Item 1. Business.
GENERAL
Corporate Structure and Business
PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, electricity transmission, and natural gas transportation and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. PG&E Corporation also currently owns National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engages in electricity generation and natural gas transportation in the United States, or U.S.
The Utility
The Utility served approximately 4.9 million electricity distribution customers and approximately 3.9 million natural gas distribution customers at December 31, 2003. The Utility had approximately $29.1 billion of assets at December 31, 2003, and generated revenues of approximately $10.4 billion in 2003. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.
On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California. The factors that caused the Utility to take this action are discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, or the MD&A, and in Note 2 of the Notes to the Consolidated Financial Statements in PG&E Corporation’s and the Utility’s Combined 2003 Annual Report to Shareholders, or the Annual Report, which is incorporated by reference into this report. The Utility has retained control of its assets and is authorized to operate its business as a debtor-in-possession during its Chapter 11 proceeding.
On December 19, 2003, the CPUC, PG&E Corporation and the Utility entered into a settlement agreement, or the Settlement Agreement, that contemplated a plan of reorganization, or the Plan of Reorganization, which fully incorporates the Settlement Agreement. The Plan of Reorganization provides that the Utility will pay allowed creditor claims in full, plus applicable interest, and emerge from Chapter 11 as an investment grade entity. On December 22, 2003, the bankruptcy court confirmed the Plan of Reorganization. The Settlement Agreement and Plan of Reorganization are discussed further below, in the MD&A and in Note 2 of the Notes to the Consolidated Financial Statements in the Annual Report.
NEGT
NEGT was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. NEGT’s subsidiaries include: Gas Transmission Northwest Corporation (formerly PG&E Gas Transmission Northwest Corporation), North Baja Pipeline, LLC, National Energy Power Company, LLC (formerly PG&E Generating Power Group, LLC) and its subsidiaries, USGen New England, Inc. and its affiliates, and National Energy & Gas Transmission Trading Holdings Corporation and its subsidiaries.
On July 8, 2003, NEGT filed a voluntary petition for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. On the same day, each of the following indirect wholly owned subsidiaries of NEGT filed a voluntary petition for relief under Chapter 11: PG&E Energy Trading Holdings Corporation (now NEGT Energy Trading Holdings Corporation), PG&E Energy Trading-Power, L.P. (now NEGT Energy Trading - Power, L.P.), PG&E Energy Trading - Gas Corpora-
tion (now NEGT Energy Trading - Gas Corporation), and PG&E ET Investments Corporation (now NEGT ET Investments Corporation) and, separately, USGen New England, Inc. On July 29, 2003, two other subsidiaries, Quantum Ventures and PG&E Energy Services Ventures, Inc. (now Energy Services Ventures, Inc.), each filed voluntary Chapter 11 petitions.
The factors that caused NEGT and its subsidiaries to take this action are discussed in the MD&A and in Note 5 of the Notes to the Consolidated Financial Statements in the Annual Report. Pursuant to Chapter 11, NEGT and its subsidiaries that filed Chapter 11 petitions retain control of their assets and are authorized to operate their businesses as debtors-in-possession while they are subject to the jurisdiction of the bankruptcy court.
NEGT’s proposed plan of reorganization, if implemented, would eliminate PG&E Corporation’s equity interest in NEGT and its subsidiaries. In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives, who previously served as directors of NEGT resigned on July 7, 2003, and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over NEGT. Accordingly, effective July 8, 2003, NEGT’s results of operations no longer are consolidated with those of PG&E Corporation. NEGT’s results of operations through July 7, 2003, and for prior years have been reclassified as discontinued operations and PG&E Corporation now accounts for its investment in NEGT using the cost method of accounting.
Corporate and Other Information
The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility file various reports with the Securities and Exchange Commission, or the SEC. These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge on both PG&E Corporation’s website, www.pge-corp.com, and the Utility’s website, www.pge.com. The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.
Employees
At December 31, 2003, PG&E Corporation and its subsidiaries and affiliates (excluding NEGT) had approximately 20,600 employees, including approximately 20,300 employees of the Utility. Of the Utility’s employees, approximately 13,500 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or ESC; and the International Union of Security Officers/ SEIU, Local 24/7, or SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2007. The SEIU collective bargaining agreement expires on February 28, 2008.
The Utility’s Plan of Reorganization and Settlement Agreement
The Plan of Reorganization provides that the Utility will pay all allowed creditor claims in full (except for the claims of holders of certain pollution control-related bond obligations that will be reinstated) from the proceeds of a public offering of long-term debt, cash on hand, and draws on revolving credit facilities. At December 31, 2003, allowed claims in the Utility’s Chapter 11 proceeding amounted to approximately $12.3 billion.
The Settlement Agreement permits the Utility to emerge from Chapter 11 as an investment grade entity by generally ensuring that the Utility will have the opportunity to collect in rates reasonable costs of providing its utility service. The Settlement Agreement provides that the Utility’s authorized return on equity will be no less than 11.22% per year and, except for 2004 and 2005, its authorized equity ratio will be no less than 52% until the Utility’s credit rating has increased to a specified level. The Settlement Agreement establishes a
$2.21 billion after-tax regulatory asset and allows for the recognition of an approximately $800 million after-tax regulatory asset related to generation assets. The Settlement Agreement and related decisions by the CPUC provide that the Utility’s revenue requirement will be collected regardless of sales levels and that the Utility’s rates will be adjusted in a timely manner to accommodate changes in costs that the Utility incurs.
On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the Settlement Agreement. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. In addition, the two CPUC Commissioners who did not vote to approve the Settlement Agreement and a municipality have appealed the bankruptcy court’s confirmation order in the U.S. District Court for the Northern District of California, or the District Court. On January 5, 2004, the bankruptcy court denied a request to stay the implementation of the Plan of Reorganization until the appeals are resolved. The District Court will set a schedule for briefing and argument of the appeals at a later date. No additional parties may request rehearings or make appeals of the CPUC’s approval of the Settlement Agreement or the bankruptcy court’s confirmation order.
Implementation of the Plan of Reorganization is subject to various conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed by the Utility and PG&E Corporation to constitute final approval. Thus, the terms of the Plan of Reorganization permit the Utility and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the long term debt) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, PG&E Corporation and the Utility cannot conclude that the applicable accounting probability standard needed to record the regulatory assets contemplated by the Settlement Agreement has been met. PG&E Corporation and the Utility believe that the Utility and the long-term debt to be issued will receive investment grade credit ratings. The Utility has targeted April 2004 to complete the sale of the long-term debt, which the Utility expects to be the last condition of the Plan of Reorganization to be satisfied. The Plan of Reorganization provides that the effective date will occur 11 business days after all the conditions have been satisfied or, with respect to all conditions except those relating to investment grade credit ratings, waived by PG&E Corporation and the Utility. There can be no assurance that the Settlement Agreement will not be overturned on rehearing or appeal or that the Plan of Reorganization will become effective.
The Settlement Agreement and Plan of Reorganization are discussed further in the MD&A and in Note 2 of the Notes to the Consolidated Financial Statements in the Annual Report.
Refinancing Supported by a Dedicated Rate Component
Under the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized pre-tax balance of the $2.21 billion after-tax regulatory asset and related federal, state and franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of the Plan of Reorganization using a securitized financing supported by a dedicated rate component, provided the following conditions are met:
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Authorizing California legislation satisfactory to the CPUC, The Utility Reform Network, or TURN, and the Utility is passed and signed into law allowing securitization of the regulatory asset and associated federal and state income and franchise taxes and providing for the collection in the Utility’s rates of any portion of the associated tax amounts not securitized;
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The CPUC determines that, on a net present value basis, the refinancing would save customers money over the term of the securitized debt compared to the regulatory asset;
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The refinancing will not adversely affect the Utility’s issuer or debt credit ratings; and
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The Utility obtains, or decides it does not need, a private letter ruling from the Internal Revenue Service, or IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.
The Utility would be permitted to complete the refinancing in up to two tranches up to one year apart, and would issue sufficient callable debt or debt with earlier maturities as part of the Plan of Reorganization to accommodate the refinancing supported by a dedicated rate component. Upon refinancing with securitization, the equity and debt components of the Utility’s rate of return on the regulatory asset would be eliminated. Instead the utility would collect from customers amounts sufficient to service the securitized debt. The Utility would use the securitization proceeds to rebalance its capital structure in order to maintain the capital structure provided for under the Settlement Agreement.
Forward-Looking Statements and Risk Factors
This combined Annual Report on Form 10-K, including the portions of the Annual Report incorporated by reference, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on the information currently available to management. These forward-looking statements are identified by words such as “estimates,” “expects,” “anticipates,” “plans,” “believes,” “could,” “should,” “would,” “may” and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements.
Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:
Whether and on What Terms the Plan of Reorganization is Implemented
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The timing and resolution of the pending applications for rehearing of the CPUC’s approval of the Settlement Agreement and any appeals that may be filed with respect to the disposition of the rehearing applications;
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The timing and resolution of the pending appeals of the bankruptcy court’s confirmation of the Plan of Reorganization;
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Whether the investment grade credit ratings and other conditions required to implement the Plan of Reorganization are obtained or satisfied; and
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Future equity and debt market conditions, future interest rates, and other factors that may affect the Utility’s ability to implement the Plan of Reorganization or affect the amounts and terms of the debt proposed to be issued under the Plan of Reorganization.
Operating Environment
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Unanticipated changes in operating expenses or capital expenditures;
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The level and volatility of wholesale electricity and natural gas prices and supplies and the Utility’s ability to manage and respond to the levels and volatility successfully;
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Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility’s assets or operations or those of third parties on which the Utility relies;
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Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates;
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The extent to which the Utility’s residual net open position (i.e., the amount of electricity the Utility needs to meet its customers’ electricity demands that is not provided by Utility-owned generation, Utility power purchase contracts, or the electricity provided by the California Department of Water Resources, or DWR, and allocated to the Utility) increases or decreases due to changes in customer and economic growth rates, the periodic expiration or termination of Utility or DWR power purchase contracts, the reallocation of the DWR power purchase contracts, whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR; the retirement or other closure of the Utility’s electricity generation facilities, the performance of the Utility’s electricity generation facilities, and other factors;
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The operation of the Utility’s Diablo Canyon nuclear power plant, which exposes the Utility to potentially significant environmental and capital expenditure outlays, and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close its Diablo Canyon power plant and purchase electricity from more expensive sources;
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Actions of credit rating agencies;
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Significant changes in the Utility’s relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and
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Acts of terrorism.
Legislative and Regulatory Environment and Pending Litigation
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The impact of current and future ratemaking actions of the CPUC, including the outcome of the Utility’s 2003 General Rate Case, or the GRC;
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Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, U.S. Congress, the CPUC, the FERC and the Nuclear Regulatory Commission, or the NRC, with regard to allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;
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The extent to which the CPUC or the FERC delays or denies recovery of the Utility’s costs, including electricity purchase costs from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons;
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How the CPUC administers the capital structure, stand-alone dividend and first priority conditions of the CPUC’s decisions permitting the establishment of holding companies for California investor-owned electric utilities;
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Whether the Utility is in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses;
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Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations, and policies; and
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The outcome of pending litigation.
Competition
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Increased competition as a result of the takeover by condemnation of the Utility’s distribution assets, duplication of the Utility’s distribution assets or services by local public utility districts, self-generation by its customers and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and
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The extent to which the Utility’s distribution customers switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers and the extent to which cities, counties and others in the Utility’s service territory begin directly serving the Utility’s customers with their own facilities or combine to form community choice aggregators.
Electric Utility Operations
Electricity Distribution Operations
The Utility’s electricity distribution network extends throughout all or a part of 46 of California’s 58 counties, comprising most of northern and central California. The Utility’s network consists of 120,428 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 89 transmission substations and 45 transmission switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. There are 609 distribution substations and 117 low voltage distribution substations. There are 264 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers.
The Utility’s distribution network interconnects to the Utility’s electricity transmission system at 1,012 points. This interconnection between the Utility’s distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers. The distribution substations serve as the central hubs of the Utility’s electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or facilities to entities, such as municipal and other utilities, that then resell the electricity.
2003 Electricity Deliveries
The following table shows the percentage of the Utility’s total 2003 electricity deliveries represented by each of its major customer classes:
(80,156 GWhs)
Electricity Distribution Operating Statistics
The following table shows certain of the Utility’s operating statistics from 1999 to 2003 for electricity sold or delivered, including the classification of sales and revenues by type of service.
(1)
These amounts include electricity provided to direct access customers who procure their own supplies of electricity.
(2)
Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.
Electricity Resources
The following table shows the percentage of the Utility’s total sources of electricity for 2003 represented by each major electricity resource:
The Utility is required to dispatch all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. To the extent the Utility’s electricity resources are not sufficient to meet the demand of the Utility’s customers, the Utility purchases the electricity from the wholesale electricity market. At other times, least-cost dispatch requires the Utility to schedule more electricity than is necessary to meet its retail load and to sell this additional electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected electricity sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract.
Generation Facilities
At December 31, 2003, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:
(1)
The Humboldt Bay facilities consist of a retired nuclear generation unit, or Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.
(2)
In July 1998, the Utility reached an agreement with the City and County of San Francisco regarding the Utility’s Hunters Point fossil fuel-fired plant, which has been designated as a “must run” facility by the California Independent System Operator, or ISO, to support system reliability. The agreement expresses the Utility’s intention to retire the plant when it is no longer needed.
Diablo Canyon Power Plant. The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, each capable of generating up to approximately 1,087 MW of electricity. Unit 1 began commercial operation in May 1985 and the operating license for this unit expires in September 2021. Unit 2 began commercial operation in March 1986 and the operating license for this unit expires in April 2025. For the ten-year period ended December 31, 2003, the Utility’s Diablo Canyon power plant achieved a capacity factor of approximately 88.5%.
The following table outlines the Diablo Canyon power plant’s refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 19 to 21 months. The average length of a refueling outage over the last five years has been approximately 35 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the steam generator replacements in 2008 and 2009 discussed below. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of up to 80 days to accommodate non-routine tasks, such as expanded steam generator inspection and repair, low pressure turbine rotor replacement and the first of two proposed steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.
During a routine inspection conducted as part of the last refueling of Unit 2 in February 2003, the Utility found indications of steam generator tube cracking in locations and of a size not previously expected. After careful inspection and analysis, Unit 2 was able to safely restart after that outage and the Utility received the approval of the NRC to operate without further steam generator inspection until the next scheduled refueling in the fall of 2004. The Utility, however, is planning to accelerate the replacement of the steam generators in Unit 2 from 2009 to 2008. The Utility plans to replace Unit 1’s steam generators in 2009. The capital expenditures necessary to complete these projects are discussed further in the MD&A.
The Utility has several types of nuclear insurance for its Diablo Canyon power plant and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay additional annual premiums of up to $36.7 million.
NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.
Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.9 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for the Diablo Canyon power plant. The balance of the $10.9 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of reactors 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors over 100 MW, the Utility may be assessed up to
$201.2 million per incident, with payments in each year limited to a maximum of $20 million per incident. Although the Price-Anderson Act expired on December 31, 2003, coverage continues to be provided to all licensees, including the Diablo Canyon power plant, that had coverage before December 31, 2003. Congress may address renewal of the Price Anderson Act in future energy legislation.
In addition, the Utility has $53.3 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.
Hydroelectric Generation Facilities. The Utility’s hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe and 5 miles of natural waterways. The system also includes water rights as specified in 83 permits and licenses and 163 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses, all of the Utility’s powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last three years, the Utility has received six renewed hydroelectric project licenses from the FERC. Licenses associated with approximately 928 MW expire within the next five years. Licenses associated with approximately 2959 MW expire between 2009 and 2043.
DWR Power Purchases
In January 2001, because of the deteriorating credit conditions of the California investor-owned electric utilities, the State of California authorized the DWR to purchase electricity to meet the portion of the demand of the utilities’ customers, plus applicable reserve margins, not satisfied from their own generation facilities and existing electricity contracts. California Assembly Bill 1X, or AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. The Utility and the other California investor-owned electric utilities act as the billing and collection agent for the DWR’s sales of electricity to retail customers.
On September 19, 2002, the CPUC issued a decision allocating electricity from 19 of the DWR’s contracts, or the DWR allocated contracts, to the Utility’s customers. Electricity from DWR allocated contracts represented approximately 29% of the Utility’s total sources of electricity in 2003. In January 2003, the Utility became responsible for scheduling and dispatching the electricity subject to the 19 DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. During 2004, a total average capacity of approximately 2,700 MW of the electricity under the DWR allocated contracts is subject to “must take” provisions that require the DWR to take and pay for the electricity regardless of whether the electricity is needed. A total average capacity for 2004 of approximately 1,200 MW of the electricity under DWR allocated contracts is subject to provisions that require the DWR to pay a capacity charge, but do not require the purchase of electricity unless that electricity is dispatched and delivered.
The DWR is currently legally and financially responsible for these contracts. The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:
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After assumption, the Utility’s issuer rating by Moody’s will be no less than A2 and the Utility’s long-term issuer credit rating by Standard & Poor’s will be no less than A;
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The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and
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The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.
The Settlement Agreement does not limit the CPUC’s discretion to review the prudence of the Utility’s administration and dispatch of the assumed DWR power purchase contracts consistent with applicable law.
Third Party Agreements
Qualifying Facility Agreements
The Utility is required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. Under PURPA, the CPUC required California investor-owned electric utilities to enter into a series of long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, price options and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility’s actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement.
As a result of the energy crisis, the Utility owed approximately $1 billion to qualifying facilities when it filed its Chapter 11 proceeding. Through December 31, 2003, the principal payments made to the qualifying facilities amounted to $998 million.
At December 31, 2003, the Utility had agreements with 300 qualifying facilities for approximately 4,400 megawatts, or MW, that are in operation. Agreements for approximately 4,000 MW expire between 2004 and 2028. Qualifying facility power purchase agreements for approximately 400 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. The Utility also has agreements with 50 qualifying facilities that are not currently providing or expected to provide electricity. The total of approximately 4,400 MW consists of approximately 2,600 MW from cogeneration projects, 800 MW from wind projects and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar and hydroelectric. On January 22, 2004, the CPUC adopted a decision that requires California investor-owned electric utilities to allow owners of qualifying facilities with power purchase agreements expiring before the end of 2005 to extend these contracts for five years. Qualifying facility power purchase agreements accounted for approximately 20% of the Utility’s 2003 electricity sources, approximately 25% of the Utility’s 2002 electricity sources, and approximately 21% of the Utility’s 2001 electricity resources. No single qualifying facility accounted for more than 5% of the Utility’s 2003, 2002 or 2001 electricity sources.
In a proceeding pending at the CPUC, the Utility has requested refunds in excess of $500 million for overpayments from June 2000 through March 2001 made to qualifying facilities. Under the Settlement Agreement, the net after-tax amount of any qualifying facilities refunds, which the Utility actually realizes in cash, claim offsets or other credits, would reduce the $2.21 billion after-tax regulatory asset. PG&E Corporation and the Utility are unable to estimate the outcome of this proceeding.
