SECURITIES AND EXCHANGE COMMISSION
| (Mark One) | | |
| x | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 20112012 |
Or |
¨ | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from _________ to ___________ |
| | | | | | |
File Number
| | as specified in its charter
| | State or Other Jurisdiction of Incorporation or Organization
| | Identification Number
|
| 1-12609 | | PG&E CORPORATION | | California | | 94-3234914 |
| 1-2348 | | PACIFIC GAS AND ELECTRIC COMPANY | | California | | 94-0742640 |
| | |
77 Beale Street, P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip Code) (Registrant’sRegistrant's telephone number, including area code) | | 
77 Beale Street, P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip Code) (Registrant’sRegistrant's telephone number, including area code) |
Securities registered pursuant to Section 12(b) of the Act:
| | |
Title of Each Class | | Name of Each Exchange on Which Registered |
PG&E Corporation:Corporation: Common Stock, no par value | | New York Stock Exchange |
Pacific Gas and Electric Company:Company: First Preferred Stock, cumulative, par value $25 per share: | | NYSE Amex Equities |
Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36% | | |
Nonredeemable: 6%, 5.50%, 5% | | |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
| | | | |
| PG&E Corporation | | | | Yesþ No¨ |
| Pacific Gas and Electric Company | | | | Yesþ No¨ |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
| | | | |
| PG&E Corporation | | | | Yes¨ Noþ |
| Pacific Gas and Electric Company | | | | Yes¨ Noþ |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
| | | | |
| PG&E Corporation | | | | Yesþ No¨ |
| Pacific Gas and Electric Company | | | | Yesþ No¨ |
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
| | | | |
| PG&E Corporation | | | | Yes þ No ¨o |
| Pacific Gas and Electric Company | | | | Yes þ No ¨o |
| |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
registrant’sregistrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:
| | | | |
| PG&E Corporation | | | | þ |
| Pacific Gas and Electric Company | | | | þ |
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):
| | |
| PG&E Corporation | | Pacific Gas and Electric Company |
Large accelerated filerþ | | Large accelerated filer¨ |
Accelerated filer¨ | | Accelerated filer¨ |
Non-accelerated filer¨ | | Non-accelerated filerþ |
Smaller reporting company¨ | | Smaller reporting company¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
| | | | |
| PG&E Corporation | | | | Yes¨ Noþ |
| Pacific Gas and Electric Company | | | | Yes¨ Noþ |
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30,
2011,2012, the last business day of the most recently completed second fiscal quarter:
| | |
| PG&E Corporation common stock | | $16,876$19,276 million |
| Pacific Gas and Electric Company common stock | | Wholly owned by PG&E Corporation |
Common Stock outstanding as of February 7, 2012:
| Common Stock outstanding as of February 11, 2013: | | | | |
| PG&E Corporation: | | 412,899,635 shares | | 431,436,673 |
| Pacific Gas and Electric Company: | | 264,374,809 shares (wholly owned by PG&E Corporation) | | |
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
| | |
Designated portions of the combined 20112012 Annual Report to Shareholders | | Part I (Items 1, 1A and 1.A.)3), Part II (Items 5, 6, 7, 7A, 8 and 9A) |
| |
Designated portions of the Joint Proxy Statement relating to the 2012 2013 Annual Meetings of Shareholders | | Part III (Items 10, 11, 12, 13 and 14) |
| | | | | | |
| 1 Kilowatt (kW) | | | = | | | One thousand watts |
| 1 Kilowatt-Hour (kWh) | | | = | | | One kilowatt continuously for one hour |
| 1 Megawatt (MW) | | | = | | | One thousand kilowatts |
| 1 Megawatt-Hour (MWh) | | | = | | | One megawatt continuously for one hour |
| 1 Gigawatt (GW) | | | = | | | One million kilowatts |
| 1 Gigawatt-Hour (GWh) | | | = | | | One gigawatt continuously for one hour |
| 1 Kilovolt (kV) | | | = | | | One thousand volts |
| 1 MVA | | | = | | | One megavolt ampere |
| 1 Mcf | | | = | | | One thousand cubic feet |
| 1 MMcf | | | = | | | One million cubic feet |
| 1 Bcf | | | = | | | One billion cubic feet |
| 1 MDth | | | = | | | One thousand decatherms |
iii
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
4.34.4 million natural gas distribution customers at December 31,
2011.2012. The Utility had approximately
$49.2$52 billion in assets at December 31,
20112012 and generated revenues of
approximately $15 billion in
2011.2012. 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 94177,94177. PG&E Corporation’s telephone number is (415) 267-7000 and theirthe Utility’s 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’sCorporation's website,www.pgecorp.com, and the
Utility’sUtility'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,
20112012, which is attached to this report as Exhibit 13 (“
20112012 Annual Report”) and the Joint Proxy Statement relating to the
20122013 Annual Meetings of Shareholders.
The 2012 Annual Report contains forward-looking statements that are necessarily subject to various risks and uncertainties. For a discussion of 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 information in the 2012 Annual Report under the headings “Cautionary Language Regarding Forward-Looking Statements” and “Risk Factors” which appear under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”).
Operational Improvements
The Utility’s electricity and natural gas businesses are each led by a senior executive who reports to the President of the Utility. During 2012, the Utility continued to build these organizations by adding new leaders with extensive industry expertise and expanding the Utility’s work force where needed to implement the Utility’s enhanced focus on safety and operational excellence. Significant improvements were made to the Utility’s natural gas operations during 2012 to enhance safety, test and replace pipelines, modernize and upgrade the system, and search and validate records. Much of this work was carried out under the Utility’s pipeline safety enhancement plan that was approved by the CPUC in late December 2012. The Utility also continued work to implement the safety recommendations made by the National Transportation Safety Board (“NTSB”) in its 2011 investigative report on the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”). (For more information, see “Natural Gas Utility Operations” below.) The Utility also undertook significant projects in 2012 to improve and modernize its electricity operations by repairing, replacing or upgrading equipment to improve reliability and safety. In addition, the Utility continued the installation of advanced electric and gas meters throughout its service territory and took other steps to lay the foundation for the development of a “smart grid” to enable customers to have better control over their energy usage and costs, to integrate new
sources of energy (such as distributed generation and storage, rooftop solar and other intermittent energy sources), and to enable the continued safe and reliable operation of the grid. (For more information, see “Electric Utility Operations” below.)
At December 31, 2011,2012, PG&E Corporation and its subsidiaries had 19,27420,593 regular employees, including 19,25320,583 regular employees of the Utility. Of the Utility’s regular employees, 11,95012,492 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 expireexpires on December 31, 2011 but will remain in effect until2014 and the earlier of the date that IBEW members ratify a new agreement or December 31, 2012. The other IBEW collective bargaining agreement will expireexpires on December 31, 2015. The ESC collective bargaining agreement was scheduled to expireexpires 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.2014. The SEIU collective bargaining agreement expires on July 31, 2012.2013.
Various aspects 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 thatUtility's business 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 knowledgea complex set of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimatedenergy, 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:
the outcome of pending and future investigationslaws, regulations, and regulatory proceedings related toat the San Bruno accident,federal, state, and local levels. This section and the safety“Ratemaking Mechanisms” section below summarize some 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;
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);
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;
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;
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;
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;
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;
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;
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;
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 causedmore 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;
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;
• | | 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;
|
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;
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;
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;
the impact of environmental remediation laws, regulations, and orders;regulatory proceedings affecting 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 whichUtility. These summaries are not recoverable through insurance or rates;
an exhaustive description of all the loss of customers due to various forms of bypasslaws, regulations, 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
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 risksregulatory proceedings that could affect the outcome of these forward-looking statementsUtility. The energy laws, regulations, 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”regulatory proceedings may change or be implemented or applied in the 2011 Annual Report.a way that 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.
currently anticipate.
PG&E
Corporation’s Regulatory EnvironmentFederal Regulation
AsCorporation is a public utility holding company PG&E Corporationthat 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:
the Utility cannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;
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;
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
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:
prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility’s affiliates;
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;
| • | | 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;
|
require certain key officers to provide annual certifications of compliance with the affiliate rules;
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);
require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company; and
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 ofinformation under the headings within MD&A entitled “Regulatory Matters” and “Natural Gas Matters” in the 20112012 Annual Report.
Report, which information is incorporated herein by reference.
The
FERCFederal Energy Regulatory Commission
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$1 million 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’sUtility's electricity transmission annual amount of revenue (“revenue requirements”) and rates, the licensing of substantially all of the
Utility’sUtility'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. UnderThe FERC authority,also has authorized the WECC and the NERC and/or FERC mayto impose penalties up to $1,000,000$1 million per day, per violation.The FERC also has issuedadopted policies and rules on electric transmission pricing reforms designed to promote investment in energy infrastructure to reduceand lower costs for consumers through incentive ratemaking for 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.projects. In addition, pursuantthe FERC’s Order No. 1000 establishes electric transmission planning and cost allocation requirements for public utility transmission providers. Order No. 1000 requires public utility transmission providers to FERC orders,improve transmission planning processes and allocate costs for new transmission facilities to the beneficiaries of those facilities.
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
Utility’s 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 otherNRC matters affecting Diablo Canyon, including the status of the Utility’s relicensing application see the section ofinformation under the heading within MD&A in the 2011 Annual Report entitled “Regulatory Matters–Matters−Diablo Canyon Nuclear Power Plant.”
Plant” in the 2012 Annual Report, which information is incorporated herein by reference.
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’snation'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 National Transportation Safety Board
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, theThe NTSB
released its final investigative report oninvestigated the San Bruno
accident. (Seeaccident and in August 2011 announced that it had determined the
sectionprobable cause 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.accident placing the blame primarily on the Utility. The Secretary is authorized under specific circumstances, someNTSB report recommended that the Utility take certain actions to improve the safety of which require an evaluation and a Congressional review period, to adopt regulations to address pipeline integrity management requirements, leak detection systems,its gas transmission system. The status of 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 2000-2001NTSB’s recommendations is discussed under “Natural Gas Utility Operations” below.
State Regulation
The 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
Public Utilities Commission
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’sUtility's electricity and natural gas distribution operations, electricity generation, and natural gas transportation and storage services. The CPUC also has jurisdiction over the
Utility’sUtility's issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the
Utility’sUtility'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 state 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 has adopted many rules and regulations to
implement state laws and policies, such as the laws relating to the development of renewable energy resources, demand response and public purpose programs, and the reduction of greenhouse gas (“GHG”) emissions. The CPUC also has been delegated authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities. The CPUC has authority to impose penalties for violating these state and federal laws, orders, or regulations of up to $50,000 per violation, per day. (See the discussion under the heading within MD&A entitled “Natural Gas Matters” in the 2012 Annual Report for information about the CPUC’s pending enforcement proceedings against the Utility relating to the Utility’s safety recordkeeping for its natural gas transmission system; the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density; and the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct that could have led to or contributed to the San Bruno accident, which discussion is incorporated herein by reference.)
Ratemaking for retail sales from the Utility’sUtility's generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies. The CPUC has imposed conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates. These conditions relate to finance, human resources, records and bookkeeping, and the transfer of customer information. Among other conditions, the financial conditions provide that the capital requirements of the Utility, entered intoas determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a settlement agreement withprudent and efficient manner, must be given first priority by PG&E Corporation’s Board of Directors (known as the CPUC“first priority” condition). In addition, the Utility must maintain on December 19, 2003, to resolveaverage its CPUC-authorized utility capital structure, although it can request a waiver of this condition if an adverse financial event reduces the Utility’s proceeding filed under Chapter 11common 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
U.S. Bankruptcy Code that had been pending inutilities’ names and logos by their affiliates, the
U.S. Bankruptcy Courtseparation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates. The CPUC has established specific penalties and enforcement procedures 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 mattersaffiliate rules violations. Utilities are required 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.self-report affiliate rules violations.
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’sstate'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’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
2012.2013. In October 2011, the CARB adopted its final “cap-and-trade” regulations to help gradually reduce GHG emissions.
In November 2012, the CARB held the first auction of GHG emission allowances under this “cap-and-trade” program. (For more information, see “Environmental Matters — Air Quality and Climate Change” below.)
The Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility’sUtility'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’sUtility'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’sUtility's business and to conduct certain related operations.
Competition in the Electricity Industry
Federal. Many provisions of
At the
Energy Policy Act of 2005 (“EPAct”) support the development of competition in the wholesale electric market. The EPAct directedfederal level, the FERC
to developis charged with developing rules to encourage fair and efficient competitive
wholesale electric markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. (See
the section“Regulatory Environment−Federal Regulation” above
entitled “The Utility’s Regulatory Environment–Federal Energy Regulation” for a description of some of these rules.) The
EPActFERC also
gives the FERChas 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 electric 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,
the California
Assembly Bill 1890, enacted in 1996,Legislature mandated the restructuring of the California electricity industry beginning in 1998 to allow customers of the California investor-owned electric utilities to purchase
energyelectricity 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 aA market framework
was established 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
California Power Exchange (“PX”).
FollowingAs the 2000-2001 California energy crisis
theunfolded, direct access was suspended. 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 11bankruptcy proceeding that was precipitated by the energy crisis, see Note 13: Resolution of Remaining Chapter 11 Disputed Claims, of the Notes to the Consolidated Financial Statements in the 20112012 Annual Report.Report, which information is incorporated herein by reference.)
During the 2000-2001 energy crisis, the
Current California
Legislature authorized the California Department of Water Resources (“DWR”)law provides only limited opportunities for customers who receive “bundled” electricity service (i.e.,
beginning on February 1, 2001,electricity, transmission and distribution services) to choose 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 alternativefrom an energy service
providers.provider other than the three California investor-owned electric utilities. As authorized by California
Senate Bill 695,law enacted
onin 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
electric 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 adoptedUnder the CPUC’s rules,
to implement the CCA program, including the imposition of a surcharge
is imposed on retail end-users of the CCA to prevent a shifting of costs to customers
ofwho continue to receive electricity from a
utility who receive bundled services and allowing a CCA to start service in phases.utility. 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.
Over 90,000 customers in Marin County are now receiving commodity service from the Marin Energy Authority, 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 the combination of “distributed generation” and storage a viable, cost-effective alternative to the Utility’s bundled electric service. The CPUC also has been consideringIn addition, the rolelevels of electric vehicles in California’sself-generation of electricity infrastructure. In July 2010,by customers (primarily solar installations) and the CPUC found that althoughuse of customer net energy metering, which allows self-generating customers to receive bill credits at the California Legislature did not intend that the CPUC regulate providers of electric vehicle charging services as public utilities,full retail rate, are increasing.
Although the CPUC has
authorityestablished ratemaking mechanisms that allow the Utility to
regulate aspects ofcollect some non-bypassable or fixed charges from those who procure electricity from alternate sources, rates for the Utility’s remaining customers could increase as alternative energy providers (CCAs or local government agencies) and alternative energy sources (self-generation and storage, distributed generation, electric
vehicle charging services. These aspects include rules relatingvehicles) become more prevalent. Increasing rate pressure on remaining customers could, in turn, cause more customers to
seek alternative energy providers or sources, further exacerbating 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.Utility’s rate challenges.
Competition in the Natural Gas Industry
FERC Order 636, issued in 1992, required
Under the FERC’s rules, interstate natural gas pipeline companies
are required to divide their services into separate gas commodity sales, transportation, and storage
services. Under Order 636, interstate natural gas pipeline companiesservices and 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’sUtility'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-coreNon-core customers have access to capacity rights for firm service
on the Utility’s natural gas pipeline, as well as interruptible (or “as-available”) services. All services are offered on a nondiscriminatory basis to any creditworthy customer.
The Gas AccordThis 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 servicessystem has operated under the CPUC-approved “Gas Accord” market structure since 1998 which largely mimics the regulatory framework required by the FERC for a four-year period beginning January 1, 2011.interstate gas pipelines. (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’sUtility'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’sUtility'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.
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
natural 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
(mainlywhich are mainly residential, commercial, industrial, and
agricultural) and to various service components (mainly customer, demand, and energy).agricultural. 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
The Utility uses balancing accounts to
produce thekeep track of its authorized revenue requirements,
includingactual customer billings collected through rates, and actual costs incurred to provide electricity and natural gas services. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the
authorized return on rate base. The Utility may be unable to earn its authorized rate of return becauseCPUC. For more information regarding the
CPUC or the FERC excludes someUtility’s balancing accounts, see Note 3: Regulatory Assets, Liabilities and Balancing Accounts, of the
Utility’s actual costs fromNotes to the
revenue requirements or because the Utility’s actual costs are higher than those reflectedConsolidated Financial Statements in the
revenue requirements.2012 Annual Report, which information is incorporated herein by reference.
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
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
basicanticipated business and operational costs related to its electricity and natural gas distribution and electricity generation
operations.operations and to provide the Utility an opportunity to earn its authorized rate of return. 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’sUtility'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 In November 2012, the Utility may file a notice of intentfiled its 2014 GRC application with the CPUC that will include a draft offor rates effective from 2014 through 2016. For more information see the Utility’s GRC application forheading within MD&A entitled “2014 General Rate Case” in the period beginning January 1, 2014. The Utility plans to file its GRC application in December 2012.
Attrition Rate Adjustments
2012 Annual Report, which information is incorporated herein by reference.
| 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’sUtility'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, natural gas transmission, and electricity generation assets. The current authorized capital structure consistingthat was in effect through 2012 consisted of 52% equity, 46% long-term debt, and 2% preferred stock, will remain in effect through 2012.The CPUC has adopted astock. Since 2008, the Utility’s authorized cost of capital has been subject to an adjustment mechanism which uses an interest rate index (thethat is triggered in a particular year if the 12-month October through SeptemberOctober-through-September average of the Moody’sapplicable 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,benchmark. If the cost of equity foradjustment mechanism is triggered, the coming year willUtility’s authorized ROE beginning on the next January 1st would 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.
increase or decrease. This mechanism did not trigger a change in the Utility’s authorized rates of return for 2012.
In December 2012, which remain set at 6.05% for long-term debt, 5.68% for preferred stock, and 11.35% for common equity, resultingthe CPUC issued a decision in an overall rate of return on rate base of 8.79%.The Utility’s next fullthe cost of capital application must be filed by April 20, 2012, soproceeding that any resulting changes would become effectiveauthorizes the Utility to maintain a capital structure consisting of 52% equity, 47% long-term debt, and 1% preferred stock beginning on January 1, 2013.
Although (For more information see the FERC has authority to setsection of MD&A entitled “2013 Cost of Capital Proceeding” in the Utility’s rate of return for its electricity transmission operations, the rate of return2012 Annual Report, which information is often unspecified if the Utility’s transmission rates are determined through a negotiated rate settlement.
incorporated herein by reference.)
Rate Recovery of Costs of
New Electricity Generation Resources
California investor-owned electric
utility isutilities are required to use the principles of “least-cost dispatch” in managing electric generation resources to meet customer demand for electricity. The utilities are also responsible for procuring electricity
required to meet customer demand, plus applicable reserve margins,
that are not satisfied from
that utility’stheir own generation facilities and existing electricity
contracts (including DWR contracts allocated to the Utility’s customers).contracts. To accomplish this, each utility must submit a
long-termten-year 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
the forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation).
