UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(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, 2008 | |
Or | |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from _________ to ___________ | |
Commission File Number | Exact Name of Registrant as specified in its charter | State or Other Jurisdiction of Incorporation or Organization | IRS Employer 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 San Francisco, California 94105 (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) (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: Common Stock, no par value | New York Stock Exchange | |
Pacific Gas and Electric Company: First Preferred Stock, cumulative, par value $25 per share: | NYSE Alternext | |
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 x No |
| Pacific Gas and Electric Company | Yes x 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 |
| Pacific Gas and Electric Company | Yes |
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 | Yesx No |
| Pacific Gas and Electric Company | Yes xNo |
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'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 | x |
| Pacific Gas and Electric Company | x |
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer”smaller reporting company (as defined in Rule 12b-2 of the Exchange Act.Act). (Check one).:
| PG&E Corporation | |||
| Pacific Gas and Electric Company | |||
Large accelerated filer x | Large accelerated filer | ||
| Accelerated filer | Accelerated filer | ||
| Non-accelerated filer | 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 |
| Pacific Gas and Electric Company | Yes |
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2005,2008, the last business day of the most recently completed second fiscal quarter:
| PG&E Corporation Common Stock | $ |
| Pacific Gas and Electric Company Common Stock | Wholly owned by PG&E Corporation |
Common Stock outstanding as of February 20, 2009: |
| PG&E Corporation: | |
| Pacific Gas and Electric Company: |
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 | Part I |
| Designated portions of the Joint Proxy Statement relating to the | Part III (Items 10, 11, 12, 13 and 14) |
TABLE OF CONTENTS
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| Energy Efficiency Programs | 11 | |
| Demand Response Programs | 12 | |
| Self-Generation Incentive Program and California Solar Initiative | 12 | |
| Low-Income Energy Efficiency Programs and California Alternate Rates for Energy | 12 | |
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| 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
Item 1.BusinessBusiness.
PG&E Corporation, incorporated in California in 1995, is an energy-baseda holding company thatwhose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company or the Utility,(“Utility”) a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution,distribution; electricity generation, procurement, and transmission,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 55.1 million electricity distribution customers and approximately 4.24.3 million natural gas distribution customers at December 31, 2005.2008. The Utility had approximately $33.8$40.5 billion of assets at December 31, 2005,2008 and generated revenues of approximately $11.7$14.6 billion in 2005.2008. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission or the CPUC,(“CPUC”), and the Federal Energy Regulatory Commission or the FERC.(“FERC”).
The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility file various reports with the Securities and Exchange Commission or the SEC.(“SEC”). These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge on both PG&E Corporation's website, www.pgecorp.comwww.pgecorp.com, and the Utility's website, www.pge.comwww.pge.com. The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.
At December 31, 2005,2008, PG&E Corporation and its subsidiaries had approximately 19,80021,667 regular employees, including approximately 19,50021,451 regular employees of the Utility. Of the Utility's regular employees, approximately 12,80014,649 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO or IBEW;(“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC or ESC;(“ESC”); and the Service Employees International Union, Local 24/7 or SEIU. The ESC and(“SEIU”). One IBEW collective bargaining agreements expireagreement expires on December 31, 2008.2011 and the other IBEW collective bargaining agreement expires on December 31, 2010. The ESC collective bargaining agreement expires on December 31, 2009. The Utility and the ESC reached an agreement in January 2009 to extend the collective bargaining agreement until December 31, 2011, subject to ratification by members of the ESC. The SEIU collective bargaining agreement expires on February 28,July 31, 2009.
This combined Annual Report on Form 10-K, including the information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2008 (“2008 Annual Report”), contains forward-looking statements that are necessarily subject to various risks and uncertainties, the realization or resolution of which are outside of management's control.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 atas of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated Utility rate base, estimated environmental remediation liabilities, estimated tax liabilities, the anticipated outcome of various regulatory and legal proceedings, estimated future cash flows, and the level of future equity or debt issuances, and are also identified by words such as "assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "aim, " "may," "might," "should," "would," "could," "goal," "potential"“assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim, “ “may,” “might,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. PG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, timely recover its authorized costs, and earn its authorized rate of return. 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, are discussed below in Item 1A. Risk Factors. These factors include, but are not limited to:
| · | |
| · | |
| · | the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas |
| · | |
| · | |
| · | changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology, including the development of alternative energy sources, |
| · | |
| · | whether the Utility can maintain the cost savings it has recognized from operating efficiencies it has achieved and identify and successfully implement additional sustainable cost-saving measures; |
| · | whether the |
| · | whether the Utility achieves the CPUC’s energy efficiency targets and recognizes any incentives the Utility may |
| · |
| · | |
| · | |
| · | |
| · | |
| · | the impact of environmental laws and regulations and |
| · | the effect of municipalization, direct access, community choice aggregation, or other forms of bypass; and |
| · | the impact of changes in federal or state tax laws, policies, or regulations. |
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.
2005 | 2004 | 2003 | 2002 | 2001 | ||||||
| Customers (average for the year): | ||||||||||
| Residential | 4,353,458 | 4,366,897 | 4,286,085 | 4,171,365 | 4,165,073 | |||||
| Commercial | 509,786 | 509,501 | 493,638 | 483,946 | 484,430 | |||||
| Industrial | 1,271 | 1,339 | 1,372 | 1,249 | 1,368 | |||||
| Agricultural | 78,876 | 80,276 | 81,378 | 78,738 | 81,375 | |||||
| Public street and highway lighting | 28,021 | 27,176 | 26,650 | 24,119 | 23,913 | |||||
| Other electric utilities | 4 | 3 | 4 | 5 | 5 | |||||
| Total (1) | 4,971,362 | 4,985,192 | 4,889,127 | 4,759,422 | 4,756,164 | |||||
| Deliveries (in GWh):(2) | ||||||||||
| Residential | 29,752 | 29,453 | 29,024 | 27,435 | 26,840 | |||||
| Commercial | 32,375 | 32,268 | 31,889 | 31,328 | 30,780 | |||||
| Industrial | 14,932 | 14,796 | 14,653 | 14,729 | 16,001 | |||||
| Agricultural | 3,742 | 4,300 | 3,909 | 4,000 | 4,093 | |||||
| Public street and highway lighting | 792 | 2,091 | 605 | 674 | 418 | |||||
| Other electric utilities | 33 | 28 | 76 | 64 | 241 | |||||
| Subtotal | 81,626 | 82,936 | 80,156 | 78,230 | 78,373 | |||||
| California Department of Water Resources (DWR) | (20,476) | (19,938) | (23,554) | (21,031) | (28,640) | |||||
| Total non-DWR electricity | 61,150 | 62,998 | 56,602 | 57,199 | 49,733 | |||||
| Revenues (in millions): | ||||||||||
| Residential | $3,856 | $3,718 | $3,671 | $3,646 | $3,396 | |||||
| Commercial | 4,114 | 4,179 | 4,440 | 4,588 | 4,105 | |||||
| Industrial | 1,232 | 1,204 | 1,410 | 1,449 | 1,554 | |||||
| Agricultural | 446 | 491 | 522 | 520 | 525 | |||||
| Public street and highway lighting | 66 | 71 | 69 | 73 | 60 | |||||
| Other electric utilities | 4 | 22 | 24 | 10 | 39 | |||||
| Subtotal | 9,718 | 9,685 | 10,136 | 10,286 | 9,679 | |||||
| DWR | (1,699) | (1,933) | (2,243) | (2,056) | (2,173) | |||||
| Direct access credits | — | — | (277) | (285) | (461) | |||||
| Miscellaneous(3) | 235 | (248) | (52) | 193 | 244 | |||||
| Regulatory balancing accounts | (327) | 363 | 18 | 40 | 37 | |||||
| Total electricity operating revenues | $7,927 | $7,867 | $7,582 | $8,178 | $7,326 | |||||
| Other Data: | ||||||||||
| Average annual residential usage (kWh) | 6,834 | 6,744 | 6,772 | 6,577 | 6,444 | |||||
| Average billed revenues (cents per kWh): | ||||||||||
| Residential | 12.96 | 12.62 | 12.65 | 13.29 | 12.65 | |||||
| Commercial | 12.71 | 12.95 | 13.92 | 14.65 | 13.34 | |||||
| Industrial | 8.25 | 8.14 | 9.62 | 9.84 | 9.71 | |||||
| Agricultural | 11.92 | 11.41 | 13.35 | 13.00 | 12.83 | |||||
| Net plant investment per customer | $2,966 | $2,790 | $2,689 | $2,105 | $2,018 |
Generation Type | County Location | Number of Units | Net Operating Capacity (MW) | |||
| Nuclear: | ||||||
| Diablo Canyon | San Luis Obispo | 2 | 2,174 | |||
| 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: | ||||||
| Humboldt Bay(1) | Humboldt | 2 | 105 | |||
| Hunters Point(2) | San Francisco | 2 | 215 | |||
| Mobile turbines | Humboldt | 2 | 30 | |||
| Fossil fuel subtotal | 6 | 350 | ||||
| Total | 118 | 6,420 |
2006 | 2007 | 2008 | 2009 | 2010 | |||||
Unit 1 | |||||||||
| Refueling | - | April | - | January | October | ||||
| Duration (days) | - | 35 | - | 80 | 35 | ||||
| Startup | - | June | - | April | November | ||||
Unit 2 | |||||||||
| Refueling | April | - | February | October | - | ||||
| Duration (days) | 45 | - | 80 | 35 | - | ||||
| Startup | June | - | April | November | - |
customer information. The DWR is currently legally and financially responsible for these contracts. The DWR has stated publicly in the past that it intended to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code, or the Settlement Agreement, provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:provide that:
| · |
| · | the Utility's |
| · | 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 |
| · | 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 |
(As discussed below under “Item 3—Legal Proceedings,” the California Attorney General and the City and County of San Francisco have alleged that PG&E Corporation and its directors, as well as the directors of the Utility, violated the CPUC’s holding company conditions during the California 2000-2001 energy crisis. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders.)
The CPUC also has adopted complex and detailed rules governing transactions between California's electricity and 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. In December 2006, the CPUC revised its rules to, among other changes:
| · | emphasize that the |
| · | require prior CPUC |
| · | require certain key officers to |
| · | 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 |
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 Purchase AgreementsAct of 1935, the Natural Gas Act of 1938 and the Public Utility Regulatory Policies Act of 1978 (“PURPA”).
This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations and regulatory mechanisms affecting the Utility. These summaries are not an exhaustive description of all the laws, regulations and regulatory proceedings that affect the Utility. The energy laws, regulations and regulatory proceedings may change or be implemented or applied in a way that the Utility does not currently anticipate. For discussion of specific pending regulatory proceedings that are expected to affect the Utility see the section of MD&A entitled “Regulatory Matters” in the 2008 Annual Report.
The FERC regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities; tariffs and conditions of service of regional transmission organizations, including the CAISO; and the terms and rates of wholesale electricity sales. The EPAct granted the FERC significant new responsibilities to oversee the reliability of the nation’s electricity transmission grid, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest. The EPAct also expanded the FERC’s authority to impose penalties for violation of certain federal statutes, including the Federal Power Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations. The FERC can impose penalties of up to $1,000,000 per day per violation. The FERC has jurisdiction over the Utility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities, and the interstate sale and transportation of natural gas.
Electric Reliability Standards; Development of Transmission Grid. As part of its directive to oversee the development of mandatory electric reliability standards to protect the national electric transmission system, the FERC certified the North American Electric Reliability Corp. (“NERC”), as the nation’s Electric Reliability Organization under the EPAct of 2005. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval. The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council (“WECC”). The Utility must self-certify compliance to the WECC on an annual basis, and the compliance program encourages self-reporting of violations. WECC staff, with participation by the NERC and the FERC, will also perform a regular compliance audit of the Utility every three years. In addition, the WECC and the NERC may perform spot checks or other interim audits, reports, or investigations. Under FERC authority the WECC, NERC, and/or FERC may impose penalties up to $1,000,000 per day per violation.
The FERC also has issued rules on electric transmission pricing reforms designed to promote needed investment in energy infrastructure, to reduce transmission congestion, and to require transmission organizations with organized electricity markets to make long-term firm transmission rights available to load-serving entities, so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk. In addition, 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.
The Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation and Water Agenciesdecommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“Humboldt Bay Unit 3”). NRC regulations require extensive monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.
The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. Under the terms of these licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by the Diablo Canyon plant. For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters – Nuclear Fuel Disposal,” below.
The Utility has contracts withUtility's operations have been significantly affected by various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts' and water agencies' debt service requirements, regardless of whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurredstatutes passed by the suppliers. These contracts expire on various dates from 2005 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 5% of the Utility’s 2005 electricity sources, approximately 5% of the Utility's 2004 electricity sources and approximately 5% of the Utility's 2003 electricity sources.California Legislature, including:
| · | Assembly Bill 1890. Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry, commencing in 1998, which was intended to create a competitive market for electricity generation and give customers of the investor-owned utilities the ability to choose “direct access” by buying energy from a service provider other than the regulated utilities. (Subsequent legislation, described below, suspended direct access during the California energy crisis of 2000-2001.) Among other provisions, 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. |
| · | Assembly Bill 1X. Assembly Bill 1X was enacted during the California 2000-2001 energy crisis when the California investor-owned electric utilities were no longer able to buy electricity. Assembly Bill 1X authorized the California Department of Water Resources (“DWR”) beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers. Assembly Bill 1X required the California investor-owned electric utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWR's billing and collection agent. To ensure that the DWR recovers its costs to procure electricity, Assembly Bill 1X required the CPUC to suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity pursuant to Assembly Bill 1X. The current DWR contracts terminate at various dates through 2015. |
| · | Assembly Bill 57. Assembly Bill 57, enacted in September 2002 and amended by Senate Bill 1976, required the California investor-owned utilities to resume purchasing power on January 1, 2003, required the CPUC to allocate electricity to be provided under the DWR contracts among the customers of the California investor-owned electric utilities, requires the utilities to file short- and long-term electricity resource procurement plans with the CPUC for approval, and authorizes the utilities to timely recover their reasonable wholesale procurement costs incurred under a CPUC-approved procurement plan through the establishment of new electricity procurement balancing accounts that reflect differences between recorded revenues and costs incurred under the approved procurement plans. |
| · | Senate Bill 1078. Senate Bill 1078, enacted in September 2002 (as amended by Senate Bill 107, enacted in September 2006 and effective on January 1, 2007) established the renewables portfolio standard (“RPS”) program, which requires each California retail seller of electricity, except municipal utilities, to increase its purchases of eligible renewable energy (such as biomass, |
| · | small hydroelectric, wind, solar and geothermal energy) by at least 1% of its retail sales, so that the amount of electricity purchased from eligible renewable resources equals at least 20% of its total retail sales by the end of 2010. An unexcused failure to satisfy the RPS targets may result in a penalty of five cents per kilowatt hour with an annual penalty cap of $25 million. The California Legislature is considering proposals to increase the RPS mandate to at least 33% by 2020. |
| · | Assembly Bill 380. Assembly Bill 380, enacted in September 2005, requires the CPUC, in consultation with the CAISO, to establish resource adequacy requirements for all load-serving entities, including the California investor-owned electric utilities but excluding local publicly owned electric utilities. Assembly Bill 380 requires each load-serving entity to maintain physical generating capacity adequate to meet its load requirements, including peak demand and planning and operating reserves, deliverable to locations and at times as may be necessary to provide reliable electric service. |
| · | Assembly Bill 32. Assembly Bill 32, enacted in September 2006, requires the California Air Resources Board (“CARB”) to adopt regulations to limit statewide greenhouse gas emission, to 1990 levels by 2020, with certain limits beginning in 2012. (See “Environmental Matters” below for more information.) |
| · | Senate Bill 1368. Senate Bill 1368, also enacted in September 2006, prohibits any load-serving entity, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload generation (i.e., electricity generation from a power plant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%) unless it complies with a greenhouse gas emission performance standard. (See “Environmental Matters” below for more information.) |
PG&E Corporation and the Utility entered into several new renewable power purchase contractsa settlement agreement with the CPUC on December 19, 2003, to resolve the Utility's proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that will helphad been pending in the Utility meet its goals.
permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. (For more information see “Environmental MattersWater Quality” below.)
The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate, and maintain the Utility's electric utilities relinquished control, but not ownership,and natural gas facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In addition, charter cities can negotiate their fees. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term, 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 transmission facilitiespolice powers relating to the California Independent System Operator, 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 the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and ratesuse public property for transmission service are set by the FERC. The ISO, which is regulated by the FERC, controls the operation of the transmission systemUtility's business and provides open access transmission service on a nondiscriminatory basis. The ISO also is responsible for assuring that the reliability of the transmission system is maintained.to conduct certain related operations.