Irrigation Districts and Water Agencies
The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements, regardless if any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. The Utility’s irrigation district and water agency contracts accounted for approximately 5% of 2003 electricity sources, approximately 4% of 2002 electricity sources and approximately 3% of 2001 electricity sources.
Other Third Party Power Agreements
Electricity Purchases to Satisfy the Residual Net Open Position
On January 1, 2003, the Utility resumed buying electricity to meet its residual net open position. During that year, more than 14,000 GWh of energy was bought and sold in the wholesale market to manage the 2003 residual net open position. Most of the Utility’s contracts entered into in 2003 had terms of less than one year. During 2004 the Utility plans to enter into contracts of longer duration to satisfy its near-term residual net open position.
Renewable Energy Contracts
California law requires that, beginning in 2003, each California investor-owned electric utility must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility estimates the annual procurement target will initially require it to purchase about 750 GWh, of electricity from renewable resources each year. The Utility met its 2003 commitment and the CPUC has approved several contracts intended to meet its 2004 renewable energy requirement.
Western Area Power Administration
In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into several long-term power contracts governing the interconnection of the Utility’s and WAPA’s electricity transmission systems, the use of the Utility’s electricity transmission and distribution system by WAPA, and the integration of the Utility’s and WAPA’s customer demands and electricity resources. The contracts give the Utility access to WAPA’s excess hydroelectric power and obligate the Utility to provide WAPA with electricity when its own resources are not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004, but termination is subject to FERC approval, which the Utility expects to receive.
The costs to fulfill the Utility’s obligations to WAPA under the contracts cannot be accurately estimated at this time since both the purchase price and the amount of electricity WAPA will need from the Utility in 2004 are uncertain. However, the Utility expects that the cost of meeting its contractual obligations to WAPA will be greater than the price the Utility receives from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, WAPA’s net amount purchased from the Utility was approximately 4,804 GWh, in 2003, 3,619 GWh in 2002 and 4,823 GWh in 2001.
For more information regarding the Utility’s power purchase contracts, see Note 12 of the Notes to the Consolidated Financial Statements of the Annual Report.
Electricity Transmission
At December 31, 2003, the Utility owned 18,612 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 42,798 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 120,428 circuit miles of distribution lines and substations with a capacity of 24,218 MVA. In 2003, the Utility delivered 80,156 GWh to its customers, including 8,979 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the Western Electricity Coordinating Council which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.
In connection with electricity industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and rates for transmission service are set by the FERC. The ISO which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The ISO also is responsible for maintaining the reliability of the transmission system.
The Utility has been working closely with the ISO to continue expanding the capacity on the Utility’s electric transmission system. The Utility is engaged in the following significant expansion projects:
Path 15 - WAPA and an independent transmission company, Trans-Elect NTD, Inc., are constructing a new 500 kV line to expand one segment of the transmission system, known as Path 15, which is located in the southern portion of the Utility’s service area, and serves as part of the primary transmission path between northern California and southern California. The improvements are intended to mitigate transmission constraints in this area. The Utility will interconnect the new 500 kV line at its existing substations at the line terminals and reconfigure its 230 kV and 115 kV facilities in the area to support a higher transfer capability through this section of the grid. This new 500 kV line is expected to be operational in October 2004.
Jefferson-Martin - This project entails laying 28 miles of 230 kV underground transmission facilities from Redwood City to Daly City that will provide additional transmission system reliability in San Francisco and northern San Mateo County. This project is expected to be completed in December 2005.
Natural Gas Utility Operations
The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 38 of California’s 58 counties and includes most of northern and central California. In 2003, the Utility served approximately 3.9 million natural gas distribution customers. The total volume of natural gas throughput during 2003 was approximately 804 Bcf.
At December 31, 2003, the Utility’s natural gas system consisted of 39,510 miles of distribution pipelines, 6,350 miles of transportation pipelines and three storage facilities. The Utility’s distribution network connects to the Utility’s transportation and storage system at approximately 2,200 major interconnection points. The Utility’s Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation, a subsidiary of NEGT, at the California-Oregon border. This line has a receipt capacity at the border of 2.0 Bcf per day. The Utility’s Line 300, which interconnects with the U.S. southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada and the southwestern United States. The Utility also is supplied by natural gas fields in California.
The Utility also owns and operates three underground natural gas storage fields located along the Utility’s transportation and storage system in close proximity to approximately 90% of the Utility’s end-user demand. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility’s northern California transportation system.
Since 1991, the CPUC has divided the Utility’s natural gas customers into two categories - core and noncore customers. This classification is based largely on a customer’s annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercial natural gas customers. In 2003, core customers represented over 99% of the Utility’s total customers and 35% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility’s total customers and 65% of its total natural gas deliveries.
The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. Currently, over 99% of core customers, representing over 98% of core market demand, receive natural gas bundled services from the Utility.
In accordance with a ratemaking settlement agreement implemented in 1998 called the Gas Accord, the Utility stopped providing procurement service to noncore customers in March 2001. During the winter of 2000-2001 when there was a steep increase in natural gas prices, many noncore customers switched to core service in order to receive procurement service from the Utility. In December 2003, the CPUC approved the Utility’s request to prohibit electricity generation, cogeneration, enhanced oil recovery and refinery, and other large noncore customers from electing to transfer to core service, and requiring smaller noncore customers to sign up for a minimum five-year term if they elect to transfer to core service. The Utility made this request because of its concern that large increases in the Utility’s natural gas supply portfolio demand from significant transfers of noncore customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce it’s pipeline system to provide core service reliability on a short-term basis to serve this new load.
The Utility offers transportation, distribution and storage services as separate and distinct services to its noncore customers. These customers may elect to receive storage services from the Utility or competitive storage providers. Noncore customers interconnected at a transportation level only pay for transportation service, while those interconnected at a distribution level pay for both transportation and distribution service. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to the Utility’s transportation system is available for all natural gas marketers and shippers, as well as noncore customers.
Customers pay a distribution rate that reflects the Utility’s costs to serve each customer class. The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’s results of operations over the long term are not affected by their consumption levels. The Utility’s results of operations can, however, be affected by noncore consumption levels because there are no similar regulatory balancing accounts related to noncore customers. Approximately 96% of the Utility’s natural gas distribution base revenues are recovered from core customers and 4% are recovered from noncore customers.
The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and natural gas utilities. The 2002 California Gas Report updated the Utility’s annual natural gas requirements forecast for the years 2002 through 2023, forecasting average annual growth in the Utility’s natural gas deliveries of approximately 1.8%. The natural 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 economic activity, conservation, and the number and location of electricity generation facilities.
Natural Gas Deliveries
The following table shows the percentage of the Utility’s total 2003 natural gas deliveries represented by each of the Utility’s major customer classes:
(804 Bcf)
Natural Gas Operating Statistics
The following table shows the Utility’s operating statistics from 1999 through 2003 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:
(1)
Includes fuel for the Utility’s fossil fuel-fired generation plants.
Natural Gas Supplies
The Utility purchases natural gas to serve the Utility’s core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2003, the Utility purchased approximately 292,000 MMcf of natural gas (net of the sale of excess supply) from 48 suppliers. Substantially all this natural gas was purchased under contracts with a term of less than one year. The Utility’s largest individual supplier represented approximately 9.6% of the total natural gas volume the Utility purchased during 2003.
The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility’s natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2003, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.
(1)
California purchases include supplies from various California producers and supplies transported into California by others.
Gas Gathering Facilities
The Utility’s gas gathering system collects and processes natural gas from third-party wells in California. During 2003, approximately 4% of the Utility’s natural gas supplies came from various California producers and from supplies transported into California by others. The natural gas is processed to remove various impurities from the natural gas stream and to odorize the natural gas so that it may be detected in the event of a leak. The facilities include 475 miles of gas gathering pipelines, as well as dehydration, separation, regulation, odorization and metering equipment located at 62 stations. The gas gathering system is geographically dispersed and is located in 14 California counties. Approximately 120 MMcf per day of natural gas flows through the Utility’s gas gathering system.
Interstate and Canadian Natural Gas Transportation Services Agreements
In 2003, approximately 67% of the Utility’s natural gas supplies came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers’ service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System. These companies’ pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with the Utility’s natural gas transportation system in the area of California near Malin, Oregon. The Utility has a firm transportation agreement with Gas Transmission Northwest Corporation for these services.
During 2003, approximately 29% of the Utility’s natural gas supplies came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Co.,
or Transwestern, and El Paso Natural Gas Company, or El Paso, to transport this natural gas from supply points in this region to interconnection points with the Utility’s natural gas transportation system in the area of California near Topock, Arizona.
The following table shows certain information about the Utility’s firm natural gas transportation agreements, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System, and the FERC in all other cases. The Utility recovers these demand charges through the CPIM. The Utility may, upon prior notice, extend each of these natural gas transportation agreements for additional minimum terms ranging, depending on the particular agreement, from one to ten years. On the FERC-regulated pipelines, the Utility has a right of first refusal allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.
Competition
Historically, energy utilities operated as regulated monopolies within service territories where they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport and distribute energy. Services were priced on a combined, or bundled, basis with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertake a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices. In recent years, energy utilities have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies. The most significant of these services are the commodity components - the supply of electricity and natural gas.
The driving forces behind these competitive pressures have been customers who believe they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators responded to these forces by providing for more competition in the energy industry. Regulators and legislators, to varying degrees, have required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.
The Electricity Industry
The FERC’s policies have supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities’ transmission grids. The FERC’s subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. The FERC’s standard market design proposal issued in July 2002 encourages unbundled transmission. The ISO also issued its own comprehensive market design proposal to effect changes to the structure and operation of the California electricity market, subject to the FERC’s approval. The FERC has approved the first phase of the ISO’s new rules and implementation of the first phase is expected to be completed in the second quarter of 2004. A later phase to establish integrated forward markets and locational marginal pricing and revise congestion management would be implemented in the future, assuming FERC approval. The ISO is expected to file proposed tariff language with the FERC later in 2004 to address these issues. Both the timing and substance of the FERC’s regional transmission organization policy and the FERC’s and the ISO’s market design processes may be affected by any energy legislation Congress may pass.
In July 2003, in order to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generator and transmission infrastructure, the FERC issued final rules on the interconnection of generators larger than 20 MW with a transmission system. The rules will require regulated transmission providers, such as the Utility or the ISO, generally to use standard interconnection procedures and a standard agreement for generator interconnections. These rules would require the Utility and the ISO to revise the existing agreements and procedures used when constructing facilities to interconnect new generators. Numerous parties have requested rehearing and a stay of the generator interconnection rules. Although the FERC has not yet ruled on the requests for rehearing, the FERC has ordered that the rules will not become effective until after the FERC accepts new tariff changes to implement the rules. The Utility, along with other transmission owners, filed proposed tariffs changes on January 20, 2004. It is uncertain when the FERC will act on the rehearing requests or the proposed tariff changes. Further, portions of the FERC’s rulemaking may be affected by any energy legislation Congress may pass.
In 1998, California implemented AB 1890, which mandated the restructuring of the California electricity industry and established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity. AB 1890 also gave customers the choice of continuing to buy electricity from the California investor-owned electric utilities or, beginning in April 1998, entering into contracts to purchase electricity from alternate energy service providers(i.e., becoming direct access customers). The CPUC suspended the right of retail end-user customers to become direct access customers on September 20, 2001. The CPUC has assessed an additional charge on certain direct access customers to avoid a shift of costs from direct access customers to customers who receive bundled service.
In October 2003, the CPUC instituted a rulemaking implementing AB 117, which permits California cities and counties to purchase and sell electricity for their residents once they have registered as community choice aggregators. Under AB 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators’ customers and be those customers’ provider of electricity of last resort. However, once registration has occurred, each community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. To prevent a shifting of costs to customers of a utility who receive bundled services, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator will pay an appropriate share of the DWR’s and the Utility’s costs. AB 117 also authorized the Utility to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from ratepayers any costs of implementing the program not reasonably attributable to a community choice aggregator.
The Utility faces competition in the electricity distribution business as a result of the construction of duplicate distribution facilities to serve specific existing or new customers, condemnation of the Utility’s distribution facilities by local governments or districts, self-generation by the Utility’s customers and technological developments. These and other forms of competition may result in stranded investment capital, loss of customer growth and additional barriers to cost recovery. As customers and local public officials explore their energy options in light of the recent California energy crisis, these bypass risks are increasing and may increase further if the Utility’s rates exceed the cost of other available alternatives.
A number of local governments and districts in California are considering various forms of providing electric distribution services within the Utility’s service territory. The City and County of San Francisco (along with other California communities) have been considering municipalization of the Utility’s electricity distribution system within their jurisdictions. In addition, the Sacramento Municipal Utility District currently is considering annexing portions of the Utility’s service territory, with the objective of enabling the district to replace the Utility within these areas. Some existing public power entities, such as the Modesto and Merced Irrigation Districts, also are expanding their services in the Utility’s service area. Finally, some districts that are not currently distributing electricity, including the El Dorado Irrigation District and the South San Joaquin Irrigation District, are considering building facilities that would duplicate the Utility’s facilities. In May 2003, the South San Joaquin Irrigation District revealed its plans to invest over $40 million to duplicate the Utility’s distribution facilities and begin serving existing and new customers in and around Manteca. In 2002, the City of Hercules formed its own municipal utility for the purpose of competing with the Utility to serve new customers within the city. In 2003, the City of Hercules began providing electricity service to a 200-home subdivision and a large commercial customer, and has been actively pursuing additional residential and commercial customers. The Utility cannot currently predict the impact of these actions on the Utility’s business, although one possible outcome is a decline in the demand for the electricity that the Utility provides, which would result in a decline in the Utility’s revenues.
The Natural Gas Industry
FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service regardless of whether the customer (often a local gas distribution company) buys the natural gas commodity from these companies.
In 1998, the Utility implemented the Gas Accord under which the natural gas transportation and storage services the Utility provides were separated for ratemaking purposes from the Utility’s distribution services. The Gas Accord changed the terms of service and rate structure for natural gas transportation, allowing the Utility’s core customers to purchase natural gas from competing suppliers. The Utility’s noncore customers purchase their natural gas from producers, marketers and brokers, and purchase their preferred mix of transportation, storage and distribution services from the Utility. Although they can select the gas suppliers of their choice, substantially all core customers buy natural gas, as well as transportation and distribution services, from the Utility as bundled service. The Gas Accord market structure has been extended by the CPUC through 2005.
The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas and the quality and reliability of transportation services. The most important competitive factor affecting the Utility’s market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility’s case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, the Utility’s market share of transportation services into southern California decreases. In addition, Kern River Pipeline Company completed a major expansion of its pipeline system in May 2003 that increased its capacity to
deliver natural gas into the southern California market by approximately 900 MMcf per day. As a result this expansion, the volume of natural gas that the Utility delivers to the southern California market may decrease, although to date the Utility has not experienced any significant decrease in its volumes shipped. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.
From time to time, existing pipeline companies propose to expand their pipeline systems for delivery of natural gas into northern and central California. As a result of the California energy crisis, several new natural gas pipeline proposals were initiated to serve proposed new generation facilities for northern and central California. Many of the electricity generation projects have been cancelled or delayed, making it difficult for sponsors of the various gas pipeline projects to acquire enough firm capacity commitments to go forward with construction.
PG&E Corporation’s Regulatory Environment
Federal Energy Regulation
PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935, or PUHCA. Currently, PG&E Corporation has no expectation of becoming a registered holding company under PUHCA. The California Attorney General has filed a petition with the SEC requesting the SEC to review and revoke PG&E Corporation’s exemption from PUHCA and to begin fully regulating the activities of PG&E Corporation and its affiliates. PG&E Corporation responded in detail to the California Attorney General petition demonstrating that PG&E Corporation qualified for an exemption from PUHCA and that there was no basis for action by the SEC. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the California Attorney General’s petition.
During 2003, proposed federal energy legislation was considered by the U.S. Senate. If adopted, the legislation would, among other things, repeal PUHCA. PUHCA currently imposes significant regulatory barriers to mergers and acquisitions involving public utilities and public utility holding companies. The repeal of PUHCA could trigger a period of consolidation among public utilities, as well as acquisitions of public utilities by other businesses. As a result, the repeal of PUHCA could increase competitive pressures on the energy utility industry, including competition from sources the Utility does not currently view as competitors. The proposed effective date for the repeal of PUHCA, as well as the proposed effective date for proposed legislation that would replace PUHCA, is December 1, 2004. Under the proposed legislation that would replace PUHCA, public utilities and public utility holding companies would remain under the regulatory oversight of the FERC, but not the SEC.
State Energy Regulation
PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the CPUC. However, the CPUC approval authorizing the Utility to form a holding company was granted subject to various conditions set forth in CPUC decisions issued in 1996 and 1999 related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:
•
the Utility is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC;
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the Utility’s dividend policy must continue to be established by the Utility’s Board of Directors as though the Utility were a stand-alone utility company;
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the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation’s Board of Directors, or (known as the first priority condition); and
•
the Utility must maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility’s equity ratio by 1% or more.
The CPUC also has adopted complex and detailed rules governing transactions between California’s electricity and natural gas distribution companies and their non-regulated affiliates. The rules permit non-regulated affiliates of regulated utilities to compete in the affiliated utility’s service territory, and also to use the name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The rules also address the separation of regulated utilities and their non-regulated affiliates and information exchange among the affiliates. The rules prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility’s non-regulated affiliates. In January 2004, the CPUC adopted rules that prohibit regulated utility electric procurement from entering into power procurement related transactions with an affiliate, subject to the following exceptions:
•
anonymous transactions through approved interstate brokers and exchanges, provided that the solicitation/bidding process is structured so that the identity of the seller is not known to the buyer until agreement is reached, and vice-versa;
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transactions for natural gas services between the regulated utility and affiliates or operating divisions that are found necessary and beneficial for ratepayer interests, subject to the receipt and review of a management audit; and
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transactions that occur pursuant to contracts with affiliates that were already existing on January 22, 2004.
The CPUC also has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.
On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned electric utilities, including the Utility, have complied with past CPUC decisions, rules and orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will investigate the utilities’ transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties; the failure of the holding companies to financially assist the utilities when needed; the transfer by the holding companies of assets to unregulated subsidiaries; and the holding companies’ actions to “ringfence” their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions or recommend statutory changes to the California legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate.
On January 9, 2002, the CPUC issued two decisions in its pending investigation. In one decision, the CPUC, for the first time, adopted a broad interpretation of the first priority condition and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies “infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve.” The three major California investor owned electric utilities and their parent holding companies had opposed this broader interpretation as being inconsistent with the prior 15 years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from acquiring assets of its utility subsidiary for inadequate consideration and acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility’s ability to fulfill its obligation to serve or to operate in a prudent and efficient manner. In the other decision, the CPUC asserted that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similar holding companies and to modify, clarify or add to the conditions.
