Item 1. Business.
General
Corporate Structure and Business
PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”) a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution, electricity generation, procurement and transmission, and natural gas procurement, transportation and storage. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997.
The Utility served approximately 5.1 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2007. The Utility had approximately $36.3 billion of assets at December 31, 2007, and generated revenues of approximately $13.2 billion in 2007. 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 (“CPUC”), and the Federal Energy Regulatory Commission (“FERC”).
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 (“SEC”). These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K 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.pgecorp.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, 2007, PG&E Corporation and its subsidiaries had approximately 20,050 regular employees, including approximately 19,785 regular employees of the Utility. Of the Utility's regular employees, approximately 12,929 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC (“ESC”); and the Service Employees International Union, Local 24/7 (“SEIU”). The ESC and IBEW collective bargaining agreements expire on December 31, 2008. The SEIU collective bargaining agreement expires on February 28, 2009.
Cautionary Language Regarding Forward-Looking Statements
This combined Annual Report on Form 10-K, including the information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2007 (“2007 Annual Report”), contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated Utility rate base, estimated environmental remediation liabilities, estimated tax liabilities, the anticipated outcome of various regulatory and legal proceedings, future cash flows, and the level of future equity or debt issuances, and are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “aim, “ “may,” “might,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. 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, but are not limited to:
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the Utility’s ability to manage capital expenditures and operating costs within authorized levels and recover costs through rates in a timely manner;
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the outcome of regulatory proceedings, including pending and future ratemaking proceedings at the CPUC and the FERC;
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the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas markets;
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the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards on the Utility’s facilities and operations, its customers, and third parties on which the Utility relies;
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the potential impacts of climate change on the Utility’s electricity and natural gas businesses;
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changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology, including the development of alternative energy sources, or other reasons;
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operating performance of the Utility’s Diablo Canyon nuclear generating facilities (“Diablo Canyon”), the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon;
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whether the Utility can maintain the cost efficiencies it has recognized from its completed initiatives to improve its business processes and customer service, improve its performance following the October 2007 implementation of new work processes and systems, and identify and successfully implement additional cost-saving measures
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whether the Utility incurs substantial unanticipated expense to improve the safety and reliability of its electric and natural gas distribution systems;
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whether the Utility achieves the CPUC’s energy efficiency targets and recognize any incentives the Utility may earn in a timely manner;
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the impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies;
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the impact of changing wholesale electric or gas market rules, including new rules of the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market;
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how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company;
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the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance or from other third parties;
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the ability of PG&E Corporation and/or the Utility to access capital markets and other sources of credit in a timely manner on favorable terms;
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the impact of environmental laws and regulations and the costs of compliance and remediation;
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the effect of municipalization, direct access, community choice aggregation, or other forms of bypass; and
the impact of changes in federal or state tax laws, policies, or regulations.
For more information about the more significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future financial condition and results of operations, see “Risk Factors” that appears near the end of the section entitled “Management's Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”) in the 2007 Annual Report that is incorporated by reference and filed as part of Exhibit 13 to this Annual Report on Form 10-K. PG&E
Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events or otherwise.
PG&E Corporation's Regulatory Environment
Federal Energy Regulation
As a public utility holding company, PG&E Corporation is subject to the requirements of the Energy Policy Act of 2005 (“EPAct”), which became effective on February 8, 2006. Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC, an independent agency within the U.S. Department of Energy (“DOE”). PG&E Corporation and its subsidiaries are exempt from all requirements of PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.
State Energy Regulation
PG&E Corporation is not a public utility under California law. The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:
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the Utility cannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;
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the Utility's dividend policy must 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 (known as the “first priority” condition); and
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the Utility must maintain on average its CPUC-authorized utility capital structure, although it can request a waiver of this condition if an adverse financial event reduces the Utility's common equity component by 1% or more.
(As discussed below under “Item 3 - Legal Proceedings,” the California Attorney General and the City and County of San Francisco have alleged that PG&E Corporation and its directors, as well as the directors of the Utility, violated the CPUC’s holding company conditions during the California 2000-2001 energy crisis. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders.)
The CPUC also has adopted complex and detailed rules governing transactions between California's electricity and gas utilities and their affiliates. The rules address the use of the utilities’ names and logos by their affiliates, the separation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates. The rules also prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility's affiliates. In December 2006, the CPUC revised its rules to, among other changes:
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emphasize that the holding company may not aid or abet a utility's violation of the rules or act as a conduit to provide confidential utility information to an affiliate;
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require prior CPUC approval before the utility can contract with an affiliate for resource procurement (e.g., electricity or gas), except in blind transactions where the identity of the other party is not known until the transaction is consummated;
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require certain key officers to provide annual certifications of compliance with the affiliate rules;
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prohibit certain key officers from serving in the same position at both the utility and the holding company, or, in the alternative, prohibit the sharing of lobbying, regulatory relations and certain legal services (except for legal services necessary to the provision of permitted shared services);
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require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company; and
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make the CPUC's Energy Division responsible for hiring independent auditors to conduct biennial audits to verify that the utility is in compliance with the affiliate rules.
The CPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.
The Utility's Regulatory Environment
Various aspects of the Utility's business are subject to a complex set of energy, environmental and other laws, regulations and regulatory proceedings at the federal, state and local levels. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935, as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938 and the Public Utility Regulatory Policies Act of 1978 (“PURPA”).
This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations and regulatory mechanisms affecting the Utility. These summaries are not an exhaustive description of all the 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 pending regulatory proceedings that are expected to affect the Utility. For more information, see “Regulatory Matters” in the MD&A in the 2007 Annual Report.
Federal Energy Regulation
The FERC
The FERC regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities; tariffs and conditions of service of regional transmission organizations, including the CAISO; and the terms and rates of wholesale electricity sales. The EPAct granted the FERC significant new responsibilities to oversee the reliability of the nation’s electricity transmission grid, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest. The EPAct also expanded the FERC’s authority to impose penalties for violation of certain federal statutes, including the Federal Power Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations. The FERC can impose penalties of up to $1,000,000 per day per violation. 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.
Electric Reliability Standards; Development of Transmission Grid. As part of its directive to oversee the development of mandatory electric reliability standards to protect the national electric transmission system, the FERC certified the North American Electric Reliability Corp., known as the NERC, as the nation’s Electric Reliability Organization under the EPAct. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval. The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council. Failure of the Utility to comply with FERC-approved electric reliability standards may subject the Utility to penalties. In addition, the CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions, and ensuring the maintenance of adequate reserves of generation capacity.
The FERC also has issued rules on electric transmission pricing reforms designed to promote needed investment in energy infrastructure, to reduce transmission congestion, and to require transmission organizations with organized electricity markets to make long-term firm transmission rights available to load-serving entities, so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk.
Prevention of Market Manipulation. The EPAct also gave the FERC broader authority to police and penalizes the exercise of market power or behavior intended to manipulate prices paid in FERC-jurisdictional transactions. In January 2006, the FERC adopted rules to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5, which prohibits fraud and manipulation in the purchase or sale of securities. Under the FERC's new regulations, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas, electric energy, or transportation/transmission services subject to the jurisdiction of the FERC: (1) to use or employ any device, scheme or artifice to defraud, (2) to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any person.
QF Regulation. Under PURPA, electric utilities were required to purchase energy and capacity from independent power producers that are qualifying cogeneration facilities known as QFs. To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms, conditions, prices and eligibility requirements. The EPAct significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to waive the obligation of an electric utility under Section
of PURPA to purchase the electricity offered to it by a QF (under a new contract or obligation), if the FERC finds that the QF has nondiscriminatory access to one of three defined categories of
competitive wholesale electricity markets. The statute permits such waivers as to a particular QF or on a “service territory-wide basis.” The Utility plans to assess whether it will file a request with the FERC to terminate its obligations under PURPA to enter into new QF purchase obligations after the implementation of the new day ahead market structure provided for in the CAISO’s Market Redesign and Technology Update (“MRTU”) initiative.
The NRC
The Nuclear Regulatory Commission (“NRC”), oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“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. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.
The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. Under the terms of these licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by the Diablo Canyon plant. For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters - Nuclear Fuel Disposal,” below.
State Energy Regulation
California Legislature
The Utility's operations have been significantly affected by various statutes passed by the California legislature, including:
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Assembly Bill 1890. Assembly Bill 1890, enacted in 1996, 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 investor-owned utilities’ customers were given the choice to become “direct access” customers by buying energy from an alternate service provider other than the regulated utilities. Among other provisions, Assembly Bill 1890 provided for the establishment of the CAISO, as a nonprofit public benefit corporation, to operate and control the state-wide electricity transmission grid and ensure efficient use and reliable operation of the transmission grid.
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Assembly Bill 1X. Assembly Bill 1X was enacted during the California 2000-2001 energy crisis when the California investor-owned electric utilities were no longer able to buy electricity. Assembly Bill 1X authorized the California Department of Water Resources (“DWR”) beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers. Assembly Bill 1X required the California investor-owned electric utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWR's billing and collection agent. To ensure that the DWR recovers its costs to procure electricity, Assembly Bill 1X required the CPUC to suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity pursuant to Assembly Bill 1X. The current DWR contracts terminate at various dates through 2015.
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Assembly Bill 57. Assembly Bill 57, enacted in September 2002 and amended by Senate Bill 1976, required the California investor-owned utilities to resume purchasing power on January 1, 2003, required the CPUC to allocate electricity to be provided under the DWR contracts among the customers of the California investor-owned electric utilities, requires the utilities to file short- and long-term electricity resource procurement plans with the CPUC for approval, and authorizes the utilities to recover their reasonable wholesale procurement costs incurred under a CPUC-approved procurement plan through the establishment of new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under the approved procurement plans.
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Senate Bill 1078. Senate Bill 1078, enacted in September 2002 (as amended by Senate Bill 107, enacted in September 2006 and effective on January 1, 2007) established the Renewables Portfolio Standard Program, which requires each California retail seller of electricity, except municipal utilities, to increase its purchases of eligible renewable energy (such as biomass, small hydro, wind, solar and geothermal energy) by at least 1% of its retail sales per year, so that the amount of electricity purchased from eligible renewable resources equals at least 20% of its total retail sales by 2010.
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Assembly Bill 380. Assembly Bill 380, enacted in September 2005, requires the CPUC, in consultation with the CAISO, to establish resource adequacy requirements for all load-serving entities, including the California investor-owned electric
utilities but excluding local publicly owned electric utilities. Assembly Bill 380 requires each load-serving entity to maintain physical generating capacity adequate to meet its load requirements, including peak demand and planning and operating reserves, deliverable to locations and at times as may be necessary to provide reliable electric service.
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Assembly Bill 32. Assembly Bill 32, enacted in September 2006, requires the California Air Resources Board (“CARB”) to adopt regulations to limit statewide greenhouse gas emission, to 1990 levels by 2020, with certain limits beginning in 2012. (See “Environmental Matters” below for more information.)
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Senate Bill 1368. Senate Bill 1368, also enacted in September 2006, prohibits any load-serving entity, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload generation (i.e., electricity generation from a power plant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%) unless it complies with a greenhouse gas emission performance standard. (See “Environmental Matters” below for more information.)
The CPUC
The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility's electricity distribution, electricity generation, 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 that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also 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.
PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utility's proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court does retain jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters. (For more information, see Note 15 of the Notes to the Consolidated Financial Statements included in the 2007 Annual Report.)
The California Energy Resources Conservation and Development Commission
The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission (“CEC”), is the state's primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.
Other Regulation
The Utility obtains 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. (For more information see “Environmental MattersWater Quality” below.)
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 and natural gas 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. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In addition, charter cities can set fees of their own determination. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term, including agreements with two large charter cities. The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the use of the public streets. 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.
Competition
Historically, energy utilities operated as regulated monopolies within service territories in which 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 undertook 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 that 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.
Competition in the Electricity Industry
Federal. At the federal level, many provisions of the EPAct support the development of competition in the wholesale electric market. The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.
Even before the passage of the EPAct, the FERC's policies 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. Order 888 requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service. 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. On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination; (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement; and (3) increase transparency in the rules applicable to planning and use of the transmission system.
The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended 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 generation and transmission. Under the rules and associated tariffs, a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator. The generator will be reimbursed over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades then is recovered by the regulated transmission provider in its overall transmission rates.
State. At the state level, Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry commencing in 1998. Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted through the Power Exchange (“PX”). As a result of the California 2000-2001 energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile remaining refund amounts owed and to make compliance filings as required by the FERC in the California refund proceeding, which is still pending at the FERC. (For information about the status of the California refund proceeding and the remaining disputed claims made by power suppliers in the Utility’s Chapter 11 proceeding, see Note 15 of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.) The CAISO, which was established pursuant to AB 1890 to take control of the California investor-owned electric transmission facilities located in California, currently administers a real-time or “spot” wholesale market for the sale of electric energy. This market is used to allocate space on the transmission lines, maintain operating reserves, and match supply with demand in real time. The CAISO’s MRTU initiative is intended to restructure the California electricity market and to enhance power grid reliability, including the implementation of a new day-ahead market. The CAISO also will provide congestion revenue rights to allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market. The MRTU tariffs will apply to all load-serving entities, including the investor-owned utilities, serving California consumers. The CAISO has delayed the start date of MRTU several times and has indicated that it will not set a new date for commencement of MRTU until market participants have had an opportunity to test the final MRTU functionality and have provided feedback to the CAISO. Also, in January 2008, the CPUC staff issued its recommendation to establish a statewide wholesale electricity capacity market to replace the current resource adequacy program. The CPUC is expected to issue a decision on this matter in May 2008. Any changes the CPUC adopts would be subject to the FERC’s approval.
