (iii) who is a former employee whose ACTUAL RETIREMENT DATE was February 1, 1993, or earlier. -73- 76 III. Election to Participate An Eligible Employee must elect to participate in the VRI by submitting a completed and signed VRI enrollment form which is received by a designated COMPANY representative no later than April 23, 1993. An Eligible Employee who fails to submit a timely enrollment form shall be deemed to have elected not to participate in the VRI. The election of an Eligible Employee not to participate in the VRI, whether through failure to submit a timely VRI election form or otherwise, shall be conclusive and binding on the employee, employee's spouse, heirs, and assigns. IV. VRI Benefit A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner to participate in the VRI shall be entitled to receive a Basic VRI Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit formula calculated under Subsection 6(a)(1), with the following adjustments: 1. SERVICE shall mean the PARTICIPANT'S SERVICE as of last VRI Retirement Date for such Eligible Employee, increased by three years; and 2. The EARLY RETIREMENT PENSION reduction provisions of Subsection 7(b) shall not apply to any Basic VRI Benefit payable under this Special Provision M. B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date selected by the Eligible Employee and shall be paid as soon as practicable after the applicable VRI Retirement Date. Eligible Employees who elect to participate in the VRI shall not be subject to the age 55 requirement contained in Section 8. C. Section 10 of the RETIREMENT PLAN shall control the conditions under which other forms of pension may be substituted for the Basic VRI Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic VRI Benefit, if the PARTICIPANT is married, Section 10(b) of the RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a MARITAL PENSION, unless the PARTICIPANT'S spouse CONSENTS to an alternative form of pension. D. The Basic VRI Benefit payable under this Special Provision M shall be in lieu of any benefit which might otherwise be payable under the RETIREMENT PLAN. E. A participant who elects to participate in VRI shall also be entitled to make the elections provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Participant Contributions on Termination of Employment), 13 (Death Benefits), and 14 (Facility of Payment). V. VRI Retirement Dates At such time as an employee elects to participate in the VRI, he shall select a VRI Retirement Date. For purposes of this Special Provision M, a VRI Retirement Date shall mean one of the following: A. May 1, 1993; B. June 1, 1993; or -74- 77 C. The first of any month during the period commencing with July 1, 1993, and ending with and including June 1, 1994. This Subsection C shall only apply in the event that the COMPANY has a demonstrated business need which requires the retention of the Eligible Employee. The selection of any such VRI Retirement Date subsequent to June 1, 1993, can be made only with the written approval of both of the Company's Executive Vice Presidents. The VRI Retirement Date selected shall also be the date as of which an Eligible Employee ceases to be an employee of the COMPANY. VI. Revocation of Election An Eligible Employee who has elected to participate in the VRI may revoke his election, provided, however, that any such revocation shall only be effective if received by the COMPANY on or before April 23, 1993, for those Eligible Employees who elected a VRI Retirement Date of May 1, 1993; or April 30, 1993, for those Eligible Employees who elected a VRI Retirement Date of June 1, 1993, or later. VII. Definitions A. Basic VRI Benefit: The benefit calculated under Section IV of this Special Provision M. B. Eligible Employee: An employee of the COMPANY who has met the eligibility criteria as set forth in Section II. For purposes of this Special Provision M only, Eligible Employee shall not include any COMPANY Officer. C. Targeted Organization: Distribution Business Unit; Engineering and Construction Business Unit; Gas Supply Business Unit except the Gas Dispatch Department and except employees with job levels of 32 and above; Nuclear Operations Support Department; Nuclear Safety and Regulatory Affairs Department; Nuclear Engineering and Construction Services Department; Nuclear Business and Financial Management Department; Nuclear Documentation and Support Department; Quality Assurance Department; human resources departments, including business unit human resources organizations being consolidated with corporate human resources; computer and telecommunication services departments, including business unit and corporate services organizations being consolidated with corporate computer and telecommunication services departments; Corporate Communications departments, including business unit media and employee communications units being consolidated with Corporate Communi- cations departments; community and governmental relations departments including regional public affairs units being consolidated with corporate governmental relations departments; and the Economics and Forecasting Department. D. VRI: The COMPANY's Voluntary Retirement Incentive program as set forth in this Special Provision M. E. VRI Retirement Date: The date selected by an Eligible Employee under Section V of this Special Provision M. -75- 78 SPECIAL PROVISION N I. Introduction This Special Provision N, an amendment to the COMPANY'S RETIREMENT PLAN, authorized by the COMPANY'S Board of Directors on September 21, 1994, is the controlling and definitive statement of the Voluntary Retirement Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus of COMPANY EMPLOYEES. The VRI is a part of the RETIREMENT PLAN, and except as otherwise provided in this Special Provision N, shall be administered in accordance with and subject to the terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section 22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of Special Provision N. The decision of an Eligible Employee to elect to participate in the VRI is wholly voluntary, and an election not to participate in the VRI shall in no way affect benefits under the RETIREMENT PLAN to which an Eligible Employee might otherwise be entitled. II. Eligibility to Participate in the VRI An Eligible Employee shall be any active EMPLOYEE of the COMPANY who was born on or before September 30, 1944, and has at least 15 years of SERVICE on September 30, 1994. For purposes of this VRI only, the term active EMPLOYEE shall not include an EMPLOYEE of the COMPANY (i) who, on September 30, 1994, is presently receiving benefits under Part B of the Group Life Insurance and Long Term Disability Plan; (ii) who is on a leave of absence, with or without pay, which began on or prior to March 30, 1994; (iii) who elected to retire under Special Provision M of Part I of the RETIREMENT PLAN or Special Provision N of Part II of the RETIREMENT PLAN; (iv) who has received or is scheduled to receive severance benefits under the COMPANY'S Workforce Management Program, Letter Agreement No. 93-42-PGE and Letter Agreement No. 93-23esc, or under any other written agreement between the COMPANY and the EMPLOYEE in which the EMPLOYEE has received benefits in connection with the termination of such EMPLOYEE'S employment; (v) who is a former EMPLOYEE who was terminated for cause; or (vi) who is a former EMPLOYEE whose ACTUAL RETIREMENT DATE was July 1, 1994, or earlier. III. Election to Participate An Eligible Employee must elect to participate in the VRI by completing and signing the VRI enrollment and waiver and release forms provided by the COMPANY and returning the completed forms to a designated COMPANY representative no later than November 21, 1994. An Eligible Employee who fails to submit timely both enrollment and waiver and release forms shall be deemed to have elected not to participate in the VRI. The election of an Eligible Employee not to participate in the VRI, whether through failure to timely submit VRI election and waiver and release forms or otherwise, shall be conclusive and binding on the EMPLOYEE, EMPLOYEE'S spouse, heirs, and assigns. IV. VRI Benefit A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner to participate in the VRI shall be entitled to receive a Basic VRI Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit formula calculated under Subsection 6(a)(1) with the following adjustments: -76- 79 1. SERVICE shall mean the PARTICIPANT'S SERVICE as of the VRI Retirement Date for such Eligible Employee, increased by three years; and 2. The EARLY RETIREMENT PENSION reduction provisions of Subsection 7(b) shall not apply to any Basic VRI Benefit payable under this Special Provision N. B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date and shall be paid as soon as practicable after the applicable VRI Retirement Date. Eligible Employees who elect to participate in the VRI shall not be subject to the age 55 requirement contained in Section 8. C. Section 10 of the RETIREMENT PLAN shall control the conditions under which other forms of pension may be substituted for the Basic VRI Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic VRI Benefit, if the PARTICIPANT is married, Subsection 10(b) of the RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a MARITAL PENSION, unless the PARTICIPANT'S spouse consents to an alternative form of pension. D. The Basic VRI Benefit payable under this Special Provision N shall be in lieu of any benefit which might otherwise be payable under the RETIREMENT PLAN. E. A PARTICIPANT who elects to participate in VRI shall also be entitled to make the elections provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Participant Contributions on Termination of Employment), 13 (Death Benefits), and 14 (Facility of Payment). V. VRI Retirement Dates At such time as an EMPLOYEE elects to participate in the VRI, he shall select a VRI Retirement Date. For purposes of this Special Provision N, a VRI Retirement Date shall mean one of the following: A. January 1, 1995; or B. The first of any month during the period commencing with February 1, 1995, and ending with and including January 1, 1996. This Subsection B shall only apply in the event that the COMPANY has a demonstrated business need which requires the retention of the Eligible Employee. The selection of any such VRI Retirement Date subsequent to January 1, 1995, can be made only with the written approval of the COMPANY'S Chief Executive Officer. The VRI Retirement Date selected shall also be the date as of which an Eligible Employee ceases to be an EMPLOYEE of the COMPANY. VI. Revocation of Election An Eligible Employee who has elected to participate in the VRI may revoke his election, provided, however, that any such revocation shall only be effective if received by the COMPANY on or before November 28, 1994. -77- 80 VII. Definitions A. Basic VRI Benefit: The benefit calculated under Section IV of this Special Provision N. B. Eligible Employee: An EMPLOYEE of the COMPANY who has met the eligibility criteria as set forth in Section II. EMPLOYEES of Pacific Gas Transmission Company, PG&E Enterprises, Pacific Service Employees Association, and any other subsidiary or affiliate of the COMPANY are not Eligible Employees for purposes of this VRI. C. VRI: The COMPANY's Voluntary Retirement Incentive program as set forth in this Special Provision N. D. VRI Retirement Date: The date selected by an Eligible Employee under Section V of this Special Provision N. -78- EX-12.1 7 COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES 1 EXHIBIT 12.1 PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES RESTATED COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1994 1993 1992 1991 1990 ---------- ---------- ---------- ---------- ---------- (DOLLARS IN THOUSANDS) Earnings: Net income......................... $1,007,450 $1,065,495 $1,170,581 $1,026,392 $ 987,170 Adjustments for losses of consolidated less than 100% owned affiliates and the Company's equity in undistributed loss (earnings) of unconsolidated affiliates....... (2,764) 6,895 (3,349) 26,671 (2,799) Income tax expense................. 836,767 901,890 895,126 851,534 881,647 Net fixed charges.................. 730,965 821,166 802,198 776,682 812,568 ---------- ---------- ---------- ---------- ---------- Total Earnings.................. $2,572,418 $2,795,446 $2,864,556 $2,681,279 $2,678,586 ========= ========= ========= ========= ========= Fixed Charges: Interest on long-term debt......... $ 651,912 $ 731,610 $ 739,279 $ 697,185 $ 699,849 Interest on short-term debt........ 77,295 87,819 61,182 77,760 110,982 Interest on capital leases......... 1,758 1,737 1,737 1,737 1,737 Capitalized Interest............... 2,660 46,055 6,511 6,107 7,214 ---------- ---------- ---------- ---------- ---------- Total Fixed Charges............. $ 733,625 $ 867,221 $ 808,709 $ 782,789 $ 819,782 ========= ========= ========= ========= ========= Ratios of Earnings to Fixed Charges............................ 3.51 3.22 3.54 3.43 3.27
- --------------- Note: For the purpose of computing the Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for losses of consolidated less than 100% owned affiliates, the Company's equity in undistributed earnings or loss of unconsolidated affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" consist of interest on short-term and long-term debt (including amounts capitalized and amortization of bond premium, discount and expense; and excluding interest on decommissioning trust funds [for which an equal amount of interest income is recorded]) and interest on capital leases. EX-12.2 8 COMPUTATION OF RATIOS OF EARNINGS TO COMB. FIXED 1 EXHIBIT 12.2 PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES RESTATED COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
YEAR ENDED DECEMBER 31, ---------------------------------------------------------------------- 1994 1993 1992 1991 1990 ---------- ---------- ---------- ---------- ---------- (DOLLARS IN THOUSANDS) Earnings: Net income................. $1,007,450 $1,065,495 $1,170,581 $1,026,392 $ 987,170 Adjustments for losses of consolidated less than 100% owned affiliates and the Company's equity in undistributed loss (earnings) of unconsolidated affiliates.............. (2,764) 6,895 (3,349) 26,671 (2,799) Income tax expense......... 836,767 901,890 895,126 851,534 881,647 Net fixed charges.......... 730,965 821,166 802,198 776,682 812,568 ---------- ---------- ---------- ---------- ---------- Total Earnings..... $2,572,418 $2,795,446 $2,864,556 $2,681,279 $2,678,586 ========= ========= ========= ========= ========= Fixed Charges: Interest on long-term debt.................... $ 651,912 $ 731,610 $ 739,279 $ 697,185 $ 699,849 Interest on short-term debt.................... 77,295 87,819 61,182 77,760 110,982 Interest on capital leases.................. 1,758 1,737 1,737 1,737 1,737 Capitalized Interest....... 2,660 46,055 6,511 6,107 7,214 ---------- ---------- ---------- ---------- ---------- Total Fixed Charges.......... 733,625 867,221 808,709 782,789 819,782 ---------- ---------- ---------- ---------- ---------- Preferred Stock Dividends: Tax deductible dividends... 4,672 4,814 5,136 5,136 5,136 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements............ 96,039 108,937 130,147 154,404 175,881 ---------- ---------- ---------- ---------- ---------- Total Preferred Stock Dividends........ 100,711 113,751 135,283 159,540 181,017 ---------- ---------- ---------- ---------- ---------- Total Combined Fixed Charges and Preferred Stock Dividends.................. $ 834,336 $ 980,972 $ 943,992 $ 942,329 $1,000,799 ========= ========= ========= ========= ========= Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends.................. 3.08 2.85 3.03 2.85 2.68
- --------------- Note: For the purpose of computing the Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for losses of consolidated less than 100% owned affiliates, the Company's equity in undistributed earnings or loss of unconsolidated affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" consist of interest on short-term and long-term debt (including amounts capitalized and amortization of bond premium, discount and expense; and excluding interest on decommissioning trust funds [for which an equal amount of interest income is recorded]) and interest on capital leases. "Preferred stock dividends" represent the sum of requirements for preferred stock dividends that are deductible for federal income tax purposes and requirements for preferred stock dividends that are not deductible for federal income tax purposes increased to an amount representing pretax earnings which would be required to cover such dividend requirements. EX-13 9 1994 ANNUAL REPORT TO SHAREHOLDERS (PORTIONS) 1 Exhibit 13 Pacific Gas and Electric Company SELECTED FINANCIAL DATA (in thousands, except per share amounts)
1994 1993 1992 1991 1990 FOR THE YEAR Operating revenues $10,447,351 $10,582,408 $10,296,088 $ 9,778,119 $ 9,470,092 Operating income 1,633,359 1,762,930 1,833,441 1,713,079 1,706,136 Net income 1,007,450 1,065,495 1,170,581 1,026,392 987,170 Earnings per common share 2.21 2.33 2.58 2.24 2.10 Dividends declared per common share 1.96 1.88 1.76 1.64 1.52 AT YEAR END Book value per common share $20.07 $19.77 $19.41 $18.40 $17.86 Common stock price per share 24.38 35.13 33.13 32.63 25.00 Total assets 27,809,133 27,162,526 24,188,159 22,900,670 21,958,397 Long-term debt and preferred stock with mandatory redemption provision (excluding current portions) 8,812,591 9,367,100 8,525,948 8,341,310 7,902,409
Matters relating to certain data above are discussed in Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition and in Notes to Consolidated Financial Statements. 12 2 Pacific Gas and Electric Company MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION Pacific Gas and Electric Company (PG&E) and its wholly owned and majority-owned subsidiaries (collectively, the Company) have three types of operations: utility, Diablo Canyon Nuclear Power Plant (Diablo Canyon) and nonregulated through PG&E Enterprises (Enterprises). The Company is engaged principally in the business of supplying electric and natural gas service throughout most of Northern and Central California. The Company's operations are regulated by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC), among others. Competition and Changing Regulatory Environment: Recent changes in both the gas and electric industries have allowed competition to develop in the gas supply and electric generation segments of the Company's business. A number of reforms at both the federal and state level have been proposed. These reforms are designed to restructure regulation in the energy supply industry and promote competition by providing electric and gas customers with purchasing options. As a result of the restructuring of the natural gas industry, the Company no longer provides combined purchase and transportation services to many of its industrial and large commercial gas customers. Instead, most of these customers now procure their gas supplies from a source other than the Company while purchasing transportation service from the Company. These customers can also use alternative transportation services available within the Company's service territory. In November 1994, the FERC approved the expansion of a competing company's natural gas pipeline into the Company's service territory. This pipeline could compete directly for transportation service to several of the Company's large customers as soon as January 1, 1996, and may result in the loss of sales on the Company's gas transportation system. While the restructuring of the electric industry is still evolving, proposals being considered are expected to bring increased competition into the electric generation business. At the federal level, the National Energy Policy Act of 1992 (Energy Act) reduces various restrictions on the operation and ownership of independent power producers and provides them and other wholesale suppliers and purchasers with increased access to electric transmission lines throughout the United States. At the state level, in April 1994, the CPUC issued a proposal on electric industry restructuring which seeks to lower energy prices and provide customers with a choice of electric generation suppliers (known as direct access). This proposal involves two key strategies: One, phase in direct access to electric generation for all customers over a six-year period beginning in 1996; two, where competition does not exist, replace traditional cost-of-service regulation with performance-based regulation (PBR). To ensure a transition that maintains the financial integrity of the utilities, the CPUC proposed that uneconomic costs of utility generating assets resulting from its proposal be recovered through a "competition transition charge." However, the CPUC proposal did not specify which costs might be recovered through such a transition charge or how such a charge would be allocated to and collected from customers. The Company has filed a response to the CPUC proposal embracing the objective of lower prices and supporting increased competition, but recommending a longer phase-in period to direct access to permit an orderly transition. Based on market prices of $.048 and $.032 per kilowatthour (kWh), the Company estimated that its uneconomic generating assets and obligations are approximately $3 billion and $11 billion, respectively, resulting from the restructuring as proposed by the CPUC. The Company identified three categories of uneconomic assets: utility-owned generation assets and power purchase commitments, power purchase obligations relating to qualifying facilities (QFs) and generation-related regulatory assets. The estimates of uneconomic assets were determined by comparing the future revenue requirements of generation assets and power purchase obligations over a twenty-year and thirty-year period, respectively, with revenues computed at the assumed market price. Diablo Canyon was included in the revenue requirement calculation using the proposed pricing modifications to the Diablo Canyon settlement. (See Operating Revenues.) The revenue requirement for Diablo Canyon and all Company-owned generation assets included a return on investment. The actual amount of uneconomic assets and obligations will depend upon the final regulation and the actual market price of electricity. The Company intends to seek recovery of its uneconomic assets and obligations through the competition transition charge. (See Note 2 of Notes to Consolidated Financial Statements.) In addition to working with the CPUC on this proposal, the Company has made several proposals to modify existing regulatory processes and to provide additional pricing flexibility to those customers with the most competitive options. The Company has proposed instituting PBR for determining nonfuel revenues, under which electric and natural gas 13 3 revenues would be determined annually by formula rather than through general rate cases (GRCs), attrition rate adjustments and cost of capital proceedings. The Company has also proposed a gas procurement incentive mechanism that would replace after-the-fact reasonableness reviews of certain costs. This proposed mechanism would measure the Company's gas procurement costs against market benchmarks and would provide for the sharing, between ratepayers and shareholders, of variances from a preset range around the market benchmark. The shifting of utility regulation from traditional cost-of-service based concepts to concepts based upon market competition and benchmarks will place greater emphasis on the Company's ability to provide valued products and services at competitive prices. The Company has announced a five-year goal of reducing its system-wide average electric rates. In addition, the Company has taken several significant actions to position itself to effectively compete in the restructured electric and gas industries. Specifically, the Company has: - Extended through 1995 its electric rate freeze which began in 1993. - Proposed a modification of the Diablo Canyon settlement to reduce the price paid for electricity generated at Diablo Canyon over the next five years. - Reduced electric rates for certain of its largest industrial customers through an economic stimulus rate that will extend through the end of 1995. - Planned reductions in annual spending in 1995 of approximately $600 million from 1993 spending levels. - Refinanced debt and preferred stock over the last three years resulting in annual savings of approximately $97 million in financing costs. The Company cannot predict the ultimate outcome of the ongoing changes that are taking place in the utility industry. However, management believes the end result will involve a fundamental change in the way the Company conducts its business. These changes may impact financial operating trends and add volatility to the Company's earnings. Management is actively seeking regulatory and operational changes that will allow the Company to provide energy services in a safe, reliable and competitive manner while achieving strong financial performance. Accounting for the Effects of Regulation: The transition to a competitive market environment may affect the Company's future revenues and cash flows. In the event that recovery of the Company's costs and investments becomes unlikely or uncertain due to competitive pressures or regulatory changes, it could cause the Company to write off applicable portions of its regulatory assets. The final CPUC determination of uneconomic costs and the method of recovery could adversely affect the Company's returns on its investments in electric generation assets. If future electric generation revenues are insufficient to recover the Company's investments and QF obligations, the Company would recognize a loss. The Company currently accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result of applying the provisions of SFAS No. 71, the Company has accumulated approximately $3.7 billion of regulatory assets, including balancing accounts, at December 31, 1994. As discussed further in Note 2 of Notes to Consolidated Financial Statements, if the CPUC's electric industry restructuring proposal is adopted as proposed or the Company determines that future electric generation rates will no longer be based on cost-of-service, the Company will discontinue application of SFAS No. 71 for the electric generation portion of its operations. If such discontinuance should occur, the Company would write off all applicable electric generation-related regulatory assets to the extent that transition cost recovery is not assured. The regulatory assets attributable to electric generation, excluding balancing accounts of approximately $700 million which are expected to be recovered in the near term, are estimated to be $1.6 billion at December 31, 1994. The final determination of the financial impact will depend on the form of regulation, including transition mechanisms, if any, adopted by the CPUC and the groups of customers affected. Currently, the Company is unable to predict the ultimate outcome of the electric industry restructuring or predict whether such outcome will have a significant impact on its financial position or results of operations. Proposed Accounting Standard: The Financial Accounting Standards Board (FASB) has proposed a new accounting standard, "Accounting for the Impairment of Long-Lived Assets," which is expected to be issued in early 1995. The Company would be required to adopt the new standard beginning January 1, 1996, but may elect to adopt it earlier. If issued by the FASB as proposed, the new standard would require, among other things, that regulatory assets recorded as a result of SFAS No. 71 continue to be probable of recovery in 14 4 rates at all times, rather than only at the time the regulatory asset is recorded. As such, regulatory assets currently recorded may require adjustment in the future if recovery is no longer probable. Under the current ratemaking, the Company does not believe there would be any immediate significant impact of adopting the standard, as proposed. Results of Operations The Company's results of operations for the three years ended December 31, 1994, are reflected in the following table and discussed below.