In a related decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the interim decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision adopted on January 9, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum could decide expeditiously whether adoption of the Utility’s original proposed plan of reorganization would violate the first priority condition. On November 26, 2003, the California Court of Appeals for the First Appellate District in San Francisco agreed to hear the petitions for review of the CPUC’s decisions. Oral argument before the appellate court is set for March 5, 2004.
PG&E Corporation and the Utility believe that they have complied with applicable statutes CPUC decisions, rules and orders. Under the Settlement Agreement the CPUC has agreed to dismiss PG&E Corporation from the CPUC’s investigation as to past practices.
On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200. Among other allegations, the California Attorney General alleges that PG&E Corporation violated the various conditions established by the CPUC in decisions approving the holding company formation. After the California Attorney General’s complaint was filed, two other complaints containing substantially similar allegations were filed by the City and County of San Francisco and by a private plaintiff. These complaints are not affected by the Settlement Agreement. For more information, see “Item 3 - Legal Proceedings” below.
The Utility’s Regulatory Environment
Various aspects of the Utility’s business are subject to a complex set of energy, environmental and other governmental laws, regulations and regulatory proceedings at the federal, state and local levels. This section and the “Ratemaking Mechanisms” section below summarize some of the more significant energy laws, regulations and regulatory mechanisms affecting the Utility. These sections are not an exhaustive description of all the energy laws, regulations and regulatory proceedings that affect the Utility. The energy laws, regulations and regulatory proceedings may change or be implemented or applied in a way that the Utility does not currently anticipate. For discussion of specific regulatory proceedings affecting the Utility, see the MD&A.
Federal Energy Regulation
The FERC
The FERC is an independent agency within the U.S. Department of Energy, or DOE, that regulates the transmission of electricity in interstate commerce and the sale for resale of electricity in interstate commerce. The FERC regulates electricity transmission, interconnections, tariffs and conditions of service of the ISO and the terms and rates of wholesale electricity sales. The ISO is responsible for providing open access transmission service on a non-discriminatory basis, meeting applicable reliability criteria, planning transmission system additions and assuring the maintenance of adequate reserves of generation capacity. In addition, the FERC has jurisdiction over the Utility’s electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility’s hydroelectric generation facilities and the interstate sale and transportation of natural gas.
In response to the California energy crisis, the FERC issued a series of orders in the spring and summer of 2001 and July 2002 aimed at prospectively mitigating extreme wholesale energy prices like those that prevailed in 2000 and 2001. These orders established a cap on bids for real-time electricity and ancillary services of $250 per MWh (unless a generator could demonstrate that its costs justified a rate in excess of $250 per MWh) and established various automatic mitigation procedures. As of December 2003, all sellers
with market-based rate authority became subject to, and incorporated in their market-based rate tariffs, behavioral conditions designed to prevent market manipulation.
In February 2004, the FERC is expected to consider ISO market monitoring and oversight in connection with the FERC’s review of the ISO’s standard market design proposals. Market monitoring and mitigation also may be affected by any energy legislation Congress may pass.
Various entities, including the Utility and the State of California, are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers from January 2000 to June 2001. In December 2002, a FERC administrative law judge issued an initial decision finding that power suppliers overcharged the utilities, the State of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001 (the only time period for which the FERC permitted refund claims), but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.
During 2003, the FERC confirmed most of the administrative law judge’s findings, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the California Power Exchange, or PX, which operates solely to reconcile remaining refund amounts owed, to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by August 2004. The actual refunds will not be determined until the FERC issues a final decision following the ISO and PX compliance filings. The FERC is uncertain when it will issue a final decision in this proceeding. In addition, future refunds could increase or decrease as a result of an alternative calculation proposed by the ISO, which incorporates revised data provided by the Utility and other entities.
Under the Settlement Agreement, the Utility and PG&E Corporation agreed to continue to cooperate with the CPUC and the State of California in seeking refunds from generators and other energy suppliers. The net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relating to the Utility’s ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offset of creditor claims in its Chapter 11 proceeding would reduce the balance of the $2.21 billion after-tax regulatory asset created by the Settlement Agreement.
The Utility has recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. The Utility currently estimates that the claims filed would have been reduced to approximately $1.2 billion based on the refund methodology recommended in the administrative law judge’s initial decision, resulting in a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset. The recalculation of market prices according to the revised methodology adopted by the FERC in its October 2003 decision could further reduce the amount of the suppliers’ claims by several hundred million dollars. However, this reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology.
The NRC
The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’s Diablo Canyon power plant and Humboldt Bay Unit 3. NRC regulations require extensive monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. Safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at the Utility’s Diablo Canyon power plant and additional significant capital expenditures could be required in the future.
State Energy Regulation
The CPUC
The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility’s electricity distribution, natural gas distribution and natural gas transportation and storage services in California. The CPUC also has jurisdiction over the Utility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’s electricity and natural gas retail customers, rate of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning and aspects of the siting of the electricity transmission system. Ratemaking for retail sales from the Utility’s generation facilities is under the jurisdiction of the CPUC. To the extent this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.
California Legislature
Over the last several years, the Utility’s operations have been significantly affected by statutes passed by the California legislature, including:
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Assembly Bill 1890. AB 1890 mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and the Utility’s customers were given the choice of becoming direct access customers;
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Assembly Bill 6X. AB 6X, enacted in January 2001 in response to the California energy crisis, prohibited disposition of utility-owned generation facilities before January 1, 2006;
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Assembly Bill 1X. AB 1X authorized the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities’ retail customers. AB 1X required the California investor-owned electric utilities, including the Utility, to deliver that electricity and act as the DWR’s billing and collection agent;
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Senate Bill 1976. SB 1976, enacted in September 2002, required the CPUC to allocate electricity from contracts that the DWR entered into under AB 1X among the customers of the California investor-owned electric utilities, required the utilities to file short- and long-term procurement plans with the CPUC, contemplated that the utilities would resume buying electricity pursuant to these plans by January 1, 2003, and mandated new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under approved procurement plans; and
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Senate Bill 1078. SB 1078, enacted in September 2002, creates a renewable portfolio standard for investor-owned utilities that requires annual 1% increases of renewable electrical procurement purchases until renewable resources equal 20% of total retail sales in 2017.
One of PG&E Corporation and the Utility’s obligations under the Settlement Agreement is seeking to refinance the remaining unamortized pre-tax balance of the regulatory asset and related federal, state and franchise taxes using a securitized financing supported by a dedicated rate component that would require enactment of authorizing California legislation. On January 22, 2004, the CPUC approved proposed legislation, Senate Bill 772, that would authorize a dedicated rate component to securitize the regulatory asset and the related taxes. The California Assembly’s Utilities and Commerce Committee approved the proposed legislation on February 2, 2004. The proposed legislation will next be considered by the California Assembly’s Appropriations Committee. Under the Settlement Agreement, any adopted legislation must be satisfactory to the CPUC, the Utility and The Utility Reform Network, or TURN and the securitization must not adversely affect the Utility’s credit ratings among other conditions.
The California Energy Resources Conservation and Development Commission
The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission, or CEC, is the state’s primary energy policy and planning agency. The CEC is responsible for the siting of all thermal power plants over 49 MW and administers public interest research and development funds, as well as renewable resource programs, including the renewable energy portfolio standard program.
Other Regulation
The Utility obtains a number of permits, authorizations and licenses in connection with the construction and operation of the Utility’s generation facilities, electricity transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. The Utility currently has seven hydroelectric projects and one transmission line project undergoing FERC relicensing. The Utility will begin relicensing proceedings on two additional hydroelectric projects within the next two years.
The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate and maintain the Utility’s electric, natural gas, oil and water facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties under the franchises. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. However, there are 38 charter cities that can set a fee of their own determination. The Utility also periodically obtains permits, authorizations and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations and licenses the Utility has rights to occupy and/or use public property for the operation of the Utility’s business and to conduct certain related operations.
Ratemaking Mechanisms
Overview
Transition from Frozen Rates to Cost of Service Ratemaking
Frozen electricity rates, which began on January 1, 1998, were designed to allow the Utility to recover its authorized utility costs, and to the extent frozen rates generated revenues in excess of these costs, to recover the Utility’s transition costs. Although the surcharges implemented in 2001 effectively increased the actual rate, under the frozen rate structure, increases in the Utility’s authorized revenue requirements did not increase the Utility’s revenues. In addition, DWR revenue requirements reduced the Utility’s revenues under the frozen rate structure. As a result of revised electricity rates discussed below and a January 2004 CPUC decision determining that the rate freeze ended on January 18, 2001, the Utility expects that once approved by the CPUC, its rates will reflect its costs of service whereby the Utility’s rates are calculated based on the aggregate of various authorized rate components. Changes in any individual revenue requirement will change customers’ electricity rates.
On January 26, 2004, the Utility filed revised electricity rates with the CPUC based on the Utility’s 2004 forecast revenue requirements and requested implementation of the rate changes. These rates reflect allocation of the Utility’s revenue requirements in accordance with a January 20, 2004 rate design settlement agreement entered into with a number of consumer groups and government agencies, including TURN and the CPUC’s Office of Ratepayer Advocates, or ORA. The rate design settlement agreement has been submitted to the
CPUC for approval. The revised rates and forecast revenue requirements are based on, and ultimately will be adjusted to reflect, pending or final CPUC decisions including:
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The Utility’s 2003 GRC;
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The allocation of the DWR’s 2004 revenue requirements;
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Pending energy supplier refunds, claim offsets or other credits pursuant to the Settlement Agreement; and
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The calculation of any over-collection of the surcharge revenues for 2003.
Based on the revised rates filed by the Utility on January 26, 2004, current electricity revenues are expected to be reduced by approximately $860 million as compared to revenues generated at current rates. On February 11, 2004, a proposed decision was issued which, if ultimately approved by the CPUC, instead is expected to reduce the Utility’s current electricity revenues by $799 million. The most significant portion of the difference between the $799 million included in the draft decision and the $860 million filed by the Utility relates to a proposed decrease in the DWR’s revenue requirement included in the Utility’s January 26, 2004 rate filing. In the January 26, 2004 rate filing, the Utility had estimated that the DWR’s revenue requirement would be reduced by approximately $79 million related to the DWR’s share of the settlement agreement of CPUC litigation reached with El Paso. However, the DWR protested the Utility’s rate filing, indicating that the amount of its share of the El Paso settlement was unknown and that the DWR had not changed its revenue requirement as a result of the El Paso settlement.
The February 11, 2004 proposed decision orders the Utility to amend its January 26, 2004 filing containing the revised electricity rates before March 1, 2004. The CPUC is expected to consider the rate design settlement at its meeting on February 26, 2004. If approved, the new rates will be effective March 1, 2004 or shortly thereafter, and the revenue reduction will be retroactive to January 1, 2004.
Revenue Requirements
Before the rates for the Utility’s electricity and natural gas utility services can be set, revenue requirements must first be determined. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs. Revenue requirements are designed to allow a utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in utility facilities, or rate base. Revenue requirements are then allocated among customer classes and specific rates designed to produce the required revenue are established. In the Utility’s rate cases, intervenors have the opportunity to comment on the Utility’s application. The issues raised by these comments are then resolved by the appropriate regulatory agency. If the Utility and the intervenors can settle these issues, these settlements are submitted to the regulatory agency for approval.
General Rate Cases
The Utility’s primary revenue requirement proceeding is the general rate case, or GRC, filed with the CPUC. In the GRC, the CPUC authorizes the Utility to collect from customers an amount known as base revenues to recover base business and operational costs related to the Utility’s electricity and natural gas distribution and electricity generation operations. The GRC typically sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedings based on a forecast of costs for the first, or test, year. After authorizing the revenue requirements, the CPUC allocates revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levels. Typical intervenors in the Utility’s GRC include the ORA and TURN.
Attrition Rate Adjustments
The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations.
Cost of Capital Proceedings
The CPUC generally conducts an annual cost of capital proceeding to determine the Utility’s authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The cost of capital proceeding establishes the percentage components that common equity, preferred equity and debt will represent in the Utility’s total authorized capital structure for a specific year. The CPUC then establishes the authorized return on common equity, preferred equity and debt that the Utility will have the opportunity to collect in its authorized rates. For 2005, this proceeding also will set the authorized rate of return for the Utility’s gas transportation and storage assets.
Baseline Allowance
The CPUC sets and periodically revises a baseline allowance for the Utility’s residential gas and electricity customers. A customer’s baseline allowance is the amount of its monthly usage that is covered under the lowest possible natural gas or electric rate. Electricity baseline usage is also exempt from certain surcharges. Natural gas or electricity usage in excess of the baseline allowance is covered by higher rates that increases with usage.
DWR Electricity and DWR Revenue Requirements
As a consequence of the California energy crisis, on January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the DWR to purchase electricity to maintain the continuity of supply to retail customers. This was followed by AB 1X, which authorized the DWR to purchase electricity and sell that electricity directly to the California investor-owned utilities’ retail end-user customers and to issue revenue bonds to finance electricity purchases. AB 1X also required the Utility to deliver the electricity purchased by the DWR over the Utility’s distribution systems and to act as a billing and collection agent for the DWR, without taking title to DWR purchased electricity or reselling it to the Utility’s customers.
AB 1X allows the DWR to recover its costs of electricity and associated transmission and related services, principal and interest on bonds issued to finance the purchase of electricity, administrative costs and certain other amounts associated with purchasing electricity through a revenue requirement. AB 1X also authorizes the CPUC to set rates to cover the DWR’s revenue requirements, but prohibits the CPUC from increasing electricity rates for residential customers who use less electricity than 130% of their existing baseline quantities.
Under AB 1X, the DWR was prohibited after December 31, 2002 from entering into new electricity purchase contracts and from purchasing electricity on the spot market. SB 1976, which became law in September 2002, required the CPUC to allocate electricity from existing DWR contracts among the customers of the California investor-owned electric utilities, including the Utility’s customers. On September 19, 2002, the CPUC issued a decision allocating electricity from the DWR contracts to the customers of the three California investor-owned electric utilities. The DWR continues to be legally and financially responsible for these contracts. The electricity provided under 19 of the DWR contracts was allocated to the Utility’s customers. The Utility is responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with these contracts.
The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power
charge. The Utility’s customers also must pay what is known as a bond charge to pay a share of the DWR’s revenue requirements to recover costs associated with the DWR’s $11.3 billion bond offering completed in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR’s revenue requirement and to provide the DWR with funds to make its electricity purchases. Because the Utility acts as a billing and collection agent for the DWR, amounts collected for the DWR and any adjustments are not included in the Utility’s revenues.
DWR Allocated Contracts
The DWR provided approximately 29% of the electricity delivered to the Utility’s customers for the year ended December 31, 2003. The DWR purchased the electricity under contracts with various generators and through open market purchases. The Utility is responsible for administration and dispatch of the DWR’s electricity procurement contracts allocated to the Utility, for purposes of meeting a portion of the Utility’s net open position. The DWR remains legally and financially responsible for the electricity procurement contracts.
The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered.
The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:
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After assumption, the Utility’s issuer rating by Moody’s Investors Services will be no less than A2 and the Utility’s long-term issuer credit rating by Standard & Poors will be no less than A;
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The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and
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The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.
Procurement Resumption and Procurement Plans
On January 1, 2003, the California investor-owned electric utilities resumed responsibility for procuring electricity to meet their residual net open positions. They also became responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The utilities also were required by SB 1976 to submit short-term and long-term procurement plans to the CPUC for approval. In December 2002, the CPUC adopted a 2003 short-term procurement plan for the Utility. The CPUC also authorized the California investor-owned electric utilities to extend their planning into the first quarter of 2004 and directed the Utility to hedge its 2004 first quarter residual net open position with transactions entered into in 2003.
In December 2003, the CPUC approved the Utility’s short-term 2004 procurement plan. In the January 2004 CPUC decision discussed below, the CPUC also adopted short-term procurement authority for 2005 for the utilities in order to allow them to begin the normal cycle for procuring products required for summer 2005, but contracts for 2005 cannot exceed one year.
On January 22, 2004, the CPUC adopted an interim decision establishing the long-term regulatory framework under which the California investor-owned electric utilities are required to plan for and procure
energy resources. The utilities are directed to meet resource needs first through cost effective energy efficiency, demand response, and renewable resources before considering the addition of conventional supply or transmission resources. The utilities are encouraged to have a diversified resource portfolio. The utilities are required to submit new long-term procurement plans in 2004 following workshops and the CPUC’s adoption of specific resource adequacy criteria. The procurement plans are required to include a range of load forecasts for distributed generation and varying levels of community choice aggregation. The CPUC adopted a planning reserve requirement of 15% to 17% applicable to all load-serving entities, including the utilities, energy service providers and future community choice aggregators. The planning reserve requirement will be phased in by January 1, 2008, and intermediate benchmarks are to be established. In addition, beginning in 2005, the utilities and other load-serving entities are required to secure 90% of their electricity needs during the peak energy months of May through September through forward contracts at least one year in advance. The CPUC also indicated that it will consider procurement incentive mechanisms for the utilities. The CPUC also continued the 5% target limitation on the utilities’ reliance on the spot market to meet their energy needs.
Effective January 1, 2003, under California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the recorded electricity procurement revenues and actual costs incurred under the Utility’s authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an investor-owned utility’s electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate when the aggregate over-collections or under-collections exceed 5% of the utility’s prior year electricity procurement revenues,, excluding amounts collected for the DWR. These mandatory adjustments will continue until January 1, 2006.
Electricity Transmission
The Utility’s electricity transmission revenues and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two sources of transmission revenues, charges under the Utility’s transmission owner tariff and charges under specific contracts with existing wholesale transmission customers that pre-date the Utility’s participation in the ISO. Customers that receive transmission services under these pre-existing contracts, referred to as existing transmission contract customers, are charged individualized rates based on the terms of their contracts. Transmission rates established by the FERC are included by the CPUC in the Utility’s retail electricity rates and collected from retail electricity customers receiving bundled service under the federal filed rate doctrine.
Transmission Owner Rate Cases
Under the FERC’s regulatory regime, the Utility is able to file a new base transmission rate case under the Utility’s transmission owner tariff whenever the Utility deems it necessary to increase its rates within certain guidelines set forth by the FERC. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.
The Utility’s transmission owner tariff includes two rate components:
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Base transmission rates, which are intended to recover the Utility’s operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity; and
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Rates to recover ISO charges for both reliability service costs and an ISO charge associated with a ten-year shift from utility-specific transmission charges to an ISO grid-wide charge, both of which are discussed below.
The Utility derives the majority of the Utility’s transmission revenue from base transmission rates.
Transmission Control Agreement
The Utility is a party to a Transmission Control Agreement, or TCA, with the ISO and other participating transmission owners. As a transmission owner, the Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA. Under this agreement, the transmission owners, which also include Southern California Edison, or SCE, San Diego Gas & Electric Company and several municipal utilities, assign operational control of their electricity transmission systems to the ISO. In addition, as a party to the TCA, the Utility is responsible for a share of the costs of reliability must-run, or RMR, agreements between the ISO and owners of the power plants subject to RMR agreements, or RMR Plants. The Utility also is an owner of some of these RMR Plants for which the Utility receives revenue from the ISO. Under the RMR agreements, RMR Plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO’s demand.