Assembly Bill 1890 also permitted retail end-use customers to choose their energy service provider by becoming a direct access customer. To ensure that the DWR recovers its costs to procure electricity for the customers of the investor-owned electric utilities, Assembly Bill 1X required the CPUC to suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity on behalf of the customers of the California investor-owned electric utilities. The CPUC suspended direct access on September 20, 2001, but allowed existing direct access customers to continue being served by alternative energy service providers, rather than investor-owned electric utilities. 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. The CPUC is scheduled to vote on February 28, 2008 on a proposed decision that concludes the CPUC does not have the authority to reinstate direct access because the DWR still supplies power under the contracts it executed during the energy crisis. The proposed decision states that the CPUC will proactively investigate how the DWR can terminate its obligations under the power contracts, by assignment or otherwise, to hasten the reinstatement of direct access.
In addition, the Utility’s customers may, under certain circumstances, obtain power from a “community choice aggregator” instead of from the Utility. California Assembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under Assembly Bill 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators' customers and would 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. The CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services. Assembly Bill 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 customers any costs of implementing the program not reasonably attributable to a community choice aggregator. No cities or counties are currently operating as community choice aggregators, but the San Joaquin Valley Power Authority has filed an implementation plan and stated that it intends to begin operating in 2008.
Competition in 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 whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from FERC rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC. The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by FERC for interstate gas pipelines. The CPUC divides the Utility's natural gas customers into two categories: “core” customers, which are primarily small commercial and residential customers, and “non-core” customers, which are primarily industrial, large commercial and electric generation customers. Under the Gas Accord structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services. All
services are offered on a nondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller, downstream local transmission systems.
The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties, was approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods. In September 2007, the CPUC approved the Gas Accord IV covering 2008 through 2010. The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential.
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. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.
PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation, have agreed to jointly pursue the development of a new 230-mile interstate gas transmission pipeline that would increase natural gas supplies for the entire West Coast region of the United States. The proposed Pacific Connector Gas Pipeline, together with the proposed Jordan Cove liquefied natural gas (“LNG”) terminal in Coos Bay, Oregon, being developed by Fort Chicago Partners, L.P., would open growing West Coast natural gas markets to diverse worldwide natural gas supply sources, providing additional alternatives to traditional Canadian, Southwest and Rocky Mountain supplies and increasing supply options and reliability. The proposed Pacific Connector Gas Pipeline would connect the proposed Jordan Cove LNG terminal to Northwest Pipeline Corporation’s pipeline system in Oregon, and to the Utility's backbone gas transmission system near Malin, Oregon. Other potential interconnects include Tuscarora Gas Transmission Company’s pipeline system, which serves northern Nevada. The proposed Pacific Connector Gas Pipeline would be capable of delivering 1 bcf per day to the West Coast natural gas market, to customers in the Pacific Northwest through Northwest Pipeline Corporation's pipeline system, to the Utility's system for delivery to customers in California, and to customers in northern Nevada through Tuscarora Gas Transmission Company’s pipeline system. In September 2007, applications with the FERC were filed to request authorization to construct the proposed Pacific Connector Gas Pipeline and the Jordan Cove LNG terminal. It is expected that the FERC will issue a decision by the end of 2008.
The development and construction of the Pacific Connector Gas Pipeline depends upon the construction of the proposed LNG terminal at Jordan Cove by Fort Chicago Partners, L.P. PG&E Corporation cannot predict whether Fort Chicago Partners, L.P. will be successful in completing the development and construction of its proposed LNG terminal. In addition, the development and construction of the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline are subject to obtaining required permits, regulatory approvals, and commitments under long-term capacity contracts. Assuming the required permits, authorizations, and long-term capacity commitments are timely received and that other conditions are timely satisfied, it is anticipated that the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline would begin commercial operation in 2011.
In December 2007, PG&E Corporation entered into a letter of intent with El Paso Corporation to acquire a 25.5% interest in El Paso Corporation’s proposed 680-mile, 42-inch natural gas transmission pipeline (the “Ruby Pipeline”) that would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border. The Ruby Pipeline is expected to have an initial capacity of 1.2 bcf per day and be expandable to 2 bcf per day. The proposed Ruby Pipeline would connect Rocky Mountain natural gas producers with northern California, Nevada, and the Pacific Northwest to provide natural gas users with competitively priced natural gas. PG&E Corporation’s acquisition of an interest in the Ruby Pipeline project is subject to various conditions, including the negotiation and execution of the partnership documents. Subject to obtaining the required regulatory and other approvals, including the approvals of the boards of directors of PG&E Corporation and El Paso Corporation, and after obtaining necessary customer commitments, the Ruby Pipeline is anticipated to be in service in the first quarter of 2011.
Ratemaking Mechanisms
Overview
The Utility’s rates for electricity and natural gas utility services are based on its costs of providing service (called cost-of-service ratemaking). Before setting rates, the CPUC and the FERC determine the annual amount of revenue (called revenue requirements) that the Utility is authorized to collect from its customers. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.
Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of providing utility services as well as a return of, and a fair rate of return on, its investment in utility facilities (called rate base). Revenue requirements are primarily determined based on the Utility’s forecast of future costs. These costs include the Utility’s costs of electricity and natural gas purchased for its customers, operating expenses, administrative and general expenses, depreciation, taxes, and public purpose programs.
Regulatory balancing accounts are used to adjust the Utility’s revenue requirements. Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations. Cost balancing accounts track differences between the Utility’s incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.
To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial and agricultural) and to various service components (mainly customer, demand, and energy). Specific rate components are designed to produce the required revenue. Rate changes become effective prospectively on or after the date of CPUC or FERC decisions. Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.
Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base. The Utility may be unable to earn its authorized rate of return because the CPUC or the FERC excludes the Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.
While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on objective or fixed standards instead of on the cost of providing service. The primary example is the Utility’s customer energy efficiency shareholder incentive mechanism. In September 2007, the CPUC established incentive ratemaking mechanisms applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles. (For more information, see “Public Purpose and Other Programs” below.) Another example is the Core Procurement Incentive Mechanism (“CPIM”) under which the Utility's natural gas purchase costs are compared to an aggregate market-based benchmark, and the Utility’s shareholders share in the costs or savings outside a tolerance band around the benchmark. (See “Natural Gas Procurement” below.)
Electricity and Natural Gas Distribution and Electricity Generation Operations
General Rate Cases
The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first, or test, year. Typical interveners in the Utility's GRC include the CPUC’s Division of Ratepayer Advocates , and The Utility Reform Network (“TURN”). On March 15, 2007, the CPUC approved a multi-party settlement agreement to resolve the Utility’s 2007 GRC. The decision sets the Utility’s electricity and natural gas distribution and electricity generation revenue requirements for a four-year period, from 2007 through 2010, rather than for a typical three-year period. Under the decision, the Utility’s next GRC will be effective January 1, 2011. On November 1, 2007, the CPUC denied an application for rehearing of the decision that had been filed by TURN and Aglet Consumer Alliance. Neither TURN nor Aglet filed a petition for appellate review of the denial. For more information, see “Results of Operations - Electric Revenues” in the MD&A in the 2007 Annual Report.
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 in order 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. The CPUC’s decision in the Utility’s 2007 GRC includes a provision for attrition adjustments to be made in 2008, 2009 and 2010. For more information, see “Results of Operations - Electric Revenues” in the MD&A in the 2007 Annual Report.
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 relative weightings of common equity, preferred equity and debt in the Utility's total authorized capital structure for a specific year. The CPUC then establishes the authorized return on each component that the Utility will collect in its authorized rates. The Utility’s CPUC-authorized capital structure for 2008 consists of 46% long-term debt, 2% preferred stock and 52% common equity. The Utility’s CPUC-authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base for 2008 is 6.05% for long-term debt, 5.68% for preferred stock and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%. The CPUC is considering various mechanisms that could replace the annual cost of capital proceedings. The CPUC is scheduled to issue a final decision on this issue by April 24, 2008.
Although the FERC has authority to set the Utility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility's transmission rates are determined through a negotiated rate settlement.
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. Natural gas or electricity usage in excess of the baseline allowance is covered by higher rates that increase with usage.
Public Purpose and Other Programs
California law requires the CPUC to authorize certain levels of funding for electric and gas public purpose programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources. In addition, California law requires the CPUC to authorize funding for the California Solar Initiative discussed below, and other self-generation programs. In addition to public purpose programs, the CPUC has authorized additional funding for demand response programs. For 2007 expenditures, the CPUC authorized the Utility to collect revenue requirements of approximately $639 million from electricity customers to fund these electricity public purpose and other programs and to collect revenue requirements of approximately $82 million from gas customers to fund these natural gas public purpose programs. The CPUC is responsible for authorizing the programs, funding levels and cost recovery mechanisms for the Utility's operation of both energy efficiency and low-income energy efficiency programs. The CEC administers both the electric and natural gas public interest research and development programs and the renewable energy program on a statewide basis. In 2007, the Utility transferred $114 million to the CEC for these programs. In 2007, surcharges collected from the Utility’s gas customers funded $7.7 million in gas public interest research and development programs administered by the CEC.
Public purpose programs include:
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Energy Efficiency Programs. The CPUC has authorized the Utility’s 2006 through 2008 energy efficiency portfolio plans and program and authorized the Utility to recover approximately $867 million to fund these programs, including funding for evaluation, measurement and verification activities. This increased energy efficiency funding level is part of a larger effort by the State of California to reduce consumption of fossil fuels. The increased funding level is designed to enable both residential and business customers to take more advantage of the diverse mix of energy efficiency programs. In May 2008, the Utility expects to file a new Application with the CPUC seeking approval of energy efficiency programs and funding for the next cycle of energy efficiency, 2009-2011.
In September 2007, the CPUC adopted an incentive ratemaking mechanism applicable to the California investor-owned utilities’ implementation of their energy efficiency programs funded for the 2006-2008 and 2009-2011 program cycles. To earn incentives, the utilities must (1) achieve at least 85% of the CPUC’s overall savings goal over the three-year program
cycle and (2) achieve at least 80% of the individual kWh, kW, and therm savings metric goals over the three-year program cycle. If the utilities achieve between 85% and 99% of the CPUC’s overall savings goal, 9% of the verified net benefits (i.e., energy resource savings minus total energy efficiency program costs) will accrue to shareholders and 91% of the verified net benefits will accrue to customers. If the utilities achieve 100% or more of the CPUC’s savings goal, the shared rate increases so that 12% of the total verified net benefits will accrue to shareholders and 88% will accrue to customers up to a stated maximum. If the utilities achieve less than 65% of any one of the individual savings metric goals, then the utilities must reimburse customers based on the greater of (1) 5 cents per kWh, 45 cents per therm, and $25 per kW for each kWh, therm, or kW unit below the 65% threshold or (2) a dollar-for-dollar payback of negative net benefits, also known as a cost-effectiveness guarantee. The maximum amount that the Utility could earn, and the maximum amount that the Utility could be required to reimburse customers, over the 2006-2008 program cycle is $180 million.
The utilities must submit two interim claims during the three-year program cycle, subject to verification of the actual amount of net benefits in a final true-up claim. The CPUC will determine for each interim claim whether a utility is entitled to incentives or is required to reimburse customers based on the level of achievement of the CPUC’s savings goals on a cumulative-to-date basis. The interim amounts will be calculated using updated estimates and assumptions about the energy savings per energy efficiency measure (“load impact”) over the three-year program period and will be reduced based on an assumption that certain customers would have undertaken the energy efficiency activity in the absence of the utilities’ energy efficiency program (the “net-to-gross” ratio”). The decision, as modified in January 2008, requires that 35% of the incentives or reimbursement obligations calculated for each interim claim be “held back” until completion of measurement studies verifying the actual energy savings for the entire three-year program cycle. The final true-up may result in an adjustment to the prior year’s interim claims, but as long as the final measured energy savings are at least 65% of the CPUC savings goals, the utilities will not be required to pay back any incentives earned on an interim basis.
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Demand Response Programs. Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. The CPUC has authorized approximately $109 million for 2006 through 2008 demand response programs for the Utility. In addition, the CPUC approved several contracts with third-party demand response providers in 2007. The payments made under the contracts are recovered through a balancing account.
In addition, on February 14, 2008, the CPUC approved the Utility’s multi-year air conditioning direct load control program and authorized funding of $179 million through June 1, 2011 to implement this program. Customers who enroll in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies. The decision will allow the Utility to enroll approximately 397,000 air conditioning load control devices to achieve approximately 305 MW of load reduction capacity by June 2011.
