SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the Fiscal Year Ended December 31, 2010
For the transition period from to
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2010, the last business day of the most recently completed second fiscal quarter:
Common Stock outstanding as of February 7, 2011:
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (Utility), a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997.
The Utility served approximately 5.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2010. The Utility had approximately $45.7 billion in assets at December 31, 2010 and generated revenues of $13.8 billion in 2010. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). In addition, the Nuclear Regulatory Commission (NRC) oversees the licensing, construction, operation, and decommissioning of the Utilitys nuclear generation facilities.
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 or furnish various reports with the Securities and Exchange Commission (SEC). These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (1934 Act), are available free of charge on both PG&E Corporations website, www.pgecorp.com, and the Utilitys website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC . 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.
This is a combined Annual Report on Form 10-K of PG&E Corporation and the Utility and includes information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2010 (2010 Annual Report) and the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders.
At December 31, 2010, PG&E Corporation and its subsidiaries had 19,424 regular employees, including 19,381 regular employees of the Utility. Of the Utilitys regular employees, 12,236 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (IBEW); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC (ESC); and the Service Employees International Union, Local 24/7 (SEIU). One IBEW collective bargaining agreement expires on December 31, 2011 and the other expires on December 31, 2015. The ESC collective bargaining agreement expires on December 31, 2011. The SEIU collective bargaining agreement expires on July 31, 2012.
Both the National Transportation Safety Board (NTSB) and the CPUC have begun investigations of the September 9, 2010 rupture of an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility in a residential area located in the City of San Bruno, California (the San Bruno accident).
The ensuing explosion and fire resulted in the deaths of eight people and injuries to numerous individuals. At least thirty-four houses were destroyed and many additional houses were damaged. The NTSB has not yet determined the cause of the pipeline rupture. The NTSB has publicly issued some preliminary reports and has announced that it will hold fact-finding hearings on March 1-3, 2011 to learn more about the San Bruno accident and important safety issues.
Various lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility. (See Item 3. Legal Proceedings, below.) In addition, on November 19, 2010, the CPUC began a formal investigation of the December 24, 2008 natural gas explosion in a house located in Rancho Cordova, California that resulted in one death, injuries to several people, and property damage (the Rancho Cordova accident). For more information about these investigations and related matters see Pending Investigations and Risk Factors in the 2010 Annual Report.
This combined Annual Report on Form 10-K, including the information incorporated by reference from the 2010 Annual Report and the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, 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 managements knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated environmental remediation, tax, and other liabilities, estimates and assumptions used in PG&E Corporations and the Utilitys critical accounting policies, the anticipated outcome of various regulatory, governmental, and legal proceedings, estimated losses and insurance recoveries associated with the San Bruno accident, estimated future cash flows, and the level of future equity or debt issuances. These statements are also identified by words such as assume, expect, intend, plan, project, believe, estimate, target, 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:
For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporations and the Utilitys future financial condition and results of operations, see the discussion in the section entitled Risk Factors in the 2010 Annual Report. 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.
As a public utility holding company, PG&E Corporation is subject to the requirements of the Energy Policy Act of 2005 (EPAct). Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005). Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.
PG&E Corporation is not a public utility under California law. The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:
The CPUC also has adopted complex and detailed rules governing transactions between Californias electricity and gas utilities and certain of their affiliates. The rules address the use of the utilities names and logos by their affiliates, the separation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates. The rules also:
The CPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.
Various aspects of the Utilitys business are subject to a complex set of energy, environmental and other laws, regulations, and regulatory proceedings at the federal, state, and local levels. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935, as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938, and the Public Utility Regulatory Policies Act of 1978 (PURPA).
This section and the Ratemaking Mechanisms section below summarize some of the more significant laws, regulations, and regulatory mechanisms affecting the Utility. These summaries are not an exhaustive description of all the laws, regulations, and regulatory proceedings that affect the Utility. The energy laws, regulations, and regulatory proceedings may change or be implemented or applied in a way that the Utility does not currently anticipate. For discussion of specific pending regulatory proceedings that are expected to affect the Utility, see Regulatory Matters and Pending Investigations in the 2010 Annual Report.
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 California Independent System Operator (CAISO), and the terms and rates of wholesale electricity sales. The FERC has authority to impose penalties of up to $1,000,000 per day 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 has jurisdiction over the Utilitys electricity transmission revenue requirements and rates, the licensing of substantially all of the Utilitys hydroelectric generation facilities, and the interstate sale and transportation of natural gas.
Electric Reliability Standards; Development of Transmission Grid. The FERC has the responsibility to approve and enforce mandatory standards governing the reliability of the nations electricity transmission grid, including standards to protect the nations bulk power system against potential disruptions from cyber and physical security breaches, 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 FERC certified the North American Electric Reliability Corporation (NERC) as the nations Electric Reliability Organization under the EPAct. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval. The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council (WECC). The Utility must self-certify compliance to the WECC on an annual basis and the compliance program encourages self-reporting of violations. WECC staff, with participation by the NERC and the FERC, will also perform a regular compliance audit of the Utility every three years. In addition, the WECC and the NERC may perform spot checks or other interim audits, reports, or investigations. Under FERC authority, the WECC, NERC, and/or FERC may impose penalties up to $1,000,000 per day per violation.
The FERC also has issued rules on electric transmission pricing reforms designed to promote needed investment in energy infrastructure, to reduce transmission congestion, and to require transmission organizations with organized electricity markets to make long-term firm transmission rights available to load-serving entities, so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk. In addition, pursuant to FERC orders, the CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions, and ensuring the maintenance of adequate reserves of generation capacity.
Prevention of Market Manipulation. The FERC has broad authority to police and penalize the exercise of market power or behavior intended to manipulate prices paid in FERC-jurisdictional transactions. The FERC has
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 FERCs regulations, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas, electric energy, or transportation/transmission services subject to the jurisdiction of the FERC (1) to use or employ any device, scheme, or artifice to defraud, (2) to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) to engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any person.
QF Regulation. Under PURPA, electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that meet the statutory definition of a qualifying facility (QF). (QFs primarily include co-generation facilities that produce combined heat and power (CHP) and renewable generation facilities.) 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 terminate the obligation of an electric utility 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 a termination of such obligations on a service territory-wide basis. For more information about the Utilitys QF agreements, see Electricity Resources Third-Party Power Purchase Agreements, below.
The Nuclear Regulatory Commission. The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utilitys retired nuclear generating unit at Humboldt Bay (Humboldt Bay Unit 3). NRC regulations require extensive monitoring and review of the safety, radiological, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.
California Legislature. The Utilitys operations have been significantly affected by statutes passed by the California legislature, including laws related to electric industry restructuring, the 2000-2001 California energy crisis, electric resource adequacy, renewable energy resources, power plant siting and permitting, and GHG emissions and other environmental matters.
The CPUC. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms. The CPUC has jurisdiction to set the rates, terms, and conditions of service for the Utilitys electricity distribution, electricity generation, natural gas distribution, and natural gas transportation and storage services in California. The CPUC also has jurisdiction over the Utilitys issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utilitys electricity and natural gas retail customers, rate of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service. The CPUC also enforces law that sets forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas gathering, transmission, and distribution piping systems, and for the safe operation of such lines and equipment.
Ratemaking for retail sales from the Utilitys 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 Utilitys operations, and regularly reviews the Utilitys 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.
PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utilitys proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court) since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utilitys financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utilitys plan of reorganization under Chapter 11, which became effective on April 12, 2004. 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.
The California Energy Resources Conservation and Development Commission. The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission (CEC), is the states 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.
The California Air Resources Board. The California Air Resources Board (CARB) is the state agency charged with setting and monitoring greenhouse gas (GHG) and other emission limits. The CARB also is responsible for adopting and enforcing regulations to meet Californias landmark law, the California Global Warming Solutions Act of 2006 (AB 32), which requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. (For more information see Environmental Matters Air Quality and Climate Change below.)
The Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utilitys generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. These permits include 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. 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 also is subject to regulations adopted by the Pipeline and Hazardous Materials Safety Administration (PHMSA) that is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nations pipeline transportation system and the shipment of hazardous materials. The CPUC also is authorized to enforce the federal pipeline safety standards, as well as state pipeline safety requirements, through penalties and/or injunctive relief.
The NTSB is an independent federal agency that is authorized to investigate pipeline accidents and certain transportation accidents that involve fatalities, substantial property damage, or significant environmental damage. The NTSB is currently investigating the San Bruno accident. (See Item 3. Legal Proceedings, below and Pending Investigations in the 2010 Annual Report for more information.)
The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate, and maintain the Utilitys electric and natural gas facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In
addition, charter cities can negotiate their fees. In most cases, the Utilitys franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term, including an agreement with a large charter city. The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the use of the public streets. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations, and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utilitys business and to conduct certain related operations.
Historically, energy utilities operated as regulated monopolies within service territories in which they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport, and distribute energy. Services were priced on a combined, or bundled, basis, with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertook a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.
In recent years, legislative and regulatory changes have brought competition to certain aspects of the energy industry, primarily the commodity componentsthe supply of electricity and natural gas to customers. Regulators and legislators, to varying degrees, have required utilities to separate (or unbundle) the prices of the energy commodities and the rates for utility services in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.
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 FERCs policies supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities transmission grids. Order 888 requires all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (OATT) that contains minimum terms and conditions of non-discriminatory service. The FERCs subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, and advanced the view that a regulated unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination, (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERCs enforcement, and (3) increase transparency in the rules applicable to planning and use of the transmission system.
