Item 1. Business
General
Corporate Structure and Business
PG&E Corporation, incorporated in California in 1995, is a holding company that conducts its business through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. 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’s revenues are generated mainly through the sale and delivery of electricity and natural gas to customers. The Utility served approximately 5.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2011. The Utility had approximately $49.2 billion in assets at December 31, 2011 and generated revenues of $15 billion in 2011. 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 Utility’s nuclear generation facilities.
Corporate and Other Information
The principal executive offices of PG&E Corporation and the Utility are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and their 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 Corporation’s website, www.pgecorp.com, and the Utility’s 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, 2011 (“2011 Annual Report”) and the Joint Proxy Statement relating to the 2012 Annual Meetings of Shareholders.
Employees
At December 31, 2011, PG&E Corporation and its subsidiaries had 19,274 regular employees, including 19,253 regular employees of the Utility. Of the Utility’s regular employees, 11,950 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”). There are two collective bargaining agreements with IBEW. One IBEW collective bargaining agreement was scheduled to expire on December 31, 2011 but will remain in effect until the earlier of the date that IBEW members ratify a new agreement or December 31, 2012. The other IBEW collective bargaining agreement will expire on December 31, 2015. The ESC collective bargaining agreement was scheduled to expire on December 31, 2011 but will remain in effect until December 31, 2012, unless a new agreement becomes effective before then. The ESC and the Utility are negotiating the terms of a new agreement and hope to complete negotiations by the end of February 2012. The proposed new agreement would then be sent to ESC members for ratification. The SEIU collective bargaining agreement expires on July 31, 2012.
Natural Gas Matters
After the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”), various civil lawsuits, regulatory investigations and proceedings, and a criminal investigation were commenced. The Utility has stated publicly that it is liable for the San Bruno accident and it will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident. In June 2011, an independent review panel appointed by the CPUC to investigate the San Bruno accident issued a report that was highly critical of the Utility’s natural gas operating practices and procedures, including its risk management and pipeline integrity programs, and its corporate culture. In August 2011, the National Transportation Safety Board (“NTSB”) announced that it had determined the probable cause of the San Bruno accident placing the blame primarily on the Utility. In January 2012, the CPUC’s Consumer Protection and Safety Division (“CPSD”) issued its report containing the findings of its investigation into the San Bruno accident and alleging that the Utility committed numerous violations in connection with the San Bruno accident. The CPUC has commenced three investigations pertaining to the Utility’s natural gas transmission operations, including an investigation of the San Bruno accident to consider the CPSD’s allegations. (See Item 3. Legal Proceedings, below.) The CPUC has also delegated to its staff the authority to issue citations and impose penalties for violation of the natural gas regulations and rules. On January 27, 2012, the CPSD exercised this new authority to issue a citation and impose a penalty of approximately $17 million on the Utility for self-reported violations of these rules. PG&E Corporation and the Utility have concluded that it is probable that the Utility will be required to pay penalties associated with these matters and have accrued an amount in their financial statements reflecting the reasonably estimable minimum amount of penalties they believe it is probable that the Utility will incur.
For more information about these investigations and related matters see “Natural Gas Matters” within the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”) in the 2011 Annual Report.
Cautionary Language Regarding Forward-Looking Statements
This combined Annual Report on Form 10-K, including the information incorporated by reference from the 2011 Annual Report and the Joint Proxy Statement relating to the 2012 Annual Meetings of Shareholders, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated environmental remediation, tax, and other liabilities, estimates and assumptions used in PG&E Corporation’s and the Utility’s 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 additional costs the Utility will incur related to its natural gas transmission and distribution business; 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,” “forecast,” “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:
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the outcome of pending and future investigations and regulatory proceedings related to the San Bruno accident, and the safety of the Utility’s natural gas transmission pipelines in its service territory; the ultimate amount of costs the Utility incurs for natural gas matters that are not recovered through rates; the ultimate amount of third-party claims associated with the San Bruno accident that are not recovered through insurance; and the amount of any civil or criminal penalties, or punitive damages, the Utility may incur related to these matters, including the amount of penalties that the CPSD may impose on the Utility for violations of natural gas safety regulations;
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the outcome of future investigations or proceedings that may be commenced by the CPUC or other regulatory authorities relating to the Utility’s compliance with law, rules, regulations, or orders applicable to the operation, inspection, and maintenance of its electric and gas facilities (in addition to investigations or proceedings related to the San Bruno accident and natural gas matters);
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whether PG&E Corporation and the Utility are able to repair the reputational harm they have suffered which, in part, will depend on their ability to adequately and timely respond to the findings and recommendations made by the NTSB and CPUC’s independent review panel and cure the deficiencies that have been identified in the Utility’s operating practices and procedures and corporate culture; developments that may occur in the various investigations of the San Bruno accident and natural gas matters; the decisions, findings, or orders issued in connection with these investigations, including the amount of civil or criminal penalties that may be imposed on the Utility, developments that may occur in the civil litigation related to the San Bruno accident; and the extent of service disruptions that may occur due to changes in pipeline pressure as the Utility continues to inspect and test pipelines;
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the adequacy and price of electricity and natural gas supplies, the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and the availability and price of nuclear fuel used in the two nuclear generation units at Diablo Canyon;
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explosions, fires, accidents, mechanical breakdowns, equipment failures, human errors, labor disruptions, and similar events, as well as acts of terrorism, war, or vandalism, including cyber-attacks, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory penalties on the Utility;
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the impact of storms, tornados, floods, drought, earthquakes, tsunamis, wildland and other fires, pandemics, solar events, electromagnetic events, and other natural disasters, or that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;
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the potential impacts of climate change on the Utility’s electricity and natural gas businesses, the impact of environmental laws and regulations aimed at the reduction of carbon dioxide and other greenhouse gases (“GHG”) on the Utility’s electricity and natural gas businesses, and whether the Utility is able to recover associated compliance costs including the cost of emission allowances and offsets that the Utility may incur under cap and trade regulations;
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changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline in the Utility’s service area, general and regional economic and financial market conditions, the development of alternative energy technologies including self-generation and distributed generation technologies, or other reasons;
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the occurrence of unplanned outages at the Utility’s large hydroelectric or nuclear generation facilities and the ability of the Utility to procure replacement electricity if hydroelectric or nuclear generation operations were unavailable;
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the results of seismic studies the Utility is conducting that could affect the Utility’s ability to continue operating Diablo Canyon or renew the operating licenses for Diablo Canyon, the impact of new NRC orders or regulations to implement various recommendations made by the NRC’s task force following the March 2011 earthquake and tsunami in Japan that caused significant damage to nuclear facilities in Japan, and the impact of new legislation, regulations, or policies that may be adopted in the future to address the operations, security, safety, or decommissioning of nuclear facilities, the storage of spent nuclear fuel, seismic design, cooling water intake, or other issues;
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the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the outcome of proceedings and investigations relating to the Utility’s natural gas operations affects the Utility’s ability to make distributions to PG&E Corporation in the form of dividends or share repurchases;
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whether the Utility’s newly installed electric and gas SmartMeterTM devices and related software systems and wireless communications equipment continue to accurately and timely measure customer energy usage and generate billing information, whether the Utility recovers costs associated with analog meters that customers may choose instead of digital meters, whether the Utility can successfully implement “dynamic pricing” retail electric rates that are more closely aligned with wholesale electricity market prices, and whether the Utility can continue to rely on third-party vendors and contractors to support the advanced metering system;
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whether the Utility is able to protect its information technology, operating systems and networks, including the advanced metering system infrastructure, from damage, disruption, or failure caused by cyber-attacks, computer viruses, and other hazards; and whether the Utility’s security measures are sufficient to protect the confidential customer, vendor and financial data contained in such systems and networks from unauthorized access and disclosure;
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the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, that are not recoverable through insurance, rates, or from other third parties;
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the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;
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the impact of environmental remediation laws, regulations, and orders; the extent to which the Utility is able to recover compliance and remediation costs from third parties or through rates or insurance, and the ultimate amount of environmental remediation costs the Utility incurs in connection with its natural gas compressor station located near Hinkley, California which are not recoverable through insurance or rates;
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the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits certain types of governmental bodies to purchase and sell electricity for their local residents and businesses; and
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the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations, such as The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010.
For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the section of MD&A entitled “Risk Factors” in the 2011 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.
PG&E Corporation’s Regulatory Environment
Federal Regulation
As a public utility holding company, PG&E Corporation is subject to the requirements of the Public Utility Holding Company Act of 2005 (“PUHCA”). Under the PUHCA, 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 the PUHCA other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.
State Regulation
PG&E Corporation is not a public utility under California law. The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:
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the Utility cannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;
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the Utility’s dividend policy must be established by the Utility’s Board of Directors as though the Utility were a stand-alone utility company;
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the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation’s Board of Directors (known as the “first priority” condition); and
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the Utility must maintain on average its CPUC-authorized utility capital structure, although it can request a waiver of this condition if an adverse financial event reduces the Utility’s common equity component by 1% or more.
The CPUC also has adopted complex and detailed rules governing transactions between California’s 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:
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prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility’s affiliates;
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emphasize that the holding company may not aid or abet a utility’s violation of the rules or act as a conduit to provide confidential utility information to an affiliate;
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require prior CPUC approval before the utility can contract with an affiliate for resource procurement (e.g., electricity or gas), except in blind transactions where the identity of the other party is not known until the transaction is consummated;
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require certain key officers to provide annual certifications of compliance with the affiliate rules;
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prohibit certain key officers from serving in the same position at both the utility and the holding company (unless otherwise permitted by the CPUC), or, in the alternative, prohibit the sharing of lobbying, regulatory relations and certain legal services (except for legal services necessary to the provision of permitted shared services);
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require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company; and
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make the CPUC’s Energy Division responsible for hiring independent auditors to conduct biennial audits to verify that the utility is in compliance with the affiliate rules.
The CPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.
The Utility’s Regulatory Environment
Various aspects of the Utility’s business are subject to a complex set of energy, environmental and other laws, regulations, and regulatory proceedings at the federal, state, and local levels. 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 and investigations that are expected to affect the Utility, see the sections of MD&A entitled “Regulatory Matters” and “Natural Gas Matters” in the 2011 Annual Report.