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Self-Generation Incentive Program and California Solar Initiative. The Utility administers the self-generation incentive program (“SGIP”) authorized by the CPUC to provide incentives to electricity customers who install certain types of clean or renewable distributed generation resources that meet all or a portion of their onsite energy usage. The CPUC has approved a budget of $83 million for the SGIP program in 2008, of which $36 million has been allocated to the Utility. The CPUC also established the California Solar Initiative (“CSI”) to bring 1,940 MW of solar power on-line by 2017 through the California investor-owned utilities, and authorized the utilities to collect an additional $2.2 billion over the 2007 through 2016 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load to meet this goal. Of the total amount authorized, the Utility has been allocated $946 million to fund customer incentives, research, development and demonstration activities (with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses. The California Legislature modified the CSI program to include participation of the California municipal utilities. The current overall goal of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2017.
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Low-Income Energy Efficiency Programs and California Alternate Rates for Energy. The CPUC has approved funding of $78 million in each of 2007 and 2008 to support energy efficiency programs for low-income and fixed-income customers. The Utility also provides a discount rate called the California Alternate Rates for Energy (“CARE”) for low-income customers. This rate subsidy is paid for by the Utility's other customers. For 2007, the amount of this subsidy was approximately $468.6 million (including avoided customer surcharges). In May 2008, the Utility expects to file an application with the CPUC seeking approval of low-income energy efficiency programs and funding for the next cycle of low-income energy efficiency, 2009-2011.
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The ClimateSmart™ Program.In 2006, the CPUC approved the ClimateSmart™ program to allow customers to choose to neutralize greenhouse gas emissions associated with their energy use. Customers who choose to enroll in the ClimateSmart™ program will pay a small premium on their monthly utility bill, based on their energy usage, to fund environmental projects aimed at removing carbon dioxide and other greenhouse gases from the air. The Utility estimates that this program, which began at the end of June 2007, will generate approximately $15 million by December 31, 2009 to fund projects that are expected to reduce greenhouse gas emissions by at least 1.5 million tons.
Rate Recovery of Costs of New Electricity Generation Resources
Overview
Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility's own generation facilities and existing electricity contracts (including DWR allocated contracts). Every other year, each utility must submit a long-term procurement plan covering a ten-year period to the CPUC for approval. In December 2007, the CPUC approved the utilities’ long-term procurement plan, covering the 2007-2016 period, subject to certain required modifications. California legislation, Assembly Bill 57, allows the utilities to recover the costs incurred in compliance with their CPUC-approved procurement plans without further reasonableness review. Each utility may, if appropriate, conduct a competitive request for offers (“RFO”) within the parameters permitted in its approved plan to meet the utility’s projected need for electricity resources. Contracts that are entered into after the competitive bidding process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the associated costs. The utilities conduct separate competitive solicitations to meet their renewable energy resource requirements. The utilities submit the renewable energy contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements.
The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility under DWR contracts) through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC in accordance with Assembly Bill 57. The ERRA tracks the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans and contracts. To determine the authorized revenue requirement recorded in the ERRA, each year the CPUC reviews the Utility’s forecasted costs under power purchase agreements and fuel costs. Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility's prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The CPUC also performs compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs.
The authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for Utility-owned generation are addressed in the Utility’s GRC. The revenue requirement to recover the initial capital costs for CPUC-approved utility owned generation projects will be recovered through a balancing account, the Utility Generation Balancing Account (“UGBA”), which will track the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs. The initial revenue requirement for the Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year.
Costs Incurred Under New Power Purchase Agreements
During 2006-2007, the CPUC approved several power purchase agreements with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements. The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.
For new non-renewable generation purchased from third parties under power purchase agreements, the Utility may elect to recover any above-market costs through either: (1) the imposition of a non-bypassable charge imposed on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the utilities’ service territory, including existing direct access customers and community choice aggregation customers. (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition Competition in the Electricity Industry.”) The non-bypassable charge can be imposed from the date of signing a power purchase agreement and last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less. Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis.
If a utility elects to use the net capacity cost allocation method, the net capacity costs would be allocated for the term of the contract or 10 years, whichever is less, starting on the date the new generation unit comes on line. Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimize the net capacity costs that would be subject to allocation. If no bids are accepted for the energy rights, the Utility would retain the rights to the energy and would value it at market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.
Costs of Utility-Owned Generation Resource Projects
During 2006, the CPUC approved three agreements related to Utility-owned generation projects in accordance with the Utility’s CPUC approved long-term procurement plan. The CPUC also authorized the amount of revenue requirements that the Utility is authorized to recover related to each project to recover capital costs and non-fuel operations and maintenance costs. For more information, see “Capital Expenditures - New Generation Facilities” in the MD&A in the 2007 Annual Report
In its December 2007 decision on the utilities’ long-term procurement plans, for future utility-owned generation projects the CPUC eliminated the limitations it had adopted in 2004 that required the utilities to share half of any construction cost savings with ratepayers while absorbing any cost overruns. Instead, the decision allows the utilities to make flexible proposals for utility-owned generation ratemaking on a case-by-case basis. For more information about the Utility’s approved long-term procurement plan covering 2007-2016, see “Electric Utility Operations - Electricity Resources- Future Long-Term Generation Resources” below.
DWR Electricity and DWR Revenue Requirements
During the California 2000-2001 energy crisis, the DWR entered into long-term contracts to purchase electricity from third parties. The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these customers through a rate component called the DWR "power charge." The rates that these customers pay also include 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. The Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.
Electricity Transmission
The Utility's electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues: charges under the Utility's transmission owner tariff and charges under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. Other customers pay transmission rates that are established by the FERC in the Utility's transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utility's retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.
Transmission Owner Rate Cases
The primary FERC rate-making proceeding to determine the amount of revenue requirements the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (“TO rate case”). A TO rate case is generally held every year and sets rates for a one-year period. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. For more information about the Utility’s TO rate cases, see “Results of Operations - Electric Operating Revenues” in the MD&A in the 2007 Annual Report.
The Utility's transmission owner tariff includes two rate components. The primary component consists of base transmission rates intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity. The Utility derives the majority of the Utility's transmission revenue from base transmission rates.
The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO. These revenues include:
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the proceeds received from the CAISO for wholesale wheeling service (i.e., the transfer of electricity that is being sold in the
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wholesale market) that the CAISO provides to third parties using the Utility’s transmission facilities, and
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revenues that the CAISO collects from transmission users to relieve congestion on the Utility’s transmission line (either in the form of financial hedges, such as firm transmission rights relating to future deliveries of electricity, or in the form of a usage charge to manage congestion relating to real-time delivery of electricity).
These revenues are adjusted by the shortfall or surplus resulting from any cost differences between the amount the Utility is entitled to receive from certain wholesale customers under specific contracts and the amount the Utility is entitled to receive or be charged for scheduling services under the CAISO’s rules and protocols.
The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge for the Utility’s use of the CAISO-controlled electric transmission grid in serving its customers. The CAISO's transmission access charge methodology, approved by the FERC in December 2004, provides for a transition over a 10-year period, from 2000-2009, to a uniform statewide high-voltage transmission rate. This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology may result in a cost shift from transmission owners whose costs for existing transmission facilities at 200 kV and above are higher than that embedded in the uniform transmission access charge rate, to transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligation for this cost differential has been capped at $32 million per year during the 10-year transition period.
In December 2007, the FERC approved a settlement between the Utility and PacificCorp, both owners of an electric transmission line which is part of the California - Oregon Intertie, and other entities, relating to the termination of agreements that govern electric transmission service over the California - Oregon Intertie. For more information, see “Electric Utility Operations - Electric Transmission” below. As a condition of the settlement, the Utility will lease back a portion of the capacity allocated to PacifiCorp from 2008 through 2017 over the eastern 500 KV line between the substation in Malin, Oregon, and the Round Mountain substation located in California. In addition, the Utility’s lease payments to PacifiCorp will be fully recovered through the Utility’s transmission owner rates.
Natural Gas
The Gas Accord
On September 20, 2007, the CPUC issued a final decision approving a multi-party settlement agreement, known as the Gas Accord IV, to establish the Utility’s natural gas transmission and storage rates and associated revenue requirements from January 1, 2008 through December 31, 2010. The Gas Accord IV establishes a 2008 natural gas transmission and storage revenue requirement of $446 million (approximately 0.6% above the currently authorized revenue requirement for 2007), a 2009 revenue requirement of $459 million (approximately 2.8% above the proposed 2008 revenue requirement), and a 2010 revenue requirement of $471 million (approximately 2.7% above the proposed 2009 revenue requirement). A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, will continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements will continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:
Backbone Transmission. The backbone transmission revenue requirement is recovered through a combination of firm, two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available, one-part rates (consisting only of volumetric usage charges). The mix of firm and as-available backbone services provided by the Utility continually changes. The Utility’s backbone transmission costs are partly assured of recovery to the extent backbone capacity is subscribed under long-term firm contracts, and to the extent the costs of that contracted capacity are recovered through fixed reservation charges. Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity. Core customers are allocated approximately 32% of the total backbone capacity on the Utility’s system. Core customers pay approximately 71% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.
Local Transmission. The local transmission revenue requirement is allocated approximately 70% to core customers and 30% to non-core customers. The core portion is protected through a balancing account and therefore represents assured revenues. The non-core portion is subject to volumetric cost recovery risk.
Storage. The storage revenue requirement is allocated approximately 71% to core customers, 13% to non-core storage service, and 17% to pipeline load balancing service. The core portion is protected through a balancing account and therefore represents assured revenues. Recovery of the non-core portion is subject to volumetric and price risk. The pipeline load balancing
portion is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.
Taken together, the backbone transmission, local transmission, and storage costs that are either protected through balancing accounts or recovered through long-term firm contract reservation charges amount to approximately 47% of the Utility’s total revenue requirement for gas transmission and storage.
Biennial Cost Allocation Proceeding
Certain of the Utility's natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s 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 over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual 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.
The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism, the CPIM. Under the CPIM, the Utility's purchase costs for a fixed twelve-month period 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 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive in their rates 75% of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income. The Utility also has received CPUC approval for a long-term gas hedging program on behalf of core customers, through 2011. The costs of the hedging program are recovered directly from gas customers, outside the CPIM mechanism, and are subject only to a compliance review, not an after-the-fact reasonableness review. (For more information see the “Risk Management Activities” section of MD&A in the 2007 Annual Report).
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 are approved 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. In 2007, in conjunction with the settlement of a FERC rate case filed by TransCanada’s Gas Transmission Northwest Corporation, which transports Canadian natural gas to California, the Utility agreed to extend its existing contract commitment for a series of multiple-year terms. The FERC approved the settlement in January 2008. The settlement is further discussed below under “Natural Gas Utility Operations - Interstate and Canadian Natural Gas Transportation Services Agreements.”
Electric Utility Operations
Electricity Resources
The following table shows the percentage of the Utility's total sources of electricity for 2007 represented by each major electricity resource:
The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. Least-cost dispatch requires the Utility, in certain cases, to schedule more electricity than is necessary to meet its retail load and therefore to sell this electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR, based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.
Owned Generation Facilities
At December 31, 2007, 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, Humboldt Bay Unit 3, and two operating fossil fuel-fired plants. As described below, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.
Diablo Canyon Power Plant. The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. Unit 1 began commercial operation in May 1985, and the operating license for this unit expires in November 2024. Unit 2 began commercial operation in March 1986, and the operating license for this unit expires in August 2025. For the 10-year period ended December 31, 2007, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 90.2%.
The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 17: Commitments and Contingencies- Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.
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 20 months. The average length of a refueling outage over the last five years has been approximately 48 days. The Utility will replace the steam generators in Unit 2 during the scheduled refueling outage which began on February 4, 2008 and will replace the steam generators in Unit 1 during the scheduled refueling outage to begin January 2009. Due to this additional work, each of these refueling outages is expected to last approximately 76 days. (The capital
expenditures necessary to complete these projects are discussed further in the “Capital Expenditures” section of MD&A in the 2007 Annual Report.) The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.
In addition, as discussed below under “Environmental Matters - Nuclear Fuel Disposal,” the Utility is constructing an on-site dry cask storage facility to store the spent nuclear fuel that is expected to be completed in 2008. To provide another storage alternative in the event that construction of the dry cask storage facility is delayed, in December 2006, the Utility completed the installation of temporary storage racks in each unit's existing spent fuel storage pool that increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, the operation of Unit 1 may have to be curtailed or halted as early as 2010 and the operation of Unit 2 may have to be curtailed or halted as early as 2011 until such time as additional spent fuel can be safely stored.
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, 56 diversions, 170 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 90 permits or licenses and 160 statements of water diversion and use. All but three of the Utility's powerhouses are licensed by the FERC, with license terms between 30 and 50 years. In the last five years, the FERC renewed six hydroelectric licenses with a total of 699 MW of hydroelectric power. The Utility is in the process of renewing licenses for projects with approximately 1,314 MW of additional hydroelectric power. Although the original licenses associated with 917 MW of the 1,314 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 2,569 MW of hydroelectric power will expire between 2013 and 2043.
