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, or the 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 4.2 million natural gas distribution customers at December 31, 2006. The Utility had approximately $34.4 billion of assets at December 31, 2006, and generated revenues of approximately $12.5 billion in 2006. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.
Corporate and Other Information
The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility file various reports with the Securities and Exchange Commission, or the SEC. These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, 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, 2006, PG&E Corporation and its subsidiaries had approximately 20,400 employees, including approximately 20,200 employees of the Utility. Of the Utility's employees, approximately 13,400 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or the IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or the ESC; and the Service Employees International Union, Local 24/7, or the SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2008. The SEIU collective bargaining agreement expires on February 28, 2009.
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, 2006, or the 2006 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, 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 timely recover costs through rates;
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the outcome of regulatory proceedings, including ratemaking proceedings pending 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 that could affect 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 operations;
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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, or 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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the ability of the Utility to recognize benefits from its initiatives to improve its business processes and customer service;
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the ability of the Utility to timely complete its planned capital investment projects;
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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 the California Independent System Operator’s, or the CAISO’s, new rules 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 in connection with pending litigation that are not recoverable through rates, from third parties, or through insurance recoveries;
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the ability of PG&E Corporation and/or the Utility to access capital markets and other sources of credit;
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the impact of environmental laws and regulations and the costs of compliance and remediation; and
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the effect of municipalization, direct access, community choice aggregation, or other forms of bypass.
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 the discussion under the heading “Risk Factors” that appears near the end of the section entitled “Management's Discussion and Analysis of Financial Condition and Results of Operations,” or the MD&A, in the 2006 Annual Report that is incorporated by reference into 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, or the 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, or 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, or the DOE.
During 2006, the FERC issued rules implementing PUHCA 2005 that impose on holding companies and their subsidiaries various requirements concerning access to books and records, accounting, record retention and the filing of reports. On June 15, 2006, PG&E Corporation filed a notification of waiver with the FERC, which was deemed granted by operation of law on August 14, 2006. The effect of this waiver is to exempt PG&E Corporation and its subsidiaries 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. The books and records provisions to which PG&E Corporation and its subsidiaries remain subject under PUHCA 2005 are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.
In addition to enacting PUHCA 2005, the EPAct also significantly modified the FERC's authority and standard of review for mergers and consolidations involving public utilities and their holding companies under Section 203 of the Federal Power Act of 1935.
State Energy Regulation
PG&E Corporation is not a public utility under the laws of California. 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 equity ratio 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 natural gas distribution companies and their non-regulated affiliates. The rules address the use of the regulated utilities’ names and logos by their non-regulated affiliates, the separation of regulated utilities and their non-regulated affiliates, information exchange among the affiliates, and energy procurement-related transactions among regulated utilities and their non-regulated 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 non-regulated 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 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;
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adopt as part of the affiliate rules the utilities’ current requirements to maintain a balanced capital structure (proportions of equity, long term debt, and preferred stock) consistent with that most recently determined to be reasonable by the CPUC; and
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make the CPUC's Energy Division responsible for hiring the independent auditors to conduct the 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 governmental 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, or 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 regulatory proceedings affecting the Utility, see the section of the MD&A entitled “Regulatory Matters” in the 2006 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 bulk power system, the FERC certified the North American Electric Reliability Corp., or 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 review. All proposed reliability standards must be submitted by the NERC to the FERC for its approval. The NERC has requested the FERC to approve a delegation agreement to permit the NERC to delegate its enforcement authority for a 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 assuring the maintenance of adequate reserves of generation capacity.
The FERC also has issued a rule on electric transmission pricing reforms designed to promote needed investment in energy infrastructure and to reduce transmission congestion. In addition, the FERC issued a rule to require transmission organizations with organized electricity markets to make available to load-serving entities long-term firm transmission rights 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 penalize the exercise of market power or behavior intended to manipulate the 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.
Several parties, including the Utility and the State of California, are seeking refunds on behalf of California electricity purchasers from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and California Power Exchange, or PX, wholesale electricity markets between May 2000 and June 2001 through various proceedings pending at the FERC and other judicial proceedings. Many issues raised in these proceedings, including the extent of the FERC’s refund authority, and the amount of potential refunds after taking into account certain costs incurred by the electricity suppliers, have not been resolved. It is uncertain when these proceedings will be concluded.
The Utility has entered into settlements with various electricity suppliers resolving certain disputed claims and the Utility's refund claims against these power suppliers. The Utility continues to pursue additional refunds through settlement discussions with other electricity suppliers. Future amounts received under these settlements, and any future settlements with electricity suppliers, will be credited to customers after deductions for contingencies and amounts related to certain wholesale power purchases. For further discussion, see the section of Note 17: Commitments and Contingencies - California Energy Crisis Proceedings, of the Notes to the Consolidated Financial Statements in the Annual Report.
QF Regulation. Under PURPA, electric utilities were required to purchase energy and capacity from independent power producers that are qualifying cogeneration facilities, or 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 210 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 wait until after the new day-ahead market structure provided for in the CAISO’s Market Redesign and Technology Update, or MRTU, initiative to restructure the California electricity market becomes effective to assess whether it will file a request with the FERC to terminate its obligations under PURPA to enter into new QF purchase obligations.
The NRC
The Nuclear Regulatory Commission, or the 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, or 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 this 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, enacted during the California 2000-2001 energy crisis, authorized the California Department of Water Resources, or the 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 long-term contracts and to act as the DWR's billing and collection agent.
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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 SB 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, the annual procurement target, 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, but not limited to, 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 to address climate change, requires the California Air Resources Board, or the CARB, to adopt regulations to limit statewide greenhouse gas emissions, to 1990 levels by 2020. (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 utility 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, or the Bankruptcy Court, since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter Settlement Agreement established certain regulatory assets and addressed various ratemaking matters in order to restore the Utility’s financial health and enable it to emerge from Chapter 11 and fully resume its traditional role of providing safe and reliable electric and gas service at just and reasonable rates, subject to CPUC regulation. 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. Although the Utility's operations are no longer subject to the oversight of the Bankruptcy Court, the Bankruptcy Court retains 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 2006 Annual Report.)
The California Energy Resources Conservation and Development Commission
The California Energy Resources Conservation and Development Commission, commonly called the California Energy
Commission, or the 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, natural gas, oil and water facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. However, there are 38 charter cities that can set fees of their own determination. The Utility also periodically obtains permits, authorizations and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations.
Competition
Historically, energy utilities operated as regulated monopolies within service territories where they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport and distribute energy. Services were priced on a combined, or bundled, basis with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities 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 open access non-discriminatory transmission tariffs, or OATT, that contain 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 that is designed to (1) strengthen the form of OATT adopted in Order 888 to ensure that it achieves its original purpose of remedying undue discrimination; (2) provide greater specificity in the form of 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 larger than 20 MW with a transmission system 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 on the 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 make compliance filings as required by the FERC in the California refund proceeding still pending at the FERC. Established pursuant to AB 1890 to take control of the California investor-owned electric transmission facilities in California, the CAISO currently administers a real-time or “spot” wholesale market for the sale of electric energy. The market is used to allocate space on the transmission lines, maintain operating reserves and match supply with demand in real time. In September 2006, the FERC approved the CAISO’s proposal to establish its MRTU initiative to restructure the California electricity market and to enhance power grid reliability. The FERC directed the CAISO to make certain changes to the MRTU proposal, including a requirement to comply with the FERC’s new rule that regional transmission organizations provide long-term transmission rights to users of the transmission grid. The MRTU tariffs, currently estimated to become effective on January 31, 2008, will apply to all load-serving entities, including the investor-owned utilities, serving California consumers.