At December 31, 2003, the ISO had RMR agreements for which the Utility could be obligated to pay the ISO an estimated $446 million in net costs during the period January 1, 2004 to December 31, 2005. These costs are recoverable under applicable ratemaking mechanisms.
It is possible that the Utility may receive a refund of RMR costs that the Utility previously paid to the ISO. In June 2000, a FERC administrative law judge issued an initial decision approving rates that, if affirmed by the FERC, would require the subsidiaries of Mirant Corporation, or Mirant, that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $340 million, including interest, for availability of Mirant’s RMR Plants under these agreements. However, on July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 and on December 15, 2003, the Utility filed claims in Mirant’s Chapter 11 proceeding including a claim for an RMR refund. The Utility is unable to predict at this time when the FERC will issue a final decision on this issue, what the FERC’s decision will be, and the amount of any refunds, which may be impacted by Mirant’s Chapter 11 filing. It is uncertain how the resolution of this matter would be reflected in rates.
Reliability Services Costs
The ISO bills the Utility for reliability services based on payments that the ISO makes to generators under reliability must run agreements and to others to support reliability of the Utility’s transmission system. The costs of reliability must run agreements attributed to supporting the Utility’s historic transmission control area are charged to the Utility as a participating transmission owner. These costs were approximately $330 million in 2003. Under the Utility’s transmission owner tariff, the Utility charges its customers rates designed to recover these reliability service charges, without mark-up or service fees. The Utility tracks costs and revenues related to reliability services in the reliability services balancing account. Periodically, the Utility’s electricity transmission rates are adjusted to refund over-collections to the Utility’s customers or to collect any under-collections from customers.
Transmission Access Charge
In March 2000, the ISO filed an application with the FERC seeking to establish its own transmission access charge as directed by AB 1890. The ISO’s transmission access charge methodology provides for transition to a uniform statewide high-voltage transmission rate, based on the revenue requirements of all participating transmission owners associated with facilities operated at 200 kV and above. The transmission access charge methodology also requires the Utility and other transmission owners, during a ten-year transition period, to pay a charge intended to reimburse other transmission owners (who are generally new ISO participants) whose costs are higher than that embedded in the uniform rate. Under the ISO’s application, the Utility’s obligation for this cost differential would be capped at $32 million per year during the ten-year transition period. A hearing in this matter was conducted at the FERC in October and November 2003 and an initial decision from the presiding administrative law judge is scheduled to be issued in March 2004.
Natural Gas
The Gas Accord
In 1998, the Utility implemented a ratemaking pact called the Gas Accord, under which the Utility’s natural gas transportation and storage services were separated for ratemaking purposes from its distribution services. The Gas Accord established natural gas transportation rates and natural gas storage rates. On December 18, 2003, the CPUC approved the Utility’s application to retain the Gas Accord market structure for 2004 and 2005, and resolved the rates, and terms and conditions of service for the Utility’s natural gas transportation and storage system for 2004. The Utility continues to be at risk of not recovering its natural gas transportation and storage costs and does not have regulatory balancing account protection for over-collections or under-collections of natural gas transportation or storage revenues.
Biennial Cost Allocation Proceeding
The Utility’s natural gas distribution costs and balancing account balances are allocated to customers in the Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any overcollection, in the balancing accounts. Balancing accounts for gas and public purpose program revenue requirements accumulate differences between authorized revenue requirements and actual base revenues.
Natural Gas Procurement
The Utility sets the natural gas procurement rate for core customers monthly based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.
Under the core procurement incentive mechanism, or the CPIM, the Utility’s natural gas purchase costs (including Canadian and interstate capacity and volumetric transportation charges) are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is currently between 99% and 102% of the benchmark, are considered reasonable and fully recoverable, in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility’s customers receive three-fourths of the savings when the costs are below 99% of the benchmark. Any awards associated with the CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual period ending October 31 that is used to measure the CPIM. These awards are not included in earnings until approved by the CPUC.
On January 22, 2004, the CPUC opened a rulemaking proceeding to establish policies and rules to ensure reliable, long-term supplies of natural gas to California. The order poses a series of questions and requires all gas utilities in California to provide information related to their natural gas procurement activities and their transportation and storage facilities. Among other things, the CPUC indicated that it may adopt rules whereby utilities could receive CPUC pre-approval of contracts for interstate pipeline capacity to support their natural gas procurement activities.
Interstate and Canadian Natural Gas Transportation and Storage
The Utility’s interstate and Canadian natural gas transportation agreements with third party service providers are governed by tariffs that detail rates, rules and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process and the applicable Canadian tariffs by the Alberta Energy and Utilities Board and the National Energy Board. The Utility’s agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility’s core natural gas procurement business. Their purpose is to
transport natural gas from the points at which the Utility takes delivery of natural gas - typically in Canada and the southwestern United States - to the points at which the Utility’s natural gas transportation system begins.
Capacity Purchases on El Paso and Transwestern Pipelines
In July 2002, the CPUC ordered California investor-owned electric utilities to contract for additional amounts of El Paso pipeline capacity to gain firm access to the southwest natural gas producing basins. The CPUC believed that if the utilities had firm access rights, they would have been able to mitigate the gas price spikes that occurred during the energy crisis when shippers raised the price of gas at the California border. The CPUC pre-approved the costs of these contracts as just and reasonable. Since the July 2002 decision, the Utility has signed contracts for capacity on the El Paso pipeline costing approximately $50.8 million for the period from November 2002 to December 2007. The July 2002 decision also ordered the California investor-owned electric utilities to retain their then-current interstate pipeline capacity levels and sell any excess capacity to third parties under short-term capacity release arrangements. It also ordered that, to the extent the California investor-owned electric utilities comply with the decision, they will be able to fully recover their costs associated with existing capacity contracts.
Under a previous CPUC decision, the Utility could not recover in rates any costs paid to Transwestern for natural gas pipeline capacity through 1997. The Utility pays approximately $22 million in annual reservation charges under the Transwestern contract. The Gas Accord provided for partial recovery of Transwestern costs after 1997. In January 2004, the CPUC approved a settlement with TURN that allows the Utility to fully recover Transwestern costs retroactive to July 2003.
In December 2002, the CPUC granted the Utility’s request to recover in rates El Paso pipeline capacity costs and prepayments made to El Paso from all natural gas customers. The Utility began recovering these costs from all natural gas customers in March 2003. In January 2004, the CPUC re-allocated all the costs, including Transwestern costs incurred since July 2003, to the Utility’s core customers, because the pipeline capacity is used to serve core customers. The Utility’s noncore customers and core aggregation customers will receive a refund or bill credit for El Paso capacity costs paid by these customers between March 2003 and January 2004.
Environmental Matters
The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance. The information below reflects current estimates that are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner’s responsibility and the availability of recoveries or contributions from third parties.
General
The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of activities, including:
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The discharge of pollutants into air, water and soil;
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The identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting of, remediation of and emergency response in connection with, hazardous, and radioactive substances; and
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Land use, including endangered species and habitat protection.
The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify or replace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations and clean up or decommission waste disposal areas at the Utility’s current or former facilities and at third-party sites where the Utility may have disposed of wastes.
Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility’s rates, subject to reasonableness review. Environmental costs associated with sites that contain hazardous wastes are subject to a special ratemaking mechanism.
In 1994, the CPUC established a ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims (e.g., for cleaning up the Utility’s facilities and sites where the Utility has sent hazardous substances) from customers. That mechanism allows the Utility to include 90% of the hazardous waste remediation costs in the Utility’s rates without review. Hazardous waste remediation costs in the future are likely to be significant. However, based on the Utility’s past experience, it believes that it can recover most of these costs in rates and through insurance claims.
Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility’s customers. The balance of any insurance recoveries, (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. There also is a special sharing of the costs incurred pursuing recovery under insurance contracts. In connection with electricity industry restructuring, this mechanism may no longer be used to recover electricity generation-related clean-up costs for contamination caused by events occurring after January 1, 1998. The Utility cannot provide assurance, however, that these costs will not be material, or that the Utility will be able to recover its costs in the future.
Air Quality
The Utility’s generation plants and natural gas pipeline operations are subject to numerous air pollution control laws, including the Federal Clean Air Act and similar state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxide and particulate matter. Fossil fuel-fired electric utility plants and gas compressor stations used in the Utility’s pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.
Various multi-pollutant initiatives have been introduced in the U.S. Senate and House of Representatives. These initiatives include limits on the emissions of nitrogen oxide, sulfur dioxide, mercury and carbon dioxide, and some would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules. Hearings on legislation to amend the federal Clean Air Act have been held in the U.S. Senate but not in the House of Representatives.
As a result of the Utility’s divestiture of most of its fossil fuel-fired and geothermal generation facilities, the Utility’s nitrogen oxide emission reduction compliance costs have been reduced significantly. Two of the local air districts in which the Utility owns and operates fossil fuel-fired generation facilities have adopted final rules under the California Clean Air Act and the federal Clean Air Act that required reductions in nitrogen oxide emissions from the facilities of approximately 90% by 2004. The Utility is in compliance with these rules. The Utility is permitted to recover in customer rates through 2004 the Utility’s costs for its nitrogen oxide retrofit projects related to natural gas compressor stations on the Utility’s Line 300, which delivers gas from the southwest. Several air districts are considering nitrogen oxide rules that would apply to the Utility’s other natural gas compressor stations in California. Eventually, the rules are likely to require nitrogen oxide reductions of up to 80% at many of these natural gas compressor stations. Substantially all these costs will be capital costs which the Utility expects to recover through rates.
In addition, current regulatory initiatives, particularly at the federal level, could increase the Utility’s compliance costs and capital expenditures primarily with respect to the Utility’s gas transportation facilities, fleet and fuel storage tanks, to comply with laws relating to emissions of carbon dioxide and other greenhouse gases, particulates and other toxic pollutants. If enacted, these laws could require the Utility to replace equipment, install additional pollution controls, purchase various emission allowances, or curtail operations. Although associated costs and capital expenditures could be material, the Utility expects that it would be able to recover these costs and capital expenditures in rates.
Water Quality
The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the U.S. Environmental Protection Agency, or the EPA. The Utility’s generation facilities are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility’s steam-electric generation facilities comply in all material respects with the discharge constituents standards and the thermal standards. In addition, under the federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction and capacity of generation facility cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each steam-electric generation facility’s intake structure to various governmental agencies and each power plant’s existing intake structure was found to meet the best technology available requirements.
The Utility’s Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a National Pollutant Discharge Elimination System, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, recreation, commercial/sport fishing, marine and wildlife habitat, shellfish harvesting and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant’s discharge was not protective of beneficial uses.
In October 2000, the Utility and the Central Coast Board reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility’s discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology meets the best technology available requirements. As part of the Central Coast settlement agreement, the Utility has agreed to take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General’s Office. A condition to the effectiveness of this settlement agreement is that the Central Coast Board renew Diablo Canyon’s NPDES permit. However, at its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported this settlement agreement, and the Central Coast Board requested its staff to develop additional information on possible mitigation measures. The California Attorney General filed a claim in the Utility’s Chapter 11 proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with the Diablo Canyon power plant’s operation of its cooling water system. The Utility is seeking withdrawal of this claim from the Utility’s Chapter 11 proceeding.
In addition, on April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing electricity generation facilities using over 50 million gallons per day, typically including some form of “once-through” cooling. The Utility’s Diablo Canyon, Hunters Point and Humboldt Bay power plants are among an estimated 539 generation
facilities nationwide that would be affected by this rulemaking. The proposed regulations call for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. Significant capital investment may be required to achieve the standards if the regulations are adopted as proposed. The final regulations are scheduled to be issued in February 2004.
In mid-January 2004, hexavalent chromium was detected in a sample taken from a groundwater monitoring well near the Utility’s natural gas compressor station located near Topock, Arizona. This monitoring well is located approximately 150 feet from the Colorado River. While hexavalent chromium had been detected during previous sampling of other monitoring wells located further from the river, previous samples from this well had not shown any detectable hexavalent chromium. The Utility is cooperating with the California Department of Toxic Substances Control, or DTSC, other state agencies and appropriate federal agencies to develop a plan to ensure that the hexavalent chromium does not impact the Colorado River. Although implementation of the plan poses several technical and regulatory obstacles, the Utility does not expect the outcome in this matter to have a material adverse effect on its results of operations or financial condition.
Endangered Species
Many of the Utility’s facilities and operations are located in or pass through areas that are designated as critical habitats for federal or state-listed endangered, threatened or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated near the Utility’s facilities or operations. The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with the state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.
Hazardous Waste Compliance and Remediation
The Utility’s facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of the Utility’s operations, the Utility generates waste that falls within CERCLA’s definition of a hazardous substance and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling and disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous waste laws and other environmental requirements.
The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.
Operations at the Utility’s current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal generation facilities and most of its fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies.
In addition, the federal Toxic Substances Control Act regulates the use, disposal and cleanup of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. During the 1980s, the Utility initiated two major programs to remove from service all of the distribution capacitors and network transformers containing high concentrations of PCBs. These programs removed the vast majority of PCBs existing in the Utility’s electricity distribution system.
The Utility is 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 from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The lampblack and tar residues are byproducts of a process that the Utility, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Utility’s manufactured gas plants were removed from service. The residues that may remain at some sites contain chemical compounds that now are classified as hazardous. The Utility owns all or a portion of 28 manufactured gas plant sites. The Utility has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at these sites. The Utility spent approximately $8 million in 2003 and expects to spend approximately $6 million in 2004 on these projects. The Utility expects that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. In addition, approximately 68 other manufactured gas plants in the Utility’s service territory are now owned by others. The Utility has not incurred any significant costs associated with these non-owned sites, but it is possible that the Utility may incur additional cleanup costs related to these sites in the future if hazardous substances for which the Utility has liability are found.
Under environmental laws such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility’s facilities, or to pay for associated cleanup costs or natural resource damages. The Utility is currently aware of eight such sites where investigation or cleanup activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility has been directed to perform site studies and any necessary remedial measures by regulatory agencies. At the Casmalia disposal facility near Santa Maria, California, the Utility and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and mitigation measures.
In addition, the Utility has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites that it no longer owns or never owned. Remedial actions may include investigations, health and ecological assessments and removal of wastes.
The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and the Utility can estimate a range of reasonably likely cleanup costs. The Utility reviews its remediation liability quarterly for each site where the Utility may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at similar sites and the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility’s responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.
The Utility had an undiscounted environmental remediation liability of approximately $314 million at December 31, 2003, and $331 million at December 31, 2002. During 2003, the liability was reduced by approximately $17 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $314 million accrued at December 31, 2003, includes approximately $104 million related to the pre-closing remediation liability associated with divested generation facilities, and approximately $210 million related to remediation costs for those generation facilities that the Utility still owns, natural gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that are either owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $314 million environmental remediation liability, approximately $147 million has been included in prior rate-setting proceedings, and the Utility expects that approximately $116 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to ratepayers.
The Utility’s undiscounted future costs could increase to as much as $422 million if the other potentially responsible parties are not financially able to contribute to these costs or the extent of contamination or necessary remediation is greater than anticipated. The $422 million amount does not include an estimate for the costs of remediation at known sites owned or operated in the past by the Utility’s predecessor corporations for which the Utility has not been able to determine whether liability exists.
The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility’s Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most of these sites, remediation is ongoing in the ordinary course of business or the Utility is in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the cleanup. Other sites identified in the California Attorney General’s claims may not, in fact, require remediation or cleanup actions. The Utility’s Plan of Reorganization provides that the Utility intends to respond to these types of claims in the ordinary course of business and since the Utility has not argued that the Chapter 11 proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the California Attorney General’s claims seeking specific cash recoveries are unenforceable. Environmental claims in the ordinary course of business will not be discharged in the Utility’s Chapter 11 proceeding and will pass through the Chapter 11 proceeding unimpaired.
Nuclear Fuel Disposal
Under the Nuclear Waste Policy Act of 1982, or Nuclear Waste Act, the DOE is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more permanent disposal sites be in operation by 1998. Consistent with the law, the Utility entered into a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Utility’s nuclear power facilities beginning not later than January 1998. The DOE has been unable to meet its contractual commitment to begin accepting spent fuel. First, there was a delay in identifying a storage site. Then, after the DOE selected Yucca Mountain, Nevada for the site, protracted litigation has prevented the DOE from constructing the storage facility. The DOE’s current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. However, considerable uncertainty exists regarding when the DOE will begin to accept spent fuel for storage or disposal. Under the Utility’s contract with the DOE, if the DOE completes a storage facility by 2010, the earliest Diablo Canyon’s spent fuel would be accepted for storage or disposal would be 2018.
On January 22, 2004, the Utility filed separate complaints in the U.S. Court of Federal Claims against the DOE alleging that the DOE has breached its contractual obligation to move used nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. The complaints seek recovery of the Utility’s costs incurred for the planning and development of on-site storage at both facilities as a result of the DOE’s failure to meet its obligations. The Utility’s complaints are similar to complaints filed by at least 20 other utilities with nuclear facilities.
Under current operating procedures, the Utility believes that the Diablo Canyon power plant’s existing spent fuel pools have sufficient capacity to enable it to operate through approximately 2007. It is unlikely that an interim or permanent DOE storage facility will be available by 2007. Therefore, the Utility has applied to the NRC for a license to build an on-site dry cask storage facility to store spent fuel at the Diablo Canyon power plant, pending disposal or storage at a DOE facility. The NRC has provided initial approvals for the facility and is expected to complete its authorization process in early 2004. The Utility also has initiated the process for obtaining a required California Costal Commission permit for the facility. If the dry cask storage facility is not approved or is delayed, the Utility also is pursuing NRC approval of another storage option to install a temporary rack in each unit that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 to 2011. During this additional period of time, the Utility also would pursue NRC approval for a high density reracking of both units, which, if approved, would allow the Utility to operate both units until shortly before the licenses expire in 2021 for Unit 1 and 2025 for Unit 2. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility, and it is otherwise unable to increase its on-site storage capacity it is possible that the operations of Diablo Canyon may have to be curtailed or halted until such time as spent fuel can be safely stored.
In July 1988, the NRC gave the Utility final approval to store radioactive waste from the Utility’s retired nuclear generating facility, Humboldt Bay Unit 3, at the plant until 2015 before ultimately decommissioning the unit. The Utility has agreed to remove all spent fuel when the federal disposal site is available. In 1988, the Utility completed the first step in the decommissioning of Humboldt Bay Unit 3 and placed the unit into SAFSTOR, a condition of monitored safe storage in which the unit will be maintained until the spent nuclear fuel is removed from the spent fuel pool and the facility is dismantled. The used fuel assemblies currently are stored in metal racks submerged in a pool of water called a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concrete and lined with stainless steel.
The Utility filed an application in December 2003 with the NRC seeking authorization to build an on-site dry cask storage facility at Humboldt Bay Unit 3. The Utility plans to file an application with the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to a dry cask facility would allow early decommissioning of Humboldt Bay Unit 3. The Utility anticipates that, if it were licensed to employ an on-site dry cask storage facility, the Utility would receive a 20-year initial license for on-site dry cask storage with the opportunity to receive a 20-year renewal term.