The CPUC approved the Utility’s electricity procurement plan in January 2012 covering 2011 through 2020 and approved the Utility’s GHG compliance instrument procurement plan in April 2012.
California
legislation, Assembly Bill 57,law allows
theelectric utilities to recover the costs incurred in compliance with their CPUC-approved
electricity procurement plans without further after-the-fact reasonableness review.
To the extent the Utility’s electricity purchases are not in compliance with the CPUC-approved plan, costs associated with those purchases may be disallowed. 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/billed and unbilled ERRA revenues and (2) electric procurement costs incurred under the
Utility’sUtility's authorized procurement plans. To determine
the 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.
On December 20, 2012, the CPUC approved the Utility’s forecast of 2013 procurement costs and associated revenue requirement. Changes in rates to reflect the approved revenue requirement became effective on January 1, 2013. (The CPUC may adjust a utility’s retail electricity rates at any time when the forecasted aggregate over-collections or under-collections in the ERRA exceed five percent of its prior year electricity procurement revenues.) The CPUC also performs an annual compliance review
of the procurement activities recorded in the ERRA to ensure that
(1) the
Utility’s procurement activities are prudent andUtility prudently administered the contracts that were entered into in
complianceaccordance with its CPUC-approved procurement
plans.In December 2011,plans, (2) utilized 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 planprinciples of least-cost dispatch 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 recovermanaging 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 fileelectric generation resources, and (3) prudently operated its 2011 ERRA compliance review on February 15, 2012.
own generation facilities.
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 meetthe renewable energy
mandate, 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
also recover any above-market costs through either (1)
the imposition of a non-bypassable
customer 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 aggregationCCA 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 ten
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 10ten 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 method, 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
also 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”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
2011 Annual Report.Utility’s GRC.
The Utility may recover any above-market costs associated with new utility-owned generation resources
through either (1)in a manner similar to the
impositionrecovery 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.above-market costs for non-renewable generation purchases described above. 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.
The
Utility’sUtility'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’sUtility'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’sUtility's transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the
Utility’sUtility'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.
See the information within MD&A entitled “FERC Transmission Owner Rate Case” in the 2012 Annual Report, which information is incorporated herein by reference.
The
Utility’sUtility's transmission owner tariff includes
twoseveral rate components. The primary component consists of base transmission rates intended to recover the
Utility’sUtility'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’sUtility's transmission revenue from base transmission rates.
The other Another component consists of rates intended tothat 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 byfacilities and charges related to the shortfall or surplus resulting from any cost differences between the amount that the Utility is entitledof providing service 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.
contracts. 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 amountscustomers, which are recovered from the Utility’s retail customers as part of retail transmission rates.
Natural Gas
Gas Safety Rulemaking Proceeding
The CPUC is conducting a rulemaking proceeding to adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms. As directed by the CPUC, in August 2011, the Utility filed its proposed pipeline safety enhancement plan to replace certain natural gas pipeline segments, install automatic or remote shut-off valves, and take other actions to modernize and upgrade its natural gas transmission system. On December 20, 2012, the CPUC approved the Utility’s proposed plan but disallowed the Utility’s request for rate recovery of a significant portion of plan-related costs that the Utility forecasted it would incur over the first phase of the plan (2011 through 2014). See the information under the heading within MD&A entitled “Natural Gas Matters−CPUC Gas Safety Rulemaking Proceeding” in the 2012 Annual Report, which information is incorporated herein by reference.
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 Utility expects to file an application to begin the
provisions containednext GT&S rate case in
the first Gas Accord that the CPUC approved in 1996. (See “Competition” above.September 2013.)
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.
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
natural gas 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’sUtility'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
Utility retains 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
20112012 Annual
Report)Report, which information is incorporated herein by reference).
Interstate and Canadian Natural Gas Transportation
The
Utility’sUtility has a number of agreements with interstate and Canadian
third-party transportation service providers 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
agreements with third-party service providerssystem begins. These 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’stransportation costs the Utility incurs under these agreements
with interstate and Canadian natural gas transportation service providers are
administeredrecovered through CPUC-approved rates 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. RockyMountains, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.costs or as electricity procurement costs. For more information, see the discussion below under “Natural Gas Utility Operations — Interstate and Canadian Natural Gas Transportation Services Agreements.”
Agreements” below.
During 2012, the CPUC opened a rulemaking proceedingUtility made significant capital investments in order to develop and adopt safety-related changes to its regulation of natural gaselectric transmission and distribution pipelines in California. The CPUC ordered each California natural gas transmission pipeline operatorinfrastructure to submit a plan that describesextend the operator’s plan to either pressure testlife of or replace those pipeline segmentsexisting infrastructure; to maintain and improve system reliability, safety, and customer service; to integrate more renewable energy resources; to increase capacity; and add new infrastructure to meet customer demand growth. The Utility improved the reliability of its system by adding emergency capacity at substations, increasing distribution system automation, upgrading poor performing circuits, performing targeted asset replacement, and improving service restoration processes. The Utility also has been working to accelerate pole replacement and maintenance of its overhead and underground electric facilities and to increase the use of wireless devices that have never been pressure tested or that lack sufficient detail relatedallow the Utility to monitor the performance of a test. On August 26, 2011,the electric system and respond more quickly to power disruptions.
The Utility also substantially completed the installation of an advanced metering infrastructure throughout its service territory in 2012. As of December 31, 2012, the Utility filed its proposed planhas installed approximately 8.9 million advanced electric and requestedgas meters. As permitted by CPUC rules, customers may choose not to have an advanced meter
installed. The new infrastructure uses SmartMeterTM technology that can measure energy use in hourly or quarter-hourly increments, allow customers to track energy usage throughout the CPUC approvebilling month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communications network and transmitted to the proposed scopeUtility’s information system where the data is stored and used for billing and other Utility business purposes.
The Utility’s advanced metering infrastructure supports the development of
a “smart grid” in California, part of a nationwide effort to improve and modernize the
worknation’s electric system by combining advanced communications and controls to
be done during the first phase (2011 through 2014)create a responsive and
authorizeresilient energy delivery network. In March 2012, the Utility
began incorporating the latest “smart grid” technology in parts of its service territory by installing automated switches that reduce outage duration and the number of customers affected by outages. When an electrical outage occurs, these switches detect a short circuit, block power flow to
recover estimated costs incurred after January 1, 2011. Thethe affected area, communicate with a central computer, and then quickly reroute power around the problem to keep as many customers powered as possible. Over the next several years, the Utility
expects that it will incur significant costsplans to
perform pipeline-related work within the proposed scope of the plan before the CPUC issues a decisionundertake various “smart grid” projects 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”invest in
the 2011 Annual Report.Electric Utility Operations
“smart grid” technologies.
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.Theway. The following table shows the percentage of the Utility’s total actual deliveries of electricity to customers in 20112012 represented by each major electricity resource. Total
20112012 Actual Electricity Delivered –
74,86476,205 GWh:
| | Percent of Bundled Retail Sales | |
| Owned Generation Facilities | | | | | | |
Nuclear | | | 23.3 | % | | | |
Small Hydroelectric | | | 1.2 | % | | | |
Large Hydroelectric | | | 9.7 | % | | | |
Fossil fuel-fired | | | 8.3 | % | | | |
Solar | | | 0.2 | % | | | |
Total | | | | | | | 42.7 | % |
| | | Percent of Bundled
Retail Sales | |
Owned generation
| | | | | | | | |
Nuclear
| | | 24.84% | | | | | |
Small Hydroelectric
Qualifying Facilities (1) | | | 1.67% | | | | | |
Large Hydroelectric
Renewable | | | 15.30%4.4 | % | | | | | |
Fossil fuel-fired
Non-Renewable | | | 6.83%9.8 | % | | | | | |
Solar
Total | | | 0.03% | | | | 14.2 | % |
Total
| | | | Irrigation Districts and Water Agencies | | | 48.67% | |
DWR
| | | | | | | | |
Natural Gas
| | | | | | | 3.57% | | |
Qualifying Facilities
| | | | | | | | |
Renewable
Small Hydroelectric | | | 5.32%0.3 | % | | | | | |
Non-Renewable
Large Hydroelectric | | | 13.36%3.5 | % | | | | | |
Total | | | | | | | 18.68% | |
Irrigation Districts
| | | | | | | | |
Small Hydroelectric
| | | 0.50% | 3.8 | % |
| Other Third-Party Purchase Agreements | | | | | |
Large Hydroelectric
| | | 5.74% | | |
Renewable | | | 12.9 | | |
Total
| | | | % | | | 6.24% | |
Bilateral
| | | | | | | | |
Renewable
Large Hydroelectric | | | 11.81%0.4 | % | | | | | |
Large Hydroelectric
Non-Renewable | | | 0.60%11.5 | % | | | | | |
Non-Renewable
Total | | | 8.48% | | | | 24.8 | % |
Total
| | | | Others, Net (2) | | | 20.89% | |
Others, Net(1)
| | | | | | | 1.95% | 14.5 | % |
| | | | | | | | |
Total | | | | | | | 100% | |
| | | | | | 100 | | % |
(1) | This amount is mainly comprised of net CAISO open market purchases, offset by transmission and distribution related system losses. |
(1) Electric utilities are required under federal law to purchase energy and capacity from independent power producers with generation facilities (20 MW or less) that meet the definition of a qualifying facility (“QF”) under the Public Utility Regulatory Policies Act of 1978. QFs primarily include co-generation facilities that produce combined heat and power and renewable generation facilities. For more information about the
power purchase agreements that the Utility has entered into with QFs, see “QF Power Purchase Agreements,” below.
(2) 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, 2011,2012, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below: | | | | | | | | | | | | |
| Generation Type | | | | County Location | | | | Number of Units | | | | Net Operating Capacity (MW) |
Nuclear: | | | | | | | | | | | | |
Diablo Canyon | | | | San Luis Obispo | | | | 2 | | | | 2,240 |
Hydroelectric: | | | | | | | | | | | | |
Conventional | | | | 16 counties in northern and central California | | | | 107 | | | | 2,684 |
Helms pumped storage(1) | | | | Fresno | | | | 3 | | | | 1,212 |
Hydroelectric subtotal: | | | | | | | | 110 | | | | 3,896 |
Fossil fuel-fired: | | | | | | | | | | | | |
Colusa Generating Station | | | | Colusa | | | | 1 | | | | 530 |
Gateway Generating Station | | | | Contra Costa | | | | 1 | | | | 530 |
Humboldt Bay Generating Station | | | | Humboldt | | | | 10 | | | | 163 |
CSU East Bay Fuel Cell | | | | Alameda | | | | 1 | | | | 1.4 |
SF State Fuel Cell | | | | San Francisco | | | | 2 | | | | 1.6 |
Fossil fuel-fired subtotal: | | | | | | | | 15 | | | | 1,226 |
Photovoltaic: | | | | | | | | | | | | |
Five Points Solar Station | | | | Fresno | | | | 1 | | | | 15 |
Stroud Solar Station | | | | Fresno | | | | 1 | | | | 20 |
Westside Solar Station | | | | Fresno | | | | 1 | | | | 15 |
Vaca Dixon Solar Station | | | | Solano | | | | 1 | | | | 2 |
Small Solar Stations | | | | San Francisco | | | | 3 | | | | 0.3 |
Photovoltaic subtotal | | | | | | | | 7 | | | | 52 |
Total | | | | | | | | 134 | | | | 7,414 |
| | | | | | | | |
(1) | See the discussion below about the status of outages of these units. |
| Generation Type | | County Location | | Number of Units | | Net Operating Capacity (MW) |
| Nuclear: | | | | | | |
Diablo Canyon | | San Luis Obispo | | | | |
| Hydroelectric: | | | | | | |
Conventional | | 16 counties in northern and central California | | 106 | | 2,683 |
Helms pumped storage | | Fresno | | | | |
Hydroelectric subtotal: | | | | | | |
| Fossil fuel-fired: | | | | | | |
Colusa Generating Station | | Colusa | | 1 | | 657 |
Gateway Generating Station | | Contra Costa | | 1 | | 580 |
Humboldt Bay Generating Station | | Humboldt | | 10 | | 163 |
CSU East Bay Fuel Cell | | Alameda | | 1 | | 1.4 |
SF State Fuel Cell | | San Francisco | | | | |
Fossil fuel-fired subtotal: | | | | | | |
| Photovoltaic: | | | | | | |
| Total | | | | | | |
| | | | | | | |
Diablo Canyon Power Plant. The
Utility’sUtility'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.2. For the twelve months period ended December 31,
2011,2012, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately
95%90%. 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-DiabloMatters−Diablo Canyon Nuclear Power Plant” in the
20112012 Annual
Report.Report, which information is incorporated herein by reference. 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 20112012 Annual Report.
Report, which information is incorporated herein by reference.
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
44.643.6 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.
| | | | | | | | | | | | |
| | | 2012 | | 2013 | | 2014 | | | | 2015 | | 2016 |
Unit 1 | | | | | | | | | | | | |
Refueling | | April | | - | | February | | | | September | | - |
Duration (days) | | 45 | | - | | 35 | | | | 35 | | - |
Startup | | June | | - | | March | | | | October | | - |
Unit 2 | | | | | | | | | | | | |
Refueling | | - | | February | | September | | | | - | | May |
Duration (days) | | - | | 45 | | 35 | | | | - | | 30 |
Startup | | - | | March | | October | | | | - | | May |
| | | | | 2013 | | 2014 | | 2015 | | 2016 | 2017 |
| Unit 1 | | | | | | | | | | | |
| Refueling | | | | - | | February | | September | | - | April |
| Duration (days) | | | | - | | 40 | | 40 | | - | 30 |
| Startup | | | | - | | March | | November | | - | May |
| Unit 2 | | | | | | | | | | | |
| Refueling | | | | February | | September | | - | | May | - |
| Duration (days) | | | | 52 | | 40 | | - | | 35 | - |
| Startup | | | | March | | November | | - | | June | - |
Hydroelectric Generation Facilities.The Utility’s hydroelectric system consists of
110109 generating units at 68 powerhouses, including the Helms pumped storage
facility, with a total generating capacity of 3,896 MW.facility. 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.units. 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 necessaryThe Utility completed inspections and repairs are made. The Utility inspected Unit 2 during a planned outageon each of the three units and returned them to service 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
1,0721,137 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
1,0721,137 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately
3,0033,002 MW of hydroelectric power will expire between 2013 and 2047.
ConventionalFossil Fuel-fired Generation Facilities.The Utility’s
conventionalnatural gas-fired 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.station. 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.InArea. On December 2010,20, 2012, the CPUC approved aan amended purchase and sale agreement between the Utility and Contra Costa Generating Station LLCa third-party developer that provides for the development and construction of the Oakley Generation Facility, a 586-MW586-megawatt natural gas-fired combined-cycle generation facility proposed to be located in Oakley, California. For more information aboutCalifornia that would be acquired by the status of this proposed facility, see the section of MD&A entitled “Capital Expenditures” in the 2011 Annual Report.
Utility no sooner than January 1, 2016.
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
to be owned and
to enteroperated by the Utility, along with entering into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties.
During 2011,Under the PV program, Utility-owned PV facilities with an aggregate
capacity of
100 MW are operational, and an additional 50 MW
became operational. Theseare under construction and expected to become operational in 2013. The operational PV facilities include, the Five Points
Solar Station,solar station (15 MW), the Westside solar station (15 MW), the Stroud
Solar Station,solar station (20 MW), the Huron solar station (20 MW), the Cantua solar station (20 MW), and the
Westside Solar Station, eachGiffen solar station (10 MW). All of
which isthese facilities are located in Fresno County.
Three otherThe PV facilities
with an aggregate capacity of 50 MWunder construction are
currently under construction. Theythe Gates solar station (20 MW), the West Gates solar station (10 MW) and the Guernsey solar station (20 MW). The Gates and West Gates solar stations are
estimated to become operational by October 2012.DWR Power Purchases
During 2011, electricity fromlocated in Fresno County; the DWR contracts allocated toGuernsey solar station is located in Kings County.
In December 2012, the Utility
provided approximately 3.57%sought CPUC approval to terminate the PV program early. If approved, the Utility will not pursue the development of the
electricity deliveredremaining 100 MW of Utility-owned PV facilities over the remaining two years of the program, but instead will procure this capacity through the CPUC’s Renewable Auction Mechanism (“RAM”) process. Additionally, the Utility proposed to
solicit the
Utility’s customers. The DWR purchasedremaining 152 MW of capacity to be provided under power purchase agreements through 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 thatRAM process rather than through 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.PV program.
Generation Resources from Third Parties
Third-Party Power Purchase AgreementsQF Power Purchase Agreements.Under the Public Utility Regulatory Policies Act (“PURPA”) of 1978 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”). In June 2011, the FERC approved the California investor-owned utilities’ joint application to terminate their obligation under PURPA to purchase QF energy and capacity from facilities exceeding 20 MW. QFs primarily include co-generation facilities that produce combined heat and power and renewable generation facilities. As of December 31, 2011,2012, the Utility had power purchase agreements with 217180 operating QFs for approximately 3,4003,000 MW of capacity that are in operation. Approximately 2,200 MWcapacity. The majority of this capacity is from cogeneration projectsfacilities and 1,200 MWthe remainder is from renewable generation resources, as discussed below.facilities. Agreements for approximately 3,1002,700 MW expire at various dates between 20122013 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 20112012 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 thatpower. These agreements require the Utility to make semi-annual fixed minimum
payments. In addition, these agreements require the Utility to makepayments as well as 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
20122013 and
2031. In 2011, they accounted for 6.24% of the Utility’s electricity deliveries.2030. Bilateral Contracts.Other Third-Party Power Purchase Agreements. 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,agreements, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the
20112012 Annual
Report.Report, which information is incorporated herein by reference.
Renewable Generation Resources
Renewable generation resources include bioenergy such as biogas and biomass, small hydroelectric, wind, solar, and geothermal energy. In April 2011,California’s Renewables Portfolio Standard (“RPS”) program gradually increases the California Governor signed legislationamount of renewable energy that establishes a new RPS that requires load-serving entities, such as the Utility, must deliver to increase the amounttheir customers from an average of renewable energy they procure from at least 20% of their total retail sales as required byin the prior RPS law,years 2011-2013 to 33% of their total retail sales. The RPS law establishes three initial compliance periods: 2011-2013, 2014-2016,sales in 2021 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 sufficientthereafter. For more 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 toregarding the new RPS requirements.
Additionally,program, see the CEC, which continues to have responsibility for certifying the eligibilitysection 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 regulationsMD&A entitled “Environmental Matters – Renewable Energy Resources” in the second quarter of 2012.
The costs incurred2012 Annual Report, which information is incorporated herein 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. Mostreference.
During 2012, most renewable energy deliveries resulted from third party
contracts, mainly QFpower purchase agreements and
bilateral contracts.QF agreements. Additional renewable resources included the Utility’s small hydroelectric and solar facilities and certain irrigation district contracts (small hydroelectric facilities). (Under California law only
small hydroelectric generation resources
with a capacity of 30(30 MW or
lessless) 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 MWthe 30-MW threshold and do not qualify as RPS-eligible resources.)