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, 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. 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 has been asked to open a proceeding to determine whether to re-establish direct access by January 1, 2008. Although the Utility supports the ability of customers to choose their energy provider, the Utility believes there are a number of important policy and implementation questions that must be addressed before re-establishing direct access in order to ensure that all customers are treated equitably, with no undue cost responsibility burdens or risks being placed either on any one customer group or on the utilities.
The Utility’s customers may also obtain power from a “community choice aggregator” instead of obtaining power 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.
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. Instead, the Utility’s pipeline operations are 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 original Gas Accord, approved by the CPUC in 1998, is a CPUC-approved settlement agreement reached among the Utility and many interested parties, under which the natural gas transportation and storage services that the Utility provides were separated for ratemaking purposes from the Utility's distribution services. The Gas Accord changed the terms of service and rate structure for natural gas transportation, allowing the Utility's core customers (i.e., residential and small commercial customers) greater flexibility to purchase natural gas from competing suppliers. The Utility's noncore customers (i.e., industrial, larger commercial and electric generation customers) purchase their natural gas from producers, marketers and brokers, and purchase their preferred mix of transportation, storage and distribution services from the Utility. Although they can select the gas suppliers of their choice, substantially all core customers buy natural gas, as well as transportation and distribution services, from the Utility as a bundled service.
Under the Gas Accord structure noncore 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.
In December 2004, the CPUC approved the Gas Accord III which retained the Gas Accord market structure and resolved the rates, terms and conditions of service for the Utility’s natural gas and transportation system through 2007. The Utility is obligated to file a new rate case proposing gas transmission and storage rates and terms and conditions of service, for the period commencing January 1, 2008. The Utility currently is scheduled to submit that filing on March 15, 2007. In the event the CPUC does not issue a final decision approving new rates effective January 1, 2008, the Gas Accord III provides that the rates and terms and conditions of service in effect as of December 31, 2007, will remain in effect, with an automatic 2 percent escalation in the rates as of January 1, 2008.
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 232-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 Jordan Cove liquefied natural gas, or 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. On May 1, 2006, the FERC approved a request to begin the environmental assessment process for the Pacific Connector Gas Pipeline under the National Environmental Policy Act. The public will have an opportunity to participate in this process. The full application to request the FERC’s authorization to construct the Pacific Connector Gas Pipeline is scheduled to be submitted to the FERC in April 2007. 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 transportation contracts. Assuming the required permits, authorizations, and long-term transportation 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.
Ratemaking Mechanisms
Cost-of-Service Ratemaking
The Utility’s rates for electricity and natural gas utility services are based on its costs of service. Before rates can be set, the CPUC and the FERC must determine the amount of “revenue requirements” that the Utility can 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, including a return of, and a fair rate of return on, its investment in utility facilities, or rate base. Revenue requirements are primarily determined based on the Utility’s forecast of future costs, including the costs of purchasing electricity and natural gas for the Utility's customers. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs.
The Utility’s regulatory balancing accounts are used as a mechanism for the Utility to recover amounts incurred for certain costs, primarily commodity costs. Sales balancing accounts accumulate differences between revenues and the Utility's authorized revenue requirements. Cost balancing accounts accumulate differences between incurred costs and authorized revenue requirements. The Utility also obtained CPUC approval for balancing account treatment of variances between forecasted and actual commodity costs and volumes. To the extent that the Utility is unable to recover its costs through rates because the Utility’s actual costs are determined to be unreasonable or are higher than forecast, the Utility may be unable to earn its authorized rate of return.
The amount of authorized revenue requirements are allocated among customer classes (mainly residential, commercial, industrial and agricultural) and specific rates are established to produce the required revenue. The Utility's rates reflect the sum of individual revenue requirement components authorized by the CPUC and the FERC. Changes in any individual revenue requirement affect customers' rates and could affect the Utility's revenues. The timing of the CPUC and other regulatory decisions affect when the Utility is able to record the authorized revenues. In annual true-up proceedings, the Utility requests the CPUC to authorize an adjustment to electric and gas rates effective to (1) reflect over- and under-collections in the Utility's major electric and gas balancing accounts, and (2) implement various other electricity and gas revenue requirement changes authorized by the CPUC or the FERC. Generally, rate changes become effective on the first day of the following year. Balances in all CPUC-authorized accounts are subject to review, verification audit and adjustment, if necessary, by the CPUC.
Electricity and Natural Gas Distribution and Electricity Generation Operations
General Rate Cases
The General Rate Case, or 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, or the DRA, and The Utility Reform Network, or TURN. On August 21, 2006, the Utility, together with the DRA and other parties, filed a motion with the CPUC seeking approval of a settlement agreement reached among the parties to resolve all of the issues raised by these parties and all revenue requirement-related issues raised by other parties in the Utility’s 2007 GRC proceeding. The settlement agreement proposes to set the Utility’s revenue requirements for a four-year period, 2007-2010, rather than for a typical three-year period. Under this proposal, the Utility’s next GRC would be effective January 1, 2011. On February 13, 2007, the administrative law judge overseeing the GRC issued a proposed decision that recommends modifications to the settlement agreement. On the same day, an alternate proposed decision was issued by the assigned CPUC Commissioner in the GRC that recommends that the settlement agreement be approved. For more information, see “Regulatory Matters - 2007 General Rate Case” in the MD&A in the 2006 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 proposed settlement agreement in the Utility’s 2007 GRC includes a provision for attrition adjustments to be made in 2008, 2009 and 2010.
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 Chapter 11 Settlement Agreement requires the CPUC to authorize a minimum return on equity for the Utility of 11.22% until the Utility receives a credit rating of “A3” from Moody’s Investor Services or “A-” from Standard & Poor’s Rating Services. The Utility’s CPUC-authorized capital structure for 2006 and 2007 consists of 46% long-term debt, 2% preferred stock and 52% 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 2006 and 2007 is 6.02% for long-term debt, 5.87% for preferred stock and 11.35% for equity, resulting in an overall rate of return on rate base of 8.79%. The CPUC will next re-evaluate the level of the Utility’s authorized return on equity and capital structure for the calendar year 2008. The Utility is required to file its 2008 cost of capital application by May 8, 2007.
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. The Utility’s rates of return for its backbone and local gas transmission and storage operations through 2007 have been previously set in the Gas Accord, described below, at 11.22% for the return on equity and 8.77% for the overall rate of return.
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
The Utility administers, and/or funds, several state-mandated and CPUC-authorized 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, the CPUC has authorized additional funding for energy efficiency and demand response programs. For 2006 expenditures, the CPUC has authorized the Utility to collect revenue requirements of approximately $583 million from electricity customers to fund these electricity public purpose and other programs and to collect revenue requirements of approximately $99 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 public interest research and development program and the renewable energy program on a statewide basis. In 2006, the Utility transferred $109 million to the CEC for these programs. These programs include:
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Energy Efficiency Programs. The CPUC has authorized 2006 through 2008 energy efficiency portfolio plans and program funding levels, not including funding for evaluation, measurement and verification, or EM&V activities for the Utility and the other investor-owned California utilities. The CPUC approved funding of approximately $867 million for the Utility's energy efficiency programs over the 2006 through 2008 period, 20% of which is to be awarded to third parties through a competitive bid process. The CPUC also has authorized funding for EM&V activities of approximately $75 million for the Utility over the 2006 through 2008 period. The 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 will enable both residential and business customers to take more advantage of the diverse mix of energy efficiency programs.
