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, 2010
Or
¨For the Fiscal Year Ended December 31, 2012 |
| Or |
| | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period fromto
| | | | | | |
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 |
| | |
One Market, Spear Tower Suite 2400
77 Beale Street, P.O. Box 770000 San Francisco, California 9410594177 (Address of principal executive offices) (Zip Code) (415) 267-7000 (Registrant'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)
| | (415) 973-7000
(Registrant’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 | | | | Yes þ No |
PG&E Corporation
| | Yes x No ¨ | | |
Pacific Gas and Electric Company | | Yes xþ 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 No þ |
PG&E Corporation
| | Yes ¨ No x | | |
Pacific Gas and Electric Company | | Yes ¨ No xþ | | |
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 | | | | Yes þ No |
PG&E Corporation
| | Yes x No ¨ | | |
Pacific Gas and Electric Company | | Yes xþ 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 xþ 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 |
| | PG&E Corporation
| | x |
| | Pacific Gas and Electric Company | | xþ |
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 | | PG&E Corporation | | Pacific Gas and Electric Company |
| | Large accelerated filerx
| | Large accelerated filer ¨þ |
| | Large accelerated filer |
Accelerated filer ¨ | | Accelerated filer ¨ |
| Non-accelerated filer | | Non-accelerated filer ¨þ | | Non-accelerated filer x |
| | 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 No þ |
PG&E Corporation
| | Yes ¨ No x | | |
Pacific Gas and Electric Company | | Yes ¨ No xþ | | |
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30,
2010,2012, the last business day of the most recently completed second fiscal quarter:
| | |
PG&E Corporation Common Stockcommon stock | | $16,024$19,276 million |
Pacific Gas and Electric Company Common Stockcommon stock | | Wholly owned by PG&E Corporation |
Common Stock outstanding as of February 7, 2011:
| Common Stock outstanding as of February 11, 2013: | | |
| PG&E Corporation: | | 396,258,407 shares431,436,673 |
| 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 20092012 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 20102013 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 whose primary purpose is to hold interests in energy-based businesses. PG&E Corporationthat conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The
Utility served approximately 5.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2010. The Utility had approximately $45.7 billion in assets at December 31, 2010 and generated revenues of $13.8 billion in 2010. ItsUtility’s revenues are generated mainly through the sale and delivery of electricity and natural
gas.gas to customers. The Utility served approximately 5.2 million electricity distribution customers and approximately 4.4 million natural gas distribution customers at December 31, 2012. The Utility had approximately $52 billion in assets at December 31, 2012 and generated revenues of approximately $15 billion in 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 officeoffices of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility isare 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 itsthe 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 .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,
20102012, which is attached to this report as Exhibit 13 (“
20102012 Annual Report”) and the Joint Proxy Statement relating to the
20112013 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, 2010,2012, PG&E Corporation and its subsidiaries had 19,42420,593 regular employees, including 19,38120,583 regular employees of the Utility. Of the Utility’s regular employees, 12,23612,492 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 expires on December 31, 20112014 and the other IBEW collective bargaining agreement expires on December 31, 2015. The ESC collective bargaining agreement expires on December 31, 2011.2014. The SEIU collective bargaining agreement expires on July 31, 2012.2013.
Various aspects of the
National Transportation Safety Board (“NTSB”)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
CPUC have begun investigations“Ratemaking Mechanisms” section below summarize some of the
September 9, 2010 rupturemore significant laws, regulations, and regulatory proceedings affecting the Utility. These summaries are not an exhaustive description of
an underground 30-inch natural gas transmission pipeline (line 132) ownedall the laws, regulations, and
operated byregulatory proceedings that affect the
UtilityUtility. The energy laws, regulations, and regulatory proceedings may change or be implemented or applied in a
residential area located in the City of San Bruno, California (the “San Bruno accident”).The ensuing explosion and fire resulted in the deaths of eight people and injuries to numerous individuals. At least thirty-four houses were destroyed and many additional houses were damaged. The NTSB has not yet determined the cause of the pipeline rupture. The NTSB has publicly issued some preliminary reports and has announcedway that it will hold fact-finding hearings on March 1-3, 2011 to learn more about the San Bruno accident and important safety issues.
Various lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility. (See Item 3. Legal Proceedings, below.) In addition, on November 19, 2010, the CPUC began a formal investigation of the December 24, 2008 natural gas explosion in a house located in Rancho Cordova, California that resulted in one death, injuries to several people, and property damage (the “Rancho Cordova accident”). For more information about these investigations and related matters see “Pending Investigations” and “Risk Factors” in the 2010 Annual Report.
Cautionary Language Regarding Forward-Looking Statements
This combined Annual Report on Form 10-K, including the information incorporated by reference from the 2010 Annual Report and the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations and projections about future events, and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated environmental remediation, tax, and other liabilities, estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies, the anticipated outcome of various regulatory, governmental, and legal proceedings, estimated losses and insurance recoveries associated with the San Bruno accident, estimated future cash flows, and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:
the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels and timely recover its costs through rates;
the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigations by the NTSB and CPUC into the cause of the San Bruno accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory, the CPUC investigation of the Rancho Cordova accident, whether the Utility incurs civil or criminal penalties as a result of these proceedings whether the Utility is required to incur additional costs for third-party liability claims or to comply with regulatory or legislative mandates which costs the Utility is unable to recover through rates or insurance, and whether the Utility incurs third-party liabilities or other costs in connection with service disruptions that may occur as the Utility complies with regulatory orders to decrease pressure in its natural gas transmission system;
reputational harm that PG&E Corporation and the Utility may suffer depending on the outcome of the various investigations, including those by the NTSB and the CPUC, the outcome of civil litigation, and the extent to which civil or criminal proceedings may be pursued by regulatory or governmental agencies;
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, and the ability of the Utility and its counterparties to post or return collateral;
explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems, human errors, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;
the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, 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;
changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or other reasons;
the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon Power Plant (“Diablo Canyon”), the availability of nuclear fuel, the outcome of the Utility’s application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies with respect to the storage of spent nuclear fuel, security, safety, cooling water intake, or other matters associated with the operations at Diablo Canyon;
whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;
the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies;
whether the Utility can successfully complete its program to install advanced meters for its electric and natural gas customers, allay customer concerns about the new metering technology, and integrate the new meters with its customer billing and other systems while also implementing the system design changes necessary to accommodate retail electric rates based on dynamic pricing (i.e., electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices) by the CPUC’s due dates;
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 the extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;
the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, including those arising from the San Bruno accident, 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 laws and regulations addressing the reduction of carbon dioxide and other greenhouse gases (“GHG”), water, the remediation of hazardous waste, and other matters, and whether the Utility is able to recover the costs of compliance with such laws, including the cost of emission allowances and offsets that the Utility may incur under federal or state cap and trade regulations;
the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties 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 risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” in the 2010 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.
currently anticipate.
PG&E
Corporation’s Regulatory EnvironmentFederal Energy Regulation
AsCorporation is a public utility holding company PG&E Corporationthat is subject to the requirements of the Energy Policy Act of 2005 (“EPAct”). Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”PUHCA”). Under the PUHCA, 2005, public utility holding companies fall principally under the regulatory oversight of the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of the PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.
State Energy Regulation
PG&E Corporation is not a public utility under California law. The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:
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. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935, as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938, and the Public Utility Regulatory Policies Act of 1978 (“PURPA”).
This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory mechanisms affecting the Utility. These summaries are not an exhaustive description of all the laws, regulations, and regulatory proceedings that affect the Utility. The energy laws, regulations, and regulatory proceedings may change or be implemented or applied in a way that the Utility does not currently anticipate. For discussion of specific pending regulatory proceedings and investigations that are expected to affect the Utility, see the information under the headings within MD&A entitled “Regulatory Matters” and “Pending Investigations”“Natural Gas Matters” in the 20102012 Annual Report.
Report, which information is incorporated herein by reference.
Federal Regulation
The Federal Energy
RegulationThe FERC. 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
requirements(“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 under the EPAct.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, will also performperforms a regular compliance audit of the Utility every three years. In addition, the WECC and the NERC may perform
spot checks or other interim audits, reports, or investigations. 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 needed 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.
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 PURPA, electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that meet the statutory definition of a qualifying facility (“QF”). (QFs primarily include co-generation facilities that produce combined heat and power (“CHP”) and renewable generation facilities.) To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms, conditions, prices, and eligibility requirements. The EPAct significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to terminate the obligation of an electric utility to purchase the electricity offered to it by a QF (under a new contract or obligation), if the FERC finds that the QF has nondiscriminatory access to one of three defined categories of competitive wholesale electricity markets. The statute permits a termination of such obligations on a “service territory-wide basis.” For more information about the Utility’s QF agreements, see “Electricity Resources – Third-Party Power Purchase Agreements,” below.
The Nuclear Regulatory Commission.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.
State Energy Regulation
California Legislature. For information about NRC matters affecting Diablo Canyon, including the status of the Utility’s relicensing application see the information under the heading within MD&A entitled “Regulatory Matters−Diablo Canyon Nuclear Power Plant” in the 2012 Annual Report, which information is incorporated herein by reference.
The Utility’s operations have been significantly affected by statutes passedPipeline and Hazardous Materials Safety Administration
The Utility also is subject to regulations adopted by the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation's pipeline transportation system and the shipment of hazardous materials. Through a certification with PHMSA, the CPUC is authorized to enforce the federal pipeline safety standards over intrastate natural gas pipelines, as well as any state pipeline safety requirements that do not conflict with the federal requirements, through penalties and/or injunctive relief.
The 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. The NTSB investigated the San Bruno accident and in August 2011 announced that it had determined the probable cause of the San Bruno accident placing the blame primarily on the Utility. The NTSB report recommended that the Utility take certain actions to improve the safety of its gas transmission system. The status of the Utility’s implementation of the NTSB’s recommendations is discussed under “Natural Gas Utility Operations” below.
State Regulation
The California
legislature, including laws related to electric industry restructuring, the 2000-2001 California energy crisis, electric resource adequacy, renewable energy resources, power plant siting and permitting, and GHG emissions and other environmental matters.The CPUC.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 to setover the rates and terms and conditions of service for the Utility’sUtility's electricity distribution, electricity generation,and natural gas distribution operations, electricity generation, and natural gas transportation and storage services in California.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, raterates 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 lawstate laws that setsset forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas gathering, transmission, and distribution pipingpipeline systems, and for the safe operation of such linespipelines 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, referredaffiliate rules violations. Utilities are required to
as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court 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.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
forecastingforecasts of future energy needs used by the CPUC in determining the adequacy of the
utilities’utilities' electricity procurement plans.
The California Air Resources Board.Board
The California Air Resources Board (“CARB”) is the state agency charged with setting and monitoring
greenhouse gas (“GHG”)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 granting agency
that granted them if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore,when they were granted. In addition, discharge permits and other approvals and licenses are granted foroften 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 also is subject to regulations adopted by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation’s pipeline transportation system and the shipment of hazardous materials. The CPUC also is authorized to enforce the federal pipeline safety standards, as well as state pipeline safety requirements, through penalties and/or injunctive relief.
The NTSB is an independent federal agency that is authorized to investigate pipeline accidents and certain transportation accidents that involve fatalities, substantial property damage, or significant environmental damage. The NTSB is currently investigating the San Bruno accident. (See Item 3. Legal Proceedings, below and “Pending Investigations” in the 2010 Annual Report for more information.)
Franchise Agreements
The Utility has
over 520 franchise agreements with
various292 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. Inaddition, 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
Historically, energy utilities operated as regulated monopolies within service territories in which they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport, and distribute energy. Services were priced on a combined, or bundled, basis, with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertook a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.
In recent years, legislative and regulatory changes have brought competition to certain aspects of the energy industry, primarily the commodity components—the supply of electricity and natural gas to customers. Regulators and legislators, to varying degrees, have required utilities to separate (or “unbundle”) the prices of the energy commodities and the rates for utility services in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.
Competition in the Electricity Industry
Federal.
At the federal level,
many provisions of the EPAct support the development of competition in the wholesale electric market. The EPAct has directed the FERC
to 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 “Regulatory Environment−Federal Regulation” above 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 needed investment in generation and transmission. Under the rules and associated tariffs,
a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator. The generator will be reimbursed over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades is then recovered by the regulated transmission provider in its overall transmission rates.
On June 17, 2010, the FERC issued a notice of proposed rulemaking and established a proceeding to examine, among other issues, whether to change the FERC’s existing policy that provides incumbent traditional public utilities a “right of first refusal” to own, construct, and operate transmission facilities within their respective service territories. The rules that the FERC adopts in this proceeding may introduce additional competition from merchant or independent transmission project developers for the construction of certain transmission facilities that do not exist today.
State.
At the state level,
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
bankruptcy proceeding that was precipitated by the energy crisis, see Note 13: Resolution of Remaining Chapter 11
proceeding, see Note 13Disputed Claims, of the Notes to the Consolidated Financial Statements in the
20102012 Annual
Report.Report, which information is incorporated herein by reference.)
Current California
Assembly Bill 1X authorized the California Department of Water Resources (“DWR”)law provides only limited opportunities for customers who receive “bundled” electricity service (i.e.,
beginning in February 1, 2001,electricity, transmission and distribution services) to choose to purchase electricity
and sell that electricity directly
to the utilities’ retail customers. Assembly Bill 1X requires the utilities to deliver electricity purchased by the DWR under the contracts and to act as the 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.Assembly Bill 1890 also provided for the establishment of the CAISO, as a nonprofit public benefit corporation, to operate and control the state-wide electricity transmission grid and ensure efficient use and reliable operation of the transmission grid. On April 1, 2009, the CAISO implemented new day-ahead, hour-ahead, and real-time wholesale electricity markets subject to bid caps that increase over time, as part of the implementation of the CAISO’s Market Redesign and Technology Upgrade initiative (“MRTU”). Market participants, including load-serving entities like the Utility, are permitted to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market by acquiring congestion revenue rights.
In addition, the Utility’s customers may, under certain circumstances, obtain power from a “communitycommunity choice aggregator”aggregator (“CCA”) instead of from the Utility. California Assembly Bill 117, enacted in 2002,law permits cities and counties and certain other public agencies to purchase and sell electricity for their local residents and businesses onceafter they have registered as community choice aggregators.
CCAs. Under
Assembly Bill 117,these arrangements, the Utility continues to provide distribution, metering, and billing services to the
community choice aggregators’ customers
of the CCAs and remains the electricity provider of last resort for those customers.
Assembly Bill 117The law provides that a
community choice aggregatorCCA 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 community choice aggregation, including the imposition of a surcharge
is imposed on retail
end-users of the community choice aggregatorCCA to prevent a shifting of costs to customers ofwho continue to receive electricity from a utility who receive bundled services and allowing a community choice aggregator to start service in phases. Assembly Bill 117utility. The law also authorizedauthorizes the Utility to recover from each community choice aggregatorCCA any costs of implementing the program that are reasonably attributable to the community choice aggregator,CCA, and to recover from all customers any costs of implementing the program not reasonably attributable to a community choice aggregator.