Competition
2005 | 2004 | 2003 | 2002 | 2001 | |||||
| Customers (average for the year): | |||||||||
| Residential | 3,929,117 | 3,812,914 | 3,744,011 | 3,738,524 | 3,705,141 | ||||
| Commercial | 216,749 | 215,547 | 208,857 | 206,953 | 205,681 | ||||
| Industrial | 962 | 2,178 | 1,988 | 1,819 | 1,764 | ||||
| Other gas utilities | 6 | 6 | 6 | 5 | 6 | ||||
| Total | 4,146,834 | 4,030,645 | 3,954,862 | 3,947,301 | 3,912,592 | ||||
| Gas supply (MMcf): | |||||||||
| Purchased from suppliers in: | |||||||||
| Canada | 204,884 | 205,180 | 196,278 | 210,716 | 209,630 | ||||
| California | (18,951) | (9,108) | (7,421) | 19,533 | 20,352 | ||||
| Other states | 103,237 | 103,801 | 102,941 | 67,878 | 76,589 | ||||
| Total purchased | 289,170 | 299,873 | 291,798 | 298,127 | 306,571 | ||||
| Net (to storage) from storage | (3,659) | (532) | 1,359 | (218) | (27,027) | ||||
| Total | 285,511 | 299,341 | 293,157 | 297,909 | 279,544 | ||||
| Utility use, losses, etc.(1) | (14,312) | (19,287) | (14,307) | (16,393) | (8,988) | ||||
| Net gas for sales | 271,199 | 280,054 | 278,850 | 281,516 | 270,556 | ||||
| Bundled gas sales (MMcf): | |||||||||
| Residential | 194,108 | 201,601 | 198,580 | 202,141 | 197,184 | ||||
| Commercial | 77,056 | 78,080 | 79,891 | 78,812 | 72,528 | ||||
| Industrial | 35 | 373 | 379 | 563 | 831 | ||||
| Other gas utilities | — | — | — | — | 13 | ||||
| Total | 271,199 | 280,054 | 278,850 | 281,516 | 270,556 | ||||
| Transportation only (MMcf): | 572,869 | 597,706 | 525,353 | 508,090 | 646,079 | ||||
| Revenues (in millions): | |||||||||
| Bundled gas sales: | |||||||||
| Residential | $2,336 | $1,944 | $1,836 | $1,379 | $2,308 | ||||
| Commercial | 885 | 712 | 697 | 499 | 783 | ||||
| Industrial | — | — | 1 | 3 | 16 | ||||
| Other gas utilities | — | — | 1 | 1 | — | ||||
| Miscellaneous | (22) | (29) | (31) | 127 | (93) | ||||
| Regulatory balancing accounts | 340 | 316 | 68 | 11 | (253) | ||||
| Bundled gas revenues | 3,539 | 2,943 | 2,572 | 2,020 | 2,761 | ||||
| Transportation service only revenue | 238 | 270 | 284 | 316 | 375 | ||||
| Operating revenues | $3,777 | $3,213 | $2,856 | $2,336 | $3,136 | ||||
| Selected Statistics: | |||||||||
| Average annual residential usage (Mcf) | 49 | 53 | 53 | 54 | 53 | ||||
| Average billed bundled gas sales revenues per Mcf: | |||||||||
| Residential | $12.04 | $9.64 | $9.25 | $6.82 | $11.70 | ||||
| Commercial | 11.48 | 9.12 | 8.73 | 6.33 | 10.80 | ||||
| Industrial | 0.61 | (0.56) | 2.48 | 4.35 | 19.15 | ||||
| Average billed transportation only revenue per Mcf | 0.42 | 0.45 | 0.54 | 0.62 | 0.58 | ||||
| Net plant investment per customer | $1,262 | $1,266 | $1,261 | $1,006 | $970 | ||||
2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||||||||||||
MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | |||||||||||||||||||||
| Canada | 204,884 | $ | 7.12 | 205,180 | $ | 5.37 | 196,278 | $ | 4.73 | 210,716 | $ | 2.42 | 209,630 | $ | 4.43 | |||||||||||||||
| California(1) | (18,951 | ) | $ | 7.70 | (9,108 | ) | $ | 4.89 | (7,421 | ) | $ | 3.39 | 19,533 | $ | 2.88 | 20,352 | $ | 11.55 | ||||||||||||
| Other states (substantially all U.S southwest) | 103,237 | $ | 7.10 | 103,801 | $ | 5.44 | 102,941 | $ | 4.63 | 67,878 | $ | 3.04 | 76,589 | $ | 10.41 | |||||||||||||||
| Total/weighted average | 289,170 | $ | 7.07 | 299,873 | $ | 5.41 | 291,798 | $ | 4.73 | 298,127 | $ | 2.59 | 306,571 | $ | 6.40 | |||||||||||||||
Pipeline | Expiration Date | Quantity MDth per day | Demand Charges for the Year Ended December 31, 2005 (In millions) | ||||
| TransCanada NOVA Gas Transmission, Ltd. | 12/31/2007 | (a) | 616 | 28.0 | |||
| TransCanada PipeLines Ltd., B.C. System | 10/31/2007 | 607 | 13.0 | ||||
| Gas Transmission Northwest Corporation | 10/31/2007 | 610 | 54.8 | ||||
| Transwestern Pipeline Co. | 03/31/2007 | 150 | 20.5 | ||||
| El Paso Natural Gas Company (b) | Various | 202 | 19.2 |
Historically, energy utilities operated as regulated monopolies within service territories wherein 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, energy utilities have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies. The most significant of these services are the commodity components—the supply of electricity and natural gas. The driving forces behind these competitive pressures have been customers who believe that they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators responded to these forces by providing for more competition in the energy industry. Regulators and legislators, to varying degrees, have required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.
Federal. At the federal level, many provisions of the EPAct support the development of competition in the wholesale electric market. The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.
Even before the passage of the EPAct, the FERC's policies have 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, or RTOs, and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. The ISO alsoOn February 16, 2007, the FERC issued its own comprehensive energy market design proposal to effect changes toOrder 890, which is designed to: (1) strengthen the structure and operationform of the California electricity market. The first phaseOATT 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 ISO’s new market design has been approved byOATT to reduce opportunities for undue discrimination and facilitate the FERCFERC’s enforcement; and was implemented by the ISO(3) increase transparency in the fourth quarter of 2004. On February 14, 2006, the ISO filed its proposed tariff language with the FERCrules applicable to implement the balance of its market design proposal. Assuming FERC approval, the balanceplanning and use of the ISO’s new market design could be implemented as early as November 2007.transmission system.
competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generatorgeneration and transmission infrastructure,transmission. Under the FERC issued final rules on the interconnection of generators larger than 20 MW withand associated tariffs, a transmission system. The new rules require regulated transmission providers, such as the Utility or the ISO, generally to use standard interconnection procedures and a standard agreement for generator interconnections. These rules required the Utility and the ISO to revise the current form of agreements and procedures used when constructing facilities to interconnect new generators. In July 2005, the FERC accepted tariff changes filed by the Utility and the ISO to implement the new rules. In doing so, the FERC confirmed that the ISO is authorized to implement California-specific modifications to the FERC's pro forma agreement and procedures for new interconnections under what is known as an "independent entity variation." The new rules, tariffs and related interconnection procedures establish time-frames for completing studies on behalf of new generator applicants, and codifyis required to pay for the FERC's preexisting policy regarding financing of transmission system upgrades needed in order to interconnect a newthe generator. Under this policy, theThe generator must finance such upgrade facilities in the first instance, but then iswill be reimbursed the funds, with interest, over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades is then is recovered by the Utilityregulated transmission provider in its overall transmission rates.
Assembly Bill 1890 also permitted retail end-use customers to choose their energy service providers (i.e.,provider by becoming a direct access customers). Thecustomer. To ensure that the DWR recovers its costs to procure electricity for the customers of the investor-owned electric utilities, Assembly Bill 1X required the CPUC suspendedto suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity on behalf of the customers of the California investor-owned electric utilities. The CPUC suspended direct access on September 20, 2001.2001, but allowed existing direct access customers to continue being served by alternative energy service providers, rather than investor-owned electric utilities. The CPUC has assessed an additional charge on certain direct access customers to avoid a shift of costs from direct access customers to customers who receive bundled service. The CPUC is actively investigating how the DWR can terminate its obligations under the power contracts, by assignment or otherwise, to hasten the reinstatement of direct access.
In addition, the Utility’s customers may, under certain circumstances, obtain power from a “community choice aggregator” instead of from the Utility. California ABAssembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under ABAssembly Bill 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators' customers and would be those customers' provider of electricity of last resort. However, once registration has occurred, each community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. ToThe CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator will pay an appropriate share of the DWR's and the Utility's costs. ABservices. Assembly Bill 117 also authorized the Utility to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from customers any costs of implementing the program not reasonably attributable to a community choice aggregator. In December 2005, the CPUC adopted rules that allow for the implementation ofNo cities or counties are currently operating as community choice aggregation.aggregators, but the San Joaquin Valley Power Authority has filed an implementation plan and stated that it may begin operating in 2009. In addition, the County of Marin and several cities in that county have voted to pursue community choice aggregation and have formed a joint powers agency to do so, but have not yet filed an implementation plan.
FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service regardless of 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 FERCthe FERC’s rules and regulations applicable to interstate pipelines.
the Utility's natural gas customers into two categories: “core” customers, which are primarily small commercial and residential customers, and “non-core” customers, which are primarily industrial, large commercial and electric generation customers. Under the Gas Accord settlement agreement,structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services. All services are offered on a CPUC-approvednondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller, downstream local transmission systems.
The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties, under whichwas approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods. In September 2007, the CPUC approved the Gas Accord IV covering 2008 through 2010. The Gas Accord separated the Utility’s natural gas transportationtransmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services the Utility provides were separatedby creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for ratemaking purposes fromtrading of firm capacity rights. Additionally, the Utility's distribution services. The Gas Accord changedeliminated balancing account protection for some services, increasing the terms of service and rate structure for natural gas transportation, allowing the Utility's core customers greater flexibility to purchase natural gas from competing suppliers. The Utility's noncore customers purchase their natural gas from producers, marketers and brokers, and purchase their preferred mix of transportation, storage and distribution services from the Utility. Although they can select the gas suppliers of their choice, substantially all core customers buy natural gas, as well as transportation and distribution services, from the Utility as a bundled service. The Gas Accord market structure has been extended by the CPUC through 2007.Utility’s risk/reward potential.
The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility's market share for transportation
of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility's case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, the Utility's market share of transportation services into southern California decreases. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.
The group intends to seek market commitments fordevelopment and construction of the Pacific Connector Gas Pipeline depends upon the construction of the proposed pipeline projectLNG terminal at Jordan Cove by Fort Chicago Energy Partners, L.P. PG&E Corporation cannot predict whether Fort Chicago Energy Partners, L.P. will be successful in completing the development and to begin environmental assessments alongconstruction of its proposed LNG terminal. In addition, the proposed route in April 2006. The group plans to file an application to seek the FERC's approval for the new pipeline by January 2007. Subject to regulatory approval,development and construction of the proposed LNG terminal and pipelinethe proposed Pacific Connector Gas Pipeline are anticipatedsubject to obtaining required permits, regulatory approvals, and commitments under long-term capacity contracts. Assuming the required permits, authorizations, and long-term capacity commitments are timely received and that other conditions are timely satisfied, the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline could begin commercial operation in 2010.2013.
Ratemaking Mechanisms
The Utility’s rates for electricity and natural gas utility services are based on its costs of service.providing service (“cost-of-service ratemaking”). Before setting rates, can be set, the CPUC and the FERC must determine the annual amount of “revenuerevenue (“revenue requirements”) that the Utility is authorized to collect from its customers to recover the Utility’s operating and capital costs.customers. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations are established by the FERC. Revenue
Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of
providing utility services includingas well as a return of, and a fair rate of return on, its investment in utility facilities (“rate base”). Revenue requirements are primarily determined based on the Utility’s forecast of future costs. These costs include the Utility’s costs of electricity and natural gas purchased for its customers, operating expenses, administrative and general expenses, depreciation, taxes, and public purpose programs.
Regulatory balancing accounts are used to adjust the Utility’s revenue requirements. Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations. In general, electricity sales are higher in the summer months and natural gas sales are higher in the winter months. Cost balancing accounts track differences between the Utility’s incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes that can be affected by seasonal demand, weather, and other factors. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.
To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial and agricultural) and to various service components (mainly customer, demand, and energy). Specific rate components are designed to produce the required revenue. Rate changes become effective prospectively on or after the date of CPUC or FERC decisions. Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.
Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base. To the extent that the Utility is unable to recover its costs through rates because the Utility’s actual costs are determined to be unreasonable or are higher than forecast, theThe Utility may be unable to earn its authorized rate of return.return because the CPUC or the FERC excludes the Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.
While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on the extent to which the utilities meet objective or fixed standards or goals, such as reliability standards or energy efficiency goals, instead of on the cost of providing service.
The Utility's primary revenue requirement proceedingGeneral Rate Case (“GRC”) is the general rate case, or GRC, filed with the CPUC. In the GRC,primary proceeding in which the CPUC authorizesdetermines the amount of revenue requirements that the Utility is authorized to collect from customers an amount known as base revenues to recover basethe Utility’s basic business and operational costs related to the Utility'sits electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC typicallyevery three years. The CPUC sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedingsperiod based on a forecast of costs for the first or test,“test” year. After authorizing the revenue requirements, the CPUC allocates revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levels. Typical interveners in the Utility's GRC include the OfficeCPUC’s Division of Ratepayer Advocate, or ORA,Advocates and The Utility Reform Network, or TURN.Network. On December 2, 2005,March 15, 2007, the CPUC approved a multi-party settlement agreement to resolve the Utility’s 2007 GRC. The decision set the Utility’s electricity and natural gas distribution and electricity generation revenue requirements for a four-year period, from 2007 through 2010, rather than for a typical three-year period. Under the decision, the Utility’s next GRC will be effective January 1, 2011. The Utility filed its 2007intends to submit a draft of the 2011 GRC application withand revenue requirement request to the CPUC.CPUC in July or August 2009. For more information, see “Regulatory Matters—2007 General Rate Case”the section of MD&A entitled “Results of Operations” in the MD&A in the 20052008 Annual Report.
The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations. The CPUC’s decision in the Utility’s 2007 GRC includes a provision for attrition adjustments made in 2008, and to be made in 2009 and 2010. For more information, see the section of MD&A entitled “Results of Operations” in the 2008 Annual Report.
Cost of Capital Proceedings
The CPUC generally conducts an annual cost of capitala proceeding to determine the Utility's authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The cost of capital proceeding establishes the percentage components thatrelative weightings of common equity, preferred equity and debt will represent in the Utility's total authorized capital structure for a specific year.structure. The CPUC then establishes the authorized return on common equity, preferred equity and debteach component that the Utility will have the opportunity to collect in its authorized rates. On December 15, 2005,In May 2008, the CPUC issuedadopted a uniform three-year cost of capital decision approving amechanism to set the cost of capital structure for the Utility consistingand the other two California investor-owned electric utilities. The utilities are required to file full cost of capital applications by April 20 of every third year, beginning on April 20, 2010.
The cost of capital mechanism uses an interest rate index (the 12-month October through September average of the Moody's Investors Service utility bond index) to trigger changes in the authorized cost of debt, preferred stock, and equity. In any year in which the 12-month October through September average for the index increases or decreases by more than 100 basis points (“deadband”) from the benchmark, the cost of equity will be adjusted by one-half of the difference between the 12-month average and the benchmark. In addition, if the mechanism is triggered, the costs of long-term debt and preferred stock will be adjusted to reflect the actual August month-end embedded costs in that year and forecasted interest rates for variable long-term debt and any new long-term debt and preferred stock forecasted to be issued in the coming year. The 12-month October 2007 through September 2008 average of the Moody's Investors Service utility bond index did not trigger a change in the authorized cost of debt, preferred stock, or equity for 2009.
The Utility’s current CPUC-authorized capital structure consists of 46% long-term debt, 2% preferred stock and 52% common equity. The CPUC set theUtility’s current CPUC-authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base for 2006 at 6.02%is 6.05% for long-term debt, 5.87%5.68% for preferred stock and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%. This capital structure and authorized rate of return will be maintained through 2010, unless the automatic adjustment mechanism is triggered. The utilities may apply for an adjustment to either the cost of capital or the capital structure 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 return is often unspecified if the Utility's transmission rates are determined through a negotiated rate settlement. The Utility’s rates of return for its backbone and local gas transmission and storage operations through 2007 has been previously set in the Gas Accord at 11.22% for the return on equity and 8.77% for the overall rate of return.