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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. In March 2006, the CPUC authorized 2006 through 2008 demand response programs and funding levels for the Utility and other investor-owned California utilities. The CPUC approved funding of approximately $109 million for the Utility’s demand response programs over the 2006 through 2008 period, which include some demand response programs that will be provided by third parties. In November 2006, the CPUC approved augmented demand response programs for the Utility and other investor-owned California utilities in order to promote system reliability during the summer peak demand periods of 2007 and 2008. These augmented programs were approved within the existing authorized budget. Programs requiring additional funding beyond the already authorized level will require further regulatory authorization. On February 15, 2007, the CPUC approved the Utility’s proposal to start a limited deployment of an airconditioning load control program that is expected to yield 5 MW of load relief for summer 2007. In early spring 2007, the Utility anticipates requesting that the CPUC approve an expanded air conditioning load control program that is expected to yield approximately 300 MW of additional load relief by the end of 2010. These increased demand response programs are part of an effort by the state of California to promote demand reduction through price-responsive programs and reliability-triggered programs.
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Self-Generation Incentive and California Solar Initiative. The Utility administers the self-generation incentive program authorized by the CPUC to provide incentives to electricity customers who install clean or renewable distributed generation resources that meets all or a portion of their onsite energy usage. The CPUC also authorized the California investor-owned utilities to collect an additional $2.1 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. The goal of this program, called the California Solar Initiative, or the CSI, is to bring 1,940 MW of solar power on-line by 2017 through the California investor-owned utilities. 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. California Senate Bill 1, enacted in August 2006, modified the CSI program to include participation of the California municipal utilities. The 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, or CARE, for low-income customers. This rate subsidy is paid for by the Utility's other customers. For 2006, the amount of this subsidy was approximately $458 million (including avoided surcharges).
Climate Protection Tariff
In December 2006, the CPUC approved the Utility’s proposal to allow customers to choose to neutralize greenhouse gas emissions associated with their energy use. Beginning in 2007, customers who choose to enroll in the 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 will generate approximately $20 million during its first three years to fund these greenhouse gas reduction projects, which will initially be focused on forest restoration and conservation projects in California. The Utility would select projects to fund through a competitive bidding process using stringent criteria and protocols developed by an independent non-profit organization, the California Climate Action Registry. Project types are expected to expand beyond forestry, such as potentially to dairy biogas methane reduction projects, as more certification protocols become available. The greenhouse gas reduction projects will be overseen by an external advisory group consisting of a wide range of community groups, businesses and non-profit conservation agencies. The program will be reviewed by independent auditors and the Utility will regularly report program results to the CPUC, as well as to all participating customers.
Rate Recovery of Costs of New Electricity Generation Resources
Overview
Each California investor-owned electric utility is responsible to procure 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). Each utility must submit a long-term procurement plan covering a ten-year period to the CPUC for approval. California legislation, Assembly Bill 57, allows the California investor-owned utilities to recover their wholesale electricity procurement costs incurred in compliance with their CPUC-approved procurement plans. After CPUC approval of the procurement plans, the utilities may, if appropriate, conduct a competitive request for offers, or RFO, from providers of all potential sources of new generation (e.g., conventional or renewable resources to be provided under turnkey developments, buyouts or power purchase agreements) to meet the utility’s projected need for electricity resources. Agreements entered into after the conclusion of 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 costs associated with that contract. If necessary, the utilities conduct separate competitive solicitations to meet their resource adequacy and renewable energy resource requirements. The utilities submit the 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, or the 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 periodic 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, or the 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, 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 utilities 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 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 spot 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. 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.
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Gateway Generating Station. In June 2006, the CPUC authorized the Utility to acquire the equipment, permits and contracts relating to a partially completed 530-MW power plant in Antioch, California, referred to as the Gateway Generating Station, or Gateway. The Utility completed the acquisition in November 2006. The CPUC authorized the Utility to recover approximately $295 million in capital costs to complete the construction of the facility as well as costs for its operation. On February 15, 2007, the CPUC approved the Utility’s request to recover an additional approximately $75 million necessary to convert the plant from fresh water cooling to dry cooling in order to reduce the environmental impact of the facility and as a result of changes to Gateway’s environmental permits. The Utility also has requested the CEC to amend the facility’s current permit to authorize the plant to be converted from fresh water cooling to dry cooling. The Utility expects that the CEC will issue a decision in the second quarter of 2007. Subject to obtaining the permit amendment from the CEC, meeting construction schedules, operational performance requirements and other conditions, the Utility estimates that it will complete construction of the Gateway facility and commence operations in
Colusa Power Plant. In November 2006, the CPUC approved an agreement for the development and construction of a 657-MW power plant to be located in Colusa County, California. The CPUC adopted an initial capital cost for the Colusa project that is equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs and a contingency amount to account for the risk and uncertainty in the estimation of owner’s costs. (Owner’s costs include the Utility’s expenses for
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Colusa Power Plant. In November 2006, the CPUC approved an agreement for the development and construction of a 657-MW power plant to be located in Colusa County, California. The CPUC adopted an initial capital cost for the Colusa project that is equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs and a contingency amount to account for the risk and uncertainty in the estimation of owner’s costs. (Owner’s costs include the Utility’s expenses for legal, engineering and consulting services as well as the costs for internal personnel and overhead related to the project.) The CPUC also authorized the Utility to adjust the initial capital cost for the Colusa project to reflect any actual incentive payments made to, or liquidated damages received from, the contractors through notification to the CPUC but without a reasonableness review. Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Colusa project will commence operations in 2010 at an estimated cost of approximately $673 million.
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Humboldt Bay. In November 2006, the CPUC also approved an agreement for the construction of a 163-MW power plant to re-power the Utility’s existing Humboldt Bay power plant, which is at the end of its useful life. The CPUC adopted an initial capital cost of the Humboldt Bay project equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs, but limited the contingency amount for owner’s costs to 5 percent of the fixed contract cost and estimated owner’s costs. Subject to obtaining required permits and meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in 2009 at an estimated cost of approximately $239 million.
On December 11, 2006, the Utility submitted its 2006 long-term procurement plan covering procurement over 2007-2016 to the CPUC for approval. For more information about the 2006 plan, see the section of MD&A in the 2006 Annual Report entitled “Regulatory Matters - Electricity Generation Resources.”
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. Because the Utility acts as a billing and collection agent for the DWR, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.
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. A transmission owner 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. 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. The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge for the Utility’s use of CAISO-controlled transmission facilities in serving its customers. These credits and charges are described below.
On August 1, 2006, the Utility filed its transmission owner rate case application with the FERC requesting authorization of an annual transmission revenue requirement effective October 1, 2006. On September 29, 2006, the FERC issued an order accepting the Utility’s rate application, suspending the requested rate changes for five months to become effective March 1, 2007, subject to refund. On February 15, 2007, the Utility submitted an offer of settlement reached by the parties and requested that the settlement judge recommend that the FERC approve the settlement. For more information, see “Regulatory Matters - FERC Transmission Rate Case” in the MD&A in the 2006 Annual Report.
CAISO Transmission Revenues
CAISO transmission 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 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).
The amount of CAISO transmission revenues is 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.
Reliability Service Costs
The CAISO has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require designated units in certain power plants, known as RMR units, to remain available to generate electricity upon the CAISO's demand when the generation from those RMR units is needed for local transmission system reliability. RMR agreements are established or extended by the CAISO on an annual basis. As a participating transmission owner under the Transmission Control Agreement with the CAISO, the Utility is responsible for reimbursing the CAISO for the RMR payments it makes to power plant owners within or adjacent to the Utility's service territory. The Utility tracks these costs in the reliability services balancing account. Periodically, the Utility’s transmission owner rates are adjusted to refund over-collections to the Utility’s customers as a result of the effect of these reliability service costs or to collect any under-collections from customers. During 2006, the CPUC adopted rules to implement state law requirements for California investor-owned utilities to meet resource adequacy requirements, including rules to address local transmission system reliability issues. As the utilities fulfill their responsibility to meet these requirements, the number of RMR agreements with the CAISO and the associated costs will decline.