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 such as distributed generation and the increased use of electric vehicles, could pose competitive challenges for traditional utilities. In July 2010,particular, technology-related cost declines and sustained federal or state subsidies could make the CPUC found that althoughcombination of “distributed generation” and storage a viable, cost-effective alternative to the California Legislature did not intend thatUtility’s bundled electric service. In addition, the CPUC regulate providerslevels of electric vehicle charging services as public utilities,self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering, which allows self-generating customers to receive bill credits at the 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 the electric vehicle charging provider; retail electricity rates paid by the electric vehicle charging provider to a regulated utility; standards and protocols to ensure functionality and interoperability between utilities and electric vehicle charging providers; and various electricity procurement requirements that apply to electricity service providers generally, such as resource adequacy and renewable energy procurement standards. A second phase of the CPUC proceeding will examine the role of the regulated utility in electric vehicle charging programs, ways to manage the impact of such programs on the electric infrastructure, the cost to customers of such programs, and other issues.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,“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 changedsystem has operated under the nature ofCPUC-approved “Gas Accord” market structure since 1998 which largely mimics the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential. The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties, was approvedregulatory framework required by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications,FERC for various successive periods. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve another settlement agreement known as the Gas Accord V to continue a majority of the Gas Accord’s terms and conditions for the Utility’s naturalinterstate gas transportation and storage services beginning January 1, 2011 and continuing through 2014.pipelines. (See “Regulatory Matters – 2011 Gas Transmission and Storage Rate Case” in the 2010 Annual Report.“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 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
annual amount of revenue
(“revenue requirements”)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
reliability standards or 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
(“DRA”) and The Utility Reform
Network (“TURN”).Network. In
the Utility’s currently pending GRC, the CPUC will authorize the Utility’s revenue requirements for 2011 through 2013. On October 15, 2010,November 2012, the Utility
together with the DRA, TURN, Aglet Consumer Alliance, and nearly all other intervening parties, filed
a motionits 2014 GRC application with the CPUC
seeking approval of a settlement agreement to resolve almost all of the issues raised by the parties in the Utility’s 2011 GRC.for rates effective from 2014 through 2016. For more information see
“Regulatory Matters – 2011the heading within MD&A entitled “2014 General Rate Case” in the
20102012 Annual
Report.Attrition Rate Adjustments
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 proposed settlement agreement in the Utility’s 2011 GRC includes a provision for attrition rate increases in 2012 and 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 unlessstock. Since 2008, the automatic adjustment mechanism described below is triggered.The CPUC has adopted aUtility’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 willadjustment mechanism is triggered, the Utility’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 2011 which remain set at 6.05% for long-term debt, 5.68% for preferred stock, and 11.35% for common equity, resulting2012.
In December 2012, the 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. The Utility may apply for an adjustment to either(For more information see the capital structure orsection of MD&A entitled “2013 Cost of Capital Proceeding” in the cost of capital sooner based on extraordinary circumstances.
Although the FERC has authority to set 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 under Assembly Bill 1X).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).
In December 2007, the The CPUC approved the utilities’ long-termUtility’s electricity procurement plans,plan in January 2012 covering 20072011 through 2016, subject to certain required modifications. 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.
Each utilityTo the extent the Utility’s electricity purchases are not in compliance with the CPUC-approved plan, costs associated with those purchases may
if appropriate, conduct a competitive request for offers (“RFO”) within the parameters permitted in its approved plan to meet the utility’s projected need for electricity resources. Contracts that are entered into after the RFO process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the associated costs. The utilities conduct separate competitive solicitations to meet their renewable energy resource requirements. The utilities submit the renewable energy contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements. For more information, see “Electric Utility Operations — Electricity Resources — Future Long-Term Generation Resources” below.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 in accordance with Assembly Bill 57.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.
Although California legislation requiringplans, (2) utilized the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collectionsprinciples of least-cost dispatch 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.
The CPUC has not yet issued a decision to complete the Utility’s 2009 ERRA compliance review proceeding.
electric generation resources, and (3) prudently operated its 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
long-term 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
elect toalso 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.(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. (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition in the Electricity Industry.”)CCA customers under certain circumstances. 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 elects to useuses the net capacity cost allocation method, the net capacity costs are allocated for the term of the contract or 10 years, whichever is shorter, starting on the date the new generation unit comes on line. Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimizecontract. To use the net capacity costsallocation 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 allocation. If no bids are accepted for the energy rights, the Utility would retain the rights to the energy and would value it at market prices for the purposes of determining the net capacity costs to be allocated untilcost allocation.
For renewable generation purchased from third parties under power purchase agreements, the
next periodic auction.California Senate Bill 695, enacted on October 11, 2009,Utility may also includes a mechanism for recovery ofrecover any above-market costs from direct access and community choice aggregationthrough the imposition of a non-bypassable charge on customers. The CPUC has not yet implemented this portion of Senate Bill 695.
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 “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
2010 Annual Report.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. Utility’s GRC.
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 toUtility may recover
any above-market costs associated with
the DWR’s $11.3 billion bond offering completednew utility-owned generation resources in
November 2002. The proceeds of this bond offering were used to repay the State of California and lendersa manner similar to the
DWRrecovery of above-market costs for
electricitynon-renewable generation purchases
made before the implementationdescribed above. The recovery 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 includedabove-market costs is typically addressed in the
Utility’s revenues.CPUC order approving a specific utility-owned generation project.
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
revenuesrevenues: (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.
For moreSee the information
about the Utility’s TO rate cases, see “Regulatory Matters — Electricwithin MD&A entitled “FERC Transmission Owner Rate
Cases”Case” in the
20102012 Annual
Report.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.(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 existing transmission facilities at 200 kV and above are higher than that embedded in the uniform transmission access charge rate, from transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The cost shift amountscustomers, which are recovered from the Utility’s retail customers as part of retail transmission rates.
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 AccordMatters−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
ratesservices in a separate rate case called the gas transmission and
associated revenue requirements from January 1, 2008 through December 31, 2010 were setstorage (“GT&S”) rate case. The CPUC’s decision in
accordance with the
CPUC-approved settlement agreement known as the Gas Accord IV. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve anothermost recent GT&S rate case approved a settlement agreement, known as the Gas Accord V,
to continue a majority of the Gas Accord IV’s terms and conditions forwhich set the Utility’s
rates and associated revenue requirements for natural gas
transportationtransmission and storage services
beginningfrom January 1, 2011
and continuing through
December 31, 2014.
(See “Regulatory Matters- 2011 Gas Transmission and Storage Rate Case”(The Utility expects to file an application to begin the next GT&S rate case in
the 2010 Annual Report.September 2013.) A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers,
would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements
would continuecontinues 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: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
36%38% of the total backbone capacity on the Utility’s system. Core customers pay approximately
72%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
71%66% to core customers and
29%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
71%51% to core customers,
12%37% to non-core storage service, and
17%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
the lower of 1.5% of total natural gas commodity
costs or $25 million.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
20102012 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 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.
Electric Utility Operations During 2012, the Utility made significant capital investments in its electric transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; 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 allow the Utility to monitor the performance of 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 has installed approximately 8.9 million advanced electric and gas 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 billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communications network and transmitted to the Utility’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 nation’s electric system by combining advanced communications and controls to create a responsive and resilient 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 the 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 plans to undertake various “smart grid” projects and invest in “smart grid” technologies.
The Utility is required to maintain physical generating capacity adequate to meet its customers’ demand for electricity (“load”),load, including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio including electricity provided under DWR contracts, in the most cost-effective way. The following table shows the percentage of the Utility’s total actual deliveries of electricity to customers in 20102012 represented by each major electricity resource:resource.
Total
20102012 Actual Electricity
Delivered: 77,772Delivered – 76,205 GWh:
| | | | | | | | |
Owned generation:
| | | | Percent of Bundled Retail Sales | | | | |
Nuclear
Owned Generation Facilities | | | 23.72 | % | | | | |
Small Hydroelectric
| | | 1.49 | % | | | | |
Large Hydroelectric
Nuclear | | | 12.6823.3 | % | | | | |
Fossil fuel-fired
| | | 4.65 | % | | | | |
Solar
Small Hydroelectric | | | 0.011.2 | % | | | | |
Other (RFO, Diesel)
| | | 0.01 | % | | | | |
Total
| | | | Large Hydroelectric | | | 42.569.7 | % |
DWR
| | | | | | | | |
Natural Gas
| | | | | | | 5.85 | % |
Qualifying Facilities
| | | | | | | | |
Renewable
Fossil fuel-fired | | | 4.998.3 | % | | | | |
Non-Renewable
| | | 13.51 | % | | | | |
Total
| | | | Solar | | | 18.500.2 | % |
Irrigation Districts
| | | | | | | | |
Small Hydroelectric
| | | 0.51 | % | | | | |
Large Hydroelectric
Total | | | 4.01 | % | | | | |
Total
| | | | | | | 4.52 | 42.7 | % |
Bilateral
| | | | | | | | |
Renewable
| | | 8.87 | % | | | | |
Large Hydroelectric
| | | 0.26 | % | | | | |
Non-Renewable
Qualifying Facilities (1) | | | 1.07 | % | | | | |
Total
| | | | | | | 10.20 | % |
Open Market
| | | | | | | | |
Unspecified
| | | | Renewable | | | 18.374.4 | % | | | | |
Non-Renewable | | | 9.8 | % | | | | |
Total | | | | | | | 14.2 | % |
| Irrigation Districts and Water Agencies | | | | | | | | |
Small Hydroelectric | | | 0.3 | % | | | | |
Large Hydroelectric | | | 3.5 | % | | | | |
Total | | | | | | | 3.8 | % |
| Other Third-Party Purchase Agreements | | | | | | | | |
Renewable | | | 12.9 | % | | | | |
Large Hydroelectric | | | 0.4 | % | | | | |
Non-Renewable | | | 11.5 | % | | | | |
Total | | | | | | | 24.8 | % |
Others, Net (2) | | | | | | | 14.5 | % |
| Total | | | | | | | 100 | % |
(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, 2010,2012, the Utility owned and operated the following generation facilities, all located in California, listed by energy source: | | | | | | | | | | |
Generation Type | | County Location | | Number of
Units | | | Net Operating
Capacity
(MW) | |
Nuclear: | | | | | | | | | | |
Diablo Canyon | | San Luis Obispo | | | 2 | | | | 2,240 | |
Hydroelectric: | | | | | | | | | | |
Conventional | | 16 counties in northern and central California | | | 107 | | | | 2,684 | |
Helms pumped storage | | Fresno | | | 3 | | | | 1,212 | |
| | | | | | | | | | |
Hydroelectric subtotal: | | | | | 110 | | | | 3,896 | |
| | | | | | | | | | |
Fossil fuel: | | | | | | | | | | |
Colusa Generating Station(1) | | Colusa | | | 1 | | | | 530 | |
Gateway Generating Station(2) | | Contra Costa | | | 1 | | | | 530 | |
Humboldt Bay Generating Station (3)(4) | | Humboldt | | | 9 | | | | 146 | |
| | | | | | | | | | |
Fossil fuel subtotal: | | | | | 11 | | | | 1,206 | |
| | | | | | | | | | |
Total | | | | | 123 | | | | 7,342 | |
| | | | | | | | | | |
| (1) | The Colusa Generating Station became operational in December 2010 with 530 MW of base capacity and 127 MW of enhanced capability. |
| (2) | The Gateway Generating Station consists of 530 MW of base capacity and 50 MW of enhanced capability. |
| (3) | Humboldt Bay Generating Station became operational in September 2010. |
| (4) | The Humboldt Bay Power Plant fossil facilities, two operating fossil fuel-fired plants and two mobile turbines, were retired at the end of September 2010. |
source and further described below:
| 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,
2010,2012, 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,For more information on matters affecting Diablo Canyon, see the
Utility filed an application at the NRC requesting that eachsection of
these licenses be renewed for 20 years. The license renewal process is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. (See the discussion under the heading “Risk Factors” that appearsMD&A entitled “Regulatory Matters−Diablo Canyon Nuclear Power Plant” in the
MD&A section of the 20102012 Annual
Report.) Under the terms of the NRC operating licenses, there must be sufficient storage capacity for the radioactive spent fuel producedReport, which information is incorporated herein by
the Diablo Canyon plant. For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters — Nuclear Fuel Disposal” below.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 20102012 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
4643.6 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.
| | | | | | | | | | |
| | | 2011 | | 2012 | | 2013 | | 2014 | | 2015 |
Unit 1 | | | | | | | | | | |
Refueling | | - | | April | | - | | February | | - |
Duration (days) | | - | | 45 | | - | | 35 | | - |
Startup | | - | | June | | - | | March | | - |
Unit 2 | | | | | | | | | | |
Refueling | | May | | - | | February | | September | | May |
Duration (days) | | 40 | | - | | 45 | | 35 | | 30 |
Startup | | June | | - | | 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
6968 powerhouses, including
athe 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, 170 dams, 172 milesHelms pumped storage facility consists of
canals, 43 milesthree motor/generator units. During 2011, the Utility began inspections of
flumes, 130 milesall three units following reports of
tunnels, 54 milesa significant failure of
pipe (penstocks, siphonsa similarly designed pumped storage generation unit in Austria that was apparently caused by cracks in the generator rotor poles due to metal fatigue. The Utility completed inspections and
low head pipes),repairs on each of the three units and
5 miles of natural waterways. The system also includes water rights as specifiedreturned them to service in
89 permits or licenses and 159 statements of water diversion and use.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 of 110 MW of hydroelectric power. The Utility is in the process of renewing
hydroelectric licenses
for projects associated with
capacity of approximately
1,0771,137 MW
and surrendering the hydroelectric license associated with the Kilarc-Cow Creek Project which has a capacity of
hydroelectric power.5 MW. Although the original licenses associated with
520880 MW of the
1,0771,137 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately
3,3673,002 MW of hydroelectric power will expire between
20112013 and 2047.
DWR Power PurchasesFossil Fuel-fired Generation Facilities. During 2010, electricity fromThe Utility’s natural gas-fired generation facilities include the DWR contracts allocated toColusa Generating Station, the Gateway Generating Station, and the Humboldt Bay generating station. In addition, the Utility provided approximately 6%owns and operates three fuel cell sites in the Bay Area. On December 20, 2012, the CPUC approved an amended purchase and sale agreement between the Utility and a third-party developer that provides for the construction of a 586-megawatt natural gas-fired facility in Oakley, California that would be acquired by the Utility no sooner than January 1, 2016.
Photovoltaic Facilities. In April 2010, the CPUC approved the Utility’s five-year program for the development of up to 250 MW of solar photovoltaic (“PV”) facilities to be owned and operated by the Utility, along with entering into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties. Under the PV program, Utility-owned PV facilities with an aggregate of 100 MW are operational, and an additional 50 MW are under construction and expected to become operational in 2013. The operational PV facilities include, the Five Points solar station (15 MW), the Westside solar station (15 MW), the Stroud solar station (20 MW), the Huron solar station (20 MW), the Cantua solar station (20 MW), and the Giffen solar station (10 MW). All of these facilities are located in Fresno County. The PV facilities under construction are the 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 located in Fresno County; the Guernsey solar station is located in Kings County.
In December 2012, the Utility 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 AgreementsQualifying FacilityQF Power Purchase Agreements.As described above under “The Utility’sUnder the Public Utility Regulatory Environment-Federal Energy Regulation,” the Utility currently isPolicies Act (“PURPA”) of 1978 electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that are QFs.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, 2010,2012, the Utility had power purchase agreements with 226180 operating QFs for approximately 3,7003,000 MW that are in operation.of capacity. The majority of this capacity is from cogeneration facilities and the remainder is from renewable generation facilities. Agreements for approximately 3,4002,700 MW expire at various dates between 20112013 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with approximately 75 inoperative QFs. The total of approximately 3,700 MW consists of 2,500 MW from cogeneration projects, and 1,200 MW from renewable generation resources, as discussed below. QF power purchases accounted for 18.5% of the Utility’s 2010 electricity deliveries. No single QF accounted for more than 5% of the Utility’s 20102012 electricity deliveries.
In December 2010, the CPUC approved a settlement agreement among the California investor-owned utilities, ratepayer groups, and representatives of the facilities that use combined heat and power (“CHP”), including CHP facilities that also qualify as QFs. The settlement establishes a new CHP/QF program that sets CHP procurement targets and GHG reduction targets (consistent with AB 32), provides for a transition of existing QF energy pricing to market-based pricing by 2015, and implements new standard power purchase agreements. In accordance with the settlement agreement, the utilities will file a joint application with the FERC requesting the
FERC to terminate the utilities’ obligations under PURPA to purchase power from all QFs sized 20 MW and above which includes the settling CHP/QFs. The settlement agreement will become effective when the CPUC decision becomes final and non-appealable, and when a FERC decision granting the utilities’ PURPA termination application becomes final and non-appealable. The FERC is expected to issue a decision on the utilities’ application in the second quarter of 2011.