The CPUC sets and periodically revises a baseline allowance for the Utility's residential gas and electricity customers. A customer's baseline allowance is the amount of its monthly usage that is covered under the lowest possible natural gas or electric rate. Natural gas or electricity usage in excess of the baseline allowance is covered by higher rates that increase with usage.
California law requires the CPUC to authorize certain levels of funding for electric and gas public purpose programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources. For 2005,California law also requires the CPUC to authorize funding for the California Solar Initiative and other self-generation programs as discussed below. Additionally, the CPUC has authorized funding for demand response programs.
For 2008, the CPUC authorized the Utility to collect revenue requirements of approximately $250$741.7 million of which approximately $656.6 million is collected from electricityelectric customers to fund these electricityelectric public purpose and other programs and to collect revenue requirements of approximately $40$85.1 million is collected from gas customers to fund these natural gas public purpose programs.
programs. The CPUC is responsible for authorizing the programs, funding levels and cost recovery mechanisms for the Utility's operation of both energy efficiency and low-income energy efficiencythese programs. The CEC administers both the electric and natural gas public interest research and development programprograms and the renewable energy program on a statewide basis. In 2005,2008, the Utility transferred $102approximately $79.5 million to the CEC for CEC-administered gas and electric programs. See the discussion below for a further description of these two programs.programs and authorized funding amounts.
| · | Energy Efficiency Programs. The Utility’s energy efficiency programs are designed to encourage the manufacture, design, distribution and customer use of energy efficient appliances and other energy-using products. The CPUC authorized funding of $403 million for 2008 gas and electric programs, including funding for the CEC-administered programs. The Utility intends to file an amended application on March 2, 2009 to seek CPUC approval and funding authorization of approximately $1.8 billion for the Utility’s 2009-2011 energy efficiency programs, an approximate increase of $860 million over the 2006-2008 budget. On October 16, 2008, the CPUC authorized bridge funding for 2009 of $394.9 million to allow the Utility to continue existing energy efficiency programs until the CPUC issues a final decision on the 2009-2011 application. |
kWh, 45 cents per therm, and $25 per kW for each kWh, therm, or kW unit below the 65% threshold, or (2) a dollar-for-dollar payback of negative net benefits, also known as a cost-effectiveness guarantee. The maximum award that the Utility could earn, and the maximum amount that the Utility could be required to reimburse customers over the 2006-2008 program cycle is $180 million.
On January 29, 2009, the CPUC instituted a new proceeding to modify the existing incentive ratemaking mechanism, to adopt a new framework to review the utilities’ 2008 energy efficiency performance and to conduct a final review of the utilities’ performance over the 2006-2008 program period. The CPUC also plans to develop a long-term incentive mechanism for program periods beginning in 2009 and beyond. For more information, see the section of MD&A entitled “Regulatory Matters─Energy Efficiency Programs and Incentive Ratemaking” in the 2008 Annual Report.
| · | Demand Response Programs. Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. The 2008 authorized funding for Demand Response Programs was $38 million. The CPUC has not yet approved the Utility’s request for funding of approximately $148 million for the Utility’s 2009-2011 demand response programs. On December 18, 2008, the CPUC authorized bridge funding of $41 million to continue certain demand response programs in 2009 until a final decision is issued on the Utility’s request. |
In addition, on February 14, 2008, the CPUC approved the Utility’s multi-year air conditioning direct load control program and authorized funding of $179 million through June 1, 2011 to implement this program. The 2008 authorized funding level was approximately $37 million. Customers who enroll in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies. The decision will allow the Utility to enroll approximately 397,000 air conditioning load control devices to achieve approximately 305 MW of load reduction capacity by June 2011.
| · | 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 customers who install certain types of clean or renewable distributed generation resources that meet all or a portion of their onsite energy usage. The CPUC approved a budget for the SGIP of approximately $36 million in each of 2008 and 2009. In late 2006, the CPUC also established the California Solar Initiative (“CSI”) to bring 1,940 MW of solar power on-line by 2017 in California and authorized the California investor-owned utilities to collect an additional $2.2 billion over the 2007 through 2016 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load to meet this goal. Of the total amount authorized, the Utility has been allocated $946 million to fund customer incentives, research, development and demonstration activities (with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses. The California Legislature modified the CSI program to include participation of the California municipal utilities. The current overall goal of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2017. |
| · | Low-Income Energy Efficiency Programs and California Alternate Rates for Energy. The CPUC authorized the Utility to collect approximately $86 million for these programs in 2008. The CPUC has authorized the Utility to collect approximately $422 million to support the Utility’s energy efficiency programs for low-income and fixed-income customers over 2009-2011. The Utility also provides a discount rate called the California Alternate Rates for Energy (“CARE”) for low-income customers. This rate subsidy is paid for by the Utility's other customers. The extent of the subsidy, during any given year, depends upon the number of customers participating in the program. In 2008, the amount of this subsidy was approximately $526.6 million, including avoided customer surcharges. The CPUC also authorized the Utility to recover approximately $28 million in administrative costs relating to the CARE subsidy over 2009-2011. |
Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility's own generation facilities and existing electricity contracts (including DWR allocated contracts). To accomplish this, each utility must submit a long-term procurement plan covering a ten-year period to the CPUC for approval. Each long-term procurement plan must be designed to reduce greenhouse gas emissions and use the State of California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation). In December 2007, the CPUC approved the utilities’ long-term procurement plans, covering the 2007-2016 period, subject to certain required modifications. California legislation, Assembly Bill 57, allows the utilities to recover the costs
incurred in compliance with their CPUC-approved procurement plans without further after-the-fact reasonableness review. Each utility may, if appropriate, conduct a competitive request for offers (“RFO”) within the parameters permitted in its approved plan to meet the 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 installationCPUC 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 retail solar energy projectsthese solicitations to serve onsite load. The intentthe CPUC for approval and authorization of the CSIisto help California move toward a cleaner energy futureassociated revenue requirements. For more information about the Utility’s approved long-term procurement plan covering 2007-2016, see “Electric Utility Operations — Electricity Resources-Future Long-Term Generation Resources” below.
The Utility recovers its electricity procurement costs and bringthe fuel costs for the Utility’s own generation facilities (but excluding the costs of solar electricity downallocated 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. The ERRA tracks the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans and contracts. To determine the authorized revenue requirement recorded in the ERRA, each year the CPUC reviews the Utility’s forecasted costs under power purchase agreements and fuel costs. Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility's prior year electricity procurement revenues (excluding amounts collected for California consumers sothe DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The CPUC also performs compliance reviews of the procurement activities recorded in the ERRA to ensure that solar productsthe Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will be cost-effective without incentives. Ofrecover its reasonable costs of providing utility service, including power purchase costs.
The CPUC has approved several power purchase agreements that the total amountUtility has entered into with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements. The CPUC also authorized the Utility has been allocated $1.2 billion to fund customer incentives. When combinedrecover fixed and variable costs associated with previously authorized funding,these contracts through the total fundsERRA.
For new non-renewable generation purchased from third parties under power purchase agreements, the Utility may elect to be provided to achieverecover any above-market costs through either: (1) the CSI’s objectives are $3.25 billion,imposition of which $1.4 billion is allocated toa non-bypassable charge imposed on bundled and departing customers only or (2) the Utility. The CSI also allocates up to 5%allocation of the annual budget for research, development“net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the utilities’ service territory, including existing direct access customers and demonstration activities, with emphasis oncommunity choice aggregation customers. (For information about the demonstrationstatus of solardirect access and solar-related technologies.community choice aggregation, see the section above entitled “Competition in the Electricity Industry.”)
The non-bypassable charge can be imposed from the date of signing a power purchase agreement and last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less. Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis. If a utility elects to use the net capacity cost allocation method, the net capacity costs would be allocated for the term of the contract or 10 years, whichever is less, starting on the date the new generation unit comes on line. Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimize the net capacity costs that would be subject to allocation. If no bids are accepted for the energy rights, the Utility would retain the rights to the energy and would value it at market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.
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 the Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year. For more information, see the section of MD&A entitled “Capital Expenditures – New Generation Facilities” in the 2008 Annual Report.
The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity these
customers
The Utility's electricity transmission revenuesrevenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues: charges under the Utility's transmission owner tariff and charges under specific contracts with wholesale transmission customers that the Utility entered into before 1998, when the ISO commenced operations.CAISO began its operations in March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. Other customers pay transmission rates that are established by the
FERC in the Utility's transmission owner tariff rate cases andcases. These FERC-approved rates are included by the CPUC in the Utility's retail electricityelectric rates, and collected from retail electricity customers receiving bundled service underconsistent with the federal filed rate doctrine.doctrine, and are collected from retail electric customers receiving bundled service.
The Utility's transmission owner tariff includes two rate components:
components. The primary component consists of base transmission rates intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity. The Utility derives the majority of the Utility's transmission revenue from base transmission rates.
The ISO also has entered into reliability must run, or RMR, agreements with various power plant owners, includingother component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility that require designated units in certain power plants, known as RMR units, to remain available to generate electricity uponfor transmission revenues received by the ISO's demand when needed for local transmission system reliability. As a participating transmission owner underCAISO. These revenues include:
| · | the proceeds received from the CAISO for wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) that the CAISO provides to third parties using the Utility’s transmission facilities, and |
| · | revenues that the CAISO collects from transmission users to relieve congestion on the Utility’s transmission line (either in the form of financial hedges, such as firm transmission rights relating to future deliveries of electricity, or in the form of a usage charge to manage congestion relating to real-time delivery of electricity). |
These revenues are adjusted by the TCA,shortfall or surplus resulting from any cost differences between the amount the Utility is responsibleentitled to receive from certain wholesale customers under specific contracts and the amount the Utility is entitled to receive or be charged for scheduling services under the ISO's costs paid under RMR agreements to power plant owners within or adjacent toCAISO’s rules and protocols.
The CAISO also charges the Utility's service territory. The Utility’s share of the ISO’sUtility for reliability service costs in 2005 was approximately $217 million. Under the Utility’s transmission owner tariff, the Utility recovers these costs, without mark-up or service fees. The Utility also received approximately $59 million in 2005 under the RMR agreements that the Utility entered into with the ISO for the Utility’s units that have been designated as RMR units. The Utility tracks these costs and revenues in the reliability services balancing account. Periodically, the Utility’s electricity transmission rates are adjusted to refund over-collections to the Utility’s customers or to collect any under-collections from customers. For further discussion of other RMR-related issues, see the section of Note 17: Commitments and Contingencies— Reliability Must Run Agreements, of the Notes to the Consolidated Financial Statements in the 2005 Annual Report.
Natural Gas
2008 through December 31, 2010. The Gas Accord IV establishes a 2008 natural gas transportationtransmission and storage systemrevenue requirement of $446 million (approximately 0.6% above the currently authorized revenue requirement for 2007), a 2009 revenue requirement of $459 million (approximately 2.8% above the three-year periodproposed 2008 revenue requirement), and a 2010 revenue requirement of 2005$471 million (approximately 2.7% above the proposed 2009 revenue requirement). A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, will continue to be assured of recovery through 2007.balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements will continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:
Backbone Transmission. The backbone transmission revenue requirement is recovered through a combination of firm, two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available, one-part rates (consisting only of volumetric usage charges). The mix of firm and as-available backbone services provided by the Utility continually changes. As a result, the Utility’s recovery of its backbone transmission costs is subject to volumetric and price risk to the extent backbone capacity is sold on an as-available basis. Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity. Core customers are allocated approximately 36% of the total backbone capacity on the Utility’s system. Core customers pay approximately 72% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.
Local Transmission. The local transmission revenue requirement is allocated approximately 71% to core customers and 29% to non-core customers. The Utility continuesrecovers the portion allocated to be at riskcore customers through a balancing account, but the Utility’s recovery of not recovering its natural gas transportationthe portion allocated to non-core customers is subject to volumetric and price risk.
Storage. The storage revenue requirement is allocated approximately 71% to core customers, 13% to non-core storage service, and 17% to pipeline load balancing service. The Utility recovers the portion allocated to core customers through a balancing account, but the 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.
Taken together, the backbone transmission, local transmission, and storage costs that are either protected through balancing accounts or recovered through long-term firm contract reservation charges amount to approximately 49% of the Utility’s total revenue requirement for gas transmission and does not have regulatory balancing account protection for over-collections or under-collections of most of its natural gas transportation or storage revenues, except for core local transmission revenue and core storage costs.storage.
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 CPIMUtility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. The Utility is used to determineprotected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism, the reasonableness of the Utility's costs of purchasing natural gas for its customers.CPIM. Under the CPIM, the Utility's natural gas purchase costs (including Canadian and interstate capacity and volumetric transportation charges) for a fixed twelve-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is currently between 99% andto 102% of the benchmark, are considered reasonable and are fully recoverablerecovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive three-fourthsin their rates 80% of any savings resulting from the savings when the costs are belowUtility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. Any awards associatedWhile this incentive mechanism remains in place, changes in the price of natural gas, consistent with the CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual period ending October 31 that is used to measure the CPIM. These awardsmarket-based benchmark, are not included in earnings until approved by the CPUC.
fact reasonableness review. (For more information see the section entitled “Risk Management Activities” in the 2008 Annual Report).
On June 26, 2008, the CPUC opened a proceeding to examine the California gas utilities’ gas cost based on its subsequent reviewincentive mechanisms and the treatment of hedging costs under those incentive mechanisms for core customers. The CPUC will determine whether the utilities’ hedging plans should be incorporated into their incentive mechanisms and whether re-examination of the Utility’s performance underutilities’ current incentive mechanisms is necessary. It is uncertain when the filed hedging plan. As part of the hedging plan, the Utility also agreed to forgoCPUC will issue a shareholder award under the CPIM for the 2004-2005 CPIM year.final decision.
The Utility's interstate and Canadian natural gas transportation agreements with third partythird-party service providers are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Energy and Utilities BoardCommission and the National Energy Board. The Utility's agreements with interstate and Canadian natural
gas transportation service providers are administered as part of the Utility's core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. For more information see the discussion below under “Natural Gas Utility Operations – Interstate and Canadian Natural Gas Transportation Services Agreements.”
Electric Utility Operations
The following table shows the percentage of the Utility's total sources of electricity for 2008 represented by each major electricity resource:
Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities) | 30% |
DWR | 15% |
Qualifying Facilities/Renewables | 18% |
Irrigation Districts | 2% |
Other Power Purchases | 35% |
The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. Least-cost dispatch requires the Utility, in certain cases, to schedule more electricity than is necessary to meet its retail load and therefore to sell this electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR, based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.
At December 31, 2008, 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: | ||||||
Humboldt Bay(1) | Humboldt | 2 | 105 | |||
Mobile turbines | Humboldt | 2 | 30 | |||
Fossil fuel subtotal | 4 | 135 | ||||
Total | 116 | 6,271 |
(1) The Humboldt Bay facilities consist of a retired nuclear generation unit, Humboldt Bay Unit 3, and two operating fossil fuel-fired plants. As described
below, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.
Diablo Canyon Power Plant. The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. Unit 1 began commercial operation in May 1985, and the operating license for this unit expires in November 2024. Unit 2 began commercial operation in March 1986, and the operating license for this unit expires in August 2025. For the 10-year period ended December 31, 2008, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 89.9%.
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 17: Commitments and Contingencies— Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.
The following table outlines the Diablo Canyon power plant's refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 51 days. The Utility will replace the steam generators in Unit 1 during the scheduled refueling outage that began in January 2009. Due to this additional work, this refueling outage is expected to last approximately 76 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.
| 2009 | 2010 | 2011 | 2012 | 2013 | |||||
| Unit 1 | |||||||||
Refueling | January | October | April | ||||||
Duration (days) | 76 | 35 | 30 | ||||||
Startup | April | November | May | ||||||
Unit 2 | |||||||||
Refueling | October | - | May | February | |||||
Duration (days) | 35 | - | 30 | 30 | |||||
Startup | November | - | June | March |
Hydroelectric Generation Facilities. The Utility's hydroelectric system consists of 110 generating units at 69 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 56 diversions, 170 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of natural waterways. The system also includes water rights as specified in 90 permits or licenses and 160 statements of water diversion and use. 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 five years, the FERC renewed three hydroelectric licenses with a total of 415 MW of hydroelectric power. The Utility is in the process of renewing licenses for projects with approximately 1,183 MW of additional hydroelectric power. Although the original licenses associated with 599 MW of the 1,183 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 2,701 MW of hydroelectric power will expire between 2018 and 2043.