For further discussion of other RMR-related issues, see the section of Note 17: Commitments and Contingencies - Reliability Must Run Agreements, of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.
Transmission Access Charge
The CAISO imposes a transmission access charge on users of the CAISO-controlled electric transmission grid. The CAISO's transmission access charge methodology approved by the FERC in December 2004, provides for a transition over a 10-year period to a uniform statewide high-voltage transmission rate, 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.
Natural Gas
The Gas Accord
Under a ratemaking pact called the Gas Accord, the Utility's natural gas transportation and storage services were separated for ratemaking purposes from its distribution services. The Gas Accord established natural gas transportation rates and natural gas storage rates. In December 2004, the CPUC approved a multi-party settlement agreement, the Gas Accord III, to retain the Gas Accord market structure, and resolve the rates, and terms and conditions of service for the Utility's natural gas transportation and storage system for the three-year period 2005 through 2007. Under this framework, the costs associated with the Utility’s local transportation and gas storage assets that are used for service to core customers are recovered through balancing account mechanisms that adjust for the difference between actual usage and forecast usage. In addition, approximately 65% of the costs associated with the Utility’s backbone gas transmission system that is used to serve core customers are recovered through fixed charges. The remaining 35% of these costs are recoverable through volumetric charges. Revenues from these charges vary depending on the level of throughput volume. The costs that are recoverable through balancing accounts or fixed reservation charges account for approximately 45% of the Utility’s total revenue requirement for gas transmission and storage. The remainder of the Utility’s gas transmission and storage costs are recovered from core customers through volumetric charges and from noncore customers under firm or interruptible transmission or storage contracts. The Utility’s recovery of this portion of its costs depend on the level of throughput volume, gas prices, and the extent to which noncore customers contract for firm services.
The Utility is obligated to file a new rate case proposing gas transmission and storage rates and terms and conditions of service, for the period commencing January 1, 2008. The Utility currently is scheduled to submit that filing on March 15, 2007. In the event the CPUC does not issue a final decision approving new rates effective January 1, 2008, Gas Accord III provides that the rates and terms and conditions of service in effect as of December 31, 2007, will remain in effect, with an automatic 2 percent escalation in the rates as of January 1, 2008.
Biennial Cost Allocation Proceeding
Certain of the Utility's natural gas distribution costs and balancing account balances are allocated to customers in the Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any 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 procurement 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 known as the Core Procurement Incentive Mechanism, or CPIM. Under the CPIM, the Utility's purchase costs for a 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. The CPIM establishes a “tolerance band” around the benchmark index price, and all costs within the tolerance band are fully recovered from core customers. If total natural gas costs fall below the tolerance band, the Utility’s customers and shareholders will share 75% and 25% of the savings below the tolerance band, respectively. Conversely, if total natural gas costs rise above the tolerance band, the Utility’s core customers and shareholders share equally the costs above the tolerance band. 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. (For more information see the “Risk Management Activities” section of MD&A in the 2006 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.
Electric Utility Operations
Electricity Resources
The following table shows the percentage of the Utility's total sources of electricity for 2006 represented by each major electricity resource:
Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities)
40%
DWR
24%
Qualifying Facilities/Renewables
20%
Irrigation Districts
6%
Other Power Purchases
10%
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 to sell this additional 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, 2006, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:
Generation Type
County Location
Number of
Units
Net Operating
Capacity (MW)
Nuclear:
Diablo Canyon
San Luis Obispo
2,240
Hydroelectric:
Conventional
counties in northern
and central California
2,684
Helms pumped storage
Fresno
1,212
Hydroelectric subtotal
3,896
Fossil fuel:
Humboldt Bay(1)
Humboldt
Mobile turbines
Humboldt
Fossil fuel subtotal
Total
6,271
(1)
The Humboldt Bay facilities consist of a retired nuclear generation unit and two operating fossil fuel-fired plants. As described above, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.
In May 2006, the Utility retired its fossil fuel-fired plant at Hunters Point in San Francisco after the completion of a new 230-kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230-kV Line. The Utility is in the process of decommissioning the Hunters Point power plant. The completed transmission line provides additional transmission system reliability in San Francisco and northern San Mateo County that allowed the Hunters Point fossil-fueled power plant in San Francisco to be retired.
Diablo Canyon Power Plant. The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, 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, 2006, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 89.8%.
The Utility has entered into various purchase agreements for nuclear fuel with terms ranging from two to five years 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 2006 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 16 to 21 months. The average length of a refueling outage over the last five years has been approximately 48 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the replacement of the steam generators in Unit 2 in 2008 and in Unit 1 in 2009. The capital expenditures necessary to complete these projects are discussed further in the “Capital Expenditures” section of MD&A in the 2006 Annual Report. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of approximately 80 days for steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.
Unit
Refueling
April
-
January
October
Duration (days)
-
Startup
May
-
April
November
Unit
Refueling
-
February
October
-
April
Duration (days)
-
-
Startup
-
April
November
-
May
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 by 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, 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 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, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe and 5 miles of natural waterways. The system also includes water rights as specified in 87 permits or licenses and 160 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses totaling approximately 7.7 MW, all of the Utility's powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last five years, the FERC has renewed six hydroelectric project licenses associated with a total of 699 MW. The Utility is in the process of seeking FERC renewal of licenses associated with approximately 1,314 MW of 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, including the 699 MW recently relicensed, will expire between 2013 and 2043.
DWR Power Purchases
During 2006, electricity from the DWR contracts allocated to the Utility provided approximately 24% 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 the DWR's electricity procurement contracts allocated to the Utility’s customers. The DWR remains legally and financially responsible for its electricity procurement contracts. As described above under “Ratemaking Mechanisms,” the Utility acts as a billing and collection agent to collect the DWR's revenue requirements from the Utility's customers. 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 2006 Annual Report.
Third-Party Power Purchase Agreements
Qualifying Facility Power Purchase Agreements. As of December 31, 2006, the Utility had agreements with 268 QFs for approximately 4,150 MW that are in operation. Agreements for approximately 3,800 MW expire at various dates between 2007 and 2028. QF power purchase agreements for approximately 350 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 68 inoperative
QFs. The total of approximately 4,150 MW consists of approximately 2,550 MW from cogeneration projects, 600 MW from wind projects and 1,000 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar and hydroelectric.
QF power purchase agreements accounted for approximately 20% of the Utility’s 2006 electricity sources, 22% of the Utility’s 2005 electricity sources and approximately 23% of the Utility's 2004 electricity sources. No single QF accounted for more than 5% of the Utility's 2006, 2005 or 2004 electricity sources.
Renewable Energy Contracts. California law requires that each California retail seller of electricity, except for municipal utilities, increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2010. During 2006, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals. Currently, power from eligible renewable energy resources comprises approximately 12% of the Utility’s retail sales. The Utility expects to comply with its 2004, 2005, 2006 and 2007 annual targets. Although the Utility expects it will achieve the 20% target using the “flexible compliance” rules by 2010, actual deliveries of renewable power may not comprise 20% of its bundled retail sales by 2010 due to such factors as the time required for the construction of new generation facilities and/or needed transmission capacity. 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 is subject to the CPUC’s review of the circumstances for under-delivery.
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 2007 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 6% of the Utility’s 2006 electricity sources, and approximately 5% of the Utility’s 2005 and 2004 electricity sources.