Irrigation Districts and Water Agencies.The Utility also has entered into
contractsagreements with various irrigation districts and water agencies to purchase hydroelectric power. These agreements
arerequire the Utility to make semi-annual fixed minimum payments as well as variable payments based on
debt service requirements (regardless of the
amount of power supplied), and include variable payments to the counterparty for operationoperating and maintenance
costs.costs incurred by the irrigation districts and water agencies. These contracts will expire on various dates between
20112013 and
2031. In 2010, they accounted for 4.52% of the Utility’s electricity deliveries.2030. Other Third-Party Power Purchase Agreements.Agreements. The Utility has entered into
power purchase agreements, including agreements to purchase renewable energy that were entered into following annual solicitations and separate bilateral negotiations. In addition, in accordance with the Utility’s CPUC-approved long-term procurement plan, the Utility has entered intoseveral power purchase agreements for
renewable and conventional generation
resources. During 2010, the Utility’s purchases under theseresources, including tolling agreements
accounted for 10.20% of the Utility’s deliveries. When market prices and
forecasted load conditions are favorable, the Utility also has the ability to procure electricity through the spot bilateral and CAISO markets. Electricity purchased in these markets accounted for 18.38% of the Utility’s deliveries in 2010.resource adequacy agreements. 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
20102012 Annual
Report.Report, which information is incorporated herein by reference.
Renewable Generation Resources
Current California law requires California retail sellers of electricity,
Renewable generation resources include bioenergy such as the Utility, to comply with a renewable portfolio standard (“RPS”) by increasing their deliveries of renewable energy (such asbiogas and biomass, small hydroelectric, wind, solar, and geothermal energy) each year, so thatenergy. California’s Renewables Portfolio Standard (“RPS”) program gradually increases the amount of electricity deliveredrenewable energy that load-serving entities, such as the Utility, must deliver to their customers from renewable resources equalsan average of at least 20% of their total retail sales byin the endyears 2011-2013 to 33% of 2010. If a retail seller is unable to meet its target for a particular year, the current CPUC “flexible compliance” rules allow the retail seller to use future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three years of the shortfall. Whether a retail seller who relies on flexible compliance rules has met the RPS target for a particular year may not be known until the end of the associated three-year roll-forward period. The CPUC has indicated that it currently intends to limit its discretion to levy penalties for an unexcused failure to meet an applicable RPS target to a maximum of $25 million per year per retail seller.For the year ended December 31, 2010, the Utility’s RPS-eligible renewable resource deliveries equaled 15.9% of itstheir total retail electricity sales. Mostsales in 2021 and thereafter. For more information regarding the new RPS program, see the section of MD&A entitled “Environmental Matters – Renewable Energy Resources” in the 2012 Annual Report, which information is incorporated herein by reference.
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
hydrohydroelectric and solar facilities and certain irrigation district contracts (small
hydrohydroelectric 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 20102012 renewable deliveries are stated in the table below. | | | | | | | | |
Type | | GWh | | | % of Bundled
Load | |
Biopower | | | 3,288 | | | | 4.9 | % |
Geothermal | | | 3,767 | | | | 4.2 | % |
Wind | | | 2,972 | | | | 3.8 | % |
Small Hydroelectric | | | 2,243 | | | | 2.9 | % |
Solar | | | 63 | | | | 0.1 | % |
| | | | | | | | |
Total | | | 12,333 | | | | 15.9 | % |
| | | | | | | | |
| | | |
| 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
20102012 Annual
Report.In April 2010, the CPUC approved the Utility’s proposed five-year program for the development of up to 250 MW of solar photovoltaic (“PV”) facilities and to enter into power purchase agreements for an additional 250 MW of PV facilities to be developedReport, which information is incorporated herein by third parties.
In addition, under its authority to implement AB 32, the CARB has adopted regulations that require virtually all load-serving entities, including the Utility, to increase their deliveries of renewable energy to meet specific annual targets. For 2012, 2013, and 2014, the amount of electricity delivered from renewable energy resources must equal at least 20% of total energy deliveries, increasing to 24% in 2015, 2016, and 2017, 28% in 2018 and 2019, and 33% in 2020 and beyond. For more information about these renewable energy requirements, see “Environmental Matters-Renewable Energy Resources” in the 2010 Annual Report.
Finally, legislation has been introduced in the California state legislature that proposes to increase the current RPS from 20% to 33% by 2020. Under the proposed bill, Senate Bill 23, the amount of electricity delivered from renewable energy resources must equal at least 25% of total energy deliveries by December 31, 2016 and 33% by December 31, 2020. If enacted, the bill would become effective on January 1, 2012. It is unclear how this proposed legislation, if adopted, would affect the CARB’s renewable energy delivery requirement.
Future Long-Term Generation Resources
The Utility plans to meet future electricity demand by focusing first on reducing consumption through energy efficiency and demand response programs, then by securing environmentally preferred energy resources, such as renewable generation and distributed generation (including solar power), and finally by relying on clean and efficient fossil-fueled generation resources. The CPUC has authorized the Utility to obtain new long-term generation resources to meet approximately 1,500 MW of forecast demand by 2016 through power purchase agreements or the development of new Utility-owned generation facilities.
The CPUC allows the California investor-owned utilities to acquire ownership of new conventional generation resources through purchase and sale agreements (“PSAs”) (a PSA is a “turnkey” arrangement in which a new generating facility is constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements). The utilities are prohibited from submitting offers for utility-build generation in their respective RFOs until questions can be resolved about how to compare offers for utility-owned generation with offers from independent power producers. The utilities are permitted to propose utility-owned generation projects through a separate application outside of the RFO process in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement), and (4) to meet unique reliability needs.
The CPUC has recently approved the Utility’s proposal to acquire the 586-MW Oakley Generation Station to be developed and constructed by a third party; however several applications for rehearing of this decision have been filed. For more information, see “Capital Expenditures” in the 2010 Annual Report.
reference.
At December 31,
2010,2012, the Utility owned approximately
18,60018,100 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
57,95360,800 MVA.
Electricity is transmitted across these lines and substations and is then distributed to customers through approximately 141,346 circuit miles of distribution lines and substations with a capacity of 28,244 MVA. In 2010, the Utility delivered 77,772 GWh to its customers, and approximately 6,000 GWh to direct access customers. The
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, including the Utility, 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 93 transmission, 58 transmission-switching substations, and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 600 distribution substations and 118 low-voltage601 distribution substations. The 53 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 1,122 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 CPUC has authorized the Utility to install approximately 10 million advanced electric and gas meters using SmartMeter™ technology throughout the Utility’s service territory by the end of 2012. As of December 31, 2010, the Utility has installed approximately 7.5 million advanced electric and gas meters through its service territory. Advanced electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communication network and transmitted to the 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, several municipalities took various steps to delay or suspend the installation of the new meters, and a class action lawsuit was filed against the Utility. In addition, customers and other private groups have raised safety and health concerns about the radio frequency technology (“RF”) used in the new system. For information about these matters, see “Regulatory Matters-Deployment of SmartMeterTM Technology” in the 2010 Annual Report. The Utility expects to complete the installation of the new meters by the end of 2012.
2010 Electricity Deliveries
The following table shows the percentage of the Utility’s total 2010 electricity deliveries represented by each of its major customer classes.
Total 2010 electricity distribution operations in 2013.
Electricity
Delivered: 83,908 GWh | | | | |
Residential Customers
| | | 37 | % |
Commercial Customers
| | | 39 | % |
Industrial Customers
| | | 17 | % |
Agricultural and Other Customers
| | | 7 | % |
Electricity Distribution Operating Statistics
The following table shows certain of the Utility’s operating statistics from
20062008 to
20102012 for electricity sold or delivered, including the classification of
sales and revenues by type of service.
| | | | | | | | | | | | | | | | | | | | |
| | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
Customers (average for the year): | | | | | | | | | | | | | | | | | | | | |
Residential | | | 4,509,620 | | | | 4,492,359 | | | | 4,488,884 | | | | 4,464,483 | | | | 4,417,638 | |
Commercial | | | 529,318 | | | | 528,786 | | | | 527,045 | | | | 521,732 | | | | 515,297 | |
Industrial | | | 1,254 | | | | 1,285 | | | | 1,265 | | | | 1,261 | | | | 1,212 | |
Agricultural | | | 83,787 | | | | 83,581 | | | | 81,757 | | | | 80,366 | | | | 79,006 | |
Public street and highway lighting | | | 31,743 | | | | 31,227 | | | | 30,474 | | | | 29,643 | | | | 28,799 | |
Other electric utilities | | | 2 | | | | 2 | | | | 2 | | | | 2 | | | | 4 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 5,155,724 | | | | 5,137,240 | | | | 5,129,427 | | | | 5,097,487 | | | | 5,041,956 | |
| | | | | | | | | | | | | | | | | | | | |
Deliveries (in GWh): (1) | | | | | | | | | | | | | | | | | | | | |
Residential | | | 30,744 | | | | 31,234 | | | | 31,454 | | | | 30,796 | | | | 31,014 | |
Commercial | | | 32,863 | | | | 32,958 | | | | 34,053 | | | | 33,986 | | | | 33,492 | |
Industrial | | | 14,415 | | | | 14,806 | | | | 16,148 | | | | 15,159 | | | | 15,166 | |
Agricultural | | | 5,071 | | | | 5,804 | | | | 5,594 | | | | 5,402 | | | | 3,839 | |
Public street and highway lighting | | | 815 | | | | 826 | | | | 877 | | | | 833 | | | | 785 | |
Other electric utilities | | | - | | | | 1 | | | | 1 | | | | 3 | | | | 14 | |
| | | | | | | | | | | | | | | | | | | | |
Subtotal | | | 83,908 | | | | 85,629 | | | | 88,127 | | | | 86,179 | | | | 84,310 | |
California Department of Water Resources (DWR) | | | (4,274 | ) | | | (13,244 | ) | | | (13,344 | ) | | | (21,193 | ) | | | (19,585 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total non-DWR electricity | | | 79,634 | | | | 72,385 | | | | 74,783 | | | | 64,986 | | | | 64,725 | |
| | | | | | | | | | | | | | | | | | | | |
Revenues (in millions): | | | | | | | | | | | | | | | | | | | | |
Residential | | | $ 4,795 | | | | $ 4,759 | | | | $ 4,656 | | | | $ 4,580 | | | | $ 4,491 | |
Commercial | | | 4,823 | | | | 4,538 | | | | 4,413 | | | | 4,484 | | | | 4,414 | |
Industrial | | | 1,424 | | | | 1,392 | | | | 1,400 | | | | 1,252 | | | | 1,293 | |
Agricultural | | | 736 | | | | 770 | | | | 727 | | | | 664 | | | | 483 | |
Public street and highway lighting | | | 79 | | | | 74 | | | | 75 | | | | 78 | | | | 72 | |
Other electric utilities | | | 60 | | | | 66 | | | | 126 | | | | 85 | | | | 59 | |
| | | | | | | | | | | | | | | | | | | | |
Subtotal | | | 11,917 | | | | 11,599 | | | | 11,397 | | | | 11,143 | | | | 10,812 | |
DWR | | | (1,383 | ) | | | (1,987 | ) | | | (1,325 | ) | | | (2,229 | ) | | | (2,119 | ) |
Miscellaneous | | | 145 | | | | 221 | | | | 336 | | | | 215 | | | | 261 | |
Regulatory balancing accounts | | | (35 | ) | | | 424 | | | | 330 | | | | 352 | | | | (202 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total electricity operating revenues | | | $ 10,644 | | | | $ 10,257 | | | | $ 10,738 | | | | $ 9,481 | | | | $ 8,752 | |
| | | | | | | | | | | | | | | | | | | | |
Other Data: | | | | | | | | | | | | | | | | | | | | |
Average annual residential usage (kWh) | | | 6,843 | | | | 6,953 | | | | 7,007 | | | | 6,898 | | | | 7,020 | |
Average billed revenues (cents per kWh): | | | | | | | | | | | | | | | | | | | | |
Residential | | | $ 15.60 | | | | $ 15.24 | | | | $ 14.80 | | | | $ 14.87 | | | | $ 14.48 | |
Commercial | | | 14.68 | | | | 13.77 | | | | 12.96 | | | | 13.19 | | | | 13.18 | |
Industrial | | | 9.88 | | | | 9.40 | | | | 8.67 | | | | 8.26 | | | | 8.53 | |
Agricultural | | | 14.51 | | | | 13.27 | | | | 13.00 | | | | 12.29 | | | | 12.58 | |
Net plant investment per customer | | | $ 4,728 | | | | $ 4,336 | | | | $ 3,994 | | | | $ 3,418 | | | | $ 3,148 | |
(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 39 of California’s 58 counties and includes most of northern and central California. In 2010, the Utility served approximately 4.3 million natural gas distribution customers.The CPUC divides the Utility’s natural gas customers into two categories: core and non-core customers. This classification is based largely on a customer’s annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The non-core customer class is comprised of industrial, larger commercial, and electric generation natural gas customers. In 2010, core customers represented more than 99% of the Utility’s total natural gas customers and 39% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 61% of its total natural gas deliveries.
The Utility provides natural gas transportation services to all core and non-core customers connected to the 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 97% of core customers, representing over 96% of the annual core market demand, receive bundled natural gas service from the Utility.
The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service subject to eligibility requirements. Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utility’s procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.
The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility’s backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.
The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’s results of operations over the long term are not affected by weather variations, conservation, or changes in their consumption levels. The Utility’s results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utility’s natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.
Natural Gas System
As ofAt December 31, 2010,2012, the Utility’s natural gas system consisted of approximately 43,00042,400 miles of distribution pipelines, approximately 6,0006,400 miles of backbone and local transmission pipelines, and threevarious 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
which interconnects with
pipeline systems located in the U.S. Southwest and
the Rocky
Mountain pipeline systemsMountains 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
1.071.1 Bcf per day. The Utility’s Line 400/401 interconnects
at the California-Oregon border with the
natural gas transportation pipeline
ofsystems owned by Gas Transmission Northwest Corporation
at the California-Oregon border.(“GTN”) and Ruby Pipeline, LLC. This line has a receipt capacity at the border of approximately
2.022.2 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States. The Utility also is supplied by natural gas fields in California.
Much of the Utility’s natural gas transmission and distribution infrastructure was placed into service in the 1940’s through the 1960’s as California’s population and economy grew. The Utility makes capital investments in its natural gas transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.
The Utility owns and operates three underground natural gas storage fields connected to the Utility’s transmission and storage
system.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
5048.7 Bcf. In addition,
twothree independent storage operators are interconnected to the
Utility’sUtility's northern California transportation system.
The Utility, along with Gill Ranch Storage, LLC, a subsidiary of Northwest
Natural Gas Company, has placedServices
The CPUC divides the Utility’s on-system natural gas customers into operation an undergroundtwo 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 2012, core customers represented more than 99% of the Utility’s total natural gas customers and 36% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 64% of its total natural gas deliveries. In addition to deliveries discussed above, the Utility delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage facility near Fresno, California. customers.
The constructionUtility 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 96% of core customers, representing over 83% of the initial phase, consistingannual 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 co-generators, enhanced oil recovery customers, refiners, and other large non-core customers. However, some smaller non-core customers are permitted to elect to receive core service, including procurement service, from the Utility if they agree to receive such service for a minimum of five years. Core service to non-core customers is subject to these restrictions to protect core procurement customers from 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 new 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'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 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 the remainder from non-core customers.