DWR Power Purchases
During 2007, electricity from the DWR contracts allocated to the Utility provided approximately 25% of the electricity delivered to the Utility's customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. During 2007, the DWR terminated a long-term power purchase agreement it had with Calpine Corporation over the objections of the Utility and other interested parties. As a result, the Utility has had to purchase replacement power on behalf of its customers at a significantly higher price. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as the contracts expire or are terminated. For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies - Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.
Third-Party Power Purchase Agreements
Qualifying Facility Power Purchase Agreements. As of December 31, 2007, the Utility had agreements with 257 QFs for approximately 4,097 MW that are in operation. Agreements for approximately 3,754 MW expire at various dates between 2008 and 2028. QF power purchase agreements for approximately 343 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with approximately 74 inoperative QFs. The total of approximately 4,097 MW consists of approximately 2,524 MW from cogeneration projects, 580 MW from wind projects and 994 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. QF power purchase agreements accounted for approximately 20%, 20%, and 22% of the Utility’s 2007, 2006, and 2005 electricity sources, respectively. No single QF accounted for more than 5% of the Utility's 2007, 2006, or 2005 electricity sources.
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, whether or not any hydroelectric power is supplied, and variable
payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2008 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 3% of the Utility’s 2007 electricity sources, approximately 6% of the Utility’s 2006 electricity sources and 5% of the Utility’s 2005 electricity sources.
Renewable Energy Contracts. California law requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of renewable energy (such as biomass, wind, solar, and geothermal energy) by at least 1% of its retail sales, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2010. The CPUC has adopted "flexible compliance" rules, which allow deliveries above interim required levels to be carried forward, permit a retail seller to maintain a procurement deficit for up to three years following the year in which the deficit is incurred, and may, in certain cases, provide allowable reasons for noncompliance. During 2007, the Utility entered into 9 new renewable power purchase agreements, representing approximately 3,000 GWh per year of renewable generation that will help the Utility to meet its goals. The Utility expects to use the flexible compliance Rules to meet the 2010 requirement. Failure to satisfy the targets may result in a penalty of five cents per kWh, with an annual penalty cap of $25 million. The exact amount of any penalty and conditions under which it would be applied are subject to the CPUC’s review of whether supply-side factors or other circumstances caused the under-delivery.
Long Term Power Purchase Agreements. In December 2007, the CPUC approved, with several modifications, the long-term electricity procurement plans (“LTPPs”) of the California investor-owned electric utilities covering the 10-year period from 2007 through 2016. Each utility is required to submit an LTPP designed to reduce greenhouse gas emissions and uses the State of California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation). The decision notes that if a previously approved contract is terminated before the generation project is built, the utilities will retain the procurement authority for the MWs subject to the terminated contract. At the end of the solicitation or request-for-offer (“RFO”) process, the utilities must justify why each bid was selected or rejected. Utilities can acquire ownership of new conventional generation resources in the utilities’ competitive RFO process only through turnkey and engineering, procurement, and construction arrangements proposed by third parties. The utilities are required to submit revised LTPPs reflecting the changes required by the CPUC within 90 days of the date the decision is mailed.
For more information regarding the Utility's power purchase contracts, see Note 17: Commitments and Contingencies- Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.
Future Long-Term Generation Resources
On December 20, 2007, the CPUC issued a decision that approves, with several modifications, the California investor-owned utilities’ long-term electricity procurement plan covering procurement during 2007-2016. The CPUC forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of new conventional generation by 2015 based on forecasts prepared by the CEC. The decision finds that in earlier years (i.e., 2007-2013), the Utility has a surplus of resources and in 2014 the forecast shows a small need for 66 MW.
The decision allows the utilities to acquire ownership of new conventional generation resources only through turnkey and engineering, construction, and procurement (“EPC”) arrangements proposed by third parties. The decision prohibits the utilities from submitting bids for utility-build generation in their respective RFOs until questions can be resolved about how to compare utility-owned generation bids with bids from independent power producers. The decision also permits utility-owned generation projects to be proposed through a separate application outside of the RFO process in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to expand existing facilities, (4) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement) and (5) to meet unique reliability needs.
Electricity Transmission
At December 31, 2007, the Utility owned 18,680 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 54,709 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 140,684 circuit miles of distribution lines and substations with a capacity of 26,370 MVA. In 2007, the Utility delivered 86,179 GWh to its customers, including 6,723 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 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO. The Utility has entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego
Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO.The Utility is required to give the CAISO two years’ notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.
The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998. In addition, under the mandatory reliability standards implemented following EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards. See the discussion of reliability standards above under “The Utility’s Regulatory Environment- Federal Energy Regulation.”
In April 2006, the Utility completed a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line. The completed transmission line provides additional transmission system reliability in San Francisco and northern San Mateo County. As result of the completion of the transmission line, the Utility was able to retire the Hunters Point power plant in San Francisco. The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO. (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO's demand when the generation from those RMR units is needed for local transmission system reliability.) Potential transmission projects include a 500-kV transmission line to increase access to southern California and Southwest generation resources and to reduce RMR generation contracts in the Fresno, California area (referred to as the “Central California Clean Energy Transmission Project”) and a high voltage transmission line between Northern California and British Columbia, Canada to access renewable generation resources in British Columbia. In addition, the Utility is currently working with several stakeholders in the western United States to assess the feasibility of new large-scale electric transmission expansion projects to address regional electricity needs over the long term.
In December 2007, the FERC approved a settlement between the Utility and PacifiCorp, both owners of an electric transmission line which is part of the California - Oregon Intertie (“COI”), as well as other entities, relating to the termination of agreements that govern transmission service over the COI. The COI is a major electric transmission link connecting California with the Pacific Northwest and vital to electric grid reliability. The settlement provides for the shared usage and coordinated planning, operation, and maintenance of the eastern 500 kV transmission line between the Malin substation in Oregon and the Round Mountain substation in California. As a result of the settlement, the Utility and PacifiCorp will each have rights to half of the capacity on the eastern 500 kV transmission line between the Malin and Round Mountain substations for a twenty year period. In addition, the Utility will lease back a portion of the capacity allocated to PacifiCorp for the first ten years. The settlement allows the Utility to continue its rights to all existing available transmission service over the eastern 500 KV line between the Malin and Round Mountain substations through December 31, 2011; these rights decrease to half of the total capacity by 2018. The settlement also provides that the Utility’s lease payments to PacifiCorp will be fully recovered through the Utility’s transmission owner rates.
Electricity Distribution Operations
The Utility's electricity distribution network extends through 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 140,684 circuit miles of distribution lines (of which approximately 19% are underground and approximately 81% are overhead). There are 93 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 605 distribution substations and 110 low-voltage distribution substations. The 54 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 1,106 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 other facilities to entities, such as
municipal and other utilities, that then resell the electricity.
During 2006, the Utility began the installation of an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility's electric and gas customers. These meters will enable the Utility to measure usage on an hourly basis for electricity and on a daily basis for natural gas, which will allow for demand-response rates to encourage customers to reduce energy consumption during peak demand periods, thus reducing peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility expects to complete the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011. On December 12, 2007, the Utility filed an application with the CPUC requesting approval to upgrade elements of the Utility’s SmartMeter™ program. The Utility seeks approval to install solid-state electric meters and associated devices that would offer an expanded range of service features for customers and increased operational efficiencies for the Utility. These upgraded meters and associated devices would provide additional energy conservation and demand response options for electric customers. In addition, the solid-state electric meters are designed to facilitate the Utility’s ability to incorporate future advanced metering technology innovations in a timely and cost-effective manner. (For more information about the advanced metering infrastructure, see the section entitled “Capital Expenditures” in the MD&A portion of the 2007 Annual Report.)
2007 Electricity Deliveries
The following table shows the percentage of the Utility's total 2007 electricity deliveries represented by each of its major customer classes:
Total 2007 Electricity Delivered: 86,179 GWh
Electricity Distribution Operating Statistics
The following table shows certain of the Utility's operating statistics from 2003 to 2007 for electricity sold or delivered, including the classification of sales and revenues by type of service.
(1)
Starting in 2005, the Utility’s methodology used to count customers changed from the number of billings to the number of active service agreements.
(2)
These amounts include electricity provided to direct access customers who procure their own supplies of electricity.
(3)
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.
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 39 of California's 58 counties and includes most of northern and central California. In 2007, the Utility served approximately 4.3 million natural gas distribution customers. The total volume of natural gas throughput during 2007 was approximately 875 Bcf.
As of December 31, 2007, the Utility's natural gas system consisted of 41,805 miles of distribution pipelines, 6,393 miles of backbone and local transmission pipelines, and three storage facilities. The Utility's distribution network connects to the Utility's transmission and storage system at approximately 2,200 major interconnection points. The Utility’s backbone transmission system, composed primarily of Lines 300, 400 and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution system. 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. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 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, the Rocky Mountains 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 connected to the Utility's transmission and storage system. These storage fields have a combined firm capacity of approximately 47 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.
In September 2007, the Utility announced that it had entered into an agreement with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, to develop an underground natural gas storage facility near Fresno, California. The new storage facility would provide approximately 20 Bcf of total capacity once the initial phase is completed, expected in 2010. On February 4, 2008, the parties executed a Joint Project Agreement which provides the Utility a 25% interest in the initial project phase. Development of the project is subject to CPUC issuance of a Certificate of Public Convenience and Necessity and an environmental review to be conducted by the CPUC under the California Environmental Quality Act. The parties plan to file an application with the CPUC in May 2008.
The CPUC divides the Utility's natural gas customers into two categories: core and non-core 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 non-core customer class is comprised of industrial, larger commercial and electric generation natural gas customers. In 2007, core customers represented more than 99% of the Utility's total customers and 38% of its total natural
gas deliveries, while non-core customers comprised less than 1% of the Utility's total customers and 62% of its total natural gas deliveries.
The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility's system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as bundled natural gas service. Currently, over 99% of core customers, representing over 96% of core market demand, receive bundled natural gas service from the Utility.
The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service through that avenue. Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utility's procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.
The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility's backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.
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 weather variations, conservation or changes in their consumption levels. The Utility's results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utility's natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.
The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2006 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 1.3% for the years 2006 through 2025. 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, price, and the number and location of electricity generation facilities.
2007 Natural Gas Deliveries
The following table shows the percentage of the Utility's total 2007 natural gas deliveries represented by each of the Utility's major customer classes:
Total 2007 Natural Gas Deliveries: 875 Bcf
Natural Gas Operating Statistics
The following table shows the Utility's operating statistics from 2003 through 2007 (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 2007, the Utility purchased approximately 278,076 Mcf of natural gas (net of the sale of excess supply) from 67 suppliers. Consistent with existing CPUC policy directives, substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility's largest individual supplier represented approximately 11% of the total natural gas volume the Utility purchased during 2007.
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 2007, 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 natural gas from third-party wells in California. During 2007, approximately 6% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 117.26 miles of gas gathering pipelines. The Utility receives gas well production at approximately 230 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 8 California counties. Approximately 132 MMcf per day of natural gas produced in northern California was delivered into the Utility's gas gathering system during 2007.
Interstate and Canadian Natural Gas Transportation Services Agreements
In 2007, approximately 60% of the gas transported on the Utility's system 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 Foothills Pipe Lines Ltd., B.C. System. hese companies' pipeline systems connect at the border to the pipeline system owned by TransCanada’s Gas Transmission Northwest Corporation (“GTN”) which provides natural gas transportation services to a point of interconnection with the Utility's natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has a firm transportation agreement with GTN for these services. As described below, as part of the FERC-approved all-party settlement of GTN’s most recent general rate case, the Utility’s contract with GTN will be replaced beginning November 1, 2009 by three smaller contracts totaling the same amount with staggered terms.
During 2007, approximately 34% of the gas transported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company 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 in effect during 2007, 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 Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases. The Utility may, upon prior notice and with the CPUC’s approval, extend each of these natural gas transportation agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights 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.
(1)
A small portion (23 MDth/d) of the Utility’s capacity is due to expire on October 31, 2009.
(2)
As of December 31, 2007, the Utility had four active contracts with El Paso with expiration dates ranging from February 29, 2008 to June 30, 2012.
(3)
This contract was not renewed.
As required by the all-party settlement of GTN’s most recent general rate case approved by the FERC on January 7, 2008, the Utility has entered into three smaller contracts with GTN with terms that begin on November 1, 2009 and terminate on various dates unless renewed, as follows:
Also, as part of the same settlement, the Utility has entered into a separate contract with GTN for firm transportation service to support the Utility’s need for natural gas for electric power plant fuel. This new contract is for a quantity of 50 MDth/d for a 59-month term, July 1, 2009, through May 31, 2014.