Other Power Purchase Agreements. After competitive solicitations, bilateral negotiations, and request for offers or proposals, were conducted, the Utility entered into several agreements with third party power providers during 2006 to meet the Utility’s intermediate and long-term generation resource needs. Under these contracts, the Utility will purchase power from facilities that may start as early as January 1, 2007 to as late as 2011. These combined agreements cover an aggregate of 7,129 MW of contractual capacity that expire between December 31, 2010 and January 31, 2036. Payments are not required under these agreements until the underlying generation facilities are operational.
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 2006 Annual Report.
Future Long-Term Generation Resources
In accordance with the Utility’s CPUC-approved procurement plan covering 2004-2014, the Utility has entered into contracts covering 2,780 MW of new long-term electricity generation resources in northern California. Three of the agreements provide for the construction of generation facilities to be owned and operated by the Utility: the 530-MW Gateway power plant located in Antioch, California; the 657-MW Colusa power plant located in Colusa, California; and the 163-MW power plant to re-power the Utility’s existing Humboldt Bay power plant, which is at the end of its useful life. Subject to obtaining required permits and meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Gateway and Humboldt Bay plants will commence operations in 2009 and the Colusa plant will commence operations in 2010. The Utility also executed five power purchase agreements that would provide approximately 1,430 MW of capacity with terms from 10 to 20 years. If permitting and construction schedules are met, the new generation facilities supporting these power purchase agreements are anticipated to begin delivering power to the grid during 2009 through 2010.
On December 11, 2006, the Utility submitted its 2006 long-term electricity procurement plan covering procurement over 2007-2016 to the CPUC for approval. The plan forecasts a need for up to an additional 2,300 MW of new dispatchable and operationally flexible capacity to come on line starting in 2011 to ensure continued reliable service. For more information about the 2006 plan, see the section of MD&A in the 2006 Annual Report entitled “Regulatory Matters - Electricity Generation Resources.”
Electricity Transmission
At December 31, 2006, the Utility owned 18,640 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 53,094 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 140,049 circuit miles of distribution lines and substations with a capacity of 26,079 MVA. In 2006, the Utility delivered 84,310 GWh to its customers, including 7,604 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 assuring 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 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 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, and to replace aging or obsolete equipment to maintain system reliability and reduce reliance on RMR generation. These potential projects include the construction of the Midway-Gregg 500-kV transmission line designed to increase access to southern California and Southwest generation resources and to reduce RMR generation contracts in the Fresno, California, area. 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 addition, the CPUC has adopted a procedure to enable the utilities to recover the cost of electric transmission facilities necessary to interconnect renewable energy resources if those costs cannot be recovered in FERC-approved rates.
Electricity Distribution Operations
The Utility's electricity distribution network extends throughout all or a part of 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 140,049 circuit miles of distribution lines (of which approximately 19% are underground and approximately 81% are overhead). There are 94 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. There are 602 distribution substations and 110 low-voltage distribution substations. There are 55 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers.
The Utility's distribution network interconnects to the Utility's electricity transmission system at 1,106 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 system for virtually all of the Utility's residential and small commercial electric and gas customers. These meters will enable the Utility to measure usage of electricity on a time-of-use basis and to charge demand-responsive rates to encourage customers to reduce energy consumption during peak demand periods and
to reduce 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. In 2006, the CPUC also approved the Utility’s proposal to offer customers a new voluntary billing option called critical peak pricing, or CPP, under which customers will be able to take advantage of electricity prices that vary by day and hour, potentially reducing their bills by shifting their energy use away from critical peak periods. By shifting energy demand away from critical peak periods, the Utility anticipates that it would need to purchase less power for critical peak periods. (For more information about the advanced metering initiative, see the section entitled “Capital Expenditures” in the MD&A portion of the 2006 Annual Report.)
Electricity Deliveries
The following table shows the percentage of the Utility's total 2006 electricity deliveries represented by each of its major customer classes.
Total 2006 Electricity Delivered: 84,310 GWh
Electricity Distribution Operating Statistics
The following table shows certain of the Utility's operating statistics from 2002 to 2006 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 38 of California's 58 counties and includes most of northern and central California. In 2006, the Utility served approximately 4.2 million natural gas distribution customers. The total volume of natural gas throughput during was approximately 836 Bcf.
At December 31, 2006, the Utility's natural gas system consisted of 40,704 miles of distribution pipelines, 6,138 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 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 annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.
The CPUC divides the Utility's natural gas customers into two categories: core and noncore customers. This classification is based largely on a customer's annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial, larger commercial and electric generation natural gas customers. In 2006, core customers represented more than 99% of the Utility's total customers and 39% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility's total customers and 61% of its total natural gas deliveries.
The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility's system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. Currently, over 99% of core customers, representing over 96% of core market demand, receive natural gas bundled services from the Utility.
The Utility does not provide procurement service to noncore customers. Electricity generators, cogenerators, enhanced oil recovery and refiners, and other large noncore customers may not transfer to core service, and smaller noncore customers must sign up for a minimum five-year term if they elect to transfer to core service. These restrictions were put in place because large increases in the Utility's natural gas supply portfolio demand from significant transfers of noncore customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.
The Utility offers backbone gas transmission, delivery (local transmission and distribution), and storage services as separate and distinct services to its noncore customers. These customers may elect to receive storage services from the Utility or other third-party storage providers. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to the Utility's backbone gas transmission system is available for all natural gas marketers and shippers, as well as noncore 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 noncore consumption levels because there are fewer regulatory balancing accounts related to noncore customers. Approximately 97% of the Utility's natural gas distribution base revenues are recovered from core customers and 3% are recovered from noncore 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.
Natural Gas Deliveries
The following table shows the percentage of the Utility's total 2006 natural gas deliveries represented by each of the Utility's major customer classes:
Total 2006 Natural Gas Deliveries: 836 Bcf
Natural Gas Operating Statistics
The following table shows the Utility's operating statistics from 2002 through (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 2006, the Utility purchased approximately 293,000 Mcf of natural gas (net of the sale of excess supply) from 68 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 10.7% of the total natural gas volume the Utility purchased during 2006.
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 2006, 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 2006, 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 395.6 miles of gas gathering pipelines. The Utility receives gas well production at approximately 250 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 13 California counties. Approximately 138 MMcf per day of natural gas produced in northern California was delivered into the Utility's gas gathering system during 2006.
Interstate and Canadian Natural Gas Transportation Services Agreements
In 2006, approximately 62% 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 PipeLines Ltd., B.C. System. These companies' pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with the Utility's natural gas transportation system in the area of California near Malin, Oregon. The Utility has a firm transportation agreement with Gas Transmission Northwest Corporation for these services.
During 2006, approximately 32% 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 Co., or Transwestern, and El Paso Natural Gas Company, or El Paso, to transport this natural gas from supply points in this region to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona. The Utility also has a short-term firm transportation agreement with Kern River Gas Transmission Company to transport this natural gas from supply points in this region to an interconnection point with the Utility’s natural gas transportation system at Daggett, California.
The following table shows certain information about the Utility's firm natural gas transportation agreements, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System, and 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.
(a) A small portion (23 MDth/d) of the Utility’s capacity is due to expire on October 31, 2008.
(b)
As of December 31, 2006, the Utility has four active contracts with El Paso with expiration dates ranging from February 28, 2007 to June 30, 2010.
Environmental Matters
The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance. The information below reflects current estimates that are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, and the availability of recoveries or contributions from third parties.
General
The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of activities, including:
·
the discharge of pollutants into air, water and soil;
·
the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting of, remediation of and emergency response in connection with hazardous and radioactive substances; and
·
land use, including endangered species and habitat protection.
The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify or replace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations and clean-up or decommission waste disposal areas at the Utility's current or former facilities and at third-party sites where the Utility may have disposed of wastes.
Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility's rates, subject to reasonableness review. Environmental costs associated with 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 (e.g., for cleaning up the Utility's facilities and sites where the Utility has sent hazardous substances) from customers. This mechanism allows the Utility to include 90% of the 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 would then be 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; 90% of any such recoveries is assigned to the Utility's customers.
Hazardous waste remediation costs are rising and 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 and similar state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxide and particulate matter. Fossil fuel-fired electric utility plants and gas compressor stations used in the Utility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies. The Utility’s existing and forecast emissions of greenhouse gases are relatively low compared to average emissions by other electric utilities and generators in the country.
In addition, various laws and regulations addressing climate change are being considered or implemented at the federal and state levels. 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 greenhouse gases. No such legislation has yet been enacted by Congress, but extensive hearings and discussion is expected in the coming year.
At the state level, in 2006 California enacted Assembly Bill 32, the California Global Warming Solutions Act of 2006, to address climate change. The law establishes a regulatory program and schedule to gradually reduce greenhouse gas emissions in California to 1990 levels by 2020. By January 1, 2008, this law requires the CARB to determine what the state-wide greenhouse gas emission level was in 1990, approve a statewide greenhouse gas emissions limit, and adopt regulations to require significant greenhouse gas emitters, including utilities and other load-serving entities, to submit annual greenhouse gas emissions reports that have been verified or certified by the CARB. Assembly Bill 32 also authorizes the CARB to monitor and enforce compliance with the greenhouse gas reduction program and to consider implementing market-based mechanisms, including trading of greenhouse gas emissions allowances.
In addition to Assembly Bill 32, California Senate Bill 1368, enacted in September 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 greenhouse gas emission performance standard. As required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim greenhouse gas 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 an enforceable state-wide greenhouse gas emissions limit is established and in operation in accordance with Assembly Bill 32, the CPUC will re-evaluate its interim greenhouse gas 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 greenhouse gases, 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.
The CARB also oversees the Periodic Smoke Inspection Program to test and repair heavy-duty diesel vehicles in order to ensure efficient operations and reduce particulate matter emissions. The program applies to approximately 2,000 vehicles owned by the Utility. In July 2006, the CARB requested the Utility's program compliance records. The Utility discovered that its records were incomplete and that some records could not be located. The Utility immediately notified the CARB and began the evaluation and implementation of process improvements to ensure accurate recordkeeping. The CARB is authorized to assess penalties of up to $500 per missing or incomplete record. The Utility continues to work with the CARB and expects to resolve the matter in the first quarter of 2007. 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.
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, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or the 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 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.
In addition, on July 9, 2004, the U.S. Environmental Protection Agency, or the EPA, published regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations affect existing electricity generation facilities using over 50 million gallons per day, typically including some form of “once-through” cooling. The Diablo Canyon power plant is among an estimated 539 generation facilities nationwide that are affected by this rulemaking. The Utility permanently closed its Hunters Point power plant in May 2006 and the Humboldt Bay power plant will be re-powered without the use of once-through cooling. The EPA regulations establish a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. Significant capital investment may be required to achieve the standards. The regulations allow site-specific compliance determinations if a facility's cost of compliance is significantly greater than either the benefits achieved or the compliance costs considered by the EPA, and also allow the use of environmental mitigation or restoration to meet compliance requirements in certain cases. Various parties challenged the EPA’s regulations and the cases were consolidated in the U.S. Court of Appeal for the Second Circuit, or Second Circuit.
In June 2006, the California State Water Resources Control Board published a draft policy for California’s implementation of Section 316(b). If adopted, the draft policy would be substantially more stringent than the 2004 EPA regulations as the state policy would eliminate the EPA’s site-specific compliance options based on cost-benefit assessments and essentially requires the installation of cooling towers at once-through cooled power facilities. The draft policy provides that nuclear facilities may use environmental restoration as a compliance option only if the installation of technology would conflict with a nuclear safety requirement. It is uncertain when the state’s final policy will be adopted. If the final policy is adopted without change from the draft policy, the Utility could be required to incur significant capital costs to achieve compliance.
On January 25, 2007, the Second Circuit issued its decision on the appeals of the EPA Section 316(b) regulations. The Second Circuit remanded significant provisions of the regulations to EPA for reconsideration and held that a cost benefit test cannot be used to establish performance standards or to grant variances from the standards. The Second Circuit also ruled that environmental restoration cannot be used to achieve compliance. The parties may seek either en banc review by the Second Circuit or review by the U.S. Supreme Court. Regardless of whether the decision is subject to further judicial review, the EPA will likely require significant time to review and revise the regulations. It is uncertain how the Second Circuit decision will affect development of the state’s proposed implementation policy. The regulatory uncertainty is likely to continue and the Utility’s cost of compliance, while likely to be significant, will remain uncertain as well.
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, as well as evaluated options to remediate the plume. At the Topock gas compressor station, located near Needles, California, adjacent to the Colorado River, hexavalent chromium has been detected in samples taken from groundwater monitoring wells located approximately 65 feet from the Colorado River. The Utility is cooperating with the California Department of Toxic Substances Control, other state agencies, appropriate federal agencies and other interested parties, to implement interim
measures as well as develop a long-term plan to ensure that the hexavalent chromium does not affect the Colorado River. In 2006, the Utility took interim measures to control the chromium plume by extracting impacted groundwater and spent approximately $17 million on these measures. The Utility plans to continue these activities in 2007 and to work toward the development of a final plan to address the plume in 2007. The Utility currently estimates that it will spend at least $20 million in 2007 for remediation activities at Topock and $22 million in 2007 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.
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. There are three complaints filed by approximately 125 plaintiffs who did not participate in the settlement that are still pending in the Superior Court for the County of Los Angeles. With respect to the unresolved claims, the Utility will continue to pursue appropriate defenses, including the statute of limitations, the exclusivity of workers’ compensation laws, lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. PG&E Corporation and the Utility do not expect that the outcome with respect to the remaining unresolved claims 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 near the Utility's facilities or operations. The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with the state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.
Hazardous Waste Compliance and Remediation
The Utility's facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of the Utility's operations, the Utility generates waste that falls within CERCLA's definition of a hazardous substance and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling and disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous waste laws and other environmental requirements.
The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.
Operations at the Utility's current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal generation facilities and most of its fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating
several such sites with the oversight of various governmental agencies.
In addition, the federal Toxic Substances Control Act regulates the use, disposal and 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, the vast majority of PCBs existing in the Utility's electricity distribution system.
The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The residues that may remain at some sites contain chemical compounds that now are classified as hazardous. The Utility owns all or a portion of 28 manufactured gas plant sites. The Utility has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at these sites. The Utility spent approximately $3 million in 2006 and expects to spend approximately $6 million in 2007 on these projects. The Utility expects that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. There are approximately 67 other manufactured gas plant sites in the Utility's service territory that are now owned by others which remain a source of potential claims. It is likely that the Utility will incur remediation costs related to some of these sites. Although the Utility has been able to quantify potential liability for many of these sites, the amount of potential liability for all of these sites cannot be quantified.
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 eight such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility is in the process of completing a three-year closure of the disposal facility which was abandoned by its operator. The Utility was the major responsible party and led this effort on behalf of the responsible parties. In 2006, the Utility completed settlements with the other responsible parties for their share of future costs and assumed ownership of the closed facility. At the Casmalia disposal facility near Santa Maria, California, the Utility and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and mitigation measures.
In addition, the Utility has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites that it no longer owns or never owned. Remedial actions may include investigations, health and ecological assessments, and removal of wastes.