Natural Gas Supplies
The Utility purchases natural gas to serve its 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 2012, the Utility purchased approximately 20 Bcf247,792 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 10% of the total capacity, was completed in 2010. natural gas volume the Utility purchased during 2012.
Interstate and Canadian Natural Gas Transportation Services Agreements
The Utility has a
25% interestnumber of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. These companies’ pipeline systems connect at the border to the pipeline system owned by GTN, which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has two firm transportation agreements with GTN for these services. In addition, 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
initial phasearea of
Malin, Oregon, at the
proposed storage facility.2010California border, 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's natural gas transportation system in the area of California near Topock, Arizona.
The total volume of natural gas
throughputdelivered to on-system customers during
20102012 was approximately
7,404945 MMDth. The following table shows the percentage of the Utility’s total
20102012 natural gas deliveries represented by each of the Utility’s major customer classes.
Total 2010 Natural Gas Deliveries: 842 Bcf
| Residential Customers | | | | 20% |
Residential Customers
| | | 28 | % |
Transport-only Customers (non-core) | | | 60 | % 75% |
Commercial Customers | | | 12 | % 5% |
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
20102012 California Gas Report forecasts average annual growth in the
Utility’sUtility'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 StatisticsThe following table shows the Utility’sUtility's operating statistics from 20062008 through 20102012 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service. | | | | | | | | | | | | | | | | | | | | |
| | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | | | | | | | | |
Customers (average for the year): | | | | | | | | | | | | | | | | | | | | |
Residential | | | 4,070,420 | | | | 4,046,364 | | | | 4,043,616 | | | | 4,030,499 | | | | 3,989,331 | |
Commercial | | | 224,400 | | | | 223,709 | | | | 224,617 | | | | 223,330 | | | | 220,024 | |
Industrial | | | 915 | | | | 928 | | | | 926 | | | | 958 | | | | 988 | |
Other gas utilities | | | 6 | | | | 6 | | | | 6 | | | | 6 | | | | 6 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 4,295,741 | | | | 4,271,007 | | | | 4,269,165 | | | | 4,254,793 | | | | 4,210,349 | |
| | | | | | | | | | | | | | | | | | | | |
Gas supply (MMcf): | | | | | | | | | | | | | | | | | | | | |
Purchased from suppliers in: | | | | | | | | | | | | | | | | | | | | |
Canada | | | 206,800 | | | | 190,485 | | | | 189,608 | | | | 199,870 | | | | 202,274 | |
California(1) | | | (32,910) | | | | (41,714) | | | | (53,126) | | | | (23,065) | | | | (13,401) | |
Other states | | | 96,338 | | | | 115,543 | | | | 123,833 | | | | 101,271 | | | | 103,658 | |
| | | | | | | | | | | | | | | | | | | | |
Total purchased | | | 270,228 | | | | 264,314 | | | | 260,315 | | | | 278,076 | | | | 292,531 | |
Net (to storage) from storage | | | (314) | | | | 876 | | | | 560 | | | | (1,120) | | | | 4,359 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 269,914 | | | | 265,190 | | | | 260,875 | | | | 276,956 | | | | 296,890 | |
Utility use, losses, etc.(2) | | | (20,798) | | | | (12,423) | | | | 1,758 | | | | (12,760) | | | | (27,610) | |
| | | | | | | | | | | | | | | | | | | | |
Net gas for sales | | | 249,116 | | | | 252,767 | | | | 262,633 | | | | 264,196 | | | | 269,280 | |
| | | | | | | | | | | | | | | | | | | | |
Bundled gas sales (MMcf): | | | | | | | | | | | | | | | | | | | | |
Residential | | | 195,195 | | | | 195,217 | | | | 198,699 | | | | 196,903 | | | | 196,092 | |
Commercial | | | 53,921 | | | | 57,550 | | | | 63,934 | | | | 67,293 | | | | 73,178 | |
Industrial | | | — | | | | — | | | | — | | | | — | | | | 10 | |
Other gas utilities | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Total | | | 249,116 | | | | 252,767 | | | | 262,633 | | | | 264,196 | | | | 269,280 | |
| | | | | | | | | | | | | | | | | | | | |
Transportation only (MMcf): | | | 564,516 | | | | 568,715 | | | | 569,535 | | | | 605,259 | | | | 559,270 | |
Revenues (in millions): | | | | | | | | | | | | | | | | | | | | |
Bundled gas sales: | | | | | | | | | | | | | | | | | | | | |
Residential | | | $ 1,991 | | | | $ 1,953 | | | | $ 2,574 | | | | $ 2,378 | | | | $ 2,452 | |
Commercial | | | 474 | | | | 496 | | | | 792 | | | | 766 | | | | 859 | |
Industrial | | | — | | | | — | | | | — | | | | — | | | | — | |
Other gas utilities | | | — | | | | — | | | | — | | | | — | | | | — | |
Miscellaneous | | | 49 | | | | 55 | | | | (30) | | | | 87 | | | | 121 | |
Regulatory balancing accounts | | | 305 | | | | 289 | | | | 221 | | | | 186 | | | | 40 | |
| | | | | | | | | | | | | | | | | | | | |
Bundled gas revenues | | | 2,819 | | | | 2,793 | | | | 3,557 | | | | 3,417 | | | | 3,472 | |
Transportation service only revenue | | | 377 | | | | 349 | | | | 333 | | | | 340 | | | | 315 | |
| | | | | | | | | | | | | | | | | | | | |
Operating revenues | | | $ 3,196 | | | | $ 3,142 | | | | $ 3,890 | | | | $ 3,757 | | | | $ 3,787 | |
| | | | | | | | | | | | | | | | | �� | | | |
Selected Statistics: | | | | | | | | | | | | | | | | | | | | |
Average annual residential usage (Mcf) | | | 48 | | | | 48 | | | | 49 | | | | 49 | | | | 49 | |
Average billed bundled gas sales revenues per Mcf: | | | | | | | | | | | | | | | | | | | | |
Residential | | | $ 10.20 | | | | $ 10.00 | | | | $ 12.95 | | | | $ 12.07 | | | | $ 12.50 | |
Commercial | | | 8.79 | | | | 8.62 | | | | 12.38 | | | | 11.38 | | | | 11.73 | |
Industrial | | | — | | | | — | | | | — | | | | — | | | | 1.03 | |
Average billed transportation only revenue per Mcf | | | 0.67 | | | | 0.61 | | | | 0.59 | | | | 0.56 | | | | 0.56 | |
Net plant investment per customer | | | $ 1,637 | | | | $ 1,557 | | | | $ 1,344 | | | | $ 1,375 | | | | $ 1,304 | |
(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.
|
| | | | | | | | | | | |
| 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 | |
Natural Gas SuppliesThe Utility purchases natural gas to serve the Utility’s core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have fluctuated generally based on market conditions. During 2010, the Utility purchased approximately 270,228 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 9% of the total natural gas volume the Utility purchased during 2010.
The following table shows the total volume and the average price of natural gas in dollars per MMcf of the 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2010 | | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
| | | MMcf | | | Avg.
Price | | | MMcf | | | Avg.
Price | | | MMcf | | | Avg.
Price | | | MMcf | | | Avg.
Price | | | MMcf | | | Avg.
Price | |
Canada | | | 206,800 | | | $ | 4.03 | | | | 190,485 | | | $ | 3.74 | | | | 189,608 | | | $ | 8.29 | | | | 199,870 | | | $ | 6.63 | | | | 202,274 | | | $ | 6.27 | |
California(1) | | | (32,910 | ) | | $ | 4.63 | | | | (41,714 | ) | | $ | 4.16 | | | | (53,126 | ) | | $ | 9.24 | | | | (23,065 | ) | | $ | 6.77 | | | | (13,401 | ) | | $ | 7.04 | |
Other states (substantially all U.S. southwest) | | | 96,338 | | | $ | 4.34 | | | | 115,543 | | | $ | 3.50 | | | | 123,833 | | | $ | 7.05 | | | | 101,271 | | | $ | 6.30 | | | | 103,658 | | | $ | 6.51 | |
| | | | | | | | | | | | | | | | | | | | |
Total/weighted average | | | 270,228 | | | $ | 4.07 | | | | 264,314 | | | $ | 3.57 | | | | 260,315 | | | $ | 7.51 | | | | 278,076 | | | $ | 6.50 | | | | 292,531 | | | $ | 6.32 | |
(1) | California purchases include supplies transported into California by others.
|
Gas Gathering Facilities
The Utility’s gas gathering system collects natural gas from third-party wells in northern and central California. During 2010, 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 123 MMcf per day of natural gas produced in northern California was delivered into the Utility’s gas gathering system during 2010.
Interstate and Canadian Natural Gas Transportation Services Agreements
In 2010, approximately 59% of the gas transported on the Utility’s system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers’ service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. These companies’ pipeline systems connect at the border to the pipeline system owned by TransCanada’s Gas Transmission Northwest Corporation (“GTN”), which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has three firm transportation agreements with GTN for these services.
During 2010, approximately 36% of the gas transported on the Utility’s system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utility’s natural gas transportation system in the area of California near Topock, Arizona.
The following table shows certain information about the Utility’s firm natural gas transportation agreements in effect during 2010 to support the Utility’s needs for its core customers, including the contract quantities, contract durations, and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by the National Energy Board of Canada in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases. The Utility may, upon prior notice and with the CPUC’s approval, extend most of these natural gas transportation agreements. The Utility retains a right of first refusal or evergreen rights on most agreements, allowing renewal at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.
| | | | | | |
| Pipeline | | Expiration Date | | Quantity MDth per day | | Demand Charges for the Year Ended December 31, 2010 (In millions) |
| | | |
TransCanada NOVA Gas Transmission, Ltd.(1) | | Various | | 619 | | $40.1 |
TransCanada Foothills Pipe Lines Ltd., B.C. System(2) | | Various | | 611 | | 16.5 |
Gas Transmission Northwest Corporation(3) | | Various | | 610 | | 72.9 |
Transwestern Pipeline Company(4) | | Various | | 177 | | 19.7 |
El Paso Natural Gas Company(5) | | Various | | 202 | | 22.3 |
(1) | As of December 31, 2010, the Utility had three active contracts with TransCanada NOVA Gas Transmission, Ltd. with expiration dates ranging from October 31, 2011 to October 31, 2020. |
(2) | As of December 31, 2010, the Utility had three active contracts with TransCanada Foothills Pipe Lines Ltd., B.C. System with expiration dates ranging from October 31, 2011 to October 31, 2012. |
(3) | As of December 31, 2010, the Utility had three active contracts with Gas Transmission Northwest Corporation with expiration dates ranging from October 31, 2011 to October 31, 2020. |
(4) | As of December 31, 2010, the Utility had two active contracts with Transwestern Pipeline Company with expiration dates ranging from February 28, 2011 to March 31, 2013. |
(5) | As of December 31, 2010, the Utility had two active contracts with El Paso Natural Gas Company with expiration dates ranging from June 30, 2012 to June 30, 2013. |
In addition, in December 2008, the CPUC approved an agreement between the Utility and El Paso Corporation for the Utility to subscribe for firm service rights on El Paso Corporation’s proposed 680-mile 42-inch natural gas transmission pipeline (“Ruby Pipeline”) that would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border. The Utility has subscribed for firm service rights for 375 MDth per day of which 250 MDth per day will serve the Utility’s core portfolio customers and 125 MDth per day will be subject to the Utility’s management of electric fuels used to generate electricity. The Ruby Pipeline will have an initial capacity of 1.5 Bcf per day and will connect Rocky Mountain natural gas producers with markets in northern California, Nevada, and the Pacific Northwest. Construction of the Ruby Pipeline began in July 2010 and is anticipated to be in service in June 2011.
Energy Efficiency, Public Purpose and OtherCustomer Programs
California law
requireshas historically required the CPUC to authorize certain levels of funding for
public purpose programs related to
energy efficiency, low-income energy efficiency, research and development, and renewable energy
resources.resources through the collection of an 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 and established an energy program investment charge to support ongoing energy efficiency and research and development. Gas public interest research continues to be funded through 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 2010,2012, the Utility collected authorized revenue requirements of $700$688 million from electric customers and $146$169 million from gas customers to fund public purpose and other programs. The CPUC is responsible for
authorizing the programs, funding levels, and cost recovery mechanisms for the Utility’s operation of these programs. The CEC administers both the electric and natural gas public interest research and development programs and the renewable energy program on a statewide basis. In 2010, the Utility transferred $84 million from its revenue requirements to the CEC to fund these programs.
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. In 2010, the Utility collected authorized revenue requirements of $436 millionequipment and energy management products to fund these programs from gas and electric customers.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,programs. The mechanism provides each utility with an earnings rate composed of a 42% increase over 2006-2008 authorized funding levels.5% management fee based on qualified program expenditures and an additional performance bonus of up to 1%. The CPUC has adopted a long-termUtility’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 $104$21 million through December 31, 2010 based onfor the energy savings achieved throughsuccessful 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 cycle. Applications for incentive awards for implementation of 2009 energy efficiency programs are due by June 30,years 2011 to enableand 2012. After the CPUC to issue a final decisioncompletes 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 endCPUC in the fourth quarter of 2011.
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.
For more information, see “Regulatory Matters — Energy Efficiency Programs and Incentive Ratemaking” in the 2010 Annual Report.
Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. TheIn April 2012, the CPUC has authorized the Utility to collect $109$192 million to fund its 2009-20112012-2014 demand response programs. In addition,Due to the timing of the decision, the CPUC has authorized the Utility to collect $179 millionrecover both 2012 and 2013 program costs through June 1, 2011 to implement its multi-year air conditioning direct load control program. Customers who enrollcustomer rates collected in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies.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.
TheIn December 2011, the CPUC approved
a budgetcontinuing annual funding for the
extensionself-generation incentive program of
the SGIP of approximately $36 million
in each of 2010 and 2011,through 2014, with any carryover funds to be administered through 2015.
In late 2006, the CPUC establishedThe Utility also administers the California Solar Initiative
(“CSI”) to bring 1,940 MW of solar power on-line in
California by 2017 andits service territory. The CPUC has authorized the
California investor-owned utilitiesUtility to collect
an additional $2.2approximately $1.1 billion
in the aggregate over thefrom 2007 through 2016
period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load,
to meet this goal. Of the total amount authorized, the Utility has been allocated $946 millionas well as to fund
customer incentives, research, development, and demonstration activities,
(with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses.
The California Legislature modified the CSI program to include participation of the California municipal utilities. The current overall objective of
the 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
20092012 through
2011.2014. 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 2010,2012, the amount of this subsidy was approximately $825 million, including avoided customer surcharges.$851 million. The CPUC also authorized the Utility to recover approximately $28$45 million in administrative costs relating to the CARE subsidy over 2009 through 2011.
2014.
Environmental MattersGeneral
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
PG&E Corporation and the Utility believe the link between man-made GHG emissions and global climate change is clear and convincing and that mandatory GHG reductions are necessary. PG&E Corporation and the Utility believe the development of a market-based cap-and-trade system, in conjunction with successful energy efficiency and demand-side management programs and the development of renewable energy resources, can reduce GHG emissions while diversifying energy supply resources and minimizing costs to customers.
Regulation.
The
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. At the state level, the CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce the AB 32.At the federal level,Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, but comprehensive federal legislation has not yet been enacted.enacted.. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions, including establishing an annual GHG reporting requirement. In June 2010, the EPA adopted the final “tailoring rule” to phase-in permit requirements for construction of new sources of GHG emissions, such as power plants and natural gas compressor stations, if the GHG emissions from these sources would exceed certain thresholds. These permit requirements also apply to major modifications proposed to be made to existing facilities that emit GHGs that meet the threshold. The EPA rules require owners of these facilities to use the “best available control technology” to minimize GHG emissions. The uncertainty about what constitutes the “best available control technology” may cause permitting delays. Several of the EPA’s actions have been challenged in court and are not likely to be resolved until late 2011 or in 2012.