The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generation and transmission. Under the rules and associated tariffs,
a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator. The generator will be reimbursed over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades is then recovered by the regulated transmission provider in its overall transmission rates.
On June 17, 2010, the FERC issued a notice of proposed rulemaking and established a proceeding to examine, among other issues, whether to change the FERCs existing policy that provides incumbent traditional public utilities a right of first refusal to own, construct, and operate transmission facilities within their respective service territories. The rules that the FERC adopts in this proceeding may introduce additional competition from merchant or independent transmission project developers for the construction of certain transmission facilities that do not exist today.
State. At the state level, California Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry beginning in 1998 to allow customers of the California investor-owned electric utilities to purchase energy from a service provider other than the regulated utilities (the ability to choose an energy provider is referred to as direct access). Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted through the Power Exchange (PX). Following the 2000-2001 California energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile remaining refund amounts owed and to make compliance filings as required by the FERC in the California refund proceeding, which is still pending at the FERC. (For information about the status of the California refund proceeding and the remaining disputed claims made by power suppliers in the Utilitys Chapter 11 proceeding, see Note 13 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.)
California Assembly Bill 1X authorized the California Department of Water Resources (DWR), beginning in February 1, 2001, to purchase electricity and sell that electricity directly to the utilities retail customers. Assembly Bill 1X requires the utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWRs billing and collection agent. To ensure that the DWR recovers the costs that it incurs under its power purchase contracts, the CPUC suspended direct access on September 20, 2001, but allowed existing direct access customers to continue being served by alternative energy service providers. As authorized by California Senate Bill 695, enacted on October 11, 2009, the CPUC has adopted a plan to reopen direct access on a limited and gradual basis to allow eligible customers of the three California investor-owned utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 11, 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and absolute caps. It is estimated that the total amount of direct access that will be allowed in the Utilitys service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utilitys total annual retail sales at the end of the period, roughly the highest level that was reached before the CPUC suspended direct access. Further legislative action is required to exceed these limits. The adopted phase-in schedule is designed to provide enough lead time for the utilities to account for small shifts in load and avoid unwarranted cost shifting and stranded costs.
Assembly Bill 1890 also 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. On April 1, 2009, the CAISO implemented new day-ahead, hour-ahead, and real-time wholesale electricity markets subject to bid caps that increase over time, as part of the implementation of the CAISOs Market Redesign and Technology Upgrade initiative (MRTU). Market participants, including load-serving entities like the Utility, are permitted to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market by acquiring congestion revenue rights.
In addition, the Utilitys customers may, under certain circumstances, obtain power from a community choice aggregator instead of from the Utility. California Assembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under Assembly Bill 117, the Utility continues to provide distribution, metering, and billing services to the community choice aggregators customers and remains the electricity provider of last resort for those customers. Assembly Bill 117 provides that a community choice aggregator can 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 and allowing a community choice aggregator to start service in phases. 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 all customers any costs of implementing the program not reasonably attributable to a community choice aggregator.
In some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or state statute to provide retail electric service, seek to acquire the Utilitys distribution facilities. For example South San Joaquin Irrigation District (SSJID) has applied to San Joaquin County Local Agency Formation Commission for the authority to provide electric distribution service in and around the cities of Manteca, Ripon and Escalon. SSJID has indicated that, if it receives the requested authority, it will seek to acquire the Utilitys distribution facilities, either under a consensual transaction, or via eminent domain.
It is also possible that technological developments, such as distributed generation and the increased use of electric vehicles, could pose competitive challenges for traditional utilities. In July 2010, the CPUC found that although the California Legislature did not intend that the CPUC regulate providers of electric vehicle charging services as public utilities, the CPUC has authority to regulate aspects of electric vehicle charging services. These aspects include rules relating to the deployment of electric vehicles; the terms under which a utility will provide services to the electric vehicle charging provider; retail electricity rates paid by the electric vehicle charging provider to a regulated utility; standards and protocols to ensure functionality and interoperability between utilities and electric vehicle charging providers; and various electricity procurement requirements that apply to electricity service providers generally, such as resource adequacy and renewable energy procurement standards. A second phase of the CPUC proceeding will examine the role of the regulated utility in electric vehicle charging programs, ways to manage the impact of such programs on the electric infrastructure, the cost to customers of such programs, and other issues.
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 Utilitys natural gas pipelines are located within the State of California and are exempt from the FERCs rules and regulations applicable to interstate pipelines; the Utilitys pipeline operations are instead subject to the jurisdiction of the CPUC.
The Utilitys 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 the FERC for interstate gas pipelines. The CPUC divides the Utilitys natural gas customers into two categories: core customers who are primarily small commercial and residential customers, and non-core customers who are primarily industrial, large commercial, and electric generation customers. Under the Gas Accord structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or as-available) services. All services are offered on a nondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utilitys citygate, which refers to the interconnection between the big backbone gas transmission system and the smaller downstream local transmission systems.
The Gas Accord separated the Utilitys natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utilitys transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally, the Gas Accord eliminated balancing account protection for some services, increasing the Utilitys risk/reward potential. The Utilitys first Gas Accord, a settlement agreement reached among the Utility and many interested parties, was approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve another settlement agreement known as the Gas Accord V to continue a majority of the Gas Accords terms and conditions for the Utilitys natural gas transportation and storage services beginning January 1, 2011 and continuing through 2014. (See Regulatory Matters 2011 Gas Transmission and Storage Rate Case in the 2010 Annual Report.)
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 Utilitys 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 Utilitys 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 Utilitys 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.
The Utilitys rates for electricity and natural gas utility services are based on its costs of providing service (cost-of-service ratemaking). Before setting rates, the CPUC and the FERC determine the annual amount of revenue (revenue requirements) that the Utility is authorized to collect from its customers. The CPUC determines the Utilitys revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utilitys revenue requirements associated with its electricity transmission operations.
Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of providing utility services as well as a return of, and a fair rate of return on, its investment in utility facilities (rate base). Revenue requirements are primarily determined based on the Utilitys forecast of future costs. These costs include the Utilitys costs of electricity and natural gas purchased for its customers, operating expenses, administrative and general expenses, depreciation, taxes, and public purpose programs.
Regulatory balancing accounts are used to adjust the Utilitys revenue requirements. Sales balancing accounts track differences between the Utilitys recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations. In general, electricity sales are higher in the summer months and natural gas sales are higher in the winter months. Cost balancing accounts track differences between the Utilitys incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes that can be affected by seasonal demand, weather, and other factors. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.
To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial, and agricultural) and to various service components (mainly customer, demand, and energy). Specific rate components are designed to produce the required revenue. Rate changes become effective prospectively on or after the date of CPUC or FERC decisions. Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.
Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base. The Utility may be unable to earn its authorized rate of return because the CPUC or the FERC excludes some of the Utilitys actual costs from the revenue requirements or because the Utilitys actual costs are higher than those reflected in the revenue requirements.
While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on the extent to which the utilities meet objective or fixed standards or goals, such as reliability standards or energy efficiency goals, instead of on the cost of providing service.
The General Rate Case (GRC) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utilitys 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 Utilitys GRC include the CPUCs Division of Ratepayer Advocates (DRA) and The Utility Reform Network (TURN). In the Utilitys currently pending GRC, the CPUC will authorize the Utilitys revenue requirements for 2011 through 2013. On October 15, 2010, the Utility, together with the DRA, TURN, Aglet Consumer Alliance, and nearly all other intervening parties, filed a motion with the CPUC seeking approval of a settlement agreement to resolve almost all of the issues raised by the parties in the Utilitys 2011 GRC. For more information, see Regulatory Matters 2011 General Rate Case in the 2010 Annual Report.
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 Utilitys 2011 GRC includes a provision for attrition rate increases in 2012 and 2013.
The CPUC authorizes the Utilitys capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) and the authorized rates of return on each component that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The current authorized capital structure consisting of 52% equity, 46% long-term debt, and 2% preferred stock will remain in effect through 2012 unless the automatic adjustment mechanism described below is triggered.
The CPUC has adopted a cost of capital adjustment mechanism which uses an interest rate index (the 12-month October through September average of the Moodys Investors Service utility bond index) to trigger changes in the authorized cost of debt, preferred stock, and equity. In any year in which the 12-month October through September average for the index increases or decreases by more than 100 basis points (deadband) from the benchmark, the cost of equity will be adjusted by one-half of the difference between the 12-month average and the benchmark. In addition, if the mechanism is triggered, the costs of long-term debt and preferred stock will be adjusted to reflect the actual August month-end embedded costs in that year and forecasted interest rates for variable long-term debt and any new long-term debt and preferred stock forecasted to be issued in the coming year.
This mechanism did not trigger a change in the Utilitys authorized rates of return for 2011 which remain set at 6.05% for long-term debt, 5.68% for preferred stock, and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%.
The Utilitys next full cost of capital application must be filed by April 20, 2012, so that any resulting changes would become effective on January 1, 2013. The Utility may apply for an adjustment to either the capital structure or the cost of capital sooner based on extraordinary circumstances.
Although the FERC has authority to set the Utilitys rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utilitys transmission rates are determined through a negotiated rate settlement.
Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utilitys own generation facilities and existing electricity contracts (including DWR contracts allocated to the Utility under Assembly Bill 1X). To accomplish this, each utility must submit a long-term procurement plan covering a 10-year period to the CPUC for approval. Each long-term procurement plan must be designed to reduce GHG emissions and use the State of Californias preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation).