Nuclear Decommissioning
Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility’s nuclear power facilities consist of two units at the Diablo Canyon power plant and the retired facility at Humboldt Bay Unit 3. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2021 and to be completed in 2040. Decommissioning of Diablo Canyon Unit 2 is scheduled to begin in 2025 and to be completed in 2041, and decommissioning of Humboldt Bay Unit 3 is scheduled to begin in 2006 and be completed in 2015.
The estimated nuclear decommissioning costs for the Diablo Canyon power plant and Humboldt Bay Unit 3 are approximately $1.83 billion in 2003 dollars (or approximately $5.25 billion in future dollars). These estimates are based on a 2002 decommissioning cost study, prepared in accordance with CPUC requirements, and used in the Utility’s Nuclear Decommissioning Costs Triennial Proceeding discussed below. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear plants. Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, costs of labor, materials and equipment.
The CPUC has established the Nuclear Decommissioning Costs Triennial Proceeding to determine the Utility’s estimated decommissioning costs and to establish the associated annual revenue requirement and escalation factors for consecutive three-year periods. In October 2003, the CPUC issued a decision in the 2002 Nuclear Decommissioning Costs Triennial Proceeding (covering 2003 through 2005) finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the Diablo Canyon power plant’s eventual decommissioning. The decision also set the annual decommissioning fund revenue requirement for
Humboldt Bay Unit 3 at approximately $18.5 million and granted the Utility’s request to begin decommissioning Humboldt Bay Unit 3 in 2006 instead of 2015. The decision further granted the Utility’s request of approximately $8.3 million for Humboldt Bay Unit 3 SAFSTOR operating and maintenance costs. The total adopted annual revenue requirement of approximately $26.7 million represents a $4.5 million decrease from the previously adopted revenue requirement of approximately $31.2 million, which included amounts for both Humboldt Bay Unit 3 and Diablo Canyon. The CPUC also ordered the Utility to partially fund its 2004 revenue requirement with approximately $10 million that the Utility collected in rates in 2000 for its nuclear decommissioning revenue requirement but that the Utility did not contribute to the trusts due to the Utility’s cash conservation needs during the energy crisis.
The Utility’s revenue requirements for nuclear decommissioning costs are recovered from ratepayers through a nonbypassable charge that will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, the Utility is allowed a deduction for the payments made to the qualified trusts. These payments cannot exceed the amount collected from ratepayers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts’ after-tax returns. Among other requirements, to maintain the qualified trust status, the Internal Revenue Service, or IRS, must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until the decommissioning costs are actually incurred.
In 2003, the Utility collected approximately $22.6 million in rates and contributed approximately $21.3 million, on an after-tax basis, to the nuclear decommissioning trusts. For 2004, the Utility is authorized to collect approximately $18.5 million in rates for decommissioning Humboldt Bay Unit 3. Of this amount, the Utility expects to contribute approximately $13.3 million, on an after-tax basis, to the qualified and non-qualified trusts for Humboldt Bay Unit 3. The Utility has requested the IRS approve the new amounts to be contributed to the qualified trusts for Humboldt Bay Unit 3. If the IRS does not approve the request, the Utility must withdraw any contributions it made to the qualified trusts for 2003 and contribute the withdrawn amounts, on an after-tax basis, to the non-qualified trust. The Utility would likely request that the CPUC approve an increase in revenue requirements to make up for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxes
The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility’s nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. All earnings on the funds held in the trusts, net of authorized disbursements from the trusts and management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC. At December 31, 2003, the Utility had accumulated decommissioning trust funds with an estimated fair value of approximately $1.4 billion, based on quoted market prices and net of deferred taxes on unrealized gains.
Electric and Magnetic Fields
Electric magnetic fields, or EMFs, naturally result from the generation, transmission, distribution and use of electricity. In January 1991, the CPUC opened an investigation to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with EMFs from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMFs, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist.
In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and
an EMF research program managed by the California Department of Health Services. As part of the Utility’s effort to educate the public about EMFs, the Utility provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.
In October 2002, the California Department of Health Services released its report, based primarily on its review of studies by others, evaluating the possible risks from EMFs, to the CPUC and the public. The report’s conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health Services’ report has assigned a higher probability to the possibility that there is a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.
It is not yet clear what actions the CPUC will take to respond to this report. Possible outcomes include, but are not limited to, continuation of current policies and imposition of more stringent measures to mitigate EMF exposures. The Utility cannot estimate the costs of such mitigation measures with any certainty at this time. However, such costs could be significant, depending on the particular mitigation measures undertaken, especially if the Utility must ultimately relocate existing power lines.
The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs from power lines. The court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMFs are similarly barred. The Utility was one of the defendants in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMFs. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs and barred plaintiffs’ personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case.
Item 2.
Item 2.
Properties.
The Utility’s corporate headquarters consist of approximately 1.8 million square feet of office space located in several buildings in San Francisco, California. In addition to this corporate office space, the Utility owns or has obtained the right to occupy and/or use real property comprising the Utility’s electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under “- Electricity Utility Operations” and “- Gas Utility Operations.” In total, the Utility occupies 9.3 million square feet, including approximately 975,000 square feet of leased office space. The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits or licenses from private landowners or governmental authorities. The Utility currently owns approximately 170,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements or donate to public agencies or non-profit conservation organizations under the settlement agreement with the CPUC. Approximately 44,000 acres of this land may be either donated or encumbered with conservation easements. The remaining land contains the Utility’s or a joint licensee’s hydroelectric generation facilities and may only be encumbered with conservation easements.
PG&E Corporation also leases approximately 74,000 square feet of office space from a third party in San Francisco, California. This lease expires in 2005.
Item 3.
Item 3.
Legal Proceedings.
In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business.
Pacific Gas and Electric Company Chapter 11 Filing
On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the Northern District of California. The factors that caused the Utility to take this action are discussed in MD&A and in Note 2 of the Notes to the Consolidated Financial Statements in the Annual Report, which is incorporated by reference into this report. During the Utility’s Chapter 11 proceeding, the Utility has retained control of its assets and is authorized to operate its business as a debtor-in-possession while it is subject to the jurisdiction of the bankruptcy court.
David A. Coulter, a director of the Utility, is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank. J.P. Morgan Trust Co. of Delaware submitted a proof of claim in the Utility’s Chapter 11 case for approximately $1.45 million relating to its ownership interest in shares of the Utility’s preferred stock. J.P. Morgan Chase Bank submitted a proof of claim for approximately $173 million, related to its provision of a stand-by letter of credit which provides credit and liquidity support for certain of the Utility’s pollution control bonds. Both entities are subsidiaries of J.P. Morgan Chase & Co.
In September 2001, PG&E Corporation and the Utility submitted a plan of reorganization that proposed to disaggregate the Utility’s current businesses. The CPUC, later joined by the Official Committee of Unsecured Creditors, or OCC, submitted a competing proposed plan of reorganization that did not provide for disaggregation of the Utility’s businesses. As discussed above, on December 19, 2003, the CPUC, PG&E Corporation and the Utility entered into the Settlement Agreement that contemplated a new plan of reorganization to supercede the competing plans. Under the Settlement Agreement, the Utility remains vertically integrated. On December 22, 2003, the bankruptcy court confirmed the Plan of Reorganization that fully incorporates the Settlement Agreement.
On December 30, 2003, the City of Palo Alto filed a motion with the bankruptcy court for a stay of the bankruptcy court’s order confirming the Plan of Reorganization pending the City of Palo Alto’s appeal of the confirmation order to the U.S. District Court for the Northern District of California, or District Court. The two CPUC Commissioners who did not vote to approve the Settlement Agreement joined in the City of Palo Alto’s motion. On January 5, 2004, the bankruptcy court denied the request for a stay. In January 2004, the City of Palo Alto and the two CPUC Commissioners filed appeals in the District Court of the bankruptcy court’s confirmation order.
On January 20, 2004, the City of Palo Alto, the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, filed separate applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the Settlement Agreement. CCSF, Aglet and the ORA also filed a joint application for rehearing. Although the CPUC is not required to act on the applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review.
Under the Settlement Agreement, the CPUC has waived all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties’ rights under the Settlement Agreement, the Plan of Reorganization or the confirmation order. The CPUC also consented to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the bankruptcy court. The CPUC’s waiver is irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off or any other legal process with respect to the enforcement of, or other determination of the parties’ rights under, the Settlement Agreement, the Plan of Reorganization or the confirmation order. The Settlement Agreement contemplates that neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties’ rights under the Settlement Agreement, the Plan of Reorganization or the confirmation order.
The Settlement Agreement generally terminates nine years after the effective date of the Plan of Reorganization, except that the rights of the parties to the Settlement Agreement that vest on or before termination, including any rights arising from any default under the Settlement Agreement, will survive termination for the purpose of enforcement. The parties agreed that the bankruptcy court will have jurisdiction
over the parties for all purposes relating to enforcement of the Settlement Agreement, the Plan of Reorganization and the confirmation order. The parties also agreed that the Settlement Agreement, the Plan of Reorganization or any order entered by the bankruptcy court contemplated or required to implement the Settlement Agreement or the Plan of Reorganization will be irrevocable and binding on the parties and enforceable under federal law notwithstanding any future decisions or orders of the CPUC.
As required by the Settlement Agreement, the Utility has requested a stay of all proceedings before the FERC, the NRC, the SEC and other regulatory agencies relating to approvals sought to implement the original plan of reorganization. The Utility also has suspended all actions to obtain or transfer licenses, permits and franchises to implement the original plan of reorganization. On the effective date of the confirmed Plan of Reorganization or as soon thereafter as practicable, the Utility and PG&E Corporation will withdraw or abandon all applications for these regulatory approvals.
There are several legal proceedings still pending in connection with the original plan of reorganization. On May 14, 2003, the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, heard oral argument in the appeal filed by the CPUC and other parties of an order issued by the District Court finding that the U.S. Bankruptcy Code expressly preempts “non-bankruptcy laws that would otherwise apply to bar, among other things, transactions necessary to implement the reorganization plan.” The District Court’s order had reversed an earlier ruling by the bankruptcy court that found that bankruptcy law did not expressly preempt certain non-bankruptcy laws in connection with the original plan of reorganization, but that it could be implied to preempt non-bankruptcy laws in certain circumstances.
On November 19, 2003, the Ninth Circuit issued a decision agreeing with the District Court’s finding that a Chapter 11 reorganization plan expressly preempts otherwise applicable non-bankruptcy laws. However, the Ninth Circuit ruled that the scope of such express preemption is limited to those non-bankruptcy laws relating to financial condition. The Ninth Circuit determined that neither the bankruptcy court nor the District Court had applied the proper standard of express preemption. It therefore reversed the District Court’s August 30, 2002, decision and remanded the matter back to the bankruptcy court for further proceedings to determine whether the Utility’s and PG&E Corporation’s original plan of reorganization satisfied the express preemption standard announced by the Ninth Circuit.
Although the Ninth Circuit stated that the question of implied preemption was not before it in the appeal, it reaffirmed that implied preemption could apply under the Bankruptcy Code, even if express preemption did not. On December 10, 2003, the Utility and PG&E Corporation filed a petition to rehear the Ninth Circuit’s decision with the panel that issued the decision, and suggested that the full Ninth Circuit should rehear the issue, since it conflicts with other Ninth Circuit cases and cases from other Circuits.
The Utility’s current Settlement Agreement and the confirmed Plan of Reorganization do not rely on the bankruptcy law preemption issues addressed in the Ninth Circuit decision.
Implementation of the Plan of Reorganization is subject to various conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed by the Utility and PG&E Corporation to constitute final approval. Thus, the terms of the Plan of Reorganization permit the Utility and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the long term debt) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, PG&E Corporation and the Utility cannot conclude that the applicable accounting probability standard needed to record the regulatory assets contemplated by the Settlement Agreement has been met. PG&E Corporation and the Utility believe that the Utility and the long-term debt to be issued will receive investment grade credit ratings. The Utility has targeted April 2004 to complete the sale of the long-term debt, which the Utility expects to be the last condition of the Plan of Reorganization to be satisfied. The Plan of Reorganization provides that the effective date will occur 11 business days after all the conditions have been satisfied or, with respect to all conditions except those relating
to investment grade credit ratings, waived by PG&E Corporation and the Utility. There can be no assurance that the Settlement Agreement will not be modified on rehearing or appeal or that the Plan of Reorganization will become effective.
Chapter 11 Filing of NEGT
On July 8, 2003, NEGT and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. On July 29, 2003, two additional subsidiaries of NEGT also filed voluntary Chapter 11 petitions. NEGT also has filed a proposed plan of reorganization with the bankruptcy court that, if implemented, would eliminate PG&E Corporation’s equity interest in NEGT and its subsidiaries.
In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives who previously served as directors of NEGT resigned on July 7, 2003 and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E no longer retains significant influence over NEGT. Accordingly, effective July 8, 2003, NEGT’s results of operations are no longer consolidated with those of PG&E Corporation and its results of operations through July 7, 2003 and for prior years have been reclassified as discontinued operations.
For more information, see Note 5 of the Notes to the Consolidated Financial Statements in the Annual Report, which is incorporated by reference and filed as Exhibit 13 to this report.
Pacific Gas and Electric Company vs. Michael Peevey, et al.
On November 8, 2000, the Utility filed a lawsuit in the District Court against the CPUC commissioners. In this lawsuit, the Utility seeks a declaration that the federally tariffed wholesale electricity costs that the Utility had incurred to serve the Utility’s customers are recoverable in retail rates under the federal filed rate doctrine.
The Utility’s complaint alleges that the wholesale electricity costs that the Utility has prudently incurred are paid pursuant to filed tariffs that the FERC has authorized and approved, and that, under the U.S. Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. The Utility’s complaint also alleges that, to the extent that the Utility is denied recovery of these wholesale electricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility’s property. The Utility argues that the CPUC’s decisions are preempted by federal law under the filed rate doctrine, which requires the CPUC to allow the Utility to recover in full it’s reasonable purchase costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also asserts claims under the Commerce Clause and the Due Process Clause of the U.S. Constitution. On January 29, 2001, the Utility’s lawsuit was transferred to the U.S. District Court for the Central District of California, where a similar lawsuit filed by Southern California Edison Company was pending. On May 2, 2001, the court dismissed the Utility’s complaints without prejudice to re-filing at a later date, on the ground that the lawsuit was premature, since two CPUC decisions referenced in the complaint had not become final under California law. The court rejected all of the CPUC’s other arguments for dismissal of the Utility’s complaint.
In August 2001, the Utility re-filed the Utility’s complaint in the District Court based on the Utility’s belief that the CPUC decisions referenced in the court’s May 2001 order had become final under California law. On October 31, 2001, the CPUC moved to dismiss the action. While the motion was under submission, the parties filed cross-motions for summary judgment.
On July 25, 2002, the court denied the CPUC’s motion to dismiss on all grounds, as well as the parties’ motions for summary judgment. While the court agreed with the Utility’s position that the filed rate doctrine applies to the federally-tariffed wholesale costs at which the Utility had purchased electricity, it held that certain triable issues of fact precluded entry of summary judgment in the Utility’s favor.
On August 23, 2002, the CPUC filed an appeal to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Pursuant to the Utility’s request, the District Court certified the appeal as “wholly without merit and, therefore, frivolous,” and rejected the CPUC’s request to stay the proceedings. On November 21,
2002, the Ninth Circuit stayed the District Court’s proceedings pending the CPUC’s appeal. The appeal was fully briefed and the Ninth Circuit heard oral argument on March 10, 2003.
Under the Settlement Agreement, the Utility will dismiss the filed rate case with prejudice on or as soon as practicable after the later of the effective date of the Plan of Reorganization and the date on which CPUC approval of the Settlement Agreement is no longer subject to appeal. Therefore, the Utility filed a motion to stay consideration of the appeal of the filed rate case. On August 11, 2003, the Ninth Circuit issued an order staying proceedings in the filed rate case. The Ninth Circuit has ordered the parties to file a status report by July 30, 2004.
In re: Natural Gas Royalties Qui Tam Litigation
This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (referred to as a relator in the terminology of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including the Utility. The cases were consolidated for pretrial purposes in the U.S. District Court for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.
Under procedures established by the False Claims Act, the United States, acting through the DOJ, is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases.
The complaints allege that the various defendants, most of whom are natural gas pipeline companies or their affiliates, incorrectly measured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases.
The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties and reasonable expenses associated with the litigation. The relator has filed a claim in the Utility’s Chapter 11 case for $2.5 billion, $2.0 billion of which is based upon the relator’s calculation of penalties against the Utility.
The Utility believes the allegations to be without merit and intends to present a vigorous defense. The Utility believes that the ultimate outcome of the litigation will not have a material adverse effect on the Utility’s financial condition or results of operations.
Diablo Canyon Power Plant
The Utility’s Diablo Canyon power plant employs a “once-through” cooling water system, which is regulated under a NPDES permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility’s Diablo Canyon power plant’s discharge was not protective of beneficial uses.
In October 2000, the Utility reached a tentative settlement of this matter with the Central Coast Board pursuant to which the Central Coast Board agreed to find that the Utility’s discharge of cooling water from the Utility’s Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available as defined in the Federal Clean Water Act. As part of the Central Coast settlement agreement, the Utility agreed to take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General’s Office. A condition to the effectiveness of the
settlement agreement is that the Central Coast Board renew Diablo Canyon’s NPDES permit. However, at its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the Central Coast settlement agreement accepted in March 2003, and the Central Coast Board requested its staff to develop additional information on possible mitigation measures.
The California Attorney General has filed a claim in the Utility’s Chapter 11 case on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with the Diablo Canyon power plant’s operation of its cooling water system. The Utility is seeking withdrawal of this claim.
On June 13, 2002, the Utility received a draft enforcement order from the California Department of Toxic Substances Control, or DTSC, alleging that the Utility’s Diablo Canyon power plant failed to maintain an adequate financial assurance mechanism to cover closure costs for its hazardous waste storage facility for several months after the Utility’s Chapter 11 filing in 2001. The draft order sought $340,000 in civil penalties for the period during which the Utility were unable to comply with the DTSC’s requirements. The draft order also directed the Utility to maintain appropriate financial assurance on a going forward basis. On September 4, 2002, the Utility received a draft enforcement order from DTSC alleging a variety of hazardous waste violations at the Utility’s Diablo Canyon power plant. This draft order sought $24,330 in civil penalties.
In April 2003, the Utility signed a final settlement agreement with DTSC, under which the Utility agreed to pay approximately $165,000 in civil penalties and approximately $30,000 in costs. The Utility paid these amounts in May 2003. The California Attorney General filed a claim in the Utility’s Chapter 11 case on behalf of DTSC, and the Utility is currently seeking withdrawal of those portions of the claim relating to financial assurance and hazardous waste matters.
The Utility believes that the ultimate outcome of these matters will not have a material adverse impact on the Utility’s financial condition or results of operations.