New Generation Facilities. In addition to the Utility-owned resources shown in the table above, the Utility has been engaged in the development of three generation facilities to be owned and operated by the Utility. On January 4, 2009, the 530-MW Gateway Generating Station located in Antioch, California, reached full load commercial production and is expected to reach final project completion at the end of the first quarter of 2009. In June 2008, the CPUC approved the construction of the Colusa Generating Station, a 657- MW combined cycle generating facility to be located in Colusa County, California. Final environmental permitting was approved on September 29, 2008 and construction began on October 1, 2008. Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Generating Station will commence operations in 2010. Also, in September 2008, the CEC issued its final decision authorizing the construction of a 163-MW power plant to re-power the Utility’s existing power plant at Humboldt Bay, which is at the end of its useful life. Demolition of existing structures on the site is complete and the contractor began preparing the site for construction in December 2008. Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in 2010. For more information, see the section of MD&A entitled “Capital Expenditures ─ New
Generation Facilities” in the 2008 Annual Report.
DWR Power Purchases
During 2008, electricity from the DWR contracts allocated to the Utility provided approximately 15% of the electricity delivered to the Utility's customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as the contracts expire or terminate. For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies – California Department of Water Resources Contracts, of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.
Qualifying Facility Power Purchase Agreements. As of December 31, 2008, the Utility had power purchase agreements with 246 QFs for approximately 3,900 MW that are in operation. Agreements for approximately 3,600 MW expire at various dates between 2009 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 74 inoperative QFs. The total of approximately 3,900 MW consists of roughly 2,500 MW from cogeneration projects, 600 MW from wind projects and 800 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. QF power purchase agreements accounted for approximately 18%, 20%, and 20%, of the Utility’s 2008, 2007, and 2006 electricity sources, respectively. No single QF accounted for more than 5% of the Utility's 2008, 2007, or 2006 electricity sources.
Irrigation Districts and Water Agencies. The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts' and water agencies' debt service requirements, whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2010 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 2%, 3%, and 6% of the Utility’s electricity sources in 2008, 2007, and 2006, respectively.
Renewable Energy Contracts. California law requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) by at least 1% of its retail sales, so that the amount of electricity delivered from renewable resources equals at least 20% of its total retail sales by the end of 2010. During 2008, the Utility entered into new renewable power purchase contracts that will help the Utility meet this RPS by 2010.
Long-Term Power Purchase Agreements. In accordance with the Utility’s CPUC-approved long-term procurement plans, the Utility has entered into several power purchase agreements with third parties. The Utility’s obligations under a portion of these agreements are contingent on the third party’s development of a new generation facility to provide the power to be purchased by the Utility under the agreements.
For more information regarding the Utility's power purchase contracts, see Note 17: Commitments and Contingencies— Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.
The Utility’s CPUC-approved long-term electricity procurement plan, covering procurement during 2007-2016, forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of new conventional generation by 2015 above the Utility's planned additions of renewable resources, energy efficiency, demand reduction programs, and previously approved contracts for new generation resources.
The utilities are permitted to acquire ownership of new conventional generation resources only through purchase and sale agreements (“PSAs”) (i.e., 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) and engineering, construction, and procurement arrangements proposed by third parties. 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. On July 21, 2008, the Utility received offers from third parties in response to the Utility’s April 1, 2008 RFO for 800 MW to 1,200 MW of dispatchable and operationally flexible new generation resources to be on-line no later than May 2015. The Utility’s RFO requested offers for both PSAs and power purchase agreements. In the fourth quarter of 2008 the Utility developed its RFO shortlist of participants and is currently involved in negotiations with potential counterparties. The Utility anticipates executing contracts and requesting CPUC approval of the executed contracts in the first half of 2009.
In addition, on February 24, 2009, the Utility requested the CPUC to approve the Utility’s proposed development of renewable generation resources based on solar photovoltaics (“PV”) technology. The Utility’s proposal includes the development and construction of up to 250 MW of Utility-owned PV generating facilities, to be deployed over a period of five years and the execution of power purchase agreements for up to 250 MW of PV projects to be developed by independent power producers. For more information regarding the Utility's proposal, see the section of MD&A entitled “Capital Expenditures ─ Proposed New Generation Facilities” in the 2008 Annual Report.
Electricity Transmission
At December 31, 2008, the Utility owned 18,650 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 56,401 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 141,036 circuit miles of distribution lines and substations with a capacity of 27,137 MVA. In 2008, the Utility delivered 88,127 GWh to its customers; including 6,191 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.
During 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO. The Utility entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO. The Utility is required to give the CAISO two years notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.
The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998. In addition, under the mandatory reliability standards implemented following EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards. See the discussion of reliability standards above under “The Utility’s Regulatory Environment-Federal Energy Regulation.”
The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO. (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO's demand when the generation from those RMR units is needed for local transmission system reliability.) Potential transmission projects include a 500-kV transmission line to improve access to new renewable generation resources and to reduce RMR generation contracts in the Fresno, California area (referred to as the “Central California Clean Energy Transmission Project”) and a high voltage transmission line between Northern California and British Columbia, Canada to access renewable generation resources in British Columbia. In addition, the Utility is currently working with several stakeholders in the western United States to assess the feasibility of new large-scale electric transmission expansion projects to address regional electricity needs over the long term.
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 141,036 circuit miles of distribution lines (of which approximately 19% are underground and approximately 81% are overhead). There are 92 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 607 distribution substations and 110 low-voltage distribution substations. The 49 combined transmission and distribution substations have both transmission and distribution transformers.
The Utility's distribution network interconnects to the Utility's electricity transmission system at 1,106 points. This interconnection between the Utility's distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility's customers. The distribution substations serve as the central hubs of the Utility's electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.
During 2006, the Utility began the installation of an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility's electric and gas customers. These meters enable the Utility to measure usage on an hourly basis for electricity and on a daily basis for natural gas, which can allow for demand-response rates to encourage customers to reduce energy consumption during peak demand periods, thus reducing peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility expects to complete the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011. The Utility also has requested the CPUC to approve the Utility’s proposal to upgrade elements of the Utility’s SmartMeter™ program. The Utility seeks approval to install solid-state electric meters and associated devices that would offer an expanded range of service features for customers and increased operational efficiencies for the Utility. These upgraded meters and associated devices would provide additional energy conservation and demand response options for electric customers. In addition, the solid-state electric meters are designed to facilitate the Utility’s ability to incorporate future advanced metering technology innovations in a timely and cost-effective manner. (For more information about the advanced metering infrastructure, see the section of MD&A entitled “Capital Expenditures ─ SmartMeter™ Program” in the 2008 Annual Report.)
2008 Electricity Deliveries. The following table shows the percentage of the Utility's total 2008 electricity deliveries represented by each of its major customer classes:
Total 2008 Electricity Delivered: 88,127 GWh
| Agricultural and Other Customers | 7% |
| Industrial Customers | 18% |
| Residential Customers | 36% |
| Commercial Customers | 39% |
The following table shows certain of the Utility's operating statistics from 2004 to 2008 for electricity sold or delivered, including the classification of sales and revenues by type of service.
| 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
| Customers (average for the year): | ||||||||||||||||||||
Residential | 4,488,884 | 4,464,483 | 4,417,638 | 4,353,458 | 4,366,897 | |||||||||||||||
Commercial | 527,045 | 521,732 | 515,297 | 509,786 | 509,501 | |||||||||||||||
Industrial | 1,265 | 1,261 | 1,212 | 1,271 | 1,339 | |||||||||||||||
Agricultural | 81,757 | 80,366 | 79,006 | 78,876 | 80,276 | |||||||||||||||
Public street and highway lighting | 30,474 | 29,643 | 28,799 | 28,021 | 27,176 | |||||||||||||||
Other electric utilities | 2 | 2 | 4 | 4 | 3 | |||||||||||||||
Total (1) | 5,129,427 | 5,097,487 | 5,041,956 | 4,971,416 | 4,985,192 | |||||||||||||||
Deliveries (in GWh):(2) | ||||||||||||||||||||
Residential | 31,454 | 30,796 | 31,014 | 29,752 | 29,453 | |||||||||||||||
Commercial | 34,053 | 33,986 | 33,492 | 32,375 | 32,268 | |||||||||||||||
Industrial | 16,148 | 15,159 | 15,166 | 14,932 | 14,796 | |||||||||||||||
Agricultural | 5,594 | 5,402 | 3,839 | 3,742 | 4,300 | |||||||||||||||
Public street and highway lighting | 877 | 833 | 785 | 792 | 2,091 | |||||||||||||||
Other electric utilities | 1 | 3 | 14 | 33 | 28 | |||||||||||||||
Subtotal | 88,127 | 86,179 | 84,310 | 81,626 | 82,936 | |||||||||||||||
California Department of Water Resources (DWR) | (13,344 | ) | (21,193 | ) | (19,585 | ) | (20,476 | ) | (19,938 | ) | ||||||||||
Total non-DWR electricity | 74,783 | 64,986 | 64,725 | 61,150 | 62,998 | |||||||||||||||
Revenues (in millions): | ||||||||||||||||||||
Residential | $ | 4,656 | $ | 4,580 | $ | 4,491 | $ | 3,856 | $ | 3,718 | ||||||||||
Commercial | 4,413 | 4,484 | 4,414 | 4,114 | 4,179 | |||||||||||||||
Industrial | 1,400 | 1,252 | 1,293 | 1,232 | 1,204 | |||||||||||||||
Agricultural | 727 | 664 | 483 | 446 | 491 | |||||||||||||||
Public street and highway lighting | 75 | 78 | 72 | 66 | 71 | |||||||||||||||
Other electric utilities | 126 | 85 | 59 | 4 | 22 | |||||||||||||||
Subtotal | 11,397 | 11,143 | 10,812 | 9,718 | 9,685 | |||||||||||||||
DWR | (1,325 | ) | (2,229 | ) | (2,119 | ) | (1,699 | ) | (1,933 | ) | ||||||||||
Direct access credits | — | — | — | — | — | |||||||||||||||
Miscellaneous | 336 | 215 | 261 | 235 | (248 | ) | ||||||||||||||
Regulatory balancing accounts | 330 | 352 | (202 | ) | (327 | ) | 363 | |||||||||||||
Total electricity operating revenues | $ | 10,738 | $ | 9,481 | $ | 8,752 | $ | 7,927 | $ | 7,867 | ||||||||||
Other Data: | ||||||||||||||||||||
Average annual residential usage (kWh) | 7,007 | 6,898 | 7,020 | 6,834 | 6,744 | |||||||||||||||
Average billed revenues (cents per kWh): | ||||||||||||||||||||
Residential | 14.80 | 14.87 | 14.48 | 12.96 | 12.62 | |||||||||||||||
Commercial | 12.96 | 13.19 | 13.18 | 12.71 | 12.95 | |||||||||||||||
Industrial | 8.67 | 8.26 | 8.53 | 8.25 | 8.14 | |||||||||||||||
Agricultural | 13.00 | 12.29 | 12.58 | 11.92 | 11.41 | |||||||||||||||
Net plant investment per customer | $ | 3,994 | $ | 3,418 | $ | 3,148 | $ | 2,966 | $ | 2,790 | ||||||||||
| (1) | Starting in 2005, the Utility’s methodology used to count customers changed from the number of billings to the number of active service agreements. |
| (2) | These amounts include electricity provided to direct access customers who procure their own supplies of electricity. |
The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 40 of California's 58 counties and includes most of northern and central California. In 2008, the Utility served approximately 4.3 million natural gas distribution customers. The total volume of natural gas throughput during 2008 was approximately 839 Bcf.
As of December 31, 2008, the Utility's natural gas system consisted of 42,017 miles of distribution pipelines, 6,418 miles of backbone and local transmission pipelines, and three storage facilities. The Utility’s backbone transmission system, composed primarily of Lines 300, 400 and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems. The Utility's Line 300, which interconnects with the U.S. Southwest and Rocky Mountain pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity of approximately 1.07 Bcf per day. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.02 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains and the southwestern United States. The Utility also is supplied by natural gas fields in California.
The Utility also owns and operates three underground natural gas storage fields connected to the Utility's transmission and storage system. These storage fields have a combined firm capacity of approximately 47 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.
The Utility, along with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, is developing an underground natural gas storage facility near Fresno, California. It is expected that construction of the initial phase, to consist of approximately 20 Bcf of total capacity, will be completed in 2010. The Utility has a 25% interest in the initial phase of the proposed storage facility. Development of the storage facility is subject to CPUC approval, including the CPUC’s environmental review as required by the California Environmental Quality Act. The Utility expects the CPUC to issue a final decision in late 2009.
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 2008, core customers represented more than 99% of the Utility's total customers and 37% of its total natural
gas deliveries, while non-core customers comprised less than 1% of the Utility's total customers and 63% 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 99% of core customers, representing over 96% of 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 through that avenue. 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.
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 2008 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 0.2% for the years 2008 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.
Total 2008 Natural Gas Deliveries: 839 Bcf
| Residential Customers | 26% |
| Transport-only Customers (non-core) | 63% |
| Commercial Customers | 11% |
The following table shows the Utility's operating statistics from 2004 through 2008 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:
| 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
| Customers (average for the year): | ||||||||||||||||||||
Residential | 4,043,616 | 4,030,499 | 3,989,331 | 3,929,117 | 3,812,914 | |||||||||||||||
Commercial | 224,617 | 223,330 | 220,024 | 216,749 | 215,547 | |||||||||||||||
Industrial | 926 | 958 | 988 | 962 | 2,178 | |||||||||||||||
Other gas utilities | 6 | 6 | 6 | 6 | 6 | |||||||||||||||
Total | 4,269,165 | 4,254,793 | 4,210,349 | 4,146,834 | 4,030,645 | |||||||||||||||
Gas supply (MMcf): | ||||||||||||||||||||
Purchased from suppliers in: | ||||||||||||||||||||
Canada | 189,608 | 199,870 | 202,274 | 204,884 | 205,180 | |||||||||||||||
California | (53,126 | ) | (23,065 | ) | (13,401 | ) | (18,951 | ) | (9,108 | ) | ||||||||||
Other states | 123,833 | 101,271 | 103,658 | 103,237 | 103,801 | |||||||||||||||
Total purchased | 260,315 | 278,076 | 292,531 | 289,170 | 299,873 | |||||||||||||||
Net (to storage) from storage | 560 | (1,120 | ) | 4,359 | (3,659 | ) | (532 | ) | ||||||||||||
Total | 260,875 | 276,956 | 296,890 | 285,511 | 299,341 | |||||||||||||||
Utility use, losses, etc. (1) | 1,758 | (12,760 | ) | (27,610 | ) | (14,312 | ) | (19,287 | ) | |||||||||||
Net gas for sales | 262,633 | 264,196 | 269,280 | 271,199 | 280,054 | |||||||||||||||
Bundled gas sales (MMcf): | ||||||||||||||||||||
Residential | 198,699 | 196,903 | 196,092 | 194,108 | 201,601 | |||||||||||||||
Commercial | 63,934 | 67,293 | 73,178 | 77,056 | 78,080 | |||||||||||||||
Industrial | 10 | 35 | 373 | |||||||||||||||||
Other gas utilities | — | — | — | — | — | |||||||||||||||
Total | 262,633 | 264,196 | 269,280 | 271,199 | 280,054 | |||||||||||||||
Transportation only (MMcf): | 569,535 | 605,259 | 559,270 | 572,869 | 597,706 | |||||||||||||||
Revenues (in millions): | ||||||||||||||||||||
Bundled gas sales: | ||||||||||||||||||||
Residential | $ | 2,574 | $ | 2,378 | $ | 2,452 | $ | 2,336 | $ | 1,944 | ||||||||||
Commercial | 792 | 766 | 859 | 885 | 712 | |||||||||||||||
Industrial | ||||||||||||||||||||
Other gas utilities | ||||||||||||||||||||
Miscellaneous | (30 | ) | 87 | 121 | (22 | ) | (29 | ) | ||||||||||||
Regulatory balancing accounts | 221 | 186 | 40 | 340 | 316 | |||||||||||||||
Bundled gas revenues | 3,557 | 3,417 | 3,472 | 3,539 | 2,943 | |||||||||||||||
Transportation service only revenue | 333 | 340 | 315 | 237 | 270 | |||||||||||||||
Operating revenues | $ | 3,890 | $ | 3,757 | $ | 3,787 | $ | 3,776 | $ | 3,213 | ||||||||||
Selected Statistics: | ||||||||||||||||||||
Average annual residential usage (Mcf) | 49 | 49 | 49 | 49 | 53 | |||||||||||||||
Average billed bundled gas sales revenues per Mcf: | ||||||||||||||||||||
Residential | $ | 12.95 | $ | 12.07 | $ | 12.50 | $ | 12.04 | $ | 9.64 | ||||||||||
Commercial | 12.38 | 11.38 | 11.73 | 11.48 | 9.12 | |||||||||||||||
Industrial | 1.03 | 0.61 | (0.56 | ) | ||||||||||||||||
Average billed transportation only revenue per Mcf | 0.59 | 0.56 | 0.56 | 0.42 | 0.45 | |||||||||||||||
Net plant investment per customer | $ | 1,344 | $ | 1,375 | $ | 1,304 | $ | 1,262 | $ | 1,266 | ||||||||||
| (1) | Includes fuel for the Utility's fossil fuel-fired generation plants. |
The Utility purchases natural gas to serve the Utility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility's portfolio of natural gas purchase contracts have fluctuated generally based on market conditions. During 2008, the Utility purchased approximately 260,315 MMcf of natural gas (net of the sale of excess supply) from suppliers. Consistent with existing CPUC policy directives, substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility's largest individual supplier represented approximately 10% of the total natural gas volume the Utility purchased during 2008.