The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and 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, 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 $511 million at December 31, 2006 and approximately $469 million at December 31, 2005. The increase in the undiscounted environmental remediation reflects an increase of $74 million for remediation at the Utility’s gas compressor stations located near Hinkley, California and Topock, Arizona. The portion of the increased liability of $39 million for remediation at the Hinkley facility is attributable to changes in the California Regional Water Quality Control Board’s imposed remediation levels. Costs incurred at this facility are not recoverable from customers and, as a result, the after-tax impact on income was a reduction of approximately $23 million for 2006. Ninety percent of the estimated remediation costs associated with the Utility’s gas compressor station located near Topock, Arizona will be recoverable in rates in accordance with the hazardous waste ratemaking mechanism which permits the Utility to recover ninety percent of hazardous waste remediation costs from customers without a reasonableness review.
For more information about environmental remediation liabilities, see Note 17 of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.
Nuclear Fuel Disposal
Under the Nuclear Waste Policy Act of 1982, the Department of Energy, or the DOE, is responsible for the transportation and permanent storage and disposal of spent nuclear fuel and high-level radioactive waste. The Utility has contracted with the DOE to provide for the disposal of these materials from Diablo Canyon. Under the contract, if the DOE completes a storage facility by 2010, the earliest that Diablo Canyon's spent fuel would be accepted for storage or disposal is thought to be 2018. Under current operating procedures, the Utility believes that the existing spent fuel pools (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. After receiving a permit from the NRC in March 2004, the Utility began building an on-site dry cask storage facility to store spent fuel through at least 2024. The Utility estimates it could complete the dry cask storage project in 2008. The NRC’s March 2004 decision, however, was appealed by various parties, and the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, issued a decision in 2006 that requires the NRC to consider the environmental consequences of a potential terrorist attack at Diablo Canyon as part of the NRC’s supplemental assessment of the dry cask storage permit. The Utility may incur significant additional expenditures if the NRC decides that the Utility must change the design and construction of the dry cask storage facility. 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, 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 with respect to Unit 2 and until such time as additional spent fuel can be safely stored.
As a result of the DOE’s failure to develop a permanent storage facility, the Utility has been required to incur substantial costs for planning and developing on-site storage options for spent nuclear fuel as described above at Diablo Canyon as well as at the retired nuclear facility at Humboldt Bay, or Humboldt Bay Unit 3. The Utility is seeking to recover these costs from the DOE on the basis that the DOE has breached its contractual obligation to move used nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. Any amounts recovered from the DOE will be credited to customers. In October 2006, the U.S. Court of Federal Claims issued a decision awarding approximately $42.8 million of the $92 million incurred by the Utility through 2004. The Utility will seek recovery of costs incurred after 2004 in future lawsuits against the DOE. In January 2007, the Utility filed a notice of appeal of the U.S. Court of Federal Claims’ decision in the U.S. Court of Appeals for the Federal Circuit seeking to increase the amount of the award and challenging the court’s finding the Utility would have had to incur some of the costs for the onsite storage facilities even if the DOE had complied with the contract. If the court’s 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 onsite storage facilities from the DOE. However, reasonably incurred costs related to the onsite 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.
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.
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. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2024 and to be completed in 2044. Decommissioning of Diablo Canyon Unit 2 is scheduled to begin in 2025 and to be completed in 2041, and decommissioning of Humboldt Bay Unit 3 is scheduled to begin in 2009 and to be completed in 2015. The Utility's revenue requirements for estimated nuclear decommissioning costs are recovered from customers through a non-bypassable charge that will continue until those costs are fully recovered. 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. For more information about nuclear decommissioning, including the estimated decommissioning costs, see Note 13 of the Notes to the Consolidated Financial Statements in the 2006 Annual Report.
Electric and Magnetic Fields
Electric and magnetic fields, or 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, based primarily on its review of studies by others, evaluating the possible risks from EMFs, to the CPUC and the public. The report's conclusions contrast with other
recent reports by authoritative health agencies in that the California Department of Health Services' report has assigned a higher probability to the possibility 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 2006 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, or the Council, to oversee the development and implementation of a Land Conservation Plan, or 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 represent 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. While the Council originally contemplated adopting and presenting the LCP to the Utility by April 2007, it currently anticipates approving the LCP in the summer of 2007. The Utility will then seek authorization from the CPUC, the FERC and other approving entities to proceed with the transactions necessary to implement the LCP. If the Council is unable to reach consensus on all or part of the LCP, the Utility will seek regulatory approval of the transactions required to implement its own plan, along with a description of the positions of the disputing board members, before April 2013.
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, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or the 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.
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, or the Superior Court, against PG&E Corporation and its directors, as well as against directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200, or Section 17200. Among other allegations, the California Attorney General alleged that past transfers of 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, or 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, or the 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, or the District Court, 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 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 27, 2005, the California Court of Appeal summarily denied a petition filed by the California Attorney General and CCSF seeking to overturn this decision. The California Attorney General and CCSF have resumed discovery in the Superior Court action. The next case management conference is scheduled for April 17, 2007.
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.
The California Air Resources Board
The CARB oversees the Periodic Smoke Inspection Program to test and repair heavy-duty diesel vehicles in order to ensure efficient operations and reduce particulate matter emissions. The program applies to approximately 2,000 vehicles owned by the Utility. In July 2006, the CARB requested the Utility's program compliance records. The Utility discovered that its records were incomplete and that some records could not be located. The Utility immediately notified the CARB and began the evaluation and implementation of process improvements to ensure accurate recordkeeping. The CARB is authorized to assess penalties of up to $500 per missing or incomplete record. The Utility continues to work with the CARB and expects to resolve the matter in the first quarter of 2007. 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, or Exchange Act, at February 1, 2007, are as follows:
All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 1, 2007, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.
The names, ages and 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 1, 2007, are as follows:
All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2007, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
As of February 1, 2007, there were 92,901 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 2006 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 is hereby incorporated by reference from “Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Financial Resources - Dividends” of the 2006 Annual Report.
As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002, PG&E Corporation issued warrants to purchase 5,066,931 shares of PG&E Corporation common stock at an exercise price of $0.01 per share. During the year ended December 31, 2006, warrant holders exercised, on a net exercise basis, warrants to purchase 51,904 shares, and received 51,890 shares of PG&E Corporation common stock in reliance on the exemption from the registration requirements of the Securities Act of 1933 provided by Section 4(2) of the Act. As of December 31, 2006, warrant holders had exercised, on a net exercise basis, warrants to purchase 5,066,931 shares, and had received 5,065,099 shares of PG&E Corporation common stock since the warrants were issued. There are no more warrants outstanding.
Pacific Gas and Electric Company did not make any sales of unregistered equity securities during the quarter ended December 31, 2006.
Issuer Purchases of Equity Securities
PG&E Corporation common stock:
During the fourth quarter of 2006, Pacific Gas and Electric Company did not redeem or repurchase any shares of its various series of preferred stock outstanding.
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 2006 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 2006 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 2006 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 2006 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 2006 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, 2006, 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, or the 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, 2006 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 2006 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
Officer Appointments
On February 21, 2007, the Utility’s Board of Directors elected William T. Morrow, 47, as President and Chief Executive Officer of the Utility, effective July 1, 2007. Mr. Morrow will continue to report to Thomas B. King, currently Chief Executive Officer of the Utility, who will become President of PG&E Corporation effective July 1, 2007. Peter A. Darbee, currently Chairman of the Board, Chief Executive Officer, and President of PG&E Corporation, will become Chairman of the Board and Chief Executive Officer of PG&E Corporation effective July 1, 2007. Mr. Darbee will continue to serve as Chairman of the Board of the Utility.