Federal Regulation
The FERC
The FERC regulates the transmission of electricity 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 Corporation (“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 Utility’s electricity transmission annual amount of revenue (“revenue requirements”) and rates, the licensing of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas.
Electric Reliability Standards; Development of Transmission Grid. The FERC has the responsibility to approve and enforce mandatory standards governing the reliability of the nation’s electricity transmission grid, including standards to protect the nation’s 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 nation’s Electric Reliability Organization. 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, also performs a 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 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.
On July 21, 2011, the FERC adopted Order No. 1000, its final rule on transmission planning and cost allocation requirements. Order No. 10000 is intended to benefit consumers by: (1) enhancing the grid’s ability to support wholesale power markets and transmit renewable energy supplies; and (2) ensuring transmission services are provided at just and reasonable rates. Order No. 1000 requires public utility transmission providers to improve transmission planning processes and allocate costs for new transmission facilities to the beneficiaries of those facilities. The transmission planning requirements established in the rule include development of regional transmission plans, consideration of transmission needs driven by public policy requirements established by state or federal laws or regulations, and coordination between pairs of neighboring transmission planning regions. The cost allocation requirements established in the rule include development of regional and interregional cost allocation methods. (Under the rule, participant-funding of new transmission facilities is permitted, but cannot be used as the regional or interregional cost allocation method.) The rule also directs that provisions granting rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation be removed from FERC-approved tariffs.
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 FERC’s 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 the Public Utility Regulatory Policies Act of 1978 (“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 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 then approved the applicable terms, conditions, prices, and eligibility requirements. 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. PURPA permits termination of such obligations on a “service territory-wide basis.” In June 2011, the FERC issued an order terminating the Utility’s QF purchase obligation for QF facilities that have a capacity of 20 MW and greater. For more information about the Utility’s 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 Utility’s retired nuclear generating unit at Humboldt Bay (“Humboldt Bay Unit 3”). NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.
The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the operating license for Diablo Canyon Unit 2 expires in August 2025. In November 2009, the Utility filed an application at the NRC to begin the license renewal process which is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. At the Utility’s request, the NRC has agreed to delay processing the Utility’s application until the Utility completes extensive seismological studies in 2015 or 2016.
Following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan, the NRC appointed a task force to develop recommendations about how to improve safety at U.S. nuclear power plants and upgrade protection against earthquakes, floods and power losses. The twelve safety recommendations were released in July 2011 and have been reviewed by the NRC staff. During 2012, it is expected that the NRC will adopt regulations or issue orders requiring nuclear power plants to implement some of the near-term recommendations. The NRC is expected to implement the remaining recommendations over the next five years.
For more information about the relicensing proceeding and other matters affecting Diablo Canyon, see the section of MD&A in the 2011 Annual Report entitled “Regulatory Matters-Diablo Canyon Nuclear Power Plant.”
The Pipeline and Hazardous Materials Safety Administration
The Utility also is subject to regulations adopted by the federal 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 nation’s pipeline transportation system and the shipment of hazardous materials. Through a certification with PHMSA, the CPUC is authorized to enforce the federal pipeline safety standards over intrastate natural gas pipelines, as well as any state pipeline safety requirements that do not conflict with the federal 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. On September 26, 2011, the NTSB released its final investigative report on the San Bruno accident. (See the section of MD&A entitled “Natural Gas Matters” in the 2011 Annual Report for more information.)
The federal Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 became effective on January 3, 2012 (the “Pipeline Safety Act”). In addition to re-authorizing funds for PHMSA’s pipeline safety programs through 2015, this act requires the Secretary of the Department of Transportation to review and evaluate certain existing pipeline safety regulations. Among other requirements, the Pipeline Safety Act requires the Secretary to examine the sufficiency of certain safety regulations and whether to adopt various NTSB recommendations made following its investigation of several natural gas incidents, including the San Bruno accident. The Secretary is authorized under specific circumstances, some of which require an evaluation and a Congressional review period, to adopt regulations to address pipeline integrity management requirements, leak detection systems, the use of automatic or remote-controlled shut-off valves, verification of pipeline records to ensure that records reflect actual pipeline characteristics, and to conduct testing to confirm the strength of certain previously untested pipelines in high consequence areas. The Pipeline Safety Act also increases the maximum civil penalties for violation of safety rules from $100,000 to $200,000 for an individual violation and from $1,000,000 to $2,000,000 for a series of violations.
State Regulation
California Legislature
The Utility’s operations have been significantly affected by statutes passed by the California legislature, including laws related to the implementation of electric industry restructuring in 1996, the 2000-2001 California energy crisis that followed electric industry restructuring, electric resource adequacy, renewable energy resources, public purpose programs, power plant siting and permitting, and GHG emissions and other environmental matters.
In April 2011, the California Governor signed new legislation establishing a new renewable portfolio standard (“RPS”) that increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from at least 20% of their total retail sales, as required by the prior law, to 33% of their total retail sales. For more information see “Renewable Energy Resources” below.
In addition, several laws were enacted during 2011 to expand the authority of the CPUC to order the gas utilities to make improvements to the natural gas transmission system in California, including ordering the utilities to install automatic or remote shut-off valves on certain pipelines and to comply with new emergency preparedness and emergency response standards and procedures.
Also, effective January 1, 2012, the CPUC’s authority to impose penalties for violating laws, orders, or regulations has increased from $20,000 per violation, per day, to $50,000 per violation, per day.
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 over the rates and terms and conditions of service for the Utility’s electricity and natural gas distribution operations, electricity generation, and natural gas transportation and storage services. The CPUC also has jurisdiction over the Utility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’s electricity and natural gas retail customers, rates 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 laws that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas gathering, transmission, and distribution pipeline systems, and for the safe operation of such pipelines and equipment. The CPUC also has been delegated authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities.
Ratemaking for retail sales from the Utility’s generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies.
PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001 (“Chapter 11 Settlement Agreement”). The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court 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 state’s primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new, and emerging renewable technologies. In addition, the CEC is responsible for forecasts of 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 GHG and other emission limits. The CARB also is responsible for adopting and enforcing regulations to meet California’s 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. In October 2011, the CARB adopted its final “cap-and-trade” regulations to help gradually reduce GHG emissions. (For more information see “Environmental Matters - Air Quality and Climate Change” below.)
Other Regulation
The Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility’s generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. 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 agency that granted them if facts develop or events occur that differ significantly from the facts and projections assumed when they were granted. In addition, discharge permits and other approvals and licenses often have a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. (For more information, see “Environmental Matters - Water Quality” below.)
The Utility has franchise agreements with 292 cities and counties that permit the Utility to install, operate, and maintain the Utility’s electric and natural gas facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In addition, charter cities can negotiate their fees. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term of years, 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 Utility’s business and to conduct certain related operations.
Competition in the Electricity Industry
Federal. Many provisions of the Energy Policy Act of 2005 (“EPAct”) support the development of competition in the wholesale electric market. The EPAct 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. (See the section above entitled “The Utility’s Regulatory Environment-Federal Energy Regulation” for a description of some of these rules.) The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.
Even before the passage of the EPAct, the FERC’s policies supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities’ transmission grids. Order 888 requires all public utilities that own, control, or operate, facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service. The FERC’s subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, and advanced the view that a regulated unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination, (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement, and (3) increase transparency in the rules applicable to planning and use of the transmission system.
The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage 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. After the power plant achieves commercial operation the transmission provider will reimburse the generator for the upgrade costs over a five-year period. The cost of the network upgrades is then recovered by the regulated transmission provider in its overall transmission rates.
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 Utility’s Chapter 11 proceeding, see Note 13: Resolution of Remaining Chapter 11 Disputed Claims, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.)
During the 2000-2001 energy crisis, the California Legislature authorized the California Department of Water Resources (“DWR”), beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the utilities’ retail customers. (The utilities deliver electricity purchased by the DWR under the contracts and act as the DWR’s 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 Utility’s service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utility’s 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.
In addition, the Utility’s customers may, under certain circumstances, obtain power from a community choice aggregator (“CCA”) instead of from the Utility. California law permits cities and counties and certain other public agencies to purchase and sell electricity for their local residents and businesses after they have registered as CCAs. Under these arrangements, the Utility continues to provide distribution, metering, and billing services to the customers of the CCAs and remains the electricity provider of last resort for those customers. The law provides that a CCA 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 the CCA program, including the imposition of a surcharge on retail end-users of the CCA to prevent a shifting of costs to customers of a utility who receive bundled services and allowing a CCA to start service in phases. The law also authorizes the Utility to recover from each CCA any costs of implementing the program that are reasonably attributable to the CCA, and to recover from all customers any costs of implementing the program not reasonably attributable to a CCA.
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 Utility’s 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 Utility’s distribution facilities, either under a consensual transaction, or via eminent domain.
It is also possible that technological developments could pose competitive challenges for traditional utilities. In particular, a combination of technology-related cost declines and sustained federal or state subsidies could make “distributed generation” a viable, cost-effective alternative to the Utility’s bundled electric service. The CPUC also has been considering the role of electric vehicles in California’s electricity infrastructure. 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 electric vehicle charging providers; retail electricity rates paid by electric vehicle charging providers 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.
Competition in the Natural Gas Industry
FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from most of the FERC’s rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC.
The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by the FERC for interstate gas pipelines. The CPUC divides the Utility’s 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 Utility’s “Citygate,” which refers to the non-physical interconnection between the big “backbone” gas transmission system and the smaller downstream local transmission systems.
The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. In addition, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential. The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties in the Utility’s natural gas transmission and storage rate case, was approved by the CPUC in 1997, took effect on March 1, 1998, and has been renewed, with slight modifications, for various successive periods. On April 14, 2011, the CPUC approved the Gas Accord V settlement agreement (“Gas Accord V”) to continue a majority of the Gas Accord’s terms and conditions of service and to set rates for the Utility’s gas transmission and storage services for a four-year period beginning January 1, 2011. (See “Ratemaking Mechanisms” below.)