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 2008, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.
| 2008 | 2007 | 2006 | 2005 | 2004 | |||||||||||
| MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | ||||||
| Canada | 189,608 | $8.29 | 199,870 | $6.63 | 202,274 | $6.27 | 204,884 | $7.12 | 205,180 | $5.37 | |||||
California (1) | (53,126) | $9.24 | (23,065) | $6.77 | (13,401) | $7.04 | (18,951) | $7.70 | (9,108) | $4.89 | |||||
| Other states (substantially all U.S. southwest) | 123,833 | $7.05 | 101,271 | $6.30 | 103,658 | $6.51 | 103,237 | $7.10 | 103,801 | $5.44 | |||||
| Total/weighted average | 260,315 | $7.51 | 278,076 | $6.50 | 292,531 | $6.32 | 289,170 | $7.07 | 299,873 | $5.41 | |||||
(1) California purchases include supplies from various California producers and supplies transported into California by others.
The Utility's gas gathering system collects natural gas from third-party wells in California. During 2008, approximately 6% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 110.3 miles of gas gathering pipelines. The Utility receives gas well production at approximately 188 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 8 California counties. Approximately 138 MMcf per day of natural gas produced in northern California was delivered into the Utility's gas gathering system during 2008.
In 2008, approximately 52% of the gas transported on the Utility's system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian 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 a firm transportation agreement with GTN for these services. As described below, as part of the FERC-approved all-party settlement of GTN’s most recent general rate case, the Utility’s contract with GTN will be replaced beginning November 1, 2009 by three smaller contracts totaling the same amount with staggered terms.
During 2008, approximately 42% 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 2008, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada 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 each of these natural gas transportation agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.
| Pipeline | Expiration Date | Quantity MDth per day | Demand Charges for the Year Ended December 31, 2008 (In millions) | ||||
| TransCanada NOVA Gas Transmission, Ltd. | 10/31/2011 | (1) | 619 | $29.5 | |||
| TransCanada Foothills Pipe Lines Ltd., B.C. System | 10/31/2011 | 611 | 15.7 | ||||
| Gas Transmission Northwest Corporation | 10/31/2009 | 610 | 89.6 | ||||
Transwestern Pipeline Company (1) | Various | 180 | 15.9 | ||||
El Paso Natural Gas Company (2) | Various | 267 | 17.2 |
| (1) | As of December 31, 2008, the Utility had two active contracts with Transwestern Pipeline Company with expiration dates ranging from February 28, 2009 to March 31, 2010. |
| (2) | As of December 31, 2008, the Utility had three active contracts with El Paso Natural Gas Company with expiration dates ranging from February 28, 2009 to June 30, 2012. |
As required by the all-party settlement of GTN’s most recent general rate case approved by the FERC on January 7, 2008, the Utility has entered into three smaller contracts with GTN with terms that begin on November 1, 2009 and terminate on various dates unless renewed, as follows:
Expiration Date | Quantity MDth per day | Estimated Demand Charges 2009-2011 (In millions) | ||||
| 10/31/2011 | 250 | $58 | ||||
| 10/31/2016 | 280 | 71 | ||||
| 10/31/2020 | 80 | 20 |
Also, as part of the same settlement, the Utility has entered into a separate contract with GTN for firm transportation service to support the Utility’s need for natural gas for electric power plant fuel. This new contract is for a quantity of 50 MDth/d for a 59-month term, July 1, 2009, through May 31, 2014.
In addition, in December 2008, the CPUC approved an agreement between the Utility and El Paso Corporation for the Utility to subscribe for 375 MDth per day of firm service rights on El Paso Corporation’s proposed 680-mile, 42-inch natural gas transmission pipeline (the “Ruby Pipeline”) that would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border. The Ruby Pipeline is expected to have an initial capacity of 1.2 Bcf per day and be expandable to 2 Bcf per day. The proposed Ruby Pipeline would connect Rocky Mountain natural gas producers with northern California, Nevada, and the Pacific Northwest to provide natural gas users with competitively priced natural gas. Subject to obtaining the required regulatory and other approvals and necessary customer commitments, the Ruby Pipeline is anticipated to be in service in the first quarter of 2011.
Environmental Matters
The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance.compliance measures. The information below reflects current estimates, thatwhich are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, and the availability of recoveries or contributions from third parties.
The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of activities, including:
| · |
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The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify or replace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations and clean upclean-up or decommission waste disposal areas at the Utility's current or former facilities and at third-party sites where the UtilityUtility’s wastes may have disposed of wastes.been disposed.
Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility's rates, subject to reasonableness review. Environmental costs associated with the clean-up of sites that contain hazardous substances are subject to a special ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims from customers (e.g.e.g., for costs of cleaning up the Utility's facilities and sites where the Utility has sentUtility’s hazardous substances) from customers.substances have been sent). This mechanism allows the Utility to include 90% of theeligible hazardous waste remediation costs in the Utility's rates without a reasonableness review. (One exception to this is the Hinkley natural gas compressor site discussed below. The cost of environmental remediation associated with this site is not recoverable from customers.) Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility's customers. The balancebalances of any insurance recoveries (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels would then beare 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;Utility, with the remainder, 90% of any such recoveries, are assigned to the Utility's customers.
Hazardous waste remediation costs are rising and are likely to be significant into the foreseeable future. Based on the Utility's past experience, it believes that it can recover most of the future costs that it may incur to remediate hazardous waste through rates and insurance recoveries. The Utility cannot provide assurance, however, that these costs will not be material, or that the Utility will be able to recover its costs in the future.
For more information about environmental remediation liabilities, see Note 17 of the “Notes to the Consolidated Financial Statements” in the 2008 Annual Report.
The Utility's electricity generation plants, and natural gas pipeline operations, fleet and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, and similaras 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, nitrogen oxide and particulate matter.
In addition, various laws and regulations addressing climate change and greenhouse gas emissions (“GHG”) are being considered or implemented at the federal and state levels, as discussed below. Fossil fuel-fired electric utility plants and gas compressor stations used in the Utility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies. In addition, greenhouse gas emissions from natural gas consumed by the Utility’s customers would be subject to regulation by the California Air Resources Board (“CARB”), as discussed below.
California Senate Bill 1368, enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload electricity generation unless the generation complies with a GHG emission performance standard. As required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim GHG emissions performance standard of 1,100 pounds of carbon dioxide per MWh that required reductions in nitrogen oxideapplies to new commitments for baseload electricity procured under contracts with a term of five years or longer or generated by the Utility. After a state-wide GHG emissions from the facilities of approximately 90% by 2004. The Utilitylimit is established and is in complianceoperation, in accordance with these rules. The Utility is permittedAB 32, the CPUC will re-evaluate its interim GHG emissions performance standard and determine whether to recover in customer rates the Utility's costs for its nitrogen oxide retrofit projects related to natural gas compressor stations on the Utility's Line 300, which delivers gas from the southwest. Several other air districts are considering nitrogen oxide rules that would apply to the Utility's other natural gas compressor stations in California. Eventually, the rules are likely to require nitrogen oxide reductions of up to 80% at many of these natural gas compressor stations. Substantially all these costs will be capital costs which the Utility expects to recover through rates.continue, modify or rescind it.
The Utility's Diablo Canyon power plant employs a "once-through"“once-through” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System or NPDES,(“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board or (“Central Coast Board.Board”). This permit allows the Diablo Canyon power plant to discharge the cooling water at an averagea temperature of 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, recreation, commercial/sport fishing, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant's discharge was not protective of beneficial uses. In January 2005,For more information, see the Central Coast Board published a draft report prepared by a team of scientists recommending several measures to mitigate the effect of the cooling water system. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposeddiscussion below 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. For a further discussion of this matter, see “Item 3. 3—Legal Proceedings,Proceedings—Diablo Canyon Power Plant.” below.
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 could not 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 is expected to issue a decision by mid-2009 regarding the cost-benefit test. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital investmentexpense to comply with the final regulations, which the Utility would seek to recover through rates. If the final regulations adopted by the EPA, the Water Board, or the California Legislature, 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.
Many of the Utility's facilities and operations are located in, or pass through, areas that are designated as critical habitats for federal or state-listed endangered, threatened or sensitive species. The Utility may be required to achieveincur 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 standards.Utility's facilities or operations. The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.
The Utility's facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act (“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site, and in some cases corporate successors to the operators or arrangers. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of the Utility's operations, the Utility generates waste that falls within CERCLA's definition of hazardous substances and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state and local laws and regulations allow site-specificrelated to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling and disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous waste laws and other environmental requirements.
The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous
Operations at the Utility's current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of complianceits geothermal and fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is significantly greater than eitherinvestigating or remediating several such sites with the benefits achieved oroversight of various governmental agencies. Additionally, the compliance costs consideredUtility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. Remedial investigations are substantially complete, and the Utility anticipates that the California Department of Toxic Substances Control will approve the remediation plan by the EPA. second quarter of 2009. The Utility spent approximately $1 million in 2008 and estimates that it will spend approximately $12 million in 2009 and approximately $15 million in 2010 for remediation at this site.
In addition, the federal Toxic Substances Control Act regulates the use, disposal and clean-up of polychlorinated biphenyls (“PCBs”), which are used in certain electrical equipment. The Utility has removed from service all of the distribution capacitors and network transformers containing high concentrations of PCBs, representing the vast majority of PCBs that had existed in the Utility's electricity distribution system.
The Utility is developing compliance strategiesassessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain retired manufactured gas plant sites. During their operation, from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The residues from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. There are 95 such sites within the Utility’s service territory that are owned by the Utility or third parties. The Utility has determined that it is liable for each plant.the remediation of 41 sites, is potentially liable for remediation of an additional 24 sites, and is not liable for remediation at the remaining 30 sites. The Utility has a program, in cooperation with environmental agencies and third party owners, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at the 41 sites for which the Utility is liable. The Utility spent approximately $12 million in 2008 and expects to spend approximately $27 million in 2009 and $20 million in 2010 on these sites. The Utility expects that expenses at these sites will increase as remedial actions related to these sites are approved by regulatory agencies and claims by third party owners are settled. Although it is likely that the Utility will incur remediation costs related to some of these sites, the Utility cannot quantify the potential amount.
Under environmental laws, such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility's facilities, or to pay for associated clean-up costs or natural resource damages. The Utility is currently aware of five 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. Other responsible parties are involved with the Utility in investigation and cleaning up the three other disposal sites with oversight from the regulatory agencies. The Utility contributes to these sites under cost sharing agreements or court approved settlements
In addition, the Utility has been named as a defendant in a civil lawsuit in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites that it no longer owns or never owned. Remedial actions may include investigations, health and ecological assessments, and removal of wastes.
Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility has a comprehensive program to monitor a network of groundwater wells at both the Hinkley and Topock natural gas compressor stations. At Hinkley, the Utility is cooperating with the Regional Water Quality Control Board to evaluate and remediate the chromium groundwater plume. In 2005, the Utility took interim measuresMeasures have been implemented to control movement of the Hinkley plume, while full-scale in-situ treatment systems operate to reduce the mass of the plume. An evaluation of the performance of these interim remedy measures, as well as evaluated options to remediatepossible future measures, is underway as part of the plume. development of a final remedy at the Hinkley site. In 2008, the Utility spent approximately $15 million on remediation activities at Hinkley, and currently estimates it will spend at least $16 million in 2009 and $6 million in 2010. Environmental remediation costs associated with the Hinkley natural gas compressor site are not recoverable from customers.
At the Topock gas compressor station, located near Needles, California, adjacentthe Utility has implemented interim measures including a system of extraction wells and a treatment plant designed to the Colorado River,prevent movement of a hexavalent chromium has been detected in samples taken from groundwater monitoring wells located approximately 65 feet fromplume toward the Colorado River. TheIn addition, the Utility is cooperatingworking with the California Department of Toxic Substances Control, or DTSC, other state agencies appropriate federal agenciesto complete investigations at this site and other interested parties, to implement interim measures as well as develop a long-term plan to ensure thatfor clean up of the hexavalent chromium does not affect the Colorado River. In 2005, the Utility took interim measures to control the chromium plume by extracting impacted groundwaterplume. A final cleanup draft plan has been developed for agency and spent approximately $38.8 million on these measures. The Utility plans to continue these activities in 2006 and to work toward the developmentstakeholder review; approval of a final version of that plan is scheduled to addressoccur by the plume in 2006.first quarter of 2010. In 2008, the Utility spent approximately $23 million on the interim measures and for work on the long term site solution. The Utility currently estimates that it will spend at least $22$19 million
in 2009 and $18 million in 20062010 for remediation activities at Topock and $7.4 million in 2006 for remediation activities at Hinkley.Topock. Although work at the Topock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described above. The Utility does not expect the remediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on its results of operations or financial condition. The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.
In April 2004, San Luis Obispo County (the California county where Diablo Canyon is located) issuedOctober 2008, the NRC rejected the final contention that had been made during the appeal. The appellant has filed a permit under the California Coastal Act, subject to a number of conditions. The Utility, along with several other interested parties, filed appeals of the County's decision with the California Coastal Commission. The Utility's appeal challenged one of the conditions pertaining to the granting of public access to the coast and other portions of the Utility's property surrounding Diablo Canyon. On December 8, 2004, the California Coastal Commission granted the Utility's applicationpetition for a coastal development permit authorizing it to proceed with its planned construction of an on-site dry cask storage facility. The Commission granted the Utility's appeal, denied the appeals of other parties and conducted a de novo review of the application. The Commission's December 8, 2004 decision requires thatNRC’s order in the Ninth Circuit. Although the appellant did not seek to obtain an order prohibiting the Utility provide expanded public accessfrom loading spent fuel, the petition stated that they may seek a stay of fuel loading at the facility. On December 31, 2008, the appellate court granted the Utility’s request to the coast and other lands surrounding Diablo Canyon, although such public access is less expansive than the County had originally required and will be subject to a one-year study process. Construction of the on-site dry cask storage facility beganintervene in the third quarter 2005 and is expectedproceeding. All briefs by all parties are scheduled to be completedfiled by 2008.April 8, 2009.
is made available.
Nuclear Decommissioning
The Utility has received a license fromUtility's nuclear power facilities consist of two units at Diablo Canyon and the NRC to build an on-site dry cask storageretired facility at Humboldt Bay Unit 3. The Utility also has received approval from the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to the dry cask facility would allow early decommissioning of Humboldt Bay Unit 3. The Utility anticipates that construction of the dry cask storage facility can be completed in time for decommissioning of Humboldt Bay Unit 3 to begin in 2009.
Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. For ratemaking purposes,The Utility makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding, used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 iswould be scheduled to begin in 20212024 and to be completed in 2040. Decommissioning2044; that decommissioning of Diablo Canyon Unit 2 iswould be scheduled to begin in 2025 and to be completed in 2041,2041; and that decommissioning of Humboldt Bay Unit 3 iswould be scheduled to begin in 2009 and to be completed in 2015.
technology, and costs of labor, materials and equipment.
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. The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain
For more information about nuclear decommissioning, including the estimated decommissioning costs, see Note 13 of the Notes to the Consolidated Financial Statements in the 20052008 Annual Report.
Electric and magnetic fields or EMFs,(“EMFs”) naturally result from the generation, transmission, distribution and use of electricity. In January 1991, the CPUC opened an investigation to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with EMFs from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMFs, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist.