At the state level,
State Regulation. AB 32 requires the gradual reduction of state-wide GHG emissions in California to the 1990 level by 2020 on a schedule beginning in 2012.2020. The CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce AB 32. 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. InThe 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.
The cap and trade program’s first two-year compliance period, which began January 1, 2013, applies to the electricity generation and large industrial sectors. The next two-year compliance period, from January 1, 2015 through December 2008,31, 2017, will expand to include the natural gas supply and transportation sectors, effectively
covering all the capped sectors until 2020. Each year the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target set pursuant to AB 32. These recommendations include increasing renewable energy supplies, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program. (For information about the CARB’s renewable energy requirements, see “Utility Operations-Electricity Resources- Renewable Generation Resources” above.)The CARB also issued proposed cap-and-trade regulations for public comment in October 2010. The proposed regulations include provisions to establish state-wide caps on GHG emissions (for three 3-year compliance periods beginning January 1, from 2012 and ending December 31, 2020), allocatewill issue emission allowances (i.e.(i.e., the rights to emit GHGs) among utilitiesequal to the amount of GHGs emissions allowed for 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’s first quarterly auction was held on November 14, 2012. Emitters (also known as covered entities) are required to obtain and other industry participants, and permitsurrender allowances equal to the amount of their GHGs emissions within a particular compliance period. Emitters may also meet up to 8% of their compliance obligation through the purchase and sale of emission allowances through a CARB-managed auction, among other provisions. After considering the comments“offset credits” which represent GHG emissions abatement achieved in sectors that had been received, on December 16, 2010, the CARB directed its staff to prepare modified regulations and publish the modified regulations for one or more 15-day public comment and review periods. The modified regulations (with such further modifications as the CARB’s executive officer approves) will be submittedare not subject to the California Officecap. For more information about the cap-and trade program, see the section of Administrative Law for final approval. If the regulations become effective, the first compliance period would begin on January 1, 2012 and apply to the electricity and industrial sectors. The second phase would begin on January 1, 2015 and would expand to include suppliers of natural gas and liquid fossil fuels. Before the new cap- and-trade program can become effective, a legal challenge to the CARB’s authority to implement its AB 32 scoping plan must be resolved. (See the sectionMD&A entitled “Environmental Matters” in the 20102012 Annual Report.)Report, which information is incorporated herein by reference.
Increasing use of renewable energy supplies also is expected to help reduce GHG emissions in California. In
additionApril 2011, the California Governor signed legislation that requires load-serving entities, such as the Utility, to
gradually increase the
requirementsamount of
AB 32, California Senate Bill 1368, enacted in 2006, prohibits any load-serving entity in California,renewable energy delivered to their customers to at least 33% of the total amount of electricity retail sales by 2020. (See “Electricity Resources” above.) In December 2011, the CPUC approved various regulations to implement the new law, including
investor-owned electric utilities, from generating base-load electricity or entering into a long-term financial commitment to purchase base-load electricity generation unless the
generating source complies with the CPUC-adopted GHG emission performance standardestablishment of
1,100 pounds of CO2 per MWh.renewable energy targets for each compliance period. (For more information, see “Renewable Generation Resources” above.)
Climate Change Mitigation and Adaptation Strategies.During
2010,2012, 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
PG&E’sthe 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 hydroelectricityhydroelectric 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%. In late 2008, the Utility also conducted focused surveys for high-volume gas leaks at its Topock and Kettleman compressor stations to reduce methane emissions.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 —aredevelopment—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”) and has voluntarily reported itstime 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 CCAR on an annual basis fromthe CARB. (For information about the sources of electric generation that the Utility delivered to customers in 2012, see “Electric Utility Operations− Electricity Resources” above.) Consistent with Utility practice since 2002, through 2008. In 2010, the Utility also voluntarily reported its 20092011 GHG emissions to The Climate Registry (“TCR”), a successor non-profit to CCARorganization that is developing consistenthas a reporting and measurement standards acrossstandard applicable to most industry sectors inacross North America. InReporting to TCR enables the Utility to 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 its 2010
emissions, the Utility also
complied with AB 32’s annual GHG emission reporting requirement by reporting its 2009reported the GHG emissions
from its facilities and operations to the
CARB.EPA under its mandatory reporting requirements. 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 highest standards developed by TCR, preliminary emissions data for 2009 areexception of gas delivered to other natural gas local distribution companies. This figure does not represent the most recent data available. Final emissions dataUtility’s compliance obligation under AB 32, which will be made publicly availableequivalent to the above reported value less the fuel that is delivered to covered entities as calculated by TCR on its website in February 2011 as well as reported by PG&E Corporation and the Utility inCARB.
Benchmarking GHG Emissions for Delivered Electricity
The Utility’s third-party-verified CO2 emissions rate associated with the
next Corporate Responsibility and Sustainability Report expected to be posted to their websites in July 2011. For information about the sources of electric generation that the Utilityelectricity delivered to customers in
2010, see “Electric Utility Operations-Electric Generation Resources” above.Total 2009 GHG Emissions by Source Category
2011 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)
| | | 20.78 | 659 |
Electricity Transmission and Distribution Line Losses
| | | 0.97 | |
Process and Fugitive Emissions from Natural Gas System
| | | 1.32 | |
Gas Compressor Stations
| | | 0.31 | |
Transportation (Fleet vehicles)
| | | 0.11 | |
Facility
Pacific Gas and Electricity UseElectric Company (2) | | | 0.04 | |
Electrical Equipment
| | | 0.06 | |
Total
| | | 23.59 | |
| | | | 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 2009 was 575 pounds of CO2 per MWh, which is a slight decrease from the 2008 emissions rate of 641 pounds of CO2 per MWh. The Utility’s 2009 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)
| | | 1,329 | |
California’s Average(1)
| | | 724 | |
Pacific Gas and Electric Company(2)
| | | 575 | |
|
(1) Source: Environmental Protection Agency eGRID 2007 Version 1.1, which contains year 2005 information configured to reflect the electric power industry’s current structure as of December 31, 2007. This is the most up-to-date information available from EPA.
(2) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s total emissions and the Utility’s emission rate for delivered electricity.
|
|
Emissions Data for Utility-Owned Generation
In addition to GHG emissions data provided above, the table below sets forth information about the GHG and other emissions from the Utility’s owned generation facilities. The Utility’s owned generation (primarily nuclear and hydroelectric facilities) comprised
approximately 36%more than 40% of the Utility’s delivered electricity in
2009.2011. The Utility’s
retained fossil-fuelfossil fuel-fired generation comprised
less than 1%approximately 6% of the Utility’s delivered electricity in
2009. | | | | |
| | | 2009 | | 2008 |
| | | | |
Total NOx Emissions (tons) | | 1,258 | | 1,163 |
NOx Emissions Rates (pounds/MWh) | | | | |
Fossil Plants | | 0.82 | | 4.26 |
All Plants | | 0.09 | | 0.09 |
Total SO2 Emissions (tons) | | 37 | | 27 |
SO2 Emissions Rates (pounds/MWh) | | | | |
Fossil- Plants | | 0.02 | | 0.098 |
All Plants | | 0.0026 | | 0.0021 |
Total CO2 Emissions (metric tons) | | 1,401,487 | | 366,553 |
CO2 Emissions Rates (pounds/MWh) | | | | |
Fossil Plants | | 1,016 | | 1,554 |
All Plants | | 110 | | 32 |
Other Emissions Statistics | | | | |
Sulfur Hexafluoride (“SF6”) Emissions | | | | |
Total SF6 Emissions (metric tons CO2-equivalent) | | 62,129 | | 64,362 |
SF6 Emissions Leak Rate | | 1.7% | | 1.9% |
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% |
Water Quality
The Utility’s Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a
Section 316(b) of the federal Clean Water Act
National Pollutant Discharge Elimination System (“NPDES”) permit issued byrequires that cooling water intake structures at electric power plants, such as the
Central Coast Regional Water Quality Control Board (“Central Coast Board”). This permit allowsnuclear generation facilities at Diablo Canyon, reflect the
Diablo Canyonpower plantbest technology available to dischargeminimize 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 atsystem). The proposed site specific assessment allows for the consideration of a temperature novariety 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. In June 2012, the EPA issued a Notice of Data Availability proposing changes to the draft regulations which, if adopted, would provide more than 22 degrees above the temperatureflexibility in complying with some of the ambient receiving water, and requires that the beneficial uses of the water be protected.requirements. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant’s discharge was not protective of beneficial uses. For more information, see the discussion below in “Item 3 — Legal Proceedings — Diablo Canyon Power Plant.”
EPA is required to issue final regulations by July 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 and may incur a material charge. Assuming theCalifornia 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.
There is continuing uncertainty about the status of federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. In July 2004, the EPA issued regulations to implement Section 316(b) intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The EPA regulations also allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases. Various parties separately challenged the EPA’s regulations and in January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a decision holding that environmental restoration cannot be used as a compliance option and that site-specific compliance variances based on a cost-benefit test cannot be used. The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and in July 2007, the EPA suspended its regulations. The U.S. Supreme Court granted review of the cost-benefit question and in April 2009, issued a decision overturning the Second Circuit, finding the EPA’s use of a cost-benefit test reasonable. Depending on the form of the final regulations that may ultimately be adopted by the EPA, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. The EPA is not expected to issue draft revised regulations before March 2011. If the final regulations adopted by the EPA require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.
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,these laws and
disposal requirements issuedregulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the
EPA under RCRACalifornia Department of Toxic Substances Control (“DTSC”), several California regional water quality control boards, and
various other federal, state,
hazardous waste laws, and
other environmental requirements.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;stations are located; current and former substations, service centers, and general construction yard sites; and sites
wherecurrently and formerly used by the Utility
stores, recycles, and disposesfor the storage, recycling, or disposal of
potentially hazardous
materials.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” andMatters,” “Critical Accounting
Polices”Polices,” and Note
1515: Commitments and Contingencies−Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in the
20102012 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 California Department of Toxic Substances Control (“DTSC”) approved the soil and groundwater remediation plan in June 2010 and remediation pursuant to the plan is underway. The Utility spent approximately $12 million in 2010 and estimates that it will spend approximately $33 million in 2011 for remediation at this site. Fossil fuel-fired Units 1 and 2 of the 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
if any, 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
$35 million in 2010 and estimates it will spend approximately $37 million in 2011 and $51 million in 2012 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
Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility
has a comprehensive program to monitor a networkis responsible for remediating this groundwater contamination and for abating the effects of
groundwater wells at both the
Hinkley and Topock natural gas compressor stations.contamination on the environment. The Utility
also ownshas incurred significant environmental liabilities associated with these sites. For more information about the
Kettleman natural gas compressor station but does not expect that it will incur any material expendituresUtility’s remediation and abatement efforts and related
liabilities, see Note 15: Commitments and Contingencies−Environmental Remediation Contingencies of the Notes to
remediation at this site.At the Hinkley site,Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.
Recovery of Environmental Remediation Costs
The CPUC has authorized the Utility
is cooperating with the Regional Water Quality Control Board (“RWQCB”) to
evaluate and remediate the chromium groundwater plume. Measures have been implementedrecover most of its environmental remediation costs through various ratemaking mechanisms, subject to
control movement of the plume, while full-scale in-situ treatment systems operate to reduce the mass of the plume. An evaluation of the performance of these interim remedy measures,exclusions for certain sites, such as
well as possible future measures, is underway as part of the development of a final remediation plan. The Utility is working with the RWQCB to prepare an environmental impact report analyzing the potential impacts of the potential remedies for the site. In addition, the Utility is complying with the RWQCB’s order that the Utility provide bottled drinking water to all residents where well water contains levels of hexavalent chromium over regional background levels. The Utility also has instituted a program to purchase those properties where chromium levels exceed background levels or that are otherwise needed for remediation purposes. The Utility estimates that total acquisition costs will be $35 million, of which $15 million is forecasted to be spent in 2011 with the remaining amount forecasted to be spent in future years. Under applicable accounting rules, these property acquisition costs will be treated as remediation costs. In 2010, the Utility spent approximately $15 million on remediation activities at Hinkley, and currently estimates it will spend at least $31 million in 2011 (including property acquisition costs of $15 million) and $5 million in 2012. Remediation costs associated with the Hinkley natural gas compressor site,
are not recoverable from customers underand subject to limitations for certain liabilities such as amounts associated with fossil fuel-fired generation facilities formerly owned by the
ratemaking mechanism discussed below nor are these costs recoverable from insurers.At the Topock natural gas compressor station, located near Needles, California, the Utility has implemented interim remediation measures, including a system of extraction wellsUtility. For more information, see Note 15: Commitments and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River, while regulatory agencies considered the Utility’s proposed final remediation plan. As a final remediation plan, the Utility has proposed an in-situ treatment project to inject ethanol into the groundwater to accelerate the microbial breakdown of hexavalent chromium into a non-toxic and non-soluble form of chromium. The proposed plan involves the construction of a significant number of additional injection and extraction wells and an associated piping system. In January 2011 the DTSC and United States Department of Interior approved the Utility’s proposal. While developing the plan the Utility consulted with various local Native American Tribes who claimed the project would negatively impact an area of cultural significance. OneContingencies−Environmental Remediation Contingencies of the tribes, the Fort Mojave Indian Tribe, has questioned the adequacy of the environmental consideration of negative cultural impacts of the project and may file an objectionNotes to the DTSC’s approval by the March 2, 2011 due date.
In 2010, the Utility spent approximately $22 million for remediation activities at Topock. Assuming the Utility is permitted to implement the approved final remediation plan, the Utility currently estimates that it will spend at least $21 million in 2011 and $23 million in 2012. The Utility’s remediation costs for Topock are subject to the ratemaking mechanism described below.
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 costsConsolidated Financial Statements 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 retained2012 Annual Report which information is incorporated herein by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels are allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utility’s claims against third parties associated with hazardous waste remediation sites are retained by the Utility, with the remainder, 90% of any such recoveries, assigned to the Utility’s customers.
The CPUC has separately authorized the Utility to recover 100% of its remediation costs for decommissioning formerly owned fossil-fueled generation facilities and certain of the Utility’s transmission stations. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.
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 developBay Unit 3. As a permanent storage site,result, the Utility obtained a permit from the NRC to buildconstructed an on-siteinterim dry cask storage facility at Diablo Canyon to store spent fuel at Diablo Canyon through at least 2024.2024, and a separate facility at Humboldt Bay. The construction of the dry cask storage facility is complete. During 2009, the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRC’s issuance of the permit is still pending in the U.S. Court of Appeals for the Ninth Circuit. The appellants claim that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon. The Ninth Circuit heard oral arguments on November 4, 2010. The Utility expects the court to issue a decision in 2011.
As a result of the DOE’s failure to build a repository for nuclear waste, 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 levelin Note 2: Summary 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. Apremature shutdown of the Diablo Canyon units would increase the likelihood of an earlier start to decommissioning. The Utility’s decommissioning cost estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plants. Actual decommissioning costs may vary from these estimates to the extent the assumptions on which the estimates are based (such as assumptions about decommissioning dates, regulatory requirements, technology, and costs of labor, materials, and equipment) differ from actual results. The Utility recovers its revenue requirements for estimated nuclear decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility’s nuclear facilities.
In April 2009, the Utility filed an application in the 2009 Nuclear Decommissioning Triennial Proceeding with new decommissioning cost estimates and other funding assumptions, such as projected cost escalation factors and projected earnings of the funds for 2010, 2011, and 2012. In July 2010, the CPUC issued a decision in the first phase of the proceeding to determine the annual revenue requirement for the decommissioning trust. The CPUC has not yet issued a decision in the second phase of the proceeding which is evaluating whether to broaden investment options available to the trusts. For more information about nuclear decommissioning, see Note 2Significant Accounting Policies of the Notes to the Consolidated Financial Statements in the 20102012 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. Electric and Magnetic FieldsElectric and magnetic fields (“EMFs”) naturally result from the generation, transmission, distribution, and use of electricity. In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. In October 2002, the California Department of Health Services released its report to the CPUC and the public, based primarily on its review of studies by others, evaluating the possible risks from EMFs. The report’s conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health Services’ report has assigned a higher probability to the possibility of a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis, and miscarriages.