The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility’s market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian and U.S. Rocky Mountains natural gas delivered to northern California, relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility’s case, includes the cost of transportation of the natural gas from Canada and the U.S. Rocky Mountains 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 and U.S. Rocky Mountains natural gas delivered to northern California increases relative to other competing natural gas sources, the Utility’s market share of transportation services into southern California decreases. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.
Ratemaking Mechanisms
Overview
The Utility’s 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 conduct proceedings to determine the revenue requirements that the Utility is authorized to collect from its customers. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.
Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of providing utility services as well as a return of, and a fair rate of return on, its investment in utility facilities (“rate base”). Revenue requirements are primarily determined based on the Utility’s forecast of future costs. These costs include the Utility’s costs of electricity and natural gas purchased for its customers, operating expenses, administrative and general expenses, depreciation, taxes, and public purpose programs.
Regulatory balancing accounts are used to adjust the Utility’s revenue requirements. Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations. 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 Utility’s 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 Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.
While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on the extent to which the utilities meet objective or fixed standards or goals, such as energy efficiency goals, instead of on the cost of providing service.
Electricity and Natural Gas Distribution and Electricity Generation Operations
General Rate Cases
The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first or “test” year. Typical interveners in the Utility’s GRC include the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network.
On May 5, 2011, the CPUC issued a final decision in the 2011 GRC to authorize the Utility’s revenue requirements for 2011 through 2013 for its costs to own and operate its electric and natural gas distribution and electric generation operations. The final decision approves the unopposed October 15, 2010 settlement agreement among the Utility, the DRA, TURN, and nearly all other intervening parties. The CPUC authorized a total 2011 revenue requirement of approximately $6.0 billion, which reflects an overall increase of $450 million, or 8.0%, over
the total 2010 authorized amount of $5.6 billion, including $55 million for the recovery of financing costs and the accelerated return of capital associated with conventional meters that have been replaced by SmartMeterTM devices. As soon as July 2012, the Utility may file a notice of intent with the CPUC that will include a draft of the Utility’s GRC application for the period beginning January 1, 2014. The Utility plans to file its GRC application in December 2012.
Attrition Rate Adjustments
The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations. The CPUC decision in the 2011 GRC also authorized attrition increases of $180 million for 2012 and $185 million for 2013.
Cost of Capital Proceedings
The CPUC authorizes the Utility’s 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.
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 Moody’s 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 for the coming year 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 Utility’s authorized rates of return for 2012 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 Utility’s 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.
Although the FERC has authority to set the Utility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility’s transmission rates are determined through a negotiated rate settlement.
Rate Recovery of Costs of New Electricity Generation Resources
Overview
Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility’s own generation facilities and existing electricity contracts (including DWR contracts allocated to the Utility’s customers). 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 California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation).
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. The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility’s customers under DWR contracts) through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC. The ERRA tracks the difference between (1) billed/unbilled ERRA revenues and (2) electric procurement costs incurred under the Utility’s authorized procurement plans. To determine rates used to collect ERRA revenues, each year the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, hedging, 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 Utility’s procurement activities are prudent and in compliance with its CPUC-approved procurement plans.
In December 2011, the CPUC approved the Utility’s bundled electricity procurement plan, covering 2011 through 2020, subject to certain required modifications. The Utility intends to file a revised bundled electricity procurement plan in April 2012 that is consistent with the CPUC’s December 2011 decision.
Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility’s prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.
On December 20, 2011, the CPUC approved the Utility’s forecast of 2012 procurement costs. The CPUC has not yet issued a decision to complete the Utility’s 2010 ERRA compliance review proceeding. The Utility will file its 2011 ERRA compliance review on February 15, 2012.
Costs Incurred Under New Power Purchase Agreements
The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved 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 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 Utility’s service territory, including existing direct access customers and community choice aggregation customers, under certain circumstances. (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 uses the net capacity cost allocation method, the net capacity costs are allocated for the term of the contract. To use the net capacity allocation, the CPUC must determine that a resource was needed to meet system or local area reliability needs for the benefit of all distribution customers. The CPUC can decide whether to require an energy auction for resources subject to the net capacity cost allocation.
For renewable generation purchased from third parties under power purchase agreements, the Utility may recover any above-market costs through the imposition of a non-bypassable charge on bundled and departing customers.
Costs of Utility-Owned Generation Resource Projects
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 Utility’s 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 facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year. For more information, see the section of MD&A entitled “Capital Expenditures” in the 2011 Annual Report.
The Utility may recover any above-market costs associated with new utility-owned generation resources 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 Utility’s service territory, including existing direct access customers and community choice aggregation customers, under certain circumstances. The recovery of above-market costs is typically addressed in the CPUC order approving a specific utility-owned generation project.
DWR Electricity and DWR Revenue Requirements
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 DWR’s revenue requirements to recover costs associated with the DWR’s $11.3 billion bond offering completed in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR’s revenue requirement and to provide the DWR with funds to make its electricity purchases. The Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utility’s revenues.
Electricity Transmission
The Utility’s electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues: (1) charges under the Utility’s 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 Utility’s transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utility’s retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.
Transmission Owner Rate Cases
The primary FERC 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.
The Utility’s transmission owner tariff includes two rate components. The primary component consists of base transmission rates intended to recover the Utility’s operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense, and return on equity. The Utility derives the majority of the Utility’s transmission revenue from base transmission rates.
The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO for providing wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) to third parties using the Utility’s 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 CAISO’s 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 transmission facilities at 200 kV and above are higher than those 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 Utility’s retail customers as part of retail transmission rates.
Natural Gas
Natural Gas Transmission and Storage Rate Cases
The CPUC determines the Utility’s authorized revenue requirements and rates for its natural gas transmission and storage services in a separate rate case called the gas transmission and storage (“GT&S”) rate case. The CPUC’s decision in the most recent GT&S rate case approved a settlement agreement, known as the Gas Accord V, which set the Utility’s rates and associated revenue requirements for natural gas transmission and storage services from January 1, 2011 through December 31, 2014. The Gas Accord V extends many of the provisions contained in the first Gas Accord that the CPUC approved in 1996. (See “Competition” above.) The Gas Accord V provided an authorized natural gas transmission and storage revenue requirement of $514 million in 2011, an increase of $52 million over the 2010 adopted revenue requirement. With attrition increases authorized by the decision, the Utility’s natural gas transmission and storage revenue requirements for 2012, 2013, and 2014 will be $541 million, $565 million, and $582 million, respectively. The Utility also has been authorized to recover (through natural gas transmission and storage rates) revenue requirements for other costs, such as the cost of electricity used to operate natural gas compressor stations and other costs, that are determined in the Utility’s 2011 GRC or other Utility regulatory proceedings.
A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements continues 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 Utility’s 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 38% of the total backbone capacity on the Utility’s system. Core customers pay approximately 69% 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 66% to core customers and 34% to non-core customers. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk.
Storage. The storage revenue requirement is allocated approximately 51% to core customers, 37% to non-core storage service, and 12% to pipeline load balancing service. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s 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.
Biennial Cost Allocation Proceeding
Certain of the Utility’s natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.
Natural Gas Procurement
The Utility sets the natural gas procurement rate for core customers monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.
The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. (The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered through electricity balancing accounts.)
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 Utility’s 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 Utility’s customers receive in their rates 80% of any savings resulting from the Utility’s 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 1.5% of total natural gas commodity costs. 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 CPUC’s Division of Ratepayer Advocates, and The Utility Reform Network to incorporate a portion of hedging costs for core customers into the Utility’s 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 2011 Annual Report).
Interstate and Canadian Natural Gas Transportation
The Utility’s interstate and Canadian natural gas transportation agreements with third-party service providers are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Utilities Commission and the National Energy Board. The Utility’s agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility’s core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky
Mountains, and the southwestern United States) to the points at which the Utility’s 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.”
Pipeline Safety Enhancement Plan
On February 24, 2011, the CPUC opened a rulemaking proceeding in order to develop and adopt safety-related changes to its regulation of natural gas transmission and distribution pipelines in California. The CPUC ordered each California natural gas transmission pipeline operator to submit a plan that describes the operator’s plan to either pressure test or replace those pipeline segments that have never been pressure tested or that lack sufficient detail related to the performance of a test. On August 26, 2011, the Utility filed its proposed plan and requested that the CPUC approve the proposed scope of the work to be done during the first phase (2011 through 2014) and authorize the Utility to recover estimated costs incurred after January 1, 2011. The Utility expects that it will incur significant costs to perform pipeline-related work within the proposed scope of the plan before the CPUC issues a decision and such costs may not be recoverable. Under the current procedural schedule, hearings will begin on March 12, 2012 and conclude on March 23, 2012 and a decision may not be issued until mid-2012 or later. For more information, see the section of MD&A entitled “Natural Gas Matters-CPUC Rulemaking Proceeding” in the 2011 Annual Report.
Electric Utility Operations
Electricity Resources
The Utility is required to maintain physical generating capacity adequate to meet its customers’ 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 Utility’s total actual deliveries of electricity in 2011 represented by each major electricity resource.
Total 2011 Actual Electricity Delivered - 74,864 GWh:
(1) This amount is mainly comprised of net CAISO open market purchases, offset by transmission and distribution related system losses.
Owned Generation Facilities
At December 31, 2011, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:
(1) See the discussion below about the status of outages of these units.
Diablo Canyon Power Plant. The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. For the twelve months period ended December 31, 2011, the Utility’s 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. For more information on the renewal process and other matters affecting Diablo Canyon, see the section of MD&A entitled “Regulatory Matters-Diablo Canyon Nuclear Power Plant” in the 2011 Annual Report.
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 2011 Annual Report.
The following table outlines the Diablo Canyon power plant’s refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 44.6 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 Utility’s hydroelectric system consists of 110 generating units at 68 powerhouses, including the Helms pumped storage facility, with a total generating capacity of 3,896 MW. Most of the Utility’s hydroelectric generation units are classified as “large” hydro facilities, as their unit capacity exceeds 30 MW. The system includes 99 reservoirs, 56 diversions, 174 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.