In December 2007, the CPUC approved the utilities long-term electricity procurement plans, covering 2007 through 2016, subject to certain required modifications. California legislation, Assembly Bill 57, allows the utilities to recover the costs incurred in compliance with their CPUC-approved procurement plans without further after-the-fact reasonableness review. Each utility may, if appropriate, conduct a competitive request for offers (RFO) within the parameters permitted in its approved plan to meet the utilitys projected need for electricity resources. Contracts that are entered into after the RFO process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the associated costs. The utilities conduct separate competitive solicitations to meet their renewable energy resource requirements. The utilities submit the renewable energy contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements. For more information, see Electric Utility Operations Electricity Resources Future Long-Term Generation Resources below.
The Utility recovers its electricity procurement costs and the fuel costs for the Utilitys own generation facilities (but excluding the costs of electricity allocated to the Utilitys customers under DWR contracts) through the Energy Resource Recovery Account (ERRA), a balancing account authorized by the CPUC in accordance with Assembly Bill 57. The ERRA tracks the difference between (1) billed/unbilled ERRA revenues and (2) electric procurement costs incurred under the Utilitys authorized procurement plans. To determine rates used to collect ERRA revenues, each year the CPUC reviews the Utilitys forecasted procurement costs related to power purchase agreements and generation fuel expense and approves a forecasted revenue requirement. The CPUC also performs an annual compliance review of the procurement activities recorded in the ERRA to ensure that the Utilitys procurement activities are prudent and in compliance with its CPUC-approved procurement plans.
Although California legislation requiring the CPUC to adjust a utilitys retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utilitys 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 utilitys resource commitment or 10 years, whichever is longer. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.
The CPUC has not yet issued a decision to complete the Utilitys 2009 ERRA compliance review proceeding.
The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utilitys CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements. The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.
For new non-renewable generation purchased from third parties under power purchase agreements, the Utility may elect to recover any above-market costs through either (1) the imposition of a non-bypassable charge 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 Utilitys service territory, including existing direct access customers and community choice aggregation customers. (For information about the status of direct access and community choice aggregation, see the section above entitled Competition in the Electricity Industry.)
The non-bypassable charge can be imposed from the date of signing a power purchase agreement and can 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 are allocated for the term of the contract or 10 years, whichever is shorter, 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 subject to allocation. If no bids are accepted for the energy rights, the Utility would retain the rights to the energy and would value it at market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.
California Senate Bill 695, enacted on October 11, 2009, also includes a mechanism for recovery of above-market costs from direct access and community choice aggregation customers. The CPUC has not yet implemented this portion of Senate Bill 695.
The CPUC-authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for operating Utility-owned generation facilities are addressed in the Utilitys GRC. The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through a balancing account, the Utility Generation Balancing Account (UGBA), which tracks 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 Utility-owned projects generally would begin to accrue in the UGBA as of the new facilitys 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. For more information, see Capital Expenditures in the 2010 Annual Report.
During the 2000-2001 California 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 DWRs revenue requirements to recover costs associated with the DWRs $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 DWRs revenue requirement and to provide the DWR with funds to make its electricity purchases. The Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utilitys revenues.
The Utilitys 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 (1) charges under the Utilitys transmission owner tariff and (2) 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 Utilitys transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utilitys retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.
The primary FERC ratemaking proceeding to determine the amount of revenue requirements that the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (TO rate case). The Utility generally files a TO rate case every year. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. For more information about the Utilitys TO rate cases, see Regulatory Matters Electric Transmission Owner Rate Cases in the 2010 Annual Report.
The Utilitys transmission owner tariff includes two rate components. The primary component consists of base transmission rates intended to recover the Utilitys operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense, and return on equity. The Utility derives the majority of the Utilitys 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 for providing wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) to third parties using the Utilitys transmission facilities. These revenues are adjusted by the shortfall or surplus resulting from any cost differences between the amount that the Utility is entitled to receive from existing transmission contract customers under specific contracts and the amount that the Utility is entitled to receive or be charged for scheduling services under the CAISOs rules and protocols.
The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge on the Utility for the use of the CAISO-controlled electric transmission grid in serving its customers. This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology results in a cost shift to 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, from transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The cost shift amounts are recovered from the Utilitys retail customers as part of retail transmission rates.
The Utilitys authorized natural gas transmission and storage rates and associated revenue requirements from January 1, 2008 through December 31, 2010 were set in accordance with the CPUC-approved settlement agreement known as the Gas Accord IV. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve another settlement agreement known as the Gas Accord V to continue a majority of the Gas Accord IVs terms and conditions for the Utilitys natural gas transportation and storage services beginning January 1, 2011 and continuing through 2014. (See Regulatory Matters- 2011 Gas Transmission and Storage Rate Case in the 2010 Annual Report.) A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utilitys ability to recover the remaining revenue requirements would continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:
Backbone Transmission. The backbone transmission revenue requirement is recovered through a combination of firm two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available one-part rates (consisting only of volumetric usage charges). The mix of firm and as-available backbone services provided by the Utility continually changes. As a result, the Utilitys recovery of its backbone transmission costs is subject to volumetric and price risk to the extent that backbone capacity is sold on an as-available basis. Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity. Core customers are allocated approximately 36% of the total backbone capacity on the Utilitys system. Core customers pay approximately 72% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.
Local Transmission. The local transmission revenue requirement is allocated approximately 71% to core customers and 29% to non-core customers. The Utility recovers the portion allocated to core customers through a balancing account, but the Utilitys recovery of the portion allocated to non-core customers is subject to volumetric and price risk.
Storage. The storage revenue requirement is allocated approximately 71% to core customers, 12% to non-core storage service, and 17% to pipeline load balancing service. The Utility recovers the portion allocated to core customers through a balancing account, but the Utilitys recovery of the portion allocated to non-core customers is subject to volumetric and price risk. The revenue requirement for pipeline load balancing service is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.
Certain of the Utilitys natural gas distribution costs and balancing account balances are allocated to customers in the CPUCs 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.
The Utility sets the natural gas procurement rate for core customers monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.
The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under the Core Procurement Incentive Mechanism (CPIM). Under the CPIM, the Utilitys purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers rates. One-half of the costs above 102% of the benchmark are recoverable in customers rates, and the Utilitys customers receive in their rates 80% of any savings resulting from the Utilitys cost of natural gas that is less than 99% of the benchmark. The remaining amount of savings are retained by the Utility as incentive revenues, subject to a cap equal to 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.
In January 2010, the CPUC approved a joint settlement agreement among the Utility, the CPUCs Division of Ratepayer Advocates, and The Utility Reform Network to incorporate a portion of hedging costs for core customers into the Utilitys CPIM beginning November 1, 2010. The settlement agreement has an initial term of seven years, through October 2017, which can be extended by agreement of the parties. As a result, the settlement agreement permits the Utility to develop and implement a sustained core hedging program. (For more information, see Note 10: Derivatives and Hedging Activities, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report).
The Utilitys 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 Utilities Commission and the National Energy Board. The Utilitys agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utilitys 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 Utilitys natural gas transportation system begins. For more information, see the discussion below under Natural Gas Utility Operations Interstate and Canadian Natural Gas Transportation Services Agreements.
The Utility is required to maintain physical generating capacity adequate to meet its customers demand for electricity (load), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. 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. The following table shows the percentage of the Utilitys total actual deliveries of electricity in 2010 represented by each major electricity resource:
Total 2010 Actual Electricity Delivered: 77,772 GWh:
At December 31, 2010, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:
Diablo Canyon Power Plant. The Utilitys Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. For the twelve months period ended December 31, 2010, the Utilitys Diablo Canyon power plant achieved an average overall capacity factor of approximately 95%. The NRC operating license for Unit 1 expires in November 2024, and the NRC operating license for Unit 2 expires in August 2025. In November 2009, the Utility filed an application at the NRC requesting that each of these licenses be renewed for 20 years. The license renewal process is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. (See the discussion under the heading Risk Factors that appears in the MD&A section of the 2010 Annual Report.) Under the terms of the NRC operating licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by the Diablo Canyon plant. For a discussion of the Utilitys spent fuel storage project, see Environmental Matters Nuclear Fuel Disposal below.
The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel. The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 15: Commitments and Contingencies Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.
The following table outlines the Diablo Canyon power plants refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 46 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.
Hydroelectric Generation Facilities. The Utilitys hydroelectric system consists of 110 generating units at 69 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. Most of the Utilitys hydroelectric generation units are classified as large hydro facilities, as their unit capacity exceeds 30 MW. The system includes 99 reservoirs, 56 diversions, 170 dams, 172 miles of canals, 43 miles of flumes, 130 miles of tunnels, 54 miles of pipe (penstocks, siphons and low head pipes), and 5 miles of natural waterways. The system also includes water rights as specified in 89 permits or licenses and 159 statements of water diversion and use.
All of the Utilitys powerhouses are licensed by the FERC (except for three small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years. In the last three years, the FERC renewed two hydroelectric licenses associated with a total of 110 MW of hydroelectric power. The Utility is in the process of renewing licenses for projects associated with approximately 1,077 MW of hydroelectric power. Although the original licenses associated with 520 MW of the 1,077 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 3,367 MW of hydroelectric power will expire between 2011 and 2047.
During 2010, electricity from the DWR contracts allocated to the Utility provided approximately 6% of the electricity delivered to the Utilitys customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. The Utility expects that the amount of power supplied under the DWRs contracts will diminish in the future as these contracts expire or are novated to the Utility.