On January 26, 2006, the CPUC issued a decision that affirms the CPUC’s “low-cost/no-cost, prudent avoidance” policy to reduce EMF exposure for new utility transmission and substation projects. The CPUC ordered the continued use of a 4% of project cost benchmark for EMF reduction measures. The CPUC also reaffirmed that it has exclusive jurisdiction with respect to utility EMF matters.
The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs from power lines. In a case involving allegations of personal injury, a California appeals court held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs, and barred plaintiffs’ personal injury claims. The California Supreme Court declined to hear the plaintiffs’ appeal of this decision.
Item 1A.Risk Factors
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 20102012 Annual Report, which information is incorporated herein by reference and included in Exhibit 13 to this report.reference.
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 which it will encumberwatershed 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 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 public agencies or non-profit conservation organizations under the Chapter 11 Settlement Agreement. Approximatelyapproximately 75,000 acres of this land may be donated in fee and encumbered withits watershed lands to public entities or qualified non-profit conservation easements. The remaining land containsorganizations. (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, and will onlybut this land may be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the) The Utility formed an entity,a non-profit organization, the Pacific Forest Watershed Lands Stewardship Council (“Council”) to oversee the development and implementation of a Land Conservation Plan (“LCP”) that will articulate the long-term management objectives for the 140,000 acres.watershed lands. The Council is governed by an 18-member board of directors, that representsone 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 Utility has appointed 1 out of 18 members of the board of directors of the Council. In December 2007, the Council adopted the LCP and submitted it to the Utility. The Utility has accepted the LCP and will seek authorization from the CPUC, the FERC, and other approving entities to proceed with the transactions necessaryCouncil’s goal is to implement the LCP.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 74,00082,000 square feet of office space from a third party in San Francisco, California. This lease expiresCalifornia, of which 40,000 square feet will expire in 2012.2014 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 1515: Commitments and Contingencies−Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 20102012 Annual Report, which discussioninformation is incorporated into this Item 3herein 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 Board.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’s NPDESCanyon's permit. At its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists’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.On May 4, 2010,
In addition, the California Water Board adopted aBoard’s policy on once-through cooling. The policy, which is subjectcooling and regulations that are expected to approvalbe issued by the California Office of Administrative Law, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the 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 Water BoardEPA in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The policyJuly 2013 could affect future negotiations between the WaterCentral Coast Board and the Utility regarding the status of the 2003 settlement agreement. (See “Item 1. Business−Environmental Matters−Water Quality” above.)
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their Utility’sUtility's financial condition or results of operations.
Litigation Related to the San Bruno Accident
As of February 8, 2011, 59 and Natural Gas Spending
At December 31, 2012, approximately 140 lawsuits on behalf of approximately 177 plaintiffs,involving third-party claims for personal injury and property damage, including two class action lawsuits, havehad been filed by residents ofagainst PG&E Corporation and the Utility in connection with the San Bruno in San Mateo County Superior Courts against the Utility, and in some cases, against PG&E Corporation. In addition, five lawsuitsaccident on behalf of 11 plaintiffs have been filed by residents of San Bruno in the San Francisco County Superior Court against the Utility, and in some cases, against PG&E Corporation. Theseapproximately 450 plaintiffs. The lawsuits seek to recover compensation for personal injury and property damage, and seek other relief. Each of the class action lawsuits include a demand that the $100 million the Utility announced would be available for assistance be placed under court supervision,relief, including punitive damages. These cases have been coordinated and also allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. One of the class action lawsuits was filed by Steve Dare and the other was filed by Danielle Ditrapani. The Utility has filed a petition on behalf of PG&E Corporation and the Utilityassigned to coordinate these lawsuitsone judge in the San Mateo County Superior Court. In its statement in supportThe trial of coordination,the first group of remaining cases began on January 2, 2013 with pretrial motions and hearings. On January 14, 2013, the court vacated the trial and all pending hearings due to the significant number of cases that have been settled outside of court. The court has urged the parties to settle the remaining cases. As of February 8, 2013, the Utility has stated that it is prepared to enterentered into early mediation in an effortsettlement agreements to resolve the claims with those plaintiffs willingof approximately 140 plaintiffs. It is uncertain whether or when the Utility will be able to do so. A hearing is scheduled for February 24, 2011.Another lawsuit was filedresolve the remaining claims through settlement.
Additionally, in
San Mateo County Superior Court asOctober 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 Utility maintains liability insurance for damagescase has been coordinated with the other cases in the approximate amountSan Mateo County Superior Court. The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of $992 millionthe court. On February 7, 2013, another purported shareholder derivative lawsuit was filed in excessU.S. District Court for the Northern 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 $10 million deductible. Althoughcomplaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility currently consider it likely that most(and other unnamed defendants) by individuals who seek certification of thecostsa class consisting of all California residents who were customers of the Utility incursbetween 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 third-partythe 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, relatingthe 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 discussion within MD&A under the heading, “Natural Gas Matters” and in Note 15: Commitments and Contingencies of the Notes to the Consolidated Financial Statements contained in the 2012 Annual Report, which discussions are incorporated herein by reference.
Pending CPUC Investigations and Potential Enforcement Matters
The CPUC is conducting three investigations pertaining to the Utility’s natural gas operations that relate to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) 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 Accidentaccident. In 2012, the SED issued investigative reports in each of these investigations alleging that the Utility committed numerous violations of applicable laws and regulations and recommending the CPUC impose penalties on the Utility. 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, The Utility Reform Network, and the City 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 SED.
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 ultimately be covered by this insurance, no amounts for insurance recoveriesissue one or more presiding officer’s decisions listing the violations determined to have been recorded ascommitted, 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 leak survey schedule. (The Utility has paid the penalty and completed all of the missed leak surveys.) As of December 31, 2010.2012, 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 the Utility associated with these or future reports that the Utility 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 unableuncertain how this matter will affect the investigative proceedings related to predictnatural 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 violations and timingthe number of such recoveries.For discussionpersons affected; and the good faith of other third-party claims relatingthe entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the San Bruno accident,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 the SED finds.
For more information, see discussions within MD&A under the heading, “Natural Gas Matters,” and Note 1515: Commitments and Contingencies−Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 20102012 Annual Report, which discussion isdiscussions are incorporated into this Item 3herein by reference.reference
Criminal Investigation
Pending InvestigationsOn 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 and Rancho Cordova AccidentsFor discussionaccident. These representatives have indicated that the Utility is a target of the pending investigations ofinvestigation. The Utility is cooperating with the San Bruno accidentinvestigation. PG&E Corporation and the Rancho Cordova accident, seeUtility 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. See the discussions within MD&A under the heading “Natural Gas Matters – Criminal Investigation,” and in Note 1515: Commitments and Contingencies of the Notes to the Consolidated Financial Statements in the 20102012 Annual Report, which discussion isdiscussions are incorporated into this Item 3herein by reference.
Item 4. [Removed and Reserved]Mine Safety Disclosures Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANTS The names, ages and positions of PG&E Corporation “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934 (“Exchange Act”) at February 1,
20112013 were as follows.
| | | | |
Name | | Age | | Position |
Peter A. DarbeeAnthony F. Earley, Jr. | | 58 63 | | Chairman of the Board, Chief Executive Officer, and President |
| Kent M. Harvey | | 52 54 | | Senior Vice President and Chief Financial Officer |
| Christopher P. Johns | | 50 52 | | President, Pacific Gas and Electric Company |
| Hyun Park | | 49 51 | | Senior Vice President and General Counsel |
| Greg S. Pruett | | 53 55 | | Senior Vice President, Corporate Affairs |
Rand L. Rosenberg | | 57 | | Senior Vice President, Corporate Strategy and Development |
| John R. Simon | | 46 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,
2011,2013, 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 |
| | | | |
Peter A. DarbeeAnthony F. Earley, Jr. | | Chairman of the Board, Chief Executive Officer, and President | | September 19, 200713, 2011 to present |
| | President and Chief Executive Officer, Pacific Gas and ElectricChairman of the Board, DTE Energy Company | | October 1, 2010 to September 5, 2008 to July 31, 200912, 2011 |
| | Chairman of the Board and Chief Executive Officer, | | July 1, 2007 to September 18, 2007 |
| | Chairman of the Board, Chief Executive Officer, and President | | January 1, 2006 to June 30, 2007 |
| | Chairman of the Board, Pacific Gas and Electric DTE Energy Company | | January 1, 2006August 1998 to May 31, 2007September 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 |
| | | | |
Name
| | Position
| | Period Held Office
|
| | 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 |
| | Vice President, General Counsel, and Secretary, Allegheny Energy, Inc. | | April 5, 2005 to October 17, 2006 |
| | |
| 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 |
| | |
Rand L. Rosenberg | | Senior Vice President, Corporate Strategy and Development | | November 1, 2005 to present |
| | |
| John R. Simon | | Senior Vice President, Human Resources | | April 16, 2007 to present |
| | Senior Vice President, Human Resources, Pacific Gas and Electric Company | | April 16, 2007 to present |
| | Executive Vice President, Global Human Capital, TeleTech Holdings, Inc. | | March 21, 2006 to April 13, 2007 |
| | Senior Vice President, Human Capital, TeleTech Holdings, Inc. | | July 31, 2001 to March 20, 2006 |
The names, ages and positions of the
Utility’sUtility's “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 1,
20112013 were as follows:
| | | | |
Name | | Age | | Position |
Peter A. Darbee | Anthony F. Earley, Jr. | | 5863 | | Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation |
| Christopher P. Johns | | 5052 | | President |
John S. Keenan | Nickolas Stavropoulos | | 6254 | | Executive Vice President, Gas Operations |
| Geisha J. Williams | | 51 | | Executive Vice President, Electric Operations |
| Karen A. Austin | | 51 | | Senior Vice President and Chief OperatingInformation Officer |
| Desmond A. Bell | | 4850 | | Senior Vice President, Safety and Shared Services and Chief Procurement Officer |
| Thomas E. Bottorff | | 5759 | | Senior Vice President, Regulatory RelationsAffairs |
| Helen A. Burt | | 5456 | | Senior Vice President and Chief Customer Officer |
| John T. Conway | | 5355 | | Senior Vice President, Energy Supply |
| Edward D. Halpin | | 51 | | Senior Vice President and Chief Nuclear Officer |
| Kent M. Harvey | | 5254 | | Senior Vice President, Financial Services |
| Gregory K. Kiraly | | 48 | | Senior Vice President, Electric Distribution Operations |
| Hyun Park | | 4951 | | Senior Vice President and General Counsel, PG&E Corporation |
| Greg S. Pruett | | 5355 | | Senior Vice President, Corporate Affairs |
Edward A. Salas | | 54 | | Senior Vice President, Engineering and Operations |
| John R. Simon | | 4648 | | Senior Vice President, Human Resources |
| Jesus Soto, Jr. | | 45 | | Senior Vice President, Gas Transmission Operations |
| Fong Wan | | 4951 | | Senior Vice President, Energy Procurement |
Geisha J. Williams | Dinyar B. Mistry | | 49 | | Senior Vice President, Energy Delivery |
Sara A. Cherry | | 4250 | | Vice President, Finance and 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,
2011,2013, 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 |
| | | | |
Peter A. DarbeeAnthony F. Earley, Jr. | | Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation | | September 19, 200713, 2011 to present |
| | President and Chief Executive OfficerChairman of the Board, DTE Energy Company | | October 1, 2010 to September 5, 2008 to July 31, 200912, 2011 |
| | Chairman of the Board and Chief Executive Officer, PG&E CorporationDTE Energy Company | | July 1, 2007August 1998 to September 18, 200730, 2010 |
| | Chairman of the Board | | January 1, 2006 to May 31, 2007 |
| | Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation | | January 1, 2006 to June 30, 2007 |
| | |
| 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 |
| | | | |
| Nickolas Stavropoulos | | Executive Vice President, Gas Operations | | June 13, 2011 to present |
| | Executive Vice President and Chief Operating Officer, U.S. Gas Distribution, National Grid | | August 2007 to March 31, 2011 |
| | | | |
| Geisha J. Williams | | Executive Vice President, Electric Operations | | June 1, 2011 to present |
| | Senior Vice President, Chief Financial Officer, and TreasurerEnergy Delivery | | OctoberDecember 1, 20052007 to May 31, 20072011 |
| | | | |
John S. KeenanKaren A. Austin | | Senior Vice President and Chief OperatingInformation Officer | | JanuaryJune 1, 20082011 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, GenerationSafety and Chief Nuclear OfficerShared Services | | December 19, 2005January 1, 2012 to December 31, 2007present |
| | |
Desmond A. Bell | | Senior Vice President, Shared Services and Chief Procurement Officer | | October 1, 2008 to presentDecember 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 |
| | Management Consultant, The Burt Group | | January 2003 to February 2006 |
| | |
| 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 present February 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 |
| | Vice President, General Counsel, and Secretary, Allegheny Energy, Inc. | | April 5, 2005 to October 17, 2006 |
| | |
| 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 |
| | | | |
Name
| | Position
| | Period Held Office
|
| | 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 |
| | |
Edward A. Salas | | Senior Vice President, Engineering and Operations | | April 11, 2007 to present |
| | Staff Vice President, Network Planning, Verizon Wireless | | May 2004 to April 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 Vice President, Global Human Capital, TeleTech | | March 21, 2006 to April 13, 2007 |
| Jesus Soto, Jr. | | Senior Vice President, Human Capital, TeleTech Holdings, Inc.Gas Transmission Operations | | July 13, 2001May 29, 2012 to March 20, 2006present |
| | 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 |
| | |
Geisha J. Williams | | Senior Vice President, Energy Delivery | | December 1, 2007 to present |
| Dinyar B. Mistry | | Vice President, Power Systems, Distribution, Florida PowerChief Financial Officer, and Light CompanyController | | July 2003October 1, 2011 to July 2007present |
| | |
Sara A. Cherry | | Vice President Finance and Chief Financial OfficerController, PG&E Corporation | | March 1,8, 2010 to present |
| | Senior Director, Internal AuditingVice President and Controller | | OctoberMarch 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 February 28,March 7, 2010 |
| | Director ofVice President, Internal AuditingAuditing/Compliance and ComplianceEthics, PG&E Corporation | | February 3,January 1, 2009 to September 30,July 31, 2009 |
| | Chief Financial Officer of Langer, Inc., a medicalVice President, Regulation and personal care products companyRates | | September 18, 200620, 2007 to December 5, 2006 |
| | Director, Management Reporting, Pacific Gas and Electric Company
| | January 2005 to January 2006
31, 2008 |
Item 5.Market for Registrant’sRegistrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities As of February
10, 2011,11, 2013, there were
75,86267,982 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
20102012 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 solely owned by PG&E Corporation. Information about the frequency,
amount, and
amountrestrictions upon the payment of, dividends on common stock declared by PG&E Corporation and the Utility is set forth in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity,
Note 6: Common Stock and
in Note 6Share-Based Compensation−Dividends of the Notes to the Consolidated Financial Statements,
and within MD&A under the heading “Liquidity and Financial Resources—Dividends,” in the
20102012 Annual Report, which information is incorporated
herein by
reference and included in Exhibit 13 to this report. A discussion of the restrictions on the payment of dividends with respect to PG&E Corporation’s and the Utility’s common stock is set forth under the section of MD&A entitled “Liquidity and Financial Resources — Dividends” and Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.reference.
Sales of Unregistered Equity Securities During the quarter ended December 31, 2010,2012, PG&E Corporation made equity contributions totaling $20$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 2010.2012.