Diablo (in millions, except per share amounts) Utility Canyon (1) Enterprises Total 1994 Operating revenues $ 8,329 $1,870 $ 248 $10,447 Operating expenses 7,281 1,252 281 8,814 ------- ------ ------ ------- Operating income (loss) $ 1,048 $ 618 $ (33) $ 1,633 ======= ====== ====== ======= Net income $ 541 $ 461 $ 5 $ 1,007 ======= ====== ====== ======= Earnings per common share $ 1.16 $ 1.04 $ .01 $ 2.21 ======= ====== ====== ======= Total assets at year end $20,303 $5,978 $1,528 $27,809 ======= ====== ====== ======= 1993 Operating revenues $ 8,398 $1,933 $ 251 $10,582 Operating expenses 7,335 1,225 259 8,819 ------- ------ ------ ------- Operating income (loss) $ 1,063 $ 708 $ (8) $ 1,763 ======= ====== ====== ======= Net income $ 552 $ 496 $ 17 $ 1,065 ======= ====== ====== ======= Earnings per common share $ 1.18 $ 1.11 $ .04 $ 2.33 ======= ====== ====== ======= Total assets at year end $19,870 $6,250 $1,043 $27,163 ======= ====== ====== ======= 1992 Operating revenues $ 8,306 $1,781 $ 209 $10,296 Operating expenses 7,125 1,118 220 8,463 ------- ------ ------ ------- Operating income (loss) $ 1,181 $ 663 $ (11) $ 1,833 ======= ====== ====== ======= Net income (loss) $ 738 $ 443 $ (10) $ 1,171 ======= ====== ====== ======= Earnings (loss) per common share $ 1.61 $ .99 $ (.02) $ 2.58 ======= ====== ====== ======= Total assets at year end $17,759 $5,494 $ 935 $24,188 ======= ====== ====== =======
(1) See Note 4 of Notes to Consolidated Financial Statements for discussion of allocations. Earnings Per Common Share: Earnings per common share were $2.21, $2.33 and $2.58 for 1994, 1993 and 1992, respectively. Earnings per common share for 1994 were lower than for 1993 primarily due to the refueling of both units of Diablo Canyon in 1994 compared to only one unit in 1993. In 1994, the Company recorded special charges for workforce reductions, gas reasonableness matters, contingencies related to gas transportation commitments and an increase in litigation reserves which in the aggregate totaled approximately $434 million. Special charges in 1993 totaled approximately $410 million and included charges for workforce reductions, gas decontracting, gas reasonableness matters, contingencies related to gas transportation commitments and the impact of increasing the federal income tax rate to 35 percent. Earnings per common share for 1993 were lower than for 1992 due to charges against earnings discussed above. These charges were partially offset by higher Diablo Canyon revenues due to the annual increase in the price per kWh as provided in the Diablo Canyon settlement. Since the Diablo Canyon settlement in 1988, Diablo Canyon has made an increasing contribution to the Company's total earnings per share. For the year ended December 31, 1994, Diablo Canyon contributed $1.04 (47 percent) to the total earnings per share of $2.21. The proposed modification of the price for power produced by Diablo Canyon, discussed below, will likely cause a decrease in the Diablo Canyon earnings per share contribution. On a consolidated basis, the Company earned an 11.1 percent, 11.9 percent and 13.7 percent return on average common stock equity for the years ended December 31, 1994, 1993 and 1992, respectively. For 1995, the CPUC has authorized a return on average common stock equity of 12.1 percent for the Company's utility operations. Common Stock Dividend: In January 1995, the Board of Directors (Board) declared a quarterly dividend of $.49 per share which corresponds to an annualized dividend of $1.96 per share. The Company's common stock dividend is based on a number of financial considerations, including sustainability, financial flexibility and competitiveness with investment opportunities of similar risk. The Company has a long-term objective of reducing its dividend payout ratio (dividends declared divided by earnings available for common stock) to reflect the increased business risk in the utility industry. At this time, the Company is unable to determine the impact, if any, the restructuring of the electric industry will have on the Company's ability to increase its dividends in the future. 15 5 Operating Revenues: Electric revenues increased $162 million, $119 million and $378 million in 1994, 1993 and 1992, respectively, compared to the preceding year. Despite the rate freeze, electric revenues increased due to higher energy costs in 1994 reflected in the electric energy cost balancing account. The higher revenues from the energy cost balancing account were offset by the decrease in revenues from Diablo Canyon resulting from the refueling of both units of the nuclear power plant in 1994 as compared with only one unit in 1993. The Company will continue through the end of 1995 its freeze on electric rates which began in 1993. The increase in 1993 electric revenues was due to rate increases associated with general increases in operating expenses and a higher electric rate base on which PG&E is allowed to earn a return. This increase was offset by a decrease in revenues resulting from a decrease in the cost of electric energy. In addition, Diablo Canyon revenues, which are included in the electric revenues discussed above, increased due to the annual increase in the price per kWh as provided in the Diablo Canyon settlement. The 1992 increase in electric revenues was primarily due to one scheduled refueling outage at Diablo Canyon as compared with two scheduled refueling outages in 1991, and the annual increase in the price per kWh as provided in the Diablo Canyon settlement. The Diablo Canyon settlement, which became effective July 1988, bases revenues for the plant primarily on the amount of electricity generated, rather than on traditional cost-based ratemaking. Under this "performance-based" approach, the Company assumes a significant portion of the operating risk of the plant because the extent and timing of the recovery of actual operating costs, depreciation and a return on the investment in the plant primarily depend on the amount of power produced and the level of costs incurred. As discussed further in Note 4 of Notes to Consolidated Financial Statements, in December 1994, the Company, a consumer advocacy branch of the CPUC staff (the Division of Ratepayer Advocates (DRA)), the California Attorney General and several other parties representing energy consumers have agreed to modify the pricing provisions of the Diablo Canyon settlement, subject to CPUC approval. Under the proposed modification, the price for power produced by Diablo Canyon would be reduced from what it would have been under the original terms of the Diablo Canyon settlement. The Diablo Canyon capacity factors for 1994, 1993 and 1992 were 81 percent, 89 percent and 88 percent, respectively, reflecting the scheduled refueling outages for Units 1 and 2 in 1994, Unit 2 in 1993 and Unit 1 in 1992. The 1994 capacity factors were also impacted by 24 days of extended unscheduled outages. There were no extended unscheduled outages in 1993 or 1992. Through December 31, 1994, the lifetime capacity factor for Diablo Canyon was 79 percent. The Company will report significantly lower revenues for Diablo Canyon during any extended outages, including refueling outages. Refueling outages, the length of which depend on the scope of the work, typically occur for each unit every eighteen months. The next refueling outages for Unit 1 and Unit 2 are scheduled to begin in September 1995 and March 1996, respectively, and each is planned to last about six weeks. Under the proposed modification to the prices prescribed in the Diablo Canyon settlement, each Diablo Canyon unit will contribute approximately $2.9 million in revenues per day at full operating power in 1995. The daily revenues could decline each year for the next five years. Gas revenues decreased $297 million in 1994 compared to the preceding year primarily due to a decrease in revenues received from our industrial and large commercial customers, who are now arranging for the purchase of their own gas supplies, with the Company providing only transportation service partially offset by revenues generated from the natural gas transmission expansion project. (See Regulatory Matters.) Gas revenues increased $168 million and $140 million in 1993 and 1992, respectively, compared to the preceding year. The 1993 increase was primarily due to rate increases associated with general increases in operating expenses and a higher gas rate base on which PG&E is allowed to earn a return, as well as increased revenues from Enterprises reflecting increases in the price and production of gas. The 1992 increase in gas revenues was primarily due to revenues resulting from the December 1991 acquisition of Tex/Con Oil & Gas Company by DALEN Resources Corp. (DALEN), a wholly owned subsidiary of Enterprises. 16 6 Operating Expenses: Operating expenses in 1994 remained constant as compared to 1993. The 1994 operating expenses include a charge against earnings of $249 million related to the workforce reductions that commenced in 1994. In comparison, the Company expensed $190 million related to the 1993 workforce reductions. As a result of the 1993 workforce reductions, administrative and general expense was less in 1994 as compared to 1993. The cost of electric energy was $312 million greater in 1994 as compared to 1993 primarily due to less favorable hydro conditions and an increase in the cost per kWh of purchased power. These unfavorable variances were offset by a favorable variance of $365 million in the cost of gas as a result of the Company no longer procuring gas for certain customers. Income tax expense has declined due to lower operating income in 1994. In 1993 and 1992, the Company's operating expenses increased $357 million and $398 million, respectively, over the preceding year. The 1993 increase was due to the charge related to the Company's 1993 workforce reductions and increases in administrative and general expense, income tax expense, and depreciation and decommissioning expense, partially offset by a decrease in the cost of electric energy. Most of the $114 million increase in administrative and general expense was due to an increase in litigation costs and an increase in employee benefit costs upon adoption of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." The $100 million increase in income tax expense was primarily due to the increase in the federal income tax rate to 35 percent. The $166 million decrease in the cost of electric energy was a result of improved hydro conditions and reflects a decline in the cost per kWh for purchased power. The 1992 increase in operating expenses was primarily due to increases in the cost of gas, the cost of electric energy, and depreciation and decommissioning expense. Other Income and (Income Deductions): Other--net includes charges in 1994 and 1993 related to gas issues. The 1994 charges consist of accruals for gas reasonableness matters, including proposed settlement agreements and contingencies related to transportation capacity commitments. (See Note 3 of Notes to Consolidated Financial Statements.) The 1993 charges include accruals for gas reasonableness matters and contingencies related to transportation capacity commitments as well as charges associated with restructuring the Company's Canadian gas supply arrangements. Regulatory Matters: In addition to the CPUC electric industry restructuring proposal, discussed further in Note 2 of Notes to Consolidated Financial Statements, during 1994 the Company received CPUC decisions in proceedings on revenues and energy costs and filed applications which will impact rates in 1995 and beyond. The most significant of these are discussed below. The CPUC has approved the Company's request to freeze retail electric rates through the end of 1995. In order to accomplish the rate freeze, rate increases attributable to energy costs and the increase in the authorized rate of return were offset by base revenue reductions. The Company is implementing base cost reductions which are reflected in the decreased base revenues. Gas rates for commodity, transportation and base costs have increased as a result of two decisions during 1994. In July, the CPUC approved a $162 million increase for recovery of previously deferred gas and transportation costs. In December, a $100 million increase in revenue was approved reflecting an increase in the cost of capital, balancing accounts adjustments and inflationary increases in costs. In addition, the Company filed an application with the CPUC requesting a gas rate increase of approximately $173 million annually for the two-year period beginning in October 1, 1995. The Company's request reflects an increase in gas and transportation costs and the collection of amounts previously deferred in balancing accounts. If the Company's request is adopted, rates would be effective September 15, 1995. In January 1995, the Company updated its 1996 GRC application to reflect CPUC decisions that went into effect on January 1, 1995. In the GRC, the Company is seeking a $162 million decrease for electric revenues and a $92 million decrease for gas revenues, compared to rates in effect in 1994. (Compared to rates in effect in 1995, there would be no change for electric revenues and a $162 million decrease for gas revenues.) Revenues to be collected from customers in 1996 may also be affected by future requests related to energy costs and cost of capital. In November 1993, the Company placed in service an expansion of its natural gas transmission system from the Canadian border into California. The pipeline provides 17 7 additional firm capacity to the Pacific Northwest and to Northern and Southern California. The total cost of construction is approximately $1.7 billion. The Company has filed applications with the FERC (for the interstate portion) and the CPUC (for the portion within California) requesting that capital and operating costs be found reasonable. Revenues are currently being collected under rates approved by the FERC and the CPUC, subject to refund. The Company believes the final decisions on these applications will not have a significant impact on its financial position or results of operations. In accordance with mechanisms established by the CPUC, the Company accumulates the difference between actual costs of generating electricity and the revenues designed to recover such costs. To the extent costs exceed revenues, the undercollection accumulates in the electric energy cost balancing account. Over the past few years, the Company has experienced a significant increase in the level of balancing account undercollection related to its electric energy costs. The increase primarily results from Diablo Canyon's generation exceeding that forecasted in the annual electric energy cost proceeding, increased fuel costs, the use of higher-cost energy sources to compensate for less than normal hydro conditions and the deferred recovery of undercollected balances. At December 31, 1994, the electric energy cost balancing account undercollection was approximately $716 million. In order to accomplish its freeze on retail electric rates, the Company will be deferring the recovery of $444 million of the electric energy cost undercollection beyond 1995 and will also forgo collection of interest on these deferred costs. Recovery of these deferred costs will depend on a number of factors. However, the Company currently believes that the amount deferred will be collected through rates over the near term. The modification of the price for Diablo Canyon power will assist in reducing the undercollected energy cost balance. Nonregulated Operations: The Company, through its wholly owned subsidiary, Enterprises, has taken steps to position itself to compete in the nonregulated energy business. Enterprises contributed $.01, $.04 and $(.02) per share to the Company's total earnings per share for the years ended December 31, 1994, 1993 and 1992, respectively. Enterprises makes the majority of its investments in nonregulated energy projects through a joint venture, U.S. Generating. Enterprises in partnership with Bechtel Enterprises, Inc. is in the process of forming a company to develop, build, own and operate international nonutility generation projects. In August 1994, Enterprises and Bechtel Enterprises, Inc. completed their acquisition of J. Makowski Co., Inc. (JMC), a Boston-based company engaged in the development of natural gas-fueled power generation projects and natural gas distribution, supply and underground storage projects. The final purchase price was approximately $250 million. Enterprises' effective ownership share of JMC is approximately 80 percent. In July 1994, the Company's Board approved a plan for the disposition of DALEN, formerly PG&E Resources Company, through an initial public offering of DALEN's common stock, as DALEN no longer fits Enterprises' business strategy. The disposition, if completed, is not anticipated to have a significant impact on the Company's financial position or results of operations. Liquidity and Capital Resources Sources of Capital: The Company's capital requirements are funded from cash provided by operations and, to the extent necessary, external financing. The Company's capital structure provides financial flexibility and access to capital markets at reasonable rates, ensuring the Company's ability to meet all of its capital requirements. Proceeds from the issuance of securities are used for capital expenditures, refundings and other general corporate purposes. Debt: In 1994, the Company issued $30 million of medium-term notes and redeemed or repurchased $135 million of mortgage bonds, medium-term notes and Eurobonds. In 1993, the Company issued $4.0 billion of mortgage bonds, pollution control revenue bonds and medium-term notes. Substantially all these proceeds were used to redeem or repurchase higher-cost mortgage bonds to accomplish a reduction in financing costs. In January 1995, the Board authorized the Company to redeem or repurchase up to $153 million of mortgage bonds. In addition, $85 million remains from a previous authorization to repurchase medium-term notes. The Company issues short-term debt (principally commercial paper) to fund fuel oil, nuclear fuel and gas inventories, unrecovered balances in balancing accounts and cyclical fluctuations in daily cash flows. At December 31, 1994 and 1993, the Company had $525 million and $764 18 8 million, respectively, of commercial paper outstanding. In addition, the Company has a $1 billion short-term credit facility to support the sale of commercial paper and other corporate purposes. There were no borrowings under this facility in 1994, 1993 or 1992. Equity: In 1994 and 1993, the Company received $274 million and $264 million, respectively, in proceeds from the sale of common stock under the employee Savings Fund Plan, the Dividend Reinvestment Plan and the employee Long-term Incentive Program. Proceeds were used for capital expenditures and other general corporate purposes. In July 1993, the Board authorized the Company to reinstate its common stock repurchase program and repurchase up to $1 billion of common stock on the open market or in negotiated transactions. This program is funded by internally generated funds. Shares will be repurchased to manage the overall balance of common stock in the Company's capital structure. Through December 31, 1994, the Company had repurchased approximately $435 million of its common stock under this program. In 1994, the Company issued $63 million of preferred stock with a mandatory redemption provision and redeemed $75 million of the Company's higher-cost preferred stock. In 1993, the Company issued $200 million of redeemable preferred stock. Proceeds were used to finance a portion of the redemption of $267 million of the Company's higher-cost preferred stock. Capital Requirements: The Company's estimated capital requirements for the next three years are shown below:
Year ended December 31, ------------------------- (in millions) 1995 1996 1997 Utility $1,212 $1,276 $1,237 Diablo Canyon 47 50 52 Enterprises 285 142 284 ------ ------ ------ Total capital expenditures 1,544 1,468 1,573 Maturing debt and sinking funds 477 373 369 ------ ------ ------ Total capital requirements $2,021 $1,841 $1,942 ====== ====== ======
Utility and Diablo Canyon expenditures will be primarily for improvements to the Company's facilities to maintain their efficiency and reliability, to extend their useful lives and to comply with environmental laws and regulations. Enterprises' estimated expenditures include oil and gas exploration and development activities by DALEN of approximately $120 million for 1995, project development expenditures for power and real-estate projects and equity commitments associated with generating facility projects. In addition to these capital requirements, the Company has other commitments as discussed in Notes 3 and 12 of Notes to Consolidated Financial Statements. Risk Management: The Company uses a number of techniques to mitigate its financial risk including the purchase of commercial insurance, the maintenance of systems of internal control and the selected use of financial instruments. The extent to which these techniques are used depends on the risk of loss and the cost to employ such techniques. These techniques do not eliminate financial risk to the Company. The majority of the Company's financing is done on a fixed-term basis thereby eliminating the financial risk associated with fluctuating interest rates. The Company has used financial instruments to eliminate the effects of fluctuations in interest rates and foreign currency exchange rates on certain of its debt. At December 31, 1994, the Company, through a series of interest rate swap transactions, had converted $639 million of a subsidiary's debt from a floating rate to a fixed rate through July 31, 1999. The Company, through foreign exchange contracts, has agreed to pay fixed interest and principal payments in U.S. dollars on $67 million of Swiss Franc debentures. In addition, DALEN periodically enters into crude oil and natural gas hedging transactions to minimize the risk of price fluctuations. The net gains and losses associated with these transactions have not been material. Environmental Matters: The Company's projected expenditures for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. Capital expenditures for environmental protection are currently estimated to be approximately $39 million, $93 million and $85 million for 1995, 1996 and 1997, respectively, and are included in the 19 9 Company's three-year table in the Capital Requirements section above. Expenditures during these years will be primarily for nitrogen oxide (NOx) emission reduction projects for the Company's fossil fuel fired generating plants and natural gas compressor stations. Pursuant to federal and state legislation, local air districts have adopted rules that require reductions in NOx emissions from company facilities. Final rules have yet to be adopted in all local air districts in which the Company operates and these rules continue to be modified. The Company currently estimates that compliance with NOx rules likely to be in place could require capital expenditures of up to $355 million over the next ten years. The Company assesses, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. Although the ultimate amount of costs that will be incurred by the Company in connection with its compliance and remediation activities is difficult to estimate, the Company has an accrued liability at December 31, 1994, of $95 million for hazardous waste remediation costs. The costs could be as much as $235 million, due to uncertainty concerning the Company's responsibility and the extent of contamination, the complexity of environmental laws and regulations and the selection of compliance alternatives. (See Note 13 of Notes to Consolidated Financial Statements.) Legal Matters: In the normal course of business, the Company is named as a party in a number of claims and lawsuits. Substantially all of these are litigated or settled with no significant impact on either the Company's results of operations or financial position. There are several significant litigation cases which are discussed in Note 13 of Notes to Consolidated Financial Statements. These cases include claims for personal injury and property damage, as well as punitive damages, allegedly suffered as a result of exposure to chromium near the Company's Hinkley Compressor Station, antitrust claims for damages as a result of Canadian natural gas purchases by one of the Company's wholly owned subsidiaries and two claims that the Company underpaid franchise fees. Accounting for Decommissioning Expense: The staff of the Securities and Exchange Commission has questioned certain current accounting practices of the electric utility industry, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations. In response to these questions, the FASB has agreed to review the accounting for removal costs, including decommissioning. If current electric utility industry accounting practices for such decommissioning are changed: (1) Annual expense for decommissioning could increase and (2) The estimated total cost for decommissioning could be recorded as a liability rather than accrued over time as accumulated depreciation. The Company does not believe that such changes, if required, would have an adverse effect on its results of operations due to its current ability to recover decommissioning costs through rates. 20 10 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED INCOME
Year Ended December 31, - ---------------------------------------- (in thousands, except per share amounts) 1994 1993 1992 OPERATING REVENUES Electric $ 8,027,976 $ 7,866,043 $ 7,747,492 Gas 2,419,375 2,716,365 2,548,596 ----------- ----------- ----------- Total operating revenues 10,447,351 10,582,408 10,296,088 ----------- ----------- ----------- OPERATING EXPENSES Cost of electric energy 2,561,778 2,250,209 2,416,554 Cost of gas 574,894 939,572 907,945 Distribution 229,640 226,975 219,082 Transmission 293,995 319,022 339,099 Customer accounts and services 433,603 403,560 421,990 Maintenance 456,889 442,939 484,751 Depreciation and decommissioning 1,397,470 1,315,524 1,221,490 Administrative and general 973,302 1,041,453 927,316 Workforce reduction costs 249,097 190,200 - Income taxes 924,620 1,006,774 906,845 Property and other taxes 296,911 297,495 295,164 Other 421,793 385,755 322,411 ----------- ----------- ----------- Total operating expenses 8,813,992 8,819,478 8,462,647 ----------- ----------- ----------- OPERATING INCOME 1,633,359 1,762,930 1,833,441 ----------- ----------- ----------- OTHER INCOME AND (INCOME DEDUCTIONS) Interest income 108,092 85,642 87,244 Allowance for equity funds used during construction 19,046 41,531 39,368 Other--net (8,344) (53,524) (3,006) ----------- ----------- ----------- Total other income and (income deductions) 118,794 73,649 123,606 ----------- ----------- ----------- INCOME BEFORE INTEREST EXPENSE 1,752,153 1,836,579 1,957,047 ----------- ----------- ----------- INTEREST EXPENSE Interest on long-term debt 651,912 731,610 739,279 Other interest charges 105,744 118,100 91,404 Allowance for borrowed funds used during construction (12,953) (78,626) (44,217) ----------- ----------- ----------- Total interest expense 744,703 771,084 786,466 ----------- ----------- ----------- NET INCOME 1,007,450 1,065,495 1,170,581 Preferred dividend requirement 57,603 63,812 78,887 ----------- ----------- ----------- EARNINGS AVAILABLE FOR COMMON STOCK $ 949,847 $ 1,001,683 $ 1,091,694 =========== =========== =========== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 429,846 430,625 422,714 EARNINGS PER COMMON SHARE $2.21 $2.33 $2.58 DIVIDENDS DECLARED PER COMMON SHARE $1.96 $1.88 $1.76
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 21 11 Pacific Gas and Electric Company CONSOLIDATED BALANCE SHEET
December 31, ---------------------------- (in thousands) 1994 1993 ASSETS PLANT IN SERVICE Electric Nonnuclear $ 17,045,247 $ 16,633,772 Diablo Canyon 6,647,162 6,518,413 Gas 7,447,879 7,146,741 ------------ ------------ Total plant in service (at original cost) 31,140,288 30,298,926 Accumulated depreciation and decommissioning (12,269,377) (11,235,519) ------------ ------------ Net plant in service 18,870,911 19,063,407 ------------ ------------ CONSTRUCTION WORK IN PROGRESS 527,867 620,187 OTHER NONCURRENT ASSETS Oil and gas properties 437,352 573,523 Nuclear decommissioning funds 616,637 536,544 Investment in nonregulated projects 761,355 304,223 Other assets 137,325 193,466 ------------ ------------ Total other noncurrent assets 1,952,669 1,607,756 ------------ ------------ CURRENT ASSETS Cash and cash equivalents 136,900 61,066 Accounts receivable Customers 1,413,185 1,264,907 Other 98,035 123,255 Allowance for uncollectible accounts (29,769) (23,647) Regulatory balancing accounts receivable 1,345,669 992,477 Inventories Materials and supplies 197,394 239,856 Gas stored underground 136,326 170,345 Fuel oil 67,707 109,615 Nuclear fuel 140,357 134,411 Prepayments 33,251 56,062 ------------ ------------ Total current assets 3,539,055 3,128,347 ------------ ------------ DEFERRED CHARGES Income tax-related deferred charges 1,155,421 1,276,532 Diablo Canyon costs 401,110 419,775 Unamortized loss net of gain on reacquired debt 382,862 395,659 Workers' compensation and disability claims recoverable 247,209 192,203 Other 732,029 458,660 ------------ ------------ Total deferred charges 2,918,631 2,742,829 ------------ ------------ TOTAL ASSETS $ 27,809,133 $ 27,162,526 ============ ============
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 22 12 Pacific Gas and Electric Company CONSOLIDATED BALANCE SHEET
December 31, ---------------------------- (in thousands) 1994 1993 CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock $ 2,151,213 $ 2,136,095 Additional paid-in capital 3,806,508 3,666,455 Reinvested earnings 2,677,304 2,643,487 ----------- ----------- Total common stock equity 8,635,025 8,446,037 Preferred stock without mandatory redemption provisions 732,995 807,995 Preferred stock with mandatory redemption provisions 137,500 75,000 Long-term debt 8,675,091 9,292,100 ----------- ----------- Total capitalization 18,180,611 18,621,132 ----------- ----------- OTHER NONCURRENT LIABILITIES Customer advances for construction 152,384 152,872 Workers' compensation and disability claims 221,200 157,000 Other 644,233 246,950 ----------- ----------- Total other noncurrent liabilities 1,017,817 556,822 ----------- ----------- CURRENT LIABILITIES Short-term borrowings 524,685 764,163 Long-term debt 477,047 221,416 Accounts payable Trade creditors 414,291 472,985 Other 337,726 389,065 Accrued taxes 436,467 303,575 Deferred income taxes 432,026 315,584 Interest payable 84,805 82,105 Dividends payable 210,903 203,923 Other 643,779 487,809 ----------- ----------- Total current liabilities 3,561,729 3,240,625 ----------- ----------- DEFERRED CREDITS Deferred income taxes 3,902,645 3,978,950 Deferred investment tax credits 391,455 410,969 Noncurrent balancing account liabilities 226,844 112,533 Other 528,032 241,495 ----------- ----------- Total deferred credits 5,048,976 4,743,947 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Notes 2, 3, 12 and 13) ----------- ----------- TOTAL CAPITALIZATION AND LIABILITIES $27,809,133 $27,162,526 =========== ===========
23 13 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED CASH FLOWS
Year ended December 31, ---------------------------------------- (in thousands) 1994 1993 1992 CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 1,007,450 $ 1,065,495 $ 1,170,581 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and decommissioning 1,397,470 1,315,524 1,221,490 Amortization 49,671 135,808 121,795 Gain on sale of investment in Alberta Natural Gas Company Ltd - - (48,722) Deferred income taxes and investment tax credits--net 15,312 319,198 164,457 Allowance for equity funds used during construction (19,046) (41,531) (39,368) Other deferred charges 32,740 (158,725) 8,147 Other noncurrent liabilities 301,842 50,279 31,374 Other deferred credits 105,262 110,145 73,259 Net effect of changes in operating assets and liabilities Accounts receivable (116,936) 64,790 39,922 Regulatory balancing accounts receivable (353,192) (218,553) (215,195) Inventories 112,443 23,097 (7,161) Accounts payable (110,033) (39,422) (102,559) Accrued taxes 132,892 44,638 128,243 Other working capital 181,481 108,873 (36,117) Other--net 210,331 13,184 49,891 ----------- ----------- ----------- Net cash provided by operating activities 2,947,687 2,792,800 2,560,037 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Construction expenditures (1,094,495) (1,763,024) (2,307,318) Allowance for borrowed funds used during construction (12,953) (78,626) (44,217) Nonregulated expenditures (328,266) (234,221) (148,226) Proceeds from sale of investment in Alberta Natural Gas Company Ltd - - 97,251 Other--net (29,914) 9,992 82,352 ---------- ----------- ----------- Net cash used by investing activities (1,465,628) (2,065,879) (2,320,158) ---------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock issued 274,269 264,489 296,653 Common stock repurchased (181,558) (257,780) (5,410) Preferred stock issued 62,312 200,001 195,451 Preferred stock redeemed (83,275) (302,640) (276,806) Long-term debt issued 60,907 4,584,548 1,676,513 Long-term debt matured or reacquired (436,673) (4,002,704) (1,409,337) Short-term debt issued (redeemed)--net (239,478) (366,961) 121,213 Dividends paid (891,850) (857,515) (809,108) Other--net 29,121 (24,885) (28,736) ---------- ----------- ----------- Net cash used by financing activities (1,406,225) (763,447) (239,567) ---------- ----------- ----------- NET CHANGE IN CASH AND CASH EQUIVALENTS 75,834 (36,526) 312 CASH AND CASH EQUIVALENTS AT JANUARY 1 61,066 97,592 97,280 ---------- ----------- ----------- CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 136,900 $ 61,066 $ 97,592 ========== =========== =========== Supplemental disclosures of cash flow information Cash paid for Interest (net of amounts capitalized) $ 674,758 $ 642,712 $ 694,512 Income taxes 712,777 542,827 682,809
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 24 14 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY AND PREFERRED STOCK
Preferred Preferred Stock Stock Total Without With Additional Common Mandatory Mandatory (dollars in thousands) Common Paid-in Reinvested Stock Redemption Redemption Stock Capital Earnings Equity Provisions Provisions(1) BALANCE DECEMBER 31, 1991 $2,087,859 $3,287,313 $2,306,152 $7,681,324 $ 894,897 $104,632 ---------- ---------- ---------- ---------- --------- -------- Net income--1992 1,170,581 1,170,581 Common stock issued (9,453,353 shares) 47,267 249,386 296,653 Common stock repurchased (179,610 shares) (898) (2,450) (2,062) (5,410) Preferred stock issued (8,000,000 shares) (4,549) (4,549) 125,000 75,000 Preferred stock redeemed (9,365,449 shares) (12,638) (14,940) (27,578) (229,106) (20,122) Cash dividends declared Preferred stock (81,393) (81,393) Common stock (744,277) (744,277) Other (2,214) (2,214) ---------- ---------- ---------- ---------- --------- -------- Net change 46,369 229,749 325,695 601,813 (104,106) 54,878 ---------- ---------- ---------- ---------- --------- -------- BALANCE DECEMBER 31, 1992 2,134,228 3,517,062 2,631,847 8,283,137 790,791 159,510 ---------- ---------- ---------- ---------- --------- -------- Net income--1993 1,065,495 1,065,495 Common stock issued (7,708,512 shares) 38,541 225,948 264,489 Common stock repurchased (7,334,876 shares) (36,674) (63,180) (157,926) (257,780) Preferred stock issued (8,000,000 shares) 200,001 Preferred stock redeemed (8,156,968 shares) (13,375) (21,958) (35,333) (182,797) (84,510) Cash dividends declared Preferred stock (62,521) (62,521) Common stock (811,196) (811,196) Other (254) (254) ---------- ---------- ---------- ---------- --------- -------- Net change 1,867 149,393 11,640 162,900 17,204 (84,510) ---------- ---------- ---------- ---------- --------- -------- BALANCE DECEMBER 31, 1993 2,136,095 3,666,455 2,643,487 8,446,037 807,995 75,000 ---------- ---------- ---------- ---------- --------- -------- Net income--1994 1,007,450 1,007,450 Common stock issued (10,508,483 shares) 52,543 221,726 274,269 Common stock repurchased (7,485,001 shares) (37,425) (66,334) (77,799) (181,558) Preferred stock issued (2,500,000 shares) (188) (188) 62,500 Preferred stock redeemed (3,000,000 shares) (5,331) (2,544) (7,875) (75,000) Cash dividends declared Preferred stock (58,203) (58,203) Common stock (840,627) (840,627) Other (9,820) 5,540 (4,280) ---------- ---------- ---------- ---------- --------- -------- Net change 15,118 140,053 33,817 188,988 (75,000) 62,500 ---------- ---------- ---------- ---------- --------- -------- BALANCE DECEMBER 31, 1994 $2,151,213 $3,806,508 $2,677,304 $8,635,025 $ 732,995 $137,500 ========== ========== ========== ========== ========= ========