Complaints Filed by the California Attorney General, City and County of San Francisco and Cynthia Behr
On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200, or Section 17200. Among other allegations, the California Attorney General alleged that past transfers of money from the Utility to PG&E Corporation, and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation. The California Attorney General also alleged that the December 2000 and January and February 2001 ringfencing transactions, by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings, violated the holding company conditions. (On January 9, 2002, the CPUC issued a decision interpreting the holding company condition regarding capital requirements (which it terms the “first priority condition”) and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies “infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve.” The three major California investor-owned energy utilities and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The three major California investor-owned utilities and their parent holding companies appealed the CPUC’s interpretation of the first priority condition to various state appellate courts. The CPUC moved to consolidate all proceedings in the San Francisco state appellate court. The CPUC’s request for consolidation was granted and all the petitions are now before the California Court of Appeal for the First Appellate District in San Francisco, California. Oral argument is scheduled for March 5, 2004.
The complaint seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, civil penalties of $2,500 against each defendant for each violation of Section 17200, a total penalty of
not less than $500 million and costs of suit. The California Attorney General’s complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. In February 2002, PG&E Corporation filed a notice of removal in the bankruptcy court to transfer the California Attorney General’s complaint to the bankruptcy court, as well as a motion to dismiss the lawsuit, or in the alternative, to stay the suit with the bankruptcy court. Subsequently, the California Attorney General filed a motion to remand the action to state court. In June 2002, the bankruptcy court held that federal law preempted the California Attorney General’s allegations concerning PG&E Corporation’s participation in the Utility’s Chapter 11 proceedings. The bankruptcy court directed the California Attorney General to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties appealed the bankruptcy court’s June 2002 order to the District Court.
On August 9, 2002, the California Attorney General filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation’s participation in the Utility’s Chapter 11 proceedings. PG&E Corporation and the directors named in the complaint have filed motions to strike certain allegations of the amended complaint. On February 28, 2003, the court denied the three motions to strike on the grounds that they were premature and stated that it would defer making a judgment on the merits of the defendants’ arguments until the factual context of the cases was more fully developed.
On February 11, 2002, a complaint entitled City and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the California Attorney General’s complaint, including allegations of unfair competition. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation “took at least $5.2 billion from the Utility,” and for unjust enrichment. The City seeks injunctive relief, the appointment of a receiver, payment to customers, disgorgement, the imposition of a constructive trust, civil penalties and costs of suit.
After removing the City’s action to the bankruptcy court in February 2002, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the bankruptcy court issued an amended order on motion to remand stating that the bankruptcy court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to state court. Both parties appealed the bankruptcy court’s remand order to the District Court.
In addition, a third case, entitled Cynthia Behr v. PG&E Corporation, et al., was filed on February 14, 2002, by a private plaintiff (who also has filed a claim under Chapter 11) in Santa Clara Superior Court also alleging a violation of Section 17200. The Behr complaint also names the directors of PG&E Corporation and the Utility as defendants. The allegations of the complaint are similar to the allegations contained in the California Attorney General’s complaint, but also include allegations of conspiracy, fraudulent transfer and violation of the California bulk sales laws. The plaintiff requests the same remedies as the California Attorney General, and, in addition, requests damages, attachment and restraints upon the transfer of defendants’ property. In March 2002, PG&E Corporation filed a notice of removal in the bankruptcy court to transfer the complaint to the bankruptcy court. Subsequently, the plaintiff filed a motion to remand the action to state court. In its June 2002 ruling mentioned above as to the California Attorney General’s and the City’s cases, the bankruptcy court retained jurisdiction over Behr’s fraudulent transfer claim and bulk sales claim, finding them to belong to the Utility’s estate. The bankruptcy court remanded Behr’s Section 17200 claim to the Santa Clara Superior Court. Both parties appealed the bankruptcy court’s remand order to the District Court.
The San Francisco Superior Court has coordinated the California Attorney General’s case with the cases filed by the City and County of San Francisco and Cynthia Behr.
On July 24, 2003, the District Court heard oral argument on the appeal and cross-appeal of the bankruptcy court’s remand order in the three cases. On October 8, 2003, the District Court reversed, in part, the bankruptcy court’s June 2002 decision and ordered the California Attorney General’s restitution claims sent back to the bankruptcy court. The District Court found that these claims, estimated along with the City and County of San Francisco’s claims at approximately $5 billion, are the property of the Utility’s Chapter 11
estate and therefore are properly within the bankruptcy court’s jurisdiction. Under the Plan of Reorganization, the Utility would release these claims. The District Court also affirmed, in part, the bankruptcy court’s June 2002 decision and found that the California Attorney General’s civil penalty and injunctive relief claims under Section 17200 could be resolved in San Francisco Superior Court, where a status conference has been scheduled for February 24, 2004. The California Attorney General and the City and County of San Francisco have appealed this ruling to the Ninth Circuit. The defendants have filed motions to dismiss the appeals. No proceedings have been scheduled in bankruptcy court regarding the restitution claims. Under Section 17200, the California Attorney General is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. The California Attorney General’s complaint asserted that the total civil penalties would be not less than $500 million. The bankruptcy court’s confirmation order provides that the California Attorney General’s and the City and County of San Francisco’s claims are not released in connection with implementation of the Plan of Reorganization.
The defendants filed a motion to seek clarification from the District Court regarding whether the District Court’s October 2003 order reaches the restitution claims against the director defendants, as distinct from PG&E Corporation. At a hearing in November 2003, the District Court confirmed that its October 2003 order holds that the defendants’ restitution claims against the directors are also the property of the Utility’s estate.
PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.
Compressor Station Chromium Litigation
The following 14 civil suits are pending in several California courts against the Utility relating to alleged chromium contamination: (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed January 30, 2001, in Los Angeles County Superior Court, (7) Fordyce v. Pacific Gas and Electric Company, filed March 16, 2001, in San Bernardino Superior Court, (8) Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (9) Alderson, et al. v. PG&E Corporation, Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April 11, 2001, in Los Angeles County Superior Court, (10) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (11) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (12) Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernardino County Superior Court, (13) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court, and (14) Lytle v. Pacific Gas and Electric Company, filed March 22, 2002, in Yolo County Superior Court.
All of these civil actions are now pending in the Los Angeles Superior Court, except the Lytle case, which is pending in Yolo County. Currently there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals have filed proofs of claim in the Utility’s Chapter 11 case, most of whom are plaintiffs in the chromium litigation. Approximately 1,035 claimants have filed proofs of claim requesting approximately $580 million in damages and another approximately 225 claimants have filed claims for an “unknown amount.”
In general, plaintiffs and claimants allege that exposure to chromium at or near the Utility’s gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona caused personal injuries, wrongful death, or other injury and seek related damages. The bankruptcy court has granted certain claimants’ motion for relief from stay so that the state court lawsuits pending before the Utility’s Chapter 11 filing can proceed.
The Utility is responding to the suits in which the Utility has been served and is asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including the statute of limitations, exclusivity of workers’ compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.
To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from the Aguayo, Acosta and Aguilar cases for a test trial. Plaintiffs’ counsel selected ten of these initial trial plaintiffs,, defense counsel selected seven of the plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 13 summary judgment motions or motions in limine (motions to exclude potentially prejudicial information) challenging the claims of the trial test plaintiffs. Two of these motions are scheduled for hearing in the first quarter of 2004, with the others to be scheduled thereafter. The trial of the test cases is scheduled to begin in March 2004. The Utility’s motion to dismiss the complaint in the Adams case was granted. The plaintiffs in that case have until April 12, 2004 to file an amended complaint.
The Utility has recorded a reserve in the Utility’s financial statements in the amount of $160 million for these matters. The Utility believes that, in light of the reserves that have already been accrued with respect to this matter, the ultimate outcome of this matter will not have a material adverse impact on the Utility’s financial condition or future results of operations.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANTS
“The names, ages and positions of PG&E Corporation executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, or Exchange Act at December 31, 2003 are as follows:
All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.
“The names, ages and position’s of the Utility’s executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at December 31, 2003 are as follows:
All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
PART II
Item 5.
Item 5.
Market for the Registrant’s Common Equity and Related Shareholder Matters.
Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth under the heading “Quarterly Consolidated Financial Data (Unaudited)” in the 2003 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 17, 2004, there were 110,740 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York, Pacific, and Swiss stock exchanges. The discussion of dividends with respect to PG&E Corporation’s common stock is hereby incorporated by reference from “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Financial Resources - Dividend Policy” of the 2003 Annual Report.
On July 2, 2003, PG&E Corporation completed the offer and sale of $600 million of 6 7/8% Senior Secured Notes due 2008 pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act of 1933, or Act. The net proceeds of the offering, approximately $581 million, together with cash on hand, were used to repay the principal balance outstanding under PG&E Corporation’s October 2002 credit agreement of approximately $720 million, plus $15 million of accrued in-kind interest and a $52 million prepayment premium. The payment resulted in the termination of PG&E Corporation’s existing credit agreement and the release of liens on PG&E Corporation’s shares of NEGT. Lehman Brothers acted as principal underwriters. The notes were offered and sold only to “qualified institutional buyers” as defined in Rule 144A under the Act in compliance with Rule 144A under the Act, and in offers and sales that occur outside the U.S. to persons other than U.S. persons, or foreign purchasers, which include dealers or other professional fiduciaries in the U.S. acting on a discretionary basis for foreign beneficial owners, other than an estate or trust, in offshore transactions meeting the requirements of Rule 903 of Regulation S under the Act. For more information, see Note 3 to the “Notes to Consolidated Financial Statements” of PG&E Corporation contained in the 2003 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Pacific Gas and Electric Company did not make any sales of unregistered equity securities during 2003, the period covered by this report.
Item 6.
Item 6.
Selected Financial Data.
A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years, is set forth under the heading “Selected Financial Data” in the 2003 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
A discussion of PG&E Corporation’s and Pacific Gas and Electric Company’s consolidated results of operations and financial condition is set forth on under the heading “Management’s Discussion and Analysis
of Financial Condition and Results of Operations” in the 2003 Annual Report, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
Information responding to Item 7A appears in the 2003 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Risk Management Activities,” and under Notes 1 and 8 of the “Notes to the Consolidated Financial Statements” of the 2003 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
Information responding to Item 8 appears in the 2003 Annual Report under the following headings for PG&E Corporation: “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Common Shareholders’ Equity;” under the following headings for Pacific Gas and Electric Company: “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’ Equity;” and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Independent Auditors’ Report,” and “Responsibility for the Consolidated Financial Statements,” which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Not applicable.
Item 9A.
Item 9A.
Controls and Procedures
Based on an evaluation of PG&E Corporation’s and Pacific Gas and Electric Company’s disclosure controls and procedures as of December 31, 2003, PG&E Corporation’s and Pacific Gas and Electric Company’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and Pacific Gas and Electric Company’s in reports the companies file or submit under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms.
There were no changes in internal controls over financial reporting that occurred during the quarter ended December 31, 2003, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or Pacific Gas and Electric Company’s controls over financial reporting.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant.
Directors
The authorized number of directors of PG&E Corporation currently is 10, and the authorized number of directors of the Utility currently is 11. On February 18, 2004, each Board of Directors approved amendments to the respective company’s bylaws to reduce the authorized number of directors effective upon adjournment of the 2004 Joint Annual Meeting of shareholders. After these amendments become effective, the bylaws will provide that the authorized number of directors of PG&E Corporation will be eight, and the authorized number of directors of Pacific Gas and Electric Company will be nine.
Information is provided below about the directors of PG&E Corporation and the Utility, including their principal occupations for the past five years, certain other directorships, age, and length of service as a director
of PG&E Corporation and the Utility. The directors of PG&E Corporation and the directors of the Utility are the same, except that Gordon R. Smith is a director of the Utility only.
David R. Andrews. Mr. Andrews is Senior Vice President Government Affairs, General Counsel, and Secretary of PepsiCo, Inc. (food and beverage businesses), and has held that position since February 2002. Prior to joining PepsiCo, Inc., Mr. Andrews was a partner in the law firm of McCutchen, Doyle, Brown & Enersen, LLP from May 2000 to January 2002 and from 1981 to July 1997. From August 1997 to April 2000, he served as the legal advisor to the U.S. Department of State and former Secretary Madeleine Albright. Mr. Andrews, 62, has been a director of PG&E Corporation and the Utility since 2000. He also serves as a director of UnionBanCal Corporation.
Leslie S. Biller. Mr. Biller is retired Vice Chairman and Chief Operating Officer of Wells Fargo & Company (financial services and retail banking). He held that position from November 1998 until his retirement in October 2002. Mr. Biller was President and Chief Operating Officer of Norwest Corporation (bank holding company) from 1997 until it merged with Wells Fargo & Company in 1998. Mr. Biller, 55, has been an advisory director of PG&E Corporation and the Utility since January 2003, and was elected a director of PG&E Corporation and the Utility on February 18, 2004. He also serves as a director of Ecolab Inc.
David A. Coulter. Mr. Coulter is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank, responsible for its investment bank, investment management, and private banking., and has held that position since January 2001. Prior to the merger with J.P. Morgan & Co. Incorporated, he was Vice Chairman of The Chase Manhattan Corporation (bank holding company) from August 2000 to December 2000. He was a partner in the Beacon Group, L.P. (investment banking firm) from January 2000 to July 2000, and was Chairman and Chief Executive Officer of BankAmerica Corporation and Bank of America NT&SA from May 1996 to October 1998. Mr. Coulter, 56, has been a director of PG&E Corporation and the Utility since 1996. He also serves as a director of Strayer Education, Inc.
C. Lee Cox. Mr. Cox is retired Vice Chairman of AirTouch Communications, Inc. and retired President and Chief Executive Officer of AirTouch Cellular (cellular telephone and paging services). He was an executive officer of AirTouch Communications, Inc. and its predecessor, PacTel Corporation, from 1987 until his retirement in April 1997. Mr. Cox, 62, has served as a director of PG&E Corporation and the Utility since 1996.
William S. Davila. Mr. Davila is President Emeritus of The Vons Companies, Inc. (retail grocery). He was President of The Vons Companies, Inc. from 1986 until his retirement in May 1992. Mr. Davila, 72, has been a director of the Utility since 1992 and a director of PG&E Corporation since 1996. He also serves as a director of The Home Depot, Inc.
Robert D. Glynn, Jr. Mr. Glynn is Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation and Chairman of the Board of the Utility. He has been an officer of PG&E Corporation since December 1996 and an officer of the Utility since January 1988. Mr. Glynn, 61, has been a director of the Utility since 1995 and a director of PG&E Corporation since 1996.
David M. Lawrence, MD Dr. Lawrence is retired Chairman and Chief Executive Officer of Kaiser Foundation Health Plan, Inc. and Kaiser Foundation Hospitals, and was an executive officer of those companies from 1991 until his retirement in 2002. Dr. Lawrence, 63, has been a director of the Utility since 1995 and a director of PG&E Corporation since 1996. He also serves as a director of Agilent Technologies Inc. and McKesson Corporation.
Mary S. Metz. Dr. Metz is President of S. H. Cowell Foundation, and has held that position since January 1999. Prior to that date, she was Dean of University Extension, University of California, Berkeley from July 1991 to June 1998. Dr. Metz, 66, has been a director of the Utility since 1986 and a director of PG&E Corporation since 1996. She also serves as a director of Longs Drug Stores Corporation, SBC Communications Inc., and UnionBanCal Corporation.
Carl E. Reichardt. Mr. Reichardt served as Vice Chairman of Ford Motor Company from October 2001 to July 2003. He is retired Chairman of the Board and Chief Executive Officer of Wells Fargo &
Company (bank holding company) and Wells Fargo Bank, N.A. He was an executive officer of Wells Fargo Bank from 1978 until his retirement in December 1994. Mr. Reichardt, 72, has been a director of the Utility since 1985 and a director of PG&E Corporation since 1996. He also serves as a director of ConAgra Foods, Inc. and Ford Motor Company.
Gordon R. Smith. Mr. Smith is President and Chief Executive Officer of the Utility, and has been an officer of the Utility since 1980. Mr. Smith, 56, has been a director of the Utility since 1997.
Barry Lawson Williams. Mr. Williams is President of Williams Pacific Ventures, Inc. (business investment and consulting), and has held that position since 1987. He also served as interim President and Chief Executive Officer of the American Management Association (management development organization) from November 2000 to June 2001. Mr. Williams, 59, has been a director of the Utility since 1990 and a director of PG&E Corporation since 1996. He also serves as a director of CH2M Hill Companies, Ltd., The Northwestern Mutual Life Insurance Company, R.H. Donnelley Corporation, The Simpson Manufacturing Company Inc., and SLM Corporation.
Executive Officers
Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included in a separate item captioned “Executive Officers of the Registrants” contained on pages 48 through 50 in Part I of this report.
Section 16 Beneficial Ownership Reporting Compliance
In accordance with Section 16(a) of the Securities Exchange Act of 1934 and Securities and Exchange Commission (SEC) regulations, PG&E Corporation’s and the Utility’s directors and certain officers, and persons who own greater than 10 percent of PG&E Corporation’s or the Utility’s equity securities must file reports of ownership and changes in ownership of such equity securities with the SEC and the principal national securities exchange on which those securities are registered, and must furnish PG&E Corporation or the Utility with copies of all such reports they file.
Based solely on its review of copies of such reports received or written representations from certain reporting persons, PG&E Corporation and the Utility believe that during 2003 all filing requirements applicable to their respective directors, officers, and 10 percent shareholders were satisfied, except that a Statement of Changes of Beneficial Ownership of Securities on Form 4 was filed late for Thomas B. King due to internal corporate administrative delays. No information is reported for individuals during periods in which they were not directors, officers, or 10 percent shareholders of the respective company.
Audit Committee Members and Financial Expert
The members of the Audit Committees for each of PG&E Corporation and the Utility are C. Lee Cox, David R. Andrews, William S. Davila, Mary S. Metz, and Barry Lawson Williams.
The Boards of Directors of PG&E Corporation and the Utility each have determined that both C. Lee Cox and Barry Lawson Williams, members of each company’s Audit Committee, each are “audit committee financial experts” as defined by the SEC regulations, implementing Section 407 of the Sarbanes-Oxley Act of 2002. Each Board of Directors has determined that Mr. Cox and Mr. Williams each are “independent” as defined by current listing standards of the New York Stock Exchange and the American Stock Exchange, as applicable.
Website Availability of Corporate Governance and Other Documents
The following documents are available both on PG&E Corporation’s website www.pgecorp.com, and Pacific Gas and Electric Company’s website, www.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers, and other executive officers, (2) PG&E Corporation’s and Pacific Gas and Electric Company’s corporate
governance guidelines, and (3) key Board Committee charters, including charters for the companies’ Audit Committees and the PG&E Corporation Nominating, Compensation, and Governance Committee. Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, Corporate Secretary of both PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.
If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company that apply to their respective Chief Executive Officers, Chief Financial Officers or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website.
Item 11.
Item 11.
Executive Compensation.