The Helms pumped storage facility consists of three motor/generator units with a combined capacity of 1,212 MW. During 2011, the Utility began inspections of all three units following reports of a significant failure of a similarly designed pumped storage generation unit in Austria that was apparently caused by cracks in the generator rotor poles due to metal fatigue. Inspection of this area of the generation unit requires a significant outage while the generator rotor is disassembled and re-assembled after any necessary inspections and repairs are made. The Utility inspected Unit 2 during a planned outage in September 2011 and found cracks that have since been repaired and the Utility has returned Unit 2 to full operation. The Utility removed Unit 3 from service for inspection in October 2011. The Utility found cracks in the generator rotor of Unit 3 which are being repaired so that the unit can be returned to full service. On November 19, 2011, an unrelated equipment failure occurred on Unit 1 which damaged the generator and Unit 1 was removed from service. Depending on the effectiveness of repairs being implemented, the Utility expects that Unit 1 will become operational by the end of 2012.
All of the Utility’s 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 capacity of 110 MW. The Utility is in the process of renewing hydroelectric licenses associated with capacity of approximately 1,072 MW and surrendering the hydroelectric license associated with the Kilarc-Cow Creek Project which has a capacity of 5 MW. Although the original licenses associated with 880 MW of the 1,072 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 3,003 MW of hydroelectric power will expire between 2013 and 2047.
Conventional Generation Facilities. The Utility’s conventional generation facilities include the Colusa Generating Station, a combined cycle generating facility with 530 MW of base capacity and 127 MW of enhanced capability that became operational in December 2010, the Gateway Generating Station with 530 MW of base capacity and 50 MW of enhanced capability that became operational in January 2009, and the 163-MW Humboldt Bay generating station that became operational in September 2010. In addition, the Utility owns and operates three fuel cell sites in the Bay Area that became operational in September 2011 and have a combined capacity of 3 MW.
In December 2010, the CPUC approved a purchase and sale agreement between the Utility and Contra Costa Generating Station LLC for the development and construction of the Oakley Generation Facility, a 586-MW natural gas-fired, combined-cycle generation facility proposed to be located in Oakley, California. For more information about the status of this proposed facility, see the section of MD&A entitled “Capital Expenditures” in the 2011 Annual Report.
Photovoltaic Facilities. In April 2010, the CPUC approved the Utility’s 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. During 2011, Utility-owned PV facilities with an aggregate capacity of 50 MW became operational. These facilities include the Five Points Solar Station, the Stroud Solar Station, and the Westside Solar Station, each of which is located in Fresno County. Three other PV facilities with an aggregate capacity of 50 MW are currently under construction. They are estimated to become operational by October 2012.
DWR Power Purchases
During 2011, electricity from the DWR contracts allocated to the Utility provided approximately 3.57% of the electricity delivered to the Utility’s customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as these contracts expire or are novated to the Utility.
Third-Party Power Purchase Agreements
QF Power Purchase Agreements. As of December 31, 2011, the Utility had power purchase agreements with 217 QFs for approximately 3,400 MW of capacity that are in operation. Approximately 2,200 MW of this capacity is from cogeneration projects and 1,200 MW is from renewable generation resources, as discussed below. Agreements for approximately 3,100 MW expire at various dates between 2012 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. QF power purchases accounted for 18.68% of the Utility’s 2011 electricity deliveries. No single QF accounted for more than 5% of the Utility’s 2011 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 produce 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 filed 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. The FERC approved the joint application in June 2011. The settlement agreement became effective on November 23, 2011 when all of the conditions precedent were satisfied.
Irrigation Districts and Water Agencies. The Utility also has entered into agreements with various irrigation districts and water agencies to purchase hydroelectric power that require the Utility to make semi-annual fixed minimum payments. In addition, these agreements require the Utility to make variable payments based on the operating and maintenance costs incurred by the irrigation districts and water agencies. These contracts will expire on various dates between 2012 and 2031. In 2011, they accounted for 6.24% of the Utility’s electricity deliveries.
Bilateral Contracts. The Utility has entered into several power purchase agreements for renewable and conventional generation resources, including tolling agreements and resource adequacy agreements. During 2011, the Utility’s purchases under these agreements accounted for 20.89% of the Utility’s deliveries.
For more information regarding the Utility’s power purchase contracts, see Note 15: Commitments and Contingencies - Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.
Renewable Generation Resources
Renewable generation resources include biomass, small hydroelectric, wind, solar, and geothermal energy. In April 2011, the California Governor signed legislation that establishes a new RPS that requires load-serving entities, such as the Utility, to increase the amount of renewable energy they procure from at least 20% of their total retail sales, as required by the prior RPS law, to 33% of their total retail sales. The RPS law establishes three initial compliance periods: 2011-2013, 2014-2016, and 2017-2020. The RPS compliance requirement that must be met for each of these compliance periods will gradually increase. Thereafter, compliance with the 33% RPS requirement will be determined on an annual basis.
The new RPS law creates three distinct categories (or “buckets”) of renewable energy products that can be used to meet the RPS requirements and imposes minimum or maximum procurement targets for each of these product categories for each compliance period. With certain exceptions, these categorical requirements will only apply to renewable energy contracts entered into after June 1, 2010. The new law also (1) limits the use of certain types of unbundled renewable energy credits and (2) restricts the ability to carry forward (or “bank”) RPS volumes from certain types of short-term contracts, to satisfy compliance obligations.
On December 15, 2011, the CPUC issued a decision to adopt the criteria for each “portfolio content category.” The decision requires all retail sellers to provide sufficient information about their RPS procurement so the CPUC can make a compliance determination that the retail seller’s RPS procurement actually meets the requirements of the portfolio content category which the retail seller claims. In addition, investor-owned utilities must provide specific information when seeking CPUC approval of RPS procurement contracts that will allow the CPUC to evaluate the proposed portfolio content category of the planned procurement, and the value and risk of the planned procurement to the utilities’ ratepayers.
In addition, the CPUC is expected to determine whether to change the penalty provisions established under the former RPS law, which provided for a maximum penalty of $25 million per year on each load-serving entity that had an unexcused failure to meet its compliance obligation. Until the CPUC adopts regulations to implement the new law, it is uncertain how the CPUC’s regulations and decisions issued pursuant to the former RPS statute, including the penalty provisions, will apply to the new RPS requirements.
Additionally, the CEC, which continues to have responsibility for certifying the eligibility of renewable resources and verifying LSE compliance with the RPS program, has also initiated a proceeding to implement the new RPS law and is expected to issue one or more draft regulations in the second quarter of 2012.
The costs incurred by the Utility under third-party contracts to meet RPS requirements are tracked in a balancing account and recovered through rates. The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximums authorized by the CPUC for the respective project.
For the year ended December 31, 2011, the Utility’s RPS-eligible renewable resource deliveries equaled 19.3% 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 Utility’s small hydroelectric and solar facilities and certain irrigation district contracts (small hydroelectric 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 Utility’s hydroelectric generating units have a capacity in excess of 30 MW and do not qualify as RPS-eligible resources.)
Total 2011 renewable deliveries are stated in the table below.
For more information regarding the Utility’s renewable energy contracts, see Note 15: Commitments and Contingencies - Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.
Electricity Transmission
At December 31, 2011, the Utility owned approximately 18,618 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of approximately 59,743 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through approximately 141,000 circuit miles of distribution lines and substations with a capacity of 29,066 MVA. In 2011, the Utility delivered 74,684 GWh to its customers, and approximately 8,494 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 Utility’s Regulatory Environment - Federal Energy Regulation.”
The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO. (RMR agreements require various power plant owners to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO’s demand when the generation from those RMR units is needed for local transmission system reliability.)
Electricity Distribution Operations
The Utility’s electricity distribution network extends through 47 of California’s 58 counties, comprising most of northern and central California. The Utility’s network consists of approximately 141,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 91 transmission substations and 57 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 601 distribution substations. The 57 combined transmission and distribution substations have both transmission and distribution transformers.
The Utility’s distribution network interconnects to the Utility’s electricity transmission system at approximately 1,758 points. This interconnection between the Utility’s distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers. The distribution substations serve as the central hubs of the Utility’s electricity distribution network and consist of transformers, voltage regulation equipment, protective devices, and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.
Much of the Utility’s electric transmission and distribution infrastructure was placed into service in the 1940’s through the 1960’s as California’s 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 Utility has been installing an advanced metering infrastructure using SmartMeterTM technology throughout its service territory. As of December 31, 2011, the Utility has installed approximately 8.9 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 Utility’s 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 and several municipalities took various steps to delay or suspend the installation of the new meters. On February 1, 2012, the CPUC issued a decision that permits customers to opt out of the SmartMeterTM program. For information about these matters, see the section of MD&A entitled “Regulatory Matters - Deployment of SmartMeterTM Technology” in the 2011 Annual Report.
Electricity Deliveries
The following table shows the percentage of the Utility’s total 2011 electricity deliveries represented by each of its major customer classes.
Total 2011 Electricity Delivered: 83,688 GWh
Electricity Distribution Operating Statistics
The following table shows certain of the Utility’s operating statistics from 2007 to 2011 for electricity sold or delivered, including the classification of sales and revenues by type of service.
(1) These amounts include electricity provided to direct access customers who procure their own supplies of electricity.
Natural Gas Utility Operations
The Utility owns and operates an integrated natural gas transportation, storage, and distribution system in California that extends throughout all or a part of 40 of California’s 58 counties and includes most of northern and central California. In 2011, the Utility served approximately 4 million natural gas distribution customers.
The CPUC divides the Utility’s on-system natural gas customers into two categories for the purpose of determining service reliability: core and non-core customers. This classification is based largely on a customer’s annual natural gas usage. The core customer class is comprised mainly of residential and small commercial natural gas customers. The non-core customer class is comprised of industrial, large commercial, and electric generation natural gas customers. In 2011, core customers represented more than 99% of the Utility’s total natural gas customers and 41% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 59% of its on-system natural gas deliveries. In addition to deliveries discussed above, the Utility delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage customers.
The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. Currently, over 3% of core customers, representing over 15% of the annual core market demand, receive bundled natural gas service from the Utility.
The Utility does not provide procurement service to electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers. However, some non-core customers are eligible to elect to receive core service, including procurement service, if such customers contract to receive core service for at least five years. These restrictions were put in place because large increases in demand for the Utility’s procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.