(1) Includes current portion. The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 25 15 Pacific Gas and Electric Company STATEMENT OF CONSOLIDATED CAPITALIZATION
December 31, ---------------------------- (dollars in thousands, except per share amounts) 1994 1993 COMMON STOCK EQUITY Common stock, par value $5 per share (authorized 800,000,000 shares, issued and outstanding 430,242,687 and 427,219,205 $ 2,151,213 $ 2,136,095 Additional paid-in capital 3,806,508 3,666,455 Reinvested earnings 2,677,304 2,643,487 ----------- ----------- Common stock equity 8,635,025 8,446,037 ----------- ----------- PREFERRED STOCK Preferred stock without mandatory redemption provision Par value $25 per share (1) Nonredeemable 5% to 6%--5,784,825 shares outstanding 144,621 144,621 Redeemable 4.36% to 8.2%--23,534,958 and 26,534,958 shares outstanding 588,374 663,374 ----------- ----------- Total preferred stock without mandatory redemption provision 732,995 807,995 ----------- ----------- Preferred stock with mandatory redemption provision Par value $25 per share (1) 6.30%--2,500,000 and none outstanding 62,500 - 6.57%--3,000,000 shares outstanding 75,000 75,000 Par value $100 per share (authorized 10,000,000 shares) - - ----------- ----------- Total preferred stock with mandatory redemption provision 137,500 75,000 ----------- ----------- Preferred stock 870,495 882,995 ----------- ----------- LONG-TERM DEBT PG&E long-term debt First and refunding mortgage bonds Maturity Interest rates 1994-1999 4.25% to 6.875% 714,074 724,610 2000-2005 5.875% to 8.75% 1,658,749 1,739,649 2006-2012 6.25% to 8.875% 477,870 477,870 2013-2019 7.5% to 12.75% 136,030 140,900 2020-2026 5.85% to 9.30% 2,902,945 2,947,428 ----------- ----------- Principal amounts outstanding 5,889,668 6,030,457 Unamortized discount net of premium (66,198) (71,817) ----------- ----------- Total mortgage bonds 5,823,470 5,958,640 Unsecured debentures, 10.81% to 12%, due 1994-2000 124,939 221,523 Pollution control loan agreements, variable rates, due 2008-2016 925,000 925,000 Unsecured medium-term notes, 4.13% to 10.10% due 1994-2014 1,443,800 1,542,625 Unamortized discount related to unsecured medium-term notes (2,428) (3,459) Other long-term debt 22,209 24,127 ----------- ----------- Total PG&E long-term debt 8,336,990 8,668,456 Long-term debt of subsidiaries 815,148 845,060 ----------- ----------- Total long-term debt of PG&E and subsidiaries 9,152,138 9,513,516 Less long-term debt--current portion 477,047 221,416 ----------- ----------- Long-term debt 8,675,091 9,292,100 ----------- ----------- TOTAL CAPITALIZATION $18,180,611 $18,621,132 =========== ===========
(1) Authorized 75,000,000 shares in total (both with and without mandatory redemption provisions). The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 26 16 Pacific Gas and Electric Company SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
Diversified Operations Intersegment (in thousands) Electric Gas (4) Eliminations Total 1994 Operating revenues $ 8,006,157 $2,194,870 $ 246,324 $ - $10,447,351 Intersegment revenues (1) 12,852 85,341 1,695 (99,888) - ----------- ---------- ---------- --------- ----------- Total operating revenues $ 8,019,009 $2,280,211 $ 248,019 $ (99,888) $10,447,351 =========== ========== ========== ========= =========== Depreciation and decommissioning $ 982,859 $ 295,979 $ 118,632 $ - $ 1,397,470 Operating income before income taxes (2) 2,213,518 381,078 (33,390) (3,227) 2,557,979 Construction expenditures (3) 834,494 292,000 - - 1,126,494 Identifiable assets (3) $19,471,121 $6,433,984 $1,436,128 $ - $27,341,233 Corporate assets 467,900 ----------- Total assets at end of year $27,809,133 =========== 1993 Operating revenues $ 7,866,043 $2,466,788 $ 249,577 $ - $10,582,408 Intersegment revenues (1) 15,369 223,443 5,079 (243,891) - ----------- ---------- ---------- --------- ----------- Total operating revenues $ 7,881,412 $2,690,231 $ 254,656 $(243,891) $10,582,408 =========== ========== ========== ========= =========== Depreciation and decommissioning $ 925,673 $ 251,490 $ 138,361 $ - $ 1,315,524 Operating income before income taxes (2) 2,344,796 440,323 (7,375) (8,040) 2,769,704 Construction expenditures (3) 929,065 954,116 - - 1,883,181 Identifiable assets (3) $19,125,555 $6,467,424 $1,053,027 $ - $26,646,006 Corporate assets 516,520 ----------- Total assets at end of year $27,162,526 =========== 1992 Operating revenues $ 7,747,492 $2,342,202 $ 206,394 $ - $10,296,088 Intersegment revenues (1) 15,150 410,014 28,191 (453,355) - ----------- ---------- ---------- --------- ----------- Total operating revenues $ 7,762,642 $2,752,216 $ 234,585 $(453,355) $10,296,088 =========== ========== ========== ========= =========== Depreciation and decommissioning $ 856,124 $ 231,443 $ 133,923 $ - $ 1,221,490 Operating income before income taxes (2) 2,308,828 441,612 (9,808) (346) 2,740,286 Construction expenditures (3) 1,124,368 1,266,535 - - 2,390,903 Identifiable assets (3) $17,658,656 $5,068,213 $ 996,860 $ - $23,723,729 Corporate assets 464,430 ----------- Total assets at end of year $24,188,159 ===========
(1) Intersegment electric and gas revenues are accounted for at tariff rates prescribed by the CPUC. (2) Income taxes and general corporate expenses are allocated in accordance with the FERC Uniform System of Accounts and requirements of the CPUC. Operating income in the Statement of Consolidated Income is net of utility income taxes. (3) Includes an allocation of common plant in service and allowance for funds used during construction. (4) Includes the nonregulated operations of wholly owned subsidiaries, including PG&E Enterprises, Mission Trail Insurance Ltd. (liability insurance), Pacific Gas Properties Company (real estate development) and Pacific Conservation Services Company (conservation loans). The accompanying Notes to Consolidated Financial Statements are an integral part of this statement. 27 17 Pacific Gas and Electric Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1: Summary of Significant Accounting Policies Regulation: Pacific Gas and Electric Company (PG&E) is regulated by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). PG&E's consolidated financial statements reflect the ratemaking policies of these commissions in conformity with generally accepted accounting principles for rate-regulated enterprises. In the Notes to Consolidated Financial Statements, regulated operations other than the Diablo Canyon Nuclear Power Plant (Diablo Canyon) are referred to as the utility. Principles of Consolidation: The consolidated financial statements include PG&E and its wholly owned and majority-owned subsidiaries (collectively, the Company). All significant intercompany transactions have been eliminated. Major subsidiaries, all of which are wholly owned, are: Pacific Gas Transmission Company (PGT)--transports natural gas from the U.S./Canadian border to the California border; Alberta and Southern Gas Co. Ltd. (A&S)-- prior to November 1, 1993, bought gas in Canada and arranged its transport to the U.S. border (see Note 3 for discussion of the restructuring of A&S's operations); Pacific Energy Fuels Company--finances the purchase of nuclear fuel through issuance of its commercial paper; PG&E Enterprises (Enterprises)-- the parent company for nonregulated subsidiaries, including DALEN Resources Corp. (DALEN), formerly PG&E Resources Company, which engages in exploration, development and production of oil and natural gas, and PG&E Generating Company which through a joint venture (U.S. Generating) develops, builds, owns and operates independent power projects. Alberta Natural Gas Company Ltd (ANG), a 49.98% owned affiliate of PGT which transports natural gas, was sold in June 1992. Prior to the sale of ANG, the Company's investment in ANG was accounted for by the equity method of accounting. Revenues: Revenues are recorded primarily for delivery of gas and electric energy to customers. These revenues give rise to receivables from a diversified base of customers including residential, commercial and industrial customers primarily in Northern and Central California. The CPUC has established mechanisms known as balancing accounts which help stabilize the Company's earnings. Specifically, sales balancing accounts accumulate differences between authorized and actual base revenues. Energy cost balancing accounts accumulate differences between the actual cost of gas and electric energy and the revenues designated for recovery of such costs. Recovery of gas and electric energy costs through these balancing accounts is subject to a reasonableness review by the CPUC. (See Note 3 for further discussion of gas costs.) Plant in Service: The cost of plant additions and replacements is capitalized. Cost includes labor, materials, construction overhead and an allowance for funds used during construction (AFUDC). AFUDC is the cost of debt and equity funds used to finance the construction of new facilities. Financing costs of capital additions for Diablo Canyon, the California portion of the PGT-PG&E Pipeline Expansion Project (Pipeline Expansion), and other nonregulated projects are calculated under Statement of Financial Accounting Standards (SFAS) No. 34, "Capitalization of Interest Cost." The original cost of retired plant plus removal costs less salvage value are charged to accumulated depreciation. Maintenance, repairs and minor replacements and additions are charged to maintenance expense. Depreciation and Nuclear Decommissioning Costs: Depreciation of plant in service is computed using a straight-line remaining-life method. The estimated cost of decommissioning the Company's nuclear power facilities is recovered in base rates through an annual allowance. For the years ended December 31, 1994, 1993 and 1992, the amount recovered in rates for decommissioning costs was $54 million each year. The estimated total obligation for nuclear decommissioning costs is approximately $1.1 billion in 1994 dollars (or $4.5 billion in future dollars); this obligation is being recognized ratably over the facilities' lives. This estimate considers the total cost (including labor, materials and other costs) of decommissioning and dismantling plant systems and structures and includes a contingency factor for possible changes in regulatory requirements and waste disposal cost increases. The decommissioning method selected for Diablo Canyon anticipates that the equipment, structures, and portions of the facility and site containing radioactive contaminants will be removed or decontaminated to a level that permits the property to be released for unrestricted use. Humboldt Bay Power Plant is being decommissioned under a method that consists of placing and maintaining the facility in protective storage until some future time when dismantling can be initiated. The average annualized escalation rate and the assumed return on qualified trust assets used to calculate the decommissioning obligation and annual expense are approximately 5.5 percent and 5.25 percent (6.25 percent on 28 18 nonqualified trust assets), respectively. (See Note 8 for further discussion of nuclear decommissioning funds.) As required by federal law, the U.S. Department of Energy (DOE) is responsible for the future storage and disposal of spent nuclear fuel. No permanent storage site has been identified and the DOE has indicated that the storage site will not be available until after 2010. The Company pays a one-tenth of one cent fee on each nuclear kilowatthour (kWh) sold to fund DOE storage and disposal activities. Income Taxes: The Company files a consolidated federal income tax return that includes domestic subsidiaries in which its ownership is 80 percent or more. Income tax expense includes current and deferred income taxes resulting from operations during the year. Investment tax credits are deferred and amortized to income over the life of the related property. Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for Income Taxes," which established new financial accounting standards for income taxes. SFAS No. 109 prohibits net-of-tax accounting, requires that deferred tax liabilities and assets be adjusted for enacted changes in the income tax rates and requires the use of the liability method of accounting for income taxes. Under the liability method, the deferred tax liability represents the tax effect of temporary differences between the financial statement and income tax bases of assets and liabilities at current income tax rates. The effect of the adoption of SFAS No. 109, as of January 1, 1993, was an increase of $1.8 billion in consolidated liabilities as a result of recording additional deferred taxes; consolidated assets also increased $1.8 billion, consisting of a $1.5 billion increase in deferred charges (income tax-related deferred charges and Diablo Canyon costs) and a $300 million increase in net plant in service. These adjustments relate to temporary differences, which prior to adoption of SFAS No. 109 were not recorded as deferred taxes, consistent with the ratemaking process. Due to regulatory treatment, the adoption of SFAS No. 109 did not have a significant impact on the Company's results of operations. Debt Premium, Discount and Related Expenses: Long-term debt premium, discount and related expenses are amortized over the life of each issue. Gains and losses on reacquired debt allocated to the utility are amortized over the remaining original lives of the debt reacquired, consistent with ratemaking; gains and losses on debt allocated to Diablo Canyon and the California portion of the Pipeline Expansion are recognized in income, and if material as an extraordinary item, at the time such debt is reacquired. Occasionally, the Company uses interest rate swap agreements and foreign currency contracts to hedge fluctuations in interest rates and foreign currency exchange rates. The Company defers any gains or losses on these transactions and records interest expense adjusted for the effects of the agreements. Oil and Gas Properties: DALEN uses the successful-efforts method of accounting for oil and gas properties. Inventories: Nuclear fuel inventory is stated at the lower of average cost or market. Amortization of fuel in the reactor is based on the amount of energy output. Other inventories are valued at average cost except for fuel oil, which is valued by the last-in-first-out method. Statement of Consolidated Cash Flows: Cash and cash equivalents (valued at cost which approximates market) include special deposits, working funds and short-term investments with original maturities of three months or less. Reclassifications: Certain amounts in the prior years' consolidated financial statements have been reclassified to conform to the 1994 presentation. Note 2: COMPETITION AND REGULATION In April 1994, the CPUC issued an order instituting a rulemaking and an investigation (OIR/OII) on electric industry restructuring. The proposal, which is subject to comment and modification, involves two major changes in electric industry regulation in California. The first would move electric utilities from traditional ratemaking to performance-based ratemaking. The second would unbundle electric services and provide electric utility retail customers with the option to choose from a range of electric generation providers, including utilities (direct access). Direct access would be phased in over a six-year period beginning in 1996. Utilities would still be obligated to provide transmission and distribution services to all customers. To ensure an orderly transition that maintains the financial integrity of the utilities, the CPUC proposed that uneconomic costs of utility generating assets be recovered through a "competition transition charge" (CTC). However, the OIR/OII did not specify which costs might be recovered through such a transition charge or how such a charge would be allocated to and collected from customers. In June 1994, the Company filed its initial comments on the CPUC's proposal. The Company's response proposed an implementation schedule for direct access beginning in 29 19 1996, with direct access service available to all customers by 2008. For direct access customers, the Company proposed that it be given the pricing flexibility to compete and sell unbundled electric power while assuming the market risk of competitive pricing. In November 1994, the Company filed testimony with the CPUC on its plan for recovering uneconomic assets and obligations which would result from the restructuring of the electric industry as proposed by the CPUC. The Company's testimony, among other things, identifies and defines the costs proposed to be included in the CTC, provides preliminary estimates of the transition costs and discusses options for allocating and recovering those costs. Based on market prices of $.048 and $.032 per kWh, the Company estimated that its uneconomic generating assets and obligations are approximately $3 billion and $11 billion, respectively, resulting from the restructuring as proposed by the CPUC. The Company identified three categories of uneconomic assets: utility-owned generation assets and power purchase commitments, power purchase obligations relating to Qualifying Facilities (QFs), and generation-related regulatory assets. The estimates of uneconomic assets were determined by comparing future revenue requirements of generation assets and power purchase obligations, over a twenty-year and thirty-year period, respectively, with revenues computed at assumed market prices. Diablo Canyon was included in the revenue requirement calculation using the proposed pricing modification to the Diablo Canyon settlement. (See Note 4.) The revenue requirement for Diablo Canyon and all Company-owned generation assets included a return on investment. The actual amount of uneconomic assets and obligations will depend on the final regulation and the actual market price of electricity. Under the Company's proposal for a longer phase-in period to direct access, the Company would not seek recovery of the transition costs associated with its own generation assets and power purchase commitments, except for commitments to purchase power from QFs. Based on this assumption and the market price assumptions referred to above, the uneconomic assets and obligations are approximately $3 billion and $5 billion, respectively. If the CPUC adopts a shorter phase-in period, the Company indicated that it would seek recovery of all uneconomic assets and obligations resulting from the restructuring through the CTC. In December 1994, the CPUC issued an interim decision in the OIR/OII. The decision sets a schedule under which the CPUC will propose a policy decision in March 1995, with a final policy decision to be effective no earlier than September 1995. The CPUC's proposed policy statement will be subject to hearings and state legislative review before it can be implemented. The CPUC also established a public working group to comment on unbundling and transition cost recovery, social programs and resource procurement, under several different models for restructuring which include direct access and a supply pool for use by wholesale and/or retail purchasers of electricity. Financial Impact of the Electric Industry Restructuring Proposal: Based on the regulatory framework in which it operates, the Company currently accounts for the economic effects of regulation in accordance with the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result of applying the provisions of SFAS No. 71, the Company has accumulated approximately $3.7 billion of regulatory assets, including balancing accounts, at December 31, 1994. In the event that recovery of specific costs through rates becomes unlikely or uncertain for all or a portion of the Company's utility operations, whether resulting from the expanding effects of competition or specific regulatory actions, it could cause the Company to write off applicable portions of its regulatory assets. If the OIR/OII is adopted as proposed, or the Company determines that future electric generation rates will no longer be based on cost-of-service, the Company will discontinue application of SFAS No. 71 for the electric generation portion of its operations. The Company continues to evaluate the current regulatory and competitive environment to determine whether and when such a discontinuance would be appropriate. If such discontinuance should occur, the Company would write off all applicable generation-related regulatory assets to the extent that transition cost recovery is not assured. The regulatory assets attributable to electric generation, excluding balancing accounts of approximately $700 million which are expected to be recovered in the near term, were approximately $1.6 billion at December 31, 1994. This amount could vary depending on the allocation methods used. The final CPUC determination of uneconomic costs and the method of recovery could adversely affect the Company's returns on its investments in electric generation assets. If future electric generation revenues are insufficient to recover the Company's investments and QF obligations, the Company would recognize a loss. The final determination of the financial impact will depend on the form of regulation, including transition mechanisms, if any, adopted by the CPUC and the groups of customers affected. Currently, the Company is unable to predict the ultimate outcome of the electric industry restructuring or predict whether such outcome will have a significant impact on its financial position or results of operations. 30 20 Note 3: Natural Gas Matters Regulatory Restructuring: Beginning August 1, 1993, PG&E implemented the CPUC's capacity brokering program which requires PG&E to make available for brokering all interstate gas pipeline capacity which is not held for its residential and smaller commercial (core) customers, and industrial and large commercial customers who choose bundled gas services (core subscription customers). PG&E's industrial and large commercial (noncore) customers, producers, aggregators, marketers and the Company's electric department can bid for such capacity. In addition, beginning November 1, 1993, PGT implemented the FERC's Order No. 636, which requires interstate pipelines to restructure their services. This order unbundled sales, transportation and storage services, instituted capacity release programs and provided for recovery of transition costs related to the restructuring of services. The Company's compliance with these regulatory changes allowed more of the Company's noncore customers to arrange for the purchase and transportation of their own gas supplies. As a result, the Company's gas purchase requirements and related need for firm transportation capacity for its gas purchases decreased, contributing to the Company's need to restructure its gas supply arrangements. Decontracting Plan: Until November 1993, PG&E purchased Canadian natural gas from PGT which in turn purchased such gas from A&S. A&S had commitments to purchase natural gas from approximately 190 Canadian gas producers under various long-term contracts, most of which extended through 2005. As a result of the regulatory restructuring discussed above, A&S, PGT, PG&E and approximately 190 Canadian gas producers entered into agreements (collectively, the Decontracting Plan) which terminated A&S's contracts with these Canadian gas producers effective November 1, 1993. Under the Decontracting Plan, producers released A&S, PGT and PG&E from any claims they may have had that resulted from the termination of the former arrangements as well as any prior claims related to these contracts. The total amount of settlement payments paid to producers was approximately $210 million. As part of the overall decontracting process, A&S's operations have been significantly reduced. A&S permanently assigned significant portions of its commitments for transportation capacity with NOVA Corporation of Alberta (NOVA) through October 2001 and ANG through October 2005 to third parties. In addition, A&S assigned approximately 600 million cubic feet per day (MMcf/d) of capacity on each of these pipelines to PG&E for use in the servicing of PG&E's core and core subscription customers. With the permanent assignments of its capacity made through the end of 1994, A&S holds remaining capacity of approximately 300 MMcf/d on each of the pipelines with total annual demand charges of approximately $15 million for which it is continuing its efforts to assign or broker. A&S believes it will be able to permanently assign substantially all of its remaining capacity by the end of 1995. To the extent others do not take this capacity, A&S will remain obligated to pay for the related demand charges. The FERC approved a transition cost recovery mechanism for PGT under which most costs incurred to restructure, reform or terminate the sales arrangements between A&S and PGT and the underlying A&S gas supply contracts, or to resolve claims by gas suppliers related to past or future liabilities or obligations of PGT or A&S arising out of the former contracts, are treated as transition costs. Twenty-five percent of the transition costs was absorbed by PGT. Twenty-five percent of the transition costs was recovered by PGT through direct bills (substantially all to PG&E as PGT's principal customer). The final fifty percent of the transition costs is being recovered by PGT through volumetric surcharges over a three-year period. Costs associated with A&S's commitments for Canadian pipeline capacity do not qualify as transition costs recoverable under this mechanism. Financial Impact of Decontracting Plan: The Company incurred transition costs of $228 million in 1993, consisting of settlement payments made to producers in connection with the implementation of the Decontracting Plan and amounts incurred by A&S in reducing certain administrative and general functions resulting from the restructuring. Of these costs, the Company deferred $143 million for future rate recovery. In addition, the Company recorded a charge of $31 million in 1993 related to A&S's remaining commitments for Canadian transportation capacity. Accordingly, the Company expensed $93 million in 1993 and a total of $23 million in prior years. Transportation Commitments: The Company has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for fixed demand charges for reserving firm capacity on the pipelines. The total demand charges that the Company will pay each year may change due to changes in tariff rates and may be offset to the extent the Company can broker or permanently assign any unused capacity. In addition to demand charges, the Company is required to pay transportation charges for actual quantities shipped. The Company's total demand and transportation charges paid under these agreements (excluding agreements with PGT) were approximately $225 million in 1994, $280 million in 1993 and $300 million in 1992. 31 21 The following table summarizes the approximate capacity held by the Company on various pipelines and the related annual demand charges as of December 31, 1994:
Total Firm Capacity Annual Demand Pipeline Held Charges Contract Company (MMcf/d) (in millions) Expiration - ------------------------- ------------- ------------- ---------- El Paso 1,140 $130 December 1997 Transwestern 200 $ 30 March 2007 NOVA 870 $ 25 October 2001 ANG 890 $ 15 October 2005
Regulatory changes have resulted in a decrease in the Company's need for firm transportation capacity for its own gas purchases. PG&E holds approximately 600 MMcf/d of firm capacity on each of the pipelines owned by El Paso Natural Gas Company (El Paso), NOVA and ANG, and 150 MMcf/d on the pipeline owned by Transwestern Pipeline Company (Transwestern) to service its core and core subscription customers. In addition, PG&E holds for its electric department approximately 50 MMcf/d on Transwestern. The Company is continuing its efforts to broker or assign any remaining unused capacity including certain amounts of that held for its core and core subscription customers when such capacity is not being used. Based on the current demand for Canadian pipeline capacity, the Company believes it will be able to broker or assign substantially all of its unused capacity on NOVA and ANG; however, due to lower demand for Southwest pipeline capacity, the Company cannot predict the volume or price of the capacity on El Paso and Transwestern that will be brokered or assigned. Substantially all demand charges incurred by the Company for pipeline capacity, including charges for capacity that is not brokered or brokered at a discount, are eligible for rate recovery subject to a reasonableness review. The Division of Ratepayer Advocates (DRA), a consumer advocacy branch of the CPUC staff, and others have challenged recovery of all demand charges for the Company's Transwestern capacity and of certain other demand charges for capacity not brokered or brokered at a discount. In November 1994, the CPUC approved an interim increase in gas rates, subject to refund, designed to collect approximately one-half of the demand charges for unbrokered or discounted El Paso and PGT capacity. The decision set hearings on the issue, and acknowledged that significant reasonable costs continue to accrue. The Company believes that the ultimate resolution of these matters will not have a significant adverse impact on its financial position or results of operations. Gas Reasonableness Proceedings: Recovery of energy costs through the Company's regulatory balancing account mechanisms is subject to a CPUC determination that such costs were incurred reasonably. Under the current regulatory framework, annual reasonableness proceedings are conducted by the CPUC on a historic calendar year basis. In March 1994, the CPUC issued decisions covering the years 1988 through 1990, ordering disallowances of $90 million of gas costs, plus accrued interest of approximately $25 million through 1993 for the Company's Canadian gas procurement activities, and $8 million for gas inventory operations. The Company has filed a lawsuit in a federal district court challenging the CPUC decision on Canadian gas costs. The CPUC decision on the Company's Canadian gas procurement activities found that the Company could have saved its customers money if it had bargained more aggressively with its then-existing Canadian suppliers or bought lower-priced gas from other Canadian sources. The CPUC concluded that it was appropriate for the Company to take a substantial portion of its Canadian gas (up to 700 MMcf/d) at the actual price charged under its then-existing Canadian gas supply contracts, but that the Company could have met the remainder of its Canadian gas requirement with lower-priced gas, either under those same contracts or with purchases from other Canadian natural gas sources. A number of other reasonableness issues related to the Company's gas procurement practices, transportation capacity commitments and supply operations for periods dating from 1988 to 1994 are still under review by the CPUC. The DRA recommended disallowances of $142 million and a penalty of $50 million and indicated that it was considering additional recommendations for pending issues. The Company and the DRA have signed settlement agreements to resolve most of these issues for a $68 million disallowance. Significant issues covered by the settlement agreements include (1) the Company's purchases of Canadian, Southwest and California gas for its electric department in 1991 and 1992 and its core customers from 1991 through May 1994; (2) the investigation by the DRA of A&S and proposed investigation of ANG for the period 1988 through May 1994; (3) the effects of Canadian gas prices on amounts paid by the Company for Northwest power purchases for 1988 through 1992 and power from QFs and geothermal producers for 1991 and 1992; (4) the Company's gas storage operations for 1991 and 1992; (5) the Company's Southwest gas procurement activities for 1988 through 1990; and (6) Canadian gas restructuring transition costs billed to PG&E by PGT. Agreements with the DRA do not constitute a CPUC decision and are subject to modification by the CPUC in its final decisions. 32 22 Financial Impact of Reasonableness Proceedings: The Company accrued approximately $135 million and $61 million in 1994 and 1993, respectively, for gas reasonableness matters including the CPUC decisions for the years 1988 through 1990 and issues covered by the settlement agreements. The Company believes the ultimate outcome of these matters will not have a significant impact on its financial position or results of operations. Note 4: Diablo Canyon Rate Case Settlement: The 1988 Diablo Canyon rate case settlement (Diablo Canyon settlement) bases revenues primarily on the amount of electricity generated by the plant, rather than on traditional cost-based ratemaking. In approving the settlement, the CPUC explicitly affirmed that Diablo Canyon costs and operations should no longer be subject to CPUC reasonableness reviews. The Diablo Canyon settlement provides that only certain Diablo Canyon costs be recovered through base rates over the term of the Diablo Canyon settlement, including a full return on such costs. The related revenues to recover these costs are included in Diablo Canyon operating revenues for reporting purposes. Other than these and decommissioning costs, Diablo Canyon no longer meets the criteria for application of SFAS No. 71. Consequently, application of this statement was discontinued for Diablo Canyon effective July 1988. Pricing: In December 1994, the Company, the DRA, the California Attorney General and several other parties representing energy consumers agreed to modify the pricing provisions of the Diablo Canyon settlement. The modification, which is subject to CPUC approval, calls for a reduction in the price paid for electricity generated by Diablo Canyon over the next five years. Under the Diablo Canyon settlement, the price per kWh of electricity generated by Diablo Canyon consists of a fixed and an escalating component. The total prices for 1994, 1993 and 1992 were 11.89 cents, 11.16 cents and 10.34 cents per kWh, respectively. Under the proposed modification, the price for power produced by Diablo Canyon would be reduced from the current level as shown in the following table. Under the proposed pricing, at full operating power each Diablo Canyon unit would contribute approximately $2.9 million in revenues per day in 1995.