Compensation of Directors
Each director who is not an officer or employee of PG&E Corporation or the Utility receives a quarterly retainer of $7,500 plus a fee of $1,000 for each Board or Board committee meeting attended. Non-employee directors who chair Board committees receive an additional quarterly retainer of $625. Under the Deferred Compensation Plan for Non-Employee Directors, directors of PG&E Corporation or the Utility may elect to defer all or part of such compensation for varying periods. Directors who participate in the Deferred Compensation Plan may convert their deferred compensation into common stock equivalents, the value of which is tied to the market value of PG&E Corporation common stock. Alternatively, participating directors may elect that their deferred compensation be invested in the Utility Bond Fund.
No director who serves on both the PG&E Corporation and Utility Boards and corresponding committees is paid additional compensation for concurrent service on the Utility’s Board or its committees, except that separate meeting fees are paid for each meeting of the Utility Board, or a Utility Board committee, that is not held concurrently or sequentially with a meeting of the PG&E Corporation Board or a corresponding PG&E Corporation Board committee. It is the usual practice of PG&E Corporation and the Utility that meetings of the respective Boards and corresponding committees are held concurrently and, therefore, that a single meeting fee is paid to each director for each set of meetings.
Directors of PG&E Corporation or the Utility are reimbursed for reasonable expenses incurred for participating in Board meetings, committee meetings, or other activities undertaken on behalf of PG&E Corporation or the Utility.
Effective January 1, 1998, the PG&E Corporation Retirement Plan for Non-Employee Directors was terminated. Directors who had accrued benefits under the Plan were given a one-time option of receiving at retirement the benefit accrued through 1997, or of converting the present value of their accrued benefit into a PG&E Corporation common stock equivalent investment held in the Deferred Compensation Plan for Non-Employee Directors. The payment of frozen accrued retirement benefits, or distributions from the Deferred Compensation Plan attributable to the conversion of retirement benefits, cannot be made until the later of age 65 or retirement from the Board.
Under the Non-Employee Director Stock Incentive Plan, which is a component of the PG&E Corporation Long-Term Incentive Program, on the first business day of January of each year, each non-employee director of PG&E Corporation is entitled to receive stock-based grants with a total aggregate equity value of $30,000, composed of (1) restricted shares of PG&E Corporation common stock valued at $10,000 (based on the closing price of PG&E Corporation common stock on the first business day of the year), and (2) a combination, as elected by the director, of non-qualified stock options and common stock equivalents with a total equity value of $20,000, based on equity value increments of $5,000. The exercise price of stock options is equal to the market value of PG&E Corporation common stock (i.e., the closing price) on the date of grant. Restricted stock and stock options vest over the five-year period following the date of grant, except that restricted stock and stock options will vest immediately upon mandatory retirement from the Board, upon a director’s death or disability, or in the event of a change in control. Common stock equivalents awarded to non-employee directors are payable only in the form of PG&E Corporation common stock following a
director’s retirement from the Board, upon a director’s death or disability, or in the event of a change in control. Unvested awards are forfeited if the recipient ceases to be a director for any other reason.
On January 2, 2003, each non-employee director received 684 restricted shares of PG&E Corporation common stock. In addition, directors who were granted stock options received options to purchase 1,101 shares of PG&E Corporation common stock for each $5,000 increment of equity value (subject to the aggregate $20,000 limit) at an exercise price of $14.61 per share, and directors who were granted common stock equivalents received 342 common stock equivalent units for each $5,000 increment of equity value (subject to the aggregate $20,000 limit).
Summary Compensation Table
This table summarizes the principal components of compensation paid to the Chief Executive Officers and the other most highly compensated executive officers of PG&E Corporation and the Utility during the past year.
(1)
Represents payments received or deferred in 2003 and 2002 for achievement of corporate and organizational objectives in 2002 and 2001, respectively, under the Short-Term Incentive Plan. No decision has been made with respect to the 2003 Short-Term Incentive Plan.
(2)
Amounts reported consist of (i) reportable officer perquisite allowances and, for 2002 and 2003, amounts for non-business related travel (Mr. Glynn $35,000 and $62,998, respectively), (ii) payments of related taxes, and (iii) for 2002 and 2003, the cost of annuities to replace existing retirement benefits, at the time they are due under the Supplemental Executive Retirement Plan (SERP). The annuities will not change the after-tax benefits that would have been provided upon retirement under the existing arrangements. The cost of the annuity and associated tax restoration payments during 2003 for retirement obligations as of December 31, 2002, are: Mr. Glynn $3,048,972, Mr. Worthington $833,927, Mr. Smith $2,402,048, Mr. Rueger $642,860, and Mr. Randolph $669,741.
(3)
As of the end of the year, the aggregate number of shares or units of restricted stock held by each named executive officer, and the value using the year-end closing price of a share of PG&E Corporation common stock, were: Mr. Glynn 148,525 (with a value of $4,124,539), Mr. Darbee 46,425 (with a value of $1,289,222), Mr. Worthington 36,325 (with a value of $1,008,745), Mr. Stanley 24,225 (with a value of $672,728), Mr. Iribe 32,300 (with a value of $896,971), Mr. Smith 64,575 (with a value of $1,793,248), Mr. King 36,325 (with a value of $1,008,745), Mr. Rueger 18,650 (with a value of $517,911), Mr. Harvey 18,650 (with a value of $517,911), Mr. Peters 18,650 (with a value of $517,911), and Mr. Randolph 18,175 (with a value of $504,720). The restrictions lapse in annual increments of up to 25 percent on the first business day of 2004, 2005, 2006, and 2007, subject to the recipient’s continued employment. In general, 20 percent of each year’s increment is subject to forfeiture if PG&E Corporation fails to be in the top quartile of the comparator group as measured by relative annual total shareholder return at the end of the prior year. With respect to the Chairman, Chief Executive Officer, and President of PG&E Corporation, 25 percent of each year’s increment is subject to forfeiture if PG&E Corporation fails to be in the top quartile of the comparator group as measured by total shareholder return at the end of the prior year, and an additional 25 percent is subject to forfeiture if PG&E Corporation fails to be in the top half of the comparator group. The shares of restricted stock have the same dividend rights as unrestricted shares of PG&E Corporation common stock.
(4)
Represents (i) payments received or deferred in 2004, 2003, and 2002 for achievement of corporate performance objectives for the periods 2001 through 2003, 2000 through 2002, and 1999 through 2001,
respectively, under the Performance Unit Plan (Mr. Glynn $1,292,837, Mr. Darbee $669,876, Mr. Worthington $522,915, Mr. Stanley $325,427, Mr. Iribe $533,063, Mr. Smith $799,143, Mr. King $533,063, Mr. Rueger $234,201, Mr. Harvey $228,463, Mr. Peters $228,463, and Mr. Randolph $228,463), (ii) common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned by executive officers under the Executive Stock Ownership Program and vested during 2003, and additional common stock equivalents reflecting dividends accrued on those SISOPs as follows: Mr. Glynn 2,948 (with a value of $42,453), Mr. Darbee 10,346 (with a value of $148,981), Mr. Worthington 533 (with a value $7,672), Mr. Stanley 2,474 (with a value of $35,623), Mr. Iribe 6,430 (with a value of $92,591), Mr. Smith 4,096 (with a value of $58,989), and Mr. King 910 (with a value of $13,111), and (iii) amounts representing one-half of the phantom restricted stock units granted in 2001 under the Senior Executive Retention Program that were subject to a performance measure (Mr. Glynn 307,692.5 units with a value of $8,544,621, Mr. Darbee 115,385 units with a value of $3,204,241, Mr. Worthington 64,102.5 units with a value of $1,780,126, Mr. Stanley 64,102.5 units with a value of $1,780,126, Mr. Iribe 86,142.5 units with a value of $2,392,177, Mr. Smith 179,487.5 units with a value of $4,984,368, Mr. King 86,142.5 units with a value of $2,392,177, Mr. Rueger 47,857.5 units with a value of $1,329,003, Mr. Harvey 47,857.5 units with a value of $1,329,003, Mr. Peters 47,857.5 units with a value of $1,329,003, and Mr. Randolph 47,857.5 units with a value of $1,329,003). The value of all phantom restricted units granted under the Senior Executive Retention Program is based solely on the closing price of PG&E Corporation common stock on the date that the units vested, December 31, 2003. As previously reported, the total number of phantom restricted stock units granted under the Program and their value as of their vesting date of December 31, 2003, inclusive of the performance-based units described above, were: Mr. Glynn 615,385 units with a value of $17,089,241, Mr. Darbee 230,770 units with a value of $6,408,483, Mr. Worthington 128,205 units with a value of $3,560,253, Mr. Stanley 128,205 units with a value of $3,560,253, Mr. Iribe 172,285 units with a value of $4,784,354, Mr. Smith 358,975 units with a value of $9,968,736, Mr. King 172,285 units with a value of $4,784,354, Mr. Rueger 95,715 units with a value of $2,658,006, Mr. Harvey 95,715 units with a value of $2,658,006, Mr. Peters 95,715 units with a value of $2,658,006, and Mr. Randolph 95,715 units with a value of $2,658,006.
(5)
Amounts reported for 2003 consist of: (i) contributions to defined contribution retirement plans (Mr. Glynn $9,000, Mr. Darbee $16,125, Mr. Worthington $3,953, Mr. Stanley $3,853, Mr. Iribe $20,000, Mr. Smith $9,000, Mr. King $20,000, Mr. Rueger $9,000, Mr. Harvey $9,000, Mr. Peters $9,000, and Mr. Randolph $9,000), (ii) contributions received or deferred under excess benefit arrangements associated with defined contribution retirement plans (Mr. Glynn $38,250, Mr. Darbee $5,925, Mr. Worthington $15,172, Mr. Stanley $9,872, Mr. Iribe $25,000, Mr. Smith $24,075, Mr. King $2,500, Mr. Rueger $7,110, Mr. Harvey $4,590, Mr. Peters $4,590, and Mr. Randolph $6,165), (iii) above-market interest on deferred compensation (Mr. Glynn $18,800, Mr. Darbee $3,757, Mr. Worthington $350, Mr. Stanley $1,057, Mr. Iribe $203, Mr. Smith $648, Mr. King $1,285, Mr. Rueger $548, Mr. Harvey $306, Mr. Peters $331, and Mr. Randolph $167), (iv) relocation allowances and other one-time payments, Mr. King $374,645, (v) sale of vacation (Mr. Worthington $20,433, Mr. Iribe $69,231, Mr. King $36,058, Mr. Harvey $5,807, Mr. Peters $581, and Mr. Randolph $1,944), and (vi) amounts received pursuant to management retention programs (Mr. Glynn $600,000, Mr. Darbee $303,333, Mr. Worthington $266,667, Mr. Stanley $190,000, Mr. Iribe $37,500, Mr. Smith $420,000, Mr. King $225,000, Mr. Rueger $226,667, Mr. Harvey $190,000, Mr. Peters $190,000, and Mr. Randolph $216,667).
Option/SAR Grants in 2003
This table summarizes the distribution and the terms and conditions of stock options granted to the executive officers named in the Summary Compensation Table during the past year.
(1)
All options granted to executive officers in 2003 are exercisable as follows: 25 percent of the options may be exercised on or after the first anniversary of the date of grant, 50 percent on or after the second anniversary, 75 percent on or after the third anniversary, and 100 percent on or after the fourth anniversary, provided that options will vest immediately upon the occurrence of certain events. No options were accompanied by tandem dividend equivalents.
(2)
No stock appreciation rights (SARs) have been granted since 1991.
(3)
The exercise price is equal to the closing price of PG&E Corporation common stock on the date of grant.
(4)
All options granted to executive officers in 2003 expire ten years and one day from the date of grant, subject to earlier expiration in the event of the officer’s termination of employment with PG&E Corporation, the Utility, or one of their respective subsidiaries.
(5)
Estimated present values are based on the Black-Scholes Model, a mathematical formula used to value options traded on stock exchanges. The Black-Scholes Model considers a number of factors, including the expected volatility and dividend rate of the stock, interest rates, and time of exercise of the option. The following assumptions were used in applying the Black-Scholes Model to the 2003 option grant shown in the table above: volatility of 45.0 percent, risk-free rate of return of 3.94 percent, dividend yield of $0.00 (the annual dividend rate on the grant date), and an exercise date ten years after the date of grant. The ultimate value of the options will depend on the future market price of PG&E Corporation common stock, which cannot be forecast with reasonable accuracy. That value will depend on the future success achieved by employees for the benefit of all shareholders. The estimated grant date present value for the options shown in the table was $5.68 per share.
Aggregated Option/SAR Exercises in 2003 and Year-End Option/SAR Values
This table summarizes exercises of stock options and tandem stock appreciation rights (granted in prior years) by the executive officers named in the Summary Compensation Table during the past year, as well as the number and value of all unexercised options held by such named executive officers at the end of 2003.
(1)
Based on the difference between the option exercise price (without reduction for the amount of accrued dividend equivalents, if any) and a fair market value of $27.77, which was the closing price of PG&E Corporation common stock on December 31, 2003.
(2)
The options exercised would have expired on January 4, 2004. After accounting for accrued dividend equivalents, Mr. Peters realized $8,240 and Mr. Randolph realized $16,830.
Long-Term Incentive Program - Awards in 2003
This table summarizes the long-term incentive grants made to the executive officers named in the Summary Compensation Table during the past year.
(1)
Represents common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned under the Executive Stock Ownership Program. SISOPs are earned by eligible officers who achieve and maintain minimum PG&E Corporation common stock ownership levels as set by the Nominating, Compensation, and Governance Committee. All of the officers named in the Summary Compensation Table are eligible officers. Each SISOP represents a share of PG&E Corporation common stock that vests at the end of three years. Units can be forfeited prior to vesting if an eligible officer fails to maintain his or her minimum stock ownership level. Upon retirement or termination, vested SISOPs are distributed in the form of an equivalent number of shares of PG&E Corporation common stock.
Retirement Benefits
PG&E Corporation and the Utility provide retirement benefits to some of the executive officers named in the Summary Compensation Table. The benefit formula for eligible executive officers is 1.7 percent of the average of the three highest combined salary and annual Short-Term Incentive Plan payments during the last ten years of service multiplied by years of credited service. During 2002 and 2003, annuities were purchased to replace a significant portion of the unfunded retirement benefits for certain officers whose entire accrued benefit could not be provided under the Retirement Plan due to tax code limits. The annuities will not change the amount or timing of the after-tax benefits that would have been provided upon retirement under the Supplemental Executive Retirement Plan (SERP) or similar arrangements. In connection with the annuities, tax restoration payments were made such that the annuitization was tax-neutral to the executive officer. Effective July 1, 2003, Mr. Darbee and Mr. King became participants in the SERP with five years of credited service. Mr. Darbee and Mr. King will each earn an additional five years of credited service provided that they are employed by PG&E Corporation or a subsidiary on July 1, 2008. As of December 31, 2003, the estimated pre-tax annual retirement benefits payable under the SERP or similar arrangements (assuming credited service to age 65), adjusted to reflect the effect of the annuities, for the most highly compensated executive officers were as follows: Mr. Glynn $309,602, Mr. Darbee $286,570, Mr. Worthington $285,740, Mr. Stanley $117,610, Mr. Smith $430,326, Mr. King $421,200, Mr. Rueger $287,450, Mr. Harvey $330,436, Mr. Peters $306,808, and Mr. Randolph $220,617. The estimated annual retirement benefits are single life annuity benefits and would not be subject to any Social Security offsets.
Termination of Employment and Change in Control Provisions
The PG&E Corporation Officer Severance Policy, which covers most officers of PG&E Corporation and its subsidiaries, including the executive officers named in the Summary Compensation Table, provides benefits if a covered officer is terminated without cause. In most situations, benefits under the policy include (1) a lump sum payment of one and one-half or two times annual base salary and Short-Term Incentive Plan target (the applicable severance multiple being dependent on an officer’s level), (2) continued vesting of equity-based incentives for 18 months or two years after termination (depending on the applicable severance multiple), (3) accelerated vesting of up to two-thirds of the common stock equivalents granted under the Executive Stock Ownership Program (depending on an officer’s level), and (4) payment of health care insurance premiums for 18 months or two years after termination (depending on the applicable severance multiple). In lieu of all or a portion of the lump sum payment, a terminated officer who is covered by PG&E Corporation’s Supplemental Executive Retirement Plan can elect additional years of service and/or age for purposes of calculating pension benefits. Effective July 21, 1999, the policy was amended to provide covered officers with alternative benefits that apply upon actual or constructive termination following a change in control or potential change in control. For these purposes, “change in control” has the same definition as under the Long-Term Incentive Program (see below). Constructive termination includes certain changes to a covered officer’s responsibilities. In the event of a change in control or potential change in control, the policy provides for a lump sum payment of the total of (1) unpaid base salary earned through the termination date, (2) Short-Term Incentive Plan target calculated for the fiscal year in which termination occurs (Target Bonus), (3) any accrued but unpaid vacation pay, and (4) three times the sum of Target Bonus and the officer’s annual base salary in effect immediately before either the date of termination or the change in control, whichever base salary is greater. Change in control termination benefits also include reimbursement of excise taxes levied upon the severance benefit pursuant to Internal Revenue Code Section 4999.
The Long-Term Incentive Program (LTIP) permits the grant of various types of stock-based incentives, including performance shares, stock options, restricted stock, performance units, and incentives granted under the Non-Employee Director Stock Incentive Plan. The LTIP and the component plans provide that, upon the occurrence of a change in control, (1) any time periods relating to the exercise or realization of any incentive (including common stock equivalents granted under the Executive Stock Ownership Program) will be accelerated so that such incentive may be exercised or realized in full immediately upon the change in control, (2) all shares of restricted stock will immediately cease to be forfeitable, and (3) all conditions relating to the realization of any stock-based incentive will terminate immediately. Under the LTIP, a “change in control”
will be deemed to have occurred if any of the following occurs: (1) any “person” (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, but excluding any benefit plan for employees or any trustee, agent, or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of PG&E Corporation representing 20 percent or more of the combined voting power of PG&E Corporation’s then outstanding securities, (2) during any two consecutive years, individuals who at the beginning of such a period constitute the Board of Directors cease for any reason to constitute at least a majority of the Board of Directors, unless the election, or the nomination for election by the shareholders of the Corporation, of each new director was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of the period, or (3) the shareholders of the Corporation shall have approved (i) any consolidation or merger of the Corporation other than a merger or consolidation that would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the combined voting power of the Corporation, such surviving entity, or the parent of such surviving entity outstanding immediately after the merger or consolidation, (ii) any sale, lease, exchange, or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation, or (iii) any plan or proposal for the liquidation or dissolution of the Corporation. For purposes of this definition, the term “combined voting power” means the combined voting power of the then outstanding voting securities of the Corporation or the other relevant entity.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management.