The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility’s backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.
The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’s results of operations over the long term are not affected by weather variations, conservation, or changes in their consumption levels. The Utility’s results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utility’s natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.
Natural Gas System
As of December 31, 2011, the Utility’s natural gas system consisted of approximately 42,309 miles of distribution pipelines, approximately 6,431 miles of backbone and local transmission pipelines, and various storage facilities. The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems. The Utility’s 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 Utility’s Line 400/401 interconnects with the natural gas transportation pipeline of TransCanada’s Gas Transmission Northwest LLC (“GTN”) and Ruby Pipeline, LLC (“Ruby Pipeline”) at the California-Oregon border. This combined receipt capacity at the border is approximately 2.0 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States. The Utility also is supplied by natural gas fields in California.
The Utility owns three underground natural gas storage fields and has a 25% interest in the Gill Ranch underground natural gas storage facility located near Fresno, California. These facilities currently provide the Utility with approximately 106.5 bcf of maximum working gas capacity. When the Gill Ranch storage facility is fully developed, the Utility’s total maximum working gas capacity would increase to 107.2 bcf. In addition, three independent storage operators are interconnected to the Utility’s northern California transportation system. A fourth independent storage operator is currently developing a field for operations planned in 2012. These additional storage facilities increase gas supply and provide additional storage capacity for customers.
During 2011, the Utility took significant action to implement the recommendations made by the NTSB and the CPUC’s independent review panel to improve the Utility’s natural gas operating practices and procedures and to comply with CPUC orders. Among other tasks, the Utility has validated the maximum allowable operating pressure (“MAOP”) of approximately 1,800 miles of pipelines, automated 11 shut off- valves, and conducted hydrostatic pressure tests on approximately 165 miles of pipelines. The Utility also is taking steps to improve its emergency response procedures and training, its supervisory controls and data acquisition system and procedures to better detect pipeline leaks and breaks, its integrity management program (including new analysis tools to identify and assess risks to pipeline integrity), its pipeline safety measures and public awareness of pipeline safety measures, and its data management system which is intended to address the NTSB’s and the CPUC’s recommendations for traceable, verifiable and complete records.
2011 Natural Gas Deliveries
The total volume of natural gas delivered to on-system customers during 2011 was approximately 804 MMDth. The following table shows the percentage of the Utility’s total 2011 natural gas deliveries represented by each of the Utility’s major customer classes.
Total 2011 Natural Gas Deliveries: 804 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 2011 California Gas Report forecasts average annual growth in the Utility’s natural gas deliveries (for core customers and non-core transportation) of approximately 0.3% for the years 2011 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.
Natural Gas Operating Statistics
The following table shows the Utility’s operating statistics from 2007 through 2011 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service.
(1) In the years presented, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.
(2) Includes fuel for the Utility’s fossil fuel-fired generation plants.
Natural Gas Supplies
The Utility purchases natural gas to serve the Utility’s core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have fluctuated generally based on market conditions. During 2011, the Utility purchased approximately 279,157 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 Utility’s largest individual supplier represented approximately 9% of the total natural gas volume the Utility purchased during 2011.
The following table shows the total volume and the average price of natural gas in dollars per MMcf of the Utility’s natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. Southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges, and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In the years presented below, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.
(1) California purchases include supplies transported into California by others.
Gas Gathering Facilities
The Utility’s gas gathering system collects natural gas from third-party wells in northern and central California. During 2011, approximately 5% of the gas transported on the Utility’s system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream, and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 40 miles of gas gathering pipelines. The Utility receives gas well production at approximately 180 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 7 California counties. Approximately 111 MMcf per day of natural gas produced in northern California was delivered into the Utility’s gas gathering system during 2011.
Interstate and Canadian Natural Gas Transportation Services Agreements
In 2011, approximately 52% of the gas transported on the Utility’s system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers’ service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-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 GTN, which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has two firm transportation agreements with GTN for these services.
During 2011, approximately 20% of the gas transported on the Utility’s system came from the U.S. Rocky Mountains. The Utility has firm transportation agreements with Ruby Pipeline to transport this gas from the U.S Rocky Mountains to the interconnection point with the Utility’s natural gas transportation system in the area of Malin, Oregon, at the California border.
During 2011, approximately 23% of the gas transported on the Utility’s system came from the southwestern United States. The Utility has firm transportation agreements with Transwestern Pipeline Company, LLC and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utility’s natural gas transportation system in the area of California near Topock, Arizona.
The following table shows certain information about the Utility’s firm natural gas transportation agreements in effect at the end of 2011 to support the Utility’s 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 CPUC’s 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.
(1) As of December 31, 2011, the Utility had two active contracts with TransCanada NOVA Gas Transmission, Ltd. with expiration dates ranging from October 31, 2016 to October 31, 2020.
(2) As of December 31, 2011, the Utility had two active contracts with TransCanada Foothills Pipe Lines Ltd., B.C. System with expiration dates of October 31, 2013.
(3) As of December 31, 2011, the Utility had two active contracts with TransCanada Gas Transmission Northwest LLC with expiration dates ranging from October 31, 2016 to October 31, 2020.
(4) As of December 31, 2011, the Utility had two active contracts with Transwestern Pipeline Company with expiration dates ranging from February 29, 2012 to March 31, 2013.
(5) As of December 31, 2011, the Utility had two active contracts with El Paso Natural Gas Company with expiration dates ranging from June 30, 2012 to June 30, 2013.
(6) The Utility has the option to reduce quantity (MDth per day) beginning with the twelfth year and annually thereafter through the end of the contract.
Public Purpose and Customer Programs
California law requires the CPUC to authorize certain levels of funding for programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources through the collection of a public goods charge. The legislation authorizing the public goods charge expired on January 1, 2012. The CPUC has ordered the Utility to continue to collect in rates the amounts that were previously funded through the public goods charge for energy efficiency, renewables, and research and development, on an interim basis through 2012. 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 2011, the Utility collected authorized revenue requirements of $731 million from electric customers and $161 million from gas customers to fund public purpose and other programs.
Energy Efficiency Programs
The Utility’s energy efficiency programs are designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products. The CPUC has authorized a total of $1.3 billion to fund the Utility’s 2010-2012 energy efficiency programs. 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 CPUC’s energy savings goals. In accordance with this mechanism, the CPUC has awarded the Utility incentive revenues totaling $130 million through December 31, 2011 for successful implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle and for the 2009 bridge year. 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.
Demand Response Programs
Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. The CPUC authorized the Utility to collect $109 million to fund its 2009-2011 demand response programs. In addition, the CPUC authorized the Utility to collect $112 million through December 31, 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 anticipates that the CPUC will issue a decision providing funding for the 2012-2014 demand response programs during the first quarter of 2012.
Self-Generation Incentive Program and California Solar Initiative
The Utility administers the self-generation incentive program (“SGIP”) authorized by the CPUC to provide incentives to electricity and gas 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. In December 2011, the CPUC approved continuing annual funding for the SGIP of approximately $36 million through 2014, with any carryover funds to be administered through 2015. The Utility also administers the California Solar Initiative (“CSI”) in its service territory. The CPUC has authorized the Utility to collect approximately $1.1 billion from 2007 through 2016 to fund customer incentives for the installation of retail solar energy projects to serve onsite load, as well as to fund research, development, and demonstration activities, and administration expenses. 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.
Low-Income Energy Efficiency Programs and California Alternate Rates for Energy
The CPUC has authorized the Utility to collect approximately $417 million to support the Utility’s energy efficiency programs for low-income and fixed-income customers over 2009 through 2011. The Utility has requested that the CPUC authorize $479 million in funding to continue this program through 2014. The Utility also provides a discount rate called the California Alternate Rates for Energy (“CARE”) for low-income customers. This rate subsidy is paid for by the Utility’s other customers. 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 2011, the amount of this subsidy was approximately $917 million, including avoided customer surcharges. The CPUC also authorized the Utility to recover approximately $35 million in administrative costs relating to the CARE subsidy through 2014.
Environmental Matters
The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of activities, including the following:
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the discharge of pollutants into the air, water, and soil;
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the transportation, handling, storage and disposal of spent nuclear fuel;
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the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, remediation and emergency response in connection with hazardous and radioactive substances;
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the reporting and reduction of carbon dioxide (“CO2”) and other GHG emissions; and
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the environmental impacts of land use, including endangered species and habitat protection.
The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify, or replace equipment, acquire permits and/or emission allowances or other emission credits for facility operations and clean-up, or decommission waste disposal areas at the Utility’s current or former facilities and at third-party sites where the Utility’s wastes may have been disposed.
The Utility’s 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 Utility’s 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 owner’s 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 Utility’s 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.”
Air Quality and Climate Change
The Utility’s electricity generation plants, natural gas pipeline operations, fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide (“SO2”), nitrogen oxide (“NOx”) and particulate matter.
Federal Regulation. At the federal level, the U.S. Environmental Protection Agency (“EPA”) is charged with implementation and enforcement of the Clean Air Act. Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, comprehensive federal legislation is unlikely to be enacted within the next few years. 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. In December 2011, the EPA released final mercury and air toxic standards for new emission sources. These
regulations set emission limits for new and existing sources of GHG emissions, specifically coal- and oil-fired power plants. While the Utility does not own any coal- or oil-fired power plants, it does procure a small portion of electricity from plants that use coal and oil. The EPA’s regulations could increase the price for this power. All of the EPA’s major GHG regulatory actions under the Clean Air Act, including the tailoring rule, are being challenged in federal court and are not likely to be resolved until mid- to late 2012, or later.
State Regulation. 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. AB 32 requires the gradual reduction of GHG emissions in California to the 1990 level by 2020. 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. The CARB has approved various regulations to implement AB 32, including a state-wide, comprehensive “cap and trade” program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by the major sources of GHG emissions. These regulations became effective on January 1, 2012.