Total 20112012 renewable deliveries are stated in the table below. | | | | |
Type | | GWh | | % of Bundled
Load |
Biopower | | 3,319 | | 4.4% |
Geothermal | | 3,781 | | 5.0% |
Wind | | 4,428 | | 5.9% |
Small Hydroelectric | | 2,733 | | 3.7% |
Solar | | 210 | | 0.3% |
| | | | |
Total | | 14,471 | | 19.3% |
| | | | |
| | | |
| Biopower | 3,373 | | 4.4% |
| Geothermal | 3,803 | | 5.0% |
| Wind | 4,338 | | 5.7% |
| Small Hydroelectric | 1,812 | | 2.4% |
| Solar | | | |
Total | | | |
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
20112012 Annual
Report.Report, which information is incorporated herein by reference.
At December 31,
2011,2012, the Utility owned approximately
18,61818,100 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60
kV andkV. The Utility also operated 91 electric transmission substations with a capacity of approximately
59,74360,800 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
UtilityUtility’s electric transmission system is interconnected with electric power systems in the WECC, which includes
14many 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 aits own 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
followingby the
EPAct,FERC, 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.”Regulation” above.
During 2012, the Utility upgraded several critical substations and re-conductored some transmission lines to improve maintenance and operating flexibility, reliability and safety, including the installation or replacement of 9 transmission substation banks. The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system and increase capacity 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 generateimprove system reliability.
Electricity Distribution
The Utility's 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, 58 transmission-switching 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 towith the Utility’s electricity transmission system primarily at approximately 1,758 points. This interconnection between the Utility’s distribution networktransmission switching substations 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
In 2012, the Utility replaced more than 130,000 feet of
the Utility’s electric transmissionunderground cable, primarily in San Francisco and
Oakland, replaced 98,000 feet of overhead wire, and installed or replaced 39 distribution
infrastructure was placed into service in the 1940’s through the 1960’s as California’s populationsubstation transformer banks to improve reliability and
economy grew.provide capacity to accommodate growing demand. The Utility
makes capital investments in its electric transmissionplans to continue performing work to improve the reliability 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 SmartMeterTMprogram. For information about these matters, see the section of MD&A entitled “Regulatory Matters – Deployment of SmartMeterTM Technology” in the 2011 Annual Report.
2011 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 distribution operations in 2013.
Electricity
Delivered: 83,688 GWh | | | | |
Residential Customers
| | | 37% | |
Commercial Customers
| | | 39% | |
Industrial Customers
| | | 17% | |
Agricultural and Other Customers
| | | 7% | |
| | | | |
Total
| | | 100% | |
| | | | |
Electricity Distribution Operating Statistics
The following table shows certain of the Utility’s operating statistics from
20072008 to
20112012 for electricity sold or delivered, including the classification of
sales and revenues by type of service.
| | | | | | | | | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
Customers (average for the year): | | | | | | | | | | | | | | | | | | | | |
Residential | | | 4,540,315 | | | | 4,509,620 | | | | 4,492,359 | | | | 4,488,884 | | | | 4,464,483 | |
Commercial | | | 530,914 | | | | 529,318 | | | | 528,786 | | | | 527,045 | | | | 521,732 | |
Industrial | | | 1,261 | | | | 1,254 | | | | 1,285 | | | | 1,265 | | | | 1,261 | |
Agricultural | | | 83,823 | | | | 83,787 | | | | 83,581 | | | | 81,757 | | | | 80,366 | |
Public street and highway lighting | | | 32,323 | | | | 31,743 | | | | 31,227 | | | | 30,474 | | | | 29,643 | |
Other electric utilities | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 2 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 5,188,638 | | | | 5,155,724 | | | | 5,137,240 | | | | 5,129,427 | | | | 5,097,487 | |
| | | | | | | | | | | | | | | | | | | | |
Deliveries (in GWh):(1) | | | | | | | | | | | | | | | | | | | | |
Residential | | | 30,871 | | | | 30,744 | | | | 31,234 | | | | 31,454 | | | | 30,796 | |
Commercial | | | 32,842 | | | | 32,863 | | | | 32,958 | | | | 34,053 | | | | 33,986 | |
Industrial | | | 14,498 | | | | 14,415 | | | | 14,806 | | | | 16,148 | | | | 15,159 | |
Agricultural | | | 4,692 | | | | 5,071 | | | | 5,804 | | | | 5,594 | | | | 5,402 | |
Public street and highway lighting | | | 781 | | | | 815 | | | | 826 | | | | 877 | | | | 833 | |
Other electric utilities | | | 4 | | | | - | | | | 1 | | | | 1 | | | | 3 | |
| | | | | | | | | | | | | | | | | | | | |
Subtotal | | | 83,688 | | | | 83,908 | | | | 85,629 | | | | 88,127 | | | | 86,179 | |
| | | | | | | | | | | | | | | | | | | | |
California Department of Water Resources (DWR) | | | (2,433) | | | | (4,274) | | | | (13,244) | | | | (13,344) | | | | (21,193) | |
| | | | | | | | | | | | | | | | | | | | |
Total non-DWR electricity | | | 81,255 | | | | 79,634 | | | | 72,385 | | | | 74,783 | | | | 64,986 | |
| | | | | | | | | | | | | | | | | | | | |
Revenues (in millions): | | | | | | | | | | | | | | | | | | | | |
Residential | | | $ 4,778 | | | | $ 4,795 | | | | $ 4,759 | | | | $ 4,656 | | | | $ 4,580 | |
Commercial | | | 4,732 | | | | 4,823 | | | | 4,538 | | | | 4,413 | | | | 4,484 | |
Industrial | | | 1,379 | | | | 1,424 | | | | 1,392 | | | | 1,400 | | | | 1,252 | |
Agricultural | | | 692 | | | | 736 | | | | 770 | | | | 727 | | | | 664 | |
Public street and highway lighting | | | 77 | | | | 79 | | | | 74 | | | | 75 | | | | 78 | |
Other electric utilities | | | 64 | | | | 60 | | | | 66 | | | | 126 | | | | 85 | |
| | | | | | | | | | | | | | | | | | | | |
Subtotal | | | 11,722 | | | | 11,917 | | | | 11,599 | | | | 11,397 | | | | 11,143 | |
| | | | | | | | | | | | | | | | | | | | |
DWR | | | - | | | | (1,383) | | | | (1,987) | | | | (1,325) | | | | (2,229) | |
Miscellaneous | | | 30 | | | | 145 | | | | 221 | | | | 336 | | | | 215 | |
Regulatory balancing accounts | | | (151) | | | | (35) | | | | 424 | | | | 330 | | | | 352 | |
| | | | | | | | | | | | | | | | | | | | |
Total electricity operating revenues | | | $ 11,601 | | | | $ 10,644 | | | | $ 10,257 | | | | $ 10,738 | | | | $ 9,481 | |
| | | | | | | | | | | | | | | | | | | | |
Other Data: | | | | | | | | | | | | | | | | | | | | |
Average annual residential usage (kWh) | | | 6,799 | | | | 6,843 | | | | 6,953 | | | | 7,007 | | | | 6,898 | |
Average billed revenues (cents per kWh): | | | | | | | | | | | | | | | | | | | | |
Residential | | | $ 15.48 | | | | $ 15.60 | | | | $ 15.24 | | | | $ 14.80 | | | | $ 14.87 | |
Commercial | | | 14.41 | | | | 14.68 | | | | 13.77 | | | | 12.96 | | | | 13.19 | |
Industrial | | | 9.51 | | | | 9.88 | | | | 9.40 | | | | 8.67 | | | | 8.26 | |
Agricultural | | | 14.75 | | | | 14.51 | | | | 13.27 | | | | 13.00 | | | | 12.29 | |
Net plant investment per customer | | | $ 5,045 | | | | $ 4,728 | | | | $ 4,336 | | | | $ 3,994 | | | | $ 3,418 | |
| (1) | These amounts include electricity provided to direct access customers who procure their own supplies of electricity.
|
| | 2012 | | 2011 | | 2010 | | 2009 | | 2008 |
| Customers (average for the year) | 5,214,170 | | 5,188,638 | | 5,155,724 | | 5,137,240 | | 5,129,427 |
Deliveries (in GWh) (1) | 86,113 | | 81,255 | | 79,634 | | 72,385 | | 74,783 |
| Revenues (in millions): | | | | | | | | | |
| Residential | $ 4,953 | | $ 4,778 | | $ 4,795 | | $ 4,759 | | $ 4,656 |
| Commercial | 4,735 | | 4,732 | | 4,823 | | 4,538 | | 4,413 |
| Industrial | 1,408 | | 1,379 | | 1,424 | | 1,392 | | 1,400 |
| Agricultural | 901 | | 692 | | 736 | | 770 | | 727 |
| Public street and highway lighting | 79 | | 77 | | 79 | | 74 | | 75 |
| Other | | | | | | | | | |
| Subtotal | | | | | | | | | |
Regulatory balancing accounts | | | | | | | | | |
Total electricity operating revenues | | | | | | | | | |
| Other Data: | | | | | | | | | |
| Average annual residential usage (kWh) | 5,961 | | 6,799 | | 6,843 | | 6,953 | | 7,007 |
| Average billed revenues (per kWh): | | | | | | | | |
| Residential | $ 0.1594 | | $ 0.1548 | | $ 0.1560 | | $ 0.1524 | | $ 0.1480 |
| Commercial | 0.1449 | | 0.1441 | | 0.1468 | | 0.1377 | | 0.1296 |
| Industrial | 0.917 | | 0.951 | | 0.988 | | 0.940 | | 0.867 |
| Agricultural | 0.1458 | | 0.1475 | | 0.1451 | | 0.1327 | | 0.1300 |
| Net plant investment per customer | $ 4,919 | | $ 5,045 | | $ 4,728 | | $ 4,336 | | $ 3,994 |
(1) These amounts include electricity provided to direct access customers who procure their own supplies of electricity.
Natural Gas Utility Operations During 2012, the Utility has taken many immediate and longer-term steps to improve the safety and reliability of its natural gas transmission system, including performing extensive pipeline testing and monitoring, and replacing and upgrading equipment. Much of this work is part of the Utility’s pipeline safety enhancement plan (“PSEP”), approved by the CPUC in December 2012, to meet the new, industry-wide safety standards for gas transmission systems. (See the information within MD&A under the heading “Natural Gas Matters” in the 2012 Annual Report, which information is incorporated herein by reference.)
In 2012, as part of the PSEP pipeline modernization program, the Utility confirmed the strength of 202 miles of transmission pipeline through hydrostatic pressure tests or records verification, installed 46 automated or remote-controlled valves, replaced 40 miles of transmission pipeline, and retrofitted 78 miles of transmission pipeline to accommodate in-line inspection tools. Since work on the program began in 2011, the Utility has also collected and digitized more than 3.5 million pipeline records, which includes validating the Maximum Allowable Operating Pressure (“MAOP”) for more than 89 percent of its gas transmission system (and 100 percent of the 2,088 miles of the Utility’s transmission pipelines in populated areas).
The Utility is also improving operations by utilizing modern tools and technologies. In 2012, the Utility began demonstrating a new car-mounted natural gas leak detection device, which is much more sensitive than traditional instruments. The Utility also began using an advanced hand-held leak-detection instrument that uses infrared technology to pinpoint methane gas without false alarms from other gases. This technology can detect and grade leaks at the same time. In addition, the Utility improved its supervisory controls and data acquisition system (“SCADA”) to better detect pipeline leaks and breaks and improved its integrity management program, including incorporating new analysis tools to identify and assess risks to pipeline integrity.
For the distribution system, the Utility has implemented a new distribution integrity management program designed to enhance operations and improve the overall safety of the gas distribution system. In 2012, the Utility replaced 23 miles of Aldyl-A plastic pipeline and identified another 150 miles to be replaced over the next two years. It also updated the geographic information system with information on more than 5,500 miles of Aldyl-A pipeline, including additional pipeline and service attribute information. The Utility also completed additional distribution leak surveys in 2012, in addition to complying with regular distribution leak survey requirements.
Many of these improvement efforts satisfy recommendations made to the Utility by the NTSB and the CPUC in 2010 and 2011. In the first half of 2012, the Utility was able to officially close out four of the twelve NTSB recommendations. In January 2013, the Utility requested closure on three more recommendations. The Utility continues to make significant progress on the remaining longer-term recommendations, and the NTSB stated in September 2012 that the Utility’s progress was acceptable.
In December 2012, the CPUC accepted the gas safety plans submitted by each gas corporation in California, including the Utility, to describe each gas corporation’s programs, plans, and initiatives, to increase the safety and reliability of their natural gas operations. The plans were submitted in compliance with California Senate Bill 705, enacted in October 2011, which requires each gas corporation subject to CPUC jurisdiction to develop and implement a plan for the safe and reliable operation of its gas pipeline system. The new law required the CPUC to review the plans and accept, modify, or reject each plan by December 31, 2012. The CPUC has ordered the Utility, as well as the other gas corporations, to submit modifications to their plans by June 2013 and to continually review, revise and update their plans as required by emerging issues, industry practices, and state and federal regulators.
Natural Gas System Assets
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,At December 31, 2012, the Utility’s natural gas system consisted of approximately 42,400 miles of distribution pipelines, approximately 6,400 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations which receive, store and move natural gas through the Utility’s pipelines. (The Utility has incurred significant environmental liabilities related to some of its compressor stations. See “Environmental Matters” below.) 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 interconnects with pipeline systems located in the U.S. Southwest and the Rocky Mountains that are owned by third parties (Transwestern Pipeline Company, El Paso Natural Gas Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline Company). Line 300 has a receipt capacity of approximately 1.1 Bcf per day. The Utility’s Line 400/401 interconnects at the California-Oregon border with the pipeline systems owned by Gas Transmission Northwest Corporation (“GTN”) and Ruby Pipeline, LLC. This line has a receipt capacity at the border of approximately 2.2 Bcf per day. Through interconnections with other interstate pipelines, the Utility
served approximately 4 millioncan receive natural gas
distribution customers.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 and operates three underground natural gas storage fields connected to the Utility’s transmission and storage system and has a 25% interest in the new Gill Ranch Storage Field. These storage fields and the Utility’s Gill Ranch share have a combined firm capacity of approximately 48.7 Bcf. In addition, three independent storage operators are interconnected to the Utility's northern California transportation system.
Natural Gas Services
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 2011,2012, core customers represented more than 99% of the Utility’s total natural gas customers and 41%36% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 59%64% of its on-systemtotal natural gas deliveries. In addition to deliveries discussed above, the Utility delivers gas to off-system customers (i.e.(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%96% of core customers, representing over 15%83% of the annual core market demand, receive bundled natural gas service from the Utility. The Utility does not provide procurement service to
large non-core customers such as electricity generators, QF
cogenerators,co-generators, enhanced oil recovery customers, refiners, and other large non-core customers. However, some
smaller non-core customers are
eligiblepermitted to elect to receive core service, including procurement service,
from the Utility if
such customers contractthey agree to receive
coresuch service for
at leasta minimum of five years.
These restrictions were put in place because large increases in demand for the Utility’s procurementCore service
caused by significant transfers ofto non-core customers
is subject to
core service would raise prices for all otherthese restrictions to protect core procurement customers
and obligatefrom price increases that could otherwise result if the Utility
incurred costs to reinforce its pipeline system
and take other measures to provide core service reliability on a short-term basis to serve
this new
load.load from non-core customers.
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’sUtility'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,
energy efficiency measures, or changes in their consumption levels. The Utility’s results of operations can
however, be affected,
however, 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 recoveredthe remainder 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
| | | | |
Residential Customers
| | | 30 | % |
Transport-only Customers (non-core)
| | | 57 | % |
Commercial Customers
| | | 13 | % |
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.
| | | | | | | | | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
Customers (average for the year): | | | | | | | | | | | | | | | | | | | | |
Residential | | | 4,100,712 | | | | 4,070,420 | | | | 4,046,364 | | | | 4,043,616 | | | | 4,030,499 | |
Commercial | | | 225,769 | | | | 224,400 | | | | 223,709 | | | | 224,617 | | | | 223,330 | |
Industrial | | | 920 | | | | 915 | | | | 928 | | | | 926 | | | | 958 | |
Other gas utilities | | | 6 | | | | 6 | | | | 6 | | | | 6 | | | | 6 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 4,327,407 | | | | 4,295,741 | | | | 4,271,007 | | | | 4,269,165 | | | | 4,254,793 | |
| | | | | | | | | | | | | | | | | | | | |
Gas supply (MMcf): | | | | | | | | | | | | | | | | | | | | |
Purchased from suppliers in: | | | | | | | | | | | | | | | | | �� | | | |
Canada | | | 197,151 | | | | 206,800 | | | | 190,485 | | | | 189,608 | | | | 199,870 | |
California(1) | | | (23,988) | | | | (32,910) | | | | (41,714) | | | | (53,126) | | | | (23,065) | |
Other states | | | 105,994 | | | | 96,338 | | | | 115,543 | | | | 123,833 | | | | 101,271 | |
| | | | | | | | | | | | | | | | | | | | |
Total purchased | | | 279,157 | | | | 270,228 | | | | 264,314 | | | | 260,315 | | | | 278,076 | |
Net (to storage) from storage | | | (709) | | | | (314) | | | | 876 | | | | 560 | | | | (1,120) | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 278,448 | | | | 269,914 | | | | 265,190 | | | | 260,875 | | | | 276,956 | |
Utility use, losses, etc.(2) | | | (25,109) | | | | (20,798) | | | | (12,423) | | | | 1,758 | | | | (12,760) | |
| | | | | | | | | | | | | | | | | | | | |
Net gas for sales | | | 253,339 | | | | 249,116 | | | | 252,767 | | | | 262,633 | | | | 264,196 | |
| | | | | | | | | | | | | | | | | | | | |
Bundled gas sales (MMcf): | | | | | | | | | | | | | | | | | | | | |
Residential | | | 201,109 | | | | 195,195 | | | | 195,217 | | | | 198,699 | | | | 196,903 | |
Commercial | | | 52,230 | | | | 53,921 | | | | 57,550 | | | | 63,934 | | | | 67,293 | |
Industrial | | | — | | | | — | | | | — | | | | — | | | | — | |
Other gas utilities | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 253,339 | | | | 249,116 | | | | 252,767 | | | | 262,633 | | | | 264,196 | |
| | | | | | | | | | | | | | | | | | | | |
Transportation only (MMcf): | | | 516,181 | | | | 564,516 | | | | 568,715 | | | | 569,535 | | | | 605,259 | |
Revenues (in millions): | | | | | | | | | | | | | | | | | | | | |
Bundled gas sales: | | | | | | | | | | | | | | | | | | | | |
Residential | | | $2,089 | | | | $1,991 | | | | $1,953 | | | | $2,574 | | | | $2,378 | |
Commercial | | | 464 | | | | 474 | | | | 496 | | | | 792 | | | | 766 | |
Industrial | | | — | | | | — | | | | — | | | | — | | | | — | |
Other gas utilities | | | 1 | | | | — | | | | — | | | | — | | | | — | |
Miscellaneous | | | 101 | | | | 49 | | | | 55 | | | | (30) | | | | 87 | |
Regulatory balancing accounts | | | 295 | | | | 305 | | | | 289 | | | | 221 | | | | 186 | |
| | | | | | | | | | | | | | | | | | | | |
Bundled gas revenues | | | 2,950 | | | | 2,819 | | | | 2,793 | | | | 3,557 | | | | 3,417 | |
Transportation service only revenue | | | 400 | | | | 377 | | | | 349 | | | | 333 | | | | 340 | |
| | | | | | | | | | | | | | | | | | | | |
Operating revenues | | | $3,350 | | | | $3,196 | | | | $3,142 | | | | $3,890 | | | | $3,757 | |
| | | | | | | | | | | | | | | | | | | | |
Selected Statistics: | | | | | | | | | | | | | | | | | | | | |
Average annual residential usage (Mcf) | | | 49 | | | | 48 | | | | 48 | | | | 49 | | | | 49 | |
Average billed bundled gas sales revenues per Mcf: | | | | | | | | | | | | | | | | | | | | |
Residential | | | $10.39 | | | | $10.20 | | | | $10.00 | | | | $12.95 | | | | $12.07 | |
Commercial | | | 8.89 | | | | 8.79 | | | | 8.62 | | | | 12.38 | | | | 11.38 | |
Industrial | | | — | | | | — | | | | — | | | | — | | | | — | |
Average billed transportation only revenue per Mcf | | | 0.77 | | | | 0.67 | | | | 0.61 | | | | 0.59 | | | | 0.56 | |
Net plant investment per customer | | | $1,721 | | | | $1,637 | | | | $1,557 | | | | $1,344 | | | | $1,375 | |
(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. |
The Utility purchases natural gas to serve the Utility’sits 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 2011,2012, the Utility purchased approximately 279,157247,792 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%10% 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2011 | | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
| | | MMcf | | | Avg.