Qualifying Facility Power Purchase Agreements. As described above under The Utilitys Regulatory Environment-Federal Energy Regulation, the Utility currently is required to purchase energy and capacity from independent power producers that are QFs. As of December 31, 2010, the Utility had power purchase agreements with 226 QFs for approximately 3,700 MW that are in operation. Agreements for approximately 3,400 MW expire at various dates between 2011 and 2028. QF power purchase agreements for approximately 300 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 75 inoperative QFs. The total of approximately 3,700 MW consists of 2,500 MW from cogeneration projects, and 1,200 MW from renewable generation resources, as discussed below. QF power purchases accounted for 18.5% of the Utilitys 2010 electricity deliveries. No single QF accounted for more than 5% of the Utilitys 2010 electricity deliveries.
In December 2010, the CPUC approved a settlement agreement among the California investor-owned utilities, ratepayer groups, and representatives of the facilities that use combined heat and power (CHP), including CHP facilities that also qualify as QFs. The settlement establishes a new CHP/QF program that sets CHP procurement targets and GHG reduction targets (consistent with AB 32), provides for a transition of existing QF energy pricing to market-based pricing by 2015, and implements new standard power purchase agreements. In accordance with the settlement agreement, the utilities will file a joint application with the FERC requesting the
FERC to terminate the utilities obligations under PURPA to purchase power from all QFs sized 20 MW and above which includes the settling CHP/QFs. The settlement agreement will become effective when the CPUC decision becomes final and non-appealable, and when a FERC decision granting the utilities PURPA termination application becomes final and non-appealable. The FERC is expected to issue a decision on the utilities application in the second quarter of 2011.
Irrigation Districts and Water Agencies. The Utility also has entered into contracts with various irrigation districts and water agencies to purchase hydroelectric power. These agreements are based on debt service requirements (regardless of the amount of power supplied), and include variable payments to the counterparty for operation and maintenance costs. These contracts will expire on various dates between 2011 and 2031. In 2010, they accounted for 4.52% of the Utilitys electricity deliveries.
Other Power Purchase Agreements. The Utility has entered into power purchase agreements, including agreements to purchase renewable energy that were entered into following annual solicitations and separate bilateral negotiations. In addition, in accordance with the Utilitys CPUC-approved long-term procurement plan, the Utility has entered into power purchase agreements for conventional generation resources. During 2010, the Utilitys purchases under these agreements accounted for 10.20% of the Utilitys deliveries. When market prices and forecasted load conditions are favorable, the Utility also has the ability to procure electricity through the spot bilateral and CAISO markets. Electricity purchased in these markets accounted for 18.38% of the Utilitys deliveries in 2010.
For more information regarding the Utilitys power purchase contracts, see Note 15: Commitments and Contingencies Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.
Current California law requires California retail sellers of electricity, such as the Utility, to comply with a renewable portfolio standard (RPS) by increasing their deliveries of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from renewable resources equals at least 20% of their total retail sales by the end of 2010. If a retail seller is unable to meet its target for a particular year, the current CPUC flexible compliance rules allow the retail seller to use future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three years of the shortfall. Whether a retail seller who relies on flexible compliance rules has met the RPS target for a particular year may not be known until the end of the associated three-year roll-forward period. The CPUC has indicated that it currently intends to limit its discretion to levy penalties for an unexcused failure to meet an applicable RPS target to a maximum of $25 million per year per retail seller.
For the year ended December 31, 2010, the Utilitys RPS-eligible renewable resource deliveries equaled 15.9% of its total retail electricity sales. Most renewable energy deliveries resulted from third party contracts, mainly QF agreements and bilateral contracts. Additional renewable resources included the Utilitys small hydro and solar facilities and certain irrigation district contracts (small hydro facilities). (Under California law only hydroelectric generation resources with a capacity of 30 MW or less can qualify as a renewable resource for purposes of meeting the RPS mandate. Most of the Utilitys hydroelectric generating units have a capacity in excess of 30 MW and do not qualify as RPS-eligible resources.)
Total 2010 renewable deliveries are stated in the table below.
For more information regarding the Utilitys renewable energy contracts, see Note 15: Commitments and Contingencies Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.
In April 2010, the CPUC approved the Utilitys proposed five-year program for the development of up to 250 MW of solar photovoltaic (PV) facilities and to enter into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties.
In addition, under its authority to implement AB 32, the CARB has adopted regulations that require virtually all load-serving entities, including the Utility, to increase their deliveries of renewable energy to meet specific annual targets. For 2012, 2013, and 2014, the amount of electricity delivered from renewable energy resources must equal at least 20% of total energy deliveries, increasing to 24% in 2015, 2016, and 2017, 28% in 2018 and 2019, and 33% in 2020 and beyond. For more information about these renewable energy requirements, see Environmental Matters-Renewable Energy Resources in the 2010 Annual Report.
Finally, legislation has been introduced in the California state legislature that proposes to increase the current RPS from 20% to 33% by 2020. Under the proposed bill, Senate Bill 23, the amount of electricity delivered from renewable energy resources must equal at least 25% of total energy deliveries by December 31, 2016 and 33% by December 31, 2020. If enacted, the bill would become effective on January 1, 2012. It is unclear how this proposed legislation, if adopted, would affect the CARBs renewable energy delivery requirement.
The Utility plans to meet future electricity demand by focusing first on reducing consumption through energy efficiency and demand response programs, then by securing environmentally preferred energy resources, such as renewable generation and distributed generation (including solar power), and finally by relying on clean and efficient fossil-fueled generation resources. The CPUC has authorized the Utility to obtain new long-term generation resources to meet approximately 1,500 MW of forecast demand by 2016 through power purchase agreements or the development of new Utility-owned generation facilities.
The CPUC allows the California investor-owned utilities to acquire ownership of new conventional generation resources through purchase and sale agreements (PSAs) (a PSA is a turnkey arrangement in which a new generating facility is constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements). The utilities are prohibited from submitting offers for utility-build generation in their respective RFOs until questions can be resolved about how to compare offers for utility-owned generation with offers from independent power producers. The utilities are permitted to propose utility-owned generation projects through a separate application outside of the RFO process in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement), and (4) to meet unique reliability needs.
The CPUC has recently approved the Utilitys proposal to acquire the 586-MW Oakley Generation Station to be developed and constructed by a third party; however several applications for rehearing of this decision have been filed. For more information, see Capital Expenditures in the 2010 Annual Report.
At December 31, 2010, the Utility owned approximately 18,600 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of approximately 57,953 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through approximately 141,346 circuit miles of distribution lines and substations with a capacity of 28,244 MVA. In 2010, the Utility delivered 77,772 GWh to its customers, and approximately 6,000 GWh to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.
During 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 entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO. The Utility is required to give the CAISO two years notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.
The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998. In addition, under the mandatory reliability standards implemented following the EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards. See the discussion of reliability standards above under The Utilitys Regulatory Environment Federal Energy Regulation.
The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utilitys transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (RMR) agreements with the CAISO. (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISOs demand when the generation from those RMR units is needed for local transmission system reliability.)
The Utilitys electricity distribution network extends through 47 of Californias 58 counties, comprising most of northern and central California. The Utilitys network consists of approximately 141,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 93 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utilitys network includes 600 distribution substations and 118 low-voltage distribution substations. The 53 combined transmission and distribution substations have both transmission and distribution transformers.
The Utilitys distribution network interconnects to the Utilitys electricity transmission system at approximately 1,122 points. This interconnection between the Utilitys 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 Utilitys customers. The distribution substations serve as the central hubs of the Utilitys 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.
Much of the Utilitys electric transmission and distribution infrastructure was placed into service in the 1940s through the 1960s as Californias population and economy grew. The Utility makes capital investments in its electric transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.
The CPUC has authorized the Utility to install approximately 10 million advanced electric and gas meters using SmartMeter technology throughout the Utilitys service territory by the end of 2012. As of December 31, 2010, the Utility has installed approximately 7.5 million advanced electric and gas meters through its service territory. Advanced electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communication network and transmitted to the Utilitys information system where the data is stored and used for billing and other Utility business purposes.
Following customer complaints that the new metering system led to overcharges, the CPUC began an investigation, several municipalities took various steps to delay or suspend the installation of the new meters, and a class action lawsuit was filed against the Utility. In addition, customers and other private groups have raised safety and health concerns about the radio frequency technology (RF) used in the new system. For information about these matters, see Regulatory Matters-Deployment of SmartMeterTM Technology in the 2010 Annual Report. The Utility expects to complete the installation of the new meters by the end of 2012.
The following table shows the percentage of the Utilitys total 2010 electricity deliveries represented by each of its major customer classes.
Total 2010 Electricity Delivered: 83,908 GWh
The following table shows certain of the Utilitys operating statistics from 2006 to 2010 for electricity sold or delivered, including the classification of sales and revenues by type of service.
The Utility owns and operates an integrated natural gas transportation, storage, and distribution system in California that extends throughout all or a part of 39 of Californias 58 counties and includes most of northern and central California. In 2010, the Utility served approximately 4.3 million natural gas distribution customers.
The CPUC divides the Utilitys natural gas customers into two categories: core and non-core customers. This classification is based largely on a customers annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The non-core customer class is comprised of industrial, larger commercial, and electric generation natural gas customers. In 2010, core customers represented more than 99% of the Utilitys total natural gas customers and 39% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utilitys total natural gas customers and 61% of its total natural gas deliveries.