The cap and trade program’s first two-year compliance period, which begins January 1, 2013, will apply to the electricity generation and large industrial sectors. The next two-year compliance period, from January 1, 2015 through December 31, 2017, also will apply to the natural gas supply and transportation sectors. (The last compliance period, from January 1, 2018 through December 31, 2020, will apply to all sectors.) Before the first compliance period begins, the CARB will issue a fixed number of emission allowances (i.e., the rights to emit GHGs), some of which will be freely allocated to regulated electric distribution utilities for their customers’ benefit. The CARB will sell other allowances at an auction, the first of which is scheduled to be held on August 15, 2012. Emitters, i.e., those entities with a compliance obligation, also can purchase “offset credits” from certified parties that develop environmental projects in sectors not regulated under the cap, such as reforestation and methane capture projects. These emitters can then use the offset credits to satisfy up to 8% of their compliance obligations. Allowances may be purchased and sold through a CARB-managed auction or in private transactions, while offset credits are available only through private transactions. On or before specified deadlines during and at the end of each compliance period, emitters must surrender allowances and offset credits, in an amount equal to their GHG emissions during the period, to the CARB. During 2012, the CARB is expected to complete additional cap-and-trade market design and implementation activities, and is expected to conduct market simulations to evaluate current market design.
The Utility’s compliance costs under the cap and trade program are expected to be passed through to customers through rates. The CPUC is conducting a rulemaking to develop rules for the allocation of auction revenues to the utilities’ electric customers and a proposed decision is scheduled to be issued in May 2012. Allocation of allowances to help reduce the compliance costs that the Utility may incur on behalf of the Utility’s small natural gas customers remains an open issue.
Increasing use of renewable energy supplies also is expected to help reduce GHG emissions in California. In April 2011, the California Governor signed legislation that requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy delivered to their customers to at least 33% of the total amount of electricity retail sales by 2020. (See “Electricity Generation Resources” above.) In December 2011, the CPUC approved various regulations to implement the new law, including the establishment of renewable energy targets for each compliance period. (See “Renewable Energy Resources” above for more information.)
Climate Change Mitigation and Adaptation Strategies. During 2011, the Utility continued its programs to develop strategies to mitigate the impact of the Utility’s 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 Utility’s 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 parts of the Sierra Nevada Mountains. This impact could, in turn, affect the Utility’s 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 rather than snow, 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 hydroelectric generation with electricity 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%.
The Utility believes its strategies to reduce GHG emissions-such 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.
Emissions Data
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 voluntarily reported its GHG emissions to CCAR on an annual basis from 2002 through 2008. The Utility has since voluntarily reported its GHG emissions to The Climate Registry (“TCR”), a successor non-profit to CCAR, that has a reporting and measurement standard applicable to most industry sectors across North America. Since 2009, the Utility has also complied with AB 32’s annual GHG emission reporting requirements, and in 2011, the Utility began reporting the GHG emissions from some of its facilities and operations to the EPA under its new requirements. In 2012, the Utility will include the GHG emissions from the natural gas supplied to end-users and the vented and fugitive emissions from its natural gas system in its report to the EPA. Beginning in 2012, the Utility will annually report to the CARB the GHG emissions from customers’ use of natural gas.
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 Utility’s GHG emissions in accordance with the standards developed by TCR, emissions data for 2010 are the most recent data available. For information about the sources of electric generation that the Utility delivered to customers in 2011, see “Electric Utility Operations-Electric Generation Resources” above.
Total 2010 GHG Emissions by Source Category
(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 Utility’s total emissions and the Utility’s emission rate for delivered electricity. Emissions data for the Utility’s owned generation resources is shown below.
Benchmarking Greenhouse Gas Emissions for Delivered Electricity
The Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2010 was 443 pounds of CO2 per MWh, which is a significant decrease from the 2009 emissions rate of 575 pounds of CO2 per MWh. The Utility’s 2010 emissions rate as compared to the national and California averages for electric utilities is shown in the following table:
(1) Source: Environmental Protection Agency eGRID 2010 Version 1.1, which contains year 2007 information, configured to reflect the electric power industry’s current structure as of December 31, 2010. This is the most up-to-date information available from EPA.
(2) 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 Utility’s total emissions and the Utility’s emission rate for delivered electricity.
Emissions Data for Utility-Owned Generation
In addition to GHG emissions data provided above, the table below sets forth information about the GHG and other emissions from the Utility’s owned generation facilities. The Utility’s owned generation (primarily nuclear and hydroelectric facilities) comprised approximately 40% of the Utility’s delivered electricity in 2010. The Utility’s retained fossil fuel-fired generation comprised approximately 5% of the Utility’s delivered electricity in 2010.
Water Quality
Section 316(b) of the federal Clean Water Act requires that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. On April 20, 2011, the EPA published draft regulations that propose specific reductions for impingement (which occurs when larger organisms are caught on water filter screens) and provide a case-by-case site specific assessment to establish compliance requirements for entrainment (which occurs when organisms are drawn through the cooling water system). The proposed site specific assessment allows for the consideration of a variety of factors including social costs and benefits, energy reliability, land availability, and non-water quality adverse impacts. The draft regulations were subject to public comment and final regulations are not expected until July 2012.
On May 4, 2010, the California Water Resources Control Board (“California 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 state’s 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 California 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 California 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, may need to procure substitute power, and may incur a material charge. Assuming the California 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 Utility’s Diablo Canyon operations must be in compliance with the California Water Board’s policy by December 31, 2024.
Hazardous Waste Compliance and Remediation
The Utility’s facilities are subject to the requirements issued by the EPA under the federal Resource Conservation and Recovery Act (“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site, and in some cases corporate successors to the operators or arrangers. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources, and the costs of required health studies. In the ordinary course of the Utility’s operations, the Utility generates waste that falls within CERCLA’s definition of hazardous substances and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state, and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling, and disposal requirements issued by the EPA under RCRA and state hazardous waste laws, and other environmental requirements. The Utility’s remediation activities are overseen by the California Department of Toxic Substances Control (“DTSC”), several California regional water quality control boards, and various other federal, state, and local agencies.
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; current and former power plant sites; former gas gathering and gas storage sites; sites where natural gas compressor stations are located; current and former substations, service center and general construction yard sites; and sites currently and formerly used by the Utility for the storage, recycling, or disposal of hazardous substances. 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,” “Critical Accounting Polices,” and Note 15: Commitments and Contingencies-Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report which information is incorporated herein by reference and included in Exhibit 13 to this report.
Generation Facilities
Operations at the Utility’s current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal 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 Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. The DTSC approved the soil and groundwater remediation plan in June 2010 and remediation pursuant to the plan is underway. The Utility spent approximately $34 million in 2011. Fossil fuel-fired Units 1 and 2 of the Utility’s 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 soil and groundwater remediation may be necessary.
Former Manufactured Gas Plant Sites
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 $33 million in 2011 on these sites.
Third-Party Owned Disposal 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 Utility’s 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.
Natural Gas Compressor Stations
The Utility owns and operates three natural gas compressor stations: one is located near Hinkley, California, another is located near the California-Arizona border in Topock, Arizona, and the third station is located near Kettleman, California. Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility is responsible for remediating this groundwater contamination and for abating the effects of the contamination on the environment.
The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region (“Regional Board”). The Regional Board has issued numerous cleanup and abatement orders directing the Utility to fully investigate the plume of hexavalent chromium and implement interim remedial measures to both reduce the mass of the underground plume and control movement of the plume. In August 2010, the Utility filed a comprehensive feasibility study with the Regional Board that included an evaluation of possible alternatives for a final groundwater remediation plan. The Utility filed several addendums to its feasibility study based on additional analyses of remediation alternatives and further information from the Regional Board. In September 2011, the Utility submitted a final remediation plan to the Regional Board. In October 2011, the Regional Board issued an amended cleanup and abatement order that requires the Utility to provide an interim and permanent replacement water system for certain properties with domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion (“ppb”) background level and propose a method to evaluate individual wells with hexavalent chromium concentrations below 3.1 ppb to determine if they have been impacted by the Utility’s past operations. The order requires that the Utility provide evidence to prove that the provided water meets primary and secondary drinking water standards and contains hexavalent chromium in concentrations no greater than 0.02 ppb. The order notes that for purposes of this standard, drinking water must test below the reporting limit of 0.06 ppb due to the limitation of laboratory analysis of low levels of chromium. The Utility has filed a petition with the California Water Board to request that the board determine that the Utility is not required to comply with these provisions of the order, in part, because the Utility believes that it is not feasible to implement the ordered actions and that the ordered actions are not supported by California law. The Regional Board’s response to the petition is due by February 20, 2012.
For the year ended December 31, 2011, the Utility increased its provision for environmental remediation liabilities associated with the Hinkley site by $140 million, which resulted primarily from changes in costs estimates and assumptions associated with these developments. For more information, see Note 15 Commitments and Contingencies of the Notes to the Consolidated Financial Statements. During 2011, the Utility spent $36 million for remediation activities at the Hinkley site. The Utility is unable to recover remediation costs for the Hinkley natural gas compressor site through the ratemaking mechanism described below.
The Utility’s investigation and remediation activities at the Topock compressor station are subject to oversight by the DTSC and the U.S. Department of the Interior. 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. In January 2011, the regulatory agencies approved the Utility’s final remediation plan under which the Utility will implement an in-situ treatment project to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. To implement the final remedy, the Utility plans to install a significant number of additional injection and extraction wells and an associated piping system. The regulatory approval of the environmental impact report associated with the final remediation plan has been challenged in the Sacramento Superior Court by the Fort Mojave Indian Tribe. The tribe alleges that the cultural mitigation requirements contained in the environmental impact report was inadequate. The Utility, the tribe and DTSC are engaged in settlement negotiations to address the tribe’s concerns. In 2011, the Utility spent approximately $14 million for remediation activities at Topock. The Utility’s remediation costs for Topock are subject to the ratemaking mechanism described below.
The Utility does not expect that it will incur any material expenditures related to remediation at the Kettleman natural gas compressor station site.
Recovery of Environmental Remediation Costs
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 Utility’s rates without a reasonableness review. Ten percent of any net insurance recoveries associated with hazardous waste
remediation sites are assigned to the Utility’s 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 Utility’s 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 Utility’s customers.