Price | | | MMcf | | | Avg.
Price | | | MMcf | | | Avg.
Price | | | MMcf | | | Avg.
Price | | | MMcf | | | Avg.
Price | |
Canada | | | 197,151 | | | $ | 3.75 | | | | 206,800 | | | $ | 4.03 | | | | 190,485 | | | $ | 3.74 | | | | 189,608 | | | $ | 8.29 | | | | 199,870 | | | $ | 6.63 | |
California(1) | | | (23,988 | ) | | $ | 4.45 | | | | (32,910 | ) | | $ | 4.63 | | | | (41,714 | ) | | $ | 4.16 | | | | (53,126 | ) | | $ | 9.24 | | | | (23,065 | ) | | $ | 6.77 | |
Other states (substantially all U.S. southwest) | | | 105,994 | | | $ | 3.74 | | | | 96,338 | | | $ | 4.34 | | | | 115,543 | | | $ | 3.50 | | | | 123,833 | | | $ | 7.05 | | | | 101,271 | | | $ | 6.30 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total/weighted average | | | 279,157 | | | $ | 3.69 | | | | 270,228 | | | $ | 4.07 | | | | 264,314 | | | $ | 3.57 | | | | 260,315 | | | $ | 7.51 | | | | 278,076 | | | $ | 6.50 | |
(1) California purchases include supplies transported into California by others.2012.
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’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 In addition, the gas transported on the Utility’s system came from the U.S. Rocky Mountains. The Utility has firm transportation agreements with Ruby Pipeline, LLC 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 hasborder, and 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’sUtility's natural gas transportation system in the area of California near Topock, Arizona.
Natural Gas Deliveries
The total volume of natural gas delivered to on-system customers during 2012 was approximately 945 MMDth. The following table shows certain information aboutthe percentage of the Utility’s firmtotal 2012 natural gas transportation agreements in effect at the enddeliveries represented by each of 2011 to support the Utility’s needsmajor customer classes.
| Residential Customers | 20% |
| Transport-only Customers (non-core) | 75% |
| Commercial Customers | 5% |
The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for itsnatural 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 2012 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 2010 through 2030. The natural gas requirements forecast is subject to many uncertainties, and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.
Natural Gas Operating Statistics
The following table shows the Utility's operating statistics from 2008 through 2012 (excluding subsidiaries) for natural gas, including the contract quantities, contract durations, and associated demand charges, netclassification of salesrevenues by type 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. | | | | | | |
| Pipeline | | Expiration Date | | Quantity MDth per day | | Demand Charges for the Year Ended December 31, 2011 (In millions) |
| | | |
TransCanada NOVA Gas Transmission, Ltd.(1) | | Various | | 370 | | $39.1 |
TransCanada Foothills Pipe Lines Ltd., B.C. System(2) | | 10/31/2013 | | 366 | | 19.0 |
TransCanada Gas Transmission Northwest LLC(3) | | Various | | 360 | | 68.1 |
Transwestern Pipeline Company(4) | | Various | | 193 | | 17.3 |
El Paso Natural Gas Company(5) | | Various | | 202 | | 23.3 |
Ruby Pipeline, LLC(6) | | 10/31/2026 | | 250 | | 10.9 |
(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. |
service.
| | | | | | | | | | | |
| Customers (average for the year) | 4,353,278 | | 4,327,407 | | 4,295,741 | | 4,271,007 | | 4,269,165 | |
| Gas purchased (MMcf) | 247,792 | | 279,157 | | 270,228 | | 264,314 | | 260,315 | |
| Average price of natural gas purchased | $ 2.45 | | $ 3.69 | | $ 4.07 | | $ 3.57 | | $ 7.51 | |
| Bundled gas sales (MMcf): | | | | | | | | | | |
Residential | 185,376 | | 201,109 | | 195,195 | | 195,217 | | 198,699 | |
Commercial | 47,341 | | 52,230 | | 53,921 | | 57,550 | | 63,934 | |
| Total | | | | | | | | | | |
| Revenues (in millions): | | | | | | | | | | |
| Bundled gas sales: | | | | | | | | | | |
Residential | $ 1,852 | | $ 2,089 | | $ 1,991 | | $ 1,953 | | $ 2,574 | |
Commercial | 383 | | 464 | | 474 | | 496 | | 792 | |
Regulatory balancing accounts | 221 | | 295 | | 305 | | 289 | | 221 | |
Other | 66 | | 102 | | 49 | | 55 | | | |
| Bundled gas revenues | | | | | | | | | 3,557 | |
| Transportation service only revenue | 499 | | 400 | | 377 | | 349 | | 333 | |
| Operating revenues | | | | | | | | | | |
| Selected Statistics: | | | | | | | | | | |
| Average annual residential usage (Mcf) | 45 | | 49 | | 48 | | 48 | | 49 | |
| Average billed bundled gas sales revenues per Mcf: | | | | | | | | | | |
Residential | $ 9.99 | | $ 10.39 | | $ 10.20 | | $ 10.00 | | $ 12.95 | |
Commercial | 8.09 | | 8.89 | | 8.79 | | 8.62 | | 12.38 | |
| Net plant investment per customer | $ 1,696 | | $ 1,721 | | $ 1,637 | | $ 1,557 | | $ 1,344 | |
Public Purpose and Customer Programs California law
requireshas historically required 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
aan electric 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
electric rates the amounts that were previously funded through the public goods charge for energy efficiency
renewables,and established an energy program investment charge to support ongoing energy efficiency and research and
development, on an interim basisdevelopment. Gas public interest research continues to be funded through
2012.the gas public purpose program surcharge. California law
also requires the CPUC to authorize funding for the California Solar Initiative and other self-generation programs, as discussed
under “Self-Generation Incentive Program and California Solar Initiative,” below. Additionally, the CPUC has authorized funding for
energy savings assistance and demand response programs. For
2011,2012, the Utility collected authorized revenue requirements of
$731$688 million from electric customers and
$161$169 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.equipment and energy management products to meet energy savings goals in California. The CPUC has authorized a total of $1.3 billion$823 million to fund the Utility’s 2013 and 2014 energy efficiency programs, including programs administered by the Marin Energy Authority, a CCA, and a regional network of San Francisco Bay area cities and counties.
On December 20, 2012, the CPUC approved a new energy efficiency incentive mechanism to reward the Utility and other California energy utilities for the successful implementation of their 2010-2012 energy efficiency programs. The CPUC has adoptedmechanism provides each utility with an earnings rate composed of a long-term5% management fee based on qualified program expenditures and an additional performance bonus of up to 1%. The Utility’s earnings rate for the 2010-2012 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.program cycle is 5.68%. 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$21 million through December 31, 2011 for the successful implementation of the Utility’s 2010 energy efficiency programs duringprograms. The CPUC decision also established the 2006 through 2008process that is expected to apply to incentive claims for program cycleyears 2011 and 2012. After the CPUC completes its audit of the utilities’ 2011 program expenditures, the utilities must file their incentive claims in the third quarter of 2013 for approval by the 2009 bridge year. CPUC in the fourth quarter of 2013. Similarly, the utilities will file their incentive claims based on the CPUC-audited 2012 program expenditures in the third quarter of 2014 for approval by the CPUC in the fourth quarter of 2014.
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 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,April 2012, the CPUC authorized the Utility to collect $112$192 million through December 31, 2011 to implementfund its multi-year air conditioning direct load control program. Customers who enroll in this program will allow2012-2014 demand response programs. Due to the timing of the decision, the CPUC authorized 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.recover both 2012 and 2013 program costs through customer rates collected in 2013.
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
SGIPself-generation incentive program 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 CSIthis initiative is to install 3,000 MW (through both
California investor-owned electric utilities and
municipal 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$469 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 program2012 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.
TheDuring any given year, 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
2011,2012, the amount of this subsidy was approximately
$917 million, including avoided customer surcharges.$851 million. The CPUC also authorized the Utility to recover approximately
$35$45 million in administrative costs relating to the CARE subsidy through 2014.
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’sUtility's personnel and the public. These laws and requirements relate to a broad range of activities, including the following:
the discharge of pollutants into the air, water, and soil;
the transportation, handling, storage and disposal of spent nuclear fuel;
| · | the discharge of pollutants into the air, water, and soil; |
the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, remediation and emergency response in connection with hazardous and radioactive substances;
| · | the transportation, handling, storage and disposal of spent nuclear fuel; |
the reporting and reduction of carbon dioxide (“CO2”) and other GHG emissions; and
| · | the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, remediation and emergency response in connection with hazardous and radioactive substances; |
the environmental impacts of land use, including endangered species and habitat protection.
| · | the reporting and reduction of carbon dioxide (“CO2”) and other GHG emissions; and |
| · | 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’sUtility'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’sowner'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’sUtility'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.”Costs” below.
Air Quality and Climate Change
The
Utility’sUtility'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.has not yet been enacted.. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions, including establishing an annual GHG reporting requirement. In June 2010,
State Regulation. AB 32 requires the EPA adopted the final “tailoring rule” to phase-in permit requirements for constructiongradual reduction of new sources ofstate-wide GHG emissions such as power plants and natural gas compressor stations, ifto 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.1990 level by 2020. 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. Theseregulations 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 beginsbegan January 1, 2013, will applyapplies to the electricity generation and large industrial sectors. The next two-year compliance period, from January 1, 2015 through December 31, 2017, also will applyexpand to include the natural gas supply and transportation sectors. (The last compliance period, from January 1, 2018 through December 31, 2020, will apply tosectors, effectively
covering all sectors.) Before the first compliance period begins,capped sectors until 2020. Each year the CARB will issue a fixed number of emission allowances (i.e., the rights to emit GHGs), some equal to the amount of which will be freely allocated to regulated electric distribution utilitiesGHGs emissions allowed for their customers’ benefit.that year. Emitters can obtain allowances from the CARB at quarterly auctions held by the CARB or from third parties on the secondary market for trading GHG allowances. The CARB will sell other allowances at anCARB’s first quarterly auction the first of which is scheduled to bewas held on August 15,November 14, 2012. Emitters i.e.,those entities with(also known as covered entities) are required to obtain and surrender allowances equal to the amount of their GHGs emissions within a particular compliance obligation,period. Emitters may 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 satisfymeet up to 8% of their compliance obligations. Allowances may be purchased and soldobligation 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 endpurchase of each compliance period, emitters must surrender allowances and offset credits, in an amount equal to their“offset credits” which represent GHG emissions during the period,abatement achieved in sectors that are not subject to the CARB. During 2012,cap. For more information about 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 andcap-and trade program, are expected to be passed through to customers through rates. The CPUCsee the section of MD&A entitled “Environmental Matters” in the 2012 Annual Report, which information 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.
incorporated herein by reference.
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(For more information, see “Renewable
EnergyGeneration Resources”
above for more information.above.)
Climate Change Mitigation and Adaptation Strategies.During
2011,2012, 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, safety-related pipeline hydrotesting, as well as normal pipeline maintenance, releases the GHG methane to the atmosphere. The Utility has taken steps to reduce the release of methane a GHG released as part ofby implementing techniques including drafting and cross-compression. In addition, the delivery of natural gas. The Utility has replacedcontinues to replace a substantial portion of its older cast iron and steel gas mains and implemented a technique called cross-compression, a process bywith new pipe, 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%.leakage.
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 byresult from climate change. PG&E Corporation and the Utility are also assessing the benefits and challenges associated with various climate change policies and identifying how a comprehensive program can be structured to mitigate overall costs to customers and the economy as a whole while ensuring that the environmental objectives of the program are met.
PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility wasAs a charter memberresult of the California Climate Action Registry (“CCAR”time necessary for a thorough, third-party verification of the Utility’s GHG emissions, emissions data for 2011 are the most recent data available. Since 2009, the Utility has complied with AB 32’s annual GHG emissions reporting requirements, reporting combustion emissions from its electric generation facilities and natural gas compressor stations to the CARB. (For information about the sources of electric generation that the Utility delivered to customers in 2012, see “Electric Utility Operations− Electricity Resources” above.) andConsistent with Utility practice since 2002, the Utility also voluntarily reported its GHG emissions to CCAR on an annual basis from 2002 through 2008. The Utility has since voluntarily reported its2011 GHG emissions to The Climate Registry (“TCR”), a successor non-profit to CCAR,organization that has a reporting and measurement standard applicable to most industry sectors across North America. Since 2009,Reporting to TCR enables the Utility has also compliedto publicly report GHG emissions not covered by mandatory reporting requirements. The Utility’s third-party verified voluntary GHG
inventory for 2011 totaled more than 50 million metric tonnes of CO2-equivalent (“CO2-e”), which includes approximately 33 million metric tonnes CO2-e from customer natural gas use.
Beginning with
AB 32’s annual GHG emission reporting requirements, and in 2011,its 2010 emissions, the Utility
began reportingalso reported the GHG emissions from
some of its facilities and operations to the EPA under its
newmandatory reporting 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
2011 Emissions Reported to the time necessary for a thorough, third-party verification ofCalifornia Air Resources Board
For its 2011 emissions, the Utility began reporting the GHG emissions from natural gas supplied to customers and the fugitive emissions from its natural gas distribution system and compressor stations. The following table shows the GHG emissions data the Utility reported to the CARB under AB 32.
| Amount (metric tonnes CO2 – equivalent) |
Fossil Fuel-Fired Plants (1) | 2,025,543 |
Natural Gas Compressor Stations (2) | 258,446 |
| Distribution Fugitive Natural Gas Emissions | 224,298 |
Customer Natural Gas Use (3) | |
| Total | |
(1) Includes nitrous oxide (“N2O”) and methane (“CH4”) emissions from the Utility’s GHGgenerating stations; does not include de minimis emissions.
(2) Includes compressor stations emitting more than 25,000 metric tonnes of CO2-e annually; does not include de minimis emissions.
(3) Includes emissions in accordancefrom the combustion of natural gas delivered to all entities on the Utility’s distribution system, with the standards developedexception of gas delivered to other natural gas local distribution companies. This figure does not represent the Utility’s compliance obligation under AB 32, which will be equivalent to the above reported value less the fuel that is delivered to covered entities as calculated by TCR,the CARB.
Benchmarking GHG Emissions for Delivered Electricity
The Utility’s third-party-verified CO2 emissions
data for 2010 arerate associated with the
most recent data available. For information about the sources of electric generation that the Utilityelectricity delivered to customers in 2011
see “Electric Utility Operations-Electric Generation Resources” above.Total 2010 GHG Emissions by Source Category
was 393 pounds of CO2 per MWh. The Utility’s 2011 emissions rate as compared to the national and California averages for electric utilities is shown in the following table: | | Amount (Pounds of CO2 per MWh) |
SourceU.S. Average (1)
| | Amount (per million metric tonnes CO2 –
equivalent)1,216 |
Delivered ElectricityCalifornia’s Average (1)(1)
| | 17.21659 |
Electricity Transmission and Distribution Line Losses
| | 1.11 |
Process and Fugitive Emissions from Natural Gas Systems
| | 1.48 |
Gas Compressor Stations
| | 0.28 |
Transportation
| | 0.11 |
Facility
Pacific Gas and Electricity UseElectric Company (2) | | 0.05 |
Electrical Equipment
| | 0.07 |
| | |
Total
| | 20.31 |
| | 393 |
(1) Source: Environmental Protection Agency eGRID 2012 Version 1.0, which contains year 2009 information configured to reflect the electric power industry's current structure as of May 10, 2012. 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 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:
| | | | |
| | Amount (Pounds of CO2
per MWh) | |
U.S. Average(1)
| | | 1,293 | |
California’s Average(1)
| | | 681 | |
Pacific Gas and Electric Company(2)
| | | 443 | |
(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
approximatelymore than 40% of the Utility’s delivered electricity in
2010.2011. The Utility’s
retained fossil fuel-fired generation comprised approximately
5%6% of the Utility’s delivered electricity in
2010. | | | | | | | | |
| | | 2010 | | | 2009 | |
Total NOx Emissions (tons) | | | 904 | | | | 1,258 | |
NOx emissions rates (pounds/MWh) | | | | | | | | |
Fossil fuel-fired plants | | | 0.49 | | | | 0.82 | |
All plants | | | 0.06 | | | | 0.09 | |
Total SO2 Emissions (tons) | | | 42 | | | | 37 | |
SO2 emissions rates (pounds/MWh) | | | | | | | | |
Fossil fuel-fired plants | | | 0.023 | | | | 0.02 | |
All plants | | | 0.003 | | | | 0.0026 | |
Total CO2 Emissions (metric tons) | | | 1,545,892 | | | | 1,401,487 | |
CO2 emissions rates (pounds/MWh) | | | | | | | | |
Fossil fuel-fired plants | | | 943 | | | | 1,016 | |
All plants | | | 106 | | | | 110 | |
Other Emissions Statistics | | | | | | | | |
Sulfur Hexafluoride (“SF6”) Emissions | | | | | | | | |
Total SF6 Emissions (metric tons CO2- equivalent) | | | 69,066 | | | | 62,129 | |
SF6 emissions leak rate | | | 1.8% | | | | 1.7% | |
2011.
| | | |
| Total NOx Emissions (tons) | 144 | 904 |
NOx Emissions Rates (pounds/MWh) | | |
Fossil Fuel-Fired Plants | 0.06 | 0.49 |
All Plants | 0.008 | 0.06 |
| Total SO2 Emissions (tons) | 12 | 42 |
SO2 Emissions Rates (pounds/MWh) | | |
Fossil Fuel-Fired Plants | 0.005 | 0.023 |
All Plants | 0.0007 | 0.003 |
| Total CO2 Emissions (metric tons) | 2,024,206 | 1,545,892 |
CO2 Emissions Rates (pounds/MWh) | | |
Fossil Fuel-Fired Plants | 875 | 943 |
All Plants | 126 | 106 |
| Other Emissions Statistics | | |
Sulfur Hexafluoride (“SF6”) Emissions | | |
Total SF6 Emissions (metric tons CO2- equivalent) | 70,052 | 69,066 |
SF6 Emissions Leak Rate | 1.7% | 1.8% |
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 andcomment. In June 2012, the EPA issued a Notice of Data Availability proposing changes to the draft regulations which, if adopted, would provide more flexibility in complying with some of the requirements. The EPA is required to issue final regulations
are not expected untilby July
2012.2013.