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,
2010, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the fourth quarter of 2010,2012, 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
20102012 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
20102012 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 2010 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
20102012 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 2010 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 “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,
2010,2012, 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,
20102012 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
20102012 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 Information 2013 PG&E Corporation Short-Term Incentive Plan
Elimination of Excise Tax Gross-Up Payments for OfficersOn February 15, 2011,20, 2013, the Compensation Committee of the PG&E Corporation Board of Directors amended(“Committee”) approved the PG&E Corporation Officer Severance Policy (Officer Severance Policy) to reduce the benefits available to certain2013 Short-Term Incentive Plan (“STIP”) under which officers under the Officer Severance Policy. Currently, the Officer Severance Policy provides enhanced change-in-control (as defined in the Officer Severance Policy) severance benefits to officersand employees of PG&E Corporation atand the Senior Vice President level or higher,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 toemployee), customer (which includes operational reliability and the principal executive officerefficient completion of any entity listed inpipeline safety work), and corporate financial performance. The resulting STIP scores for each of these measures will have the Officer Severance Policy, which typically includes PG&E Corporation’s primary subsidiaries, including Pacific Gasfollowing weightings: safety (40%), customer (35%), and Electric Company (Covered Officers)corporate financial performance (25%). The Internal Revenue Code imposes an excise tax on change-in-control severance benefits ifCommittee also approved the value equals or exceeds a safe harbor limit equal to three times a recipient’s average annualized income. The Officer Severance Policy reimburses the Covered Officersspecific performance targets for excise taxes levied upon the change-in-control severance benefits.
The amendments to the Officer Severance Policy will eliminate excise tax gross-up payments for severance benefits triggered by a change in control (1) for current Covered Officers, effective three years after the current Covered Officers are given noticeeach of the change, and (2) for executive officers who become eligible to receive change-in-control severance benefits under the Officer Severance Policy on or after February 15, 2011. Under the amended Officer Severance Policy, a Covered Officer will receive severance that results in the best after-tax benefit to the Covered Officer, either by receiving the full change-in-control severance benefit with the excise tax paid by the Covered Officer, or by receiving a reduced severance calculated in a manner that results in a total severance benefit below the Internal Revenue Code’s safe harbor limit described above. There are no other policies, arrangements, or agreements that provide for excise tax gross-ups to any current officers of PG&E Corporation or Pacific Gas and Electric Company.
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
20112013 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
20112013 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
20102012 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the
20112013 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
and Director Independence Committee
DutiesMembership Requirements” and
Composition“Corporate Governance – Committee
Membership Requirements”Membership” in the Joint Proxy Statement relating to the
20112013 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,
(CD&A),” “Compensation Committee Report,” “Summary Compensation Table -
2010,2012,” “Grants of Plan-Based Awards in
2010,2012,” “Outstanding Equity Awards at Fiscal Year End -
2010,2012,” “Option Exercises and Stock Vested During
2010,2012,” “Pension Benefits
- 2010,– 2012,” “Non-Qualified Deferred Compensation
– 2012,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and
“2010“Compensation of Non-Employee Directors – 2012 Director Compensation” in the Joint Proxy Statement relating to the
20112013 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
20112013 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,
20102012 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
| | 3,842,313(1) | | $25.16 | | 7,856,348(2) |
Equity compensation plans not approved by shareholders
| | — | | — | | — |
Total equity compensation plans | | 3,842,313(1) | | $25.16 | | 7,856,348(2) |
| (1) | Includes 2,472,30245,597 phantom stock units, 2,101,484 restricted stock units and 3,088,896 performance shares. The weighted average exercise price reported in column (b) does not take these awards into account. The 1,219,940 performance shares included in this total reflects the number of shares that would be issued should PG&E Corporation achieve the maximum performance target for the applicable three-year period. 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 20102012 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’sCorporation Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2010.2012. 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 LTIP and the 2006 LTIP, see Note 66: Common Stock and Share-Based Compensation of the Notes to the Consolidated Financial Statements in the 20102012 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 PersonRelated Party Transactions
” “Review, Approval, and Ratification of Related Person Transactions” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company
––Board and Director
Independence and Qualifications”Independence” in the Joint Proxy Statement relating to the
20112013 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 20112013 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
20102012 Annual Report and are incorporated by reference in this report:
Consolidated Statements of Income for the Years Ended December 31, 2012, 2011, and 2010 2009,for each of PG&E Corporation and 2008Pacific Gas and Electric Company.
Consolidated Statements 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,
20102012 and
20092011 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31,
2010, 2009,2012, 2011, and
20082010 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Equity for the Years Ended December 31,
2010, 2009,2012, 2011, and
20082010 for PG&E Corporation.
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31,
2010, 2009,2012, 2011, and
20082010 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,
20102012 and
20092011 and for the Years Ended December 31,
2010, 2009,2012, 2011, and
2008.2010.
II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31,
2010, 2009,2012, 2011, and
2008.2010.
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: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) |
| | |
Number | | Exhibit Description |
3.3 | | Bylaws of PG&E Corporation amended as of September 16, 2009March 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2009March 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 February 17, 2010June 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K10-Q for the yearquarter ended December 31, 2009June 30, 2012 (File No. 1-2348), Exhibit 3.5)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) |
| |
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) |
| |
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) |
| |
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 | | Seventh Supplemental Indenture dated as of June 11, 2009 relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due June 10, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit 4.1) |
| |
4.9
| | 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) |
| | |
Exhibit
Number
| | Exhibit Description
|
4.10
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) |
| |
4.11
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) |
| |
4.12
| | Eleventh Supplemental Indenture dated as of October 12, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due October 11, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 12, 2010 (File No. 1-2348), Exhibit 4.1) |
| |
4.13
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) |
| 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'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) |
| 4.17 | | 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) |
| |
4.15
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 8, 2010,30, 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 |
| 10.3 | | Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and Electric Company, as borrower, (2) Wells Fargo Bank,Citibank, N.A., as administrative agent and a 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 syndication agent and a lender, (4) Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, and U.S. Bank, N.A., as documentationco-documentation agents and lenders, and (5) the following other lenders: Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, New York Branch, Goldman Sachs Bank USA, Mizuho Corporate 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, UBS Loan Finance LLC, Citibank,U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank RBC Bank (USA), JPMorgan Chase Bank, N.A., and The Northern Trust Company. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 20102011 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2) |
| |
10.2
10.4 | | Amended and Restated Unsecured RevolvingAmendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement entered into among (1) Pacific Gas and Electric Company, Citicorp North America, Inc.as borrower, (2) Citibank, N.A., as administrative agent and a lender, (3) JPMorgan Securities Inc.Chase Bank, N.A., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2) |
| | |
Exhibit
Number
| | Exhibit Description
|
10.3
| | Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007, filed as Exhibit 10.1 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2) |
| |
10.4
| | Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentationco-syndication agents and lenders, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1) |
| |
10.5
| | Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V.,(4) The Royal Bank of America, N.A.,Scotland plc and BarclaysWells Fargo Bank, Plc,National Association as documentationco-documentation agents and lenders, and (5) the following other lenders, dated February 26, 2007, filed as Exhibit 10.3 above (incorporated by reference to PG&E Corporationlenders: 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 Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)East West Bank |
| |
10.6
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) |
| |
10.7
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) |
| |
10.8
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) |
| 10.8* | | 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) |
*10.9
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'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) |
| 10.11* | | 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 10.3) |
| 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* | | Performance Share 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 10.4) |
Exhibit Number | | Exhibit Description |
| 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's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5) |
| 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'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 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 |
| 10.19* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. dated April 4, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.2) |
| 10.20* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Edward D. Halpin dated February 3, 2012 for employment starting April 1, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.21) |
| 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) |
| 10.22* | | 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) |
| 10.23* | | 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) |
| |
*10.10
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) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009) (File No. 1-12609), Exhibit 10.9 |
| |
*10.11
| | Letter regarding Compensation Arrangement between PG&E Corporation2009 and Peter A. Darbee effective Julyas of August 1, 20032011) (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) |
| | |
Exhibit
Number
| | Exhibit Description
|
*10.12
| | 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, 20082011 (File No. 1-12609), Exhibit 10.11) |
| |
10.25*10.13 | | 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) |
| |
*10.14
| | 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) |
| |
*10.15
| | 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) |
| |
*10.16
| | 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) |
| |
*10.17
| | Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.1) |
| |
*10.18
| | Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011 |
| |
*10.19
| | 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) |
10.27*10.20 | | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.21)2013 |
| |
*10.21
10.28* | | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 20112012 (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) |
| |
10.29*10.22 | | 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 |
*10.23
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) |
| |
10.31*10.24 | | 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 |
10.33*10.25 | | 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) |
| |
10.34*10.26 | | 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) |
Exhibit
Number
10.35 * | | Exhibit Description
|
*10.27
| | 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) |
| |
*10.28
| | 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) |
| |
*10.29
10.36* | | Resolution of the PG&E Corporation Board of Directors dated September 17, 2008,19, 2012, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.36)2013 |
| |
*10.30
10.37* | | Resolution of the Pacific Gas and Electric Company Board of Directors dated September 17, 2008,19, 2012, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.37)2013 |
| |
*10.31
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's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.31) |
| |
10.39*10.32 | | 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) |
| |
*10.33
10.40* | | PG&E Corporation 2006 Long-Term Incentive Plan, as amended through December 15, 2010effective 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's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.10) |
*10.34
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) |
*10.35
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) |
| |
*10.36
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 |
| |
*10.37
10.48* | | Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (amendments 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 10.45) |
| |
*10.38
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) |
| |
10.50*10.39 | | Form of Performance ShareRestricted Stock Unit Agreement for 20092011 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, 2011 (File No. 1-12609), Exhibit 10.3)10.9) |
| |
*10.40
| | 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) |
| | |
Exhibit
Number
| | Exhibit Description
|
*10.41
| | 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) |
| |
*10.42
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. 126091-12609 and File No. 1-2348), Exhibit 99.1) |
| |
*10.43
10.52* | | Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44) |
| |
*10.44
| | 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, 2008 (File No. 1-12609), Exhibit 10.6) |
| |
*10.45
| | Form of Amended and Restated Performance Share Agreement for 2007 grants (amendments 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 10.52) |
| |
*10.46
| | Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments 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 10.53) |
| |
*10.47
| | 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, 20102012 (File No. 1-12609), Exhibit 10.2) |
| 10.53* | | 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) |
*10.48
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 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 10.3) |
| 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) |
*10.49
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) |
| |
*10.50
| | 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) |
| |
*10.51
10.60* | | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51) |
| |
10.61*10.52 | | 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) |
| |
*10.53
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) |
| |
10.63*10.54 | | 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) |
| |
10.64*10.55 | | 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) |
| | |
Number
| | Exhibit Description |
*10.56
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) |
| |
10.66 *10.57 | | 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) |
| |
10.67*10.58 | | 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 |
| |
13 | | The following portions of the 20102012 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 |
| |
***101.LAB
| | XBRL Taxonomy Extension Labels Linkbase Document |
| |
***101.PRE
| | XBRL Taxonomy Extension Presentation 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 Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its subsidiary, Pacific Gas and Electric Company. |
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,
20102012 to be signed on their behalf by the undersigned, thereunto duly authorized.
| | | | | | | | |
| | PG&E CORPORATION | | | | PACIFIC GAS AND ELECTRIC COMPANY |
| | (Registrant) ANTHONY F. EARLEY, JR. | | (Registrant) CHRISTOPHER P. JOHNS |
| | | (Registrant)
Anthony F. Earley, Jr. | | | | (Registrant)
| | |
| | | | |
| | *PETER A. DARBEE
| | | | *CHRISTOPHER P. JOHNS
| | |
| | Peter A. Darbee
| | | | Christopher P. Johns | | |
By: | | | | |
By: | | Chairman of the Board, Chief Executive Officer, and President | By: | By: | | President | | |
| | | | |
| Date: | February 21, 2013 | Date: | February 17, 201121, 2013 |
| | Date: | | February 17, 2011 | | |
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 | | | | | | | | |
| | | | |
*PETER A. DARBEE
| | | | Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation) | | |
| ANTHONY F. EARLEY, JR. | | February 17, 201121, 2013 | | |
Peter A. DarbeeAnthony F. Earley, Jr. | | |
| | | | |
| | | | |
*CHRISTOPHERCHRISTOPHER P. JOHNS
| | | | President (Pacific (Pacific Gas and Electric Company)
| | | | February 17, 201121, 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 17, 201121, 2013 |
| Kent M. Harvey | | | |
| | | | |
| | | | |
*SARA A. CHERRY
DINYAR B. MISTRY | | | | Vice President, Finance and Chief Financial Officer, and Controller (Pacific Gas and Electric Company) | | | | February 17, 2011 |
Sara A. Cherry | | | | | | |
| | | | |
C. Principal Accounting Officer | | | | | | | | |
| | | | |
*DINYAR B. MISTRY
| | | | Vice President and Controller (PG&E Corporation and
Pacific Gas and Electric Company)
| | | | February 17, 201121, 2013 |
| Dinyar B. Mistry | | | |
| | | | |
| | | | |
D. DirectorsC. Principal Accounting Officer | | | | |
| | | | |
| | | | |
*DAVID R. ANDREWS
DINYAR B. MISTRY | | Vice President and Controller (PG&E Corporation) Vice President, Chief Financial Officer, and Controller (Pacific Gas and Electric Company) | | February 21, 2013 |
| Dinyar B. Mistry |
| | | | |
| D. Directors | | | | |
| | Director | | | | February 17, 201121, 2013 |
| David R. Andrews | | | | |
|
|
| | | | |
| | | | |
*LEWIS*LEWIS CHEW
| | | | Director | | | | February 17, 201121, 2013 |
| Lewis Chew | | | | |
| | | | |
| | | | | | | | |
*C.*C. LEE COX
| | | | Director | | | | February 17, 201121, 2013 |
| C. Lee Cox | | | | |
| | | | |
| | | | |
*PETER A. DARBEE
| | *ANTHONY F. EARLEY, JR. | | Director | | February 21, 2013 |
| Anthony F. Earley, Jr. | | February 17, 2011 | | |
Peter A. Darbee | | | | | | | | |
| | | | |
*MARYELLEN C. HERRINGER
| | *FRED J. FOWLER | | Director | | February 21, 2013 |
| Fred J. Fowler | | | | |
| | | | |
| *MARYELLEN C. HERRINGER | | Director | | February 17, 201121, 2013 |
| Maryellen C. Herringer | | | | |
| | | | |
| | | | |
*CHRISTOPHER*CHRISTOPHER P. JOHNS
| | | | Director (Pacific Gas and Electric Company only) | | | | February 17, 201121, 2013 |
| Christopher P. Johns | | | | |
| | | | |
| | | | |
*ROGER*ROGER H. KIMMEL
| | | | Director | | | | February 17, 201121, 2013 |
| Roger H. Kimmel | | | | |
| | | | |
| | | | |
*RICHARD*RICHARD A. MESERVE
| | | | Director | | | | February 17, 201121, 2013 |
| Richard A. Meserve | | | | |
| | | | |
| | | | |
*FORREST*FORREST E. MILLER
| | | | Director | | | | February 17, 201121, 2013 |
| Forrest E. Miller | | | | |
| | | | |
| | | | |
*ROSENDO*ROSENDO G. PARRA
| | | | Director | | | | February 17, 201121, 2013 |
| Rosendo G. Parra | | | | |
| | | | |
| | | | |
*BARBARA*BARBARA L. RAMBO
| | | | Director | | | | February 17, 201121, 2013 |
| Barbara L. Rambo | | |
| | | | |
| | | | |
*BARRY*BARRY LAWSON WILLIAMS
| | | | Director | | | | February 17, 201121, 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,
20102012 and
2009,2011, and for each of the three years in the period ended December 31,
2010,2012, and the
Company’sCompany's and the Utility’s internal control over financial reporting as of December 31,
2010,2012, and have issued our
reportreports thereon dated February
17, 2011;21, 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
20102012 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 17, 2011
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)
| | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Administrative service revenue | | $ | 53 | | | $ | 59 | | | $ | 119 | |
Equity in earnings of subsidiaries | | | 1,105 | | | | 1,231 | | | | 1,182 | |
Operating expenses | | | (55 | ) | | | (61 | ) | | | (105 | ) |
Interest income | | | 1 | | | | 1 | | | | 4 | |
Interest expense | | | (35 | ) | | | (43 | ) | | | (30 | ) |
Other income (expense) | | | 4 | | | | 11 | | | | (46 | ) |
| | | | | | | | | | | | |
Income before income taxes | | | 1,073 | | | | 1,198 | | | | 1,124 | |
Income tax benefit | | | 26 | | | | 22 | | | | 60 | |
| | | | | | | | | | | | |
Income from continuing operations | | | 1,099 | | | | 1,220 | | | | 1,184 | |
Gain on disposal of NEGT | | | — | | | | — | | | | 154 | |
| | | | | | | | | | | | |
Income Available for Common Shareholders | | $ | 1,099 | | | $ | 1,220 | | | $ | 1,338 | |
| | | | | | | | | | | | |
| | | |
Weighted average common shares outstanding, basic | | | 382 | | | | 368 | | | | 357 | |
| | | | | | | | | | | | |
| | | |
Weighted average common shares outstanding, diluted | | | 392 | | | | 386 | | | | 358 | |
| | | | | | | | | | | | |
Earnings per common share, basic | | $ | 2.86 | | | $ | 3.25 | | | $ | 3.64 | |
| | | | | | | | | | | | |
Earnings per common share, diluted | | $ | 2.82 | | | $ | 3.20 | | | $ | 3.63 | |
| | | | | | | | | | | | |
In calculating diluted EPS, PG&E Corporation applies the if-converted method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition,
| | | 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.