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. As part of the Utility's effort to educate the public about EMFs, the Utility provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.
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, to the CPUC and the public.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 that there isof a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.
On January 26, 2006, the CPUC issued a decision which affirms the CPUC’s “low-cost/no-cost, prudent avoidance” policy to mitigatereduce EMF exposure for new utility transmission and substation projects. The CPUC ordered the continued use of a 4% of project cost benchmark for EMF mitigation. In addition, the CPUC (1) adopted rules and policies to improve
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. The court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for allegedIn a case involving allegations of personal injury, resulting from exposure to EMFs are similarly barred. The Utility was one of the defendants in civil litigation in which the plaintiffs alleged personal injuries resulting from exposure to EMFs. In January 1998, thea California appeals court in this matter 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. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case.plaintiffs’ appeal of this decision.
A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations— Risk“Risk Factors” in the 2005MD&A in the 2008 Annual Report, which information is hereby incorporated by reference and filed as part ofincluded in Exhibit 13 to this report.
The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility's electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under "Electricity“Electric Utility Operations"Operations” and "Gas“Natural Gas Utility Operations."” In total, the Utility occupies 8.29.8 million square feet of real property, including 7.08.5 million square feet that the Utility owns. Of the 8.29.8 million square feet of occupied real property, approximately 1.51.7 million square feet represent the Utility's corporate headquarters located in several Utility owned buildings in San Francisco, California. The Utility leases approximately 120,000 square feet of the approximate 1.5 million square feet of office space. The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits or licenses from private landowners or governmental authorities
authorities. The Utility currently owns approximately 167,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements and/or donate to public agencies or non-profit conservation organizations under the Chapter 11 Settlement Agreement. Approximately 75,000 acres of this land may be donated in fee and encumbered with conservation easements. The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and will only be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council or the Council,(“Council”) to oversee the development and implementation of a Land Conservation Plan or LCP,(“LCP”) that will articulate the long-term management objectives for the 140,000 acres. The Council is guidedgoverned by an 18-member Board of Directors that representrepresents 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 one1 out of 18
members of the Board of Directors of the Council. TheIn December 2007, the Council is charged to adopt and presentadopted the LCP and submitted it to the Utility by April 2007. Utility.
The Utility has accepted the LCP and will then seek authorization from the CPUC, the FERC and other approving entities to proceed with the transactions necessary to implement the LCP. If the Council is unable to reach consensus on all or part of the LCP, the Utility will seek regulatory approval of the transactions required to implement its own plan, along with a description of the positions of the disputing board members before April 2013.
PG&E Corporation also leases approximately 74,000 square feet of office space from a third party in San Francisco, California. This lease expires in 2012.
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.
The Utility's Diablo Canyon power plant employs a "once-through"“once-through” cooling water system that is regulated under a NPDESClean Water Act permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility's Diablo Canyon power plant's discharge was not protective of beneficial uses.
In October 2000, the Utility and the Central Coast Board reached a tentative settlement of this matter pursuant tounder which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Utility's 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 Central Coasttentative settlement, agreement, 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 Central Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit.
At its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the Central Coast settlement agreement, accepted in March 2003, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers. The Water Board is developing a state policy for the implementation of Section 316(b) of the Clean Water Act, the adoption of which could affect future negotiations between the Central Coast Board and the Utility. For more information about the draft state policy, see “Environmental Matters—Water Quality” above.
On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court for the County of San Francisco or (“Superior Court,Court”) against PG&E Corporation and its directors, as well as against directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200 or (“Section 17200.17200”). Among other allegations, the California Attorney General alleged that past transfers of funds from the Utility to PG&E Corporation during the period from 1997 through 2000 (primarily in the form of dividends and stock repurchases), and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation. The California Attorney General alleged that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis.
The complaint seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, civil penalties of $2,500 against each defendant for each violation of Section 17200, a total penalty of not less than $500 million and costs of suit. The California Attorney General's complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility.
On February 11, 2002, a complaint entitled City and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in the Superior Court. The complaint contains some of the same allegations contained in the California Attorney General's complaint, including allegations of unfair competition in violation of Section 17200. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation "took“took at least
The complaints, which have been consolidated in the Superior Court, were filed after the CPUC issued two decisions in its investigative proceeding commenced in April 2001 into whether the California investor-owned electric utilities, including the Utility, complied with past CPUC decisions, rules and orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC would, among other matters, investigate the utilities' transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties, the failure of the holding companies to financially assist the utilities when needed, the transfer by the holding companies of assets to unregulated subsidiaries, and the holding companies' actions to "ringfence"“ringfence” their unregulated subsidiaries. In May 2005, the CPUC closed this investigation without making any findings. Under the Settlement Agreement, the CPUC agreed to dismiss with prejudice PG&E Corporation and the Utility from the CPUC's investigation as to past practices.
PG&E Corporation believes that the intercompany transactions challenged by the California Attorney General and CCSF were in full compliance with applicable law and CPUC conditions. The challenged transactions forming the bulk of the restitution claims were regular quarterly dividends and stock repurchases. As part of its annual cost of capital proceedings, the Utility advised the CPUC in advance of its forecast stock repurchases and dividends. The CPUC did not challenge or question those payments.
In February and March 2002, PG&E Corporation filed noticesJanuary 2006, the Ninth Circuit issued a decision on the parties’ appeals of removal invarious rulings by the Bankruptcy Court to transferand the complaints toU.S. District Court for the Bankruptcy Court. Subsequently,Northern District of California concerning jurisdictional issues. The Ninth Circuit found that the plaintiffs filed motions to remand their actions to state court. In June 2002, the BankruptcySuperior Court held that federal law preemptedhad jurisdiction over the California Attorney General’s allegations concerningand CCSF’s restitution claims. (In October 2006, the U.S. Supreme Court declined to grant PG&E Corporation’s participation inrequest to review the Utility’s bankruptcy proceedings.Ninth Circuit’s decision.) The Bankruptcy Court directed the California Attorney General to file an amended complaint omitting certain of his Section 17200 allegations and remanded the amended complaint to the Superior Court. The Bankruptcy Court retained jurisdiction over CCSF’s causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by CCSF, but remanded CCSF’s Section 17200 cause of action to state court. In both cases, the parties appealed the Bankruptcy Court’s remand order to the District Court. In August 2002, the California Attorney General filed its amended complaint in the Superior Court. The Superior Court has coordinatedNinth Circuit did not address the California Attorney General’s case withand CCSF’s underlying allegations that PG&E Corporation and the case filed by CCSF.
While the Ninth Circuit appeal was pending, the Superior Court held a trial in December 2004 to consider the appropriate standard to determine what constitutes a separate violation of Section 17200 in order to determine the magnitude of potential penalties under Section 17200 (up to $2,500 per separate “violation”). The Superior Court did not address the question of whether any violations occurred. In March 2005, the Superior Court issued a decision rejecting the “per victim” and “per [customer] bill” approaches advocated by the plaintiffs, standards that potentially could have resulted in millions of separate “violations.” The Superior Court found that the appropriate standard was each transfer of money from the Utility to PG&E Corporation that plaintiffs allege violated Section 17200. In July 27, 2005, the California Court of Appeal summarily denied a petition filed by the California Attorney General and CCSF seeking to overturn this decision.
PG&E Corporation believes that the California Attorney General’s and CCSF’s allegations have no merit and will continue to vigorously respond to and defend against the litigation.PG&E Corporation believes that the ultimate outcome of this matter would not result in a material adverse effect on PG&E Corporation’s financial condition or results of operations.
Not applicable.
The names, ages and positions of PG&E Corporation "executive“executive officers,"” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934 or (“Exchange Act,Act”) at February 1, 2006,20, 2009, are as follows:
Name | Age | Position | ||
| Chairman of the Board, Chief Executive Officer, and President | ||||
| Senior Vice President and Chief Risk and Audit Officer | ||||
| Senior Vice President, Chief Financial Officer, and Treasurer | ||||
| Senior Vice | ||||
| 50 | Senior Vice President, Public Affairs | |||
| Hyun Park | 47 | Senior Vice President and General Counsel | ||
| Greg S. Pruett | 51 | Senior Vice President, Corporate Relations | ||
| Rand L. Rosenberg | Senior Vice President, Corporate Strategy and Development | |||
| Senior Vice President, |
All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 20, 2009, 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 | ||
| Chairman of the Board, Chief Executive Officer, and President | September 19, 2007 to present | |||
| President and Chief Executive Officer, Pacific Gas and Electric Company | September 5, 2008 to present | |||
| 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 | |||
| Chairman of the Board, Pacific Gas and Electric Company | January 1, 2006 to | |||
| President and Chief Executive Officer | January 1, 2005 to December 31, 2005 | |||
| Senior Vice President and Chief Financial Officer | ||||
| Senior Vice President and Chief Risk and Audit Officer | October 1, 2005 to present | |||
| Senior Vice President, | November 1, 2000 to September 30, 2005 | |||
| Senior Vice President, Chief Financial Officer, and Treasurer | October 4, 2005 to present | |||
| Senior Vice President and Treasurer, Pacific Gas and Electric Company | June 1, 2007 to present | |||
| Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company | October 1, 2005 to | |||
| Senior Vice President, Chief Financial Officer, and Controller | January 1, 2005 to October 3, 2005 | |||
| Senior Vice President and Controller | September 19, 2001 to December 31, 2004 | |||
| Senior | ||||
| Senior Vice President, Generation and Chief | ||||
| November | ||||
| Senior Vice President, Public Affairs | March 1, 2007 to present | |||
| Senior Vice President, Public Affairs, Pacific Gas and Electric Company | June 20, 2007 to present | |||
| Vice President, Governmental Relations, Pacific Gas and Electric Company | September 26, 2005 to February 28, 2007 | |||
| Chairperson, California Medical Assistance Commission | November 13, 2003 to November 30, 2005 | |||
| 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 | |||
| Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc. | March 2000 to February 2005 | |||
| Greg S. Pruett | Senior Vice President, Corporate Relations | November 1, 2007 to present | ||
| 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 | |||
| Chief Public Affairs Officer, Bechtel National, Inc. | June 12, 2004 to September 12, 2005 | |||
| Vice President, Corporate Communications, PG&E Corporation | January 1, 1998 to September 12, 2003 | |||
| Rand L. Rosenberg | Senior Vice President, Corporate Strategy and Development | November 1, 2005 to present | ||
| Executive Vice President and Chief Financial Officer, Infospace, Inc. | September 2000 to January 20, 2001 | |||
| Senior Vice President, | ||||
| 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's "executive“executive officers,"” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 1, 2006,20, 2009, are as follows:
Name | Age | Position | ||
| President and Chief Executive Officer | ||||
| 60 | Senior Vice President and Chief Operating Officer | |||
| Desmond A. Bell | 46 | Senior Vice President, Shared Services and Chief Procurement Officer | ||
| Thomas E. Bottorff | Senior Vice President, Regulatory Relations | |||
| Senior Vice President | ||||
| Senior Vice President, Generation and Chief Nuclear Officer | ||||
| 48 | Senior Vice President and Treasurer | |||
| Patricia M. | 48 | Senior Vice President and Chief Information Officer | ||
| Nancy E. McFadden | 50 | Senior Vice President, Public Affairs | ||
| Hyun Park | 47 | |||
| Senior Vice President and General Counsel, PG&E Corporation | ||||
| Greg S. Pruett | 51 | Senior Vice President, Corporate Relations, PG&E Corporation | ||
| Edward A. Salas | 52 | Senior Vice President, Engineering and Operations | ||
| John R. Simon | 44 | Senior Vice President, Human Resources | ||
| Fong Wan | 47 | Senior Vice President, Energy Procurement | ||
| Geisha J. Williams | 47 | Senior Vice President, Energy Delivery | ||
| Barbara L. Barcon | 52 | Vice President, Finance and Chief Financial Officer |
All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2006,20, 2009 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 | ||
| President and Chief Executive Officer | September 5, 2008 to present | |||
| Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation | September 19, 2007 to present | |||
| Chairman of the Board and Chief Executive Officer, PG&E Corporation | July 1, 2007 to September 18, 2007 | |||
| Chairman of the Board, Pacific Gas and Electric Company | January 1, 2006 to | |||
| Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation | January 1, 2006 to | |||
| President and Chief Executive Officer, PG&E Corporation | January 1, 2005 to December 31, 2005 | |||
| Senior Vice President and Chief Financial Officer, PG&E Corporation | ||||
| Senior Vice President and Chief | January 1, | |||
| Senior Vice President, | ||||
| November | ||||
| Senior Vice President, Shared Services and Chief Procurement Officer | October 1, 2008 to present | |||
| 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 Relations | October 14, 2005 to present | ||
| Senior Vice President, Customer Service and Revenue | March 1, 2004 to October 13, 2005 | |||
| Vice President, Customer Service | June 1, 1999 to February 29, 2004 | |||
| Senior Vice President | ||||
| Senior Vice President, | ||||
| Senior Vice President and | ||||
| Site Vice President, Monticello Nuclear Plant, Nuclear Management Company | May 2005 to June 1, 2007 | |||
| Site Director, Monticello Nuclear Plant, Nuclear Management Company | April 2004 to | |||
| Vice President, | ||||
| Senior Vice President | ||||
| Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation | October 4, 2005 to present | |||
| Senior Vice President, Chief Financial Officer, and Treasurer | October 1, 2005 to May 31, 2007 | |||
| Senior Vice President, Chief Financial Officer, and Controller, PG&E Corporation | January 1, 2005 to October 3, 2005 | |||
| Senior Vice President and Controller, PG&E Corporation | September 19, 2001 to December 31, 2004 | |||
| Patricia M. Lawicki | Senior Vice President and | |||
| Vice President and Chief Information Officer | January 12, 2005 to October 31, 2007 | |||
| Vice President, Chief Information Officer, NiSource, Inc. | April 23, 2003 to January 7, 2005 | |||
| Senior Vice President, | ||||
| Senior Vice President, Public Affairs, PG&E Corporation | March 1, 2007 to present | |||
| Vice President, | September 26, 2005 to February 28, 2007 | |||
| Chairperson, California Medical Assistance Commission | November | |||
| 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 | |||
| Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc. | March 2000 to February 2005 | |||
| Greg S. Pruett | Senior Vice President, Corporate Relations, PG&E Corporation | November 1, 2007 to present | ||
| 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 | |||
| Chief Public Affairs Officer, Bechtel National, Inc. | June 12, 2004 to September 12, 2005 | |||
| Vice President, | ||||
| Senior Vice President, | ||||
| Staff Vice President, | ||||
May 2003 to April 2004 | ||||
| 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 | |||
| Senior Vice President, Human Capital, TeleTech Holdings, Inc. | July 13, 2001 to March 20, 2006 | |||
| Fong Wan | Senior Vice President, Energy Procurement | October 1, 2008 to present | ||
| Vice President, Energy Procurement | January 9, 2006 to | |||
| Vice President, Power Contracts and Electric Resource Development | May 1, 2004 to January 8, 2006 | |||
| Vice President, Risk Initiatives, PG&E Corporation Support Services, Inc. | November 1, 2000 to April 30, 2004 | |||
| Senior Vice President, Energy Delivery | December 1, 2007 to present | |||
| Vice President, Power Systems, Distribution, Florida Power and | July 2003 to July 2007 | |||
| Barbara L. Barcon | Vice President, Finance and Chief Financial Officer | March 24, 2008 to present | ||
| Senior Vice President, The Gores Group - Glendon Partners Private Equity Firm | 2007 to 2008 | |||
| Vice President, Financial Process Excellence, Northrop Grumman Corporation | ||||
| Vice President, Planning and Analysis, Northrop Grumman Corporation | 2003 to 2004 |
Neither PG&E Corporation at an exercise price of $0.01 per share. On November 17, 2005 and December 29, 2005, warrant holders exercised, on a net exercise basis, warrants to purchase, innor the aggregate, 73,559 shares, and received, in the aggregate, 73,538 shares of PG&E Corporation common stock in reliance on the exemption from the registration requirements of the Securities Act of 1933 provided by Section 4(2) of the Act.