Diablo Canyon Price (cents) per kWh ----------------------------------- 1995 1996 1997 1998 1999 Original Settlement Price* 12.15 12.42 12.70 12.98 13.28 Proposed Price 11.00 10.50 10.00 9.50 9.00
- ---------------- * assumes 3.5% inflation After December 31, 1999, the escalating portion of the Diablo Canyon price would increase using the same formula specified in the original Diablo Canyon settlement. The proposed modification provides the Company with the right to reduce the price below the amount specified. The parties to the proposed modification have agreed that the difference between the Company's revenue requirement under the original Diablo Canyon settlement prices and the proposed prices would be applied to the energy cost balancing account until the undercollection in that account is fully amortized. Financial Information: Selected financial information for Diablo Canyon is shown below:
Year ended December 31, --------------------------- (in millions) 1994 1993 1992 Operating revenues $1,870 $1,933 $1,781 Operating income 618 708 663 Net income 461 496 443
In determining operating results of Diablo Canyon, operating revenues were specifically identified pursuant to the Diablo Canyon settlement. The majority of operating expenses were also specifically identified, including income tax expense. Administrative and general expense, principally labor costs, is allocated based on a study of labor costs. Interest is charged to Diablo Canyon based on an allocation of corporate debt. Note 5: Preferred Stock Nonredeemable preferred stock ($25 par value) consists of 5%, 5.5% and 6% series, which have rights to annual dividends per share of $1.25, $1.375 and $1.50, respectively. Redeemable preferred stock without mandatory redemption provisions (4.36 percent to 8.2 percent, $25 par value) is subject to redemption at the Company's option, in whole or in part, if the Company pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. Annual dividends and redemption prices per share range from $1.09 to $2.05, and from $25.75 to $28.125, respectively. The 6.30% (due 2004 to 2009) and the 6.57% (due 2002 to 2007) series of preferred stock are subject to mandatory redemption provisions and are entitled to sinking funds providing for the retirement of stock outstanding, beginning on January 31, 2004, and July 31, 2002, respectively, at par value plus accumulated and unpaid dividends through the redemption date. In addition, the 6.30% and 6.57% series may be redeemed at the Company's option at par value plus 33 23 accumulated and unpaid dividends on or after January 31, 2004, and July 31, 2002, respectively. The estimated fair value of the Company's preferred stock with mandatory redemption provisions at December 31, 1994 and 1993, was approximately $117 million and $81 million, respectively, based primarily on matrix pricing models. During 1994, the Company issued $63 million of 6.30% redeemable preferred stock and redeemed the 8.16% redeemable preferred stock with a par value of $75 million. During 1993, the Company issued $125 million of 6 7/8% redeemable preferred stock and $75 million of 7.04% redeemable preferred stock. Proceeds were used to finance a portion of the 1993 redemption of the Company's 9.00%, 9.30%, 9.48% and 10.17% redeemable preferred stock with an aggregate par value of $267 million. Dividends on preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Company, holders of the preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. Note 6: Long-term Debt Mortgage Bonds: The Company's First and Refunding Mortgage Bonds are issued in series, and at December 31, 1994, bear annual interest rates ranging from 4.25 percent to 12.75 percent and mature from 1995 to 2026. The Company had $5.9 billion and $6.0 billion of mortgage bonds outstanding at December 31, 1994 and 1993, respectively. Additional bonds may be issued, subject to CPUC approval, up to a maximum total amount outstanding of $10 billion, assuming compliance with indenture covenants for earnings coverage and property available as security. The Board of Directors (Board) may increase the amount authorized, subject to CPUC approval. The indenture requires that net earnings excluding depreciation and interest be equal to or greater than 1.75 times the annual interest charges on the Company's mortgage bonds outstanding. All real properties and substantially all personal properties of PG&E are subject to the lien of the indenture. The Company is required by the indenture to make semi-annual sinking fund payments on February 1 and August 1 of each year for the retirement of the bonds. These payments equal .5 percent of the aggregate bonded indebtedness outstanding on the preceding November 30 and May 31, respectively. Bonds of any series, with certain exceptions, may be used to satisfy this requirement. In addition, holders of series 84D bonds maturing in 2017 have an option to redeem their bonds in 1995. In conjunction with the Company's focus on reducing the levels of higher-cost debt, the Company redeemed or repurchased $80 million and $3,536 million of higher-cost mortgage bonds in 1994 and 1993, respectively. Interest rates on the bonds redeemed or repurchased ranged from 7.50 percent to 12.75 percent. In January 1995, the Board authorized the Company to redeem or repurchase up to $153 million of mortgage bonds. Included in the total of outstanding mortgage bonds are First and Refunding Mortgage Bonds issued by the Company to finance air and water pollution control and sewage and solid waste disposal facilities. These mortgage bonds are held in trust for the California Pollution Control Financing Authority (CPCFA), who arranged these financings, and are in addition to the Pollution Control Loan Agreements discussed below. At December 31, 1994 and 1993, the Company had outstanding $768 million of mortgage bonds held in trust for the CPCFA with interest rates ranging from 5.85 percent to 8.875 percent and maturity dates from 2007 to 2023. Pollution Control Loan Agreements: In addition to the pollution control loans secured by the Company's mortgage bonds (described above), the Company had loans totaling $925 million at December 31, 1994 and 1993, from the CPCFA to finance air and water pollution control and sewage and solid waste disposal facilities. Interest rates on the loans vary depending upon whether the loans are in a daily, weekly, commercial paper or fixed rate mode. Conversions from one mode to another take place at the Company's option. Average annual interest rates on these loans for 1994 ranged from 2.79 percent to 2.98 percent. These loans are subject to redemption on demand by the holder under certain circumstances and are secured by irrevocable letters of credit which mature as early as 1997. Medium-term Notes: The Company had $1,444 million of unsecured medium-term notes outstanding at December 31, 1994 with interest rates ranging from 4.13 percent to 9.90 percent and maturities from 1995 to 2014. At December 31, 1994, the Company has remaining $85 million on a previous authorization to repurchase medium-term notes. Holders of Series B medium-term notes maturing in 2004 have an option to redeem their notes in 1995. 34 24 Long-term Debt of Subsidiaries: PGT obtained long-term debt financing from a consortium of banks pursuant to a loan agreement dated April 30, 1993. Under the loan agreement, PGT borrowed $673 million to finance the pipeline expansion and its existing pipeline system. The debt is initially guaranteed by PG&E. The weighted average rate of interest on this loan during 1994 was 6.4 percent. The interest rate on the PGT debt (which ranged from 4.0 percent to 8.1 percent in 1994) is a floating rate subject to periodic determination in accordance with the terms of the loan agreement and may vary depending on the nature and the length of the borrowings, but is generally tied to the banks' base rate, domestic certificate of deposit rates, or the applicable London Interbank Offered Rates (LIBOR) for maturities ranging from one to twelve months. In 1994, PGT executed a series of interest rate swap transactions which converted $639 million of the floating rate debt to a fixed rate through July 31, 1999. The interest rate on the remaining debt outstanding, which is due in 1995, was fixed by utilizing options available to PGT under the loan agreement. At December 31, 1994, PGT had outstanding ten interest rate swap agreements with commercial banks with a total notional principal amount of $639 million. These swap agreements effectively change PGT's interest rate on its floating rate debt to a fixed rate of 8.4 percent. The interest rate swap agreements mature in July 1999. At December 31, 1994, the fair market value of these swap agreements represented an unrealized gain of $25.7 million. DALEN has a two-year revolving loan agreement expiring February 1997 which provides for maximum borrowings of $200 million at a variable interest rate. The revolving loan may be extended annually by consent of the banks and may be converted to a five-year term loan at DALEN's option. At December 31, 1994, approximately $115 million was outstanding at an effective interest rate of approximately 7 percent. The loan is secured by DALEN's oil and gas investments. Repayment Schedule: At December 31, 1994, the Company's combined aggregate amount of maturing long-term debt and sinking fund requirements, for the years 1995 through 1999, are $477 million, $373 million, $369 million, $715 million and $317 million, respectively. Fair Value: The estimated fair value of the Company's total long-term debt of $9.2 billion and $9.5 billion at December 31, 1994 and 1993, respectively, was approximately $8.6 billion (including the $25.7 million unrealized gain attributable to the PGT interest rate swap agreements) and $9.9 billion, respectively. The estimated fair value of long-term debt was determined based on quoted market prices, where available. Where quoted market prices were not available, the estimated fair value was determined using other valuation techniques (e.g., matrix pricing models or the present value of future cash flows). Note 7: Short-term Borrowings Short-term borrowings consist of commercial paper with a weighted average interest rate of 6.18 percent at December 31, 1994. The usual maturity for commercial paper is one to ninety days. Commercial paper outstanding at December 31, 1994 and 1993, was $525 million and $764 million, respectively. The carrying amount of short-term borrowings approximates fair value. The Company has a $1 billion revolving credit facility with various banks to support the sale of commercial paper and for other corporate purposes. There were no borrowings under this facility in 1994, 1993 or 1992. This credit facility expires in November 1999; however, it may be extended annually for additional one-year periods upon mutual agreement between the Company and the banks. Note 8: Investments in Debt and Equity Securities Effective January 1, 1994, the Company adopted SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," which established new financial accounting and reporting standards for investments in debt and equity securities. All of the Company's investments in debt and equity securities are included in Nuclear Decommissioning Funds and are classified as available-for-sale. These securities are held in external trust funds to be used for the decommissioning of the Company's nuclear facilities and are reported at fair value. Unrealized gains and losses are recorded to Accumulated Depreciation and Decommissioning, net of tax. Funds may not be released from the external trust funds until authorized by the CPUC. The proceeds received during 1994 from the sale of securities held as available-for-sale were approximately $1 billion. During 1994, the gross realized gains and losses on sales of securities held as available-for-sale were $9.9 million and $11.9 million, respectively. The cost of equity securities sold is determined by specific identification. The cost of debt securities sold is based on a first-in-first-out method. 35 25 The following table provides a summary of amortized cost and fair value by major security type:
- ------------------------------------------------------------------------------------------------ (in thousands) December 31, 1994 - ------------------------------------------------------------------------------------------------ Gross Gross unrealized unrealized Amortized holding holding Fair cost gains losses value --------- ---------- ---------- --------- Debt of U.S. Treasury and other federal entities $290,511 $ 20 $ (7,972) $282,559 State and local obligations 94,899 1,268 (2,485) 93,682 Equity Securities 184,954 18,556 (9,261) 194,249 Other 46,398 24 (275) 46,147 -------- ------- -------- -------- Total investments in securities $616,762 $19,868 $(19,993) $616,637 ======== ======= ======== ========
Investments in debt securities maturing within ten years totaled $293 million, and investments in debt securities with maturities in excess of ten years totaled $114 million. At December 31, 1993, the cost and estimated fair value of the decommissioning funds was $537 million and $576 million, respectively. Note 9: Employee Benefit Plans Retirement Plan: The Company provides a noncontributory defined benefit pension plan covering substantially all employees. The retirement benefits are based on years of service and the employee's base salary. The Company's funding policy is to contribute each year not more than the maximum amount deductible for federal income tax purposes and not less than the minimum contribution required under the Employee Retirement Income Security Act of 1974. At December 31, 1994, plan assets exceeded the projected benefit obligation by $517 million. The plan's funded status was:
December 31, ------------------------- (in thousands) 1994 1993 Actuarial present value of benefit obligations Vested benefits $(3,079,045) $(3,203,408) Nonvested benefits ( 131,489) (154,349) ----------- ----------- Accumulated benefit obligation (3,210,534) (3,357,757) Effect of projected future compensation increases ( 441,951) (577,926) ----------- ----------- Projected benefit obligation (3,652,485) (3,935,683) Plan assets at market value 4,169,516 4,376,110 ----------- ----------- Plan assets in excess of projected benefit obligation 517,031 440,427 Unrecognized prior service cost 93,425 117,312 Unrecognized net gain (908,485) (759,690) Unrecognized net transition obligation 108,800 120,253 ----------- ----------- Accrued pension liability $ (189,229) $ (81,698) =========== ===========
Plan assets consist substantially of common stocks and fixed-income securities. The unrecognized prior service cost is amortized over approximately 16 years. The unrecognized net transition obligation is amortized over approximately 18 years, beginning in 1987. The vested benefit obligation is the actuarial present value of vested benefits to which employees are currently entitled based on their expected termination dates. Assumptions used to calculate the projected benefit obligation to determine the plan's funded status were:
December 31, ---------------------- 1994 1993 Weighted average discount rate 8% 7% Average rate of projected future compensation increases 5% 5%
The cost of this plan is charged to expense and to plant in service through construction work in progress. Net pension cost, using the projected unit credit actuarial cost method, was:
Year ended December 31, ---------------------------------- (in thousands) 1994 1993 1992 Service cost for benefits earned $ 109,132 $ 129,166 $ 127,388 Interest cost 272,932 268,698 248,674 Actual loss (return) on plan assets 20,358 (511,526) (204,576) Net amortization and deferral (412,547) 177,597 (78,560) --------- --------- --------- Net pension (income) cost $ (10,125) $ 63,935 $ 92,926 ========= ========= =========
The decrease in net pension cost in 1994 compared to 1993 was primarily due to changes in the assumed rates of projected compensation increases and turnover to better reflect actual and expected rates. The decrease in net pension cost in 1993 compared to 1992 was primarily due to a change in the expected long-term rate of return on plan assets to better reflect actual and expected earnings on the funds invested. The expected long-term rate of return on plan assets used to calculate pension cost was nine percent for 1994 and 1993 and eight percent for 1992. Net pension cost is calculated using expected return on plan assets. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the determination of future pension cost. In 1994, the plan experienced a negative rather 36 26 than an expected positive investment return on plan assets, due to weak performance in domestic equities and bonds. In 1993, actual return on plan assets exceeded expected return whereas, in 1992, actual return on plan assets was less than expected. In conformity with accounting for rate-regulated enterprises, regulatory adjustments have been recorded in the income statement and balance sheet for the difference between utility pension cost determined for accounting purposes and that for ratemaking, which is based on a contribution approach. Savings Fund Plan: The Company sponsors a defined contribution pension plan to which employees with at least one year of service may make contributions. Employees may contribute up to 15 percent of their covered compensation on a pretax or after-tax basis. These contributions, up to a maximum of six percent of covered compensation, are eligible for matching Company contributions at specified rates. The cost of Company contributions was charged to expense and to plant in service through construction work in progress and totaled $35 million, $36 million and $35 million for 1994, 1993 and 1992, respectively. Long-term Incentive Program: The Company implemented a Long-term Incentive Program (Program) in 1992. The Program allows eligible participants to be granted stock options with or without associated stock appreciation rights, dividend equivalents and/or performance-based units. The Program incorporates those shares previously authorized under the Company's 1986 Stock Option Plan. A total of 14.5 million shares of common stock have been authorized for award under the Program and the 1986 Stock Option Plan. Costs associated with the Program, which have not been significant, are not recoverable in rates. At December 31, 1994, stock options on 2,496,356 shares, granted at option prices ranging from $16.75 to $34.25, were outstanding. During 1994, 597,000 options were granted at an option price of $34.25, which was the market price per share on the date of grant. Outstanding stock options expire ten years and one day after the date of grant and become exercisable on a cumulative basis at one-third each year commencing two years from the date of grant. Stock options also become exercisable within certain time limitations upon the optionee's termination due to retirement, disability or death, and upon certain changes in control of the Company. In 1994, 1993 and 1992, stock options on 52,143, 174,387 and 157,446 shares, respectively, were exercised at option prices ranging from $24.75 to $32.13, $16.75 to $33.13 and $16.75 to $26.63, respectively. At December 31, 1994, stock options on 940,076 shares were exercisable. Postretirement Benefits Other Than Pensions: The Company provides a contributory defined benefit medical plan for retired employees and their eligible dependents and a noncontributory defined benefit life insurance plan for retired employees. Substantially all employees retiring at or after age 55 are eligible for these benefits. The medical benefits are provided through plans administered by an insurance carrier or a health maintenance organization. Certain retirees are responsible for a portion of the cost based on past claims experience of the Company's retirees. In 1993, the Company implemented a plan change that will limit the amount it will contribute toward postretirement medical benefits. This limitation will take effect for all retirees beginning in 2001. The Company's funding policy for the medical and life insurance benefits is to contribute each year the amount provided for in rates. Life insurance benefits which are not funded are provided through an insurance company at a cost based on total current claims paid plus administrative fees. The cost of these plans is charged to expense and to plant in service through construction work in progress. Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," which requires accrual of the expected cost of these benefits during the employees' years of service. The assumptions and calculations involved in determining the accrual closely parallel pension accounting requirements. The Company previously recognized these costs as benefits were paid and funded, which was consistent with ratemaking. In December 1992, the CPUC issued a decision on the ratemaking treatment for these benefits in 1993 and beyond. The decision authorized recovery of these benefits, within certain guidelines, at a level equal to the lesser of the annual SFAS No. 106 cost, based on amortization of the transition obligation over 20 years, or the amount which can be contributed annually on a tax-deductible basis to appropriate trusts. Due to this regulatory treatment, adoption of SFAS No. 106 did not have a significant impact on the Company's financial position or results of operations. 37 27 At December 31, 1994, the accumulated postretirement benefit obligation exceeded plan assets by $427 million, principally due to recent adoption of SFAS No. 106. The medical and life insurance plans' funded status was:
(in thousands) December 31, ------------------------------- 1994 1993 Accumulated postretirement benefit obligation Retirees $(497,889) $(384,706) Other fully eligible participants (104,865) (148,018) Other active plan participants (219,639) (365,786) --------- --------- Total accumulated postretirement benefit obligation (822,393) (898,510) Plan assets at market value 394,939 345,938 --------- --------- Accumulated postretirement benefit obligation in excess of plan assets (427,454) (552,572) Unrecognized prior service cost 25,377 - Unrecognized net (gain) loss (115,249) 21,481 Unrecognized transition obligation 462,082 543,939 --------- --------- (Accrued) prepaid postretirement benefit liability $ (55,244) $ 12,848 ========= =========
The unrecognized prior service cost in 1994 reflects a plan amendment which provides an increase in benefits to certain retirees. It is amortized over approximately 18 years. Plan assets consist substantially of common stocks and fixed-income securities. In accordance with SFAS No. 106, the Company elected to amortize the actuarially-determined transition obligation over 20 years beginning in 1993. The plan change implemented in 1993 that will limit the Company's contributions toward postretirement medical benefits reduced the accumulated postretirement benefit obligation at July 1, 1993 by approximately $450 million. The assumptions used to calculate the benefit obligations included a weighted average discount rate of eight percent for 1994 and seven percent for 1993, and an average rate of projected future compensation increases of five percent for 1994 and 1993. The assumed health care cost trend rate for 1995 is approximately 11 percent, grading down to an ultimate rate in 2005 of approximately six percent. The effect of a one-percentage-point increase in the assumed health care cost trend rate for each future year would increase the accumulated postretirement benefit obligation at December 31, 1994, by approximately $110 million and the 1994 aggregate service and interest costs by approximately $13 million. Net postretirement medical and life insurance cost, using the projected unit credit actuarial cost method, was:
Year ended December 31, --------------------------- (in thousands) 1994 1993 Service cost for benefits earned $ 23,617 $ 38,496 Interest cost 64,872 73,502 Actual return on plan assets (1,232) (23,999) Amortization of unrecognized prior service cost 1,711 - Amortization of transition obligation 28,913 39,620 Net amortization and deferral (29,804) (3,390) -------- -------- Net postretirement benefit cost $ 88,077 $124,229 ======== ========
The decrease in net postretirement benefit cost in 1994 compared to 1993 was primarily due to the plan change implemented July 1, 1993 that will limit the Company's contributions toward postretirement medical benefits. The expected long-term rate of return on plan assets used to calculate postretirement medical and life insurance benefit costs was nine percent for 1994 and 1993. Net postretirement benefit cost is calculated using expected return on plan assets. The difference between actual and expected return on plan assets is included in net amortization and deferral and is considered in the determination of future postretirement benefit cost. In 1994 and 1993, actual return on plan assets was less than expected return. For 1992, the cost of postretirement medical and life insurance benefits was based on benefits paid and funded and totaled $98 million. Workforce Reductions: The effects of workforce reductions announced by the Company in 1994 and 1993 are reflected in the pension and postretirement benefits funded status tables above and the costs are discussed in Note 10. Postemployment Benefits: Effective January 1, 1994, the Company adopted SFAS No. 112, "Employers' Accounting for Postemployment Benefits," which requires employers to adopt accrual accounting for benefits provided to former or inactive employees and their beneficiaries and covered dependents, after employment but before retirement. For the Company, such benefits consist primarily of long-term disability, workers' compensation, and continuation of medical and life insurance coverage. Due to current regulatory treatment, adoption of SFAS No. 112 did not have a significant impact on the Company's financial position or results of operations. Adoption of SFAS No. 112 resulted in an increase of approximately $90 million in noncurrent liabilities and deferred charges as of January 1, 1994. 38 28 Note 10: Workforce Reductions In 1994, the Company announced workforce reductions which when combined with the 3,000 positions eliminated in 1993 will result in the elimination of approximately 6,000 positions by the end of 1995. The majority of the reductions have occurred through voluntary retirement incentives (VRI) for employees 50 years of age with at least 15 years of service. Remaining reductions will be accomplished by severances and attrition in 1995. In December 1994, the Company expensed the total cost of the 1994 workforce reductions of $249 million and recorded a corresponding liability for benefits to be funded or paid. This amount consists of $136 million for additional pension benefits and $52 million for other postretirement benefits extended in connection with the VRI, and $61 million of estimated severance costs for approximately 1,500 severances. Most of these severances will be in the Customer Energy Services and Electric Supply business units, in functions that the Company has determined to be not absolutely necessary for safe, reliable and responsive service, including construction and certain staff and support services. The Company does not plan to seek rate recovery for the cost of the 1994 workforce reductions as it did with the 1993 workforce reductions. The total cost of the 1993 workforce reductions was $264 million, net of a curtailment gain relating to pension benefits. Included in this amount was $151 million for additional pension benefits and $22 million for other postretirement benefits extended in connection with the VRI. As a result of a freeze on electric rates, the Company expensed $190 million of workforce reduction costs relating to electric operations. The amount relating to gas operations was deferred for future rate recovery and is being amortized as savings are realized. At December 31, 1994, $31 million remained to be amortized. The Company recorded the costs and savings incurred in connection with the 1993 workforce reductions in a memorandum account authorized by the CPUC, with the recovery of such costs subject to a CPUC reasonableness review. Note 11: Income Taxes The current and deferred components of income tax expense were:
Year ended December 31, ----------------------------------- (in thousands) 1994 1993 1992 Current Federal $ 606,885 $ 417,558 $536,774 State 214,570 165,134 193,895 --------- ---------- -------- Total current 821,455 582,692 730,669 --------- ---------- -------- Deferred (substantially all federal) Depreciation 174,600 207,690 165,944 Regulatory balancing accounts 96,881 77,515 85,210 Workforce reduction (102,975) 24,765 - Gas reasonableness (47,952) (25,037) - (Gain) loss on reacquired debt (6,374) 42,405 15,959 Other--net (79,523) 12,270 (78,783) --------- ---------- -------- Total deferred 34,657 339,608 188,330 --------- ---------- -------- Investment tax credits--net (19,345) (20,410) (23,873) --------- ---------- -------- Total income tax expense $ 836,767 $ 901,890 $895,126 ========= ========== ======== Classification of income tax expense: Included in operating expenses $ 924,620 $1,006,774 $906,845 Included in other--net (87,853) (104,884) (11,719) --------- ---------- -------- Total income tax expense $ 836,767 $ 901,890 $895,126 ========= ========== ========
The significant components of net deferred income tax liabilities are as follows:
December 31, ------------------------------------ (in thousands) 1994 1993 - ----------------------------------------------------------------------------------------- Deferred income taxes assets: Deferred income taxes--current $ 173,357 $ 160,177 Deferred income taxes--noncurrent 959,459 647,018 ---------- ---------- Total deferred income tax assets 1,132,816 807,195 ========== ========== Deferred income tax liabilities: Deferred income taxes--current Regulatory balancing accounts 559,750 449,216 Other 45,633 26,545 ---------- ---------- Total deferred income taxes--current 605,383 475,761 ---------- ---------- Deferred income taxes-noncurrent Plant in service 3,627,294 3,386,122 Income tax-related deferred charges (1) 474,242 523,953 Other 760,568 715,893 ---------- ---------- Total deferred income taxes--noncurrent 4,862,104 4,625,968 ---------- ---------- Total deferred income tax liabilities 5,467,487 5,101,729 ========== ========== Total net deferred income taxes $4,334,671 $4,294,534 ========== ========== Classification of net deferred income taxes: Included in current liabilities $ 432,026 $ 315,584 Included in deferred credits 3,902,645 3,978,950 ---------- ---------- Total net deferred income taxes $4,334,671 $4,294,534 ========== ==========
(1) Represents the portion of the deferred income tax liability related to the revenues required to recover future income taxes. 39 29 The differences between income taxes and amounts determined by applying the federal statutory rate to income before income tax expense were:
Year ended December 31, ------------------------------- 1994 1993 1992 Federal statutory income tax rate 35.0% 35.0% 34.0% Increase (decrease) in income tax rate resulting from State income tax (net of federal benefit) 8.3 6.5 6.7 Effect of regulatory treatment of depreciation differences 3.7 4.5 5.0 Investment tax credits (1.1) (1.0) (1.2) Other--net (.5) .8 (1.2) ---- ---- ---- Effective tax rate 45.4% 45.8% 43.3% ==== ==== ====
Note 12: Commitments Capital Projects: Capital expenditures for 1995 are estimated to be approximately $1,544 million, consisting of $1,212 million for utility expenditures, $47 million for Diablo Canyon expenditures and $285 million for nonregulated expenditures. At December 31, 1994, Enterprises had firm commitments totaling $214 million to make capital contributions for its equity share of generating facility projects. The contributions, payable upon commercial operation of the projects, are estimated to be $100 million in 1995 and $114 million in 1996. QFs: Under the Public Utility Regulatory Policies Act of 1978, the Company is required to purchase electric energy and capacity produced by QFs. The CPUC established a series of power purchase agreements which set the applicable terms, conditions and price options. QFs must meet certain performance obligations, depending on the contract, prior to receiving capacity payments. The total cost of both energy and capacity payments to QFs is recoverable in rates. The Company's contracts with QFs expire on various dates from 1995 to 2026. Under these contracts, the Company is required to make payments only when energy is supplied or when capacity commitments are met. Payments to QFs are expected to vary in future years. In 1994, the Company negotiated early termination or suspension of certain QF contracts at a cost of $155 million to be paid over a six-year period beginning in 1994. This amount was deferred and is expected to be recovered in future rates. QF deliveries in the aggregate account for approximately 21 percent of the Company's 1994 electric energy requirements and no single contract accounted for more than five percent of the Company's energy needs. QF deliveries in 1994 represented approximately 86 percent of the QFs' plant output, in the aggregate. The amount of energy received from QFs and the total energy and capacity payments made under these agreements were:
Year ended December 31, ----------------------------- (in millions) 1994 1993 1992 Kilowatthours received 21,699 21,242 21,173 Energy payments $ 1,196 $ 1,099 $ 1,084 Capacity payments $ 518 $ 503 $ 489
Irrigation Districts and Water Agencies: The Company has contracts with various irrigation districts and water agencies to purchase hydroelectric power. The contracts expire on various dates from 2004 to 2031. Under these contracts, the Company must make specified semi-annual minimum payments whether or not any energy is supplied, subject to the provider's retention of the FERC's authorization. Additional variable payments for operation and maintenance costs incurred by the providers are also required to be made under the contracts. The total cost of these payments is recoverable in rates. At December 31, 1994, the future minimum payments under these contracts are $34 million for each of the years 1995 through 1999 and a total of $451 million for periods thereafter. Total payments under these contracts were $49 million, $45 million and $54 million in 1994, 1993 and 1992, respectively. Note 13: Contingencies Helms Pumped Storage Plant (Helms): Helms, a three-unit hydroelectric combined generating and pumped storage facility, completion of which was delayed due to a water conduit rupture in 1982 and various start-up problems related to the plant's generators, became commercially operable in 1984. As a result of the damage caused by the rupture and the delay in the operational date, the Company incurred additional costs which are currently excluded from rate base and lost revenues during the period while the plant was under repair. In October 1994, the Company signed a settlement with the DRA regarding the recovery of Helms costs not currently in rate base and prior-year revenue requirements related to these costs. The settlement provides for recovery of substantially all of the remaining net unrecovered costs (after adjustment for depreciation) and revenues. The settlement has been submitted to the CPUC for approval. 40 30 The Company cannot predict whether the settlement will be approved by the CPUC. However, the Company does not believe the ultimate outcome of the matter will have a significant impact on its financial position or results of operations. Nuclear Insurance: The Company is a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). Under these policies, if the nuclear plant of a member utility is damaged or the member incurs costs beyond those covered by insurance for business interruption due to a prolonged accidental outage, the Company may be subject to maximum assessments of $28 million (property damage) and $7 million (business interruption), in each case per policy period, in the event losses exceed the resources of NML or NEIL. The federal government has enacted laws that require all utilities with nuclear generating facilities to share in payment for claims resulting from a nuclear incident. The Price-Anderson Act limits industry liability for third-party claims resulting from any nuclear incident to $8.9 billion per incident. Coverage of the first $200 million is provided by a pool of commercial insurers. If a nuclear incident results in public liability claims in excess of $200 million, the Company may be assessed up to $159 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation: The Company assesses, on an ongoing basis, measures that may need to be taken to comply with laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Company may be required to pay for remedial action at sites where the Company has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA; federal Superfund law) or the California Hazardous Substance Account Act (California Superfund law). These sites include former manufactured gas plant sites and sites used by the Company for the storage or disposal of materials which may be determined to present a significant threat to human health or the environment because of an actual or potential release of hazardous substances. Under CERCLA, the Company's financial responsibilities may include remediation of hazardous wastes, even if the Company did not deposit those wastes on the site. The overall costs of the hazardous materials and hazardous waste compliance and remediation activities ultimately undertaken by the Company are difficult to estimate due to uncertainty concerning the Company's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Company has an accrued liability at December 31, 1994, of $95 million for hazardous waste remediation costs. The costs may be as much as $235 million if, among other things, the Company is held responsible for cleanup at additional sites, other potentially responsible parties are not financially able to contribute to these costs, or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Company is responsible. The Company will seek recovery of prudently incurred hazardous waste compliance and remediation costs through ratemaking procedures approved by the CPUC. The Company believes the ultimate outcome of these matters will not have a significant adverse impact on its financial position or results of operations. Legal Matters: Stanislaus Litigation: In 1993, a lawsuit was filed on behalf of the County of Stanislaus, California and a residential customer of the Company and purportedly as a class action on behalf of all natural gas customers of the Company during the period of February 1988 through October 1993. The lawsuit alleged that the purchase of natural gas in Canada by A&S was accomplished in violation of various antitrust laws resulting in increased prices of natural gas for PG&E's customers. Damages to the class members were estimated as potentially exceeding $800 million. The complaint indicated that the damages to the class could include over $150 million paid by the Company to terminate the contracts with the Canadian gas producers in November 1993. In August 1994, a federal district court granted the Company's motion to dismiss the federal and state antitrust claims and the state unfair practices claims against the Company and PGT. The court also granted the plaintiffs' motion seeking class certification. In September 1994, the plaintiffs filed an amended complaint in which A&S has been added as a defendant. The amended complaint restates the claims in the original complaint and alleges that the defendants, through anticompetitive practices, precluded certain customers of the Company access to alternative sources of gas in Canada over the PGT pipeline. A new motion to dismiss was filed by the Company in early November 1994. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position. 41 31 Hinkley Litigation: In 1993, a complaint was filed in a state superior court on behalf of individuals seeking recovery of an unspecified amount of damages for personal injuries and property damage allegedly suffered as a result of exposure to chromium near the Company's Hinkley Compressor Station, as well as punitive damages. The original complaint has been amended, and additional complaints have been filed, to include additional plaintiffs. The plaintiffs contend that the Company discharged chromium-contaminated wastewater into unlined ponds, which led to chromium percolating into the groundwater of surrounding property. The plaintiffs further allege that the Company discharged the chromium into those ponds to avoid costly alternatives. The Company has reached an agreement with plaintiffs pursuant to which those plaintiffs' actions will be submitted to binding arbitration for resolution of issues concerning the cause and extent of any damages suffered by plaintiffs as a result of the alleged chromium contamination. Under the terms of the agreement, the Company will pay an aggregate amount of no more than $400 million in settlement of such plaintiffs' claims, including $50 million paid to escrow to date. In turn, those plaintiffs, and their attorneys, agree to indemnify the Company against any additional losses the Company may incur with respect to related claims pursued by the identified plaintiffs who do not agree to this settlement or by other third parties who may be sued by the plaintiffs in connection with the alleged chromium contamination. At December 31, 1994, the Company has a remaining reserve of $50 million against any future potential liability in this case. The Company believes the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. County Franchise Fees Litigation: In March 1994, Santa Clara and Alameda counties filed a class action suit in a state superior court against the Company on behalf of themselves and 45 other counties in the Company's service area. This lawsuit alleges that the Company underpaid franchise fees to the counties for the right to use or occupy public streets or roads as a result of incorrectly computing these payments. Should the counties prevail, the amount of damages for alleged underpayments for the years 1987 through 1994 could be as high as $145 million, including interest, at Decmeber 31, 1994. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. City Franchise Fees Litigation: In May 1994, the City of Santa Cruz filed a class action suit in a state superior court against the Company on behalf of itself and 106 other cities in the Company's service area. The complaint alleges that the Company has underpaid electric franchise fees to the cities by calculating fees at different rates from other cities. Should the cities prevail, the amount of damages for alleged underpayments for the years 1987 through 1994 could be as high as $137 million, including interest, at December 31, 1994. The Company believes that the ultimate outcome of this matter will not have a significant adverse impact on its financial position or results of operations. 42 32 Pacific Gas and Electric Company Quarterly Consolidated Financial Data (Unaudited) Quarterly Financial Data: Due to the seasonal nature of the utility business and the scheduled refueling outages for Diablo Canyon, operating revenues, operating income and net income are not generated evenly by quarter during the year. In the first quarter of 1994, the Company took a charge against earnings of approximately $90 million as a result of the CPUC disallowances in the gas reasonableness proceedings for 1988 through 1990 and the Company's assessment of open reasonableness issues. In the second quarter of 1994, the Company increased its litigation reserves by $50 million. In the fourth quarter of 1994, the Company took a charge against earnings of $249 million related to 1994 workforce reductions. In the second quarter of 1993, the Company took a charge against earnings of $141 million related to the workforce reductions for management employees. In the third quarter of 1993, the Company's earnings reflected charges of $144 million resulting from the Company's workforce reductions, termination of Canadian gas contracts and an increase in the federal income tax rate. The fourth quarter of 1993 reflected charges against earnings of $126 million for Canadian gas costs incurred by the Company for 1988 through 1990 and for commitments for gas transportation capacity. The Company's common stock is traded on the New York, Pacific, London, Amsterdam, Basel and Zurich stock exchanges. There were approximately 230,000 common shareholders of record at December 31, 1994. Dividends are paid on a quarterly basis, and there are no significant restrictions on the present ability of the Company to pay dividends.
Quarter ended ---------------------------------------------------- (in thousands, except per share amounts) December 31 September 30 June 30 March 31 1994 Operating revenues $2,638,179 $2,855,221 $2,439,680 $2,514,271 Operating income 238,286 584,694 395,705 414,674 Net income 103,500 425,633 241,365 236,952 Earnings per common share (1) .21 .96 .53 .52 Dividends declared per common share .49 .49 .49 .49 Common stock price per share High 25.25 25.13 29.75 35.00 Low 21.38 22.00 22.50 28.50 1993 Operating revenues $2,707,171 $2,947,294 $2,464,125 $2,463,818 Operating income 428,914 525,981 387,707 420,328 Net income 208,382 356,099 245,350 255,664 Earnings per common share (1) .45 .79 .53 .56 Dividends declared per common share .47 .47 .47 .47 Common stock price per share High 36.75 36.63 35.38 35.75 Low 33.50 33.13 31.75 31.75
(1) Includes Diablo Canyon scheduled refueling outages which impacted earnings per common share for all quarters in 1994 and for the first and second quarters of 1993. In addition, Diablo Canyon experienced unscheduled outages in the second quarter of 1994. 43 33 Pacific Gas and Electric Company REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and the Board of Directors of Pacific Gas and Electric Company: We have audited the accompanying consolidated balance sheet and the statement of consolidated capitalization of Pacific Gas and Electric Company (a California corporation) and subsidiaries as of December 31, 1994 and 1993, and the related statements of consolidated income, cash flows, common stock equity and preferred stock, and the schedule of consolidated segment information for each of the three years in the period ended December 31, 1994. These financial statements and schedule of consolidated segment information are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements and schedule of consolidated segment information referred to above present fairly, in all material respects, the financial position of Pacific Gas and Electric Company and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. As discussed in Note 2 of Notes to Consolidated Financial Statements, in 1994, the California Public Utilities Commission (CPUC) issued a proposal to restructure the electric industry in California which could significantly alter the ratemaking applied to the Company. If this proposal is adopted or if electric generation rates are no longer based on cost of service, the Company would discontinue the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" for a portion of its operations. The CPUC's proposal could also impact the recovery of certain costs, including power purchase obligations and investments in related electric generation assets. Currently, the Company is unable to predict the ultimate outcome of the electric industry restructuring or predict whether such outcome will have a significant impact on its financial position or results of operations. As explained in Notes 1 and 9 of Notes to Consolidated Financial Statements, effective January 1, 1993, the Company changed its method of accounting for postretirement benefits other than pensions and for income taxes. ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP San Francisco, California February 6, 1995 44 34 Pacific Gas and Electric Company RESPONSIBILITY FOR FINANCIAL STATEMENTS The responsibility for the integrity of the financial information included in this report rests with management. Such information has been prepared in accordance with generally accepted accounting principles appropriate in the circumstances, and is based on the Company's best estimates and judgments after giving consideration to materiality. The Company maintains systems of internal controls supported by formal policies and procedures which are communicated throughout the Company. These controls are adequate to provide reasonable assurance that assets are safeguarded from material loss or unauthorized use and to produce the records necessary for the preparation of financial information. There are limits inherent in all systems of internal controls, based on the recognition that the costs of such systems should not exceed the benefits to be derived. The Company believes its systems provide this appropriate balance. In addition, the Company's internal auditors perform audits and evaluate the adequacy of and the adherence to these controls, policies and procedures. Arthur Andersen LLP, the Company's independent public accountants, considered the Company's systems of internal accounting controls and have conducted other tests as they deemed necessary to support their opinion on the consolidated financial statements. Their auditors' report contains an independent informed judgment as to the fairness, in all material respects, of the Company's reported results of operations and financial position. The financial data contained in this report have been reviewed by the Audit Committee of the Board of Directors. The Audit Committee is composed of six outside directors who meet regularly with management, the corporate internal auditors and Arthur Andersen LLP, jointly and separately, to review internal accounting controls and auditing and financial reporting matters. The Company maintains high standards in selecting, training and developing personnel to ensure that management's objectives of maintaining strong, effective internal controls and unbiased, uniform reporting standards are attained. The Company believes its policies and procedures provide reasonable assurance that operations are conducted in conformity with applicable laws and with its commitment to a high standard of business conduct. 45 EX-23 10 CONSENT OF ARTHUR ANDERSEN LLP 1 Exhibit 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports dated February 6, 1995, included or incorporated by reference in this Form 10-K, into the Company's previously filed registration statements as follows: (1) Form S-3 Registration Statement File No. 33-7542 (relating to the Company's Common Stock Shelf Program); (2) Form S-3 Registration Statement File No. 33-54469 (relating to the Company's Dividend Reinvestment Plan); (3) Form S-3 Registration Statement File No. 33-64136 (relating to $2,000,000,000 aggregate principal amount of the Company's First and Refunding Mortgage Bonds and Medium-Term Notes); (4) Form S-3 Registration Statement File No. 33-50707 (relating to $1,500,000,000 aggregate principal amount of the Company's First and Refunding Mortgage Bonds); (5) Form S-3 Registration Statement File No. 33-38334 (relating to 2,414,892 shares of the Company's Common Stock); (6) Form S-8 Registration Statement File No. 33-50601 (relating to the Company's Savings Fund Plan for Employees); (7) Form S-8 Registration Statement File No. 33-23692 (relating to the Company's 1986 Stock Option Plan); and (8) Form S-3 Registration Statement File No. 33-62488 (relating to 10,000,000 shares of the Company's Redeemable First Preferred Stock). ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP San Francisco, California March 27, 1995 EX-24.1 11 RESOLUTION OF THE BOARD OF DIRECTORS 1 Exhibit 24.1 RESOLUTION OF THE BOARD OF DIRECTORS OF PACIFIC GAS AND ELECTRIC COMPANY March 15, 1995 BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y. H. CHENG, KATHLEEN RUEGER, GARY P. ENCINAS, and JULIE C. GAVIN is hereby authorized to sign on behalf of this corporation and as attorneys in fact for the President and Chief Executive Officer, Vice President and Chief Financial Officer, and Controller of this corporation the Form 10-K Annual Report for the year ended December 31, 1994, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and all amendments and other filings or documents related thereto to be filed with the Securities and Exchange Commission, and to do any and all acts necessary to satisfy the requirements of the Securities Exchange Act of 1934 and the regulations of the Securities and Exchange Commission adopted thereto with regard to said Form 10-K Annual Report. 2 I, KATHLEEN RUEGER, do hereby certify that I am an Assistant Corporate Secretary of PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of California; that the above and foregoing is a full, true and correct copy of a resolution which was dully adopted by the Board of Directors of said corporation at a meeting of said Board which was duly and regularly called and held at the office of said corporation on March 15, 1995, and that this resolution has never been amended, revoked, or repealed, but is still in full force and effect. WITNESS my hand and the seal of said corporation hereunto affixed this 23 day of March, 1995. KATHLEEN RUEGER Kathleen Rueger Assistant Corporate Secretary PACIFIC GAS AND ELECTRIC COMPANY CORPORATE SEAL EX-24.2 12 POWERS OF ATTORNEY 1 Exhibit 24.2 POWER OF ATTORNEY Each of the undersigned Directors of Pacific Gas and Electric Company hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y. H. CHENG, KATHLEEN RUEGER, GARY P. ENCINAS or JULIE C. GAVIN his or her attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his or her capacity as such Director of said corporation the Form 10-K Annual Report for the year ended December 31, 1994, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. In WITNESS WHEREOF, we have signed these presents this 15th day of March, 1995. Richard A. Clarke David M. Lawrence - ------------------------------ ------------------------------ Stanley T. Skinner Alan Seelenfreund - ------------------------------ ------------------------------ Leslie L. Luttgens Barry Lawson Williams - ------------------------------ ------------------------------ H.M. Conger Carl E. Reichardt - ------------------------------ ------------------------------ William F. Miller John B. M. Place - ------------------------------ ------------------------------ Mary S. Metz Richard B. Madden - ------------------------------ ------------------------------ Melvin B. Lane George A. Maneatis - ------------------------------ ------------------------------ John C. Sawhill - ------------------------------ ------------------------------ William S. Davilla - ------------------------------ ------------------------------ 2 POWER OF ATTORNEY STANLEY T. SKINNER, the undersigned, President and Chief Executive Officer and Director of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y. H. CHENG, KATHLEEN RUEGER, GARY P. ENCINAS or JULIE C. GAVIN his attorneys in fact with full power of substitution to sign with the Securities and Exchange Commission in his capacity as President and Chief Executive Officer and Director of said corporation the Form 10-K Annual Report for the year ended December 31, 1994, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 15th day of March, 1995. STANLEY T. SKINNER ------------------ STANLEY T. SKINNER 3 POWER OF ATTORNEY GORDON R. SMITH, the undersigned, Vice President and Chief Financial Officer of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y. H. CHENG, KATHLEEN RUEGER, GARY P. ENCINAS or JULIE C. GAVIN his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Vice President and Chief Financial Officer of said corporation the Form 10-K Annual Report for the year ended December 31, 1994, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 15th day of March, 1995. GORDON R. SMITH --------------- GORDON R. SMITH 4 POWER OF ATTORNEY THOMAS C. LONG, the undersigned, Controller of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y. H. CHENG, KATHLEEN RUEGER, GARY P. ENCINAS or JULIE C. GAVIN his attorneys in fact with full power of substitution to sign and file with the Securities and Exchange Commission in his capacity as Controller of said corporation the Form 10-K Annual Report for the year ended December 31, 1994, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all amendments and other filings or documents related thereto, and hereby ratifies all that said attorneys in fact or any of them may do or cause to be done by virtue hereof. IN WITNESS WHEREOF, I have signed these presents this 15th day of March, 1995. THOMAS C. LONG -------------- THOMAS C. LONG EX-99 13 FORM 11-K SAVINGS FUND PLAN INFORMATION 1 Exhibit 99 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 -------- INFORMATION REQUIRED BY FORM 11-K ANNUAL REPORT PURSUANT TO SECTION 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 1994 A. Full titled of the plan and the address of the plan, if different from that of the issuer named below: SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY B. Name of issuer of the securities held pursuant to the plan and the address of its principal executive office: PACIFIC GAS AND ELECTRIC COMPANY 77 Beale Street P.O. Box 770000 San Francisco, CA 94177 2 The financial statements of the Savings Fund Plan Master Trust and the Savings Fund Plan Parts I, II and III (Plans) as of December 31, 1994 and 1993, the related statements of net assets as of December 31, 1994 and 1993, and changes in net assets of the Plans for the year ended December 31, 1994, and the Savings Fund Plan Master Trust schedules of assets held for investment purposes of as of December 31, 1994, and of reportable transactions for year ended December 31, 1994 together with the report of Arthur Andersen LLP, independent accountants, are presented herewith. 