Accordingly, the basic and diluted earnings per share calculation for the ended December 31, 2008 reflects the allocation of earnings between In addition, during 2010, PG&E Corporation common stock andapplied the participating security.
“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)
| | | | | | | | |
| | | Balance at December 31, | |
| | | 2010 | | | 2009 | |
ASSETS | | | | | | | | |
Current Assets | | | | | | | | |
Cash and cash equivalents | | $ | 240 | | | $ | 193 | |
Advances to affiliates | �� | | 25 | | | | 20 | |
Deferred income taxes | | | 5 | | | | 3 | |
Income taxes receivable | | | 1 | | | | 9 | |
Other current assets | | | — | | | | 5 | |
| | | | | | | | |
Total current assets | | | 271 | | | | 230 | |
| | | | | | | | |
Noncurrent Assets | | | | | | | | |
Equipment | | | 14 | | | | 14 | |
Accumulated depreciation | | | (14 | ) | | | (13 | ) |
| | | | | | | | |
Net equipment | | | — | | | | 1 | |
Investments in subsidiaries | | | 11,618 | | | | 10,935 | |
Other investments | | | 89 | | | | 84 | |
Deferred income taxes | | | 116 | | | | 32 | |
Other | | | 2 | | | | 4 | |
| | | | | | | | |
Total noncurrent assets | | | 11,825 | | | | 11,056 | |
| | | | | | | | |
Total Assets | | $ | 12,096 | | | $ | 11,286 | |
| | | | | | | | |
| | |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | | | |
Current Liabilities | | | | | | | | |
Accounts payable – related parties | | $ | 106 | | | $ | 32 | |
Accounts payable – other | | | 3 | | | | 2 | |
Long-term debt, classified as current | | | — | | | | 247 | |
Income taxes payable | | | 1 | | | | 12 | |
Other | | | 213 | | | | 199 | |
| | | | | | | | |
Total current liabilities | | | 323 | | | | 492 | |
| | | | | | | | |
Noncurrent Liabilities | | | | | | | | |
Long-term debt | | | 349 | | | | 348 | |
Income taxes payable | | | 48 | | | | 14 | |
Other | | | 94 | | | | 99 | |
| | | | | | | | |
Total noncurrent liabilities | | | 491 | | | | 461 | |
| | | | | | | | |
Common Shareholders’ Equity | | | | | | | | |
Common stock | | | 6,878 | | | | 6,280 | |
Reinvested earnings | | | 4,606 | | | | 4,213 | |
Accumulated other comprehensive loss | | | (202 | ) | | | (160 | ) |
| | | | | | | | |
Total common shareholders’ equity | | | 11,282 | | | | 10,333 | |
| | | | | | | | |
Total Liabilities and Shareholders’ Equity | | $ | 12,096 | | | $ | 11,286 | |
| | | | | | | | |
| | | | |
| | | | | | | |
| 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)
| | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
Cash Flows from Operating Activities: | | | | | | | | | | | | |
Net income | | $ | 1,099 | | | $ | 1,220 | | | $ | 1,338 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | |
Depreciation and amortization | | | 38 | | | | 20 | | | | 27 | |
Equity in earnings of subsidiaries | | | (1,105 | ) | | | (1,231 | ) | | | (1,180 | ) |
Deferred income taxes and tax credits, net | | | 19 | | | | — | | | | — | |
Noncurrent income taxes receivable/payable | | | 34 | | | | (9 | ) | | | (108 | ) |
Current income taxes receivable/payable | | | (1 | ) | | | 148 | | | | 46 | |
Other | | | (50 | ) | | | (13 | ) | | | (150 | ) |
| | | | | | | | | | | | |
Net cash provided by (used in) operating activities | | | 34 | | | | 135 | | | | (27 | ) |
| | | | | | | | | | | | |
Cash Flows From Investing Activities: | | | | | | | | | | | | |
Investment in subsidiaries | | | (340 | ) | | | (721 | ) | | | (275 | ) |
Dividends received from subsidiaries | | | 716 | | | | 624 | | | | 596 | |
Other | | | (4 | ) | | | 10 | | | | (12 | ) |
| | | | | | | | | | | | |
Net cash provided by (used in) investing activities | | | 372 | | | | (87 | ) | | | 309 | |
| | | | | | | | | | | | |
Cash Flows From Financing Activities(1): | | | | | | | | | | | | |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2009 | | | — | | | | 348 | | | | — | |
Common stock issued | | | 303 | | | | 219 | | | | 225 | |
Common stock dividends paid | | | (662 | ) | | | (590 | ) | | | (546 | ) |
Other | | | — | | | | 1 | | | | 2 | |
| | | | | | | | | | | | |
Net cash used in financing activities | | | (359 | ) | | | (22 | ) | | | (319 | ) |
| | | | | | | | | | | | |
Net change in cash and cash equivalents | | | 47 | | | | 26 | | | | (37 | ) |
Cash and cash equivalents at January 1 | | | 193 | | | | 167 | | | | 204 | |
| | | | | | | | | | | | |
Cash and cash equivalents at December 31 | | $ | 240 | | | $ | 193 | | | $ | 167 | |
| | | | | | | | | | | | |
(1) | On January 15, 2010, PG&E Corporation paid a quarterly common stock dividend of $0.42 per share. On April 15, July 15, and October 15, 2010, PG&E Corporation paid quarterly common stock dividends of $0.455 per share. |
On January 15, 2009,
| | | 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 $0.39 per share. On April 15, July 15, and October 15, 2009, PG&E Corporation paid quarterly common stock dividends of $0.42 per share.On January 15, 2008, PG&E Corporation paid a quarterly common stock dividend of $0.36 per share. On April 15, July 15, and October 15, 2008, PG&E Corporation paid quarterly common stock dividends of $0.39 per share. Of the total dividend payments made by PG&E Corporation in 2008, approximately $28 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.
PG&E Corporation
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31,
2010, 2009,2012, 2011, and
20082010
(in millions)
| | | | | | | | | | | | | | | | | | | | |
| | | | | | Additions | | | | | | | |
Description | | Balance at
Beginning of
Period | | | Charged to
Costs and
Expenses | | | Charged to
Other
Accounts | | | Deductions (3) | | | Balance at End
of Period | |
Valuation and qualifying accounts deducted from assets: | | | | | | | | | | | | | | | | | | | | |
2010: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) (2) | | $ | 68 | | | $ | 56 | | | $ | — | | | $ | 43 | | | $ | 81 | |
| | | | | | | | | | | | | | | | | | | | |
2009: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) (2) | | $ | 76 | | | $ | 68 | | | $ | — | | | $ | 76 | | | $ | 68 | |
| | | | | | | | | | | | | | | | | | | | |
2008: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts(1) (2) | | $ | 58 | | | $ | 68 | | | $ | 11 | | | $ | 61 | | | $ | 76 | |
| | | | | | | | | | | | | | | | | | | | |
(1) | Allowance for uncollectible accounts is deducted from “Accounts receivable – Customers, net.”
|
(2) | Allowance for uncollectible accounts does not include NEGT.
|
(3) | 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,
2010, 2009,2012, 2011, and
20082010
(in millions)
| | | | | | | | | | | | | | | | | | | | |
| | | | | | 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: | | | | | | | | | | | | | | | | | | | | |
2010: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts (1) | | $ | 68 | | | $ | 56 | | | $ | — | | | $ | 43 | | | $ | 81 | |
| | | | | | | | | | | | | | | | | | | | |
2009: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts (1) | | $ | 76 | | | $ | 68 | | | $ | — | | | $ | 76 | | | $ | 68 | |
| | | | | | | | | | | | | | | | | | | | |
2008: | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts (1) | | $ | 58 | | | $ | 68 | | | $ | 11 | | | $ | 61 | | | $ | 76 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | 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, net.”
|
(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 16, 2009March 1, 2012 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2009March 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 February 17, 2010June 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K10-Q for the yearquarter ended December 31, 2009June 30, 2012 (File No. 1-2348), Exhibit 3.5)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) |
| | |
Exhibit
Number
| | Exhibit Description
|
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) |
| |
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 | | Seventh Supplemental Indenture dated as of June 11, 2009 relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due June 10, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit 4.1) |
| |
4.9
| | 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) |
| |
4.10
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) |
| |
4.11
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) |
| |
4.12
| | Eleventh Supplemental Indenture dated as of October 12, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due October 11, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 12, 2010 (File No. 1-2348), Exhibit 4.1) |
| |
4.13
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'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) |
| 4.17 | | 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) |
Exhibit Number | | Exhibit Description |
4.15
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) |
| | |
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 8, 2010,30, 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 |
| 10.3 | | Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and Electric Company, as borrower, (2) Wells Fargo Bank,Citibank, N.A., as administrative agent and a 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 syndication agent and a lender, (4) Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, and U.S. Bank, N.A., as documentationco-documentation agents and lenders, and (5) the following other lenders: Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, New York Branch, Goldman Sachs Bank USA, Mizuho Corporate 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, UBS Loan Finance LLC, Citibank,U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank RBC Bank (USA), JPMorgan Chase Bank, N.A., and The Northern Trust Company. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 20102011 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2) |
| |
10.2
10.4 | | Amended and Restated Unsecured RevolvingAmendment No. 1, dated as of December 24, 2012, to the May 31, 2011 Credit Agreement entered into among (1) Pacific Gas and Electric Company, Citicorp North America, Inc.as borrower, (2) Citibank, N.A., as administrative agent and a lender, (3) JPMorgan Securities Inc.Chase Bank, N.A., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2) |
| |
10.3
| | Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007, filed as Exhibit 10.1 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2) |
| |
10.4
| | Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentationco-syndication agents and lenders, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1) |
| |
10.5
| | Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V.,(4) The Royal Bank of America, N.A.,Scotland plc and BarclaysWells Fargo Bank, Plc,National Association as documentationco-documentation agents and lenders, and (5) the following other lenders, dated February 26, 2007, filed as Exhibit 10.3 above (incorporated by reference to PG&E Corporationlenders: 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 Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)East West Bank |
| |
10.6
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) |
| |
10.7
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) |
| | |
Exhibit
Number
| | Exhibit Description
|
10.8
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) |
| 10.8* | | 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 |
*10.9
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'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) |
| 10.11* | | 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 10.3) |
| 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* | | Performance Share 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 10.4) |
| 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's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5) |
| 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'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 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 |
| 10.19* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. dated April 4, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.2) |
| 10.20* | | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Edward D. Halpin dated February 3, 2012 for employment starting April 1, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.21) |
| 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) |
| 10.22* | | 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) |
| 10.23* | | 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) |
| |
*10.10
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) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009) (File No. 1-12609), Exhibit 10.9 |
| |
*10.11
| | Letter regarding Compensation Arrangement between PG&E Corporation2009 and Peter A. Darbee effective Julyas of August 1, 20032011) (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) |
| |
*10.12
| | 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, 20082011 (File No. 1-12609), Exhibit 10.11) |
| |
*10.13
Exhibit Number | | 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)Description |
| |
10.25*10.14 | | 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) |
| |
*10.15
| | 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) |
| |
*10.16
| | 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) |
| |
*10.17
| | Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.1) |
| |
*10.18
| | Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011 |
| |
*10.19
| | 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) |
10.27*10.20 | | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.21)2013 |
| |
*10.21
10.28* | | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2011 |
| | 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) |
| | Exhibit Description
|
*10.22
| | 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) |
| |
*10.23
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) |
| |
10.31*10.24 | | 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 |
10.33*10.25 | | 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) |
| |
10.34*10.26 | | 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) |
| |
10.35 *10.27 | | 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) |
| |
*10.28
| | 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) |
| |
*10.29
10.36* | | Resolution of the PG&E Corporation Board of Directors dated September 17, 2008,19, 2012, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.36)2013 |
| |
*10.30
10.37* | | Resolution of the Pacific Gas and Electric Company Board of Directors dated September 17, 2008,19, 2012, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.37)2013 |
| |
*10.31
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's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.31) |
| |
10.39*10.32 | | 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) |
| |
*10.33
10.40* | | PG&E Corporation 2006 Long-Term Incentive Plan, as amended through December 15, 2010effective 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's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.10) |
*10.34
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 |
*10.35
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) |
| | |
Exhibit
Number
| | Exhibit Description
|
*10.36
| | 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) |
| |
*10.37
10.48* | | Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (amendments 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 10.45) |
| |
*10.38
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) |
| |
10.50*10.39 | | Form of Performance ShareRestricted Stock Unit Agreement for 20092011 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, 2011 (File No. 1-12609), Exhibit 10.3)10.9) |
| |
*10.40
| | 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) |
| |
*10.41
| | 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) |
| |
*10.42
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. 126091-12609 and File No. 1-2348), Exhibit 99.1) |
| |
*10.43
10.52* | | Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44) |
| |
*10.44
| | 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, 2008 (File No. 1-12609), Exhibit 10.6) |
| |
*10.45
| | Form of Amended and Restated Performance Share Agreement for 2007 grants (amendments 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 10.52) |
| |
*10.46
| | Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments 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 10.53) |
| |
*10.47
| | 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, 20102012 (File No. 1-12609), Exhibit 10.2) |
| 10.53* | | 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) |
*10.48
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 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 10.3) |
| 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) |
*10.49
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) |
Exhibit
Number
| | Exhibit Description
|
*10.50
| | 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) |
| |
*10.51
10.60* | | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51) |
| |
10.61*10.52 | | 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) |
| |
*10.53
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) |
| |
10.63*10.54 | | 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) |
| |
10.64*10.55 | | 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) |
| |
*10.56
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) |
| |
10.66 *10.57 | | 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) |
| |
10.67*10.58 | | 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 |
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13 | | The following portions of the 20102012 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.” |
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21 | | Subsidiaries of the Registrant |
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23 | | Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP) |
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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 |
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24.2
24 | | Powers of Attorney |
| | |
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 |
| |
***101.LAB
| | XBRL Taxonomy Extension Labels Linkbase Document |
| |
***101.PRE
| | XBRL Taxonomy Extension Presentation 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 Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its subsidiary, Pacific Gas and Electric Company. |