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. The policy
oralso allows other compliance measures to be taken 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.”
IfThe policy also established a nuclear review committee to evaluate the feasibility and cost of alternative technologies for nuclear plants. The committee’s consultant, Bechtel, must complete an assessment for the California Water
Board disagreed andBoard’s review by October 2013. Upon review of the feasibility assessment, 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.
If the California Water Board requires the installation of cooling towers that the Utility believes are 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. 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’sUtility'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’sUtility's operations, the Utility generates waste that falls within CERCLA’sCERCLA'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 necessaryhas a comprehensive program in place to comply with federal, state, and local laws and regulations related to hazardous materials and hazardous waste compliance,
remediation activities, and
remediation activities.other environmental requirements. The Utility
has a comprehensive programassesses and monitors, on an ongoing basis, measures that may be necessary to comply with
hazardous waste storage, handling, and disposal requirements issued by the EPA under RCRA and state hazardous wastethese laws and
other environmental requirements.regulations and implements changes to its program as deemed appropriate. 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
centercenters, 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
the sections within MD&A entitled “Environmental Matters,” “Critical Accounting Polices,” and Note 15: Commitments and
Contingencies–Contingencies−Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in the
20112012 Annual Report, which information is incorporated herein by
reference and included in Exhibit 13 to this report.reference.
Operations at the
Utility’sUtility'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$51 million in
20112012 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’sUtility'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 has incurred significant environmental liabilities associated with these sites. For more information about 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 remediationrelated 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 1515: Commitments and Contingencies−Environmental Remediation Contingencies of the Notes to the Consolidated Financial Statements. During 2011,Statements in the 2012 Annual Report, which information is incorporated herein by reference.
Recovery of Environmental Remediation Costs
The CPUC has authorized the Utility
spent $36 million for remediation activities at the Hinkley site. The Utility is unable to recover
most of its environmental remediation costs
through various ratemaking mechanisms, subject to exclusions for
certain sites, such as 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 millionlimitations 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 anycertain liabilities 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 liabilitiesas amounts associated with fossil fuel-fired generation facilities thatformerly owned by the Utility sold in 1998Utility. For more information, see Note 15: Commitments 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 excessContingencies−Environmental Remediation Contingencies of the Utility’s ultimate obligations may be subjectNotes to refund to customers.
the Consolidated Financial Statements in the 2012 Annual Report which information is incorporated herein by reference.
Nuclear Fuel Disposal
As part of
Under the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (“DOE”)DOE and electric utilities with commercial nuclear power plants were authorized 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 thanby January 31, 1998, in exchange for fees paid by the utilities. In 1983, theThe DOE entered into a contracthas been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and itsthe retired nuclear facility at Humboldt Bay. Because the DOE failed to meet its contractual obligations to dispose of nuclear waste,Bay Unit 3. As a result, 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 Utility2024, and a license to build the dry cask storage facility.separate facility at Humboldt Bay. The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to build on-siteconstruct interim storage facilities for 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,fuel.
On September 5, 2012, the U.S.
CourtDepartment of
Federal ClaimsJustice and the Utility executed a settlement agreement that awarded the Utility
$89 million. The DOE filed an appeal$266 million for spent fuel storage costs incurred through December 31, 2010. For more information, see Note 15: Commitments and Contingencies−Environmental Remediation Contingencies of
this decision on May 28, 2010. On August 3, 2010, the
Utility filed two complaints againstNotes to the
DOEConsolidated Financial Statements in the
U.S. Court of Federal Claims seeking2012 Annual Report, which information is incorporated herein by reference. Considerable uncertainty continues 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 fromexist regarding when and whether the DOE will
be creditedmeet its contractual obligation to
customers.the Utility and other nuclear power plant owners to dispose of spent fuel.
The Utility’sUtility'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 contributionsfiles an application with the CPUC every three years requesting approval of the Utility’s estimated decommissioning costs and authorization to recover the estimated costs through rates. Nuclear decommissioning charges collected through rates are held in nuclear decommissioning trusts to providebe used for the eventual decommissioning of each nuclear unit. In(See the Utility’s 2005discussion of the 2012 Nuclear Decommissioning Cost TriennialTriennal 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 fromcustomers 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,Policies of the Notes to the Consolidated Financial Statements in the 20112012 Annual Report.
Report, which information is incorporated herein by reference.)
Many of the Utility’sUtility'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’sUtility'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. A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forthappears within MD&A under the heading “Risk Factors” in the MD&A in the 20112012 Annual Report, which information is incorporated herein by reference and included in Exhibit 13 to this report.reference.
Item 1B.Unresolved Staff Comments The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility’sUtility'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. In March and September 2012, the Utility entered into 10-year facility lease agreements for 250,000 and 145,000 square feet of office space, respectively, in San Ramon, California. The Utility also recently entered into a lease agreement for a new 12,000 square foot data center located near Sacramento, California. In total, the Utility occupies 10.8 million square feet of real property, including 8.6 million square feet that the Utility owns. Of the 10.8 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 currently owns approximately 167,000 acres of land, including approximately 140,000 acres of watershed lands. As part of the settlement agreement entered into by PG&E Corporation and the Utility to resolve the Utility’s proceeding under Chapter 11 Settlement Agreement,of the U.S. Bankruptcy Code, 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’sUtility's or a joint licensee’slicensee'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-termmanagement 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. 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–Contingencies−Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 20112012 Annual Report.Report, which information is incorporated herein by reference.
Diablo Canyon Power Plant
The Utility’sUtility'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’sUtility's Diablo Canyon power plant’splant'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’sUtility'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’sGeneral's Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon’sCanyon'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’scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists’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 20122013 could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement. (See “Item 1. Business–Business−Environmental Matters–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’sUtility'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 and Natural Gas Spending
At December 31, 2012, approximately 140 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, havehad been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 370450 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 aCourt. The trial date of July 23, 2012 has been set for the first group of these cases. During the case management conferenceremaining cases began on January 19, 2012,2, 2013 with pretrial motions and hearings. On January 14, 2013, the court addressed, among other topics, mandatory settlement conferences.vacated the trial and all pending hearings due to the significant number of cases that have been settled outside of court. The court expressed its preference that generally households suffering a death or serious injury should proceed first.has urged the parties to settle the remaining cases. As of February 8, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs. It is likelyuncertain whether or when the mandatory settlement conferencesUtility will startbe able to resolve the remaining claims through settlement.
Additionally, in
late March or early April 2012. The next case management conference is scheduled for March 2, 2012.Additionally,October 2010, 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.claims, relating to the Utility’s natural gas business. 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 On February 7, 2013, another purported shareholder derivative lawsuit was filed in U.S. District Court for the litigation relatedNorthern District of California to seek recovery on behalf of PG&E Corporation for alleged breaches of fiduciary duty by officers and directors, among other claims.
In addition, on August 23, 2012, a complaint was filed in the San Bruno accident,Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions. The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses. To state their claims, the plaintiffs cited the January 2012 investigative report from the CPUC’s Safety and Enforcement Division (“SED”) that alleged, from 1996 to 2010, the Utility spent less on capital expenditures and operations and maintenance expense for its natural gas transmission operations than it recovered in rates, by $95 million and $39 million, respectively. The SED recommended that the Utility should use such amounts to fund future gas transmission expenditures and operations. Plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of Section 17200 of the California Business and Professions Code (“Section 17200”) and claim that this violation also constitutes a violation of California Public Utilities Code Section 2106 (“Section 2106”), which provides a private right of action for violations of the California constitution or state laws by public utilities. Plaintiffs seek restitution and disgorgement under Section 17200 and compensatory and punitive damages under Section 2106. PG&E Corporation and the Utility contest the allegations. In January 2013, PG&E Corporation and the Utility requested that the court dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs’ allegations. In the alternative, PG&E Corporation and the Utility requested that the court stay the proceeding until the CPUC investigations described above are concluded. The court has set a hearing on the motion for April 26, 2013.
For additional information, see the section ofdiscussion within MD&A entitledunder the heading, “Natural Gas Matters” and in the 2011 Annual Report. See also Note 15: Commitments and Contingencies–Legal and Regulatory Contingencies of the Notes to the Consolidated Financial Statements contained in the 20112012 Annual Report, which discussiondiscussions are incorporated herein by reference.
Pending CPUC Investigations and Potential Enforcement Matters
The CPUC 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 issuedconducting three orders to institute investigations (“OII”) pertaining to various aspects of the Utility’s natural gas transmission system, including an investigation ofoperations that relate to (1) 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’sits natural 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 federaldensity, 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(3) 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”). Amonginstallation, integrity management, recordkeeping and 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,operational practices, and other events or courses of conduct, that could have led to or contributed to the San Bruno accident, as well as,accident. In 2012, the Utility’s compliance withSED issued investigative reports in each of these investigations alleging that the Utility committed numerous violations of applicable laws and regulations and recommending the CPUC orders and resolutions issued sinceimpose penalties on the dateUtility. Evidentiary hearings were held in each of these investigations. The CPUC administrative law judges (“ALJs”) who oversee the investigations have adopted a revised procedural schedule, including the dates by which the parties’ briefs must be submitted. The ALJs have also permitted the other parties (the City of San Bruno, accident. The CPUC citedUtility Reform Network, and the findingsCity and County of San Francisco) to separately address in their opening briefs their allegations against the Utility, if any, in addition to the allegations made by the CPSDSED.
The ALJs have ordered the SED and other parties to file single coordinated briefs to address potential monetary penalties and remedies (which could include remedial operational or policy measures) for all three investigations by April 26, 2013. After briefing has been completed, the ALJs will issue one or more presiding officer’s decisions listing the violations determined to have been committed, the amount of penalties, and any required remedial actions. Based on the revised procedural schedule, one or more presiding officer’s decisions will be issued by July 23, 2013. The decisions would become the final decisions of the CPUC thirty days after issuance unless the Utility or another party filed an appeal, or a CPUC commissioner requested review of the decision, within such time.
California gas corporations are required to provide notice to the CPUC of any self-identified or self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices. The CPUC has authorized the SED to issue citations and impose penalties based on self-reported violations. In April 2012, the CPUC affirmed a $17 million penalty that had been imposed by the SED based on the Utility’s self-report that it failed to conduct periodic leak surveys because it had not included 16 gas distribution maps in its investigative report releasedleak survey schedule. (The Utility has paid the penalty and completed all of the missed leak surveys.) As of December 31, 2012, the Utility has submitted 34 self-reports with the CPUC, plus additional follow-up reports. The SED has not yet taken formal action with respect to the Utility’s other self-reports. The SED may issue additional citations and impose penalties on January 12, 2012. In its report, the CPSD allegedUtility associated with these or future reports that the San Bruno accident wasUtility may file.
In addition, in July 2012, the Utility reported to the CPUC that it had discovered that its access to some pipelines has been limited by vegetation overgrowth or building structures that encroach upon some of the Utility’s gas transmission pipeline rights-of-way. The Utility is undertaking a system-wide effort to identify and remove encroachments from its pipeline rights-of-way over a multi-year period. PG&E Corporation and the Utility are uncertain how this matter will affect the investigative proceedings related to natural gas operations, or whether additional proceedings or investigations will be commenced by the CPUC that could result in regulatory orders or the imposition of penalties on the Utility.
The CPUC can impose significant penalties for violations of applicable laws, rules, and orders. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the Utility’s failureviolations and the number of persons affected; and the good faith of the entity charged in attempting to follow accepted industry practice when installingachieve compliance, after notification of a violation. The CPUC is also required to consider the sectionappropriateness of pipethe amount of the penalty to the size of the entity charged. The CPUC has historically exercised this discretion in determining penalties. The CPUC's delegation of enforcement authority to the SED allows the SED to use these factors in exercising discretion to determine the number of violations, but the SED is required to impose the maximum statutory penalty for each separate violation that failed, the Utility’s failureSED finds.
For more information, see discussions within MD&A under the heading, “Natural Gas Matters,” and Note 15: Commitments and Contingencies−Legal and Regulatory Contingencies, of the Notes to comply with federal pipeline integrity management requirements, the Utility’s inadequate recordkeeping practices, deficienciesConsolidated Financial Statements 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 engaged2012 Annual Report, which discussions are incorporated herein 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.
reference
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. These representatives have indicated that the Utility is a target of the investigation. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees. 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 See the discussions within MD&A under the heading “Natural Gas Matters – Criminal Investigation, Regarding Substation Construction Permit
On June 10, 2011,” and in Note 15: Commitments and Contingencies of 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. PursuantNotes to the approved settlement agreement,Consolidated Financial Statements in the Utility has paid a fine of $100,000 and contributed $50,000 to an environmental group.
2012 Annual Report, which discussions are incorporated herein by reference.
Item 4.Mine Safety Disclosures
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,
20122013 were as follows.
| | | | |
Name | | Age | | Position |
Anthony F. Earley, Jr. | | 62 63 | | Chairman of the Board, Chief Executive Officer, and President |
Kent M. Harvey | | 53 54 | | Senior Vice President and Chief Financial Officer |
Christopher P. Johns | | 51 52 | | President, Pacific Gas and Electric Company |
Hyun Park | | 50 51 | | Senior Vice President and General Counsel |
Greg S. Pruett | | 54 55 | | Senior Vice President, Corporate Affairs |
John R. Simon | | 47 48 | | Senior Vice President, Human Resources |
All officers of PG&E Corporation serve at the pleasure of the Board of
Directors.Directors of PG&E Corporation. During
at least the past five years through February 1,
2012,2013, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.