PG&E Corporation common stock:
Period | Total Number of Shares Purchased | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)(2)(3) | Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs | |||||||||
| October 1 through October 31, 2005 | - | $ | - | - | $ | - | |||||||
| November 1 through November 30, 2005 | 31,650,300 | $ | 34.75 | 31,650,300 | $ | 500,000,000 | |||||||
| December 1 through December 31, 2005 | - | $ | - | - | $ | - | |||||||
Total | 31,650,300 | $ | 34.75 | 31,650,300 | $ | 500,000,000 | |||||||
| Period | Total Number of Shares Purchased | Average Price Paid Per Share | 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, 2008 | - | $ | - | $ | - | ||||||
| November 1 through November 30, 2008 | - | $ | - | $ | - | ||||||
| December 1 through December 31, 2008 | 3,872 | (1) | $ | $38.71 | - | $ | - | ||||
| Total | 3,872 | $ | $38.71 | - | $ | - | |||||
(1) Shares tendered to satisfy tax withholding obligations arising upon the vesting of PG&E Corporation restricted stock. | |||||||||||
During the fourth quarter of 2005, Pacific Gas and Electric Company2008, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.
A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years, is set forth under the heading "Selected“Selected Financial Data"Data” in the 20052008 Annual Report, which information is hereby incorporated by reference and filed as part ofincluded in Exhibit 13 to this report.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated financial condition and results of operations and financial condition is set forth under the heading "Management's“Management's Discussion and Analysis of Financial Condition and Results of Operations"Operations” in the 20052008 Annual Report, which discussion is hereby incorporated by reference and filed as part ofincluded in Exhibit 13 to this report.
Information responding to Item 7A appears in the 20052008 Annual Report under the heading "Management's“Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities,"” and under Notes 12, 11 and 12 of the "NotesNotes to the Consolidated Financial Statements"Statements of the 20052008 Annual Report, which information is hereby incorporated by reference and filed as part ofincluded in Exhibit 13 to this report.
Information responding to Item 8 appears in the 20052008 Annual Report under the following headings for PG&E Corporation: "Consolidated“Consolidated Statements of Income," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows,"” and "Consolidated“Consolidated Statements of Shareholders' Equity;"” under the following headings for Pacific Gas and Electric Company: "Consolidated“Consolidated Statements of Income," "Consolidated” “Consolidated Balance Sheets," "Consolidated” “Consolidated Statements of Cash Flows,"” and "Consolidated“Consolidated Statements of Shareholders' Equity;"” and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes“Notes to the Consolidated Financial Statements," "Quarterly” “Quarterly Consolidated Financial Data (Unaudited),"” and "Report“Report of Independent Registered Public Accounting Firm,"” which information is hereby incorporated by reference and filed as part ofincluded in Exhibit 13 to this report.
Not applicable.
Based on an evaluation of PG&E Corporation's and the Utility's disclosure controls and procedures as of December 31, 2005,2008, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities and Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange CommissionSEC rules and forms. In addition, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 20052008 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's internal control over financial reporting.
Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management's report, together with the report of the independent registered public accounting firm, appears in their joint 2005the 2008 Annual Report to Shareholders under the heading "Management's“Management's Report on Internal Control Over Financial Reporting"Reporting” and "Report“Report of Independent Registered Public Accounting Firm,"” which information is hereby incorporated by reference and filed as part ofincluded in Exhibit 13 to this report.
Measure | 2005 Results | 2006 Target | ||||
| 1. | Customer Satisfaction (Residential & Business) 1 | 94.0 | 96.0 | |||
| 2. | Timely bills (% issued within 35 days) | 99.38% | 99.51% | |||
| 3. | Estimate of Outage Restoration Accuracy | 47% | 50% | |||
| 4. | System Average Interruption Duration Index (SAIDI) 2 | 178.7 | 166 | |||
| 5. | System Average Interruption Frequency Index (SAIFI) 2 | 1.344 | 1.31 | |||
| 6. | Energy Availability (Generation and Procurement) 3 | -- 3 | -- 3 | |||
| 7. | Telephone Service Level 4 | 75/20 | 76/20 | |||
| 8. | Expense Per Customer | $278 | $283 5 | |||
| 9. | Diablo Canyon composite performance index6 | 98.2 | 98.2 | |||
| 10. | Employee survey (Premier) index | 64.0% | 68.0% | |||
| 11. | Lost workday case rate7 | 1.04 | 0.878 |
Not applicable.
PART III
Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included above in a separate item captioned "Executive“Executive Officers of the Registrants"Registrants” at the end of Part I of this report. Other information responding to Item 10 is included under the heading "Item“Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company"Company” and under the heading "Section“Section 16(a) Beneficial Ownership Reporting Compliance"Compliance” in the Joint Proxy Statement relating to the 20062009 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Website Availability of Code of Ethics, Corporate Governance and Other Documents
The following documents are available both on PG&E Corporation's website www.pgecorp.comwww.pgecorp.com, and Pacific Gas and Electric Company's website, www.pge.comwww.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers and other executive officers, (2) PG&E Corporation's and Pacific Gas and Electric Company's corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies' Audit Committees and the PG&E Corporation Nominating Compensation, and Governance Committee and Compensation Committee. Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, Vice President, Corporate Governance and Corporate Secretary of PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.
If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company that apply to their respective Chief Executive Officers, Chief Financial Officers or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within 4 business days of the waiver.
Procedures for Shareholder Recommendations of Nominees to the Boards of Directors
During 2008 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy
Statement relating to the 2008 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or the Utility’s Boards of Directors.
Audit Committees and Audit Committee Financial Expert
Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is included under the heading “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company Board Committees Audit Committees” in the Joint Proxy Statement relating to the 2009 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 11. Executive Compensation
Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Compensationheadings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table - 2008,” “Grants of Directors" and under the headings "Summary Compensation Table," "Option/SAR Grants in 2005," "Aggregated Option/SAR Exercises in 2005 and Year-End Option/SAR Values," "Long-Term Incentive Program—Plan-based Awards in 2005," "Retirement2008,” “Outstanding Equity Awards at Fiscal Year End - 2008,” “Option Exercises and Stock Vested During 2008,” “Pension Benefits" – 2008,” “Non-Qualified Deferred Compensation,” “Compensation of Non-Employee Directors,” and "Employment Contracts,“Potential Payments Upon Resignation, Retirement, Termination, of Employment, and Change Inin Control, Provisions"Death, or Disability” in the Joint Proxy Statement relating to the 20062009 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Security“Security Ownership of Management"Management” and under the heading "Principal Shareholders"“Principal Shareholders” in the Joint Proxy Statement relating to the 20062009 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Equity Compensation Plan Information
The following table provides information as of December 31, 20052008 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation'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 | 12,012,774 | $23.26 | 8,952,785(1) | |||
| Equity compensation plans not approved by shareholders | — | $— | — | |||
| Total equity compensation plans | 12,012,774 | $23.26 | 8,952,785 |
| 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 | 3,062,874(1) | $23.45 | 10,342,381(2) | |||
| Equity compensation plans not approved by shareholders | — | — | — | |||
| Total equity compensation plans | 3,062,874(1) | $23.45 | 10,342,381(2) |
| (1) Includes 94,613 phantom stock units and restricted stock units. The weighted average exercise price reported in column (b) does not take these awards into account. |
| (2) Represents the total number of shares available for issuance under the PG&E Corporation's Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2008. 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, and phantom stock. For a description of the LTIP and the 2006 LTIP, see Note 14 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report. |
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Certain Relationshipsheadings “Related Person Transactions,” “Review, Approval, and Ratification of Related Transactions"Person Transactions” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company Director Independence” in the Joint Proxy Statement relating to the 20062009 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Information responding to Item 14, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Information“Information Regarding the Independent Registered Public Accounting Firm of PG&E Corporation and Pacific Gas and Electric Company"Company” in the Joint Proxy Statement relating to the 20062009 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
(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 20052008 Annual Report and are incorporated by reference in this report:
Consolidated Statements of Income for the Years Ended December 31, 2005, 2004,2008, 2007, and 2003,2006 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2005,2008 and 20042007 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007, and 2006 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2005, 2004,2008, 2007, and 2003,2006 for each of PG&E Corporation and Pacific Gas and Electric Company.
Notes to the Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
2.The following financial statement schedules and report of independent registered public accounting firm are filed as part of this report:
Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
I—Condensed Financial Information of Parent as of December 31, 20052008 and 20042007 and for the Years Ended December 31, 2005, 2004,2008, 2007, and 2003.2006.
II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2005, 2004,2008, 2007, and 2003.2006.
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.
3.Exhibits required by Item 601 of Regulation S-K:
Exhibit Number | Exhibit Description | ||
| 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'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'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's Quarterly Report on 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'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 January 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'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 January 1, | ||
| 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's Form 10-Q filed May 4, 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 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 Current Report on 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 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 Current Report on Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1) | ||
| 4.4 | Third Supplemental Indenture dated as of March 3, 2008 relating to the 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 Current Report on 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 Current Report on Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1) | ||
| 4.6 | Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1). | ||
| Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1) | |||
| 10.1 | Amended and Restated Unsecured Revolving Credit Agreement | ||
| 10.2 | |||
| 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's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99) | |||
| 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) | |||
| 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) | |||
| * | 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) | ||
| *10.7 | |||
| | |||
| PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 | |||
| * | |||
| Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4) | |||
| * | Restricted Stock Award Agreement between PG&E Corporation and | ||
| * | Amendment to January 3, 2007 Restricted Stock Agreement | ||
| * | Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and | ||
| *10.12 | Restricted Stock Unit Agreement between Peter A. Darbee and | ||
| *10.13 | Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended | ||
| *10.14 | Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609), Exhibit 10.4) | ||
| *10.15 | Performance Share Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2007) (File No. 1-12609), Exhibit 10.13) | ||
| *10.16 | Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2007) (File No. 1-12609), Exhibit 10.14) | ||
| *10.17 | Separation Agreement between William T. Morrow and Pacific Gas and Electric Company dated July 8, 2008 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 1-12609), Exhibit 10) | ||
| *10.18 | 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) | ||
| *10.19 | 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) | ||
| *10.20 | Letter regarding Compensation Agreement between PG&E Corporation and G. Robert Powell dated August 8, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2007) (File No. 1-12609), Exhibit 10.17) | ||
| *10.21 | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 | ||
| *10.22 | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Barbara Barcon dated March 3, 2008 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.3) | ||
| *10.23 | Separation Agreement between PG&E Corporation and G. Robert Powell dated March 6, 2008 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.4) | ||
| *10.24 | 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) | ||
| *10.25 | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2008 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2007 (File No. 1-12609), Exhibit 10.19) | ||
| *10.26 | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2009 | ||
| *10.27 | 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) | ||
| *10.28 | 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) | ||
| *10.29 | Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.30 | Pacific Gas and Electric Company Relocation Assistance Program for Officers | ||
| *10.31 | Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16) | ||
| *10.32 | 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) | ||
| *10.33 | 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 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 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) | ||
| * | Resolution of the PG&E Corporation Board of Directors dated | ||
| * | Resolution of the Pacific Gas and Electric Company Board of Directors dated | ||
| * | Resolution of the PG&E Corporation Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 | ||
| *10.37 | Resolution of the Pacific Gas and Electric Company Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 | ||
| *10.38 | PG&E Corporation 2006 Long-Term Incentive Plan, | ||
| * | 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's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10) | ||
| * | |||
| Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37) | |||
| * | Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3) | ||
| * | Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1) | ||
| * | 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's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39) | ||
| *10.44 | Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.5) | ||
| *10.45 | 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) | ||
| *10.46 | 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's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1) | ||
| * | |||
| Form of Performance Share Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2) | |||
| * | Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2) | ||
| *10.49 | |||
| Form of Performance Share Agreement for 2007 grants under the PG&E Corporation | |||
| PG&E Corporation | |||
| * | Form of Performance Share 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 10.6) | ||
| *10.51 | Form of Amended and Restated Performance Share Agreement for 2006 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.52 | Form of Amended and Restated Performance Share Agreement for 2007 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.53 | Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.54 | PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective February 17, 2009 | ||
| *10.55 | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48) | ||
| * | PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) | ||
| *10.57 | PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49) | ||
| * | Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.59 | PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1) | ||
| * | PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39) | ||
| * | 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's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40) | ||
| * | 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) | ||
| 11 | Computation of Earnings Per Common Share | ||
| 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 | ||
| 13 | The following portions of the | ||
| 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 | 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 | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002 | ||
| **32.2 | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 | ||
*Management contract or compensatory agreement.
**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 20052008 to be signed on their behalf by the undersigned, thereunto duly authorized.