The Utility provides natural gas transportation services to all core and non-core customers connected to the Utilitys system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as bundled natural gas service. Currently, over 97% of core customers, representing over 96% of the annual core market demand, receive bundled natural gas service from the Utility.
The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service subject to eligibility requirements. Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utilitys procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.
The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utilitys backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.
The Utility has regulatory balancing accounts for core customers designed to ensure that the Utilitys results of operations over the long term are not affected by weather variations, conservation, or changes in their consumption levels. The Utilitys results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utilitys natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.
As of December 31, 2010, the Utilitys natural gas system consisted of approximately 43,000 miles of distribution pipelines, approximately 6,000 miles of backbone and local transmission pipelines, and three storage facilities. The Utilitys backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utilitys interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utilitys local transmission and distribution systems. The Utilitys Line 300, which interconnects with the U.S. Southwest and Rocky Mountain pipeline systems owned by third parties (Transwestern Pipeline Company, El Paso Natural Gas Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline Company), has a receipt capacity of approximately 1.07 Bcf per day. The Utilitys 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 2.02 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.
Much of the Utilitys natural gas transmission and distribution infrastructure was placed into service in the 1940s through the 1960s as Californias population and economy grew. The Utility makes capital investments in its natural gas transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.
The Utility owns and operates three underground natural gas storage fields connected to the Utilitys transmission and storage system. These storage fields have a combined firm capacity of approximately 50 Bcf. In addition, two independent storage operators are interconnected to the Utilitys northern California transportation system.
The Utility, along with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, has placed into operation an underground natural gas storage facility near Fresno, California. The construction of the initial phase, consisting of approximately 20 Bcf of total capacity, was completed in 2010. The Utility has a 25% interest in the initial phase of the proposed storage facility.
The total volume of natural gas throughput during 2010 was approximately 7,404 MMDth. The following table shows the percentage of the Utilitys total 2010 natural gas deliveries represented by each of the Utilitys major customer classes.
Total 2010 Natural Gas Deliveries: 842 Bcf
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 2010 California Gas Report forecasts average annual growth in the Utilitys natural gas deliveries (for core customers and non-core transportation) of approximately 0.3% for the years 2010 through 2030. 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.
The following table shows the Utilitys operating statistics from 2006 through 2010 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service.
The Utility purchases natural gas to serve the Utilitys core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utilitys portfolio of natural gas purchase contracts have fluctuated generally based on market conditions. During 2010, the Utility purchased approximately 270,228 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all this natural gas was purchased under contracts with a term of one year or less. The Utilitys largest individual supplier represented approximately 9% of the total natural gas volume the Utility purchased during 2010.
The following table shows the total volume and the average price of natural gas in dollars per MMcf of the Utilitys 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 the years presented below, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.
The Utilitys gas gathering system collects natural gas from third-party wells in northern and central California. During 2010, approximately 5% of the gas transported on the Utilitys 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 40 miles of gas gathering pipelines. The Utility receives gas well production at approximately 180 metering facilities. The Utilitys gas gathering system is geographically dispersed and is located in 7 California counties. Approximately 123 MMcf per day of natural gas produced in northern California was delivered into the Utilitys gas gathering system during 2010.
In 2010, approximately 59% of the gas transported on the Utilitys 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-Canada border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. These companies pipeline systems connect at the border to the pipeline system owned by TransCanadas Gas Transmission Northwest Corporation (GTN), which provides natural gas transportation services to a point of interconnection with the Utilitys natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTNs pipeline, has three firm transportation agreements with GTN for these services.
During 2010, approximately 36% of the gas transported on the Utilitys system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utilitys natural gas transportation system in the area of California near Topock, Arizona.
The following table shows certain information about the Utilitys firm natural gas transportation agreements in effect during 2010 to support the Utilitys needs for its core customers, 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 the National Energy Board of Canada in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases. The Utility may, upon prior notice and with the CPUCs approval, extend most of these natural gas transportation agreements. The Utility retains a right of first refusal or evergreen rights on most agreements, allowing renewal 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.
In addition, in December 2008, the CPUC approved an agreement between the Utility and El Paso Corporation for the Utility to subscribe for firm service rights on El Paso Corporations proposed 680-mile 42-inch natural gas transmission pipeline (Ruby Pipeline) that would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near Californias northern border. The Utility has subscribed for firm service rights for 375 MDth per day of which 250 MDth per day will serve the Utilitys core portfolio customers and 125 MDth per day will be subject to the Utilitys management of electric fuels used to generate electricity. The Ruby Pipeline will have an initial capacity of 1.5 Bcf per day and will connect Rocky Mountain natural gas producers with markets in northern California, Nevada, and the Pacific Northwest. Construction of the Ruby Pipeline began in July 2010 and is anticipated to be in service in June 2011.
California law requires the CPUC to authorize certain levels of funding for public purpose programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources. California law also requires the CPUC to authorize funding for the California Solar Initiative and other self-generation programs, as discussed below. Additionally, the CPUC has authorized funding for demand response programs.
For 2010, the Utility collected authorized revenue requirements of $700 million from electric customers and $146 million from gas customers to fund public purpose and other programs. The CPUC is responsible for
authorizing the programs, funding levels, and cost recovery mechanisms for the Utilitys operation of these programs. The CEC administers both the electric and natural gas public interest research and development programs and the renewable energy program on a statewide basis. In 2010, the Utility transferred $84 million from its revenue requirements to the CEC to fund these programs.
The Utilitys energy efficiency programs are designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products. In 2010, the Utility collected authorized revenue requirements of $436 million to fund these programs from gas and electric customers. The CPUC has authorized a total of $1.3 billion to fund the Utilitys 2010-2012 energy efficiency programs, a 42% increase over 2006-2008 authorized funding levels. The CPUC has adopted a long-term energy efficiency strategic plan designed to encourage innovative market transformation activities, such as the pursuit of zero net energy buildings, in addition to traditional energy efficiency rebate programs.
The CPUC established an incentive ratemaking mechanism to encourage the California investor-owned utilities to promote energy efficiency and to meet the CPUCs energy savings goals. In accordance with this mechanism, the CPUC has awarded the Utility incentive revenues totaling $104 million through December 31, 2010 based on the energy savings achieved through implementation of the Utilitys energy efficiency programs during the 2006 through 2008 program cycle. Applications for incentive awards for implementation of 2009 energy efficiency programs are due by June 30, 2011, to enable the CPUC to issue a final decision by the end of 2011.
It is uncertain what form of incentive ratemaking the CPUC will establish and what amount, if any, the Utility will be authorized to earn for future energy efficiency programs. For more information, see Regulatory Matters Energy Efficiency Programs and Incentive Ratemaking in the 2010 Annual Report.
Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. The CPUC has authorized the Utility to collect $109 million to fund its 2009-2011 demand response programs. In addition, the CPUC has authorized the Utility to collect $179 million through June 1, 2011 to implement its multi-year air conditioning direct load control program. Customers who enroll in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies.
The Utility administers the self-generation incentive program (SGIP) authorized by the CPUC to provide incentives to electricity customers who install certain types of clean or renewable distributed generation and energy storage resources that meet all or a portion of their onsite energy usage. The CPUC approved a budget for the extension of the SGIP of approximately $36 million in each of 2010 and 2011, with any carryover funds to be administered through 2015. In late 2006, the CPUC established the California Solar Initiative (CSI) to bring 1,940 MW of solar power on-line in California by 2017 and authorized the California investor-owned utilities to collect an additional $2.2 billion in the aggregate over the 2007 through 2016 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load to meet this goal. Of the total amount authorized, the Utility has been allocated $946 million to fund customer incentives, research, development, and demonstration activities (with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses. The California Legislature modified the CSI program to include participation of the California municipal utilities. The current overall objective of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2016.
The CPUC has authorized the Utility to collect approximately $417 million to support the Utilitys energy efficiency programs for low-income and fixed-income customers over 2009 through 2011. The Utility also provides
a discount rate called the California Alternate Rates for Energy (CARE) for low-income customers. This rate subsidy is paid for by the Utilitys other customers. The extent of the subsidy, during any given year, for customers collectively depends upon the number of customers participating in the program and their actual energy usage. In 2010, the amount of this subsidy was approximately $825 million, including avoided customer surcharges. The CPUC also authorized the Utility to recover approximately $28 million in administrative costs relating to the CARE subsidy over 2009 through 2011.
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 Utilitys personnel and the public. These laws and requirements relate to a broad range of activities, including the following:
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 emission allowances or other emission credits for facility operations and clean-up, or decommission waste disposal areas at the Utilitys current or former facilities and at third-party sites where the Utilitys wastes may have been disposed.
The Utilitys estimated costs to comply with environmental laws and regulations are based on current estimates and assumptions that are subject to change. In addition, the Utility is likely to incur costs as it develops and implements strategies to mitigate the impact of its operations on the environment, including climate change and its foreseeable impact on the Utilitys future operations. The actual amount of costs that the Utility will incur is subject to many factors, 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 owners responsibility, the availability of recoveries or contributions from third parties, and the development of market-based strategies to address climate change. Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utilitys rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a special ratemaking mechanism described below under Recovery of Environmental Remediation Costs.
PG&E Corporation and the Utility believe the link between man-made GHG emissions and global climate change is clear and convincing and that mandatory GHG reductions are necessary. PG&E Corporation and the Utility believe the development of a market-based cap-and-trade system, in conjunction with successful energy efficiency and demand-side management programs and the development of renewable energy resources, can reduce GHG emissions while diversifying energy supply resources and minimizing costs to customers.