| | | | |
Name | | Position | | Period Held Office |
| | | | |
Anthony F. Earley, Jr. | | Chairman of the Board, Chief Executive Officer, and President | | September 13, 2011 to present |
| | Executive Chairman of the Board, DTE Energy Company | | October 1, 2010 to September 12, 2011 |
| | Chairman of the Board and Chief Executive Officer, DTE Energy Company | | August 1998 to September 30, 2010 |
| | | | |
Kent M. Harvey | | Senior Vice President and Chief Financial Officer | | August 1, 2009 to present |
| | Senior Vice President, Financial Services, Pacific Gas and Electric Company | | August 1, 2009 to present |
| | Senior Vice President and Chief Risk and Audit Officer | | October 1, 2005 to July 31, 2009 |
| | | | |
Christopher P. Johns | | President, Pacific Gas and Electric Company | | August 1, 2009 to present |
| | Senior Vice President and Chief Financial Officer | | May 1, 2009 to July 31, 2009 |
| | Senior Vice President, Financial Services, Pacific Gas and Electric Company | | May 1, 2009 to July 31, 2009 |
| | Senior Vice President, Chief Financial Officer, and Treasurer | | October 4, 2005 to April 30, 2009 |
| | Senior Vice President and Treasurer, Pacific Gas and Electric Company | | June 1, 2007 to April 30, 2009 |
| | Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company | | October 1, 2005 to May 31, 2007 |
| | |
Hyun Park | | Senior Vice President and General Counsel | | November 13, 2006 to present |
| | | | |
Greg S. Pruett | | Senior Vice President, Corporate Affairs | | November 1, 2009 to present |
| | Senior Vice President, Corporate Affairs, Pacific Gas and Electric Company | | November 1, 2009 to present |
| | Senior Vice President, Corporate Relations | | November 1, 2007 to October 31, 2009 |
| | Senior Vice President, Corporate Relations, Pacific Gas and Electric Company | | March 1, 2009 to October 31, 2009 |
| | Vice President, Corporate Relations | | March 1, 2007 to October 31, 2007 |
| | Vice President, Communications and Marketing, American Gas Association | | April 10, 2006 to February 23, 2007 |
| | |
John R. Simon | | Senior Vice President, Human Resources | | April 16, 2007 to present |
| | | | |
Name
| | Position
| | Period Held Office
|
| | Senior Vice President, Human Resources, Pacific Gas and Electric Company | | April 16, 2007 to present |
| | Executive Vice President, Global Human Capital, TeleTech Holdings, Inc. | | March 21, 2006 to April 13, 2007 |
The names, ages and positions of the
Utility’sUtility's “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 1,
20122013 were as follows:
| | | | |
Name | | Age | | Position |
| Anthony F. Earley, Jr. | | 6263 | | Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation |
| Christopher P. Johns | | 5152 | | President |
| Nickolas Stavropoulos | | 5354 | | Executive Vice President, Gas Operations |
| Geisha J. Williams | | 5051 | | Executive Vice President, Electric Operations |
| Karen A. Austin | | 5051 | | Senior Vice President and Chief Information Officer |
| Desmond A. Bell | | 4950 | | Senior Vice President, Safety and Shared Services |
| Thomas E. Bottorff | | 5859 | | Senior Vice President, Regulatory RelationsAffairs |
| Helen A. Burt | | 5556 | | Senior Vice President and Chief Customer Officer |
| John T. Conway | | 5455 | | Senior Vice President, Energy Supply |
| Edward D. Halpin | | 51 | | Senior Vice President and Chief Nuclear Officer |
| Kent M. Harvey | | 5354 | | Senior Vice President, Financial Services |
Hyun Park
| Gregory K. Kiraly | | 5048 | | Senior Vice President, Electric Distribution Operations |
| Hyun Park | | 51 | | Senior Vice President and General Counsel, PG&E Corporation |
| Greg S. Pruett | | 5455 | | Senior Vice President, Corporate Affairs |
| John R. Simon | | 4748 | | Senior Vice President, Human Resources |
Fong Wan
| Jesus Soto, Jr. | | 5045 | | Senior Vice President, Gas Transmission Operations |
| Fong Wan | | 51 | | Senior Vice President, Energy Procurement |
| Dinyar B. Mistry | | 4950 | | Vice President, Chief Financial Officer, and Controller |
All officers of the Utility serve at the pleasure of the Board of
Directors.Directors of the Utility. During
at least the past five years through February 1,
2012,2013, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
| | | | |
Name | | Position | | Period Held Office |
| | | | |
Anthony F. Earley, Jr. | | Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation | | September 13, 2011 to present |
| | Executive Chairman of the Board, DTE Energy Company | | October 1, 2010 to September 12, 2011 |
| | Chairman of the Board and Chief Executive Officer, DTE Energy Company | | August 1998 to September 30, 2010 |
| | | | |
Christopher P. Johns | | President | | August 1, 2009 to present |
| | Senior Vice President, Financial Services | | May 1, 2009 to July 31, 2009 |
| | Senior Vice President and Chief Financial Officer, PG&E Corporation | | May 1, 2009 to July 31, 2009 |
| | Senior Vice President and Treasurer | | June 1, 2007 to April 30, 2009 |
| | Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation | | October 4, 2005 to April 30, 2009 |
| | Senior Vice President, Chief Financial Officer, and Treasurer | | October 1, 2005 to May 31, 2007 |
| | |
Nickolas Stavropoulos | | Executive Vice President, Gas Operations | | June 13, 2011 to present |
| | | | |
Name
| | Position
| | Period Held Office
|
| | Executive Vice President and Chief Operating Officer, U.S. Gas Distribution, National Grid | | August 2007 to March 31, 2011 |
| | President, KeySpan Energy Delivery | | June 2004 to August 2007 |
| | |
| Geisha J. Williams | | Executive Vice President, Electric Operations | | June 1, 2011 to present |
| | Senior Vice President, Energy Delivery | | December 1, 2007 to May 31, 2011 |
| | Vice President, Power Systems, Distribution, Florida Power and Light Company | | July 2003 to July 2007 |
| | |
| Karen A. Austin | | Senior Vice President and Chief Information Officer | | June 1, 2011 to present |
| | President, Consumer Electronics, Sears Holdings | | February 2009 to May 2011 |
| | Executive Vice President, Chief Information Officer, Sears Holdings | | March 2005 to January 2009 |
| | | | |
| Desmond A. Bell | | Senior Vice President, Safety and Shared Services | | January 1, 2012 to present |
| | Senior Vice President, Shared Services and Chief Procurement Officer | | October 1, 2008 to December 31, 2011 |
| | Vice President, Shared Services and Chief Procurement Officer | | March 1, 2008 to September 30, 2008 |
| | Vice President and Chief of Staff | | March 19, 2007 to February 29, 2008 |
| | Vice President, Parts Logistics, Bombardier Aerospace | | April 2003 to September 2006 |
| | |
| Thomas E. Bottorff | | Senior Vice President, Regulatory Affairs | | September 1, 2012 to present |
| | Senior Vice President, Regulatory Relations | | October 14, 2005 to presentAugust 31, 2012 |
| | | | |
| Helen A. Burt | | Senior Vice President and Chief Customer Officer | | February 27, 2006 to present |
| | | | |
| John T. Conway | | Senior Vice President, Energy Supply | | March 1, 2012 to present |
| | Senior Vice President, Energy Supply and Chief Nuclear Officer | | April 1, 2009 to presentFebruary 29, 2012 |
| | Senior Vice President, Generation and Chief Nuclear Officer | | October 1, 2008 to March 31, 2009 |
| | Senior Vice President and Chief Nuclear Officer | | March 1, 2008 to September 30, 2008 |
| | Site Vice President, Diablo Canyon Power Plant | | May 29, 2007 to February 29, 2008 |
| | | | |
| Edward D. Halpin | | Senior Vice President and Chief Nuclear Officer | | April 2, 2012 to present |
| | President, Chief Executive Officer and Chief Nuclear Officer, South Texas Project Nuclear Operating Company | | December 2009 to March 2012 |
| | Chief Nuclear Officer, South Texas Project Nuclear Operating Company | | October 2008 to November 2009 |
| | Site Vice President, MonticelloSouth Texas Project Nuclear Plant, Nuclear ManagementOperating Company | | May 2005June 2006 to May 2007September 2008 |
| | | | |
| Kent M. Harvey | | Senior Vice President, Financial Services | | August 1, 2009 to present |
| | Senior Vice President and Chief Financial Officer, PG&E Corporation | | August 1, 2009 to present |
| | Senior Vice President and Chief Risk and Audit Officer, PG&E Corporation | | October 1, 2005 to July 31, 2009 |
| | | | |
| Gregory K. Kiraly | | Senior Vice President, Electric Distribution Operations | | September 18, 2012 to present |
| | Vice President, Electric Distribution Operations | | October 1, 2011 to September 17, 2012 |
| | Vice President, SmartMeter Operations | | August 23, 2010 to September 30, 2011 |
| | Vice President, Electric Maintenance and Construction | | January 1, 2010 to August 22, 2010 |
| | Vice President, Transmission Substations, Maintenance and Construction | | January 1, 2009 to December 31, 2009 |
| | Vice President, Maintenance and Construction | | April 14, 2008 to December 31, 2008 |
| | Vice President, Distribution Systems Operations, Energy Delivery, Commonwealth Edison Company | | June 2007 to April 2008 |
| | | | |
| Hyun Park | | Senior Vice President and General Counsel, PG&E Corporation | | November 13, 2006 to present |
| | | | |
| Greg S. Pruett | | Senior Vice President, Corporate Affairs | | November 1, 2009 to present |
| | Senior Vice President, Corporate Affairs, PG&E Corporation | | November 1, 2009 to present |
| | Senior Vice President, Corporate Relations | | March 1, 2009 to October 31, 2009 |
| | Senior Vice President, Corporate Relations, PG&E Corporation | | November 1, 2007 to October 31, 2009 |
| | Vice President, Corporate Relations, PG&E Corporation | | March 1, 2007 to October 31, 2007 |
| | Vice President, Communications and Marketing, American Gas Association | | April 10, 2006 to February 23, 2007 |
| | |
| John R. Simon | | Senior Vice President, Human Resources | | April 16, 2007 to present |
| | Senior Vice President, Human Resources, PG&E Corporation | | April 16, 2007 to present |
| | Executive | | |
| Jesus Soto, Jr. | | Senior Vice President, Global Human Capital, TeleTechGas Transmission Operations | | March 21, 2006May 29, 2012 to April 13, 2007present |
| | Vice President, Operations Services, El Paso Pipeline Group | | May 2007 to May 2012 |
| | | | |
| Fong Wan | | Senior Vice President, Energy Procurement | | October 1, 2008 to present |
| | Vice President, Energy Procurement | | January 9, 2006 to September 30, 2008 |
| | | | |
Name
| | Position
| | Period Held Office
|
| Dinyar B. Mistry | | Vice President, Chief Financial Officer, and Controller | | October 1, 2011 to present |
| | Vice President and Controller, PG&E Corporation | | March 8, 2010 to present |
| | Vice President and Controller | | March 8, 2010 to September 30, 2011 |
| | Vice President and Chief Risk and Audit Officer | | September 16, 2009 to March 7, 2010 |
| | Vice President and Chief Risk and Audit Officer, PG&E Corporation | | August 1, 2009 to March 7, 2010 |
| | Vice President, Internal Auditing/Compliance and Ethics, PG&E Corporation | | January 1, 2009 to July 31, 2009 |
| | Vice President, Regulation and Rates | | September 20, 2007 to December 31, 2008 |
| | Vice President, State Regulation | | November 9, 2005 to September 19, 2007 |
Item 5.Market for Registrant’sRegistrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities As of February
7, 2012,11, 2013, there were
71,94367,982 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.exchange. 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
20112012 Annual Report, which information is incorporated
herein by
reference and included in Exhibit 13 to this report.reference. 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 Reportis set forth 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–Share-Based Compensation−Dividends of the Notes to the Consolidated Financial Statements, and
inwithin MD&A under the
section of MD&A entitledheading “Liquidity and Financial Resources—Dividends,”
in the 2012 Annual Report, which information is incorporated
herein by
reference and included in Exhibit 13 to this report.reference.
Sales of Unregistered Equity Securities During the quarter ended December 31, 2011,2012, PG&E Corporation made equity contributions totaling $205$170 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 2011.2012.
Issuer Purchases of Equity Securities PG&E Corporation common stock:
| | Total Number of Shares Purchased | | | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs |
| October 1 through October 31, 2012 | | - | | - | | - | | $ - |
| November 1 through November 30, 2012 | | - | | - | | - | | - |
| December 1 through December 31, 2012 | | | | | | | | |
Total | | | | | | | | |
| | | | | | | | | |
(1) Shares of PG&E Corporation common stock tendered to pay stock option exercise price. |
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 2011,2012, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.
Item 6.Selected Financial DataA summary of selected
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
20112012 Annual Report, which information is incorporated
herein by
reference and included in Exhibit 13 to this report.reference.
Item 7.Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations A discussion of PG&E Corporation’sCorporation's and the Utility’s consolidated financial condition and results of operations is set forth under the heading “Management’s“Management's Discussion and Analysis of Financial Condition and
Results of Operations” in the
20112012 Annual Report, which discussion is incorporated
herein by
reference and included in Exhibit 13 to this report.reference.
Item 7A.Quantitative and Qualitative Disclosures About Market Risk Information responding to Item 7A
appears in the 2011 Annual Reportis set forth within MD&A under the heading
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk“Risk Management Activities,” and
under Notes 10in Note 10: Derivatives and
11Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements
ofin the
20112012 Annual Report, which information is incorporated
herein by
reference and included in Exhibit 13 to this report.reference.
Item 8.Financial Statements and Supplementary Data Information responding to Item 8
appears in the 2011 Annual Reportis set forth under the following headings for PG&E Corporation: “Consolidated Statements of
Income,” “Consolidated Statements of Comprehensive 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
Statements of Comprehensive Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of
Shareholders’ Equity;”Shareholders' Equity” in the 2012 Annual Report 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“Reports of Independent Registered Public Accounting
Firm,”Firm” in the 2012 Annual Report, which information is incorporated
herein by
reference and included in Exhibit 13 to this report.reference.
Item 9.Changes in and Disagreements withWith Accountants on Accounting and Financial Disclosure Item 9A.Controls and Procedures Based on an evaluation of PG&E
Corporation’sCorporation's and the
Utility’sUtility's disclosure controls and procedures as of December 31,
2011,2012, PG&E
Corporation’sCorporation's and the
Utility’sUtility'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’sCorporation's and the
Utility’sUtility'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’sCorporation's and the
Utility’sUtility'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,
20112012 that have materially affected, or are reasonably likely to materially affect, PG&E
Corporation’sCorporation's or the
Utility’sUtility'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’sManagement's report, together with the report of the independent registered public accounting firm, appears in the
20112012 Annual Report under the heading
“Management’s“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.Other InformationNot applicable.
2013 PG&E Corporation Short-Term Incentive Plan
On February 20, 2013, the Compensation Committee of the PG&E Corporation Board of Directors (“Committee”) approved the PG&E Corporation 2013 Short-Term Incentive Plan (“STIP”) under which officers and employees of PG&E Corporation and the Utility may receive cash awards based on the extent to which specified performance targets are met in each of three areas: safety (both public and employee), customer (which includes operational reliability and the efficient completion of pipeline safety work), and corporate financial performance. The resulting STIP scores for each of these measures will have the following weightings: safety (40%), customer (35%), and corporate financial performance (25%). The Committee also approved the specific performance targets for each of these STIP components.
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 captionedset forth under “Executive Officers of the Registrants” at the end of Part I of this report. Other information regarding directors is
includedset forth under the heading “Nominees for Directors of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the
20122013 Annual Meetings of Shareholders, which information is
hereby incorporated
herein 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
20122013 Annual Meetings of Shareholders, which information is
hereby incorporated
herein by reference.
Website Availability of Code of Ethics, Corporate Governance and Other Documents
The following documents are available both on PG&E Corporation’sCorporation's websitewww.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’sCorporation's and the
Utility’sUtility'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
20112012 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the
20122013 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
includedset forth under the
headingheadings “Corporate Governance
– Board Committee Duties and Composition
– Audit Committees” and “Corporate Governance
– Board
Committee Duties and
Composition –Director Independence Committee Membership Requirements” and
“Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company“Corporate Governance – Committee Membership” in the Joint Proxy Statement relating to the
20122013 Annual Meetings of Shareholders, which information is
hereby incorporated
herein by reference.
Item 11.Executive Compensation Information responding to Item 11, for each of PG&E Corporation and the Utility, is
includedset forth under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table -
2011,2012,” “Grants of Plan-Based Awards in
2011,2012,” “Outstanding Equity Awards at Fiscal Year End -
2011,2012,” “Option Exercises and Stock Vested During
2011,2012,” “Pension Benefits –
2011,2012,” “Non-Qualified Deferred Compensation –
2011,2012,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and
“2011“Compensation of Non-Employee Directors – 2012 Director Compensation” in the Joint Proxy Statement relating to the
20122013 Annual Meetings of Shareholders, which information is hereby incorporated
herein by reference.
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
includedset forth under the
headingheadings “Security Ownership of Management” and
under the heading “Other“Share Ownership Information - Principal Shareholders” in the Joint Proxy Statement relating to the
20122013 Annual Meetings of Shareholders, which information is
hereby incorporated
herein by reference.
Equity Compensation Plan Information
The following table provides information as of December 31,
20112012 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E
Corporation’sCorporation's existing equity compensation plans.
| Plan Category | | (a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | | | (b) Weighted Average Exercise Price of Outstanding Options, Warrants and Rights | | | (c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) | |
| Equity compensation plans approved by shareholders | | | 5,758,820 | (1) | | $ | 30.05 | | | | 4,548,119 | (2) |
| Equity compensation plans not approved by shareholders | | | - | | | | - | | | | - | |
| Total equity compensation plans | | | 5,758,820 | (1) | | $ | 30.05 | | | | 4,548,119 | (2) |
| | | | | | |
Plan Category
| | (a)
Number of Securities to
be Issued Upon Exercise
of Outstanding Options,
Warrants and Rights
| | (b)
Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights
| | (c)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column(a))
|
Equity compensation plans approved by shareholders
| | 5,301,546 (1) | | $26.80 | | 5,715,712(2) |
Equity compensation plans not approved by shareholders
| | - | | - | | - |
Total equity compensation plans
| | 5,301,546(1) | | $26.80 | | 5,715,712(2) |
| (1) | Includes 60,20045,597 phantom stock units, 1,663,1372,101,484 restricted stock units and 2,650,8123,088,896 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).shares. 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 66: Common Stock and Share-Based Compensation of the Notes to the Consolidated Financial Statements in the 20112012 Annual Report.Report, which description is incorporated herein by reference. For performance shares, amounts reflected in this table assume payout in shares at 200% of target. The actual number of shares issued can range from 0% to 200% of target depending on achievement of total shareholder return objectives. Also, restricted stock units and performance shares are generally settled in net shares. Upon vesting, shares with a value equal to required tax withholding will be withheld and, in lieu of issuing the shares, taxes will be paid on behalf of employees. Shares not issued due to share withholding or performance achievement below maximum will be available again for issuance. |
| (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, 2011.2012. 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 66: Common Stock and Share-Based Compensation of the Notes to the Consolidated Financial Statements in the 20112012 Annual Report.Report, which description is incorporated herein by reference. |
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”Transactions and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company
––Board and Director
Independence and Qualifications”Independence” in the Joint Proxy Statement relating to the
20122013 Annual Meetings of Shareholders, which information is
hereby incorporated
herein by reference.
Item 14.Principal Accountant Fees and Services Information responding to Item 14, for each of PG&E Corporation and the Utility, is includedset forth 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 20122013 Annual Meetings of Shareholders, which information is hereby incorporated herein by reference. Item 15.Exhibits and Financial Statement Schedules(a) | The following documents are filed as a part of this report: |
(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
20112012 Annual Report and are incorporated by reference in this report:
Consolidated Statements of Income for the Years Ended December 31, 2012, 2011, 2010, and 20092010 for each of PG&E Corporation and Pacific Gas and Electric Company. Consolidated
Balance Sheets atStatements of Comprehensive Income for the Years Ended December 31,
2012, 2011, and 2010 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2012 and 2011 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31,
2012, 2011,
2010, and
20092010 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Equity for the Years Ended December 31,
2012, 2011,
2010, and
20092010 for PG&E Corporation.
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31,
2012, 2011,
2010, and
20092010 for Pacific Gas and Electric Company.
Notes to the Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report
Reports 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,
20112012 and
20102011 and for the Years Ended December 31,
2012, 2011,
2010, and
2009.2010.
II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31,
2012, 2011,
2010, and
2009.2010.