The settlement sets rates on the GTN pipeline for a minimum term of five years commencing January 1, 2007, and provides for substantial refunds to the Utility and other shippers for the higher rates paid since that time. The Utility estimates it will receive refunds on behalf of customers of approximately $24 million by early April 2008. For contract commitments extending beyond December 31, 2011, the Utility will be obligated to pay the then-effective GTN rate as set by the FERC.
In addition, in December 2007, the Utility entered into an agreement to subscribe for 375 MDth per day of firm service rights on the proposed Ruby Pipeline for a 15-year term commencing in 2011, when the pipeline is proposed to be placed into service. The Utility’s commitment is contingent upon the satisfaction of certain conditions precedent, including CPUC approval. (For more information, see “Competition” above.) The Utility expects the CPUC will issue a decision by the end of 2008.
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 measures. The information below reflects current estimates, which are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, and the availability of 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:
·
the discharge of pollutants into air, water and soil;
·
the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, remediation and emergency response in connection with hazardous and radioactive substances; and
·
environmental impacts of 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’s wastes may have been disposed.
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 the clean-up of sites that contain hazardous substances are subject to a special ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims from customers (e.g., for costs of cleaning up the Utility's facilities and sites where the Utility’s hazardous substances have been sent). This mechanism allows the Utility to include 90% of eligible hazardous waste remediation costs in the Utility's rates without a reasonableness review. Ten percent of any net insurance recoveries associated with hazardous waste remediation sites is assigned to the Utility's customers. The balance of any insurance recoveries (90%) is retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels are allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utility's claims against third parties associated with hazardous waste remediation sites is retained by the Utility, with the remainder, 90% of any such recoveries, assigned to the Utility's customers.
Hazardous waste remediation costs are rising and are likely to be significant into the foreseeable future. Based on the Utility's past experience, it believes that it can recover most of the future costs that it may incur to remediate hazardous waste through rates and insurance recoveries. 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 and Climate Change
The Utility's electricity generation plants, natural gas pipeline operations, fleet and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act as well as 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. In addition, various laws and regulations addressing climate change are being considered or implemented at the federal and state levels, as discussed below. Fossil fuel-fired 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.
The Utility’s existing and forecast emissions of climate-changing “greenhouse gases,” or GHGs, are relatively low compared to average emissions by other electric utilities and generators in the country, but the Utility anticipates that it will be affected by the increasing attention of the federal and state government to the control of GHGs is gaining increasing attention. At the federal level, several legislative initiatives have been introduced recently in Congress aimed at addressing climate change through imposition of nation-wide regulatory limits on the emissions of GHGs. No such legislation has yet been enacted by Congress, but extensive hearings and discussion are expected in the coming year. At the state level, in 2006 California enacted Assembly Bill 32 (“AB 32”), the California Global Warming Solutions Act of 2006, to address climate change. AB 32 establishes a regulatory program and schedule to gradually reduce GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. AB 32 also authorizes the California Air Resources Board (“CARB”) to monitor and enforce compliance with the GHG reduction program and to consider implementing market-based mechanisms, including trading of GHG emissions allowances. Pursuant to AB 32, on December 6, 2007, the CARB adopted a state-wide GHG 1990 emissions baseline of 427 million metric tons of carbon dioxide (or its equivalent). This 1990 baseline serves as the 2020 emissions reduction target for the state of California. The CARB has not yet determined reduction goals applicable to the utility sector or individual utilities within the utility sector. The CARB also adopted a GHG reporting regulation that will require reporting of 2008 GHG emissions in 2009. The Utility will be required to submit verified GHG emissions reports under CARB’s reporting regulation. AB 32 requires CARB to adopt a Scoping Plan by January 2, 2009 for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target.
California Senate Bill 1368, also enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload electricity generation unless the generation complies with a GHG emission performance standard. As required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim GHG emissions performance standard of 1,100 pounds of carbon dioxide per MWh that applies to new commitments for baseload electricity procured under contracts with a term of five years or longer or generated by the Utility. After a state-wide GHG emissions limit is established and is in operation, in accordance with AB 32, the CPUC will re-evaluate its interim GHG emissions performance standard and determine whether to continue, modify or rescind it.
The new California legislation, as well as current federal and other state regulatory initiatives relating to emissions of carbon dioxide and other GHGs, particulates and other pollutants, could cause the Utility's compliance costs and capital expenditures to increase. 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 will recover these costs and capital expenditures in rates consistent with the recovery of other reasonable costs of complying with
environmental laws and regulations.
Water Quality
The Utility's Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System (“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board (“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 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 under which the Central Coast Board 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 reflects the best technology available, as defined in the federal Clean Water Act. As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to 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 settlement agreement. On June 17, 2003, the 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.
At its meeting on July 10, 2003, 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 the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers.
In July 2004, the U.S. Environmental Protection Agency (“EPA”) published regulations under Section 316(b) of the Clean Water Act that apply to existing electricity generation facilities that use over 50 million gallons of water per day, which typically include some form of "once-through" cooling in which water from natural bodies of water is used to cool a generating facility and the heated water is discharged back into the source. The Utility's Diablo Canyon power plant is among an estimated 539 generation facilities nationwide that are affected by this rulemaking. The EPA regulations are intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations allow site-specific compliance measures if a facility's cost of compliance is significantly greater than either the benefits to be achieved or the compliance costs considered by the EPA. The EPA regulations also allow the use of environmental mitigation or restoration to meet compliance requirements in certain cases. In response to the EPA regulations, in June 2006, the California State Water Resources Control Board (“Water Board”) published a draft policy for California’s implementation of Section 316(b) that proposes to eliminate the EPA’s site-specific compliance options, although the draft state policy would permit environmental restoration as a compliance option for nuclear facilities if the installation of cooling towers would conflict with a nuclear safety requirement. Various parties separately challenged the EPA's regulations in court, and the cases were consolidated in U.S. Court of Appeals for the Second Circuit (“Second Circuit”). In January 2007, the Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and held that a cost-benefit test could not be used to comply with performance standards or to obtain a variance from the standards. The Second Circuit also ruled that environmental restoration cannot be used to comply with the standard. Petitions seeking Supreme Court review of the Second Circuit’s decision are pending, and the EPA has suspended its regulations. It is uncertain when the EPA will issue revised regulations, whether the Supreme Court will accept review of the Second Circuit decision, how judicial developments will affect the EPA’s revised regulations; how judicial developments and EPA’s revised regulations will affect the Water Board’s proposed policy, and when the Water Board will issue its final policy. Depending on the nature of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations which the Utility would seek to recover through rates. If either the final regulations adopted by the EPA or the Water Board require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon.
Compressor Station Litigation
Several lawsuits have been filed against the Utility alleging that exposure to chromium at or near the Utility's natural gas compressor stations caused personal injuries, wrongful deaths or other injuries. During 2006, the Utility entered into a settlement
agreement to resolve most of these claims. Pursuant to the settlement agreement, in April 2006 the Utility released $295 million from escrow for payment to approximately 1,100 plaintiffs. Three complaints, filed by approximately 125 plaintiffs who did not participate in the settlement, are still pending in the Superior Court for the County of Los Angeles. During 2007 some individual plaintiffs’ claims were dismissed based on the applicable statute of limitations. Also, during 2007 the Utility agreed to settle with the remaining plaintiffs, subject to execution of final documentation and court approval of the settlement of the minor plaintiffs' claims which is expected to occur during the first half of 2008. PG&E Corporation and the Utility do not expect that the settlement will have a material adverse effect on their financial condition or results of operations.
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 at or near the Utility's facilities or operations. The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with 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 (“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“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, and in some cases corporate successors to the operators or arrangers. 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 hazardous substances 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. Additionally, the Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. Preliminary remedial investigations are underway, with agency approval of a remediation plan expected by second quarter 2009. The Utility estimates that it will spend approximately $16.6 million in 2008 and approximately $22.7 million in 2009 for these activities.
In addition, the federal Toxic Substances Control Act regulates the use, disposal and clean-up of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. The Utility has removed from service all of the distribution capacitors and network transformers containing high concentrations of PCBs, representing the vast majority of PCBs that had existed 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 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 residues from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. There are 95 such sites within the Utility’s service territory that are owned by the
Utility or third parties. The Utility has determined that it is liable for the remediation of 42 sites, is potentially liable for remediation of an additional 33 sites, and is not liable for remediation at the
remaining 20 sites. The Utility has a program, in cooperation with environmental agencies and third party owners, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at the 42 sites for which the Utility is liable. The Utility spent approximately $7 million in 2007 and expects to spend approximately $25 million in 2008 on these sites. The Utility expects that expenses at these sites will increase as remedial actions related to these sites are approved by regulatory agencies and claims by third party owners are settled. The Utility is implementing a new program to analyze potential liability for remediation at the 33 additional sites. Although it is likely that the Utility will incur remediation costs related to some of these sites the Utility cannot quantify the potential amount.
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 clean-up costs or natural resource damages. The Utility is currently aware of six such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility substantially completed closure of the disposal facility, which was abandoned by its operator. The Utility was the major responsible party and led the remediation effort on behalf of the responsible parties. For the Casmalia disposal facility near Santa Maria, California, the Utility and several parties that sent waste 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 remediation 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.
Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility has a comprehensive program to monitor a network of groundwater wells at both the Hinkley and Topock natural gas compressor stations. At Hinkley, the Utility is cooperating with the Regional Water Quality Control Board to evaluate and remediate the chromium groundwater plume. In 2006, the Utility took interim measures to control movement of the Hinkley plume, and evaluated options to remediate the plume. At the Topock gas compressor station, located near Needles, California, hexavalent chromium has been detected in samples taken from groundwater monitoring wells located approximately 65 feet from the Colorado River, which is adjacent to the site. The Utility, in cooperation with the California Department of Toxic Substances Control, other state agencies and appropriate federal agencies, has implemented interim measures including a system of extractions wells and a treatment plant designed to prevent movement of the plume toward the river. In addition the Utility is working with the agencies to develop a long-term plan to ensure that the hexavalent chromium does not affect the Colorado River. In 2007, the Utility spent approximately $23 million on the interim measures and for work on the longer term site solution. The Utility plans to continue these activities in 2008 and to work toward the development of a final plan to address the plume in 2008. The Utility currently estimates that it will spend at least $20 million in 2008 for remediation activities at Topock and $14 million in 2008 for remediation activities at Hinkley. Although work at the Topock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described above. The Utility does not expect the remediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on its results of operations or financial condition. The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.
The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of reasonably likely clean-up costs. The Utility reviews its remediation liability on a quarterly basis for each site where it 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, and considers enacted laws and regulations, experience gained at similar sites, and an assessment of 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. The Utility estimates the upper end of this cost range using reasonably possible outcomes that are least favorable to the Utility. 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 had an undiscounted environmental remediation liability of approximately $528 million at December 31, 2007 and approximately $511 million at December 31, 2006. The Utility’s undiscounted future costs could increase to as much as $834 million if necessary remediation is greater than anticipated.
For more information about environmental remediation liabilities, see Note 17 of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.
Nuclear Fuel Disposal
As part of the Nuclear Waste Policy Act of 1982, Congress authorized the DOE and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities' spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay. The DOE failed to develop a permanent storage site by January 31, 1998. The Utility believes that the existing spent fuel pools at Diablo Canyon (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until approximately 2010 for Unit 1 and 2011 for Unit 2.
Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the NRC to build an on-site dry cask storage facility to store spent fuel through at least 2024. After various parties appealed the NRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit issued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the potential environmental consequences in the event of a terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats. In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility. On January 15, 2008, the NRC decided to hold hearings on whether it provided a complete list of the references upon which it relied to find that there would not be a significant environmental impact and whether it sufficiently addressed the impacts on land and the local economy of a potential terrorist attack. It is expected that the NRC will issue a final decision in the third quarter of 2008.
The Utility expects to complete the dry cask storage facility and begin loading spent fuel in 2008. If the Utility is unable to complete the dry cask storage facility, if operation of the facility is delayed beyond 2010, or if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 and continued until such time as additional safe storage for spent fuel is made available.
The Utility and other nuclear power plant owners have sued the DOE for breach of contract. The Utility seeks to recover its costs to develop on-site storage at Diablo Canyon and Humboldt Bay Unit 3. In October 2006, the U.S. Court of Federal Claims found the DOE had breached its contract and awarded the Utility approximately $42.8 million of the $92 million incurred by the Utility through 2004. The Utility appealed to the U.S. Court of Appeals for the Federal Circuit seeking to increase the amount of the award and challenged the U.S. Court of Federal Claims’ finding that the Utility would have incurred some of the costs for the on-site storage facilities even if the DOE had complied with the contract. A decision on the appeal is expected by the end of 2008. The Utility will seek to recover costs incurred after 2004 in future lawsuits against the DOE. Any amounts recovered from the DOE will be credited to customers through rates.
PG&E Corporation and the Utility are unable to predict the outcome of this appeal or the amount of any additional awards the Utility may receive. If the U.S. Court of Federal Claims’ decision is not overturned or modified on appeal, it is likely that the Utility will be unable to recover all of its future costs for on-site storage facilities from the DOE. However, reasonably incurred costs related to the on-site storage facilities are, in the case of Diablo Canyon, recoverable through rates and, in the case of Humboldt Bay Unit 3, recoverable through its decommissioning trust fund.