3 [ARTHUR ANDERSEN LLP LOGO] REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Employee Benefit Finance Committee of Pacific Gas and Electric Company and Participants in the Savings Fund Plans: We have audited the accompanying statements of net assets of Pacific Gas and Electric Company Savings Fund Plan Master Trust (the Trust) as of December 31, 1994 and 1993, and the related statement of changes in net assets for the year ended December 31, 1994. These financial statements and the schedules referred to below are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the net assets of the Trust as of December 31, 1994 and 1993, and the changes in net assets for the year ended December 31, 1994, in conformity with generally accepted accounting principles. The accompanying statements are those of the Trust established under the Pacific Gas and Electric Company Savings Fund Plan Master Trust. These statements do not purport to present the financial statements of the individual employee benefit plans and do not contain disclosures necessary for a fair presentation of the financial statements of the individual employee benefit plans in conformity with generally accepted accounting principles. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedules of assets held for investment purposes as of December 31, 1994, and reportable transactions for the year ended December 31, 1994, are presented for purposes of additional analysis and are not a required part of the basic financial statements but are supplementary information required by the Department of Labor's Rules and Regulations for Reporting and Disclosure under the Employee Retirement Income Security Act of 1974. The fund information in the statements of net assets and changes in net assets is presented for purposes of additional analysis rather than to present the net assets and changes in net assets of each fund. The supplemental schedules and fund information have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, are fairly stated in all material respects in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Arthur Andersen LLP San Francisco, California, March 10, 1995 4 [ARTHUR ANDERSEN LLP LOGO] REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Employee Benefit Finance Committee of Pacific Gas and Electric Company and Participants in the Savings Fund Plan: We have audited the accompanying statements of net assets available for benefits of Pacific Gas and Electric Company Savings Fund Plan - Part I (the Plan) as of December 31, 1994 and 1993, and the related statement of changes in net assets available for benefits for the year ended December 31, 1994. These financial statements are the responsibility of the Plan's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the net assets available for benefits of the Plan as of December 31, 1994 and 1993, and the changes in its net assets available for benefits for the year ended December 31, 1994, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Arthur Andersen LLP San Francisco, California, March 10, 1995 5 [ARTHUR ANDERSEN LLP LOGO] REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Employee Benefit Finance Committee of Pacific Gas and Electric Company and Participants in the Savings Fund Plan: We have audited the accompanying statements of net assets available for benefits of Pacific Gas and Electric Company Savings Fund Plan - Part II (the Plan) as of December 31, 1994 and 1993, and the related statement of changes in net assets available for benefits for the year ended December 31, 1994. These financial statements are the responsibility of the Plan's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the net assets available for benefits of the Plan as of December 31, 1994 and 1993, and the changes in its net assets available for benefits for the year ended December 31, 1994, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Arthur Andersen LLP San Francisco, California, March 10, 1995 6 [ARTHUR ANDERSEN LLP LOGO] REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Employee Benefit Finance Committee of Pacific Gas and Electric Company and Participants in the Savings Fund Plan: We have audited the accompanying statements of net assets available for benefits of Pacific Gas and Electric Company Savings Fund Plan - Part III (the Plan) as of December 31, 1994 and 1993, and the related statement of changes in net assets available for benefits for the year ended December 31, 1994. These financial statements are the responsibility of the Plan's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As further discussed in Note 1 to the financial statements, the Plan was terminated in conjunction with the transfer of its remaining net assets to related plans. In our opinion, the financial statements referred to above present fairly, in all material respects, the net assets available for benefits of the Plan as of December 31, 1994 and 1993, and the changes in its net assets available for benefits for the year ended December 31, 1994, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Arthur Andersen LLP San Francisco, California, March 10, 1995 7 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN MASTER TRUST FINANCIAL STATEMENTS TABLE OF CONTENTS REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS FINANCIAL STATEMENTS Statements of Net Assets - December 31, 1994 and 1993 Statement of Changes in Net Assets for the Year Ended December 31, 1994 Notes to Financial Statements - December 31, 1994 SCHEDULES Schedule I: Item 27(a) - Schedule of Assets Held for Investment Purposes - December 31, 1994 Schedule II: Item 27(d) - Schedule of Reportable Transactions for the Year Ended December 31, 1994 8 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN MASTER TRUST STATEMENT OF NET ASSETS December 31, 1994
Fund Information ------------------------------------------------- United Company States Diversified Guaranteed Stock Bond Equity Income Fund Fund Fund Fund ------- ------ ------------ ---------- ---------------------In Thousands----------------- ASSETS Investments, at fair value Pacific Gas and Electric Company common stock $1,131,413 $ - $ - $ - United States Government securities - 4,616 553 - Corporate stocks - preferred - - 1,048 - Corporate stocks - common - - 340,032 - Corporate debt instruments - - - 53,210 Insurance company general accounts - - - 151,704 Registered investment companies Vanguard Bond Market Fund - - - - Columbia Balanced Fund - - - - Dreyfus Utility Stock Fund - - - - Interest bearing accounts 163 12,254 60,228 ---------- ------ -------- -------- Total Investments 1,131,576 4,616 353,887 265,142 ---------- ------ -------- -------- Receivables Dividends and interest 22,830 - 993 2,560 Other receivables - - 6,293 - ---------- ------ -------- -------- Total Receivables 22,830 - 7,286 2,560 ---------- -------- -------- Total Assets 1,154,406 4,616 361,173 267,702 ---------- ------ -------- -------- LIABILITIES 36 - 11,371 - ---------- ------ -------- -------- Total Liabilities 36 - 11,371 - ---------- -------- -------- NET ASSETS $1,154,370 $4,616 $349,802 $267,702 ========== ====== ======== ========
Fund Information ---------------------------------------------------------------- Bond Stock and Utility Index Bond Stock PAYSOP Fund Fund Fund Fund Total ----- --------- ------- ------ ----- ---------------------------In Thousands-------------------------- ASSETS Investments, at fair value Pacific Gas and Electric Company common stock $ - $ - $ - $ - $1,131,413 United States Government securities - - - - 5,169 Corporate stocks - preferred - - - - 1,048 Corporate stocks - common - - - - 340,032 Corporate debt instruments - - - - 53,210 Insurance company general accounts - - - - 151,704 Registered investment companies Vanguard Bond Market Fund 23,632 - - - 23,632 Columbia Balanced Fund - 102,861 - - 102,861 Dreyfus Utility Stock Fund - - 45,458 - 45,458 Interest bearing accounts - - - - 72,645 ------- -------- ------- ------- ---------- Total Investments 23,632 102,861 45,458 - 1,927,172 ------- -------- ------- ------- ---------- Receivables Dividends and interest 138 - 844 - 27,365 Other receivables - - - - 6,293 ------- -------- ------- ------- ---------- Total Receivables 138 - 844 - 33,658 ------- -------- ------- ------- ---------- Total Assets 23,770 102,861 46,302 - 1,960,830 ------- -------- ------- ------- ---------- LIABILITIES - - - - 11,407 ------- -------- ------- ------- ---------- Total Liabilities - - - - 11,407 ------- -------- ------- ------- ---------- NET ASSETS $23,770 $102,861 $46,302 $ - $1,949,423 ======= ======== ======= ======= ==========
The accompanying Notes to Financial Statements are an integral part of these statements. 1 9 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN MASTER TRUST STATEMENT OF NET ASSETS December 31, 1993
Fund Information -------------------------------------------------- United Company States Diversified Guaranteed Stock Bond Equity Income Fund Fund Fund Fund -------- ------- ------------ ---------- ------------------In Thousands-------------------- ASSETS Investments, at fair value Pacific Gas and Electric Company common stock $1,569,458 $ - $ - $ - United States Government securities - 4,562 178 - Corporate stocks - preferred - - 1,299 - Corporate stocks - common - - 300,039 - Corporate debt instruments - - - 41,099 Insurance company general accounts - - - 188,421 Registered investment companies Vanguard Bond Market Fund - - - - Columbia Balanced Fund - - - - Dreyfus Utility Stock Fund - - - - Interest bearing accounts 110 24 5,135 1,328 ---------- ------ -------- -------- Total Investments 1,569,568 4,586 306,651 230,848 ---------- ------ -------- -------- Receivables Dividends and interest 21,132 - 767 2,821 Other receivables - - 1,168 - ---------- ------ -------- -------- Total Receivables 21,132 - 1,935 2,821 ---------- ------ -------- -------- Total Assets 1,590,700 4,586 308,586 233,669 ---------- ------ -------- -------- LIABILITIES - - 1,197 - ---------- ------ -------- -------- Total Liabilities - - 1,197 - ---------- ------ -------- -------- NET ASSETS $1,590,700 $4,586 $307,389 $233,669 ========== ====== ======== ========
Fund Information ------------------------------------------------------------------ Bond Stock and Utility Index Bond Stock PAYSOP Fund Fund Fund Fund Total ------ ---------- ------- ------ ----- --------------------------In Thousands--------------------------- ASSETS Investments, at fair value Pacific Gas and Electric Company common stock $ - $ - $ - $10,116 $1,579,574 United States Government securities - - - - 4,740 Corporate stocks - preferred - - - - 1,299 Corporate stocks - common - - - - 300,039 Corporate debt instruments - - - - 41,099 Insurance company general accounts - - - - 188,421 Registered investment companies Vanguard Bond Market Fund 28,740 - - - 28,740 Columbia Balanced Fund - 104,083 - - 104,083 Dreyfus Utility Stock Fund - - 75,336 - 75,336 Interest bearing accounts - - - - 6,597 ------- -------- ------- ------- ---------- Total Investments 28,740 104,083 75,336 10,116 2,329,928 ------- -------- ------- ------- ---------- Receivables Dividends and interest - - - 136 24,856 Other receivables - - - - 1,168 ------- -------- ------- ------- ---------- Total Receivables - - - 136 26,024 ------- -------- ------- ------- ---------- Total Assets 28,740 104,083 75,336 10,252 2,355,952 ------- -------- ------- ------- ---------- LIABILITIES - - - - 1,197 ------- -------- ------- ------- ---------- Total Liabilities - - - - 1,197 ------- -------- ------- ------- ---------- NET ASSETS $28,740 $104,083 $75,336 $10,252 $2,354,755 ======= ======== ======= ======= ==========
The accompanying Notes to Financial Statements are an integral part of these statements. 2 10 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN MASTER TRUST STATEMENT OF CHANGES IN NET ASSETS For the Year Ended December 31, 1994
Fund Information ---------------------------------------------------------------------- United Company States Diversified Guaranteed Bond Stock and Stock Bond Equity Income Index Bond Fund Fund Fund Fund Fund Fund ---------- ------ ----------- ---------- -------- -------- ------------------------------ In Thousands-------------------------- BALANCE, JANUARY 1, 1994 $1,590,700 $4,586 $307,389 $233,669 $28,740 $104,083 ---------- ------ ------- ------- -------- -------- ADDITIONS Participating plans contributions Participant 52,679 - 23,489 5,749 1,282 6,458 Employer 24,393 - 4,421 1,102 350 1,689 ---------- ------ ------- ------- -------- -------- Total participating plans contributions 77,072 - 27,910 6,851 1,632 8,147 ---------- ------ ------- ------- -------- -------- Earnings from investments Interest Interest bearing accounts 56 - 397 478 - - United States Government securities - 289 - - - - Fixed income investments - - - 11,373 - - ---------- ------ ------- ------- -------- -------- Total interest 56 289 397 11,851 - - Dividends - common stock 89,489 - 8,975 - - - Registered investment company dividends - - - - 1,725 - Other income 5 - 25 50 - - ---------- ------ ------- ------- ------- ------- Total earnings from investments 89,550 289 9,397 11,901 1,725 - ---------- ------ ------ ------- ------- ------- Gain (loss) on securities Realized on sale or distribution 47,181 - 10,965 - (378) 1,337 Unrealized appreciation (depreciation) in fair value of securities held (527,262) - (9,011) - (2,131) (1,277) Gains (losses) on futures contracts (545) Net appreciation (depreciation) in fair value of assets held (480,081) - 1,409 - (2,509) 60 ---------- ------ ------- ------- ------- ------- Total additions (reductions) (313,459) 289 38,716 18,752 848 8,207 ---------- ------ ------- ------- ------- ------- Fund Information ------------------------------- Utility Stock PAYSOP Fund Fund Total ------- ------- --------- ----------In Thousands--------- BALANCE, JANUARY 1, 1994 $75,336 $10,252 $2,354,755 ------- ------- ---------- ADDITIONS Participating plans contributions Participant 4,685 - 94,342 Employer 1,258 - 33,213 ------- ------- ---------- Total participating plans contributions 5,943 - 127,555 ------- ------- ---------- Earnings from investments Interest Interest bearing accounts - - 931 United States Government securities - - 289 Fixed income investments - - 11,373 ------- ------- ---------- Total interest - - 12,593 Dividends - common stock - 426 98,890 Registered investment company dividends 3,312 - 5,037 Other income - 2 82 ------- ------- ---------- Total earnings from investments 3,312 428 116,602 ------- ------- ---------- Gain (loss) on securities Realized on sale or distribution (4,656) 73 54,522 Unrealized appreciation (depreciation) in fair value of securities held (8,424) (4,008) (552,113) Gains (losses) on futures contracts (545) Net appreciation (depreciation) in fair value of assets held (13,080) (3,935) (498,136) ------- ------- ---------- Total additions (reductions) (3,825) (3,507) (253,979) ------- ------- ----------
The accompanying Notes to Financial Statements are an integral part of these statements. 3 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN MASTER TRUST STATEMENT OF CHANGES IN NET ASSETS (Continued) For the Year Ended December 31, 1994
Fund Information --------------------------------------------------------------------- United Company States Diversified Guaranteed Bond Stock and Stock Bond Equity Income Index Bond Fund Fund Fund Fund Fund Fund --------- ------ ----------- ---------- ------- -------- ------------------------In Thousands--------------------------------- DEDUCTIONS Withdrawals paid to participating plans for benefit payments $74,557 $235 $17,733 $ 43,562 $1,512 $8,558 Expenses 266 - 2 - - 519 ---------- ------ -------- -------- ------- -------- Total deductions 74,823 235 17,735 43,562 1,512 9,077 ---------- ------ -------- -------- ------- -------- TRANSFERS between investment funds (48,048) (24) 21,432 58,843 (4,306) (352) ---------- ------ -------- -------- ------- -------- CHANGE IN NET ASSETS (436,330) 30 42,413 34,033 (4,970) (1,222) ---------- ------ -------- -------- ------- -------- BALANCE, DECEMBER 31, 1994 $1,154,370 $4,616 $349,802 $267,702 $23,770 $102,861 ========== ====== ======== ======== ======= ======== Fund Information ------------------------------------- Utility Stock PAYSOP Fund Fund Total ------- ------ -------- --------------In Thousands----------- DEDUCTIONS $4,088 $314 $ 150,559 Withdrawals paid to participating plans 7 - 794 for benefit payments ------- ------- ---------- Expenses 4,095 314 151,353 ------- ------- ---------- Total deductions (21,114) (6,431) - ------- ------- ---------- TRANSFERS between investment funds (29,034) (10,252) (405,332) ------- ------- ---------- CHANGE IN NET ASSETS $46,302 $ $1,949,423 ======= ======= ========== BALANCE, DECEMBER 31, 1994
The accompanying Notes to Financial Statements are an integral part of these statements. 4 11 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN MASTER TRUST NOTES TO FINANCIAL STATEMENTS December 31,1994 NOTE 1: MASTER TRUST DESCRIPTION The Pacific Gas and Electric Company established the Savings Fund Plan Master Trust (the Master Trust) on January 1, 1988 to hold the assets of certain defined contribution retirement plans sponsored by Pacific Gas and Electric Company (the Company). Pacific Service Employees Association also participates in the Master Trust. The Master Trust is administered by Pacific Gas and Electric Company's Employee Benefit Administrative Committee, and State Street Bank and Trust Company is the trustee (the Trustee). Interest income, dividends, investment fees, and the net appreciation (depreciation) in the fair value of investments held by the Master Trust are allocated to the individual participating plans each week based upon their proportional share of the individual fund balances. Although the Company has not expressed any intent to do so, its Board of Directors reserves the right to amend or terminate the Master Trust at any time by giving written notice to the Trustee. If the Master Trust is terminated, the Master Trust assets shall be paid out to each separate participating plan in proportion to its interest in the Master Trust. NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF ACCOUNTING The financial statements of the Master Trust are prepared in conformity with generally accepted accounting principles. These financial statements do not purport to present the net assets available for benefits or the change in net assets available for benefits of any of the individual participating retirement plans and do not include all disclosures necessary for a fair presentation of the financial statements of the individual participating plans in conformity with generally accepted accounting principles. Investments in the Guaranteed Income Fund are valued at cost which approximates fair value. Generally, all other investments held by the Master Trust are stated at fair value based on published market quotations. NOTE 3: FEDERAL INCOME TAXES The Internal Revenue Service has ruled that the Master Trust is exempt under Section 501(a). Accordingly, no provision for federal income taxes has been made in the financial statements. 5 12 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN MASTER TRUST NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: INVESTMENTS The Trustee invests a significant portion of the contributions from the participating plans in the common stock of the Company. Purchases of this stock are made directly from the Company. The Company pays all costs of administering the Master Trust, including fees and expenses of the Trustee. However, customary brokerage fees and commissions due to transfers, withdrawals and distributions are paid by the plans. Investment management fees are netted against the performance of the Stock and Bond Fund and Bond Index Fund, and are paid by the Company in connection with the Diversified Equity Fund and the Guaranteed Income Fund. Individual plan participants designate the way in which their contributions are invested and may change their investment designation once each calendar quarter. Participants may elect to have their contributions invested in one or more of the following funds: - Company Stock Fund, invested in Pacific Gas and Electric Company common stock; - Diversified Equity Fund (DEF), invested in a diversified portfolio of common stock of other companies; - Guaranteed Income Fund (GIF), invested in contracts which offer a fixed rate of interest for a specified period of time; - Bond Index Fund (BIF), invested in Vanguard Bond Market Fund, a diversified portfolio consisting of marketable fixed-income securities; - Stock and Bond Fund (SBF), invested in Columbia Balanced Fund, a diversified portfolio of marketable equity securities and marketable fixed-income securities. - Utility Stock Fund (USF), invested in Dreyfus Utility Stock Fund, a portfolio of marketable equity securities of electric utility companies that are members of the Edison Electric Institute, including Pacific Gas and Electric Company. A participant's interest in the investment funds is measured in "units". For investments in the common stock of the Company and in United States Savings Bonds, a unit is a share of common stock and a United States Savings Bond, respectively. 6 13 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN MASTER TRUST NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: INVESTMENTS (CONTINUED) VALUATION OF INVESTMENTS All investments (other than GIF) held by the Master Trust are stated at fair value based on published market quotations. Investments in the GIF are valued at cost which approximates fair value. The net depreciation in fair value of investments in the accompanying statement of changes in net assets reflects the net difference between fair value and cost of investments bought during the year and the net difference between fair value and the beginning of the year fair value of assets held, sold or distributed. The net depreciation in the fair value of investments by major investment category for the year ended December 31, 1994 is as follows:
---In Thousands--- Pacific Gas and Electric Company Common Stock Fund $(480,081) PAYSOP Fund (3,935) DEF 1,409 BIF (2,509) SBF 60 USF (13,080) ---------- Total depreciation $(498,136) ==========
FINANCIAL INVESTMENTS WITH OFF-BALANCE SHEET RISK The DEF fund investment manager routinely enters into Standard and Poor's (S&P 500) futures contracts as a hedge against future price increases in S&P stocks. At each balance sheet date, these contracts are marked to fair value, and the resulting appreciation (depreciation) in the contracts' value is recorded. As of December 31, 1994, there were 31 Future Buy S&P March 1995 contracts valued at approximately $7 million, and a decline of approximately $545,000 in the value of the contracts was recorded. The collateral (included in interest bearing accounts) with respect to these contracts consisted of a $440,000 U.S. treasury bill which will mature on April 6, 1995 and a $120,000 U.S. treasury bill which matured on February 23, 1995. 7 14 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- --------------- -------------- --------------- ------In Thousands------ Pacific Gas and Electric Company common stock funds * Pacific Gas and Electric Company Stock Fund 46,416,948 $1,029,874 $1,131,413 Interest bearing accounts N/A 163 163 ---------- ---------- ---------- Total Pacific Gas and Electric Company common stock 46,416,948 $1,030,037 $1,131,576 ========== ========== ========== United States Bond Fund United States Savings Bonds, Series E (units of $18.75 cost and $25.00 maturity) 6,721 $126 $467 United States Savings Bonds, Series EE (units of $25.00 cost and $50.00 maturity) 90,124 2,253 3,536 United States Savings Bonds, Series EE (units of $50.00 cost and $100.00 maturity) 10,088 504 613 ---------- ---------- ---------- Total United States Bond Fund 106,933 $2,883 $4,616 ========== ========== ========== DEF Corporate stocks - common AMR Corp. Del. 7,600 $ 448 $ 405 AT&T Corp. 184,300 8,728 9,261 Abbott Labs 137,900 3,790 4,499 Adobe Sys Inc. 3,100 60 92 Advanced Micro Devices Inc. 10,100 245 251 Aetna Life & Cas. Co. 11,900 532 561 Ahmanson H F & Co. 13,100 203 211 Air Prods & Chems. Inc. 7,300 309 326 Albermarle Corp. 10,100 135 140 Allegheny Ludlum Corp. 13,100 230 246 Allegheny Power Systems Inc. 14,000 338 305 Allied Signal Inc. 67,800 1,985 2,305 Allstate Corp. 46,600 1,126 1,101 Aluminum Co. America 25,500 1,636 2,209 Alza Corp. 11,800 395 212 Ambac Inc. 4,200 175 156 American Elec. Pwr. Inc. 20,000 645 657 American Gen. Corp. 15,700 435 444 American Home Products Corp. 44,700 2,807 2,805 American Intl. Group Inc. 39,900 3,045 3,910 Ameritech Corp. 64,900 1,732 2,620 Amoco Corp. 18,400 952 1,088 Amsouth Bancorporation 4,500 143 116 Anadarko Pete Corp. 9,000 348 347 Aon Corp. 7,500 247 240 Armstrong World Inds. Inc. 4,400 173 169 Ashland Oil Inc. 9,300 317 321 Atlantic Richfield Co. 19,000 1,953 1,933 Autodesk Incorporated 5,200 189 206
8 15 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- --------------- --------------- -------------- ------In Thousands------ Avnet Inc. 2,100 $ 91 $ 78 Avon Prods. Inc. 13,100 763 783 Baker Hughes Inc. 19,000 438 347 Baltimore Gas & Electric Co. 17,100 381 378 Banc One Corp. 46,600 1,456 1,182 Bank of Boston Corp. 9,800 228 254 BankAmerica Corp. 42,300 1,908 1,671 Bankers Tr. N.Y. Corp. 12,200 789 676 Barnett Bks. Inc. 11,600 488 445 Bausch & Lomb Inc. 11,400 480 386 Baxter Intl. Inc. 49,200 1,269 1,390 Bay Networks Inc. 12,200 450 360 Bear Stearns Cos. Inc. 13,400 280 206 Bell Atlantic Corp. 52,100 2,573 2,592 Bellsouth Corp. 59,300 3,146 3,210 Beneficial Corp. 3,200 116 125 Bethleham Stl. Corp. 23,100 422 416 Black & Decker Corporation 45,400 765 1,078 Bowater Inc. 100 2 3 Boyd Gaming Corp. 7,200 118 77 Brinker Intl. Inc. 15,100 329 274 Bristol Myers Squibb Co. 19,800 1,204 1,146 Browning Ferris Inds. Inc. 39,100 954 1,109 Burlington Northn. Inc. 9,800 532 472 CBS Inc. 14,600 689 809 CMS Energy Corp. 9,900 220 226 CPC Intl. Inc. 32,900 1,550 1,752 CSX Corp. 14,200 985 989 Campbell Soup Co. 32,000 1,310 1,412 Carnival Corp. 27,400 525 582 Carolina Pwr. & Lt. Co. 1,800 46 48 Caterpillar Inc. 50,200 1,318 2,767 Central & South West Corp. 21,700 472 491 Champion Intl. Corp. 13,800 370 504 Charming Shoppes Inc. 19,200 294 127 Chase Manhattan Corp. 21,500 577 739 Chemical Bkg. Corp. 27,600 1,103 990 Chemical Waste Mgmt. Inc. 1,700 33 16 Chevron Corp. 99,900 4,130 4,458 Chiron Corp. 4,900 323 394 Chrysler Corp. 16,300 693 799 Chubb Corp. 4,900 348 379 Cincinnati Milacron Inc. 1,100 25 26 Cinergy Corp. 10,100 250 236 Circus Circus Enterprises Inc. 20,400 709 474 Citicorp 84,900 1,885 3,513 Coca Cola Co. 168,000 6,755 8,652 Colgate Palmolive Co. 19,800 1,050 1,255 Coltec Inds. Inc. 10,400 210 178 Columbia/HCA Healthcare Corp. 68,800 2,842 2,511 Comcast Corp. 16,100 266 253 Comerica Inc. 13,200 397 322