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
| | |
Number
| | Exhibit Description |
2.1 | | Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company’sCompany's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1) |
| |
2.2 | | Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company’sCompany's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2) |
| |
3.1 | | Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1) |
| |
3.2 | | Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2) |
Exhibit Number | | Exhibit Description |
3.3 | | Bylaws of PG&E Corporation amended as of September 13, 2011March 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011March 31, 2012 (File No. 1-12609), Exhibit 3.1) |
| |
3.4 | | Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3) |
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3.5 | | Bylaws of Pacific Gas and Electric Company amended as of May 1, 2011June 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2011June 30, 2012 (File No. 1-2348), Exhibit 3.2)3) |
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4.1 | | Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’sCompany's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1) |
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4.2 | | First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1) |
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4.3 | | Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (file(File No. 1-2348), Exhibit 4.1) |
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4.4 | | Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1) |
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4.5 | | Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1) |
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4.6 | | Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1) |
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Exhibit
Number
| | Exhibit Description
|
4.7 | | Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1) |
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4.8 | | Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1) |
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4.9 | | Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1) |
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4.10 | | Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1) |
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4.11 | | Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1) |
Exhibit Number | | Exhibit Description |
4.12 | | Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1) |
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4.13 | | Fourteenth Supplemental Indenture dated as of September 12, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’sCompany's 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1) |
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4.14 | | Fifteenth Supplemental Indenture dated as of November 22, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 22, 2011 (File No. 1-2348), Exhibit 4.1) |
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4.15 | | Sixteenth Supplemental Indenture dated as of December 1, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1) |
| 4.16 | | Seventeenth Supplemental Indenture dated as of April 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1) |
4.16
4.17 | | Eighteenth Supplemental Indenture dated as of August 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1) |
| 4.18 | | Senior Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due April 1, 2014, dated as of March 12, 2009, between PG&E Corporation and Deutsche Bank Trust Company Americas as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1) |
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4.17
4.19 | | First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.2) |
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Exhibit
Number
| | Exhibit Description
|
10.1 | | Credit Agreement, dated May 31, 2011, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.1) |
| 10.2 | | Amendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank |
Exhibit Number | | Exhibit Description |
10.2
10.3 | | Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.2) |
| 10.4 | | Amendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank |
10.3
10.5 | | Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Form 8-K filed December 22, 2003)2003 (File No. 1-12609 and File No. 1-2348), Exhibit 99) |
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10.4
10.6 | | Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8) |
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10.5
10.7 | | Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9) |
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10.6 *
| | Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4) |
| |
10.7 *
| | Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.11) |
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10.8 *
| | Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12) |
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10.9 *
| | Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12) |
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10.10 *
10.8* | | Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation dated May 12, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.3) |
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Exhibit
Number
| | Exhibit Description
|
10.11 *
10.9* | | Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.1) |
| 10.10* | | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.3) |
10.12 *
10.11* | | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011(incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2) |
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10.13 *
10.12* | | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.3) |
| 10.13* | | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.4) |
10.14 *
10.14* | | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.4) |
Exhibit Number | | Exhibit Description |
10.15 *
10.15* | | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5) |
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10.16 *
10.16* | | Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.4) |
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10.17 *
| | Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.18) |
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10.18 *
| | Separation Agreement between PG&E Corporation and Rand S. Rosenberg dated October 31, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.6) |
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10.19 *
10.17* | | Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.18) |
| 10.18* | | Letter regarding Compensation Arrangement between PG&E Corporation and John R. Simon dated March 9, 2007 |
10.20 *
10.19* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.21) |
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10.21 *
| | Severance Agreement between Pacific Gas and Electric Company and John S. KeenanJesus Soto, Jr. dated April 5, 20114, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 20112012 (File No. 1-2348), Exhibit 10.5)10.2) |
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10.22 *
10.20* | | SettlementLetter regarding Compensation Agreement and Release between Pacific Gas and Electric Company and John S. KeenanEdward D. Halpin dated February 3, 2012 for employment starting April 5, 20111, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 20112012 (File No. 1-2348), Exhibit 10.6)10.21) |
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10.23 *
10.21* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.7) |
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10.24 *
10.22* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.8) |
| |
10.25 *
| | Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.18) |
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Exhibit
Number
| | Exhibit Description
|
10.26 *
| | Separation Agreement between Pacific Gas and Electric Company and Edward Salas, as approved by the PG&E Corporation Compensation Committee on June 14, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.12) |
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10.27 *
10.23* | | PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10) |
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10.28 *
10.24* | | PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009 and as further amended with respect to investment options effective as of July 13, 2009 and as of August 1, 2011) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.11) |
| |
10.29
10.25* | | PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24) |
| 10.26* | | PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2) |
10.30
10.27* | | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2011 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.21)2013 |
| |
10.31 *
10.28* | | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 (File No. 1-12609), Exhibit 10.31) |
| |
10.32
10.29* | | Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27) |
Exhibit Number | | Exhibit Description |
10.33 *
10.30* | | Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28) |
| |
10.34
10.31* | | PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.1)January 1, 2013 |
| 10.32* | | PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, effective January 1, 2013 |
10.35
10.33* | | Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30) |
| |
10.36
10.34* | | Postretirement Life Insurance Plan of the Pacific Gas and Electric Company as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K10-Q for fiscal year 1991the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.16)10.7) |
| |
10.37
10.35 * | | Amendment to Postretirement Life Insurance Plan of the Pacific Gas and Electric Company dated December 30, 2008 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.32) |
| |
10.38 *
| | PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27) |
| | |
Exhibit
Number
10.36* | | Exhibit Description
Resolution of the PG&E Corporation Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013 |
10.39 *
10.37* | | Resolution of the Pacific Gas and Electric Company Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013 |
| 10.38* | | Resolution of the PG&E Corporation Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.31) |
| |
10.40
10.39* | | Resolution of the Pacific Gas and Electric Company Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2010 (File No. 1-12348), Exhibit 10.32) |
| |
10.41 *
10.40* | | PG&E Corporation 2006 Long-Term Incentive Plan, as amended througheffective January 1, 2013 |
10.41 * | | PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective June 15, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.10) |
| |
10.42 *
10.42* | | PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10) |
| 10.43* | | Form of Restricted Stock Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.1) |
10.43 *
10.44* | | Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.1) |
| 10.45* | | Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2) |
| 10.46* | | Form of Restricted Stock Unit Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.2) |
| 10.47* | | Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39) |
| |
10.44 *
Exhibit Number | | Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.5)Description |
| |
10.45 *
10.48* | | Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.45) |
| |
10.46 *
10.49* | | Form of Restricted Stock Unit Agreement for 20092012 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 2009 (File No.��1-12609), Exhibit 10.2) |
| |
10.47 *
| | Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010June 30, 2012 (File No. 1-12609), Exhibit 10.2)10.3) |
| |
10.48
10.50* | | Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.1) |
| |
10.49 *
| | Form of Restricted Stock Unit Agreement for 2011 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.9) |
| |
10.50 *
10.51* | | Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’sCompany's Form 8-K filed January 6, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99.1) |
| |
10.51 *
10.52* | | Form of Performance Share Agreement for 20082012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 20082012 (File No. 1-12609), Exhibit 10.6)10.2) |
| |
10.52 *
10.53* | | Form of Amended and Restated Performance Share Agreement for 20082011 grants (amendments to comply with Internal Revenue Code Section 409A Regulations)under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K10-Q for the yearquarter ended DecemberMarch 31, 20082011 (File No. 1-12609), Exhibit 10.53)10.2) |
| 10.54* | | Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3) |
10.53 *
10.55* | | Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.3) |
| | |
Exhibit
Number
| | Exhibit Description
|
10.54 *
| | Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3) |
| |
10.55 *
| | Form of Performance Share Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.2) |
| |
10.56 *
10.56* | | PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.3) |
| 10.57* | | PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2) |
10.57 *
10.58* | | PG&E Corporation 2012 Officer Severance Policy, effective as of March 1, 2012 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.6) |
| 10.59* | | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporatedMarch 1, 2012(incorporated by reference to PG&E Corporation’sCorporation's Form 10-K10-Q for the yearquarter ended DecemberMarch 31, 20052012 (File No. 1-12609), Exhibit 10.48)10.5) |
| |
10.58 *
| | PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.56) |
| |
10.59 *
10.60* | | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51) |
| |
10.60
10.61* | | PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49) |
| |
10.61 *
10.62* | | Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58) |
| |
10.62
10.63* | | PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1) |
| |
10.63
10.64* | | PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39) |
Exhibit Number | | Exhibit Description |
10.64 *
10.65* | | PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54) |
| |
10.65
10.66 * | | Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40) |
| |
10.66
10.67* | | Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41) |
| |
12.1 | | Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company |
| |
12.2 | | Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company |
| |
12.3 | | Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation |
| | |
Exhibit
Number
| | Exhibit Description
|
13 | | The following portions of the 20112012 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s“Management's Discussion and Analysis of Financial Condition and Results of Operations,” financial statements of PG&E Corporation entitled “Consolidated Statements of Income,” “Consolidated Statements of Comprehensive 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 Statements of Comprehensive Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’Shareholders' Equity,” “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Management’s“Management's Report on Internal Control Over Financial Reporting,” and “Report of Independent Registered Public Accounting Firm.” |
| |
21 | | Subsidiaries of the Registrant |
| |
23 | | 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
24 | | 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 2002 |
| |
32.1***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***32.2 | | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 |
| |
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. |
* 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. |
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,
20112012 to be signed on their behalf by the undersigned, thereunto duly authorized.
| | | | | | | | |
| | | | PG&E CORPORATION | | | | PACIFIC GAS AND ELECTRIC COMPANY |
| | | | ANTHONY F. EARLEY, JR. | | | | CHRISTOPHER P. JOHNS |
| | | | Anthony F. Earley, Jr. | | | | Christopher P. Johns |
By: | | | | |
| | By: | | Chairman of the Board, Chief Executive Officer, and President | By: | By:President |
| Date: | February 21, 2013 | Date: | February 21, 2013 |
| | President |
| | | | |
| | Date: | | February 16, 2012 | | Date: | | February 16, 2012 |
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.
| | | | | | | | |
| Signature | | Title | | Title | | | | Date |
| | | | |
| A. Principal Executive Officers | | | | |
| | | | |
| | | | |
* ANTHONY F. EARLEY, JR.
| | | | Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation) | | |
| ANTHONY F. EARLEY, JR. | | February 16, 201221, 2013 | | |
| Anthony F. Earley, Jr. | | |
| | | | |
| | | | |
*CHRISTOPHERCHRISTOPHER P. JOHNS
| | | | President (Pacific (Pacific Gas and Electric Company)
| | | | February 16, 201221, 2013 |
Christopher P. Johns | | |
Christopher P. Johns | | | | | |
| | | | |
| B. Principal Financial Officers | | | | |
| | | | |
| | | | |
*KENTKENT M. HARVEY
| | | | Senior Vice President and Chief Financial Officer and Treasurer (PG&E Corporation)
| | | | February 16, 201221, 2013 |
| Kent M. Harvey | | | |
| | | | |
| | | | |
*DINYARDINYAR B. MISTRY
| | | | Vice President, Chief Financial Officer, and Controller | | (Pacific Gas and Electric Company) | | February 16, 201221, 2013 |
| Dinyar B. Mistry | | | |
(Pacific Gas and Electric Company) | | | | |
| | | | |
| C. Principal Accounting Officer | | | | |
| | | | |
| | | | |
*DINYARDINYAR B. MISTRY
| | | | Vice President and Controller (PG&E Corporation) | | | | February 16, 2012 |
Dinyar B. Mistry | | | | Vice President, Chief Financial Officer, and Controller (Pacific Gas and Electric Company) | | February 21, 2013 |
| Dinyar B. Mistry |
| | | | |
| | | | |
| D. Directors | | | | | | | | |
| | | | |
*DAVID R. ANDREWS
| | | | Director | | February 21, 2013 |
| David R. Andrews | | February 16, 2012 |
David R. Andrews(1) | | |
|
|
| | | | | | |
(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. |
| | | | | | | | |
| | | | |
*LEWIS*LEWIS CHEW
| | | | Director | | | | February 16, 201221, 2013 |
| Lewis Chew | | | | |
| | | | |
| | | | | | | | |
*C.*C. LEE COX
| | | | Director | | | | February 16, 201221, 2013 |
| C. Lee Cox | | | | |
| | | | |
| | | | |
*ANTHONY*ANTHONY F. EARLEY, JR.
| | | | Director (PG&E Corporation only) | | | | February 16, 201221, 2013 |
| Anthony F. Earley, Jr. | | | | |
| | | | |
| | | | |
*MARYELLEN C. HERRINGER
| | *FRED J. FOWLER | | Director | | February 21, 2013 |
| Fred J. Fowler | | | | |
| | | | |
| *MARYELLEN C. HERRINGER | | Director | | February 16, 201221, 2013 |
| Maryellen C. Herringer | | | | |
| | | | |
| | | | |
*CHRISTOPHER*CHRISTOPHER P. JOHNS
| | | | Director (Pacific Gas and Electric Company only) | | | | February 16, 201221, 2013 |
| Christopher P. Johns | | | | |
| | | | |
| | | | |
*ROGER*ROGER H. KIMMEL
| | | | Director | | | | February 16, 201221, 2013 |
| Roger H. Kimmel | | | | |
| | | | |
| | | | |
*RICHARD*RICHARD A. MESERVE
| | | | Director | | | | February 16, 201221, 2013 |
| Richard A. Meserve | | | | |
| | | | |
| | | | |
*FORREST*FORREST E. MILLER
| | | | Director | | | | February 16, 201221, 2013 |
| Forrest E. Miller | | | | |
| | | | |
| | | | |
*ROSENDO*ROSENDO G. PARRA
| | | | Director | | | | February 16, 201221, 2013 |
| Rosendo G. Parra | | | | |
| | | | |
| | | | |
*BARBARA*BARBARA L. RAMBO
| | | | Director | | | | February 16, 201221, 2013 |
| Barbara L. Rambo | | |
| | | | |
| | | | |
*BARRY*BARRY LAWSON WILLIAMS
| | | | Director | | | | February 16, 201221, 2013 |
| Barry Lawson Williams | | |
| | | | |
| *By: | HYUN PARK | | | | | |
| HYUN PARK, Attorney-in-Fact | | | | | |
| | |
*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,
20112012 and
2010,2011, and for each of the three years in the period ended December 31,
2011,2012, and the
Company’sCompany's and the Utility’s internal control over financial reporting as of December 31,
2011,2012, and have issued our
reportreports thereon dated February
16, 201221, 2013 (which report
on the consolidated financial statements 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 reportreports are included in your
20112012 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)2.15. These consolidated financial statement schedules are the responsibility of the
Company’sCompany'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
February 21, 2013
SCHEDULE I—
CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED STATEMENTS OF INCOME
(in AND COMPREHENSIVE INCOME
(in millions, except per share amounts)
| | | september 30 | | | | september 30 | | | | september 30 | |
| | | Year Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
Administrative service revenue | | | $ 44 | | | | $ 53 | | | | $ 59 | |
Operating expenses | | | (44) | | | | (55) | | | | (61) | |
Interest income | | | 1 | | | | 1 | | | | 1 | |
Interest expense | | | (22) | | | | (35) | | | | (43) | |
Other income (expense) | | | (17) | | | | 4 | | | | 11 | |
Equity in earnings of subsidiaries | | | 852 | | | | 1,105 | | | | 1,231 | |
| | | | | | | | | | | | |
Income before income taxes | | | 814 | | | | 1,073 | | | | 1,198 | |
Income tax benefit | | | 30 | | | | 26 | | | | 22 | |
| | | | | | | | | | | | |
Income Available for Common Shareholders | | | $ 844 | | | | $ 1,099 | | | | $ 1,220 | |
| | | | | | | | | | | | |
| | | |
Weighted average common shares outstanding, basic | | | 401 | | | | 382 | | | | 368 | |
| | | | | | | | | | | | |
| | | |
Weighted average common shares outstanding, diluted | | | 402 | | | | 392 | | | | 386 | |
| | | | | | | | | | | | |
Earnings per common share, basic | | | $ 2.10 | | | | $ 2.86 | | | | $ 3.25 | |
| | | | | | | | | | | | |
Earnings per common share, diluted | | | $ 2.10 | | | | $ 2.82 | | | | $ 3.20 | |
| | | | | | | | | | | | |
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,
| | | Year Ended December 31, | |
| | | | | | | | | | |
| Administrative service revenue | | $ | 43 | | | $ | 44 | | | $ | 53 | |
| Operating expenses | | | (41 | ) | | | (44 | ) | | | (55 | ) |
| Interest income | | | 1 | | | | 1 | | | | 1 | |
| Interest expense | | | (22 | ) | | | (22 | ) | | | (35 | ) |
| Other income (expense) | | | (39 | ) | | | (17 | ) | | | 4 | |
| Equity in earnings of subsidiaries | | | 817 | | | | 852 | | | | 1,105 | |
| Income before income taxes | | | 759 | | | | 814 | | | | 1,073 | |
| Income tax benefit | | | 57 | | | | 30 | | | | 26 | |
| Net income | | $ | 816 | | | $ | 844 | | | $ | 1,099 | |
| Other Comprehensive Income | | | | | | | | | | | | |
| Pension and other postretirement benefit plans (net of income tax of $72, $9, $25 in 2012, 2011, and 2010, respectively) | | | 108 | | | | (11 | ) | | | (42 | ) |
| Other (net of income tax of $3 in 2012) | | | 4 | | | | - | | | | - | |
| Total other comprehensive income (loss) | | | 112 | | | | (11 | ) | | | (42 | ) |
| Comprehensive Income | | $ | 928 | | | $ | 833 | | | $ | 1,057 | |
| Weighted average common shares outstanding, basic | | | 424 | | | | 401 | | | | 382 | |
| Weighted average common shares outstanding, diluted | | | 425 | | | | 402 | | | | 392 | |
| Net earnings per common share, basic | | $ | 1.92 | | | $ | 2.10 | | | $ | 2.86 | |
| Net earnings per common share, diluted | | $ | 1.92 | | | $ | 2.10 | | | $ | 2.82 | |
PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.
In addition, during 2010, PG&E Corporation applied the “if-converted” method to reflect the impact of the Convertible Subordinated Notes to the extent it was dilutive when compared to basic EPS.