Nuclear Decommissioning
The Utility's nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay Unit 3. 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 makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding (“NDCTP”), used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and be completed in 2044; that decommissioning of Diablo Canyon Unit 2 would be scheduled to begin in 2025 and be completed in 2041; and that decommissioning of Humboldt Bay Unit 3 would be scheduled to begin in 2009 and be completed in 2015. The Utility’s decommissioning cost estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates, regulatory requirements, technology, and costs of labor, materials and equipment. The Utility recovers its revenue requirements for estimated nuclear decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for
decommissioning and dismantling the Utility's nuclear facilities.
For more information about nuclear decommissioning, including the estimated decommissioning costs, see Note 13 of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.
Electric and Magnetic Fields
Electric and magnetic fields (“EMFs”) naturally result from the generation, transmission, distribution and use of electricity. 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. In October 2002, the California Department of Health Services released its report to the CPUC and the public, based primarily on its review of studies by others, evaluating the possible risks from EMFs. 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 of a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.
On January 26, 2006, the CPUC issued a decision which affirms the CPUC’s “low-cost/no-cost, prudent avoidance” policy to reduce EMF exposure for new utility transmission and substation projects. The CPUC ordered the continued use of a 4% of project cost benchmark for EMF reduction measures. The CPUC also reaffirmed that it has exclusive jurisdiction with respect to utility EMF matters.
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. In a case involving allegations of personal injury, a California appeals court 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. The California Supreme Court declined to hear the plaintiffs’ appeal of this decision.
Item 1A.
Item 1A. Risk Factors
A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading “Risk Factors” in the MD&A in the 2007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
Item 1B.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2.
Item 2. Properties
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 “Electric Utility Operations” and “Natural Gas Utility Operations” above. In total, the Utility occupies 9.8 million square feet of real property, including 8.5 million square feet that the Utility owns. Of the 9.8 million square feet of occupied real property, approximately 1.7 million square feet represent the Utility's corporate headquarters located in several buildings in San Francisco, California. The Utility leases approximately 120,000 square feet of the approximate 1.7 million square feet of 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 167,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements and/or donate to public agencies or non-profit conservation organizations under the Chapter 11 Settlement Agreement. Approximately 75,000 acres of this land may be donated in fee and encumbered with conservation easements. The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and will only be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council (“Council”) to oversee the development and implementation of a Land Conservation Plan (“LCP”) that will articulate the long-term management objectives for the 140,000 acres. The Council is governed by an 18-member Board of Directors that represents a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials. The Utility has appointed 1 out of 18 members of the Board of Directors of the Council. In December 2007, the Council adopted the LCP and submitted it to the Utility.
The Utility has accepted the LCP and will seek authorization from the CPUC, the FERC and other approving entities to proceed with the transactions necessary to implement the LCP.
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 2012.
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.
Diablo Canyon Power Plant
The Utility's Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System (“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board (“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 and the Central Coast Board reached a tentative settlement under which the Central Coast Board 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 reflects the best technology available, as defined in the federal Clean Water Act. As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to 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 settlement agreement. On June 17, 2003, the 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.
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 the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers. The California State Water Resources Control Board is developing a state policy for the implementation of Section 316(b) of the Clean Water Act, the adoption of which could affect future negotiations between the Central Coast Board and the Utility. For more information about the draft state policy, see “Environmental Matters-Water Quality” in this report.
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their Utility's financial condition or results of operations.
Complaints Filed by the California Attorney General and the City and County of San Francisco
On January 10, 2002, the California Attorney General filed a complaint in the Superior Court for the County of 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 (“Section 17200”). Among other allegations, the California Attorney General alleged that past transfers of funds from the Utility to PG&E Corporation during the period from 1997 through 2000 (primarily in the form of dividends and stock repurchases), 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 alleged that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis.
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.
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 the Superior Court. The complaint contains some of the same allegations contained in the California Attorney General's complaint, including allegations of unfair competition in violation of Section 17200. 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 and County of San Francisco (“CCSF”) seeks injunctive relief, the appointment of a receiver, restitution, disgorgement, the imposition of a constructive trust, civil penalties of $2,500 against each defendant for each violation of Section 17200 and costs of suit.
The complaints, which have been consolidated in the Superior Court, were filed after the CPUC issued two decisions in its investigative proceeding commenced in April 2001 into whether the California investor-owned electric utilities, including the Utility, 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 would, among other matters, 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. In May 2005, the CPUC closed this investigation without making any findings.
PG&E Corporation believes that the intercompany transactions challenged by the California Attorney General and CCSF were in full compliance with applicable law and CPUC conditions. The challenged transactions forming the bulk of the restitution claims were regular quarterly dividends and stock repurchases. As part of its annual cost of capital proceedings, the Utility advised the CPUC in advance of its forecast stock repurchases and dividends. The CPUC did not challenge or question those payments.
In January 2006, the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision on the parties’ appeals of various rulings by the Bankruptcy Court and the U.S. District Court for the Northern District of California concerning jurisdictional issues. The Ninth Circuit found that the Superior Court had jurisdiction over the California Attorney General’s and CCSF’s restitution claims. (In October 2006, the U.S. Supreme Court declined to grant PG&E Corporation’s request to review the Ninth Circuit’s decision.) The Ninth Circuit did not address the California Attorney General’s and CCSF’s underlying allegations that PG&E Corporation and the other defendants violated Section 17200. The Ninth Circuit also did not decide the issue of who would be entitled to receive the proceeds, if any, of a restitution award, and PG&E Corporation continues to believe that any such proceeds would be the property of the Utility. Pursuant to the Chapter 11 Settlement Agreement, the CPUC released all claims against PG&E Corporation or the Utility arising out of or in any way related to the energy crisis, including the CPUC’s investigation into past PG&E Corporation actions during the California energy crisis. Accordingly, PG&E Corporation believes that any claims for such proceeds by the CPUC would be precluded.
While the Ninth Circuit appeal was pending, the Superior Court held a trial in December 2004 to consider the appropriate standard to determine what constitutes a separate violation of Section 17200 in order to determine the magnitude of potential penalties under Section 17200 (up to $2,500 per separate “violation”). The Superior Court did not address the question of whether any violations occurred. In March 2005, the Superior Court issued a decision rejecting the “per victim” and “per [customer] bill” approaches advocated by the plaintiffs, standards that potentially could have resulted in millions of separate “violations.” The Superior Court found that the appropriate standard was each transfer of money from the Utility to PG&E Corporation that plaintiffs allege violated Section 17200. In July 2005, the California Court of Appeal summarily denied a petition filed by the California Attorney General and CCSF seeking to overturn this decision. The next case management conference in Superior Court is scheduled on May 13, 2008.
PG&E Corporation believes that the California Attorney General’s and CCSF’s allegations have no merit and will continue to vigorously respond to and defend against the litigation. PG&E Corporation believes that the ultimate outcome of this matter would not result in a material adverse effect on PG&E Corporation’s financial condition or results of operations.
Solano County District Attorney’s Office
In a letter dated July 11, 2007, the Solano County District Attorney's Office stated its intention to file a civil complaint against the Utility for record-keeping violations related to an underground storage tank at the Utility’s service center in Vallejo, California. The letter attached a copy of the draft complaint, which detailed a series of alleged California Health and Safety Code record-keeping violations, some of which date back to 2004. Alleged violations include failing to complete inspections, testing, and certifications, and to make records available to the County. Under the California Health and Safety Code, penalties of up to $5,000 per day for each violation may be assessed. The draft complaint also seeks penalties for unfair and unlawful business practices under California Business and Professions Code Section 17200, under which penalties of up to $2,500 per violation may be assessed. There
are no allegations related to the discharge of any hazardous substances. The Utility is investigating the allegations and has entered into discussions with the District Attorney. The Utility believes that the ultimate outcome of this matter would not result in a material adverse effect on its financial condition or 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 (“Exchange Act”) at February 20, 2008, are as follows:
Name
Age
Position
Peter A. Darbee
Chairman of the Board, Chief Executive Officer, and President
Kent M. Harvey
Senior Vice President and Chief Risk and Audit Officer
Christopher P. Johns
Senior Vice President, Chief Financial Officer, and Treasurer
Nancy E. McFadden
Senior Vice President, Public Affairs
William T. Morrow
President and Chief Executive Officer, Pacific Gas and Electric Company
Hyun Park
Senior Vice President and General Counsel
Greg S. Pruett
Senior Vice President, Corporate Relations
Rand L. Rosenberg
Senior Vice President, Corporate Strategy and Development
John R. Simon
Senior Vice President, Human Resources
All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 20, 2008, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.
Name
Position
Period Held Office
Peter A. Darbee
Chairman of the Board, Chief Executive Officer, and President
September 19, 2007 to present
Chairman of the Board and Chief Executive Officer
July 1, 2007 to September 18, 2007
Chairman of the Board, Chief Executive Officer, and President
January 1, 2006 to June 30, 2007
Chairman of the Board, Pacific Gas and Electric Company
January 1, 2006 to May 31, 2007
President and Chief Executive Officer
January 1, 2005 to December 31, 2005
Senior Vice President and Chief Financial Officer
September 20, 1999 to December 31, 2004
Kent M. Harvey
Senior Vice President and Chief Risk and Audit Officer
October 1, 2005 to present
Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company
November 1, 2000 to September 30, 2005
Christopher P. Johns
Senior Vice President, Chief Financial Officer, and Treasurer
October 4, 2005 to present
Senior Vice President and Treasurer, Pacific Gas and Electric Company
June 1, 2007 to present
Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company
October 1, 2005 to May 31, 2007
Senior Vice President, Chief Financial Officer, and Controller
January 1, 2005 to October 3, 2005
Senior Vice President and Controller
September 19, 2001 to December 31, 2004
Nancy E. McFadden
Senior Vice President, Public Affairs
March 1, 2007 to present
Senior Vice President, Public Affairs, Pacific Gas and Electric Company
June 20, 2007 to present
Vice President, Governmental Relations, Pacific Gas and Electric Company
September 26, 2005 to February 28, 2007
Chairperson, California Medical Assistance Commission
November 13, 2003 to November 30, 2005
Senior Advisor and Deputy Chief of Staff, Office of Governor Gray Davis
May, 2001 to November, 2003
William T. Morrow
President and Chief Executive Officer, Pacific Gas and Electric Company
July 1, 2007 to present
President and Chief Operating Officer, Pacific Gas and Electric Company
August 1, 2006 to June 30, 2007
Chief Executive Officer, Europe, Vodafone Group PLC (a global mobile telecommunications company)
May 1, 2006 to July 31, 2006
President, Vodafone KK, Japan
April 1, 2005 to April 30, 2006
Chief Executive Officer, Vodafone UK, Ltd.
February 1, 2004 to March 31, 2005
President, Japan Telecom Holdings Co., Inc.
December 21, 2001 to January 31, 2004
Hyun Park
Senior Vice President and General Counsel
November 13, 2006 to present
Vice President, General Counsel, and Secretary, Allegheny Energy, Inc. (an investor-owned utility company headquartered in Pennsylvania)
April 5, 2005 to October 17, 2006
Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc.
March 2000 to February 2005
Greg S. Pruett
Senior Vice President, Corporate Relations
November 1, 2007 to present
Vice President, Corporate Relations
March 1, 2007 to October 31, 2007
Vice President, Communications and Marketing, American Gas Association
April 10, 2006 to February 23, 2007
Chief Public Affairs Officer, Bechtel National, Inc.
June 12, 2004 to September 12, 2005
Vice President, Corporate Communications, PG&E Corporation
January 1, 1998 to September 12, 2003
Rand L. Rosenberg
Senior Vice President, Corporate Strategy and Development
November 1, 2005 to present
Executive Vice President and Chief Financial Officer, Infospace, Inc.
September 2000 to January 20, 2001
John R. Simon
Senior Vice President, Human Resources
April 16, 2007 to present
Senior Vice President, Human Resources, Pacific Gas and Electric Company
April 16, 2007 to present
Executive Vice President, Global Human Capital, TeleTech Holdings, Inc.
March 21, 2006 to April 13,2007
Senior Vice President, Human Capital, TeleTech Holdings, Inc.
July 31, 2001 to March 20, 2006
The names, ages and positions of the Utility's “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 20, 2008, are as follows:
Name
Age
Position
Peter A. Darbee
Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
William T. Morrow
President and Chief Executive Officer
Thomas E. Bottorff
Senior Vice President, Regulatory Relations
Helen Burt
Senior Vice President and Chief Customer Officer
Christopher P. Johns
Senior Vice President and Treasurer
John S. Keenan
Senior Vice President and Chief Operating Officer
Patricia M. Lawicki
Senior Vice President and Chief Information Officer
Nancy E. McFadden
Senior Vice President, Public Affairs
Hyun Park
Senior Vice President and General Counsel, PG&E Corporation
Greg S. Pruett
Senior Vice President, Corporate Relations, PG&E Corporation
Edward A. Salas
Senior Vice President, Engineering and Operations
John R. Simon
Senior Vice President, Human Resources
Geisha J. Williams
Senior Vice President, Energy Delivery
G. Robert Powell
Vice President, Chief Financial Officer, and Controller
Fong Wan
Vice President, Energy Procurement
All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 20,
2008, 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.