Mr. Morrow has been President and Chief Operating Officer of the Utility since August 15, 2006. Before joining the Utility, Mr. Morrow held various executive positions in the telecommunications industry. Most recently Mr. Morrow served as Chief Executive Officer, Europe, of Vodafone Group PLC, a position he held from May 2006 to July 2006. From April 2005 to April 2006, Mr. Morrow served as President of Vodafone K.K. in Japan and from February 2004 to March 2005, he was Chief Executive Officer of Vodafone, U.K., Ltd. From December 2001 through January 2004, Mr. Morrow was President of Japan Telecom Holdings Co., Inc. and Japan Telecom Co., Inc. Previously in 2001, Mr. Morrow was Vice President and Country Manager, Japan for Vodafone Group PLC.
Mr. King has served as Chief Executive Officer of the Utility since August 15, 2006. Prior to that date, Mr. King served as President and Chief Executive Officer of the Utility, a position he held from January 1, 2006 to August 14, 2006. He served as Executive Vice President and Chief Operating Officer of the Utility from July 1, 2005 to December 31, 2005, and as Executive Vice President and Chief of Utility Operations from August 2, 2004 to June 30, 2005. From November 1, 2003 to August 1, 2004, he was Senior Vice President and Chief of Utility Operations of the Utility. Prior to November 1, 2003, Mr. King had been a Senior Vice President of PG&E Corporation from January 1, 1999. Since 2000, Mr. King also held various executive positions at PG&E National
Energy Group, Inc., a former subsidiary of PG&E Corporation involved in power generation, natural gas transmission, and wholesale energy marketing and trading. Mr. King focused his activities primarily in the natural gas transmission business. From November 15, 2002 to July 8, 2003, Mr. King served as the President and as a director of PG&E National Energy Group, Inc.
Mr. King and Mr. Morrow are entitled to receive equity awards under the PG&E Corporation 2006 Long-Term Incentive Plan and the PG&E Corporation Executive Stock Ownership Program. They are also eligible to receive annual cash incentive awards under an annual Short-Term Incentive Plan adopted by the PG&E Corporation Board of Directors. The Utility provides retirement benefits to all of its employees, including its officers, under a tax-qualified defined benefit pension plan. Officers of PG&E Corporation and the Utility are also entitled to receive pension benefits under the PG&E Corporation Supplemental Executive Retirement Plan, a non-tax qualified defined benefit pension plan. Officers of PG&E Corporation and the Utility may also participate in the PG&E Corporation Retirement Savings Plan, a 401(k) plan available to all eligible employees, and the PG&E Corporation Supplemental Retirement Savings Plan. PG&E Corporation also has adopted an Officer Severance Policy that covers officers of PG&E Corporation and the Utility. These plans, as well as perquisites provided to officers, are described in PG&E Corporation’s and the Utility’s 2006 joint proxy statement filed with the Securities and Exchange Commission.
Neither Mr. Morrow nor Mr. King has any relationship or related transaction with PG&E Corporation or the Utility that would require disclosure pursuant to Item 404(a) of Securities and Exchange Commission Regulation S-K.
Short-Term Incentive Plan
As previously disclosed, the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors, or the Committee, has approved the structure of the PG&E Corporation 2007 Short-Term Incentive Plan, or STIP, under which officers of PG&E Corporation and the Utility are provided an opportunity to receive annual incentive cash payments. Corporate financial performance, as measured by corporate earnings from operations, will account for 50 percent of the incentive, percent of the incentive will be based on customer satisfaction indices, percent of the incentive will be based on the Utility’s success in implementing its strategy to achieve operational excellence and improved customer service, 5 percent will be based on the results of an employee opinion survey measuring employee engagement, and the remaining 5 percent will be based on achieving safety standards. At its meeting on February 21, 2007, the Committee approved the specific performance scale that will be used to determine the extent to which the corporate financial objective, as measured by earnings from operations, has been met. The Committee used the same methodology to establish the performance scale for the corporate financial performance portion of the 2007 STIP as was used for the 2006 STIP. The corporate financial performance measure is based on PG&E Corporation's budgeted earnings from operations that were previously approved by the Board, 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 2007 performance targets for each of the four other measures set forth in the table below. The 2006 performance results for each measure are included for comparative purposes.
STIP Performance Targets (1)
1.
As explained above, 50% of the STIP award will be based on achievement of corporate earnings from operations targets.
2. This measure reflects a weighted composite of the overall customer satisfaction indices of the Utility’s residential and business customers as reported by the J.D. Power Residential Survey and the J.D. Power Business Survey. For 2006, the residential customers’ and business customers’ scores were weighted equally. In an effort to enhance the focus on improving residential customer satisfaction, which has been lower than business customer satisfaction, for the 2007 target the weighting of the residential customers’ score will be increased to 60% and the weighting of the business customers’ score will be lowered to 40%. In addition, for 2007, J.D. Power and Associates has changed the scale used to report results from the J.D. Power Survey from a scale that attempted to center the industry average score at approximately 100 to a 1,000-point scale. By way of comparison, results for 2006 would have been 678 under the new 1000-point scale based on equally weighted scores and results for 2006 would have been based on the revised weightings. The 2007 target may be adjusted to reflect changes in the J.D. Power industry average scores, which are expected by mid-year 2007.
3. The Business Transformation Index is comprised of five measurement points that define success in achieving key Business Transformation operational, financial, and post-implementation objectives. The five measurement points are (1) overall Business Transformation cost performance in comparison to budgeted amounts, (2) overall business transformation benefit performance in comparison to planned/budgeted amounts, (3) new business customer connection performance for cycle time and number of customer commitments met, (4) SmartMeterTM project performance for number of meters installed and activated, and (5) the extent to which core business transformation initiatives are implemented compared to planned schedule and scope of initiatives.
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. 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 Utility’s OSHA Recordable rate from the prior year.
The Committee has full discretion as to the determination of final officer STIP awards for 2007 performance.
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 2007 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, Compensation, and Governance 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 2006 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s joint proxy statement relating to the 2006 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 2007 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,” “Grants of Plan-based Awards in 2006,” “Outstanding Equity Awards at Fiscal Year End,” “Option Exercises and Stock Vested During 2006,” “Pension Benefits,” “Nonqualified Deferred Compensation,” and “Compensation of Directors,” and “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” in the Joint Proxy Statement relating to the 2007 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 2007 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Equity Compensation Plan Information
The following table provides information as of December 31, 2006 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.
(1) Includes 79,639 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 PG&E Corporation's Long-Term Incentive Program, or LTIP, and the PG&E Corporation 2006 Long-Term Incentive Plan, or 2006 LTIP, as of December 31, 2006. 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 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 2006 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 2007 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 2007 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 2006 Annual Report and are incorporated by reference in this report:
Consolidated Statements of Income for the Years Ended December 31, 2006, 2005, and 2004, for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 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, 2006, 2005, and 2004, 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, 2006 and 2005 and for the Years Ended December 31, 2006, 2005, and 2004.
II - Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2006, 2005, and 2004.
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:
* 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, 2006 to be signed on their behalf by the undersigned, thereunto duly authorized.
PG&E CORPORATION
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
HYUN PARK
(Registrant)
HYUN PARK
By:
(Hyun Park, Attorney-in-Fact)
By:
(Hyun Park, Attorney-in-Fact)
Date:
February 22, 2007
Date:
February 22, 2007
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.
(Hyun Park, Attorney-in-Fact)
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, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, management’s assessment of the effectiveness of the Company’s and the Utility’s internal control over financial reporting as of December 31, 2006, and the effectiveness of the Company’s and the Utility’s internal control over financial reporting as of December 31, 2006, and have issued our reports thereon dated February 21, 2007; such consolidated financial statements and reports are included in your 2006 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 the 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, 2007
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)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
(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, 2006 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.
(2) 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, 2006, 2005 and 2004
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2006, 2005 and 2004
EXHIBIT INDEX
* Management contract or compensatory agreement.
** Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.