Regulation. The Utilitys electricity generation plants, natural gas pipeline operations, fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state
and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter. At the federal level, the U.S. Environmental Protection Agency (EPA) is charged with implementation and enforcement of the Clean Air Act. At the state level, the CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce the AB 32.
At the federal level, there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions but comprehensive federal legislation has not yet been enacted. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions, including establishing an annual GHG reporting requirement. In June 2010, the EPA adopted the final tailoring rule to phase-in permit requirements for construction of new sources of GHG emissions, such as power plants and natural gas compressor stations, if the GHG emissions from these sources would exceed certain thresholds. These permit requirements also apply to major modifications proposed to be made to existing facilities that emit GHGs that meet the threshold. The EPA rules require owners of these facilities to use the best available control technology to minimize GHG emissions. The uncertainty about what constitutes the best available control technology may cause permitting delays. Several of the EPAs actions have been challenged in court and are not likely to be resolved until late 2011 or in 2012.
At the state level, AB 32 requires the gradual reduction of GHG emissions in California to the 1990 level by 2020 on a schedule beginning in 2012. The CARB established a state-wide GHG 1990 emissions baseline of 427 million metric tons of CO2 (or its equivalent) to serve as the 2020 emissions limit for the state of California. In December 2008, the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target set pursuant to AB 32. These recommendations include increasing renewable energy supplies, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program. (For information about the CARBs renewable energy requirements, see Utility Operations-Electricity Resources- Renewable Generation Resources above.)
The CARB also issued proposed cap-and-trade regulations for public comment in October 2010. The proposed regulations include provisions to establish state-wide caps on GHG emissions (for three 3-year compliance periods beginning January 1, from 2012 and ending December 31, 2020), allocate emission allowances (i.e., the rights to emit GHGs) among utilities and other industry participants, and permit the purchase and sale of emission allowances through a CARB-managed auction, among other provisions. After considering the comments that had been received, on December 16, 2010, the CARB directed its staff to prepare modified regulations and publish the modified regulations for one or more 15-day public comment and review periods. The modified regulations (with such further modifications as the CARBs executive officer approves) will be submitted to the California Office of Administrative Law for final approval. If the regulations become effective, the first compliance period would begin on January 1, 2012 and apply to the electricity and industrial sectors. The second phase would begin on January 1, 2015 and would expand to include suppliers of natural gas and liquid fossil fuels. Before the new cap- and-trade program can become effective, a legal challenge to the CARBs authority to implement its AB 32 scoping plan must be resolved. (See the section entitled Environmental Matters in the 2010 Annual Report.)
In addition to the requirements of AB 32, California Senate Bill 1368, enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from generating base-load electricity or entering into a long-term financial commitment to purchase base-load electricity generation unless the generating source complies with the CPUC-adopted GHG emission performance standard of 1,100 pounds of CO2 per MWh.
Climate Change Mitigation and Adaptation Strategies. During 2010, the Utility continued its programs to develop strategies to mitigate the impact of the Utilitys operations (including customer energy usage) on the environment and to develop its strategy to plan for the actions that it will need to take to adapt to the likely impacts that climate change will have on the Utilitys future operations. With respect to electric operations, climate scientists project that, sometime in the next several decades, climate change will lead to increased electricity demand due to more extreme and frequent hot weather events. Climate scientists also predict that climate change will result in significant reductions in snowpack in the Sierra Nevada Mountains. This impact could, in turn, affect PG&Es hydroelectric generation. At this time, the Utility does not anticipate that reductions in Sierra Nevada snowpack will have a significant impact on its hydroelectric generation, due in large part to its adaptation strategies. For example,
one adaptation strategy the Utility is developing is a combination of operating changes that may include, but are not limited to, higher winter carryover reservoir storage levels, reduced conveyance flows in canals and flumes in response to an increased portion of precipitation falling as rain and reduced discretionary reservoir water releases during the late spring and summer. If the Utility is not successful in fully adapting to projected reductions in snowpack over the coming decades, it may become necessary to replace some of its hydroelectricity from other sources, including GHG-emitting natural gas-fired power plants.
With respect to natural gas operations, the Utility has taken steps to reduce the release of methane, a GHG released as part of the delivery of natural gas. The Utility has replaced a substantial portion of its older cast iron and steel gas mains and implemented a technique called cross-compression, a process by which natural gas is transferred from one pipeline to another during large pipeline construction and repair projects. Cross-compression reduces the amount of natural gas vented to the atmosphere by 75% to 90%. In late 2008, the Utility also conducted focused surveys for high-volume gas leaks at its Topock and Kettleman compressor stations to reduce methane emissions.
The Utility believes its strategies to reduce GHG emissionssuch as energy efficiency and demand response programs, infrastructure improvements, and the support of renewable energy development are also effective strategies for adapting to the expected increased demand for electricity in extreme hot weather events likely to be caused by climate change. PG&E Corporation and the Utility are also assessing the benefits and challenges associated with various climate change policies and identifying how a comprehensive program can be structured to mitigate overall costs to customers and the economy as a whole while ensuring that the environmental objectives of the program are met.
PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility was a charter member of the California Climate Action Registry (CCAR) and has voluntarily reported its GHG emissions to CCAR on an annual basis from 2002 through 2008. In 2010, the Utility also voluntarily reported its 2009 GHG emissions to The Climate Registry (TCR), a successor non-profit to CCAR that is developing consistent reporting and measurement standards across industry sectors in North America. In 2010, the Utility also complied with AB 32s annual GHG emission reporting requirement by reporting its 2009 GHG emissions to the CARB.
PG&E Corporation and the Utility also publish third-party-verified GHG emissions data in their annual Corporate Responsibility and Sustainability Report. As a result of the time necessary for a thorough, third-party verification of the Utilitys GHG emissions in accordance with the highest standards developed by TCR, preliminary emissions data for 2009 are the most recent data available. Final emissions data will be made publicly available by TCR on its website in February 2011 as well as reported by PG&E Corporation and the Utility in the next Corporate Responsibility and Sustainability Report expected to be posted to their websites in July 2011. For information about the sources of electric generation that the Utility delivered to customers in 2010, see Electric Utility Operations-Electric Generation Resources above.
(1) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utilitys total emissions and the Utilitys emission rate for delivered electricity. Emissions data for the Utilitys owned generation resources is shown below.
The Utilitys third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2009 was 575 pounds of CO2 per MWh, which is a slight decrease from the 2008 emissions rate of 641 pounds of CO2 per MWh. The Utilitys 2009 emissions rate as compared to the national and California averages for electric utilities is shown in the following table:
In addition to GHG emissions data provided above, the table below sets forth information about the GHG and other emissions from the Utilitys owned generation facilities. The Utilitys owned generation (primarily nuclear and hydroelectric facilities) comprised approximately 36% of the Utilitys delivered electricity in 2009. The Utilitys retained fossil-fuel generation comprised less than 1% of the Utilitys delivered electricity in 2009.
The Utilitys Diablo Canyon power plant employs a once-through cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). This permit allows the Diablo Canyon
power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plants discharge was not protective of beneficial uses. For more information, see the discussion below in Item 3 Legal Proceedings Diablo Canyon Power Plant.
On May 4, 2010, the California Water Resources Control Board (Water Board) adopted a policy on once-through cooling. The policy, effective October 1, 2010, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the states nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are wholly out of proportion to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be wholly unreasonable after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the wholly out of proportion test. The Utility also believes that the installation of cooling towers at Diablo Canyon would be wholly unreasonable. If the Water Board disagreed and if the installation of cooling towers at Diablo Canyon were not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. Assuming the Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utilitys Diablo Canyon operations must be in compliance with the Water Boards policy by December 31, 2024.
There is continuing uncertainty about the status of federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. In July 2004, the EPA issued regulations to implement Section 316(b) intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The EPA regulations also allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases. Various parties separately challenged the EPAs regulations and in January 2007, the U.S. Court of Appeals for the Second Circuit (Second Circuit) issued a decision holding that environmental restoration cannot be used as a compliance option and that site-specific compliance variances based on a cost-benefit test cannot be used. The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and in July 2007, the EPA suspended its regulations. The U.S. Supreme Court granted review of the cost-benefit question and in April 2009, issued a decision overturning the Second Circuit, finding the EPAs use of a cost-benefit test reasonable. Depending on the form of the final regulations that may ultimately be adopted by the EPA, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. The EPA is not expected to issue draft revised regulations before March 2011. If the final regulations adopted by the EPA require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.
The Utilitys facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site, and in some cases corporate successors to the operators or arrangers. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources,
and the costs of required health studies. In the ordinary course of the Utilitys operations, the Utility generates waste that falls within CERCLAs definition of hazardous substances and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state, and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling, and disposal requirements issued by the EPA under RCRA and 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 (MGP) 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.
Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. For more information about environmental remediation liabilities, see Environmental Matters and Critical Accounting Polices and Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report which information is incorporated herein by reference and included in Exhibit 13 to this report.
Operations at the Utilitys current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal and fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies. Additionally, the Utilitys Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. The California Department of Toxic Substances Control (DTSC) approved the soil and groundwater remediation plan in June 2010 and remediation pursuant to the plan is underway. The Utility spent approximately $12 million in 2010 and estimates that it will spend approximately $33 million in 2011 for remediation at this site. Fossil fuel-fired Units 1 and 2 of the Utilitys Humboldt Bay power plant shut down in September 2010, and are now in the decommissioning process along with the nuclear Unit 3, which was shut down in 1976. The Utility has entered into a voluntary cleanup agreement with the DTSC and is currently completing a soil and groundwater investigation to determine what, if any, soil and groundwater remediation may be necessary.