Name
Position
Period Held Office
Peter A. Darbee
Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
September 19, 2007 to present
Chairman of the Board and Chief Executive Officer, PG&E Corporation
January 1, 2006 to September 19, 2007
Chairman of the Board, Pacific Gas and Electric Company
January 1, 2006 to May 31, 2007
Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
January 1, 2006 to June 30, 2006
President and Chief Executive Officer, PG&E Corporation
January 1, 2005 to December 31, 2005
Senior Vice President and Chief Financial Officer, PG&E Corporation
July 9, 2001 to December 31, 2004
William T. Morrow
President and Chief Executive Officer
July 1, 2007 to present
President and Chief Operating Officer
August 1, 2006 June 30, 2007
Chief Executive Officer, Europe, Vodafone Group PLC (a global mobile telecommunications company)
May 1, 2006 to July 31, 2006
President, Vodafone KK, Japan
April 1, 2005 to April 30, 2006
Chief Executive Officer, Vodafone UK, Ltd.
February 1, 2004 to March 31, 2005
President, Japan Telecom Holdings Co., Inc.
December 21, 2001 to January 31, 2004
Thomas E. Bottorff
Senior Vice President, Regulatory Relations
October 14, 2005 to present
Senior Vice President, Customer Service and Revenue
March 1, 2004 to October 13, 2005
Vice President, Customer Service
June 1, 1999 to February 29, 2004
Helen Burt
Senior Vice President and Chief Customer Officer
January 9, 2006 to present
Vice President, Electric Transmission
July 1, 2005 to January 8, 2006
Vice President, Distribution Asset Management, American Electric Power
February 1, 2004 to June 30, 2005
Senior Vice President, Power and Gas, UMS Group, Inc.
October 1, 2001 to January 31, 2004
Christopher P. Johns
Senior Vice President and Treasurer
June 1, 2007 to present
Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation
October 4, 2005 to present
Senior Vice President, Chief Financial Officer, and Treasurer,
October 1, 2005 to May 31, 2007
Senior Vice President, Chief Financial Officer, and Controller, PG&E Corporation
January 1, 2005 to October 3, 2005
Senior Vice President and Controller, PG&E Corporation
September 19, 2001 to December 31, 2004
Patricia M. Lawicki
Senior Vice President and Chief Information Officer
November 1, 2007 to present
Vice President and Chief Information Officer
January 12, 2005 to October 31, 2007
Vice President, Chief Information Officer, NiSource, Inc.
April 23, 2003 to January 7, 2005
John S. Keenan
Senior Vice President and Chief Operating Officer
January 1, 2008 to present
Senior Vice President, Generation and Chief Nuclear Officer
December 19, 2005 to December 31, 2007
Vice President, Fossil Generation, Progress Energy
November 10, 2003 to December 18, 2005
Vice President, Brunswick Nuclear Plant, Progress Energy
May 1, 1998 to November 9, 2003
Nancy E. McFadden
Senior Vice President, Public Affairs
June 20, 2007 to present
Senior Vice President, Public Affairs, PG&E Corporation
March 1, 2007 to present
Vice President, Governmental Relations
September 26, 2005 to February 28, 2007
Chairperson, California Medical Assistance Commission
November 13, 2003 to November 30, 2005
Senior Advisor and Deputy Chief of Staff, Office of Governor Gray Davis
May 2001 to November 2003
Hyun Park
Senior Vice President and General Counsel, PG&E Corporation
November 13, 2006 to present
Vice President, General Counsel, and Secretary, Allegheny Energy, Inc. (an investor-owned utility company headquartered in Pennsylvania)
April 5, 2005 to October 17, 2006
Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc.
March 2000 to February 2005
Greg S. Pruett
Senior Vice President, Corporate Relations, PG&E Corporation
November 1, 2007 to present
Vice President, Corporate Relations, PG&E Corporation
March 1, 2007 to October 31, 2007
Vice President, Communications and Marketing, American Gas Association
April 10, 2006 to February 23, 2007
Chief Public Affairs Officer, Bechtel National, Inc.
June 12, 2004 to September 12, 2005
Vice President, Corporate Communications, PG&E Corporation
January 1, 1998 to September 12, 2003
Edward A. Salas
Senior Vice President, Engineering and Operations
April 11, 2007 to present
Staff Vice President, Network Planning, Verizon Wireless, Basking Ridge, N.J.
Contractor, Verizon Wireless, Local Number Portability Implementation
May 2004 to April 2007
May 2003 to April 2004
John R. Simon
Senior Vice President, Human Resources
April 16, 2007 to present
Senior Vice President, Human Resources, PG&E Corporation
April 16, 2007 to present
Executive Vice President, Global Human Capital, TeleTech
March 21, 2006 to April 13, 2007
Senior Vice President, Human Capital, TeleTech Holdings, Inc.
July 13, 2001 to March 20, 2006
Geisha J. Williams
Senior Vice President, Energy Delivery
December 1, 2007 to present
Vice President, Power Systems, Distribution, Florida Power and Light Company
July 2003 to July 2007
Vice President, Distribution Operations, Florida Power and Light Company
February 2002 to July 2003
G. Robert Powell
Vice President, Chief Financial Officer, and Controller
June 1, 2007 to present
Vice President and Controller
December 21, 2005 to May 31, 2007
Controller (Interim)
November 9, 2005 to December 20, 2005
Vice President and Controller, PG&E Corporation
October 4, 2005 to present
Partner, PricewaterhouseCoopers LLP
July 2002 to September 2005
Fong Wan
Vice President, Energy Procurement
January 9, 2006 to present
Vice President, Power Contracts and Electric Resource Development
May 1, 2004 to January 8, 2006
Vice President, Risk Initiatives, PG&E Corporation Support Services, Inc.
November 1, 2000 to April 30, 2004
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
As of February 19, 2008, there were 88,752 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York Stock Exchange and the Swiss stock exchanges. The high and low sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth under the heading “Quarterly Consolidated Financial Data (Unaudited)” in the 2007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. The discussion of dividends with respect to PG&E Corporation's common stock set forth under the heading “Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Financial Resources-Dividends” in the 2007 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
PG&E Corporation did not repurchase any shares of its common stock during 2007. The Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding during of 2007.
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 2007 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 financial condition and results of operations is set forth under the heading “Management's Discussion and Analysis of Financial Condition and Results of Operations” in the 2007 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 2007 Annual Report under the heading “Management's Discussion and Analysis of Financial Condition and Results of Operations-Risk Management Activities,” and under Notes 2 and 12 of the “Notes to the Consolidated Financial Statements” of the 2007 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 2007 Annual Report under the following headings for PG&E Corporation: “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity;” under the following headings for Pacific Gas and Electric Company: “Consolidated Statements of Income,” “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),” and “Report of Independent Registered Public Accounting Firm,” 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 the Utility's disclosure controls and procedures as of December 31, 2007, PG&E Corporation's and the Utility'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 the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's internal control over financial reporting.
Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management's report, together with the report of the independent registered public accounting firm, appears in the 2007 Annual Report under the heading “Management's Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm,” which information is hereby incorporated by reference and filed as part of Exhibit 13 to this
report.
Item 9B.
Item 9B. Other Information
Amendment to Bylaws
On February 20, 2008, the Boards of Directors of PG&E Corporation and the Utility amended the respective company’s Bylaws to decrease the authorized number of directors, effective May 14, 2008, to eliminate the vacancy on the Board of Directors that will result from the retirement of David A. Coulter as a director of each company following the companies’ joint annual meeting of shareholders. Under PG&E Corporation’s Bylaws, the authorized number of directors may not be less than 7 or more than 13, but within that range the Board of Directors may set the exact number of directors by an amendment to the Bylaws. Under the Utility’s Bylaws, the authorized number of directors may not be less than 9 or more than 17, but within that range the Board of Directors may set the exact number of directors by an amendment to the Bylaws. Effective May 14, 2008, PG&E Corporation’s authorized number of directors will decrease from 10 to 9 and the Utility’s authorized number of directors will decrease from 11 to 10. The text of the amendment to PG&E Corporation’s Bylaws is attached to this report as Exhibit 3.4 and the text of the amendment to the Utility’s Bylaws is attached to this report as Exhibit 3.7.
Under PG&E Corporation’s and the Utility’s Corporate Governance Guidelines, at least 75% of its Board is required to be composed of independent directors, generally defined as directors who (1) are neither current nor former officers or employees of, nor consultants to, PG&E Corporation, the Utility, or their consolidated subsidiaries, (2) are neither current nor former officers or employees of any other corporation on whose board of directors any officer of the Utility serves as a member, and (3) otherwise meet the definition of “independence” set forth in the stock exchange rules applicable to PG&E Corporation and the Utility. The composition of PG&E Corporation’s and the Utility’s Board of Directors currently meets the Corporate Governance Guidelines and will continue to do so after May 14, 2008.
Officer Compensation
On February 20, 2008, the Compensation Committee of the PG&E Corporation Board of Directors (“Committee”) approved the specific performance targets for each component of the 2008 Short-Term Incentive Plan (“STIP”). The Committee previously approved the STIP structure and the weighting of each component in December 2007. Officers of PG&E Corporation and the Utility are eligible to receive cash incentives under the STIP based on the extent to which the adopted 2008 performance targets are met. The Committee will continue to retain full discretion as to the determination of final officer STIP payments.
The 2008 STIP structure for officers focuses the annual incentive opportunity on returns to shareholders by emphasizing financial objectives such as earnings from operations. The structure also recognizes the equal importance of improving reliability and customer satisfaction, and employee safety and engagement. Corporate financial performance, as measured by corporate earnings from operations, will account for 40% of the incentive, 20% of the incentive will be based on the Utility’s success in improving reliability, 20% of the incentive will be based on the Utility’s success in improving customer satisfaction, 10% will be based on the results of an employee opinion survey, and the remaining 10% will be based on achieving safety standards. For 2008, the Committee has adopted a mechanism stating that if corporate financial performance does not exceed 98% of the budgeted earnings from operations, the aggregate operational metric contribution to the 2008 STIP pool will be capped at 100% of the operational component target award, or 60% of the total target STIP award pool.
The corporate financial performance measure is based on PG&E Corporation's budgeted earnings from operations that were previously approved by the Board of Directors, consistent with the basis for reporting and guidance to the financial community. As with previous earnings performance scales, unbudgeted items impacting comparability such as changes in accounting methods, workforce restructuring, and one-time occurrences will be excluded. The Committee also approved the 2008 performance targets for each of the four other measures set forth in the table below. The 2007 performance results for each of these measures are included for comparative purposes.
2008 STIP Operational Performance Targets(1)
1. As explained above, 40% of the STIP award will be based on achievement of corporate earnings from operations targets.
2.
The Customer Satisfaction and Brand Health Index is the result of a quarterly survey performed by an independent research firm, Research International, and is a combination of a customer satisfaction score, which has a 75% weighting, as well as a brand favorability score (measuring the relative strength of the PG&E brand against a select group of companies), which has a 25% weighting. The customer satisfaction score will measure overall satisfaction with the Utility’s operational performance in delivering its services. The brand favorability score will measure residential, small business and medium business customer perceptions. This index replaces the index used in the 2006 and 2007 STIP structures based on residential and business customer satisfaction indices as reported the J.D. Power Residential Customer Satisfaction Survey and the J.D. Power Business Customer Satisfaction Survey.
3.
The Reliable Energy Delivery Index is a composite index score that measures key drivers of reliability, including outage frequency and duration (System Average Interruption Frequency Index (SAIFI), Customer Average Interruption Duration Index (CAIDI)), Execution of Electric-Based Work Units, and Gas Transmission and Distribution Integrity. This index replaces the Business Transformation Index used in the 2007 STIP structure.
4.
The Premier Survey is the primary tool used to measure employee engagement at PG&E Corporation and the Utility. The employee index is designed around 15 key drivers of employee engagement and organizational health. The average overall employee survey index score provides a comprehensive metric that is derived by adding the percent of favorable responses from all 40 core survey items (all of which fall into one of 15 broader topical areas), and then dividing the total sum by 40.
5.
An “OSHA Recordable” is an occupational (job-related) injury or illness that requires medical treatment beyond first aid, or results in work restrictions, death or loss of consciousness. The “OSHA Recordable Rate” is the number of OSHA Recordables for every 200,000 hours worked, or for approximately 100 employees. This metric measures the percentage reduction in the Corporation’s OSHA Recordable rate from the prior year and is used to monitor the effectiveness of the Corporation’s safety programs, which are intended to significantly reduce the number and degree of employee injuries and illnesses.
Cash awards under the STIP may range from 30 percent to 100 percent of base salary depending on officer level, with a maximum payout of 200 percent of base salary, as determined by the Committee.