9 16 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- --------------- --------------- ------------- -----------In Thousands-------- Compaq Computer Corp. 31,300 $ 962 $1,236 Connor Peripherals Inc. 1,600 30 15 Conrail Inc. 3,900 183 197 Consolidated Edison Co. NY Inc. 1,900 47 49 Cooper Inds. Inc. 24,100 1,057 822 Cooper Tire & Rubber 8,800 214 208 Corestates Finl. Corp. 13,000 336 338 Cracker Barrel Old Ctry. Store 13,800 380 255 Crestar Finl. Corp. 2,200 101 83 Crown Cork & Seal Inc. 19,400 734 732 Cummins Engine Inc. 3,400 140 154 Dayton Hudson Corp. 23,400 1,370 1,656 Dean Witter Discover & Co. 18,700 620 633 Deere & Co. 12,200 531 808 Dell Computer Corp. 4,400 186 180 Delta Air Lines Inc. DE 5,300 306 268 Detroit Edison Co. 12,000 424 314 Dillard Dept Stores Inc. 15,300 591 409 Disney, Walt Co. 98,100 3,713 4,525 Dominion Res. Inc. VA 20,300 742 726 Donnelley R R & Sons Inc. 32,300 900 953 Dover Corp. 7,000 397 361 Dow Chemical Company 35,600 2,120 2,394 Du Pont E I De Nemours and Co. 95,800 4,629 5,389 Duke Power Co. 400 15 15 E Sys. Inc. 3,500 136 146 Eastman Kodak Co. 51,200 2,068 2,445 Eaton Corp. 9,200 357 455 El Paso Nat. Gas Co. 4,400 169 134 Electronic Arts 5,900 193 114 Emerson Elec. Co. 3,600 206 225 Enron Corp. 38,900 1,142 1,186 Entergy Corp. 27,700 877 606 Equifax Inc. 14,600 424 385 Ethyl Corp. 20,200 248 194 Exxon Corp. 109,300 6,139 6,640 FPL Group Inc. 20,500 621 720 Federal Home Ln. Mtg. Corp. 20,500 1,017 1,035 Federal Natl. Mtg. Assn. 39,800 2,853 2,900 Fifth Third Bancorp. 4,000 193 192 First Chicago Corp. 8,400 286 401 First Data Corp. 25,500 1,010 1,208 First Empire St. Corp. 200 30 27 First Fidelity Bancorp. New 4,900 211 220 First Tenn. Natl. Corp. 3,700 172 151 First Union Corp. 19,100 875 790 First USA Inc. 6,100 201 201 First VA Bks. Inc. 3,900 156 125 Firstar Corp. New 7,100 219 191 Fleet Finl. Group Inc. 13,900 416 452 Ford Motor Co. Del. 97,400 2,055 2,727 Forest Labs Inc. 5,500 255 256
10 17 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- --------------- --------------- ------------ ---------In Thousands--------- Freeport McMoran Copper & Gold 7,200 $ 176 $ 153 Fruit of the Loom Inc. 18,500 556 500 GTE Corp. 113,100 3,959 3,435 Gap Inc. 25,000 804 762 Gateway 2000 Inc. 7,400 166 160 General Dynamics Corp. 9,800 323 426 General Electric Co. 209,200 8,199 10,669 General Mills Inc. 29,200 1,877 1,664 General Mtrs. Corp. 98,500 3,787 4,162 General Mtrs. Corp. 30,800 1,005 1,186 General Pub. Utils. Corp. 13,100 352 344 General Signal Corp. 6,600 200 210 Gensia Inc. 5,700 152 24 George Gulf Corp. 600 16 23 Georgia Pacific Corp. 13,100 714 937 Gillette Co. 36,100 2,137 2,698 Golden West Finl. Corp. Del. 7,300 289 257 Goodyear Tire and Rubber 12,700 414 427 Grainger W W Inc. 8,800 483 508 Great Western Finl. Corp. 19,200 295 307 Harley Davidson Inc. 20,000 520 560 Harris Corp. Del. 1,800 76 77 Healthcare Compare Corp. 3,000 89 102 Health Mgmt. Assoc. 7,600 180 190 Hewlett Packard Co. 34,700 1,868 3,466 Home Depot Inc. 76,900 3,237 3,537 Honeywell Inc. 31,100 771 980 Household Intl. Corp. 8,800 242 327 Houston Inds. Inc. 15,100 514 538 Hubbell Inc. 1,100 60 59 Humana Inc. 30,900 601 699 Huntington Bancshares Inc. 14,200 301 245 ITT Corp. 31,700 1,930 2,809 Illinois Cent. Corp. 5,600 175 172 Illinova Corp. 4,400 90 96 Inco Ltd. 20,900 492 598 Ingersoll Rand Co. 3,700 119 117 Intel Corp. 44,400 2,412 2,836 International Business Machs. 78,700 4,030 5,784 International Game Technology 29,000 610 450 International Paper Company 30,100 1,373 2,269 Johnson & Johnson 33,500 1,433 1,834 Johnson Ctls. Inc. 8,100 386 397 KU Energy Corp. 300 8 8 Kellogg Co. 32,500 2,003 1,889 Keycorp New 26,300 840 657 Kimberly Clark Corp. 19,900 1,005 1,005 Knight Ridder Inc. 9,700 513 490 Lilly Eli & Co. 42,000 2,755 2,756 Limited Inc. 71,500 1,613 1,296 Lincoln Natl. Corp. IN 1,100 44 39 Linear Technology Corp. 3,300 107 163
11 18 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- --------------- --------------- -------------- ------In Thousands------ Liz Claiborne 20,500 $471 $349 Lockheed Corp. 9,800 511 712 Loral Corp. 13,000 334 492 Louisiana Pacific Corp. 14,700 478 401 MBIA Inc. 3,600 220 202 MCI Communications Corp. 74,600 1,443 1,371 Manor Care Inc. 9,000 221 246 Marshall & Ilsley Corp. 11,400 232 217 Martin Marietta Corp. New 15,000 473 666 Masco Corp. 61,400 1,610 1,389 May Dept. Stores Co. 30,000 1,178 1,012 McDonalds Corp. 132,100 3,974 3,864 McDonnell Douglas Corp. 2,900 184 412 Medtronic Inc. 16,400 534 912 Mellon Bk. Corp. 17,000 573 521 Melville Corporation 19,700 944 608 Mercantile Bancorporation Inc. 4,900 180 153 Mercantile Bankshares Corp. 100 2 2 Merck & Co. Inc. 179,800 6,217 6,855 Mercury Finl. Co. 13,500 210 176 Meridian Bancorp. Inc. 6,600 192 176 Merrill Lynch & Co. Inc. 11,700 427 418 Microsoft Corp. 65,300 2,901 3,991 Mirage Resorts Inc. 21,600 492 443 Mobil Corp. 60,800 4,741 5,122 Monsanto Co. 16,000 1,112 1,128 Motorola Inc. 62,600 3,032 3,623 NBD Bancorp. Inc. 9,200 265 252 NIPSCO Inds. Inc. 7,400 203 220 National Svc. Inds. Inc. 23,800 611 610 Nationsbank Corp. 30,900 1,450 1,394 New England Elec. Sys. 7,100 233 228 Niagara Mohawk Pwr. Corp. 12,100 181 172 Nine West Group Inc. 2,400 66 68 Noram Energy Corp. 15,500 150 83 Norfolk Southern Corp. 14,700 857 891 Northern Telecom Ltd. 30,100 1,095 1,005 Northern Trust Corp. 5,100 211 179 Northrop Grumman Corp. 300 9 13 Norwest Corp. 38,400 953 898 Novell Inc. 63,100 1,584 1,081 Nucor Corp. 18,400 1,169 1,021 Occidental Pete Corp. 48,100 904 926 Ogden Corp. 3,000 56 56 Oracle Sys. Corp. 36,200 582 1,597 Oryx Energy Co. 7,100 149 84 Owens Corning Fiberglass Corp. 17,600 582 563 PNC Bk. Corp. 49,300 972 1,041 PPG Inds. Inc. 28,200 870 1,047 Paccar Inc. 5,300 279 235 Pacific Telesis Group 48,100 1,432 1,371 Paine Webber Group Inc. 500 7 8
12 19 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- --------------- --------------- -------------- ----------In Thousands-------- Panhandle Eastern Corp. 22,900 $ 479 $ 452 Parker Hannifin Corp. 7,100 297 323 Penney, J.C. Inc. 3,200 136 143 Pepsico Inc. 133,400 5,075 4,836 Pfizer Inc. 47,400 2,224 3,662 Phelps Dodge Corp. 16,300 762 1,009 Philip Morris Cos. Inc. 117,900 8,554 6,779 Pinnacle West Cap Corp. 9,800 202 194 Portland Gen. Corp. 400 7 8 Potomac Elec. Pwr. Co. 12,600 279 232 Praxair Inc. 22,100 354 453 Premier Indl. Corp. 9,100 233 215 Proctor & Gamble Company 98,100 3,187 6,082 Providian Corp. 10,700 350 330 Public Svc. Enterprise Group 26,600 670 705 Ralston Pruina Co. 13,800 611 616 Raytheon Co. 10,800 679 690 Republic N.Y. Corp. 5,800 261 262 Reynolds Metals Co. 15,800 771 774 Rockwell Intl. Corp. 17,600 670 629 Royal Dutch Pete Co. 70,700 4,669 7,600 SCECorp 48,300 997 706 SPS Transaction Svcs. Inc. 6,200 204 163 Safeco Corp. 6,900 329 359 St. Paul Cos. Inc. 35,800 867 1,602 Schlumberger Ltd. 37,400 2,148 1,884 Schwab, Charles Corp. 6,400 177 223 Scott Paper Co. 9,700 601 671 Service Corp. Intl. 20,500 417 569 Shamut National Corp. 13,900 241 228 Silicon Graphics Inc. 12,600 177 389 Sonat Inc. 55,900 1,144 1,565 Southern Co. 68,800 1,464 1,376 Southtrust Corp. 8,200 152 148 Southwest Airlines Co. 16,700 559 280 Southwestern Bell Corp. 71,700 2,801 2,895 Sprint Corp. 38,700 1,079 1,069 Standard Fed. Bk. Troy, Mich. 200 5 5 State Street Boston Corp. 4,700 151 135 Sun Microsystems Inc. 15,100 444 536 Sundstrand Corp. 1,900 75 86 Superior Inds. Intl. Inc. 1,600 51 42 Sybase Inc. 6,100 173 317 Synovus Finl. Corp. 4,200 79 76 TJX Cos. Inc. New 13,700 318 214 TRW Inc. 19,500 1,280 1,287 Tele Communications Inc. New 85,400 1,750 1,857 Tenneco Inc. 52,600 2,028 2,235 Texaco Inc. 38,900 2,531 2,329 Texas Instrs. Inc. 9,700 670 726 Texas Utils. Co. 46,400 1,556 1,485 Time Warner Inc. 16,900 584 594
13 20 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- --------------- -------------- ------------- ----------In Thousands-------- Torchmark Inc. 6,600 $ 380 $ 230 Toys R Us Inc. 47,600 1,835 1,452 Transamerica Corp. 5,000 268 249 Tribune Co. New 11,600 632 635 Tyco Int. Ltd. 18,100 799 860 UAL Corp. 1,200 99 105 UJB Finl. Corp. 3,300 90 80 UNUM Corp. 7,400 357 279 UNICOM Corp. 25,300 569 607 Union Carbide Corp. 25,800 432 758 Union Elec. Co. 300 11 11 Union Pac. Corp. 39,800 1,387 1,816 Union Texas Pete Hldgs. Inc. 11,000 215 228 U.S. West Inc. 49,200 1,911 1,753 United Technologies Corp. 25,300 1,421 1,591 V. F. Corp. 17,000 844 827 Viacom Inc. 29,300 826 1,190 WMX Technolgies Inc. 93,800 3,180 2,462 Wabash Natl. Corp. 1,200 50 47 Wal Mart Stores Inc. 315,900 8,767 6,713 Warner Lambert Co. 6,300 414 485 Washington Mut. Inc. 9,400 212 159 West One Bancorp. 200 5 5 Western Res. Inc. 6,400 219 183 Weyerhauser Co. 19,400 760 727 Wheelabrator Technologies Inc. 31,000 561 457 Whirlpool Corp. 1,800 106 91 Wisconsin Energy Corp. 6,400 165 166 Woolworth Corp. 18,400 355 276 Worthington Inds. In. 10,100 201 202 ---------- ---------- ---------- Total common stocks 8,386,100 $311,785 $340,032 ---------- ---------- ---------- Corporate stocks - preferred Chrysler Corp. 7,700 $1,167 $1,048 ---------- ---------- ---------- Interest bearing accounts * State Street Bank & Trust Co. 12,253,620 $12,254 $12,254 U.S. Treasury Bills 560,000 553 553 ---------- ---------- ---------- Total interest bearing accounts 12,813,620 $12,807 $12,807 Total DEF 21,207,420 $325,759 $353,887 ========== ========== ==========
GIF (1) Fixed Income Allstate Life Insurance Co. - 10/98, 6.80% N/A $3,075 $3,075 Allstate Life Insurance Co. - 11/99, 8.28% N/A 5,011 5,011 Bankers Trust Basic - 07/96, 6.36% N/A 1,246 1,246 Bankers Trust Basic - 07/97, 5.02% N/A 9,655 9,655
14 21 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- -------------- --------------- ------------- ---------In Thousands---------- CDC Investment Mgmt. Corp. - 06/98, 7.11% N/A $4,023 $4,023 CDC Investment Mgmt. Corp. - 10/99, 7.59% N/A 3,020 3,020 Canada Life Assurance - 11/95, 4.30% N/A 5,009 5,009 Canada Life Assurance - 12/95, 4.34% N/A 4,011 4,011 Confederated Life Assurance - 03/96, 8.58% N/A 1,000 1,000 Continental Assurance Co. - 06/96, 5.80% N/A 3,560 3,560 Continental Assurance Co. - 08/94, 6.52% N/A 0 0 Crown Life - 03/98, 1.00% N/A 1,163 1,163 Hancock John Mutual Life - 09/96, 5.34% N/A 4,470 4,470 Hancock John Mutual Life - 10/97, 4.82% N/A 7,367 7,367 Hartford - 12/95, 6.52% N/A 2,990 2,990 IBM CR Corp - 02/95, 6.56% N/A 1,016 1,016 Mass Mutual Life Ins - 11/03, 5.95% N/A 18,010 18,010 Met Life Ins. - 08/99, 7.42% N/A 4,944 4,944 New York Life Ins. Co. - 05/96, 8.40% N/A 1,567 1,567 New York Life Ins. Co. - 12/98, 1.00% N/A 9,482 9,482 New York Life Ins. Co. - 12/99, 1.00% N/A 9,845 9,845 Peoples Security Life - 01/98, 5.42% N/A 2,825 2,825 Peoples Security Life - 03/99, 5.30% N/A 4,993 4,993 Peoples Security Life - 06/96, 4.69% N/A 2,500 2,500 Peoples Security Life - 06/97, 1.00% N/A 9,989 9,989 Peoples Security Life - 07/94, 8.47% N/A 1,127 1,127 Peoples Security Life - 07/96, 4.15% N/A 3,699 3,699 Peoples Security Life - 07/98, 5.50% N/A 5,967 5,967 Peoples Security Life - 09/96, 4.10% N/A 3,616 3,616 Peoples Security Life - 09/97, 5.11% N/A 4,969 4,969 Peoples Security Life - 09/98, 5.63% N/A 3,219 3,219 Provident Mutual Life Ins. Co. - 05/95, 6.34% N/A 4,659 4,659 Prudential Ins. Co. - 03/95, 4.22% N/A 3,000 3,000 Prudential Ins. Co. - 04/96, 8.04% N/A 1,748 1,748 Prudential Ins. Co. - 09/98, 1.00% N/A 4,455 4,455 Prudential Ins. Co. - 11/95, 6.11% N/A 4,623 4,623 Union Bank of Switzerland - 08/97, 1.00% N/A 7,097 7,097 Union Bank of Switzerland - 03/00, 4.62% N/A 10,310 10,310 Union Bank of Switzerland - 03/00, 5.15% N/A 6,575 6,575 Union Bank of Switzerland - 10/98, 5.63% N/A 10,268 10,268 United of Omaha Life - 07/95, 8.35% N/A 2,067 2,067 United of Omaha Life - 08/95, 5.30% N/A 3,567 3,567 United of Omaha Life - 09/95, 5.00% N/A 2,017 2,017 United of Omaha Life - 09/96, 4.40% N/A 1,160 1,160 ---------- ---------- ---------- Total fixed income N/A $204,914 $204,914 ---------- ---------- ----------
15 22 SAVINGS FUND PLAN FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES December 31, 1994
Number of Shares or U.S. Savings Bonds Held at (e) Current (a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value ------------------------------------------------- --------------- --------------- -------------- -----------In Thousands-------- Interest bearing accounts Chevron Oil Finance Co. N/A $ 12,899 $ 12,899 Exxon Funding B.V. N/A 9,955 9,955 Federal Natl. Mtg. Assn. Disc. Nts. N/A 9,967 9,967 General Elec. Cap. Corp. N/A 12,848 12,848 Rabobank USA Financial Corp. N/A 12,366 12,366 * State Street Bank & Trust Co. N/A 2,193 2,193 ---------- ---------- ---------- N/A $ 60,228 $ 60,228 ---------- ---------- ---------- Total GIF N/A $ 265,142 $ 265,142 ========== ========== ========== BIF Vanguard Bond Market Fund 2,577,091 $ 25,649 $ 23,632 ========== ========== ========== SBF Columbia Balanced Fund 15,950,137 $ 92,198 $ 102,861 ========== ========== ========== USF Dreyfus Utility Stock Fund 4,029,936 $ 54,941 $ 45,458 ========== ========== ========== Total Investments $1,796,609 $1,927,172 ========== ==========
(1) The GIF is not measured in number of shares and is not applicable (N/A). * Party-in-interest. 16 23 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3751 PACIFIC GAS & ELECTRIC SAVINGS BENEFIT PLAN SERVICES ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 1,590,603,374.79 5% OF ASSET VALUE: 79,530,168.74
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 202 186,794,661.04 257 144,611,684.23 -45,878,079.66 459 331,406,309.27 FIXED INCOME 0 0.00 0 0.00 0.00 0 0.00 SHORT TERM 0 0.00 0 0.00 0.00 0 0.00 REPORTABLE TRANSACTION TOTALS 202 186,794,661.04 257 144,611,648.23 -45,878,079.66 459 331,406,309.27 NON REPORTABLE TRANSACTION TOTALS 133 95,034,004.11 77 95,029,926.22 0.00 210 190,063,930.33
[State Street LOGO] 24 ITEM 27 (D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3757 PACIFIC GAS & ELECTRIC SAVINGS BENEFIT PLAN SERVICES ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 28,739,630.44 5% OF ASSET VALUE: 1,436,981.52
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 96 3,691,830.66 44 6,290,311.85 -402,572.17 140 9,982,142.51 FIXED INCOME 0 0.00 0 0.00 0.00 0 0.00 SHORT TERM 0 0.00 0 0.00 0.00 0 0.00 REPORTABLE TRANSACTION TOTALS 96 3,691,830.66 44 6,290,311.85 -402,572.17 140 9,982,142.51 NON REPORTABLE TRANSACTION TOTALS 0 0.00 0 0.00 0.00 0 0.00
[State Street LOGO] 25 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3758 PACIFIC GAS & ELECTRIC SAVINGS COLUMBUS BALANCED FUND ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 104,083,308.36 5% OF ASSET VALUE: 5,204,165.42
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 99 11,800,644.25 44 13,083,212.89 -54,318.06 143 24,883,857.14 FIXED INCOME 0 0.00 0 0.00 0.00 0 0.00 SHORT TERM 0 0.00 0 0.00 0.00 0 0.00 REPORTABLE TRANSACTION TOTALS 99 11,800,644.25 44 13,083,212.89 -54,318.06 143 24,883,857.14 NON REPORTABLE TRANSACTION TOTALS 0 0.00 0 0.00 0.00 0 0.00
[State Street LOGO] 26 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3759 PACIFIC GAS & ELECTRIC SAVINGS DREFUS UTILITY STOCK FUND ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 75,336,398.43 5% OF ASSET VALUE: 3,766,819.92
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 83 8,796,613.55 52 25,594,505.39 -4,268,225.41 135 34,391,118.94 FIXED INCOME 0 0.00 0 0.00 0.00 0 0.00 . SHORT TERM 0 0.00 0 0.00 0.00 0 0.00 REPORTABLE TRANSACTION TOTALS 83 8,796,613.55 52 25,594,505.39 -4,268,225.41 135 34,391,118.94 NON REPORTABLE TRANSACTION TOTALS 0 0.00 0 0.00 0.00 0 0.00
[State Street LOGO] 27 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3760 PACIFIC GAS & ELECTRIC SAVINGS BENEFIT PLAN SERVICES ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 10,252,015.50 5% OF ASSET VALUE: 512,600.78
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 28 568,437.35 88 6,749,679.50 -3,934,582.23 116 7,318,116.85 FIXED INCOME 0 0.00 0 0.00 0.00 0 0.00 SHORT TERM 0 0.00 0 0.00 0.00 0 0.00 REPORTABLE TRANSACTION TOTALS 28 568,437.35 88 6,749,679.50 -3,934,582.23 116 7,318,116.85 NON REPORTABLE TRANSACTION TOTALS 34 230,700.24 34 230,938.30 0.00 68 461,638.54
[State Street LOGO] 28 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3757 PACIFIC GAS & ELECTRIC SAVINGS VANGUARD BOND MARKET FUND ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 28,739,630.44 5% OF ASSET VALUE: 1,436,981.52
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 921937108 VANGUARD BD INDEX FD INC 96 3,691,830.66 44 6,290,311.85 -402,572.17 140 9,982,142.51 COMMON AND PREFERRED TOTALS 96 3,691,830.66 44 6,290,311.85 -402,572.17 140 9,982,142.51
[State Street LOGO] 29 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3751 PACIFIC GAS & ELECTRIC SAVINGS BENEFIT PLAN SERVICES ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 1,590,603,374.79 5% OF ASSET VALUE: 79,530,168.74
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 694308107 PACIFIC GAS & ELEC CO 202 186,794,661.04 257 144,611,648.23 -45,878,079.66 459 331,406,309.27 COMMON AND PREFERRED TOTALS -45,878,079.66 202 186,794,661.04 257 144,611,648.23 459 331,406,309.27
[State Street LOGO] 30 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3758 PACIFIC GAS & ELECTRIC SAVINGS COLUMBIA BALANCED FUND ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 104,083,308.36 5% OF ASSET VALUE: 5,204,165.42
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 197216104 COLUMBIA BALANCED FUND INC 99 11,800,644.25 44 13,083,212.89 -54,318.06 143 24,883,857.14 COMMON AND PREFERRED TOTALS 99 11,800,644.25 44 13,083,212.89 -54,318.06 143 24,883,857.14
[State Street LOGO] 31 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3759 PACIFIC GAS & ELECTRIC SAVINGS DREYFUS UTILITY STOCK FUND ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 75,336,398.43 5% OF ASSET VALUE: 3,766,819.92
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 261893101 DREYFUS EDISON ELEC INDEX FD 83 8,796,613.55 52 25,594,505.39 -4,268,225.41 135 34,391,118.94 COMMON AND PREFERRED TOTALS 83 8,796,613.55 52 25,594,505.39 -4,268,225.41 135 34,391,118.94
[State Street LOGO] 32 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3760 PACIFIC GAS & ELECTRIC SAVINGS BENEFIT PLAN SERVICES ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 10,252,015.50 5% OF ASSET VALUE: 512,600.78
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE BROKER PURCHASE PRICE SALES PRICE EXPENSES 5500 GAIN/LOSS COST/PROCEEDS 550 GAIN/LOSS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 0.00 6,430,879.39 10,287.419.09 -3,856,539.70 FIXED INCOME 0.00 0.00 0.00 0.00 SHORT TERM 0.00 0.00 0.00 0.00 REPORTABLE TRANSACTION TOTALS 0.00 6,430,879.39 10,287.419.09 -3,856,539.70
[State Street LOGO] 33 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3760 PACIFIC GAS & ELECTRIC SAVINGS BENEFIT PLAN SERVICES ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 10,252,015.50 5% OF ASSET VALUE: 512,600.78
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE # PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 694308107 PACIFIC GAS & ELEC CO 28 568,437.35 88 6,749,679.50 -3,934,582.23 116 7,318,116.85 COMMON AND PREFERRED TOTALS 28 568,437.35 88 6,749,679.50 -3,934,582.23 116 7,318,116.85
[State Street LOGO] 34 ITEM 27(D) - SCHEDULE OF REPORTABLE TRANSACTIONS FOR THE YEAR ENDED DECEMBER 31, 1994 3760 PACIFIC GAS & ELECTRIC SAVINGS BENEFIT PLAN SERVICES ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS FROM DATE: 01/01/94 TO DATE: 12/31/94 BEGINNING NET ASSET VALUE: 10,252,015.50 5% OF ASSET VALUE: 512,600.78
- ------------------------------------------------------------------------------------------------------------------------------------ ASSET ID SECURITY DESCRIPTION RATE MAT DATE BROKER PURCHASE PRICE SALES PRICE EXPENSES 5500 COST COST/PROCEEDS 550 GAIN/LOSS - ------------------------------------------------------------------------------------------------------------------------------------ COMMON AND PREFERRED 694308107 PACIFIC GAS & ELEC CO DIRECT ISS 21.56 0.00 10,287.419.09 6,430,879.39 -3,856,539.70 COMMON AND PREFERRED TOTALS 0.00 6,430,879.39 10,287.419.09 -3,856,539.70
[State Street LOGO] 35 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I FINANCIAL STATEMENTS TABLE OF CONTENTS REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS FINANCIAL STATEMENTS STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS -- DECEMBER 31, 1994 AND 1993 STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS FOR THE YEAR ENDED DECEMBER 31, 1994 NOTES TO FINANCIAL STATEMENTS -- DECEMBER 31, 1994 36 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS December 31, 1994 AND 1993
1994 1993 ------ ------ ----------------In Thousands----------- ASSETS: Investment in Pacific Gas and Electric Company Master Trust, at fair value $839,081 $960,671 Participant contributions receivable 1 220 Employer contributions receivable _ 88 ------- ------- Total assets 839,082 960,979 LIABILITIES 43 38 ------- ------- NET ASSETS AVAILABLE FOR BENEFITS $839,039 $960,941 ======= =======
The accompanying Notes to Financial Statements are an integral part of these statements. 1 37 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS For the Year Ended December 31, 1994
-----In Thousands---- ADDITIONS: Participant contributions $ 36,071 Employer contributions 16,679 Interplan transfers 2,163 ------- Total Additions 54,913 ------- DEDUCTIONS: Net investment loss from Pacific Gas and Electric Company Master Trust 118,414 Benefits paid directly to participants or beneficiaries 57,941 Expenses 460 ------- Total Deductions 176,815 ------- Decrease in Net Assets Available for Benefits (121,902) NET ASSETS AVAILABLE FOR BENEFITS Beginning of the year 960,941 ------- End of the year $839,039 =======
The accompanying Notes to Financial Statements are an integral part of these statements. 2 38 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 1: Plan Description The Pacific Gas and Electric Company Savings Fund Plan - Part I (the Plan) is a defined contribution plan and is subject to the provisions of the Employee Retirement Income Security Act of 1974. The Plan covers all eligible management employees of Pacific Gas and Electric Company (the Company), Pacific Gas Transmission Company, and any other entity designated by the Company's Board of Directors. Although the Company has not expressed any intent to do so, its Board of Directors reserves the right to amend or terminate the Plan at any time. The Plan is administered by the Employee Benefit Administrative Committee and the Employee Benefit Finance Committee. Participants should refer to the Plan document for a complete description of the Plan's provisions. All participants' contributions and their share of all employer contributions, and the earnings and losses resulting from such contributions are immediately vested and nonforfeitable. Employees are eligible to participate in the Plan upon completion of one year of service. Employee contributions, up to a maximum of 6% of covered compensation, depending on length of service, are matched by employer contributions at a 75% rate. Eligible employees may elect to contribute to the Plan up to 15% of their covered compensation on a pre-tax or after-tax basis. This amount may be deferred compensation, 401(k), or after-tax contributions, non-401(k). 401(k) contributions are not subject to federal or state income tax until withdrawn or distributed from the Plan. All contributions made to the Plan prior to October 1, 1984, are considered to be non-401(k) contributions. As provided under the Tax Reform Act of 1986, employee 401(k) contributions may not exceed $9,240 for 1994, and total contributions to a participant's account may not exceed the lesser of 25% of compensation or $30,000 a year. The annual 401(k) limitation is adjusted each year to reflect changes in the cost of living. Eligible employees may elect to contribute to the Plan any excess funds from the FLEX Benefits Program, which is a cafeteria plan qualified under Section 125 of the Internal Revenue Code (IRC). These funds, which are invested in the participant's account once a year in December, are considered 401(k) contributions, but are not eligible for matching employer contributions. NOTE 2: Summary of Significant Accounting Policies The financial statements of the Plan are prepared in conformity with generally accepted accounting principles. The Plan's interest in the Pacific Gas and Electric Company Savings Fund Plan Master Trust (the Master Trust) is stated at fair value based on the Plan's prorated interest in the Master Trust. The Master Trust values investments in the Guaranteed Income Fund at cost which approximates fair value. Generally, all other investments are stated at fair value based upon published market quotations. 3 39 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 2: Summary of Significant Accounting Policies (Continued) Interest income, dividends, investment fees, and the net appreciation (depreciation) in the fair value of the investments held by the Master Trust are allocated to the individual participating plans each week based upon their proportional share of the fund balances. Benefits are recorded when paid. NOTE 3: Federal Income Taxes The Internal Revenue Service (IRS) has ruled that the Plan is a qualified tax-exempt plan under Section 401(a) and Section 409(a) of the IRC and the trust forming a part thereof is exempt under Section 501(a). Accordingly, no provision for federal income taxes has been made in the financial statements. Furthermore, participating employees are not liable for federal income tax on amounts allocated to their accounts attributable to: (1) employee 401(k) contributions, (2) dividends, earnings, and interest income on both 401(k) contributions and non-401(k) contributions, or (3) employer contributions, until the time that they withdraw such amounts from the Plan. The Plan has obtained a favorable tax determination letter from the IRS and the Plan sponsor believes that the Plan continues to be designed and operated in accordance with IRS requirements. NOTE 4: Investments The Plan has a prorated interest in the net assets of the Master Trust. The Master Trust Agreement allows certain of the Company's savings fund plans and the Pacific Service Employees Association, to participate in the Master Trust. The Plan and Master Trust Trustee, State Street Bank and Trust Company, invests a significant portion of the contributions to the Plan in common stock of the Company. Purchases of this stock are made directly from the Company. The Company pays all costs of administering the Plan, including fees and expenses of the Trustee. However, customary brokerage fees and commissions due to transfers, withdrawals and distributions are paid by the Plan. Investment management fees are netted against the performance of the Stock and Bond Fund, Utility Stock Fund, and Bond Index Fund and are paid by the Company in connection with the Diversified Equity Fund and the Guaranteed Income Fund. 4 40 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) Participants designate the way in which their contributions are invested and may change their investment designation once each calendar quarter. Participants may elect to have their contributions invested in one or more of the following funds: - Company Stock Fund, invested in Pacific Gas and Electric Company common stock; - Diversified Equity Fund (DEF), invested in a diversified portfolio of common stock of other companies; - Guaranteed Income Fund (GIF), invested in contracts which offer a fixed rate of interest for a specified period of time; - Bond Index Fund (BIF), invested in Vanguard Bond Market Fund, a diversified portfolio consisting of marketable fixed-income securities; - Stock and Bond Fund (SBF), invested in Columbia Balanced Fund, a diversified portfolio of marketable equity securities and marketable fixed-income securities; - Utility Stock Fund (USF), invested in Dreyfus Utility Stock Fund, a portfolio of marketable equity securities of electric utility companies that are members of the Edison Electric Institute, including the Company. A participant's interest in the investment funds is measured in "units". For investments in the common stock of the Company and in United States Savings Bonds, a unit is a share of common stock and a United States Savings Bond, respectively. 5 41 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The following summarizes the net assets and related investment loss of the Master Trust and the Plan's allocated share of such amounts:
----In Thousands---- 1994 1993 ----------------- ----------------- Investments, primarily at fair value: Company Stock Fund Pacific Gas and Electric Company common stock $1,131,413 $1,569,458 United States Bond Fund United States Government securities 5,169 4,740 DEF Corporate stocks - preferred 1,048 1,299 Corporate stocks - common 340,032 300,039 GIF Corporate debt instruments 53,210 41,099 Insurance company general accounts 151,704 188,421 Registered investment companies Vanguard Bond Market Fund 23,632 28,740 Columbia Balanced Fund 102,861 104,083 Dreyfus Utility Stock Fund 45,458 75,336 PAYSOP Fund Pacific Gas and Electric Company common stock 0 10,116 Interest bearing accounts 72,645 6,597 --------- --------- Total investments 1,927,172 2,329,928 --------- --------- Receivables: Dividends and interest 27,365 24,856 Other receivables 6,293 1,168 --------- --------- Total receivables 33,658 26,024 --------- --------- Total assets 1,960,830 2,355,952 --------- --------- LIABILITIES 11,407 1,197 --------- --------- NET ASSETS $1,949,423 $2,354,755 ========= ========= Allocated to the Plan $ 839,081 $ 960,671 Allocated to other plans 1,110,342 1,394,084 --------- --------- $1,949,423 $2,354,755 ========= =========
6 42 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The composition of the Master Trust investment loss for the year ended December 31, 1994 is as follows:
-In Thousands- Interest income Interest bearing accounts $ 931 United States Government securities 289 Fixed income investments 11,373 --------- Total interest income 12,593 --------- Dividend income Common stock 98,890 Registered investment companies 5,037 --------- Total dividend income 103,927 --------- Net depreciation in fair value of investments (498,136) Expenses, net of other income (712) --------- Total investment loss ($382,328) ========= Allocated to the Plan ($118,414) Allocated to other plans (263,914) --------- ($382,328) =========
7 43 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The net depreciation in fair value of investments of the Master Trust by major investment category for the year ended December 31, 1994 is as follows:
-In Thousands- Pacific Gas and Electric Company Common Stock Fund ($480,081) PAYSOP Fund (3,935) Diversified Equity Fund 1,409 Bond Index Fund (2,509) Stock and Bond Fund 60 Utility Stock Fund (13,080) --------- Total depreciation ($498,136) ========= Allocated to the Plan ($162,982) Allocated to other plans (335,154) --------- ($498,136) =========
8 44 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The net asset value per unit of the DEF, BIF, SBF, and USF is determined by dividing the fair value of Fund assets by the number of Fund units outstanding. The net asset value per unit of the GIF is $1.00, whereby each $1.00 of contributions or interest earned represents one unit. The total number of units held by the Plan and the value per unit of the DEF, GIF, BIF, SBF and USF for the four quarters ended December 31, 1994 and 1993 are as follows:
1994 ---------- March 31 June 30 September 30 December 31 -------- ------- ------------ ----------- DEF Number of units 2,850,195 2,937,324 2,994,629 3,019,934 Value per unit $67.27 $67.91 $71.50 $71.72 GIF Number of units 105,879,138 102,091,554 104,479,607 127,731,989 Value per unit $1.00 $1.00 $1.00 $1.00 BIF Number of units 1,630,823 1,548,151 1,474,848 1,396,372 Value per unit $11.61 $11.63 $11.68 $11.75 SBF Number of units 12,120,202 12,177,328 12,060,386 11,622,737 Value per unit $6.11 $6.06 $6.21 $6.21 USF Number of units 2,590,033 2,313,483 2,189,934 1,927,519 Value per unit $12.98 $11.89 $12.24 $12.73
9 45 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued)
1993 ---------- March 31 June 30 September 30 December 31 -------- ------- ------------ ----------- DEF Number of units 2,593,090 2,799,854 2,664,331 2,725,851 Value per unit $65.07 $65.44 $67.25 $69.44 GIF Number of units 108,940,209 150,749,436 110,606,418 109,282,898 Value per unit $1.00 $1.00 $1.00 $1.00 BIF Number of units 1,668,168 1,802,675 1,690,981 1,679,963 Value per unit $11.44 $11.70 $12.08 $12.06 SBF Number of units 9,435,637 11,400,946 11,199,558 11,917,450 Value per unit $5.83 $5.96 $6.17 $6.23 USF Number of units 1,815,171 2,264,729 2,504,277 2,683,123 Value per unit $14.41 $14.72 $15.39 $14.60
10 46 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART I NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 5: Reconciliation of Financial Statements to Form 5500 The following is a reconciliation of net assets available for benefits per the financial statements to the Form 5500:
--In Thousands-- December 31 ----------- 1994 1993 ---- ---- Net assets available for benefits per the financial statements $839,039 $960,941 Amounts allocated to withdrawing participants (1,330) (5,275) ------- ------- Net assets available for benefits per the Form 5500 $837,709 $955,666 ======= =======
The following is a reconciliation of benefits paid to participants per the financial statements to the Form 5500:
--In Thousands-- Year ended December 31, 1994 ----------------- Benefits paid to participants per the financial statements $57,941 Add: Amounts allocated to withdrawing participants at December 31, 1994 1,330 Less: Amounts allocated to withdrawing participants at December 31, 1993 (5,275) ------ Benefits paid to participants per the Form 5500 $53,996 ======
11 47 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II FINANCIAL STATEMENTS TABLE OF CONTENTS REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS FINANCIAL STATEMENTS STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS DECEMBER 31, 1994 AND 1993 STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS FOR THE YEAR ENDED DECEMBER 31, 1994 NOTES TO FINANCIAL STATEMENTS -- DECEMBER 31, 1994 48 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS December 31, 1994 AND 1993
1994 1993 -------- -------- ----------------In Thousands--------------- ASSETS: Investment in Pacific Gas and Electric Company Master Trust, at fair value $1,105,628 $1,378,240 Participant contributions receivable -- 287 Employer contributions receivable -- 60 --------- --------- Total assets 1,105,628 1,378,587 LIABILITIES 42 76 --------- --------- NET ASSETS AVAILABLE FOR BENEFITS $1,105,586 $1,378,511 ========= =========
The accompanying Notes to Financial Statements are an integral part of these statements. 1 49 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS For the Year Ended December 31, 1994
-----In Thousands---- ADDITIONS: Participant contributions $ 57,543 Employer contributions 16,306 Interplan transfers 4,212 --------- Total Additions 78,061 --------- DEDUCTIONS: Net investment loss from Pacific Gas and Electric Company Master Trust 258,784 Benefits paid directly to participants or beneficiaries 91,900 Expenses 302 --------- Total Deductions 350,986 --------- Decrease in Net Assets Available for Benefits (272,925) NET ASSETS AVAILABLE FOR BENEFITS Beginning of the year 1,378,511 --------- End of the year $1,105,586 =========
The accompanying Notes to Financial Statements are an integral part of these statements. 2 50 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN PART - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 1: Plan Description The Pacific Gas and Electric Company Savings Fund Plan - Part II (the Plan) is a defined contribution plan and is subject to the provisions of the Employee Retirement Income Security Act of 1974. The Plan covers all eligible non-management employees of Pacific Gas and Electric Company (the Company), Pacific Gas Transmission Company, and any other entity designated by the Company's Board of Directors. Although the Company has not expressed any intent to do so, its Board of Directors reserves the right to amend or terminate the Plan at any time. The Plan is administered by the Employee Benefit Administrative Committee and the Employee Benefit Finance Committee. Participants should refer to the Plan document for a complete description of the Plan's provisions. All participants' contributions and their share of all employer contributions, and the earnings and losses resulting from such contributions are immediately vested and nonforfeitable. Employees are eligible to participate in the Plan upon completion of one year of service. Employee contributions, up to a maximum of 6% of covered compensation, depending on length of service, are matched by employer contributions at a 50% rate. Eligible employees may elect to contribute to the Plan up to 15% of their covered compensation on a pre-tax or after-tax basis. This amount may be deferred compensation, 401(k), or after-tax contributions, non-401(k). 401(k) contributions are not subject to federal or state income tax until withdrawn or distributed from the Plan. All contributions made to the Plan prior to October 1, 1984, are considered to be non-401(k) contributions. As provided under the Tax Reform Act of 1986, employee 401(k) contributions may not exceed $9,240 for 1994 and total contributions to a participant's account may not exceed the lesser of 25% of compensation or $30,000 a year. The annual 401(k) limitation is adjusted each year to reflect changes in the cost of living. Non-management non-bargaining unit employees may elect to contribute to the Plan any excess funds from the FLEX Benefits Program, which is a cafeteria plan qualified under Section 125 of the Internal Revenue Code (IRC). These funds, which are invested in the participant's account once a year in December, are considered 401(k) contributions, but are not eligible for matching employer contributions. NOTE 2: Summary of Significant Accounting Policies The financial statements of the Plan are prepared in conformity with generally accepted accounting principles. The Plan's interest in the Pacific Gas and Electric Company Savings Fund Plan Master Trust (the Master Trust) is stated at fair value based on the Plan's prorated interest in the Master Trust. The Master Trust values investments in the Guaranteed Income Fund at cost which approximates fair value. All other investments are stated at fair value based upon published market quotations. 3 51 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN PART - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 2: Summary of Significant Accounting Policies (Continued) Interest income, dividends, investment fees, and the net appreciation (depreciation) in the fair value of the investments held by the Master Trust are allocated to the individual participating plans each week based upon their proportional share of the fund balances. Benefits are recorded when paid. NOTE 3: Federal Income Taxes The Internal Revenue Service (IRS) has ruled that the Plan is a qualified tax-exempt plan under Section 401(a) and Section 409(a) of the IRC and the trust forming a part thereof is exempt under Section 501(a). Accordingly, no provision for federal income taxes has been made in the financial statements. Furthermore, participating employees are not liable for federal income tax on amounts allocated to their accounts attributable to: (1) employee 401(k) contributions, (2) dividends, earnings, and interest income on both 401(k) contributions and non-401(k) contributions, or (3) employer contributions, until the time that they withdraw such amounts from the Plan. The Plan has obtained a favorable tax determination letter from the IRS and the Plan sponsor believes that the Plan continues to be designed and operated in accordance with IRS requirements. NOTE 4: Investments The Plan has a prorated interest in the net assets of the Master Trust. The Master Trust Agreement allows certain of the Company's savings fund plans and the Pacific Service Employees Association, to participate in the Master Trust. The Plan and Master Trust Trustee, State Street Bank and Trust Company, invests a significant portion of the contributions to the Plan in common stock of the Company. Purchases of this stock are made directly from the Company. The Company pays all costs of administering the Plan, including fees and expenses of the Trustee. However, customary brokerage fees and commissions due to transfers, withdrawals and distributions are paid by Plan participants. Investment management fees are netted against the performance of the Stock and Bond Fund, Utility Stock Fund and Bond Index Fund and are paid by the Company in connection with the Diversified Equity Fund and the Guaranteed Income Fund. 4 52 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN PART - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) Participants designate the way in which their contributions are invested and may change their investment designation once each calendar quarter. Participants may elect to have their contributions invested in one or more of the following funds: - Company Stock Fund, invested in Pacific Gas and Electric Company common stock; - Diversified Equity Fund (DEF), invested in a diversified portfolio of common stock of other companies; - Guaranteed Income Fund (GIF), invested in contracts which offer a fixed rate of interest for a specified period of time; - Bond Index Fund (BIF), invested in Vanguard Bond Market Fund, a diversified portfolio consisting of marketable fixed-income securities; - Stock and Bond Fund (SBF), invested in Columbia Balanced Fund, a diversified portfolio of marketable equity securities and marketable fixed-income securities; - Utility Stock Fund (USF), invested in Dreyfus Utility Stock Fund, a portfolio of marketable equity securities of electric utility companies that are members of the Edison Electric Institute, including the Company. A participant's interest in the investment funds is measured in "units". For investments in the common stock of the Company and in United States Savings Bonds, a unit is a share of common stock and a United States Savings Bond, respectively. 5 53 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The following summarizes the net assets and related investment loss of the Master Trust and the Plan's allocated share of such amounts:
----In Thousands---- 1994 1993 ------------------------------- Investments, primarily at fair value: Company Stock Fund Pacific Gas and Electric Company common stock $1,131,413 $1,569,458 United States Bond Fund United States Government securities 5,169 4,740 DEF Corporate stocks - preferred 1,048 1,299 Corporate stocks - common 340,032 300,039 GIF Corporate debt instruments 53,210 41,099 Insurance company general accounts 151,704 188,421 Registered investment companies Vanguard Bond Market Fund 23,632 28,740 Columbia Balanced Fund 102,861 104,083 Dreyfus Utility Stock Fund 45,458 75,336 PAYSOP Fund Pacific Gas and Electric Company common stock 0 10,116 Interest bearing accounts 72,645 6,597 --------- --------- Total investments 1,927,172 2,329,928 --------- --------- Receivables: Dividends and interest 27,365 24,856 Other receivables 6,293 1,168 --------- --------- Total receivables 33,658 26,024 --------- --------- Total assets 1,960,830 2,355,952 --------- --------- LIABILITIES 11,407 1,197 --------- --------- NET ASSETS $1,949,423 $2,354,755 ========= ========= Allocated to the Plan $1,105,628 $1,378,240 Allocated to other plans 843,795 976,515 --------- --------- $1,949,423 $2,354,755 ========= =========
6 54 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The composition of the Master Trust investment loss for the year ended December 31, 1994 is as follows:
-In Thousands- Interest income Interest bearing accounts $ 931 United States Government securities 289 Fixed income investments 11,373 --------- Total interest income 12,593 --------- Dividend income Common stock 98,890 Registered investment companies 5,037 --------- Total dividend income 103,927 --------- Net depreciation in fair value of investments (498,136) Expenses, net of other income (712) --------- Total investment loss ($382,328) ========= Allocated to the Plan ($258,784) Allocated to other plans (123,544) --------- ($382,328) =========
7 55 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The net depreciation in fair value of investments of the Master Trust by major investment category for the year ended December 31, 1994 is as follows:
-In Thousands- Pacific Gas and Electric Company Common Stock Fund ($480,081) PAYSOP Fund (3,935) Diversified Equity Fund 1,409 Bond Index Fund (2,509) Stock and Bond Fund 60 Utility Stock Fund (13,080) --------- Total depreciation ($498,136) ========= Allocated to the Plan ($330,117) Allocated to other plans (168,019) --------- ($498,136) =========
8 56 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The net asset value per unit of the DEF, BIF, SBF, and USF is determined by dividing the fair value of Fund assets by the number of Fund units outstanding. The net asset value per unit of the GIF is $1.00, whereby each $1.00 of contributions or interest earned represents one unit. The total number of units held by the Plan and the value per unit of the DEF, GIF, BIF, and USF for the four quarters ended December 31, 1994 and 1993 are as follows:
1994 --------- March 31 June 30 September 30 December 31 -------- ------- ------------ ----------- DEF Number of units 1,753,173 1,806,766 1,842,015 1,857,851 Value per units $67.27 $67.91 $71.50 $71.72 GIF Number of units 115,940,854 111,793,335 114,408,326 139,870,385 Value per units $1.00 $1.00 $1.00 $1.00 BIF Number of units 731,690 694,599 661,711 626,501 Value per units $11.61 $11.63 $11.68 $11.75 SBF Number of units 5,151,085 5,175,363 5,125,664 4,939,662 Value per units $6.11 $6.06 $6.21 $6.21 USF Number of units 2,296,953 2,051,696 1,942,128 1,709,406 Value per units $12.98 $11.89 $12.24 $12.73
9 57 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued)
1993 -------- March 31 June 30 September 30 December 31 -------- ------- ------------ ----------- DEF Number of units 1,511,663 1,696,161 1,747,731 1,700,987 Value per units $65.07 $65.44 $67.25 $69.44 GIF Number of units 75,908,115 91,144,285 169,591,270 124,388,496 Value per units $1.00 $1.00 $1.00 $1.00 BIF Number of units 674,034 712,355 860,340 703,276 Value per units $11.44 $11.70 $12.08 $12.06 SBF Number of units 3,000,210 3,972,889 4,599,099 4,785,165 Value per units $5.83 $5.96 $6.17 $6.23 USF Number of units 1,213,254 1,806,882 2,308,411 2,475,717 Value per units $14.41 $14.72 $15.39 $14.60
10 58 PACIFC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART II NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 5: Reconciliation of Financial Statements to Form 5500 The following is a reconciliation of net assets available for benefits per the financial statements to the Form 5500:
--In Thousands-- December 31 ----------- 1994 1993 ---- ---- Net assets available for benefits per the financial statements $1,105,586 $1,378,511 Amounts allocated to withdrawing participants (1,634) (7,321) --------- --------- Net assets available for benefits per the Form 5500 $1,103,952 $1,371,190 ========= =========
The following is a reconciliation of benefits paid to participants per the financial statements to the Form 5500:
--In Thousands-- Year ended December 31, 1994 ----------------- Benefits paid to participants per the financial statements $91,900 Add: Amounts allocated to withdrawing participants at December 31, 1994 1,634 Less: Amounts allocated to withdrawing participants at December 31, 1993 (7,321) ------ Benefits paid to participants per the Form 5500 $86,213 ======
11 59 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III FINANCIAL STATEMENTS TABLE OF CONTENTS REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS FINANCIAL STATEMENTS STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS DECEMBER 31, 1994 AND 1993 STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS FOR THE YEAR ENDED DECEMBER 31, 1994 NOTES TO FINANCIAL STATEMENTS -- DECEMBER 31, 1994 60 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS December 31, 1994 AND 1993
1994 1993 -------- -------- --------In Thousands-------- ASSETS: Investment in Pacific Gas and Electric Company Master Trust, at fair value - $10,252 ------- ------ NET ASSETS AVAILABLE FOR BENEFITS $ - $10,252 ======= ======
The accompanying Notes to Financial Statements are an integral part of these statements. 1 61 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS For the Year Ended December 31, 1994
-----In Thousands----- DEDUCTIONS: Net investment loss from Pacific Gas and Electric Company Master Trust $ 3,507 Benefits paid directly to participants or beneficiaries 314 ------- Total Deductions 3,821 ------- Interplan transfers (6,431) ------- Decrease in Net Assets Available for Benefits (10,252) NET ASSETS AVAILABLE FOR BENEFITS Beginning of the year $ 10,252 ------- End of the year $ - =======
The accompanying Notes to Financial Statements are an integral part of these statemen 2 62 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 1: Plan Description The Pacific Gas and Electric Company Savings Fund Plan - Part III (the Plan) is a Payroll Based Employee Stock Ownership Plan (PAYSOP). The Plan is subject to the provisions of the Employee Retirement Income Security Act of 1974. The Plan covers all eligible employees of Pacific Gas and Electric Company (the Company), Pacific Gas Transmission Company, and any other entity designated by the Company's Board of Directors. The Plan is administered by the Employee Benefit Administrative Committee and the Employee Benefit Finance Committee. Participants should refer to the Plan document for a complete description of the Plan's provisions. Effective January 1, 1983, the Economic Recovery Tax Act of 1981 permitted the Company to claim a tax credit if it contributed Company common stock or money to purchase Company common stock to the PAYSOP Fund equal to .5 percent of eligible employee covered compensation. Company stock held by the PAYSOP Fund became fully vested and nonforfeitable. The PAYSOP tax credit was eliminated by the Tax Reform Act of 1986 for the tax years beginning January 1, 1987. For the PAYSOP Fund, the tax year concides with the calendar year. Contributions to the PAYSOP Fund cannot be withdrawn until 84 months after the month in which the stock was purchased. After the 84th month, the stock and the earnings attributable to that stock are transferred to the Company Stock Fund in the Master Trust. The last Company contribution to the PAYSOP Fund was made in 1987 based upon compensation earned by participants in tax year 1986. After the 84 month time requirement was met in 1994, the Plan was terminated effective December 31, 1994. The remaining net assets were transfered to the other related retirement plans maintained by the Company. NOTE 2: Summary of Significant Accounting Policies The financial statements of the Plan are prepared in conformity with generally accepted accounting principles. The Plan's interest in the Pacific Gas and Electric Company Savings Fund Plan Master Trust (the Master Trust) is stated at fair value based on the Plan's prorated interest in the Master Trust. Generally, the Master Trust values investments at fair value based upon published market quotations. The net assets of the Master Trust are allocated initially to the individual participating plans based upon the relative values of assets contributed to the Master Trust. In addition, interest income, dividends, investment fees, and the net appreciation (depreciation) in the fair value of the investments held by the Master Trust are allocated to the individual participating plans each week based upon their relative market values. Benefits are recorded when paid. 3 63 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 3: Federal Income Taxes The Internal Revenue Service (IRS) has ruled that the Plan is a qualified tax-exempt plan under Section 401(a) and Section 409(a) of the IRC and the trust forming a part thereof is exempt under Section 501(a). Accordingly, no provision for federal income taxes has been made in the financial statements. The Plan has obtained a favorable tax determination letter from the IRS and while the Plan was in existence the Plan sponsor believes that the Plan continued to be designed and operated in accordance with IRS requirements. NOTE 4: Investments The Plan has a prorated interest in the net assets of the Master Trust. The Master Trust Agreement allows certain of the Company savings fund plans and the Pacific Service Employees Association, to participate in the Master Trust. The Plan and Master Trust Trustee, State Street Bank and Trust Company, invested all of the contributions to the Plan in common stock of the Company. Purchases of this stock are made directly from the Company. The Company pays all costs of administering the Plan, including fees and expenses of the Trustee. However, customary brokerage fees and commissions due to transfers, withdrawals and distributions are paid by the Plan. 4 64 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The following summarizes the net assets and related investment loss of the Master Trust and the Plan's allocated share of such amounts:
----In Thousands---- 1994 1993 ---------- ---------- Investments, primarily at fair value: Company Stock Fund Pacific Gas and Electric Company common stock $1,131,413 $1,569,458 United States Bond Fund United States Government securities 5,169 4,740 DEF Corporate stocks - preferred 1,048 1,299 Corporate stocks - common 340,032 300,039 GIF Corporate debt instruments 53,210 41,099 Insurance company general accounts 151,704 188,421 Registered investment companies Vanguard Bond Market Fund 23,632 28,740 Columbia Balanced Fund 102,861 104,083 Dreyfus Utility Stock Fund 45,458 75,336 PAYSOP Fund Pacific Gas and Electric Company common stock 0 10,116 Interest bearing accounts 72,645 6,597 --------- --------- Total investments 1,927,172 2,329,928 --------- --------- Receivables: Dividends and interest 27,365 24,856 Other receivables 6,293 1,168 --------- ---------- Total receivables 33,658 26,024 --------- --------- Total assets 1,960,830 2,355,952 --------- --------- LIABILITIES 11,407 1,197 --------- --------- NET ASSETS $1,949,423 $2,354,755 ========= ========= Allocated to the Plan $ 0 $ 10,252 Allocated to other plans 1,949,423 2,344,503 --------- --------- $1,949,423 $2,354,755 ========= =========
5 65 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The composition of the Master Trust investment loss for the year ended December 31, 1994 is as follows:
-In Thousands- Interest income Interest bearing accounts $ 931 United States Government securities 289 Fixed income investments 11,373 --------- Total interest income 12,593 --------- Dividend income Common stock 98,890 Registered investment companies 5,037 --------- Total dividend income 103,927 --------- Net depreciation in fair value of investments (498,136) --------- Expenses, net of other income (712) --------- Total investment loss ($382,328) ========= Allocated to the Plan ($3,507) Allocated to other plans (378,821) --------- ($382,328) =========
6 66 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 4: Investments (Continued) The net depreciation in fair value of investments of the Master Trust by major investment category for the year ended December 31, 1994 is as follows:
-In Thousands- Pacific Gas and Electric Company Common Stock Fund ($480,081) PAYSOP Fund (3,935) Diversified Equity Fund 1,409 Bond Index Fund (2,509) Stock and Bond Fund 60 Utility Stock Fund (13,080) --------- Total depreciation ($498,136) ========= Allocated to the Plan ($3,935) Allocated to other plans (494,201) --------- ($498,136) =========
7 67 PACIFIC GAS AND ELECTRIC COMPANY SAVINGS FUND PLAN - PART III NOTES TO FINANCIAL STATEMENTS December 31, 1994 NOTE 5: Reconciliation of Financial Statements to Form 5500 The following is a reconciliation of net assets available for benefits per the financial statements to the Form 5500:
--In Thousands-- December 31 ----------- 1994 1993 ---- ---- Net assets available for benefits per the financial statements $ 0 $10,252 Amounts allocated to withdrawing participants 0 (32) ------- ------ Net assets available for benefits per the Form 5500 $ 0 $10,220 ======= ======
The following is a reconciliation of benefits paid to participants per the financial statements to the Form 5500:
--In Thousands-- Year ended December 31, 1994 ----------------- Benefits paid to participants per the financial statements $ 314 Add: Amounts allocated to withdrawing participants at December 31, 1994 0 Less: Amounts allocated to withdrawing participants at December 31, 1993 (32) ----- Benefits paid to participants per the Form 5500 $ 282 =====
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