The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain retired MGP sites. During their operation, from the mid-1800s through the early 1900s, MGPs produced lampblack and coal tar residues. The residues from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. The Utility has been coordinating with environmental agencies and third-party owners to evaluate and take appropriate action to mitigate any potential environmental concerns at 41 MGP sites that the Utility owned or operated in the past. Of these sites owned or operated by the Utility, 40 sites have been or are in the process of being investigated and/or remediated, and the Utility is developing a strategy to investigate and remediate the last site. The Utility spent approximately $35 million in 2010 and estimates it will spend approximately $37 million in 2011 and $51 million in 2012 on these sites.
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 Utilitys facilities, or to pay for associated clean-up costs or natural resource damages. The Utility is currently aware of two such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility substantially completed closure of the disposal facility, which was abandoned by its operator. The Utility was the major responsible party and led the remediation effort on behalf of the responsible parties. For the Casmalia disposal facility near Santa Maria, California, the Utility and several parties that sent waste to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and remediation measures.
Groundwater at the Utilitys Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utilitys 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. The Utility also owns the Kettleman natural gas compressor station but does not expect that it will incur any material expenditures related to remediation at this site.
At the Hinkley site, the Utility is cooperating with the Regional Water Quality Control Board (RWQCB) to evaluate and remediate the chromium groundwater plume. Measures have been implemented to control movement of the plume, while full-scale in-situ treatment systems operate to reduce the mass of the plume. An evaluation of the performance of these interim remedy measures, as well as possible future measures, is underway as part of the development of a final remediation plan. The Utility is working with the RWQCB to prepare an environmental impact report analyzing the potential impacts of the potential remedies for the site. In addition, the Utility is complying with the RWQCBs order that the Utility provide bottled drinking water to all residents where well water contains levels of hexavalent chromium over regional background levels. The Utility also has instituted a program to purchase those properties where chromium levels exceed background levels or that are otherwise needed for remediation purposes. The Utility estimates that total acquisition costs will be $35 million, of which $15 million is forecasted to be spent in 2011 with the remaining amount forecasted to be spent in future years. Under applicable accounting rules, these property acquisition costs will be treated as remediation costs. In 2010, the Utility spent approximately $15 million on remediation activities at Hinkley, and currently estimates it will spend at least $31 million in 2011 (including property acquisition costs of $15 million) and $5 million in 2012. Remediation costs associated with the Hinkley natural gas compressor site are not recoverable from customers under the ratemaking mechanism discussed below nor are these costs recoverable from insurers.
At the Topock natural gas compressor station, located near Needles, California, the Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River, while regulatory agencies considered the Utilitys proposed final remediation plan. As a final remediation plan, the Utility has proposed an in-situ treatment project to inject ethanol into the groundwater to accelerate the microbial breakdown of hexavalent chromium into a non-toxic and non-soluble form of chromium. The proposed plan involves the construction of a significant number of additional injection and extraction wells and an associated piping system. In January 2011 the DTSC and United States Department of Interior approved the Utilitys proposal. While developing the plan the Utility consulted with various local Native American Tribes who claimed the project would negatively impact an area of cultural significance. One of the tribes, the Fort Mojave Indian Tribe, has questioned the adequacy of the environmental consideration of negative cultural impacts of the project and may file an objection to the DTSCs approval by the March 2, 2011 due date.
In 2010, the Utility spent approximately $22 million for remediation activities at Topock. Assuming the Utility is permitted to implement the approved final remediation plan, the Utility currently estimates that it will spend at least $21 million in 2011 and $23 million in 2012. The Utilitys remediation costs for Topock are subject to the ratemaking mechanism described below.
The CPUC has approved a ratemaking mechanism under which the Utility is authorized to recover environmental costs associated with the clean-up of most sites that contain hazardous substances, including former MGP sites, third-party disposal sites, and natural gas compressor sites (other than the Hinkley site). This mechanism allows the Utility to include 90% of eligible hazardous substance cleanup costs in the Utilitys rates without a reasonableness review. Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utilitys customers. The balances of any insurance recoveries (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels are allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utilitys claims against third parties associated with hazardous waste remediation sites are retained by the Utility, with the remainder, 90% of any such recoveries, assigned to the Utilitys customers.
The CPUC has separately authorized the Utility to recover 100% of its remediation costs for decommissioning formerly owned fossil-fueled generation facilities and certain of the Utilitys transmission stations. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utilitys ultimate obligations may be subject to refund to customers.
As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (DOE) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utilitys two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay.
Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the NRC to build an on-site dry cask storage facility at Diablo Canyon to store spent fuel through at least 2024. The construction of the dry cask storage facility is complete. During 2009, the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRCs issuance of the permit is still pending in the U.S. Court of Appeals for the Ninth Circuit. The appellants claim that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon. The Ninth Circuit heard oral arguments on November 4, 2010. The Utility expects the court to issue a decision in 2011.
As a result of the DOEs failure to build a repository for nuclear waste, the Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010. On August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage. The Utility estimates that it has incurred costs of at least $205 million since 2005. Amounts recovered from the DOE will be credited to customers.
The Utilitys nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay Unit 3. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utilitys 2005 Nuclear Decommissioning Cost Triennial Proceeding, which is used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and be completed in 2044, that decommissioning of Diablo Canyon Unit 2 would be scheduled to begin in 2025 and be completed in 2041, and that decommissioning of Humboldt Bay Unit 3 would be scheduled to begin in 2009 and be completed in 2015. A
premature shutdown of the Diablo Canyon units would increase the likelihood of an earlier start to decommissioning. The Utilitys decommissioning cost estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utilitys nuclear power plants. Actual decommissioning costs may vary from these estimates to the extent the assumptions on which the estimates are based (such as assumptions about decommissioning dates, regulatory requirements, technology, and costs of labor, materials, and equipment) differ from actual results. The Utility recovers its revenue requirements for estimated nuclear decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utilitys nuclear facilities.
In April 2009, the Utility filed an application in the 2009 Nuclear Decommissioning Triennial Proceeding with new decommissioning cost estimates and other funding assumptions, such as projected cost escalation factors and projected earnings of the funds for 2010, 2011, and 2012. In July 2010, the CPUC issued a decision in the first phase of the proceeding to determine the annual revenue requirement for the decommissioning trust. The CPUC has not yet issued a decision in the second phase of the proceeding which is evaluating whether to broaden investment options available to the trusts. For more information about nuclear decommissioning, see Note 2 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.
Many of the Utilitys facilities and operations are located in, or pass through, areas that are designated as critical habitats for federal, or state-listed endangered, threatened, or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated at or near the Utilitys facilities or operations. The Utility is seeking to secure habitat conservation plans to ensure long-term compliance with state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.
Electric and magnetic fields (EMFs) naturally result from the generation, transmission, distribution, and use of electricity. In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. In October 2002, the California Department of Health Services released its report to the CPUC and the public, based primarily on its review of studies by others, evaluating the possible risks from EMFs. The reports 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 that affirms the CPUCs 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.
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 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
The Utility owns or has obtained the right to occupy and/or use real property comprising the Utilitys 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 which information is incorporated herein by reference. 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 Utilitys corporate headquarters located in several Utility-owned buildings in San Francisco, California. 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 Utilitys or a joint licensees hydroelectric generation facilities or is otherwise used for utility operations and will only be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council (Council) to oversee the development and implementation of a Land Conservation Plan (LCP) that will articulate the long-term management objectives for the 140,000 acres. The Council is governed by an 18-member board of directors that represents a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials. The Utility has appointed 1 out of 18 members of the board of directors of the Council. In December 2007, the Council adopted the LCP and submitted it to the Utility. The Utility has accepted the LCP and will seek authorization from the CPUC, the FERC, and other approving entities to proceed with the transactions necessary to implement the LCP.
PG&E Corporation also leases approximately 74,000 square feet of office space from a third party in San Francisco, California. This lease expires in 2012.
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. For more information regarding PG&E Corporations and the Utilitys liability for legal matters, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item 3 by reference.
The Utilitys Diablo Canyon power plant employs a once-through cooling water system that is regulated under a Clean Water Act permit issued by 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 Utilitys Diablo Canyon power plants 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 Utilitys 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 Generals Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyons 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.
On May 4, 2010, the Water Board adopted a policy on once-through cooling. The policy, which is subject to approval by the California Office of Administrative Law, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the states nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are wholly out of proportion to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be wholly unreasonable after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The policy could affect future negotiations between the Water Board and the Utility regarding the status of the 2003 settlement agreement.
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their Utilitys financial condition or results of operations.
As of February 8, 2011, 59 lawsuits on behalf of approximately 177 plaintiffs, including two class action lawsuits, have been filed by residents of San Bruno in San Mateo County Superior Courts against the Utility, and in some cases, against PG&E Corporation. In addition, five lawsuits on behalf of 11 plaintiffs have been filed by residents of San Bruno in the San Francisco County Superior Court against the Utility, and in some cases, against PG&E Corporation. These lawsuits seek to recover compensation for personal injury and property damage and seek other relief. Each of the class action lawsuits include a demand that the $100 million the Utility announced would be available for assistance be placed under court supervision, and also allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. One of the class action lawsuits was filed by Steve Dare and the other was filed by Danielle Ditrapani. The Utility has filed a petition on behalf of PG&E Corporation and the Utility to coordinate these lawsuits in the San Mateo County Superior Court. In its statement in support of coordination, the Utility has stated that it is prepared to enter into early mediation in an effort to resolve claims with those plaintiffs willing to do so. A hearing is scheduled for February 24, 2011.