Security Ownership of Management
The following table sets forth the number of shares of PG&E Corporation common stock beneficially owned (as defined in the rules of the Securities and Exchange Commission) as of January 31, 2004, by the respective directors of PG&E Corporation and the Utility, the executive officers of PG&E Corporation and the Utility named in the Summary Compensation Table, and all directors and executive officers of PG&E Corporation and the Utility as a group. As of January 31, 2004, no director, nominee for director, or executive officer owned shares of any class of the Utility’s securities. The table also sets forth common stock equivalents credited to the accounts of directors and executive officers under PG&E Corporation’s deferred compensation and equity plans.
*
Less than 1 percent
(1)
Includes any shares held in the name of the spouse, minor children, or other relatives sharing the home of the director or executive officer and, in the case of executive officers, includes shares of PG&E Corporation common stock held in the defined contribution retirement plans maintained by PG&E Corporation, Pacific Gas and Electric Company, and their respective subsidiaries. Except as otherwise indicated below, the directors, nominees for director, and executive officers have sole voting and investment power over the shares shown. Voting power includes the power to direct the voting of the shares held, and investment power includes the power to direct the disposition of the shares held.
Also includes the following shares of PG&E Corporation common stock in which the beneficial owners share voting and investment power: Mr. Andrews 2,076 shares, Mr. Biller 1,051 shares, Mr. Coulter 5,681 shares, Mr. Cox 24,192 shares, Mr. Davila 200 shares, Dr. Lawrence 15,676 shares, Dr. Metz 7,681 shares, Mr. Smith 3,884 shares, Mr. Darbee 69,818, Mr. Worthington 2,288 shares, Mr. Rueger 13,987 shares, Mr. Peters 184 shares, all PG&E Corporation directors and executive officers as a group 132,547 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 74,612 shares.
(2)
Includes shares of PG&E Corporation common stock which the directors and executive officers have the right to acquire within 60 days of January 31, 2004, through the exercise of vested stock options granted under the PG&E Corporation Long-Term Incentive Program, as follows: Mr. Andrews 1,978 shares, Mr. Cox 23,015 shares, Mr. Glynn 1,713,325 shares, Dr. Lawrence 23,015 shares, Dr. Metz 14,368 shares, Mr. Reichardt 20,141 shares, Mr. Smith 702,392 shares, Mr. Williams 16,254 shares, Mr. Darbee 353,159 shares, Mr. Iribe 404,601 shares, Mr. Stanley 263,626 shares, Mr. Worthington 374,701 shares, Mr. King 385,726 shares, Mr. Rueger 178,506 shares, Mr. Harvey 97,300 shares, Mr. Peters 226,376 shares, Mr. Randolph 231,258 shares, all PG&E Corporation directors and executive officers as a group 3,845,092 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 3,589,855 shares. The directors and executive officers have neither voting power nor investment power with respect to shares shown unless and until such shares are purchased through the exercise of the options, pursuant to the terms of the PG&E Corporation Long-Term Incentive Program.
(3)
Includes restricted shares of PG&E Corporation common stock awarded under the PG&E Corporation Long-Term Incentive Program. As of January 31, 2004, directors and executive officers of PG&E Corporation and Pacific Gas and Electric Company held the following numbers of restricted shares that may not be sold or otherwise transferred until certain vesting conditions are satisfied: Mr. Andrews 2,076 shares, Mr. Biller 1,051 shares, Mr. Coulter 3,703 shares, Mr. Cox 3,703 shares, Mr. Davila 4,056 shares, Mr. Glynn 163,393 shares, Dr. Lawrence 4,056 shares, Dr. Metz 4,056 shares, Mr. Reichardt 4,056 shares, Mr. Smith 70,321 shares, Mr. Williams 4,056 shares, Mr. Darbee 48,498 shares, Mr. Iribe 24,225 shares, Mr. Stanley 25,008 shares, Mr. Worthington 39,553 shares, Mr. King 39,553 shares, Mr. Rueger 18,777 shares, Mr. Harvey 19,797 shares, Mr. Peters 19,797 shares, Mr. Randolph 13,631 shares, all PG&E Corporation directors and executive officers as a group 417,498 shares, and all Pacific Gas and Electric Company directors and executive officers as a group 381,892 shares.
(4)
The percent of class calculation is based on the number of shares of PG&E Corporation common stock outstanding as of January 31, 2004, excluding shares held by a subsidiary.
(5)
Reflects the number of stock units purchased by directors and executive officers through salary and other compensation deferrals or awarded under equity compensation plans. The value of each stock unit is equal to the value of a share of PG&E Corporation common stock and fluctuates daily based on the market price of PG&E Corporation common stock. The directors and officers who own these stock units share the same market risk as PG&E Corporation shareholders, although they do not have voting rights with respect to these stock units.
(6)
Mr. Andrews, Mr. Biller, Mr. Coulter, Mr. Cox, Mr. Davila, Dr. Lawrence, Dr. Metz, Mr. Reichardt, and Mr. Williams are directors of both PG&E Corporation and Pacific Gas and Electric Company.
(7)
Mr. Glynn is a director and executive officer of PG&E Corporation, and also is a director of Pacific Gas and Electric Company. He is named in the Summary Compensation Table.
(8)
Mr. Smith is a director and an executive officer of Pacific Gas and Electric Company, and also is an executive officer of PG&E Corporation. He is named in the Summary Compensation Table.
(9)
Mr. Darbee, Mr. Iribe, Mr. Stanley, and Mr. Worthington are executive officers of PG&E Corporation named in the Summary Compensation Table.
(10)
Mr. Harvey, Mr. King, Mr. Peters, and Mr. Rueger are executive officers of Pacific Gas and Electric Company named in the Summary Compensation Table.
(11)
Mr. Randolph retired as an executive officer of Pacific Gas and Electric Company in 2003. He is named in the Summary Compensation Table.
Principal Shareholders
The following table presents certain information regarding shareholders that PG&E Corporation and the Utility know are the beneficial owners of more than 5 percent of any class of voting securities of PG&E Corporation or the Utility as of January 31, 2004:
(1)
Pacific Gas and Electric Company’s common stock and preferred stock vote together as a single class. Each share is entitled to one vote.
(2)
As a result of the formation of the holding company on January 1, 1997, PG&E Corporation became the holder of all issued and outstanding shares of Pacific Gas and Electric Company common stock. As of January 31, 2004, PG&E Corporation and a subsidiary held 100 percent of the issued and outstanding shares of Pacific Gas and Electric Company common stock, and neither PG&E Corporation nor any of its subsidiaries held shares of Pacific Gas and Electric Company preferred stock.
(3)
The information relating to State Street Bank and Trust Company is based on beneficial ownership as of December 31, 2003, as reported in a Schedule 13G, dated February 5, 2004, filed with the Securities and Exchange Commission. The bank held 19,204,598 shares in its capacity as Trustee of the Pacific Gas and Electric Company Savings Fund Plan. The Trustee may not vote these shares in the absence of voting instructions from the Plan participants. The bank also held 12,422,008 shares of PG&E Corporation common stock in various other fiduciary capacities. The bank has sole voting power with respect to 11,500,089 of these shares, shared voting power with respect to 13,495 of these shares, sole investment
power with respect to 12,386,522 of these shares, and shared investment power with respect to 31,486 of these shares.
Equity Compensation Plan Information
The following table provides information as of December 31, 2003, concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation’s existing equity compensation plans.
(1)
Represents the total number of shares available for issuance under PG&E Corporation’s Long-Term Incentive Program (LTIP) as of December 31, 2003. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock, performance shares, and phantom stock payable in an equal number of shares upon termination of employment or service as a director. No more than 5,000,000 of the reserved shares under the LTIP may be awarded as restricted stock. For a description of the LTIP, see Note 14 to the Consolidated Financial Statements.
Item 13.
Item 13. Certain Relationships and Related Transactions.
Not applicable.
Item 14.
Item 14. Principal Accountant Fees and Services
Fees Paid to Independent Public Accountants
The Audit Committees have reviewed the audit and non-audit fees that PG&E Corporation, Pacific Gas and Electric Company, and their respective subsidiaries have paid to the independent public accountants for purposes of considering whether such fees are compatible with maintaining the auditor’s independence.
Audit Fees. Estimated fees billed for services rendered by Deloitte & Touche LLP for the reviews of Forms 10-Q and for the audits of the financial statements of PG&E Corporation and its subsidiaries were $9.8 million for 2002 and $6.5 million for 2003. These amounts include fees for stand-alone audits of various subsidiaries, including estimated fees of $4.4 million for 2002 and $2.8 million for 2003 for Pacific Gas and Electric Company and its subsidiaries.
Audit-Related Fees. Aggregate fees billed for all audit-related services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consisted of $0.9 million of fees in 2002 and $0.7 million of fees for 2003. These amounts include $206,000 of audit-related fees in 2002 and $351,000 of audit-related fees in 2003 for Pacific Gas and Electric Company and its subsidiaries. Specific services for both PG&E Corporation and its subsidiaries and Pacific Gas and Electric Company and its subsidiaries in both years include employee benefit plan audits, consultations on financial accounting and reporting standards, a required transition property procedures report, and nuclear decommissioning trust audits. Amounts in 2003 also include Sarbanes-Oxley Section 404 readiness work.
Tax Fees. Aggregate fees billed for permissible tax services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consisted of $2.2 million of fees during 2002 and $1.1 million of fees during 2003. These amounts for 2002 include $4,000 for Pacific Gas and Electric Company and its subsidiaries. Specific services in both years include services to support IRS audit appeals and questions, tax
strategy services, and review of tax returns. Amounts in 2002 also include a review of a private letter ruling request.
All Other Fees. Aggregate fees billed for all other services rendered by Deloitte & Touche LLP to PG&E Corporation and its subsidiaries consisted of $1.1 million in 2002. These services were consulting services for the implementation of risk management software. None of these services were for Pacific Gas and Electric Company. No such services were rendered in 2003.
Pre-Approval of Services Provided by the Independent Public Accountant
As of June 2002, PG&E Corporation and its controlled subsidiaries have entered into new engagements with Deloitte & Touche LLP and its affiliate, Deloitte Consulting, only for audit services, audit-related services, or tax services, which Deloitte & Touche LLP and its affiliates may provide to Deloitte & Touche LLP’s audit clients under the Sarbanes-Oxley Act of 2002. PG&E Corporation and its subsidiaries traditionally have obtained these types of services from its independent public accountants.
Since November 2002, the Audit Committees have been responsible for pre-approving all audit and non-audit services provided by Deloitte & Touche LLP to PG&E Corporation, Pacific Gas and Electric Company, or their controlled subsidiaries, pursuant to Committee pre-approval procedures that are reviewed and amended from time to time. At the beginning of each fiscal year, the PG&E Corporation and Pacific Gas and Electric Company Audit Committees approve the selection of the independent public accountants for that fiscal year, and approve obtaining from the auditors a detailed list of (1) audit services, (2) audit-related services, and (3) tax services, up to specified fee amounts. “Audit services” generally includes audit and review of annual and quarterly financial statements and services that only the external auditors reasonably can provide (e.g., comfort letters, statutory audits, attest services, consents, and assistance with and review of documents filed with the Securities and Exchange Commission). “Audit-related services” generally include assurance and related services that traditionally are performed by the independent public accountants (e.g., employee benefit plan audits, due diligence related to mergers and acquisitions, accounting consultations and audits in connection with acquisitions, internal control reviews, and attest services that are not required by statute or regulation). “Tax services” generally includes compliance, tax strategy, tax appeals, and specialized tax issues, all of which also must be permissible under the Sarbanes-Oxley Act of 2002. In determining whether to pre-approve any services from the independent public accountants, the Audit Committees assess, among other things, the impact of that service on the auditor’s independence.
Following the initial annual pre-approval, the Audit Committees must pre-approve any proposed engagement of the independent public accountants for any audit, audit-related, and tax services that are not included on the list of pre-approved services, and must pre-approve any listed pre-approved services that would cause PG&E Corporation or Pacific and Electric Company to exceed the authorized fee amounts. Other services may be obtained from the independent public accountants only following review and approval from the applicable company’s management and review and pre-approval by the applicable Audit Committee.
Each Audit Committee has delegated to one or more members of the Committee the authority to pre-approve audit and non-audit services provided by the respective company’s independent public accountants. Any pre-approvals granted pursuant to this authority must be presented to the full Audit Committee at the next regularly scheduled Committee meeting. No such pre-approvals were granted for 2003.
At each regular meeting of the Audit Committees, management reports the specific non-audit services being performed by Deloitte & Touche LLP for the respective company and its subsidiaries, the dollar amounts associated with these services, and a comparison of fees paid to date to the pre-approved amounts.
During 2003, all services provided by Deloitte & Touche LLP to PG&E Corporation, Pacific Gas and Electric Company, and their consolidated affiliates were approved pursuant to the applicable pre-approval procedures.
Item 15.
Item 15. 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, supplemental information, and independent auditors’ report are contained in the 2003 Annual Report, which have been incorporated by reference in this report:
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002, and 2001, for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2003, and 2002 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Common Shareholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001, for PG&E Corporation.
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2003, 2002, and 2001 for Pacific Gas and Electric Company.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Independent Auditors’ Report (Deloitte & Touche LLP).
2.
Independent Auditors’ Report (Deloitte & Touche LLP) included at page 77 of this Form 10-K.
3.
Financial statement schedules:
I - Condensed Financial Information of Parent as of December 31, 2003 and 2002 and for the Years Ended December 31, 2003, 2002, and 2001.
II - Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2003, 2002, and 2001.
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.
4.
Exhibits required to be filed by Item 601 of Regulation S-K:
*
Management contract or compensatory agreement.
**
Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
(b) The following Current Reports on Form 8-K(1) were filed, or furnished as indicated, during the quarter ended December 31, 2003, and through the date hereof:
1.
October 3, 2003
Item 9.
Regulation FD Disclosure (furnished to the SEC)
Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended August 31, 2003 and Balance Sheet dated August 31, 2003
2.
October 15, 2003
Item 5.
Other Events
District Court ruling regarding California Business and Professions Code Section 17200 lawsuits
Item 9.
Regulation FD Disclosure (furnished to the SEC)
Exhibit 1 - Revised Financial Projections Relating to the Settlement Plan
3.
October 24, 2003
Item 5.
Other Events
A. Credit Rating Change
B. Department of Water Resources’ (DWR) 2001-2002 Revenue Requirement True-Up Proceeding
4.
November 12, 2003
Item 12.
Results of Operations and Financial Condition (furnished to the SEC)
Release of Third Quarter Earnings Results
5.
November 20, 2003
Item 5.
Other Events
A. Proposed Decisions Regarding Proposed Settlement Agreement
B. Conclusion of Confirmation Trial Testimony in Utility’s Chapter 11 Proceeding
C. Ninth Circuit Preemption Decision
6.
December 2, 2003
Item 9.
Regulation FD Disclosure (furnished to the SEC)
Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended October 31, 2003 and Balance Sheet dated October 31, 2003
7.
December 9, 2003
Item 5.
Other Events
A. Additional Proposed Decisions Regarding Proposed Settlement Agreement
B. Credit Rating Agency Announcement
8.
December 12, 2003
Item 5.
Other Events
Proposed Decision Issued in the California Department of Water Resources” (DWR) 2001-2002 Revenue Requirement True-Up Proceeding and the DWR 2004 Revenue Requirement Proceeding
9.
December 15, 2003
Item 5.
Other Events
Bankruptcy Court Decision Approving Proposed Chapter 11 Settlement Agreement and Plan of Reorganization
10.
December 16, 2003
Item 5.
Other Events
Comments Regarding Proposed Settlement Agreement Filed by the Utility and TURN
11.
December 22, 2003
Item 5.
Other Events
A. California Public Utilities Commission Approves Proposed Settlement Agreement as Recommended to be Modified by Pacific Gas and Electric Company and The Utility Reform Network
B. CPUC Approves Gas Accord II
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 - Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices
12.
December 23, 2003
Item 5.
Other Events
Bankruptcy Court Confirms Utility’s Plan of Reorganization
13.
December 31, 2003
Item 9.
Regulation FD Disclosure (furnished to the SEC) Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended November 30, 2003 and Balance Sheet dated November 30, 2003
14.
January 22, 2004
Item 5.
Other Events
Applications Filed for Rehearing of CPUC Decision Approving Chapter 11 Settlement Agreement
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 - Notice to Directors and Executive Officers, dated January 22, 2004
Item 11.
Temporary Suspension of Trading Under Registrant’s Employee Benefits Plan
15.
February 3, 2004
Item 5.
Other Events
Implementation of Chapter 11 Settlement Rate Reduction
16.
February 19, 2004
Item 5.
Other Events
Item 7.
Financial Statements, Pro Forma Financial Information, and Exhibits Exhibit 99 - Amendment to Rights Agreement dated February 18, 2004, between PG&E Corporation and Mellon Investor Services LLC
Item 12.
Results of Operations and Financial Condition (furnished to the SEC)
Release of Third Quarter Earnings Results
(1)
Unless otherwise noted, all reports were filed under Commission File Number 1-2348 (Pacific Gas and Electric Company) and Commission File Number 1-12609 (PG&E Corporation).
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 2003 to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 19th day of February, 2004.
PG&E CORPORATION
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
(Registrant)
By
By
GARY P. ENCINAS
GARY P. ENCINAS
(Gary P. Encinas, Attorney-in-Fact)
(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 registrants and in the capacities and on the dates indicated.
*By
GARY P. ENCINAS
(Gary P. Encinas, Attorney-in-Fact)
INDEPENDENT AUDITORS’ REPORT
To the Shareholders and the Boards of Directors of
PG&E Corporation and Pacific Gas and Electric Company
We have audited the consolidated financial statements of PG&E Corporation and subsidiaries and of Pacific Gas and Electric Company (a Debtor-in-Possession) and subsidiaries (collectively, the “Companies”) as of December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003 and have issued our report thereon dated February 18, 2004 (which report expresses an unqualified opinion and includes explanatory paragraphs relating to accounting changes, a revision to the 2002 and 2001 financial statements of PG&E Corporation and going concern uncertainties). Such consolidated financial statements of each of the Companies are included in the combined 2003 Annual Report to Shareholders (of PG&E Corporation and Pacific Gas and Electric Company) and are incorporated herein by reference. Our audits also included the respective consolidated financial statement schedules of PG&E Corporation and Pacific Gas and Electric Company, listed in Item 15(a)2. These consolidated financial statement schedules are the responsibility of the respective managements of PG&E Corporation and Pacific Gas and Electric Company. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the respective basic consolidated financial statements of PG&E Corporation and Pacific Gas and Electric Company taken as a whole, present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
San Francisco, California
February 18, 2004
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
CONDENSED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2003, 2002 and 2001
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003, 2002 and 2001
PG&E CORPORATION
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 2002 and 2001
(1)
Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.”
(2)
Allowance for uncollectible accounts does not include NEGT.
(3)
Deductions consist principally of write-offs, net of collections of receivables previously written off.
(4)
Provision was deduction from “Regulatory Assets.”
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR IN POSSESSION
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2003, 2002 and 2001
(1)
Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.”
(2)
Deductions consist principally of write-offs, net of collections of receivables previously written off.
(3)
Provision was deduction from “Regulatory Assets.”
EXHIBIT INDEX
*
Management contract or compensatory agreement.
**
Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.