SCHEDULE I—
CONDENSED FINANCIAL INFORMATION OF PARENT— – (Continued) (in millions)
| | | september 30 | | | | september 30 | |
| | | Balance at December 31, | |
| | | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
Current Assets | | | | | | | | |
Cash and cash equivalents | | | $ 209 | | | | $ 240 | |
Advances to affiliates | | | 18 | | | | 25 | |
Income taxes receivable | | | 8 | | | | 1 | |
Deferred income taxes | | | 4 | | | | 5 | |
| | | | | | | | |
Total current assets | | | 239 | | | | 271 | |
| | | | | | | | |
Noncurrent Assets | | | | | | | | |
Equipment | | | 14 | | | | 14 | |
Accumulated depreciation | | | (14) | | | | (14) | |
| | | | | | | | |
Net equipment | | | – | | | | – | |
Investments in subsidiaries | | | 12,378 | | | | 11,618 | |
Other investments | | | 94 | | | | 89 | |
Income taxes receivable | | | 2 | | | | – | |
Deferred income taxes | | | 143 | | | | 116 | |
Other | | | 2 | | | | 2 | |
| | | | | | | | |
Total noncurrent assets | | | 12,619 | | | | 11,825 | |
| | | | | | | | |
Total Assets | | | $ 12,858 | | | | $ 12,096 | |
| | | | | | | | |
| | |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | |
Current Liabilities | | | | | | | | |
Accounts payable – related parties | | | $ – | | | | $ 106 | |
Accounts payable – other | | | 21 | | | | 3 | |
Income taxes payable | | | 57 | | | | 1 | |
Other | | | 208 | | | | 213 | |
| | | | | | | | |
Total current liabilities | | | 286 | | | | 323 | |
| | | | | | | | |
Noncurrent Liabilities | | | | | | | | |
Long-term debt | | | 349 | | | | 349 | |
Income taxes payable | | | 3 | | | | 48 | |
Other | | | 119 | | | | 94 | |
| | | | | | | | |
Total noncurrent liabilities | | | 471 | | | | 491 | |
| | | | | | | | |
Common Shareholders’ Equity | | | | | | | | |
Common stock | | | 7,602 | | | | 6,878 | |
Reinvested earnings | | | 4,712 | | | | 4,606 | |
Accumulated other comprehensive loss | | | (213) | | | | (202) | |
| | | | | | | | |
Total common shareholders’ equity | | | 12,101 | | | | 11,282 | |
| | | | | | | | |
Total Liabilities and Shareholders’ Equity | | | $ 12,858 | | | | $ 12,096 | |
| | | | | | | | |
| | | | |
| | | | | | | |
| ASSETS | | | | | | |
| Current Assets | | | | | | |
| Cash and cash equivalents | | $ | 207 | | | $ | 209 | |
| Advances to affiliates | | | 26 | | | | 18 | |
| Income taxes receivable | | | 33 | | | | 8 | |
| Deferred income taxes | | | - | | | | 4 | |
| Total current assets | | | 266 | | | | 239 | |
| Noncurrent Assets | | | | | | | | |
| Equipment | | | 1 | | | | 14 | |
| Accumulated depreciation | | | (1 | ) | | | (14 | ) |
| Net equipment | | | - | | | | - | |
| Investments in subsidiaries | | | 13,387 | | | | 12,378 | |
| Other investments | | | 102 | | | | 94 | |
| Income taxes receivable | | | 5 | | | | 2 | |
| Deferred income taxes | | | 178 | | | | 143 | |
| Other | | | 1 | | | | 2 | |
| Total noncurrent assets | | | 13,673 | | | | 12,619 | |
| Total Assets | | $ | 13,939 | | | $ | 12,858 | |
| | | | | | | | | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | |
| Current Liabilities | | | | | | | | |
| Short-term borrowings | | $ | 120 | | | $ | - | |
| Accounts payable – other | | | 48 | | | | 21 | |
| Income taxes payable | | | - | | | | 57 | |
| Other | | | 221 | | | | 208 | |
| Total current liabilities | | | 389 | | | | 286 | |
| Noncurrent Liabilities | | | | | | | | |
| Long-term debt | | | 349 | | | | 349 | |
| Other | | | 127 | | | | 122 | |
| Total noncurrent liabilities | | | 476 | | | | 471 | |
| Common Shareholders’ Equity | | | | | | | | |
| Common stock | | | 8,428 | | | | 7,602 | |
| Reinvested earnings | | | 4,747 | | | | 4,712 | |
| Accumulated other comprehensive loss | | | (101 | ) | | | (213 | ) |
| Total common shareholders’ equity | | | 13,074 | | | | 12,101 | |
| Total Liabilities and Shareholders’ Equity | | $ | 13,939 | | | $ | 12,858 | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
| | september 30 | | | september 30 | | | | september 30 | | | | september 30 | |
| | | Year Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
Cash Flows from Operating Activities: | | | | | | | | | | | | |
Net income | | $ | 844 | | | $ | 1,099 | | | $ | 1,220 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | |
Depreciation and amortization | | | 36 | | | | 38 | | | | 20 | |
Equity in earnings of subsidiaries | | | (852) | | | | (1,105) | | | | (1,231) | |
Deferred income taxes and tax credits, net | | | (26) | | | | 19 | | | | – | |
Noncurrent income taxes receivable/payable | | | (47) | | | | 34 | | | | (9) | |
Current income taxes receivable/payable | | | 49 | | | | (1) | | | | 148 | |
Other | | | (80) | | | | (50) | | | | (13) | |
| | | | | | | | | | | | | | |
Net cash provided by (used in) operating activities | | | (76) | | | | 34 | | | | 135 | |
| | | | | | | | | | | | | | |
Cash Flows From Investing Activities: | | | | | | | | | | | | | | |
Investment in subsidiaries | | | (759) | | | | (347) | | | | (721) | |
Dividends received from subsidiaries(1) | | | 716 | | | | 716 | | | | 624 | |
Proceeds from tax equity investments | | | 129 | | | | 7 | | | | – | |
Other | | | – | | | | (4) | | | | 10 | |
| | | | | | | | | | | | | | |
Net cash provided by (used in) investing activities | | | 86 | | | | 372 | | | | (87) | |
| | | | | | | | | | | | | | |
Cash Flows From Financing Activities: | | | | | | | | | | | | | | |
Borrowings under revolving credit facilities | | | 150 | | | | 90 | | | | – | |
Repayments under revolving credit facilities | | | (150) | | | | (90) | | | | – | |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2009 | | | – | | | | – | | | | 348 | |
Common stock issued | | | 662 | | | | 303 | | | | 219 | |
Common stock dividends paid(2) | | | (704) | | | | (662) | | | | (590) | |
Other | | | 1 | | | | – | | | | 1 | |
| | | | | | | | | | | | | | |
Net cash used in financing activities | | | (41) | | | | (359) | | | | (22) | |
| | | | | | | | | | | | | | |
Net change in cash and cash equivalents | | | (31) | | | | 47 | | | | 26 | |
Cash and cash equivalents at January 1 | | | 240 | | | | 193 | | | | 167 | |
| | | | | | | | | | | | | | |
Cash and cash equivalents at December 31 | | $ | 209 | | | $ | 240 | | | $ | 193 | |
| | | | | | | | | | | | | | |
(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,
| | | Year Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| Cash Flows from Operating Activities: | | | | | | | | | |
| Net income | | $ | 816 | | | $ | 844 | | | $ | 1,099 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
| Stock-based compensation amortization | | | 51 | | | | 36 | | | | 38 | |
| Equity in earnings of subsidiaries | | | (817 | ) | | | (852 | ) | | | (1,105 | ) |
| Deferred income taxes and tax credits, net | | | (31 | ) | | | (26 | ) | | | 19 | |
| Noncurrent income taxes receivable/payable | | | (6 | ) | | | (47 | ) | | | 34 | |
| Current income taxes receivable/payable | | | (82 | ) | | | 49 | | | | (1 | ) |
| Other | | | 20 | | | | (80 | ) | | | (50 | ) |
| Net cash provided by (used in) operating activities | | | (49 | ) | | | (76 | ) | | | 34 | |
| Cash Flows From Investing Activities: | | | | | | | | | | | | |
| Investment in subsidiaries | | | (1,023 | ) | | | (759 | ) | | | (347 | ) |
Dividends received from subsidiaries (1) | | | 716 | | | | 716 | | | | 716 | |
| Proceeds from tax equity investments | | | 228 | | | | 129 | | | | 7 | |
| Other | | | - | | | | - | | | | (4 | ) |
| Net cash provided by (used in) investing activities | | | (79 | ) | | | 86 | | | | 372 | |
| Cash Flows From Financing Activities: | | | | | | | | | | | | |
| Borrowings under revolving credit facilities | | | 120 | | | | 150 | | | | 90 | |
| Repayments under revolving credit facilities | | | - | | | | (150 | ) | | | (90 | ) |
| Common stock issued | | | 751 | | | | 662 | | | | 303 | |
Common stock dividends paid (2) | | | (746 | ) | | | (704 | ) | | | (662 | ) |
| Other | | | 1 | | | | 1 | | | | - | |
| Net cash provided by (used in) financing activities | | | 126 | | | | (41 | ) | | | (359 | ) |
| Net change in cash and cash equivalents | | | (2 | ) | | | (31 | ) | | | 47 | |
| Cash and cash equivalents at January 1 | | | 209 | | | | 240 | | | | 193 | |
Cash and cash equivalents at December 31 | | $ | 207 | | | $ | 209 | | | $ | 240 | |
| Supplemental disclosures of cash flow information | | | | | | | | | | | | |
| Cash received (paid) for: | | | | | | | | | | | | |
| Interest, net of amounts capitalized | | $ | (20 | ) | | $ | (20 | ) | | $ | (20 | ) |
Income taxes, net | | | (60 | ) | | | 8 | | | | 36 | |
| Supplemental disclosures of noncash investing and financing | | | | | | | | | | | | |
| activities | | | | | | | | | | | | |
| Noncash common stock issuances | | $ | 22 | | | $ | 24 | | | $ | 265 | |
| Common stock dividends declared but not yet paid | | | 196 | | | | 188 | | | | 183 | |
| | | | | | | | | | | | | |
(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow. |
| (2) On January 15, April 15, July 15, October 15, 2012, PG&E Corporation paid quarterly common stock dividends of $0.455 per share. |
| | |
| 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. |
| | |
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,
2012, 2011,
2010, and
20092010
(in millions)
| | | september 30000 | | | | september 30000 | | | | september 30000 | | | | september 30000 | | | | september 30000 | |
| | | | | | Additions | | | | | | | |
Description | | Balance at
Beginning of
Period | | | Charged to
Costs and
Expenses | | | Charged to
Other
Accounts | | | Deductions (2) | | | Balance at End
of Period | |
| Valuation and qualifying accounts deducted from assets: | | | | | | | | | | | | | | | | | | | | |
2011: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | | $ 81 | | | | $ 60 | | | | $ - | | | | $ 60 | | | | $ 81 | |
| | | | | | | | | | | | | | | | | | | | |
2010: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | | $ 68 | | | | $ 56 | | | | $ - | | | | $ 43 | | | | $ 81 | |
| | | | | | | | | | | | | | | | | | | | |
2009: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | | $ 76 | | | | $ 68 | | | | $ - | | | | $ 76 | | | | $ 68 | |
| | | | | | | | | | | | | | | | | | | | |
| (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.
|
| | | | | | | | | | | | | |
| | Balance at Beginning of Period | | | Charged to Costs and Expenses | | | Charged to Other Accounts | | | | | | | |
| Valuation and qualifying accounts deducted from assets: | | | | | | | | | | | | | | | |
| 2012: | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | $ | 81 | | | $ | 66 | | | $ | - | | | $ | 60 | | | $ | 87 | |
| 2011: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | $ | 81 | | | $ | 60 | | | $ | - | | | $ | 60 | | | $ | 81 | |
| 2010: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | $ | 68 | | | $ | 56 | | | $ | - | | | $ | 43 | | | $ | 81 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
(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,
2012, 2011,
2010, and
20092010
(in millions)
| | | september 30000 | | | | september 30000 | | | | september 30000 | | | | september 30000 | | | | september 30000 | |
| | | | | | Additions | | | | | | | |
Description | | Balance at
Beginning of
Period | | | Charged to
Costs and
Expenses | | | Charged to
Other
Accounts | | | Deductions(2) | | | Balance at
End of Period | |
| Valuation and qualifying accounts deducted from assets: | | | | | | | | | | | | | | | | | | | | |
2011: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | | $ 81 | | | | $ 60 | | | | $ - | | | | $ 60 | | | | $ 81 | |
2010: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | | $ 68 | | | | $ 56 | | | | $ - | | | | $ 43 | | | | $ 81 | |
| | | | | | | | | | | | | | | | | | | | |
2009: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | | $ 76 | | | | $ 68 | | | | $ - | | | | $ 76 | | | | $ 68 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | Balance at Beginning of Period | | | Charged to Costs and Expenses | | | Charged to Other Accounts | | | | | | | |
| Valuation and qualifying accounts deducted from assets: | | | | | | | | | | | | | | | |
| 2012: | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | $ | 81 | | | $ | 66 | | | $ | - | | | $ | 60 | | | $ | 87 | |
| 2011: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | $ | 81 | | | $ | 60 | | | $ | - | | | $ | 60 | | | $ | 81 | |
| 2010: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) | | $ | 68 | | | $ | 56 | | | $ | - | | | $ | 43 | | | $ | 81 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
(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
| (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
| | |
Number
| | Exhibit Description |
2.1 | | Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company’sCompany's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1) |
| |
2.2 | | Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company’sCompany's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2) |
| |
3.1 | | Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1) |
| |
3.2 | | Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2) |
| |
3.3 | | Bylaws of PG&E Corporation amended as of September 13, 2011March 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011March 31, 2012 (File No. 1-12609), Exhibit 3.1) |
| |
3.4 | | Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3) |
| |
3.5 | | Bylaws of Pacific Gas and Electric Company amended as of May 1, 2011June 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2011June 30, 2012 (File No. 1-2348), Exhibit 3.2)3) |
| |
4.1 | | Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’sCompany's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1) |
| |
4.2 | | First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1) |
| |
4.3 | | Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (file(File No. 1-2348), Exhibit 4.1) |
| |
4.4 | | Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1) |
| |
4.5 | | Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1) |
| | |
Exhibit
Number
| | Exhibit Description |
4.6 | | Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1) |
Exhibit Number | | Exhibit Description |
4.7 | | Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1) |
| |
4.8 | | Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1) |
| |
4.9 | | Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1) |
| |
4.10 | | Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1) |
| |
4.11 | | Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1) |
| |
4.12 | | Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1) |
| |
4.13 | | Fourteenth Supplemental Indenture dated as of September 12, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’sCompany's 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1) |
| |
4.14 | | Fifteenth Supplemental Indenture dated as of November 22, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 22, 2011 (File No. 1-2348), Exhibit 4.1) |
| |
4.15 | | Sixteenth Supplemental Indenture dated as of December 1, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1) |
| 4.16 | | Seventeenth Supplemental Indenture dated as of April 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1) |
4.16
4.17 | | Eighteenth Supplemental Indenture dated as of August 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1) |
| 4.18 | | Senior Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due April 1, 2014, dated as of March 12, 2009, between PG&E Corporation and Deutsche Bank Trust Company Americas as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1) |
| | |
Number
| | Exhibit Description |
4.17
4.19 | | First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.2) |
| |
10.1 | | Credit Agreement, dated May 31, 2011, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.1) |
| 10.2 | | Amendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank |
10.2
10.3 | | Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.2) |
| 10.4 | | Amendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank |
10.3
10.5 | | Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation’sCorporation's and Pacific Gas and Electric Company’sCompany's Form 8-K filed December 22, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 99) |
| |
10.4
10.6 | | Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8) |
| |
10.5
10.7 | | Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9) |
| |
10.6 *
| | Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4) |
| |
10.7 *
| | Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.11) |
| |
10.8 *
| | Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12) |
| |
10.9 *
| | Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12) |
| | |
Exhibit
Number
| | Exhibit Description |
10.10 *
10.8* | | Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation dated May 12, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.3) |
Exhibit Number | | Exhibit Description |
10.11 *
10.9* | | Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.1) |
| 10.10* | | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.3) |
10.12 *
10.11* | | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2) |
| 10.12* | | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2) |
| |
10.13 *
| | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.3) |
| 10.13* | | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.4) |
10.14 *
10.14* | | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.4) |
| |
10.15 *
10.15* | | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5) |
| |
10.16 *
10.16* | | Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.4) |
| |
10.17 *
| | Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.18) |
| |
10.18 *
| | Separation Agreement between PG&E Corporation and Rand S. Rosenberg dated October 31, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.6) |
| |
10.19 *
10.17* | | Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.18) |
| 10.18* | | Letter regarding Compensation Arrangement between PG&E Corporation and John R. Simon dated March 9, 2007 |
10.20 *
10.19* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.21) |
| |
10.21 *
| | Severance Agreement between Pacific Gas and Electric Company and John S. KeenanJesus Soto, Jr. dated April 5, 20114, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 20112012 (File No. 1-2348), Exhibit 10.5)10.2) |
| |
10.22 *
10.20* | | SettlementLetter regarding Compensation Agreement and Release between Pacific Gas and Electric Company and John S. KeenanEdward D. Halpin dated February 3, 2012 for employment starting April 5, 20111, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 20112012 (File No. 1-2348), Exhibit 10.6)10.21) |
| |
10.23 *
10.21* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.7) |
| |
10.24 *
10.22* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.8) |
| | |
Exhibit
Number
| | Exhibit Description |
10.25 *
| | Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.18) |
| |
10.26 *
| | Separation Agreement between Pacific Gas and Electric Company and Edward Salas, as approved by the PG&E Corporation Compensation Committee on June 14, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.12) |
| |
10.27 *
10.23* | | PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10) |
| |
10.28 *
10.24* | | PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009 and as further amended with respect to investment options effective as of July 13, 2009 and as of August 1, 2011) (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.11) |
Exhibit Number | | Exhibit Description |
10.29
10.25* | | PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24) |
| 10.26* | | PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2) |
10.30
10.27* | | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2011 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.21)2013 |
| |
10.31 *
10.28* | | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 (File No. 1-12609), Exhibit 10.31) |
| |
10.32
10.29* | | Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27) |
| |
10.33 *
10.30* | | Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28) |
| |
10.34
10.31* | | PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.1)January 1, 2013 |
| 10.32* | | PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, effective January 1, 2013 |
10.35
10.33* | | Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30) |
| |
10.36
10.34* | | Postretirement Life Insurance Plan of the Pacific Gas and Electric Company as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company’sCompany's Form 10-K10-Q for fiscal year 1991the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.16)10.7) |
| |
10.37
10.35 * | | Amendment to Postretirement Life Insurance Plan of the Pacific Gas and Electric Company dated December 30, 2008 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.32) |
| | |
| | Exhibit Description |
10.38 *
| | PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27) |
| 10.36* | | Resolution of the PG&E Corporation Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013 |
10.39 *
10.37* | | Resolution of the Pacific Gas and Electric Company Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013 |
| 10.38* | | Resolution of the PG&E Corporation Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.31) |
| |
10.40
10.39* | | Resolution of the Pacific Gas and Electric Company Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2010 (File No. 1-12348), Exhibit 10.32) |
| |
10.41 *
10.40* | | PG&E Corporation 2006 Long-Term Incentive Plan, as amended througheffective January 1, 2013 |
| 10.41* | | PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective June 15, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.10) |
| |
10.42 *
10.42* | | PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10) |
Exhibit Number | | Exhibit Description |
10.43 *
10.43* | | Form of Restricted Stock Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.1) |
| 10.44* | | Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.1) |
| 10.45* | | Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2) |
| 10.46* | | Form of Restricted Stock Unit Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.2) |
| 10.47* | | Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39) |
| |
10.44 *
| | Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.5) |
| |
10.45 *
10.48* | | Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.45) |
| |
10.46 *
10.49* | | Form of Restricted Stock Unit Agreement for 20092012 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 2009June 30, 2012 (File No. 1-12609), Exhibit 10.2)10.3) |
| |
10.47
10.50* | | Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2) |
| |
10.48 *
| | Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.1) |
| |
10.49 *
| | Form of Restricted Stock Unit Agreement for 2011 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.9) |
| |
10.50 *
10.51* | | Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’sCompany's Form 8-K filed January 6, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99.1) |
| |
10.51 *
10.52* | | Form of Performance Share Agreement for 20082012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 20082012 (File No. 1-12609), Exhibit 10.6) |
| | 10.2) |
Exhibit
Number
| | Exhibit Description |
10.52 *
10.53* | | Form of Amended and Restated Performance Share Agreement for 20082011 grants (amendments to comply with Internal Revenue Code Section 409A Regulations)under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K10-Q for the yearquarter ended DecemberMarch 31, 20082011 (File No. 1-12609), Exhibit 10.53)10.2) |
| 10.54* | | Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3) |
10.53 *
10.55* | | Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.3) |
| |
10.54 *
| | Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3) |
| |
10.55 *
| | Form of Performance Share Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.2) |
| |
10.56 *
10.56* | | PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.3) |
| 10.57* | | PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2) |
10.57 *
10.58* | | PG&E Corporation 2012 Officer Severance Policy, effective as of March 1, 2012 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.6) |
Exhibit Number | | Exhibit Descrkiption |
| 10.59* | | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporatedMarch 1, 2012(incorporated by reference to PG&E Corporation’sCorporation's Form 10-K10-Q for the yearquarter ended DecemberMarch 31, 20052012 (File No. 1-12609), Exhibit 10.48)10.5) |
| |
10.58 *
| | PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.56) |
| |
10.59 *
10.60* | | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51) |
| |
10.60
10.61* | | PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49) |
| |
10.61 *
10.62* | | Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58) |
| |
10.62
10.63* | | PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1) |
| |
10.63
10.64* | | PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39) |
| |
10.64 *
10.65* | | PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54) |
| |
10.65
10.66 * | | Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation’sCorporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40) |
| |
10.66
10.67* | | Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41) |
| |
12.1 | | Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company |
| | |
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 |
| |
13 | | The following portions of the 20112012 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: “Selected Financial Data,” “Management’s“Management's Discussion and Analysis of Financial Condition and Results of Operations,” financial statements of PG&E Corporation entitled “Consolidated Statements of Income,” “Consolidated Statements of Comprehensive 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 Statements of Comprehensive Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’Shareholders' Equity,” “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Management’s“Management's Report on Internal Control Over Financial Reporting,” and “Report of Independent Registered Public Accounting Firm.” |
| |
21 | | Subsidiaries of the Registrant |
| |
23 | | 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
24 | | Powers of Attorney |
Exhibit Number | | Exhibit Description |
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 2002 |
| |
**32.1
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
32.2** | | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 |
| |
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.
| * | 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. |