Another lawsuit was filed in San Mateo County Superior Court as a purported shareholder derivative lawsuit to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.
The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that most of the
costs the Utility incurs for third-party claims relating to the San Bruno Accident will ultimately be covered by this insurance, no amounts for insurance recoveries have been recorded as of December 31, 2010. PG&E Corporation and the Utility are unable to predict the amount and timing of such recoveries.
For discussion of other third-party claims relating to the San Bruno accident, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item 3 by reference.
For discussion of the pending investigations of the San Bruno accident and the Rancho Cordova accident, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item 3 by reference.
The names, ages and positions of PG&E Corporation executive officers, as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934 (Exchange Act) at February 1, 2011 were 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, 2011, 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 Utilitys executive officers, as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 1, 2011 were as follows:
All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2011, 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.
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
As of February 10, 2011, there were 75,862 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 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report. Information about the frequency and amount of dividends on common stock declared by PG&E Corporation and the Utility is set forth in PG&E Corporations Consolidated Statements of Equity, the Utilitys Consolidated Statements of Shareholders Equity, and in Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report. A discussion of the restrictions on the payment of dividends with respect to PG&E Corporations and the Utilitys common stock is set forth under the section of MD&A entitled Liquidity and Financial Resources Dividends and Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
Sales of Unregistered Equity Securities
During the quarter ended December 31, 2010, PG&E Corporation made equity contributions totaling $20 million to the Utility in order to maintain the Utilitys 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures. PG&E Corporation did not make any sales of unregistered equity securities during 2010.
Issuer Purchases of Equity Securities
During the quarter ended December 31, 2010, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the fourth quarter of 2010, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.
A summary of selected financial information, for each of PG&E Corporation and the Utility for each of the last five fiscal years, is set forth under the heading Selected Financial Data in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
A discussion of PG&E Corporations and the Utilitys consolidated financial condition and results of operations is set forth under the heading Managements Discussion and Analysis of Financial Condition and Results of Operations in the 2010 Annual Report, which discussion is incorporated by reference and included in Exhibit 13 to this report.
Information responding to Item 7A appears in the 2010 Annual Report under the heading Managements Discussion and Analysis of Financial Condition and Results of OperationsRisk Management Activities, and under Notes 10 and 11 of the Notes to the Consolidated Financial Statements of the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
Information responding to Item 8 appears in the 2010 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 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 Reports of Independent Registered Public Accounting Firm, which information is incorporated by reference and included in Exhibit 13 to this report.
Based on an evaluation of PG&E Corporations and the Utilitys disclosure controls and procedures as of December 31, 2010, PG&E Corporations and the Utilitys 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 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporations and the Utilitys 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 Corporations and the Utilitys management,
including PG&E Corporations and the Utilitys 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, 2010 that have materially affected, or are reasonably likely to materially affect, PG&E Corporations or the Utilitys internal control over financial reporting.
Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Managements report, together with the report of the independent registered public accounting firm, appears in the 2010 Annual Report under the heading Managements Report on Internal Control Over Financial Reporting and Report of Independent Registered Public Accounting Firm, which information is incorporated by reference and included in Exhibit 13 to this report.
Elimination of Excise Tax Gross-Up Payments for Officers
On February 15, 2011, the Compensation Committee of the PG&E Corporation Board of Directors amended the PG&E Corporation Officer Severance Policy (Officer Severance Policy) to reduce the benefits available to certain officers under the Officer Severance Policy. Currently, the Officer Severance Policy provides enhanced change-in-control (as defined in the Officer Severance Policy) severance benefits to officers of PG&E Corporation at the Senior Vice President level or higher, and to the principal executive officer of any entity listed in the Officer Severance Policy, which typically includes PG&E Corporations primary subsidiaries, including Pacific Gas and Electric Company (Covered Officers). The Internal Revenue Code imposes an excise tax on change-in-control severance benefits if the value equals or exceeds a safe harbor limit equal to three times a recipients average annualized income. The Officer Severance Policy reimburses the Covered Officers for excise taxes levied upon the change-in-control severance benefits.
The amendments to the Officer Severance Policy will eliminate excise tax gross-up payments for severance benefits triggered by a change in control (1) for current Covered Officers, effective three years after the current Covered Officers are given notice of the change, and (2) for executive officers who become eligible to receive change-in-control severance benefits under the Officer Severance Policy on or after February 15, 2011. Under the amended Officer Severance Policy, a Covered Officer will receive severance that results in the best after-tax benefit to the Covered Officer, either by receiving the full change-in-control severance benefit with the excise tax paid by the Covered Officer, or by receiving a reduced severance calculated in a manner that results in a total severance benefit below the Internal Revenue Codes safe harbor limit described above. There are no other policies, arrangements, or agreements that provide for excise tax gross-ups to any current officers of PG&E Corporation or Pacific Gas and Electric Company.
Item 10. Directors, Executive Officers and Corporate Governance
Information regarding executive officers of PG&E Corporation and the Utility is included above in a separate item captioned Executive Officers of the Registrants at the end of Part I of this report. Other information regarding directors is included under the heading Nominees for Directors of PG&E Corporation and Pacific Gas and Electric Company in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference. Information regarding compliance with Section 16 of the Exchange Act is included under the heading Section 16(a) Beneficial Ownership Reporting Compliance in the Joint Proxy Statement relating to the 2011 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 Corporations website www.pgecorp.com, and the Utilitys website, www.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and the Utility applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers and other executive officers, (2) PG&E Corporations and the Utilitys corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies Audit Committees and the PG&E Corporation Nominating and Governance Committee and Compensation Committee.
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 the Utility 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 four business days of the waiver.
Procedures for Shareholder Recommendations of Nominees to the Boards of Directors
During 2010 there were no material changes to the procedures described in PG&E Corporations and the Utilitys Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporations or Pacific Gas and Electric Companys 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 Corporate Governance Board Committee Duties and Composition Audit Committees and Corporate Governance Board Committee Duties and Composition Committee Membership Requirements in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Information responding to Item 11, for each of PG&E Corporation and the Utility, is included under the headings Compensation Discussion and Analysis (CD&A), Compensation Committee Report, Summary Compensation Table - 2010, Grants of Plan-Based Awards in 2010, Outstanding Equity Awards at Fiscal Year End - 2010, Option Exercises and Stock Vested During 2010, Pension Benefits - 2010, Non-Qualified Deferred Compensation, Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability and 2010 Director Compensation in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Information regarding the beneficial ownership of securities for each of PG&E Corporation and the Utility, is included under the heading Security Ownership of Management and under the heading Other Information - Principal Shareholders in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Equity Compensation Plan Information
The following table provides information as of December 31, 2010 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporations existing equity compensation plans.
Information responding to Item 13, for each of PG&E Corporation and the Utility, 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 and Qualifications in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Information responding to Item 14, for each of PG&E Corporation and the Utility, is included under the heading Information Regarding the Independent Registered Public Accounting Firm for PG&E Corporation and Pacific Gas and Electric Company in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 15. Exhibits and Financial Statement Schedules
1. The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are contained in the 2010 Annual Report and are incorporated by reference in this report:
Consolidated Statements of Income for the Years Ended December 31, 2010, 2009, and 2008 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2010 and 2009 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009, and 2008 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Equity for the Years Ended December 31, 2010, 2009, and 2008 for PG&E Corporation.
Consolidated Statements of Shareholders Equity for the Years Ended December 31, 2010, 2009, and 2008 for 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:
Reports of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
ICondensed Financial Information of Parent as of December 31, 2010 and 2009 and for the Years Ended December 31, 2010, 2009, and 2008.
IIConsolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2010, 2009, and 2008.
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:
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, 2010 to be signed on their behalf by the undersigned, thereunto duly authorized.
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.
To the Board of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company
San Francisco, California
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, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and the Companys and the Utilitys internal control over financial reporting as of December 31, 2010, and have issued our report thereon dated February 17, 2011; such consolidated financial statements and our report are included in your 2010 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the consolidated financial statement schedules of the Company and Utility listed in Item 15(a)2. These consolidated financial statement schedules are the responsibility of the Companys and the Utilitys 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
February 17, 2011
San Francisco, California
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME
(in millions, except per share amounts)
In calculating diluted EPS, PG&E Corporation applies the if-converted method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.
Accordingly, the basic and diluted earnings per share calculation for the ended December 31, 2008 reflects the allocation of earnings between PG&E Corporation common stock and the participating security.
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)
CONDENSED BALANCE SHEETS
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
On January 15, 2009, PG&E Corporation paid a quarterly common stock dividend of $0.39 per share. On April 15, July 15, and October 15, 2009, PG&E Corporation paid quarterly common stock dividends of $0.42 per share.
On January 15, 2008, PG&E Corporation paid a quarterly common stock dividend of $0.36 per share. On April 15, July 15, and October 15, 2008, PG&E Corporation paid quarterly common stock dividends of $0.39 per share. Of the total dividend payments made by PG&E Corporation in 2008, approximately $28 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.
SCHEDULE II CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2010, 2009, and 2008
Pacific Gas and Electric Company
SCHEDULE II CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2010, 2009, and 2008