The CPUC has historically authorized the Utility to recover 100% of its remediation costs for decommissioning fossil fuel-fired generation facilities and sites through decommissioning funds collected in rates, and the Utility believes it is probable that it will continue to recover these costs in the future. The CPUC also authorized the Utility to make a one-time recovery of $139 million in rates for pre-closing environmental remediation liabilities associated with fossil fuel-fired generation facilities that the Utility sold in 1998 and 1999 in connection with electric industry restructuring. The remaining liability at these sites is $81 million. Any future changes to these liabilities will impact PG&E Corporation’s and the Utility’s financial results. The Utility expects to recover labor and other administrative costs associated with environmental remediation through other ratemaking mechanisms. Finally, the Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.
Nuclear Fuel Disposal
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 Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay. Because the DOE failed to meet its contractual obligations to dispose of nuclear waste, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024. On February 15, 2011, the U.S. Court of Appeals for the Ninth Circuit denied an appeal that had been filed to challenge the NRC’s order granting the Utility a license to build the dry cask storage facility.
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.
Nuclear Decommissioning
The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay Unit 3. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding, 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 Utility’s decommissioning cost estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plants. Actual decommissioning costs may vary from these estimates 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 Utility’s 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: Summary of Significant Accounting Policies- Nuclear Decommissioning Trusts, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.
Endangered Species
Many of the Utility’s facilities and operations are located in, or pass through, areas that are designated as critical habitats for federal, or state-listed endangered, threatened, or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated at or near the Utility’s facilities or operations. The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.
Item 1A.
Item 1A. Risk Factors
A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading “Risk Factors” in the MD&A in the 2011 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility’s electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under “Electric Utility Operations” and “Natural Gas Utility Operations” 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 Utility’s 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, including approximately 140,000 acres of watershed lands. As part of the Chapter 11 Settlement Agreement, the Utility agreed to protect its watershed lands with conservation easements or equivalent protections, and/or donate up to approximately 75,000 acres of its watershed lands to public entities or qualified non-profit conservation organizations. (The Utility will not donate watershed lands that contain the Utility’s or a joint licensee’s hydroelectric generation facilities or is otherwise used for utility operations, but this land may be encumbered with conservation easements.) The Utility formed a non-profit organization, 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 watershed lands. The Council is governed by an 18-member board of directors, one of whom was appointed by the Utility. The other members represent a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials. The Council’s goal is to implement the transactions contemplated in the LCP over the next few years, subject to obtaining any required permits and approvals from the FERC, the CPUC, and other governmental agencies.
PG&E Corporation also leases approximately 82,000 square feet of office space from a third party in San Francisco, California, of which 40,000 square feet will expire in 2014 and the remaining in 2022.
Item 3.
Item 3. Legal Proceedings
In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s liability for legal matters, see Note 15: Commitments and Contingencies-Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.
Diablo Canyon Power Plant
The Utility’s Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act permit issued by the Central Coast Regional Water Quality Control Board (“Central Coast Board”). This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility’s Diablo Canyon power plant’s discharge was not protective of beneficial uses.
In October 2000, the Utility and the Central Coast Board reached a tentative settlement under which the Central Coast Board agreed to find that the Utility’s discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act. As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement agreement. On June 17, 2003, the settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General’s Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon’s permit.
At its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists’ draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists’ recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers.
In addition, the California Water Board’s policy on once-through cooling and regulations that are expected to be issued by the EPA in July 2012 could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement. (See “Item 1. Business-Environmental Matters-Water Quality” above.)
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their Utility’s financial condition or results of operations.
Hinkley Natural Gas Compressor Station
As previously disclosed, groundwater at the Utility’s Hinkley natural gas compressor station contains hexavalent chromium as a result of the Utility’s past operating practices. At the Hinkley site, the Utility is cooperating with the California Regional Water Quality Control Board, Lahontan Region (“Regional Board”) to evaluate and remediate the chromium groundwater plume. The Regional Board has issued several orders directing the Utility to implement interim remedial measures to both reduce the mass of the underground plume of hexavalent chromium and to monitor and control movement of the plume. In September 2011, the Utility submitted a final remediation plan to the Regional Board that recommends a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. On February 2, 2012, the Regional Board and the Utility reached a settlement of a claim for administrative penalties the Regional Board sought to impose on the Utility due to the Utility’s alleged violation of a 2008 order requiring the Utility to control the spread of the chromium groundwater plume beyond boundaries described in the order. Under the terms of the settlement, the Utility will pay a penalty of $3.6 million, half of which will fund the construction of a replacement water system for the Hinkley public school. The settlement is subject to approval of the full Regional Board.
For more information about the Utility’s remediation activities at the Hinkley site, see the section of MD&A entitled “Environmental Matters” in the 2011 Annual Report.
Litigation Related to the San Bruno Accident
Approximately 100 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, have been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 370 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. The Utility stated publicly that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court and a trial date of July 23, 2012 has been set for the first of these cases. During the case management conference on January 19, 2012, the court addressed, among other topics, mandatory settlement conferences. The court expressed its preference that generally households suffering a death or serious injury should proceed first. It is likely the mandatory settlement conferences will start in late March or early April 2012. The next case management conference is scheduled for March 2, 2012.
Additionally, a purported shareholder derivative lawsuit was filed following the San Bruno accident 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 case has been coordinated with the other cases in the San Mateo County Superior Court. The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of the court.
For more information regarding the litigation related to the San Bruno accident, see the section of MD&A entitled “Natural Gas Matters” in the 2011 Annual Report. See also Note 15: Commitments and Contingencies-Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report, which discussion is incorporated into this Item 3 by reference and included in Exhibit 13 to this report.
Pending Investigations Regarding the San Bruno Accident and Natural Gas Matters
As described below, the CPUC has issued three orders to institute investigations (“OII”) pertaining to various aspects of the Utility’s natural gas transmission system, including an investigation of the San Bruno accident. If the CPUC determines that the Utility violated applicable law, rules or orders, in connection with the CPUC’s investigations, the CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.) As described below, a criminal investigation into the San Bruno accident also was commenced by federal and state authorities.
For more information, see the section of MD&A entitled “Natural Gas Matters” in the 2011 Annual Report and Note 15: Commitments and Contingencies-Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report, which discussion is incorporated into this Item 3 by reference and included in Exhibit 13 to this report.
CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines. On February 24, 2011, the CPUC issued an OII pertaining to safety recordkeeping for the Utility’s gas transmission pipeline (Line 132) that ruptured in the San Bruno accident, as well as for its entire gas transmission system. The CPUC will determine (1) whether the Utility’s recordkeeping practices for its gas transmission pipeline system and its knowledge of its own gas transmission pipeline system (and, in particular, the San Bruno pipeline) was deficient and unsafe, and (2) whether the Utility thereby violated applicable law and safety standards. Among other matters, this phase will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and/or accurate and effective technical recordkeeping in compliance with the law. The CPUC will consider whether the Utility’s approach to recordkeeping stems from corporate-level management policies and practices and, if so, whether such practices and policies contributed to recordkeeping violations that adversely affected safety. The CPSD is scheduled to file its report on the Utility’s recordkeeping practices on March 5, 2012. Evidentiary hearings for the investigation are scheduled for September 2012 with a final decision expected in February 2013.
CPUC Investigation Regarding Class Location Designations for Pipelines. On November 10, 2011, the CPUC issued an OII pertaining to the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density. Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the MAOP up to which a pipeline can be operated. In the OII, the CPUC referred to the Utility’s June 30, 2011 class location study, in which the Utility reported that the class designations for some of its transmission pipeline segments had changed from what was reflected in the Utility’s Geographical Information System (“GIS”). Among other issues, the CPUC will determine whether the Utility failed to conduct class location studies when required, failed to adequately patrol and conduct continuing surveillance of its pipeline transmission system, failed to replace pipeline segments or reduce MAOP when the class location designation of a segment changed, and failed to furnish and maintain adequate, efficient, just and reasonable natural gas transmission service.
On January 17, 2012, the Utility reported that 162 miles of pipeline had a current class location higher than reflected in its GIS. Most of the misclassifications were due to the Utility’s failure to correctly identify development or well-defined areas near the pipeline. The Utility stated that some segments had been incorrectly classified since 1971. The Utility also determined that it had not timely performed a class location study for certain segments and did not confirm the MAOP of those segments for which the Utility had not timely identified a change in class location. On February 2, 2012, the Utility filed an update reporting that approximately 10 miles of pipeline had been operating at an MAOP higher than allowed for their current class location.
A prehearing conference was held on February 3, 2012 at which the assigned administrative law judge (“ALJ”) set April 2, 2012 as the date for the Utility to submit a second update reporting the final results of its validation of the class location data. The ALJ will set a second prehearing conference during the week of April 16, 2012.
CPUC Investigation Regarding San Bruno Accident. On January 12, 2012, the CPUC issued an OII to determine whether the Utility violated applicable laws, rules, orders, requirements, and industry safety standards in connection with the San Bruno accident. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility’s compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. The CPUC cited the findings and allegations made by the CPSD in its investigative report released on January 12, 2012. In its report, the CPSD alleged that the San Bruno accident was caused by the Utility’s failure to follow accepted industry practice when installing the section of pipe that failed, the Utility’s failure to comply with federal pipeline integrity management requirements, the Utility’s inadequate recordkeeping practices, deficiencies in the Utility’s data collection and reporting system, inadequate procedures to handle emergencies and abnormal conditions, the Utility’s deficient emergency response actions after the incident, and a systemic failure of the Utility’s corporate culture that emphasized profits over safety. The CPUC noted that the CPSD’s investigation is ongoing and that the CPSD could raise additional concerns for the CPUC to consider.
The CPSD report also discussed the findings of an independent consulting firm engaged by the CPUC to conduct an audit of the Utility’s natural gas transmission and storage expenditures from 1996 to 2010. The CPSD report stated that the purpose of the audit was to determine whether the amounts that the CPUC authorized for gas pipeline safety investments were actually spent on safety investments. The CPSD made various recommendations based on its allegations and the findings in the consultant’s audit report. During this time, the consultant’s audit report alleged that the Utility spent less on capital expenditures and operation and maintenance expense than it recovered in rates, by $95 million and $39 million, respectively, and alleged that the Utility collected $430 million more in revenues than needed to earn its authorized ROE. Among other recommendations, the CPSD recommended that the Utility should use such amounts to fund future gas transmission expenditures and operations.