Non-Employee Director Compensation
Also on February 20, 2008, the Boards of Directors of PG&E Corporation and the Utility amended each company’s resolution regarding non-employee director compensation to clarify and restate the application of the compensation program for non-employee directors in light of (1) the division of the PG&E Corporation Nominating, Compensation, and Governance Committee into two separate committees (the Nominating and Governance Committee and the Compensation Committee), and (2) recent changes to the process for selecting the lead director. The amended resolutions do not change the compensation levels previously authorized by the Boards of Directors on December 20, 2006. The amended resolutions are effective as of January 1, 2008 and are attached to this report as exhibits.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included above in a separate item captioned “Executive Officers of the Registrants” at the end of Part I of this report. Other information responding to Item 10 is included under the heading “Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company” and under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Website Availability of Code of Ethics, 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 and Governance Committee and Compensation Committee. Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, Vice President, Corporate Governance and Corporate Secretary of 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 and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within 4 business days of the waiver.
Procedures for Shareholder Recommendations of Nominees to the Boards of Directors
During 2007 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2007 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or the Utility’s Boards of Directors.
Audit Committees and Audit Committee Financial Expert
Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is included under the heading “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric CompanyBoard CommitteesAudit Committees” in the Joint Proxy Statement relating to the 2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 11.
Item 11. Executive Compensation
Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under
the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table - 2007,” “Grants of Plan-based Awards in 2007,” “Outstanding Equity Awards at Fiscal Year End - 2007,” “Option Exercises and Stock Vested During 2007,” “Pension Benefits,” “Non-Qualified Deferred Compensation,” “Compensation of Directors,” and “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” in the Joint Proxy Statement relating to the 2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading “Security Ownership of Management” and under the heading “Principal Shareholders” in the Joint Proxy Statement relating to the 2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Equity Compensation Plan Information
The following table provides information as of December 31, 2007 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.
Plan Category
(a)
Number of Securities to
be Issued Upon Exercise
of Outstanding Options,
Warrants and Rights
(b)
Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights
(c)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column(a))
Equity compensation plans approved by shareholders
3,970,661(1)
$24.00
10,847,999(2)
Equity compensation plans not approved by shareholders
-
$-
-
Total equity compensation plans
3,970,661(1)
$24.00
10,847,999(2)
(1) Includes 87,989 phantom stock units and restricted stock units. The weighted average exercise price reported in column (b) does not take these awards into account.
(2) Represents the total number of shares available for issuance under the PG&E Corporation's Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2007. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock and phantom stock payable in an equal number of shares upon termination of employment or service as a director. The LTIP expired on December 31, 2005. The 2006 LTIP, which became effective on January 1, 2006 authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP. Outstanding stock-based awards granted under the 2006 LTIP include stock options, restricted stock, restricted stock units and phantom stock payable in an equal number of shares upon termination of employment or service as a director. For a description of the LTIP and the 2006 LTIP, see Note 14 of the Notes to the Consolidated Financial Statements in the 2007 Annual Report.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the headings “Related Person Transactions,” “Review, Approval, and Ratification of Related Person Transactions” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric CompanyDirector Independence” in the Joint Proxy Statement relating to the 2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 14.
Item 14. Principal Accountant Fees and Services
Information responding to Item 14, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading “Information Regarding the Independent Registered Public Accounting Firm of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2008 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as a part of this report:
1. The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are contained in the 2007 Annual Report and are incorporated by reference in this report:
Consolidated Statements of Income for the Years Ended December 31, 2007, 2006, and 2005 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2007 and 2006 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006, and 2005 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2007, 2006, and 2005 for each of PG&E Corporation and Pacific Gas and Electric Company.
Notes to the Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
2. The following financial statement schedules and report of independent registered public accounting firm are filed as part of this report:
Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
I-Condensed Financial Information of Parent as of December 31, 2007 and 2006 and for the Years Ended December 31, 2007, 2006, and 2005.
II-Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2007, 2006, and 2005.
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.
3. Exhibits required by Item 601 of Regulation S-K:
Exhibit
Number
Exhibit Description
2.1
Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2
Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1
Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2
Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3
Bylaws of PG&E Corporation amended as of September 19, 2007 (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007) (File No. 1-12609), Exhibit 3.1)
3.4
Text of the amendment to the Bylaws of PG&E Corporation effective May 14,
3.5
Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
3.6
Bylaws of Pacific Gas and Electric Company amended as of January 1,
3.7
Text of the amendment to the Bylaws of Pacific Gas and Electric Company effective May 14, 2008
4.1
Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2
First Supplemental Indenture dated as of March 13, 2007 relating to the issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.3
Second Supplemental Indenture dated as of December 4, 2007 relating to the issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017(incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)
4.4
Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
4.5
Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
10.1
Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.2
Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.3
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 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.4
Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
10.5
Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*10.6
PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
*10.7
PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.11)
*10.8
Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*10.9
Restricted Stock Award Agreement between PG&E Corporation and Peter A. Darbee dated January 3, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 12348), Exhibit 10.3)
*10.10
Retention Agreement between PG&E Corporation and Thomas B. King dated August 31, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.2)
*10.11
Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.1)
*10.12
Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609), Exhibit 10.4)
*10.13
Performance Share Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.14
Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.15
Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005) (File No. 1-12609), Exhibit 10.18)
*10.16
Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)
*10.17
Letter regarding Compensation Agreement between PG&E Corporation and G. Robert Powell dated
August 8, 2005
*10.18
PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.17)
*10.19
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2008
*10.20
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2007 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.20)
*10.21
Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 31, 2004, and frozen as of January 1, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004) (File No. 1-2348), Exhibit 10.20)
*10.22
Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005) (File No. 1-2348), Exhibit 10.27)
*10.23
Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*10.24
Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.25
PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
*10.26
Resolution of the PG&E Corporation Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-K for the year ended December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit 10.29)
*10.27
Resolution of the Pacific Gas and Electric Company Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-K for the year ended December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit 10.30)
*10.28
Resolution of the PG&E Corporation Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1,
*10.29
Resolution of the Pacific Gas and Electric Company Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1,
*10.30
PG&E Corporation 2006 Long-Term Incentive Plan, as amended on February 15, 2006 (with respect to change in control provisions) and December 20, 2006 and October 17, 2007 (with respect to Section 7 governing nondiscretionary awards to non-employee directors)
*10.31
PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.32
Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
*10.33
Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
*10.34
Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
*10.35
Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1)
*10.36
Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39)
*10.37
Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*10.38
Form of Performance Share Award Agreement for 2004 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.38)
*10.39
Form of Performance Share Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
*10.40
Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2)
*10.41
Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006)
*10.42
PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) Exhibit 10.2)
*10.43
PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.46)
*10.44
PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.37) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44)
*10.45
PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)
*10.46
PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*10.47
PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
*10.48
PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
*10.49
Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
*10.50
Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
Computation of Earnings Per Common Share
12.1
Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
The following portions of the 2007 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management's Discussion and Analysis of Financial Condition and Results of Operations,” financial statements of PG&E Corporation entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity,” “Notes to the Consolidated Financial Statements,” and “Quarterly Consolidated Financial Data (Unaudited),” “Management's Report on Internal Control Over Financial Reporting,” “Report of Independent Registered Public Accounting Firm,” and “Report of Independent Registered Public Accounting Firm.”
Subsidiaries of the Registrant
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1
Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2
Powers of Attorney
31.1
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of
31.2
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of
**32.2
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
* 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.
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, 2007 to be signed on their behalf by the undersigned, thereunto duly authorized.
PG&E CORPORATION
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
*PETER A. DARBEE
(Registrant)
*WILLIAM T. MORROW
By:
Peter A. Darbee
Chairman of the Board, Chief Executive Officer
and President
By:
William T. Morrow
President and Chief Executive Officer
Date:
February 22, 2008
Date:
February 22, 2008
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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Boards of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company
We have audited the consolidated financial statements of PG&E Corporation and subsidiaries (the "Company") and Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and the Company's and Utility’s internal control over financial reporting as of December 31, 2007, and have issued our reports thereon dated February 21, 2008; such consolidated financial statements and reports are included in your 2007 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the consolidated financial statement schedules of the Company and Utility listed in Item 15(a)2. These consolidated financial statement schedules are the responsibility of the Company's and the Utility’s management. 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 basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
DELOITTE & TOUCHE LLP
San Francisco, California
February 21, 2008
PG&E CORPORATION
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
(in millions)
PG&E CORPORATION
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF PARENT -- (Continued)
CONDENSED STATEMENTS OF INCOME
(in millions, except per share amounts)
(1) PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31, 2004.
PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method.
Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2007 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.
PG&E CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
(2) On January 15, 2007, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share. On April 15, July 15, and October 15, 2007, PG&E Corporation paid quarterly common stock dividends of $0.36 per share. Of the total dividend payments made by PG&E Corporation in 2006, approximately $35 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.
On January 16, April 15, July 15, and October 15, 2006, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share, totaling approximately $489 million. Of the total dividend payments made by PG&E Corporation in 2006, approximately $33 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.
On April 15, July 15 and October 17, 2005, PG&E Corporation paid a quarterly common stock dividend of $0.30 per share, totaling approximately $356 million. Of the total dividend payments made by PG&E Corporation in 2005, approximately $22 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. PG&E Corporation did not pay any dividends during 2004.
PG&E Corporation
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2007, 2006, and 2005
Pacific Gas and Electric Company
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2007, 2006, and 2005
Exhibit Index
Exhibit
Number
Exhibit Description
2.1
Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2
Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1
Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2
Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3
Bylaws of PG&E Corporation amended as of September 19, 2007 (incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007) (File No. 1-12609), Exhibit 3.1)
3.4
Text of the amendment to the Bylaws of PG&E Corporation effective May 14,
3.5
Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
3.6
Bylaws of Pacific Gas and Electric Company amended as of January 1,
3.7
Text of the amendment to the Bylaws of Pacific Gas and Electric Company effective May 14, 2008
4.1
Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q filed May 4, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2
First Supplemental Indenture dated as of March 13, 2007 relating to the issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
4.3
Second Supplemental Indenture dated as of December 4, 2007 relating to the issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017(incorporated by reference from Pacific Gas and Electric Company’s Current Report on Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)
4.4
Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
4.5
Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
10.1
Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.2
Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)
10.3
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 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.4
Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
10.5
Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)
*10.6
PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
*10.7
PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.11)
*10.8
Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*10.9
Restricted Stock Award Agreement between PG&E Corporation and Peter A. Darbee dated January 3, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 12348), Exhibit 10.3)
*10.10
Retention Agreement between PG&E Corporation and Thomas B. King dated August 31, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.2)
*10.11
Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 1-12609), Exhibit 10.1)
*10.12
Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609), Exhibit 10.4)
*10.13
Performance Share Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.14
Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007
*10.15
Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005) (File No. 1-12609), Exhibit 10.18)
*10.16
Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)
*10.17
Letter regarding Compensation Agreement between PG&E Corporation and G. Robert Powell dated
August 8, 2005
*10.18
PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.17)
*10.19
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2008
*10.20
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2007 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.20)
*10.21
Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 31, 2004, and frozen as of January 1, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004) (File No. 1-2348), Exhibit 10.20)
*10.22
Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005) (File No. 1-2348), Exhibit 10.27)
*10.23
Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*10.24
Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.25
PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
*10.26
Resolution of the PG&E Corporation Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-K for the year ended December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit 10.29)
*10.27
Resolution of the Pacific Gas and Electric Company Board of Directors dated December 20, 2006, adopting director compensation arrangement effective January 1, 2007 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-K for the year ended December 31, 2006 (File No. 1-12609 and File No. 12348), Exhibit 10.30)
*10.28
Resolution of the PG&E Corporation Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1,
*10.29
Resolution of the Pacific Gas and Electric Company Board of Directors dated February 20, 2008, adopting director compensation arrangement effective January 1,
*10.30
PG&E Corporation 2006 Long-Term Incentive Plan, as amended on February 15, 2006 (with respect to change in control provisions) and December 20, 2006 and October 17, 2007 (with respect to Section 7 governing nondiscretionary awards to non-employee directors)
*10.31
PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.32
Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
*10.33
Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
*10.34
Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
*10.35
Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1)
*10.36
Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39)
*10.37
Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*10.38
Form of Performance Share Award Agreement for 2004 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.38)
*10.39
Form of Performance Share Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
*10.40
Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2)
*10.41
Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44)
*10.42
PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609) Exhibit 10.2)
*10.43
PG&E Corporation Executive Stock Ownership Program Guidelines as amended February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.46)
*10.44
PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.37)
*10.45
PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)
*10.46
PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
*10.47
PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
*10.48
PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
*10.49
Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
*10.50
Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
Computation of Earnings Per Common Share
12.1
Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
The following portions of the 2007 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management's Discussion and Analysis of Financial Condition and Results of Operations,” financial statements of PG&E Corporation entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity,” “Notes to the Consolidated Financial Statements,” and “Quarterly Consolidated Financial Data (Unaudited),” “Management's Report on Internal Control Over Financial Reporting,” “Report of Independent Registered Public Accounting Firm,” and “Report of Independent Registered Public Accounting Firm.”
Subsidiaries of the Registrant
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1
Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2
Powers of Attorney
31.1
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of
31.2
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of
**32.2
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002