| PG&E CORPORATION | PACIFIC GAS AND ELECTRIC COMPANY | ||
(Registrant) | (Registrant) | ||
By: | Peter A. Darbee Chairman of the Board, Chief Executive Officer, and President | By: | Peter A. Darbee President and Chief Executive Officer |
| Date: | February 24, 2009 | Date: | February 24, 2009 |
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 | Date | ||||||||
A. | Principal Executive Officers | |||||||||
| *PETER A. DARBEE | Chairman of the Board, Chief Executive Officer, President, and | February | ||||||||
| Peter A. Darbee | ||||||||||
| President and Chief Executive Officer (Pacific Gas and Electric Company) | ||||||||||
B. | Principal Financial Officers | |||||||||
| *CHRISTOPHER P. JOHNS | Senior Vice President, Chief Financial Officer, and Treasurer (PG&E | February | ||||||||
| Christopher P. Johns | ||||||||||
| *BARBARA L. BARCON | (Pacific Gas and Electric Company) | February 24, 2009 | ||||||||
| Barbara L. Barcon | ||||||||||
| C. Principal Accounting Officer | ||||||||||
| * | Vice President and Controller (PG&E Corporation and | February | ||||||||
| *Stephen J. Cairns | ||||||||||
D. Directors | ||||||||||
| *DAVID R. ANDREWS | Director | February 24, 2009 | ||||||||
| David R. Andrews | ||||||||||
| *C. LEE COX | Director | February 24, 2009 | ||||||||
| C. Lee Cox | ||||||||||
| *MARYELLEN C. HERRINGER | Director | February 24, 2009 | ||||||||
| Maryellen C. Herringer | ||||||||||
| * | Director | February 24, 2009 | ||||||||
| Roger H. Kimmel | ||||||||||
| *RICHARD A. MESERVE | Director | February 24, 2009 | ||||||||
| Richard A. Meserve | ||||||||||
| *MARY S. METZ | Director | February 24, 2009 | ||||||||
| Mary S. Metz | ||||||||||
| *FORREST E. MILLER | Director | February 24, 2009 | ||||||||
| Forrest E. Miller | ||||||||||
| *BARBARA L. RAMBO | Director | February 24, 2009 | ||||||||
| Barbara L. Rambo | ||||||||||
| *BARRY LAWSON WILLIAMS | Director | February | ||||||||
| Barry Lawson Williams | |||||||||
| * | |||||||||
| HYUN PARK, Attorney-in-Fact | |||||||||
| REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM |
To the BoardsBoard 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, 20052008 and 2004,2007, and for each of the three years in the period ended December 31, 2005, management’s assessment of the effectiveness of2008, and the Company’s and the Utility’s internal control over financial reporting as of December 31, 2005, and the effectiveness of the Company’s and the Utility’s internal control over financial reporting as of December 31, 2005,2008, and have issued our reportsreport thereon dated February 15, 2006;19, 2009 (which expresses an unqualified opinion and includes for the Company and Utility an explanatory paragraph stating that in January 2008 new accounting standards were adopted for addressing fair value measurement and an amendment to an interpretation of accounting standards for offsetting amounts related to certain contracts, in 2007 a new interpretation of accounting standards for uncertainty in income taxes, and in 2006 new accounting standards for defined benefit pensions and other postretirement plans and share-based payments); such consolidated financial statements and reportsour report are included in your 20052008 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the condensedconsolidated financial statement schedules of the Company and the Utility listed in Item 15 (a) 15(a)2. These condensedconsolidated financial statement schedules are the responsibility of the Company’s and the Utility’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such condensedconsolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
DELOITTE & TOUCHE LLP
February 15, 200619, 2009
San Francisco, CA
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETSSTATEMENTS OF INCOME
(in millions, except per share amounts)
| Year Ended December 31, | |||
| 2008 | 2007 | 2006 | |
| Administrative service revenue | 119 | 102 | 110 |
| Equity in earnings of subsidiaries | 1,182 | 1,006 | 964 |
| Operating expenses | (105) | (112) | (115) |
| Interest income | 4 | 15 | 15 |
| Interest expense | (30) | (31) | (30) |
| Other income (expense) | (46) | (6) | (1) |
| Income before income taxes | 1,124 | 974 | 943 |
| Income tax benefit | 60 | 32 | 48 |
| Income from continuing operations | 1,184 | 1,006 | 991 |
| Gain on disposal of NEGT | 154 | - | - |
| Net income before intercompany eliminations | 1,338 | 1,006 | 991 |
Weighted average common shares outstanding, basic | 357 | 351 | 346 |
| Weighted average common shares outstanding, diluted | 358 | 353 | 349 |
Earnings per common share, basic(1) | $3.64 | $2.79 | $2.78 |
Earnings per common share, diluted(1) | $3.63 | $2.78 | $2.76 |
Balance at December 31, | |||||||
2005 | 2004 | ||||||
ASSETS | |||||||
| Cash and cash equivalents | $ | 250 | $ | 183 | |||
| Advances to affiliates | 38 | 22 | |||||
| Other current assets | 3 | 3 | |||||
| Total current assets | 291 | 208 | |||||
| Equipment | 15 | 15 | |||||
| Accumulated depreciation | (14 | ) | (13 | ) | |||
| Net equipment | 1 | 2 | |||||
| Investments in subsidiaries | 7,401 | 8,848 | |||||
| Other investments | 71 | 31 | |||||
| Deferred income taxes | 127 | 104 | |||||
| Other | 15 | 14 | |||||
| Total Assets | $ | 7,906 | $ | 9,207 | |||
LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||
| Current Liabilities | |||||||
| Accounts payable—related parties | $ | 27 | $ | 3 | |||
| Accounts payable—other | 17 | 15 | |||||
| Income taxes payable | 28 | 83 | |||||
| Other | 193 | 53 | |||||
| Total current liabilities | 265 | 154 | |||||
| Noncurrent Liabilities: | |||||||
| Long-term debt | 280 | 280 | |||||
| Other | 143 | 140 | |||||
| Total noncurrent liabilities | 423 | 420 | |||||
| Preferred stock | — | — | |||||
| Common Shareholders' Equity | |||||||
| Common stock | 5,827 | 6,518 | |||||
| Common stock held by subsidiary | (718 | ) | (718 | ) | |||
| Unearned compensation | (22 | ) | (26 | ) | |||
| Reinvested earnings | 2,139 | 2,863 | |||||
| Accumulated other comprehensive loss | (8 | ) | (4 | ) | |||
| Total common shareholders' equity | 7,218 | 8,633 | |||||
| Total Liabilities and Shareholders' Equity | $ | 7,906 | $ | 9,207 | |||
Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2008 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)— (Continued)
CONDENSED STATEMENTS OF INCOMEBALANCE SHEETS
(in millions, except per share amounts)millions)
| Balance at December 31, | ||
| 2008 | 2007 | |
| ASSETS | ||
Current Assets: | ||
| Cash and cash equivalents | $ 167 | $ 204 |
| Advances to affiliates | 28 | 30 |
| Income taxes receivable | 148 | 46 |
| Other current assets | 14 | 3 |
| Total current assets | 357 | 283 |
| Equipment | 17 | 17 |
| Accumulated depreciation | (15) | (15) |
| Net equipment | 2 | 2 |
| Investments in subsidiaries | 9,539 | 8,886 |
| Other investments | 68 | 87 |
| Deferred income taxes | 51 | 51 |
| Other | 4 | 9 |
| Total Assets | $ 10,021 | $ 9,318 |
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||
| Current Liabilities: | ||
| Accounts payable—related parties | $ 34 | $ 40 |
| Accounts payable—other | 18 | 24 |
| Other | 189 | 174 |
| Total current liabilities | 241 | 238 |
| Noncurrent Liabilities: | ||
| Long-term debt | 280 | 280 |
| Income taxes payable | 23 | 131 |
| Other | 100 | 116 |
| Total noncurrent liabilities | 403 | 527 |
| Common Shareholders' Equity | ||
| Common stock | 5,984 | 6,110 |
| Common stock held by subsidiary | - | (718) |
| Reinvested earnings | 3,614 | 3,151 |
| Accumulated other comprehensive income | (221) | 10 |
| Total common shareholders' equity | 9,377 | 8,553 |
| Total Liabilities and Shareholders' Equity | $ 10,021 | $ 9,318 |
Year Ended December 31, | ||||||||||
2005 | 2004 | 2003 | ||||||||
| Administrative service revenue | $ | 97 | $ | 85 | $ | 101 | ||||
| Equity in earnings of subsidiaries | 918 | 3,959 | 917 | |||||||
| Operating expenses | (97 | ) | (110 | ) | (133 | ) | ||||
| Interest income | 9 | 15 | 20 | |||||||
| Interest expense | (35 | ) | (132 | ) | (200 | ) | ||||
| Other income (expense) | (17 | ) | (91 | ) | 2 | |||||
| Income before income taxes | 875 | 3,726 | 707 | |||||||
| Income tax benefit | 29 | 94 | 84 | |||||||
| Income from continuing operations | 904 | 3,820 | 791 | |||||||
| Gain on disposal of NEGT | 13 | 684 | — | |||||||
| Discontinued operations | — | — | (365 | ) | ||||||
| Cumulative effect of changes in accounting principles | — | — | (6 | ) | ||||||
| Net income before intercompany eliminations | $ | 917 | $ | 4,504 | $ | 420 | ||||
Weighted average common shares outstanding | 372 | 398 | 385 | |||||||
Earnings per common share, basic(1) | $ | 2.40 | $ | 10.80 | $ | 1.04 | ||||
Earnings per common share, diluted(1) | $ | 2.37 | $ | 10.57 | $ | 1.02 | ||||
PG&E CORPORATION
SCHEDULE I — – CONDENSED FINANCIAL INFORMATION OF PARENT — – (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
| Year Ended December 31, | ||||||||||
| 2008 | 2007 | 2006 | ||||||||
| Cash Flows from Operating Activities: | ||||||||||
| Net income | $ | 1,338 | $ | 1,006 | $ | 991 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||
| Depreciation and amortization | 3 | 1 | - | |||||||
| Equity in earnings of subsidiaries | (1,180) | (1,006) | (964) | |||||||
| Noncurrent income taxes receivable/payable | (108) | 4 | - | |||||||
| Other | (81) ) | (19) ) | 132 | |||||||
| Net cash used in operating activities | (28) | 24 | 159 | |||||||
| Cash Flows From Investing Activities: | ||||||||||
| Capital expenditures | - | (1) | (1) | |||||||
| Investment in subsidiaries | (275) | (405) | - | |||||||
| Dividends received from subsidiaries | 596 | 509 | 460 | |||||||
| Other | (12) | - | - | |||||||
| Net cash provided by investing activities | 309 | 103 | 459 | |||||||
Cash Flows From Financing Activities(1): | ||||||||||
| Common stock issued | 225 | 175 | 131 | |||||||
| Common stock repurchased | - | - | (114) | |||||||
| Common stock dividends paid | (546) | (496) | (456) | |||||||
| Other | 2 | 12 | (43) | |||||||
| Net cash used in financing activities | (319) | (309) | (482) | |||||||
| Net change in cash and cash equivalents | (38) | (182) | 136 | |||||||
| Cash and cash equivalents at January 1 | 204 | 386 | 250 | |||||||
| Cash and cash equivalents at December 31 | $ | 166 | $ | 204 | $ | 386 | ||||
(1) 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. On January 15, 2007, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share. On April 15, July 15, and October 15, 2007, PG&E Corporation paid quarterly common stock dividends of $0.36 per share. Of the total dividend payments made by PG&E Corporation in 2007, approximately $35 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. On January 16, April 15, July 15, and October 15, 2006, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share, totaling approximately $489 million. Of the total dividend payments made by PG&E Corporation in 2006, approximately $33 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. | ||||||||||
Year Ended December 31, | ||||||||||
2005 | 2004 | 2003 | ||||||||
| Cash Flows from Operating Activities: | ||||||||||
| Net income | $ | 917 | $ | 4,504 | $ | (420 | ) | |||
| Gain on disposal of NEGT (net of income tax benefit of $13 million in 2005 and income tax expense of $374 million in 2004) | (13 | ) | (684 | ) | — | |||||
| Loss from operations of NEGT (net of income tax benefit of $320 million) | — | — | 365 | |||||||
| Cumulative effect of changes in accounting principles | — | — | 6 | |||||||
| Net income from continuing operations | 904 | 3,820 | 791 | |||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||
| Equity in earnings of subsidiaries | (918 | ) | (3,959 | ) | (917 | ) | ||||
| Deferred taxes | (23 | ) | 27 | 265 | ||||||
| NEGT settlement payment | — | (30 | ) | — | ||||||
| Other | 86 | 160 | 391 | |||||||
| Net cash provided by operating activities | 49 | 18 | 530 | |||||||
| Cash Flows From Investing Activities: | ||||||||||
| Capital expenditures | (1 | ) | — | — | ||||||
| Investment in subsidiaries | — | (28 | ) | — | ||||||
| Stock repurchase by subsidiary | 1,910 | — | — | |||||||
| Dividends received from subsidiaries | 445 | — | — | |||||||
| Increase in restricted cash | — | 361 | — | |||||||
| Other | (38 | ) | — | — | ||||||
| Net cash provided by investing activities | 2,316 | 333 | — | |||||||
Cash Flows From Financing Activities(2): | ||||||||||
| Common stock issued | 243 | 162 | 166 | |||||||
| Common stock repurchased | (2,188 | ) | (350 | ) | — | |||||
| Common stock dividends paid | (334 | ) | — | — | ||||||
| Long-term debt issued | — | — | 581 | |||||||
| Long-term debt redeemed | (2 | ) | (652 | ) | (787 | ) | ||||
| Other | (17 | ) | (1 | ) | 1 | |||||
| Net cash used by financing activities | (2,298 | ) | (841 | ) | (39 | ) | ||||
| Net change in cash and cash equivalents | 67 | (490 | ) | 491 | ||||||
| Cash and cash equivalents at January 1 | 183 | 673 | 182 | |||||||
| Cash and cash equivalents at December 31 | $ | 250 | $ | 183 | $ | 673 | ||||
PG&E CORPORATIONCorporation
SCHEDULE II—II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2005, 20032008, 2007, and 20042006
Additions | ||||||||||||||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions(3) | Balance at End of Period | |||||||||||
(in millions) | ||||||||||||||||
Valuation and qualifying accounts deducted from assets: | ||||||||||||||||
| 2005 | ||||||||||||||||
Allowance for uncollectible accounts(1) | $ | 93 | $ | 21 | $ | — | $ | 37 | $ | 77 | ||||||
| 2004: | ||||||||||||||||
Allowance for uncollectible accounts(1)(2) | $ | 68 | $ | 85 | $ | — | $ | 60 | $ | 93 | ||||||
| 2003: | ||||||||||||||||
Allowance for uncollectible accounts(1)(2) | $ | 59 | $ | 42 | $ | — | $ | 33 | $ | 68 | ||||||
Additions | |||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions(3) | Balance at End of Period |
| (in millions) | |||||
| Valuation and qualifying accounts deducted from assets: | |||||
| 2008: | |||||
Allowance for uncollectible accounts(1)(2) | $ 58 | $ 68 | $ 11 | $ 61 | $ 76 |
| 2007: | |||||
Allowance for uncollectible accounts(1)(2) | $ 50 | $ 20 | $ - | $ 12 | $ 58 |
| 2006: | |||||
Allowance for uncollectible accounts(1)(2) | $ 77 | $ 2 | $ - | $ 29 | $ 50 |
(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. | |||||
SCHEDULE II—II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2005, 20042008, 2007, and 20032006
Additions | ||||||||||||||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions(2) | Balance at End of Period | |||||||||||
(in millions) | ||||||||||||||||
Valuation and qualifying accounts deducted from assets: | ||||||||||||||||
| 2005 | ||||||||||||||||
Allowance for uncollectible accounts(1) | $ | 93 | $ | 21 | $ | — | $ | 37 | $ | 77 | ||||||
| 2004: | ||||||||||||||||
Allowance for uncollectible accounts(1) | $ | 68 | $ | 85 | $ | — | $ | 60 | $ | 93 | ||||||
| 2003: | ||||||||||||||||
Allowance for uncollectible accounts(1) | $ | 59 | $ | 42 | $ | — | $ | 33 | $ | 68 | ||||||
Additions | |||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions(2) | Balance at End of Period |
| (in millions) | |||||
| Valuation and qualifying accounts deducted from assets: | |||||
| 2008: | |||||
Allowance for uncollectible accounts(1) | $ 58 | $ 68 | $ 11 | $ 61 | $ 76 |
| 2007: | |||||
Allowance for uncollectible accounts(1) | $ 50 | $ 20 | $ - | $ 12 | $ 58 |
| 2006: | |||||
Allowance for uncollectible accounts(1) | $ 77 | $ 2 | $ - | $ 29 | $ 50 |
(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
Exhibit 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'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'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's Quarterly Report on 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'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 January 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'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 January 1, | ||
| 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's Form 10-Q filed May 4, 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 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 Current Report on 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 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 Current Report on Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1) | ||
| 4.4 | Third Supplemental Indenture dated as of March 3, 2008 relating to the 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 Current Report on 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 Current Report on Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1) | ||
| 4.6 | Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1). | ||
| Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1) | |||
| 10.1 | Amended and Restated Unsecured Revolving Credit Agreement | ||
| 10.2 | |||
| 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's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99) | |||
| 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) | |||
| 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) | |||
| * | 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) | ||
| * | PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 | ||
| * | |||
| Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4) | |||
| * | Restricted Stock Award Agreement between PG&E Corporation and | ||
| * | Amendment to January 3, 2007 Restricted Stock Agreement | ||
| * | Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and | ||
| *10.12 | Restricted Stock Unit Agreement between Peter A. Darbee and | ||
| *10.13 | Letter regarding Compensation Arrangement between Pacific Gas and Electric Company and William T. Morrow dated June 20, 2006 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended | ||
| *10.14 | Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated January 29, 2007 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609), Exhibit 10.4) | ||
| *10.15 | Performance Share Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2007) (File No. 1-12609), Exhibit 10.13) | ||
| *10.16 | Restricted Stock Award Agreement between PG&E Corporation and William T. Morrow dated November 6, 2007 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2007) (File No. 1-12609), Exhibit 10.14) | ||
| *10.17 | Separation Agreement between William T. Morrow and Pacific Gas and Electric Company dated July 8, 2008 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 1-12609), Exhibit 10) | ||
| *10.18 | 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) | ||
| *10.19 | 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) | ||
| *10.20 | Letter regarding Compensation Agreement between PG&E Corporation and G. Robert Powell dated August 8, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2007) (File No. 1-12609), Exhibit 10.17) | ||
| *10.21 | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 | ||
| *10.22 | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Barbara Barcon dated March 3, 2008 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.3) | ||
| *10.23 | Separation Agreement between PG&E Corporation and G. Robert Powell dated March 6, 2008 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.4) | ||
| *10.24 | 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) | ||
| *10.25 | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2008 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2007 (File No. 1-12609), Exhibit 10.19) | ||
| *10.26 | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2009 | ||
| *10.27 | 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) | ||
| *10.28 | 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) | ||
| *10.29 | Supplemental Executive Retirement Plan of PG&E Corporation as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.30 | Pacific Gas and Electric Company Relocation Assistance Program for Officers | ||
| *10.31 | Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16) | ||
| *10.32 | 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) | ||
| *10.33 | 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 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 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) | ||
| *10.34 | |||
| Resolution of the PG&E Corporation Board of Directors dated | |||
| * | Resolution of the Pacific Gas and Electric Company Board of Directors dated | ||
| * | Resolution of the PG&E Corporation Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 | ||
| *10.37 | Resolution of the Pacific Gas and Electric Company Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 | ||
| *10.38 | PG&E Corporation 2006 Long-Term Incentive Plan, | ||
| * | 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's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10) | ||
| * | |||
| Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37) | |||
| * | Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3) | ||
| * | Form of Restricted Stock Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.1) | ||
| * | 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's Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39) | ||
| *10.44 | Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.5) | ||
| *10.45 | 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) | ||
| *10.46 | 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's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1) | ||
| * | |||
| Form of Performance Share Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2) | |||
| * | Form of Performance Share Agreement for 2006 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 9, 2006, Exhibit 99.2) | ||
| * | Form of Performance Share Agreement for 2007 grants under the PG&E Corporation | ||
| PG&E Corporation | |||
| * | Form of Performance Share 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 10.6) | ||
| *10.51 | Form of Amended and Restated Performance Share Agreement for 2006 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.52 | Form of Amended and Restated Performance Share Agreement for 2007 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.53 | Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.54 | PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective February 17, 2009 | ||
| *10.55 | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48) | ||
| * | PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) | ||
| *10.57 | PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49) | ||
| * | Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) | ||
| *10.59 | PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1) | ||
| * | PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39) | ||
| * | 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's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40) | ||
| *10.62 | |||
| | |||
| 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) | |||
| 11 | Computation of Earnings Per Common Share | ||
| 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 | ||
| 13 | The following portions of the | ||
| 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 | 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 | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002 | ||
| **32.2 | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 | ||
*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.