In the OII, the CPUC stated that it may consider ordering the Utility to implement the recommendations made in the CPSD’s report, in order to improve and ensure system-wide safety and reliability. In addition, the CPUC stated that it will decide in a separate proceeding whether the Utility’s ratepayers or shareholders, or both, will pay for the Utility’s cost of testing, pipe replacement, or other costs, noting that some costs may stem from the San Bruno pipeline rupture or from recordkeeping deficiencies, both of which could be significant.
At a prehearing conference held on February 14, 2012, the ALJ set a procedural schedule for the parties to conduct discovery and submit testimony before evidentiary hearings begin on September 17, 2012.
Criminal Investigation Regarding the San Bruno Accident. On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility.
CPUC Investigation Regarding Substation Construction Permit
On June 10, 2011, the CPUC issued an order to investigate whether the Utility failed to comply with the CPUC’s November 9, 2009 decision granting the Utility’s request for a permit to construct a substation when the Utility removed an almond tree orchard to prepare the site for construction. Although the Utility believed it complied with the decision in all material respects, the Utility entered into a settlement agreement with the CPUC staff to resolve the investigation that was approved by the CPUC in January 2012. Pursuant to the approved settlement agreement, the Utility has paid a fine of $100,000 and contributed $50,000 to an environmental group.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANTS
The names, ages and positions of PG&E Corporation “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934 (“Exchange Act”) at February 1, 2012 were as follows.
Name
Age
Position
Anthony F. Earley, Jr.
Chairman of the Board, Chief Executive Officer, and President
Kent M. Harvey
Senior Vice President and Chief Financial Officer
Christopher P. Johns
President, Pacific Gas and Electric Company
Hyun Park
Senior Vice President and General Counsel
Greg S. Pruett
Senior Vice President, Corporate Affairs
John R. Simon
Senior Vice President, Human Resources
All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 1, 2012, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.
The names, ages and positions of the Utility’s “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 1, 2012 were as follows:
Name
Age
Position
Anthony F. Earley, Jr.
Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
Christopher P. Johns
President
Nickolas Stavropoulos
Executive Vice President, Gas Operations
Geisha J. Williams
Executive Vice President, Electric Operations
Karen A. Austin
Senior Vice President and Chief Information Officer
Desmond A. Bell
Senior Vice President, Safety and Shared Services
Thomas E. Bottorff
Senior Vice President, Regulatory Relations
Helen A. Burt
Senior Vice President and Chief Customer Officer
John T. Conway
Senior Vice President, Energy Supply and Chief Nuclear Officer
Kent M. Harvey
Senior Vice President, Financial Services
Hyun Park
Senior Vice President and General Counsel, PG&E Corporation
Greg S. Pruett
Senior Vice President, Corporate Affairs
John R. Simon
Senior Vice President, Human Resources
Fong Wan
Senior Vice President, Energy Procurement
Dinyar B. Mistry
Vice President, Chief Financial Officer, and Controller
All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2012, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
As of February 7, 2012, there were 71,943 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 2011 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report. Shares of common stock of the Utility are not listed but are solely owned by PG&E Corporation. Information about the frequency, amount, and restrictions upon the payment of, dividends on common stock declared by PG&E Corporation and the Utility appears in the 2011 Annual Report in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, in Note 6: Common Stock and Share-based Compensation-Dividends, of the Notes to the Consolidated Financial Statements, and in the section of MD&A entitled “Liquidity and Financial Resources-Dividends,” 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, 2011, PG&E Corporation made equity contributions totaling $205 million to the Utility in order to maintain the Utility’s 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 2011.
Issuer Purchases of Equity Securities
During the quarter ended December 31, 2011, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the fourth quarter of 2011, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.
Item 6.
Item 6. Selected Financial Data
A summary of selected financial information, for each of PG&E Corporation and the Utility for each of the last five fiscal years, is set forth under the heading “Selected Financial Data” in the 2011 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
A discussion of PG&E Corporation’s and the Utility’s consolidated financial condition and results of operations is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2011 Annual Report, which discussion is incorporated by reference and included in Exhibit 13 to this report.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Item 7A appears in the 2011 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Risk Management Activities,” and under Notes 10 and 11 of the Notes to the Consolidated Financial Statements of the 2011 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
Item 8.
Item 8. Financial Statements and Supplementary Data
Information responding to Item 8 appears in the 2011 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 “Report of Independent Registered Public Accounting Firm,” which information is incorporated by reference and included in Exhibit 13 to this report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A. Controls and Procedures
Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of December 31, 2011, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.
Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management’s report, together with the report of the independent registered public accounting firm, appears in the 2011 Annual Report under the heading “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm,” which information is incorporated by reference and included in Exhibit 13 to this report.
Item 9B.
Item 9B. Other Information
Not applicable.
PART III
Item 10.
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 2012 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 2012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Website Availability of Code of Ethics, Corporate Governance and Other Documents
The following documents are available both on PG&E Corporation’s website www.pgecorp.com, and the Utility’s 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 Corporation’s and the Utility’s corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies’ Audit Committees and the PG&E Corporation Nominating and Governance Committee and Compensation Committee.
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 2011 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2012 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards of Directors.
Audit Committees and Audit Committee Financial Expert
Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is included under the heading “Corporate Governance - Board Committee Duties and Composition - Audit Committees” and “Corporate Governance - Board Committee Duties and Composition - Committee Membership Requirements” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company - Committee Membership” in the Joint Proxy Statement relating to the 2012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 11.
Item 11. Executive Compensation
Information responding to Item 11, for each of PG&E Corporation and the Utility, is included under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table - 2011,” “Grants of Plan-Based Awards in 2011,” “Outstanding Equity Awards at Fiscal Year End - 2011,” “Option Exercises and Stock Vested During 2011,” “Pension Benefits - 2011,” “Non-Qualified Deferred Compensation - 2011,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “2011 Director Compensation” in the Joint Proxy Statement relating to the 2012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
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 2012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Equity Compensation Plan Information
The following table provides information as of December 31, 2011 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation’s existing equity compensation plans.
(1) Includes 60,200 phantom stock units, 1,663,137 restricted stock units and 2,650,812 performance shares (reflecting in the case of the performance shares the number of shares that would be issued should PG&E Corporation achieve the maximum performance target for the applicable three-year period). The weighted average exercise price reported in column (b) does not take these awards into account. For a description of these performance shares, see Note 6 of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.
(2) Represents the total number of shares available for issuance under the PG&E Corporation Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2011. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock, and phantom stock. The LTIP expired on December 31, 2005. The 2006 LTIP, which became effective on January 1, 2006, authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP. Outstanding stock-based awards granted under the 2006 LTIP include stock options, restricted stock, restricted stock units, phantom stock and performance shares. For a description of the 2006 LTIP, see Note 6 of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information responding to Item 13, for each of PG&E Corporation and the Utility, is included under the headings “Related Person Transactions,” “Review, Approval, and Ratification of Related Party 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 2012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 14.
Item 14. Principal Accountant Fees and Services
Information responding to Item 14, for each of PG&E Corporation and 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 2012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as a part of this report:
1. The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are contained in the 2011 Annual Report and are incorporated by reference in this report:
Consolidated Statements of Income for the Years Ended December 31, 2011, 2010, and 2009 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2011 and 2010 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010, and 2009 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Equity for the Years Ended December 31, 2011, 2010, and 2009 for PG&E Corporation.
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2011, 2010, and 2009 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).
I-Condensed Financial Information of Parent as of December 31, 2011 and 2010 and for the Years Ended December 31, 2011, 2010, and 2009.
II-Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2011, 2010, and 2009.
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.
3. Exhibits required by Item 601 of Regulation S-K
Exhibit
Number
Exhibit Description
The following portions of the 2011 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” financial statements of PG&E Corporation entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’ Equity,” “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Management’s Report on Internal Control Over Financial Reporting,” and “Report of Independent Registered Public Accounting Firm.”
Subsidiaries of the Registrant
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1
Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2
Powers of Attorney
31.1
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of
**32.1
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB
XBRL Taxonomy Extension Labels Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
*
Management contract or compensatory agreement.
**
Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 2011 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.
(1) Mr. Andrews’ power of attorney authorizes Mr. Park to sign for Mr. Andrews only in his capacity as a director of PG&E Corporation.
*By:
HYUN PARK
HYUN PARK, Attorney-in-Fact
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2011 and 2010, and for each of the three years in the period ended December 31, 2011, and the Company’s and the Utility’s internal control over financial reporting as of December 31, 2011, and have issued our report thereon dated February 16, 2012 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to several investigations and enforcement matters pending with the California Public Utilities Commission that may result in material amounts of penalties); such consolidated financial statements and our report are included in your 2011 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the consolidated financial statement schedules of the Company and Utility listed in Item 15(a)2. These consolidated financial statement schedules are the responsibility of the Company’s and the Utility’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
February 16, 2012
San Francisco, California
PG&E CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME
(in millions, except per share amounts)
In calculating diluted EPS during the period PG&E Corporation’s Convertible Subordinated Notes were outstanding, PG&E Corporation applied 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.
PG&E CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
CONDENSED BALANCE SHEETS
(in millions)
PG&E CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow.
(2) On January 15, April 15, July 15, October 15, 2011, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
On January 15, 2010, PG&E Corporation paid a quarterly common stock dividend of $0.42 per share. On April 15, July 15, and October 15, 2010, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
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.
PG&E Corporation
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2011, 2010, and 2009
(in millions)
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
Pacific Gas and Electric Company
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2011, 2010, and 2009
(in millions)
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
EXHIBIT INDEX
Exhibit
Number
Exhibit Description
12.2
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
12.3
Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
The following portions of the 2011 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” financial statements of PG&E Corporation entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’ Equity,” “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Management’s Report on Internal Control Over Financial Reporting,” and “Report of Independent Registered Public Accounting Firm.”
Subsidiaries of the Registrant
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1
Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2
Powers of Attorney
31.1
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of
**32.1
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB
XBRL Taxonomy Extension Labels Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
* Management contract or compensatory agreement.
** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.